ENTERGY NEW ORLEANS, LLC - Annual Report: 2016 (Form 10-K)

Borrowings

Letters of Credit

Capacity Available

(In Millions)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K



(Mark One)

X	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	For the Fiscal Year Ended December 31, 2016
	OR
	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	For the transition period from ____________ to ____________



Commission File Number	Registrant, State of Incorporation or Organization, Address of Principal Executive Offices, Telephone Number, and IRS Employer Identification No.	Commission File Number	Registrant, State of Incorporation or Organization, Address of Principal Executive Offices, Telephone Number, and IRS Employer Identification No.
1-11299	ENTERGY CORPORATION (a Delaware corporation) 639 Loyola Avenue New Orleans, Louisiana 70113 Telephone (504) 576-4000 72-1229752	1-35747	ENTERGY NEW ORLEANS, INC. (a Louisiana corporation) 1600 Perdido Street New Orleans, Louisiana 70112 Telephone (504) 670-3700 72-0273040


1-10764	ENTERGY ARKANSAS, INC. (an Arkansas corporation) 425 West Capitol Avenue Little Rock, Arkansas 72201 Telephone (501) 377-4000 71-0005900	1-34360	ENTERGY TEXAS, INC. (a Texas corporation) 10055 Grogans Mill Road The Woodlands, TX 77380 Telephone (409) 981-2000 61-1435798


1-32718	ENTERGY LOUISIANA, LLC (a Texas limited liability company) 4809 Jefferson Highway Jefferson, Louisiana 70121 Telephone (504) 576-4000 47-4469646	1-09067	SYSTEM ENERGY RESOURCES, INC. (an Arkansas corporation) 1340 Echelon Parkway Jackson, Mississippi 39213 Telephone (601) 368-5000 72-0752777


1-31508	ENTERGY MISSISSIPPI, INC. (a Mississippi corporation) 308 East Pearl Street Jackson, Mississippi 39201 Telephone (601) 368-5000 64-0205830

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Securities registered pursuant to Section 12(b) of the Act:



Registrant	Title of Class	Name of Each Exchange on Which Registered

Entergy Corporation	Common Stock, $0.01 Par Value – 179,394,698 shares outstanding at January 31, 2017	New York Stock Exchange, Inc. Chicago Stock Exchange, Inc.

Entergy Arkansas, Inc.	Mortgage Bonds, 4.90% Series due December 2052	New York Stock Exchange, Inc.
	Mortgage Bonds, 4.75% Series due June 2063	New York Stock Exchange, Inc.
	Mortgage Bonds, 4.875% Series due September 2066	New York Stock Exchange, Inc.

Entergy Louisiana, LLC	Mortgage Bonds, 5.25% Series due July 2052	New York Stock Exchange, Inc.
	Mortgage Bonds, 4.70% Series due June 2063	New York Stock Exchange, Inc.
	Mortgage Bonds, 4.875% Series due September 2066	New York Stock Exchange, Inc.

Entergy Mississippi, Inc.	Mortgage Bonds, 4.90% Series due October 2066	New York Stock Exchange, Inc.

Entergy New Orleans, Inc.	Mortgage Bonds, 5.0% Series due December 2052	New York Stock Exchange, Inc.
	Mortgage Bonds, 5.50% Series due April 2066	New York Stock Exchange, Inc.

Entergy Texas, Inc.	Mortgage Bonds, 5.625% Series due June 2064	New York Stock Exchange, Inc.

Securities registered pursuant to Section 12(g) of the Act:



Registrant	Title of Class

Entergy Arkansas, Inc.	Preferred Stock, Cumulative, $100 Par Value
	Preferred Stock, Cumulative, $0.01 Par Value

Entergy Mississippi, Inc.	Preferred Stock, Cumulative, $100 Par Value

Entergy New Orleans, Inc.	Preferred Stock, Cumulative, $100 Par Value

Entergy Texas, Inc.	Common Stock, no par value

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Indicate by check mark if the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.



	Yes	No

Entergy Corporation	ü
Entergy Arkansas, Inc.		ü
Entergy Louisiana, LLC	ü
Entergy Mississippi, Inc.		ü
Entergy New Orleans, Inc.		ü
Entergy Texas, Inc.		ü
System Energy Resources, Inc.		ü

Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.



	Yes	No

Entergy Corporation		ü
Entergy Arkansas, Inc.		ü
Entergy Louisiana, LLC		ü
Entergy Mississippi, Inc.		ü
Entergy New Orleans, Inc.		ü
Entergy Texas, Inc.		ü
System Energy Resources, Inc.		ü

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrants have submitted electronically and posted on Entergy’s corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ü]

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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “accelerated filer,” “large accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Securities Exchange Act of 1934.



	Large accelerated filer	Accelerated filer	Non-accelerated filer	Smaller reporting company

Entergy Corporation	ü
Entergy Arkansas, Inc.			ü
Entergy Louisiana, LLC			ü
Entergy Mississippi, Inc.			ü
Entergy New Orleans, Inc.			ü
Entergy Texas, Inc.			ü
System Energy Resources, Inc.			ü

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Act.) Yes o No þ

System Energy Resources meets the requirements set forth in General Instruction I(1) of Form 10-K and is therefore filing this Form 10-K with reduced disclosure as allowed in General Instruction I(2). System Energy Resources is reducing its disclosure by not including Part III, Items 10 through 13 in its Form 10-K.

The aggregate market value of Entergy Corporation Common Stock, $0.01 Par Value, held by non-affiliates as of the end of the second quarter of 2016 was $14.6 billion based on the reported last sale price of $81.35 per share for such stock on the New York Stock Exchange on June 30, 2016. Entergy Corporation is the sole holder of the common stock of Entergy Arkansas, Inc., Entergy Mississippi, Inc., Entergy New Orleans, Inc., Entergy Texas, Inc., and System Energy Resources, Inc. Entergy Corporation is the direct and indirect holder of the common membership interests of Entergy Utility Holdings Company, LLC, which is the sole holder of the common membership interests of Entergy Louisiana, LLC.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders, to be held May 5, 2017, are incorporated by reference into Part III hereof.

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TABLE OF CONTENTS



	SEC Form 10-K Reference Number	Page Number

Forward-looking information		iv
Definitions		vi
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis	Part II. Item 7.	1
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	49
Report of Independent Registered Public Accounting Firm		50
Consolidated Statements of Operations For the Years Ended December 31, 2016, 2015, and 2014	Part II. Item 8.	51
Consolidated Statements of Comprehensive Income (Loss) For the Years Ended December 31, 2016, 2015, and 2014	Part II. Item 8.	53
Consolidated Statements of Cash Flows For the Years Ended December 31, 2016, 2015, and 2014	Part II. Item 8.	54
Consolidated Balance Sheets, December 31, 2016 and 2015	Part II. Item 8.	56
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2016, 2015, and 2014	Part II. Item 8.	58
Notes to Financial Statements	Part II. Item 8.	59
Note 1. Summary of Significant Accounting Policies	Part II. Item 8.	59
Note 2. Rate and Regulatory Matters	Part II. Item 8.	70
Note 3. Income Taxes	Part II. Item 8.	113
Note 4. Revolving Credit Facilities, Lines of Credit, and Short-term Borrowings	Part II. Item 8.	125
Note 5. Long-term Debt	Part II. Item 8.	129
Note 6. Preferred Equity	Part II. Item 8.	138
Note 7. Common Equity	Part II. Item 8.	140
Note 8. Commitments and Contingencies	Part II. Item 8.	144
Note 9. Asset Retirement Obligations	Part II. Item 8.	153
Note 10. Leases	Part II. Item 8.	158
Note 11. Retirement, Other Postretirement Benefits, and Defined Contribution Plans	Part II. Item 8.	162
Note 12. Stock-based Compensation	Part II. Item 8.	190
Note 13. Business Segment Information	Part II. Item 8.	195
Note 14. Acquisitions, Dispositions, and Impairment of Long-lived Assets	Part II. Item 8.	197
Note 15. Risk Management and Fair Values	Part II. Item 8.	204
Note 16. Decommissioning Trust Funds	Part II. Item 8.	220
Note 17. Variable Interest Entities	Part II. Item 8.	226
Note 18. Transactions with Affiliates	Part II. Item 8.	228
Note 19. Quarterly Financial Data	Part II. Item 8.	230
Entergy’s Business	Part I. Item 1.	233
Utility	Part I. Item 1.	233
Entergy Wholesale Commodities	Part I. Item 1.	252
Regulation of Entergy’s Business	Part I. Item 1.	257
Litigation		272
Employees		273
Availability of SEC filings and other information on Entergy’s website		273
Risk Factors	Part I. Item 1A.	275
Unresolved Staff Comments	Part I. Item 1B.	None
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis	Part II. Item 7.	301

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Report of Independent Registered Public Accounting Firm		320
Consolidated Income Statements For the Years Ended December 31, 2016, 2015, and 2014	Part II. Item 8.	321
Consolidated Statements of Cash Flows For the Years Ended December 31, 2016, 2015, and 2014	Part II. Item 8.	323
Consolidated Balance Sheets, December 31, 2016 and 2015	Part II. Item 8.	324
Consolidated Statements of Changes in Common Equity for the Years Ended December 31, 2016, 2015, and 2014	Part II. Item 8.	326
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	327
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis	Part II. Item 7.	328
Report of Independent Registered Public Accounting Firm		351
Consolidated Income Statements For the Years Ended December 31, 2016, 2015, and 2014	Part II. Item 8.	353
Consolidated Statements of Comprehensive Income For the Years Ended December 31, 2016, 2015, and 2014	Part II. Item 8.	354
Consolidated Statements of Cash Flows For the Years Ended December 31, 2016, 2015, and 2014	Part II. Item 8.	355
Consolidated Balance Sheets, December 31, 2016 and 2015	Part II. Item 8.	356
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2016, 2015, and 2014	Part II. Item 8.	358
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	359
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis	Part II. Item 7.	360
Report of Independent Registered Public Accounting Firm		375
Income Statements For the Years Ended December 31, 2016, 2015, and 2014	Part II. Item 8.	376
Statements of Cash Flows For the Years Ended December 31, 2016, 2015, and 2014	Part II. Item 8.	377
Balance Sheets, December 31, 2016 and 2015	Part II. Item 8.	378
Statements of Changes in Common Equity for the Years Ended December 31, 2016, 2015, and 2014	Part II. Item 8.	380
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	381
Entergy New Orleans, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis	Part II. Item 7.	382
Report of Independent Registered Public Accounting Firm		396
Consolidated Income Statements For the Years Ended December 31, 2016, 2015, and 2014	Part II. Item 8.	397
Consolidated Statements of Cash Flows For the Years Ended December 31, 2016, 2015, and 2014	Part II. Item 8.	399
Consolidated Balance Sheets, December 31, 2016 and 2015	Part II. Item 8.	400
Consolidated Statements of Changes in Common Equity for the Years Ended December 31, 2016, 2015, and 2014	Part II. Item 8.	402
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	403
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis	Part II. Item 7.	404
Report of Independent Registered Public Accounting Firm		418
Consolidated Income Statements For the Years Ended December 31, 2016, 2015, and 2014	Part II. Item 8.	419
Consolidated Statements of Cash Flows For the Years Ended December 31, 2016, 2015, and 2014	Part II. Item 8.	421
Consolidated Balance Sheets, December 31, 2016 and 2015	Part II. Item 8.	422
Consolidated Statements of Changes in Common Equity for the Years Ended December 31, 2016, 2015, and 2014	Part II. Item 8.	424
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	425

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System Energy Resources, Inc.
Management’s Financial Discussion and Analysis	Part II. Item 7.	426
Report of Independent Registered Public Accounting Firm		435
Income Statements For the Years Ended December 31, 2016, 2015, and 2014	Part II. Item 8.	436
Statements of Cash Flows For the Years Ended December 31, 2016, 2015, and 2014	Part II. Item 8.	437
Balance Sheets, December 31, 2016 and 2015	Part II. Item 8.	438
Statements of Changes in Common Equity for the Years Ended December 31, 2016, 2015, and 2014	Part II. Item 8.	440
Selected Financial Data - Five-Year Comparison	Part II. Item 6.	441
Properties	Part I. Item 2.	442
Legal Proceedings	Part I. Item 3.	442
Mine Safety Disclosures	Part I. Item 4.	442
Executive Officers of Entergy Corporation	Part I. and Part III. Item 10.	442
Market for Registrants’ Common Equity and Related Stockholder Matters	Part II. Item 5.	444
Selected Financial Data	Part II. Item 6.	446
Management’s Discussion and Analysis of Financial Condition and Results of Operations	Part II. Item 7.	446
Quantitative and Qualitative Disclosures About Market Risk	Part II. Item 7A.	446
Financial Statements and Supplementary Data	Part II. Item 8.	446
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	Part II. Item 9.	446
Controls and Procedures	Part II. Item 9A.	446
Attestation Report of Registered Public Accounting Firm	Part II. Item 9A.	448
Directors and Executive Officers of the Registrants	Part III. Item 10.	449
Executive Compensation	Part III. Item 11.	455
Security Ownership of Certain Beneficial Owners and Management	Part III. Item 12.	502
Certain Relationships and Related Transactions and Director Independence	Part III. Item 13.	506
Principal Accountant Fees and Services	Part III. Item 14.	507
Exhibits and Financial Statement Schedules	Part IV. Item 15.	510
Form 10-K Summary	Part IV. Item 16.	510
Signatures		511
Consents of Independent Registered Public Accounting Firm		518
Report of Independent Registered Public Accounting Firm		519
Index to Financial Statement Schedules		S-1
Exhibit Index		E-1

This combined Form 10-K is separately filed by Entergy Corporation and its six “Registrant Subsidiaries:” Entergy Arkansas, Inc., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., Entergy Texas, Inc., and System Energy Resources, Inc. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes representations only as to itself and makes no other representations whatsoever as to any other company.

The report should be read in its entirety as it pertains to each respective reporting company. No one section of the report deals with all aspects of the subject matter. Separate Item 6, 7, and 8 sections are provided for each reporting company, except for the Notes to the financial statements. The Notes to the financial statements for all of the reporting companies are combined. All Items other than 6, 7, and 8 are combined for the reporting companies.

iii

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FORWARD-LOOKING INFORMATION

In this combined report and from time to time, Entergy Corporation and the Registrant Subsidiaries each makes statements as a registrant concerning its expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Words such as “may,” “will,” “could,” “project,” “believe,” “anticipate,” “intend,” “expect,” “estimate,” “continue,” “potential,” “plan,” “predict,” “forecast,” and other similar words or expressions are intended to identify forward-looking statements but are not the only means to identify these statements. Although each of these registrants believes that these forward-looking statements and the underlying assumptions are reasonable, it cannot provide assurance that they will prove correct. Any forward-looking statement is based on information current as of the date of this combined report and speaks only as of the date on which such statement is made. Except to the extent required by the federal securities laws, these registrants undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.

Forward-looking statements involve a number of risks and uncertainties. There are factors that could cause actual results to differ materially from those expressed or implied in the forward-looking statements, including (a) those factors discussed or incorporated by reference in Item 1A. Risk Factors, (b) those factors discussed or incorporated by reference in Management’s Financial Discussion and Analysis, and (c) the following factors (in addition to others described elsewhere in this combined report and in subsequent securities filings):


•	resolution of pending and future rate cases and negotiations, including various performance-based rate discussions, Entergy’s utility supply plan, and recovery of fuel and purchased power costs;


•	long-term risks and uncertainties associated with the termination of the System Agreement in 2016, including the potential absence of federal authority to resolve certain issues among the Utility operating companies and their retail regulators;

•

regulatory and operating challenges and uncertainties and economic risks associated with the Utility operating companies’ participation in MISO, including the effect of current or projected MISO market rules and market and system conditions in the MISO markets, the allocation of MISO system transmission upgrade costs, and the effect of planning decisions that MISO makes with respect to future transmission investments by the Utility operating companies;


•	changes in utility regulation, including the beginning or end of retail and wholesale competition, the ability to recover net utility assets and other potential stranded costs, and the application of more stringent transmission reliability requirements or market power criteria by the FERC or the U.S. Department of Justice;


•	changes in the regulation or regulatory oversight of Entergy’s nuclear generating facilities and nuclear materials and fuel, including with respect to the planned potential or actual shutdown of nuclear generating facilities owned or operated by Entergy Wholesale Commodities, and the effects of new or existing safety or environmental concerns regarding nuclear power plants and nuclear fuel;


•	resolution of pending or future applications, and related regulatory proceedings and litigation, for license renewals or modifications or other authorizations required of nuclear generating facilities and the effect of public and political opposition on these applications, regulatory proceedings, and litigation;


•	the performance of and deliverability of power from Entergy’s generation resources, including the capacity factors at its nuclear generating facilities;


•	the operation and maintenance of Entergy’s nuclear generating facilities require the commitment of substantial human and capital resources that can result in increased costs and capital expenditures;


•	Entergy’s ability to develop and execute on a point of view regarding future prices of electricity, natural gas, and other energy-related commodities;


•	prices for power generated by Entergy’s merchant generating facilities and the ability to hedge, meet credit support requirements for hedges, sell power forward or otherwise reduce the market price risk associated with those facilities, including the Entergy Wholesale Commodities nuclear plants;


•	the prices and availability of fuel and power Entergy must purchase for its Utility customers, and Entergy’s ability to meet credit support requirements for fuel and power supply contracts;


•	volatility and changes in markets for electricity, natural gas, uranium, emissions allowances, and other energy-related commodities, and the effect of those changes on Entergy and its customers;

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FORWARD-LOOKING INFORMATION (Concluded)


•	changes in law resulting from federal or state energy legislation or legislation subjecting energy derivatives used in hedging and risk management transactions to governmental regulation;


•	changes in environmental laws and regulations or associated litigation, including requirements for reduced emissions of sulfur dioxide, nitrogen oxide, greenhouse gases, mercury, particulate matter, heat, and other regulated air and water emissions, and changes in costs of compliance with environmental laws and regulations;


•	the effects of changes in federal, state or local laws and regulations, and other governmental actions or policies, including changes in monetary, fiscal, tax, environmental, or energy policies;


•	uncertainty regarding the establishment of interim or permanent sites for spent nuclear fuel and nuclear waste storage and disposal and the level of spent fuel and nuclear waste disposal fees charged by the U.S. government or other providers related to such sites;


•	variations in weather and the occurrence of hurricanes and other storms and disasters, including uncertainties associated with efforts to remediate the effects of hurricanes, ice storms, or other weather events and the recovery of costs associated with restoration, including accessing funded storm reserves, federal and local cost recovery mechanisms, securitization, and insurance;


•	effects of climate change, including the potential for increases in sea levels or coastal land and wetland loss;


•	changes in the quality and availability of water supplies and the related regulation of water use and diversion;


•	Entergy’s ability to manage its capital projects and operation and maintenance costs;


•	Entergy’s ability to purchase and sell assets at attractive prices and on other attractive terms;


•	the economic climate, and particularly economic conditions in Entergy’s Utility service area and the Northeast United States and events and circumstances that could influence economic conditions in those areas, including power prices, and the risk that anticipated load growth may not materialize;


•	the effects of Entergy’s strategies to reduce tax payments;


•	changes in the financial markets and regulatory requirements for the issuance of securities, particularly as they affect access to capital and Entergy’s ability to refinance existing securities, execute share repurchase programs, and fund investments and acquisitions;


•	actions of rating agencies, including changes in the ratings of debt and preferred stock, changes in general corporate ratings, and changes in the rating agencies’ ratings criteria;


•	changes in inflation and interest rates;


•	the effect of litigation and government investigations or proceedings;


•	changes in technology, including with respect to new, developing, or alternative sources of generation;


•	the effects, including increased security costs, of threatened or actual terrorism, cyber-attacks or data security breaches, natural or man-made electromagnetic pulses that affect transmission or generation infrastructure, accidents, and war or a catastrophic event such as a nuclear accident or a natural gas pipeline explosion;


•	Entergy’s ability to attract and retain talented management and directors;


•	changes in accounting standards and corporate governance;


•	declines in the market prices of marketable securities and resulting funding requirements and the effects on benefits costs for Entergy’s defined benefit pension and other postretirement benefit plans;


•	future wage and employee benefit costs, including changes in discount rates and returns on benefit plan assets;


•	changes in decommissioning trust fund values or earnings or in the timing of, requirements for, or cost to decommission Entergy’s nuclear plant sites and the implementation of decommissioning of such sites following shutdown;


•	the decision to cease merchant power generation at all Entergy Wholesale Commodities nuclear power plants by as early as 2021, including the implementation of the planned shutdown of Pilgrim, Palisades, Indian Point 2, and Indian Point 3 and the planned shutdown or sale of FitzPatrick;


•	the effectiveness of Entergy’s risk management policies and procedures and the ability and willingness of its counterparties to satisfy their financial and performance commitments;


•	factors that could lead to impairment of long-lived assets; and


•	the ability to successfully complete strategic transactions Entergy may undertake, including mergers, acquisitions, or divestitures, regulatory or other limitations imposed as a result of any such strategic transaction, and the success of the business following any such strategic transaction.

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DEFINITIONS

Certain abbreviations or acronyms used in the text and notes are defined below:



Abbreviation or Acronym	Term

AFUDC	Allowance for Funds Used During Construction
ALJ	Administrative Law Judge
ANO 1 and 2	Units 1 and 2 of Arkansas Nuclear One (nuclear), owned by Entergy Arkansas
APSC	Arkansas Public Service Commission
ASLB	Atomic Safety and Licensing Board, the board within the NRC that conducts hearings and performs other regulatory functions that the NRC authorizes
ASU	Accounting Standards Update issued by the FASB
Board	Board of Directors of Entergy Corporation
Cajun	Cajun Electric Power Cooperative, Inc.
capacity factor	Actual plant output divided by maximum potential plant output for the period
City Council	Council of the City of New Orleans, Louisiana
D. C. Circuit	U.S. Court of Appeals for the District of Columbia Circuit
DOE	United States Department of Energy
Entergy	Entergy Corporation and its direct and indirect subsidiaries
Entergy Corporation	Entergy Corporation, a Delaware corporation
Entergy Gulf States, Inc.	Predecessor company for financial reporting purposes to Entergy Gulf States Louisiana that included the assets and business operations of both Entergy Gulf States Louisiana and Entergy Texas
Entergy Gulf States Louisiana	Entergy Gulf States Louisiana, L.L.C., a Louisiana limited liability company formally created as part of the jurisdictional separation of Entergy Gulf States, Inc. and the successor company to Entergy Gulf States, Inc. for financial reporting purposes. The term is also used to refer to the Louisiana jurisdictional business of Entergy Gulf States, Inc., as the context requires. Effective October 1, 2015, the business of Entergy Gulf States Louisiana was combined with Entergy Louisiana.
Entergy Louisiana	Entergy Louisiana, LLC, a Texas limited liability company formally created as part of the combination of Entergy Gulf States Louisiana and the company formerly known as Entergy Louisiana, LLC (Old Entergy Louisiana) into a single public utility company and the successor to Old Entergy Louisiana for financial reporting purposes.
Entergy Texas	Entergy Texas, Inc., a Texas corporation formally created as part of the jurisdictional separation of Entergy Gulf States, Inc. The term is also used to refer to the Texas jurisdictional business of Entergy Gulf States, Inc., as the context requires.
Entergy Wholesale Commodities	Entergy’s non-utility business segment primarily comprised of the ownership, operation, and decommissioning of nuclear power plants, the ownership of interests in non-nuclear power plants, and the sale of the electric power produced by its operating power plants to wholesale customers
EPA	United States Environmental Protection Agency
ERCOT	Electric Reliability Council of Texas
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FitzPatrick	James A. FitzPatrick Nuclear Power Plant (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment
Grand Gulf	Unit No. 1 of Grand Gulf Nuclear Station (nuclear), 90% owned or leased by System Energy

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DEFINITIONS (Continued)



Abbreviation or Acronym	Term

GWh	Gigawatt-hour(s), which equals one million kilowatt-hours
Independence	Independence Steam Electric Station (coal), owned 16% by Entergy Arkansas, 25% by Entergy Mississippi, and 7% by Entergy Power, LLC
Indian Point 2	Unit 2 of Indian Point Energy Center (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment
Indian Point 3	Unit 3 of Indian Point Energy Center (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment
IRS	Internal Revenue Service
ISO	Independent System Operator
kV	Kilovolt
kW	Kilowatt, which equals one thousand watts
kWh	Kilowatt-hour(s)
LDEQ	Louisiana Department of Environmental Quality
LPSC	Louisiana Public Service Commission
Mcf	1,000 cubic feet of gas
MISO	Midcontinent Independent System Operator, Inc., a regional transmission organization
MMBtu	One million British Thermal Units
MPSC	Mississippi Public Service Commission
MW	Megawatt(s), which equals one thousand kilowatts
MWh	Megawatt-hour(s)
Nelson Unit 6	Unit No. 6 (coal) of the Nelson Steam Electric Generating Station, 70% of which is co-owned by Entergy Louisiana (57.5%) and Entergy Texas (42.5%) and 10.9% of which is owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment
Net debt to net capital ratio	Gross debt less cash and cash equivalents divided by total capitalization less cash and cash equivalents
Net MW in operation	Installed capacity owned and operated
NRC	Nuclear Regulatory Commission
NYPA	New York Power Authority
Palisades	Palisades Nuclear Plant (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment
Parent & Other	The portions of Entergy not included in the Utility or Entergy Wholesale Commodities segments, primarily consisting of the activities of the parent company, Entergy Corporation
Pilgrim	Pilgrim Nuclear Power Station (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment
PPA	Purchased power agreement or power purchase agreement
PRP	Potentially responsible party (a person or entity that may be responsible for remediation of environmental contamination)
PUCT	Public Utility Commission of Texas
Registrant Subsidiaries	Entergy Arkansas, Inc., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., Entergy Texas, Inc., and System Energy Resources, Inc.

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DEFINITIONS (Concluded)



Abbreviation or Acronym	Term

River Bend	River Bend Station (nuclear), owned by Entergy Louisiana
RTO	Regional transmission organization
SEC	Securities and Exchange Commission
System Agreement	Agreement, effective January 1, 1983, as modified, among the Utility operating companies relating to the sharing of generating capacity and other power resources. The agreement terminated effective August 2016.
System Energy	System Energy Resources, Inc.
TWh	Terawatt-hour(s), which equals one billion kilowatt-hours
Unit Power Sales Agreement	Agreement, dated as of June 10, 1982, as amended and approved by FERC, among Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy, relating to the sale of capacity and energy from System Energy’s share of Grand Gulf
Utility	Entergy’s business segment that generates, transmits, distributes, and sells electric power, with a small amount of natural gas distribution
Utility operating companies	Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas
Vermont Yankee	Vermont Yankee Nuclear Power Station (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment, which ceased power production in December 2014
Waterford 3	Unit No. 3 (nuclear) of the Waterford Steam Electric Station, 100% owned or leased by Entergy Louisiana
weather-adjusted usage	Electric usage excluding the effects of deviations from normal weather
White Bluff	White Bluff Steam Electric Generating Station, 57% owned by Entergy Arkansas

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ENTERGY CORPORATION AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Entergy operates primarily through two business segments: Utility and Entergy Wholesale Commodities.


•	The Utility business segment includes the generation, transmission, distribution, and sale of electric power in portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans; and operation of a small natural gas distribution business.

•

The Entergy Wholesale Commodities business segment includes the ownership, operation, and decommissioning of nuclear power plants located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. Entergy Wholesale Commodities also provides services to other nuclear power plant owners and owns interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. See “Entergy Wholesale Commodities Exit from the Merchant Power Business” below for discussion of the operation and planned shutdown or sale of each of the Entergy Wholesale Commodities nuclear power plants.

Following are the percentages of Entergy’s consolidated revenues and net income generated by its operating segments and the percentage of total assets held by them.



	% of Revenue			% of Net Income (Loss)						% of Total Assets
Segment	2016	2015	2014	2016		2015		2014		2016		2015		2014
Utility	83	82	78	204		711		88		89		86		82
Entergy Wholesale Commodities	17	18	22	(265	)	(680	)	31		15		18		22
Parent & Other	—	—	—	(39	)	(131	)	(19	)	(4	)	(4	)	(4	)

See Note 13 to the financial statements for further financial information regarding Entergy’s business segments.

Net income (loss) for 2016 includes $2,836 million ($1,829 million net-of-tax) of impairment and related charges primarily to write down the carrying values of the Entergy Wholesale Commodities’ Palisades, Indian Point 2, and Indian Point 3 plants and related assets to their fair values. Net income (loss) for 2015 includes $2,036 million ($1,317 million net-of-tax) of impairment and related charges primarily to write down the carrying values of the Entergy Wholesale Commodities’ FitzPatrick, Pilgrim, and Palisades plants and related assets to their fair values. See Note 14 to the financial statements for further discussion of the impairment and related charges.

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Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

Results of Operations

2016 Compared to 2015

Following are income statement variances for Utility, Entergy Wholesale Commodities, Parent & Other, and Entergy comparing 2016 to 2015 showing how much the line item increased or (decreased) in comparison to the prior period.



	Utility			Entergy Wholesale Commodities			Parent & Other (a)			Entergy
	(In Thousands)
2015 Consolidated Net Income (Loss)		$1,114,516			($1,065,657	)		($205,593	)		($156,734	)

Net revenue (operating revenue less fuel expense, purchased power, and other regulatory charges/credits)	350,528			(123,791		)	(33		)	226,704
Other operation and maintenance	(83,265		)	15,269			9,726			(58,270		)
Asset write-offs, impairments, and related charges	(68,672		)	799,403			—			730,731
Taxes other than income taxes	(10,229		)	(16,259		)	(432		)	(26,920		)
Depreciation and amortization	49,600			(39,180		)	(509		)	9,911
Gain on sale of asset	—			(154,037		)	—			(154,037		)
Other income	15,153			8,666			4,281			28,100
Interest expense	14,414			(3,930		)	12,417			22,901
Other expenses	19,589			(15,074		)	—			4,515
Income taxes	407,627			(581,924		)	(35		)	(174,332		)
2016 Consolidated Net Income (Loss)		$1,151,133			($1,493,124	)		($222,512	)		($564,503	)


(a)	Parent & Other includes eliminations, which are primarily intersegment activity.

Refer to “SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES” which accompanies Entergy Corporation’s financial statements in this report for further information with respect to operating statistics.

Results of operations for 2016 include $2,836 million ($1,829 million net-of-tax) of impairment and related charges primarily to write down the carrying values of the Entergy Wholesale Commodities’ Palisades, Indian Point 2, and Indian Point 3 plants and related assets to their fair values. See Note 14 to the financial statements for further discussion of the impairment and related charges. Results of operations for 2016 also include a reduction of income tax expense, net of unrecognized tax benefits, of $238 million as a result of a tax election to treat a subsidiary that owns one of the Entergy Wholesale Commodities nuclear power plants as a corporation for federal income tax purposes; income tax benefits as a result of the settlement of the 2010-2011 IRS audit, including a $75 million tax benefit recognized by Entergy Louisiana related to the treatment of the Vidalia purchased power agreement and a $54 million net benefit recognized by Entergy Louisiana related to the treatment of proceeds received in 2010 for the financing of Hurricane Gustav and Hurricane Ike storm costs pursuant to Louisiana Act 55; and a reduction in expenses of $100 million ($64 million net-of-tax) due to the effects of recording in 2016 the final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. See Note 3 to the financial statements for additional discussion of the income tax items. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.

Results of operations for 2015 include $2,036 million ($1,317 million net-of-tax) of impairment and related charges primarily to write down the carrying values of the Entergy Wholesale Commodities’ FitzPatrick, Pilgrim, and

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Management’s Financial Discussion and Analysis

Palisades plants and related assets to their fair values. See Note 14 to the financial statements for further discussion of the impairment and related charges. As a result of the Entergy Louisiana and Entergy Gulf States Louisiana business combination, results of operations for 2015 also include two items that occurred in October 2015: 1) a deferred tax asset and resulting net increase in tax basis of approximately $334 million and 2) a regulatory liability of $107 million ($66 million net-of-tax) as a result of customer credits to be realized by electric customers of Entergy Louisiana, consistent with the terms of the stipulated settlement in the business combination proceeding. See Note 2 to the financial statements for further discussion of the business combination and customer credits. Results of operations for 2015 also include the sale in December 2015 of the 583 MW Rhode Island State Energy Center for a realized gain of $154 million ($100 million net-of-tax) on the sale and the $77 million ($47 million net-of-tax) write-off and regulatory charges to recognize that a portion of the assets associated with the Waterford 3 replacement steam generator project is no longer probable of recovery. See Note 14 to the financial statements for further discussion of the Rhode Island State Energy Center sale. See Note 2 to the financial statements for further discussion of the Waterford 3 write-off.

Net Revenue

Utility

Following is an analysis of the change in net revenue comparing 2016 to 2015.



	Amount
	(In Millions)

2015 net revenue		$5,829
Retail electric price	289
Louisiana business combination customer credits	107
Volume/weather	14
Louisiana Act 55 financing savings obligation	(17		)
Other	(43		)
2016 net revenue		$6,179

The retail electric price variance is primarily due to:

•

an increase in base rates at Entergy Arkansas, as approved by the APSC. The new rates were effective February 24, 2016 and began billing with the first billing cycle of April 2016. The increase includes an interim base rate adjustment surcharge, effective with the first billing cycle of April 2016, to recover the incremental revenue requirement for the period February 24, 2016 through March 31, 2016. A significant portion of the increase is related to the purchase of Power Block 2 of the Union Power Station;


•	an increase in the purchased power and capacity acquisition cost recovery rider for Entergy New Orleans, as approved by the City Council, effective with the first billing cycle of March 2016, primarily related to the purchase of Power Block 1 of the Union Power Station;


•	an increase in formula rate plan revenues for Entergy Louisiana, implemented with the first billing cycle of March 2016, to collect the estimated first-year revenue requirement related to the purchase of Power Blocks 3 and 4 of the Union Power Station; and


•	an increase in revenues at Entergy Mississippi, as approved by the MPSC, effective with the first billing cycle of July 2016, and an increase in revenues collected through the storm damage rider.

See Note 2 to the financial statements for further discussion of the rate proceedings. See Note 14 to the financial statements for discussion of the Union Power Station purchase.

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Management’s Financial Discussion and Analysis

combination. Consistent with the terms of the stipulated settlement in the business combination proceeding, electric customers of Entergy Louisiana will realize customer credits associated with the business combination; accordingly, in October 2015, Entergy recorded a regulatory liability of $107 million ($66 million net-of-tax). These costs are being amortized over a nine-year period beginning December 2015. See Note 2 to the financial statements for further discussion of the business combination and customer credits.

The volume/weather variance is primarily due to the effect of more favorable weather during the unbilled period and an increase in industrial usage, partially offset by the effect of less favorable weather on residential sales. The increase in industrial usage is primarily due to expansion projects, primarily in the chemicals industry, and increased demand from new customers, primarily in the industrial gases industry.

The Louisiana Act 55 financing savings obligation variance results from a regulatory charge for tax savings to be shared with customers per an agreement approved by the LPSC. The tax savings results from the 2010-2011 IRS audit settlement on the treatment of the Louisiana Act 55 financing of storm costs for Hurricane Gustav and Hurricane Ike. See Note 3 to the financial statements for additional discussion of the settlement and benefit sharing.

Included in Other is a provision of $23 million recorded in 2016 related to the settlement of the Waterford 3 replacement steam generator prudence review proceeding, offset by a provision of $32 million recorded in 2015 related to the uncertainty at that time associated with the resolution of the Waterford 3 replacement steam generator prudence review proceeding. See Note 2 to the financial statements for a discussion of the Waterford 3 replacement steam generator prudence review proceeding.

Entergy Wholesale Commodities

Following is an analysis of the change in net revenue comparing 2016 to 2015.



	Amount
	(In Millions)

2015 net revenue		$1,666
Nuclear realized price changes	(149		)
Rhode Island State Energy Center	(44		)
Nuclear volume	(36		)
FitzPatrick reimbursement agreement	41
Nuclear fuel expenses	68
Other	(4		)
2016 net revenue		$1,542

As shown in the table above, net revenue for Entergy Wholesale Commodities decreased by approximately $124 million in 2016 primarily due to:

•

lower realized wholesale energy prices and lower capacity prices, although the average revenue per MWh shown in the table below for the nuclear fleet is slightly higher because it includes revenues from the FitzPatrick reimbursement agreement with Exelon, the amortization of the Palisades below-market PPA, and Vermont Yankee capacity revenue. The effect of the amortization of the Palisades below-market PPA and Vermont Yankee capacity revenue on the net revenue variance from 2015 to 2016 is minimal;


•	the sale of the Rhode Island State Energy Center in December 2015. See Note 14 to the financial statements for further discussion of the Rhode Island State Energy Center sale; and


•	lower volume in the Entergy Wholesale Commodities nuclear fleet resulting from more refueling outage days in 2016 as compared to 2015 and larger exercise of resupply options in 2016 as compared to 2015. See “Nuclear

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Management’s Financial Discussion and Analysis

Matters - Indian Point 2 Outage” below for discussion of the extended Indian Point 2 outage in the second quarter 2016.

The decrease was partially offset by:

•

an increase resulting from the reimbursement agreement with Exelon pursuant to which Exelon is reimbursing Entergy for specified out-of-pocket costs associated with preparing for the refueling and operation of FitzPatrick that otherwise would have been avoided had Entergy shut down FitzPatrick in January 2017. Revenues received from Exelon under the reimbursement agreement are offset in nuclear fuel expenses and other operation and maintenance expenses and have no material effect on net income. See “Entergy Wholesale Commodities Exit from the Merchant Power Business - Planned Sale of FitzPatrick” below for further discussion of the reimbursement agreement; and


•	a decrease in nuclear fuel expenses primarily related to the impairments of the FitzPatrick, Pilgrim, and Palisades plants and related assets. See Note 14 to the financial statements for discussion of the impairments.

Following are key performance measures for Entergy Wholesale Commodities for 2016 and 2015.



	2016	2015
Owned capacity (MW) (a)	4,800	4,880
GWh billed	35,881	39,745
Average revenue per MWh	$51.55	$51.88

Entergy Wholesale Commodities Nuclear Fleet
Capacity factor	87%	91%
GWh billed	33,551	35,859
Average revenue per MWh	$51.90	$51.49
Refueling Outage Days:
FitzPatrick	—	—
Indian Point 2	102	—
Indian Point 3	—	23
Palisades	—	32
Pilgrim	—	34


(a)	The reduction in owned capacity is due to Entergy’s sale of its 50% membership interest in Top Deer Wind Ventures, LLC in November 2016. See Note 14 to the financial statements for discussion of the sale.

Other Income Statement Items

Utility

Other operation and maintenance expenses decreased from $2,443 million for 2015 to $2,360 million for 2016 primarily due to:

•

a decrease of $78 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs;


•	the effects of recording final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $19 million of spent nuclear

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Management’s Financial Discussion and Analysis

fuel storage costs previously recorded as other operation and maintenance expense. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation;

•

the deferral in 2016 of $8 million of previously-incurred costs related to ANO post-Fukushima compliance and $10 million of previously-incurred costs related to ANO flood barrier compliance, as approved by the APSC in February 2016 as part of the Entergy Arkansas 2015 rate case settlement. These costs are being amortized over a ten-year period beginning March 2016. See Note 2 to the financial statements for further discussion of the rate case settlement; and


•	a decrease of $13 million in energy efficiency costs, including the effects of true-ups to energy efficiency filings for fixed costs to be collected from customers and incentives recognized as a result of participation in energy efficiency programs.

The decrease was partially offset by an increase of $61 million in nuclear generation expenses primarily due to higher nuclear labor costs, including contract labor, and an overall higher scope of work done during plant outages in 2016 as compared to prior year.

The asset write-offs, impairments, and related charges variance is due to the following activity:


•	the $45 million ($28 million net-of-tax) write-off in 2015 to recognize that a portion of the assets associated with the Waterford 3 replacement steam generator project was no longer probable of recovery; and


•	the $23.5 million ($15.3 million net-of-tax) write-off in 2015 of the regulatory asset associated with the Spindletop gas storage facility as a result of the approval of the System Agreement termination settlement agreement.

See Note 2 to the financial statements for further discussion of the asset write-offs.

Depreciation and amortization expenses increased primarily due to additions to plant in service, including the Union Power Station purchased in March 2016, partially offset by the effects of recording the final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $11 million in 2016 of spent nuclear fuel storage costs previously recorded as depreciation. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.

Other expenses increased primarily due to an increase in nuclear refueling outage expenses as a result of amortization of higher costs associated with refueling outages and increases in decommissioning expenses in 2016 primarily due to revised decommissioning cost studies in 2015 for Grand Gulf and Waterford 3. See Note 9 to the financial statements for further discussion of the revised decommissioning cost studies.

Entergy Wholesale Commodities

Other operation and maintenance expenses increased from $899 million for 2015 to $915 million for 2016 primarily due to:


•	an increase of $60 million in severance and retention costs related to the planned shutdown or sale of the Pilgrim and FitzPatrick plants. See “Entergy Wholesale Commodities Exit From the Merchant Power Business” below and Note 14 to the financial statements for discussion of the decisions to cease operations of the plants;


•	$41 million associated with preparing to refuel FitzPatrick in January 2017. Exelon reimbursed Entergy for these costs in accordance with the reimbursement agreement discussed in “Entergy Wholesale Commodities Exit From the Merchant Power Business - Planned Sale of FitzPatrick” below; and


•	an increase of $26 million in costs related to Pilgrim’s response to a planned NRC enhanced inspection as a result of the NRC placing Pilgrim in its “multiple/repetitive degraded cornerstone column” (Column 4) of its Reactor Oversight Process Action Matrix in September 2015. See Note 8 to the financial statements for further discussion of the NRC’s decision and Pilgrim’s response.

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Management’s Financial Discussion and Analysis

The increase was partially offset by:

•

the effects of recording the final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $60 million in 2016 compared to the reimbursement of approximately $2 million in 2015 of spent nuclear fuel storage costs previously recorded as other operation and maintenance expenses. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation;


•	a decrease of $32 million as a result of the sale of the Rhode Island State Energy Center in December 2015. See Note 14 to the financial statements for further discussion of the Rhode Island State Energy Center sale; and

•

a decrease of $21 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs.

The asset write-offs, impairments, and related charges variance is due to $2,836 million ($1,829 million net-of-tax) in 2016 of impairment and related charges primarily to write down the carrying values of the Entergy Wholesale Commodities’ Palisades, Indian Point 2, and Indian Point 3 plants and related assets to their fair values, partially offset by $2,036 million ($1,317 million net-of-tax) in 2015 of impairment and related charges primarily to write down the carrying values of the Entergy Wholesale Commodities’ FitzPatrick, Pilgrim, and Palisades plants and related assets to their fair values. See Note 14 to the financial statements for further discussion of these charges.

Depreciation and amortization expenses decreased primarily due to:


•	decreases in depreciable asset balances as a result of the impairments of the FitzPatrick, Pilgrim, and Palisades plants. See Note 14 to the financial statements for further discussion of the impairments;

•

the effects of recording the final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $15 million in 2016 compared to the reimbursement of approximately $4 million in 2015 of spent nuclear fuel storage costs previously recorded as depreciation. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and


•	a decrease in depreciable asset balances as a result of the sale of the Rhode Island State Energy Center in December 2015. See Note 14 to the financial statements for further discussion of the Rhode Island State Energy Center sale.

The gain on sale of asset resulted from the sale in December 2015 of the 583 MW Rhode Island State Energy Center in Johnston, Rhode Island, a business wholly-owned by Entergy in the Entergy Wholesale Commodities segment. Entergy sold Rhode Island State Energy Center for approximately $490 million and realized a pre-tax gain of $154 million on the sale. See Note 14 to the financial statements for further discussion of the Rhode Island State Energy Center sale.

Other expenses decreased primarily due to the reduction in deferred refueling outage amortization costs related to the impairments of the FitzPatrick, Pilgrim, and Palisades plants and related assets, partially offset by increases in decommissioning expenses primarily as a result of a trust transfer agreement Entergy entered into with NYPA in August 2016 to transfer the decommissioning trusts and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants to Entergy and a revision to the estimated decommissioning cost liability for the Entergy Wholesale Commodities’ Pilgrim plant as a result of a revised decommissioning cost study in 2015. See Note 14 to the financial statements for further discussion of the impairments and related charges and Note 9 to the financial statements for further discussion of nuclear decommissioning costs.

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Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

Income Taxes

See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates, and for additional discussion regarding income taxes.

The effective income tax rate for 2016 was 59.1%. The difference in the effective income tax rate versus the statutory rate of 35% for 2016 was primarily due to a tax election to treat a subsidiary that owns one of the Entergy Wholesale Commodities nuclear power plants as a corporation for federal income tax purposes and the reversal of a portion of the provision for uncertain tax positions as a result of the settlement of the 2010-2011 IRS audit, partially offset by state income taxes and certain book and tax differences related to utility plant items. See Note 3 to the financial statements for additional discussion of the tax election, the tax settlement, and a reconciliation of the federal statutory rate of 35% to the effective income tax rate.

The effective income tax rate for 2015 was 80.4%. The difference in the effective income tax rate versus the statutory rate of 35% for 2015 was primarily due to the tax effects of the Louisiana business combination. See Note 3 to the financial statements for further discussion of the tax effects of the Louisiana business combination and a reconciliation of the federal statutory rate of 35% to the effective income tax rate.

2015 Compared to 2014

Following are income statement variances for Utility, Entergy Wholesale Commodities, Parent & Other, and Entergy comparing 2015 to 2014 showing how much the line item increased or (decreased) in comparison to the prior period.



	Utility			Entergy Wholesale Commodities			Parent & Other			Entergy
	(In Thousands)
2014 Consolidated Net Income (Loss)		$846,496			$294,521			($180,760	)		$960,257

Net revenue (operating revenue less fuel expense, purchased power, and other regulatory charges/credits)	94,195			(558,060		)	(1,885		)	(465,750		)
Other operation and maintenance	166,812			(123,645		)	1,278			44,445
Asset write-offs, impairments, and related charges	(3,553		)	1,928,707			—			1,925,154
Taxes other than income taxes	35,010			(20,196		)	2			14,816
Depreciation and amortization	57,076			(36,892		)	(1,546		)	18,638
Gain on sale of asset	—			154,037			—			154,037
Other income	(3,993		)	(4,899		)	(18,607		)	(27,499		)
Interest expense	11,403			10,142			(5,583		)	15,962
Other expenses	10,821			(19,533		)	—			(8,712		)
Income taxes	(455,387		)	(787,327		)	10,190			(1,232,524		)
2015 Consolidated Net Income (Loss)		$1,114,516			($1,065,657	)		($205,593	)		($156,734	)

Results of operations for 2015 include $2,036 million ($1,317 million net-of-tax) of impairment and related charges to write down the carrying values of certain Entergy Wholesale Commodities’ plants and related assets to their fair values. See Note 14 to the financial statements for further discussion of the impairment and related charges. As

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Management’s Financial Discussion and Analysis

a result of the Entergy Louisiana and Entergy Gulf States Louisiana business combination, results of operations for 2015 also include two items that occurred in October 2015: 1) a deferred tax asset and resulting net increase in tax basis of approximately $334 million and 2) a regulatory liability of $107 million ($66 million net-of-tax) as a result of customer credits to be realized by electric customers of Entergy Louisiana, consistent with the terms of the stipulated settlement in the business combination proceeding. See Note 2 to the financial statements for further discussion of the business combination and customer credits. Results of operations for 2015 also include the sale in December 2015 of the 583 MW Rhode Island State Energy Center for a realized gain of $154 million ($100 million net-of-tax) on the sale and the $77 million ($47 million net-of-tax) write-off and regulatory charges to recognize that a portion of the assets associated with the Waterford 3 replacement steam generator project is no longer probable of recovery. See Note 14 to the financial statements for further discussion of the Rhode Island State Energy Center sale. See Note 2 to the financial statements for further discussion of the Waterford 3 write-off.

Results of operations for 2014 include $154 million ($100 million net-of-tax) of charges related to Vermont Yankee primarily resulting from the effects of an updated decommissioning cost study completed in the third quarter 2014 along with reassessment of the assumptions regarding the timing of decommissioning cash flows and severance and employee retention costs. See Note 14 to the financial statements for further discussion of the charges. Results of operations for 2014 also include the $56.2 million ($36.7 million net-of-tax) write-off in 2014 of Entergy Mississippi’s regulatory asset associated with new nuclear generation development costs as a result of a joint stipulation entered into with the Mississippi Public Utilities Staff, subsequently approved by the MPSC, in which Entergy Mississippi agreed not to pursue recovery of the costs deferred by an MPSC order in the new nuclear generation docket. See Note 2 to the financial statements for further discussion of the new nuclear generation development costs and the joint stipulation.

Net Revenue

Utility

Following is an analysis of the change in net revenue comparing 2015 to 2014.



	Amount
	(In Millions)

2014 net revenue		$5,735
Retail electric price	187
Volume/weather	95
Waterford 3 replacement steam generator provision	(32		)
MISO deferral	(35		)
Louisiana business combination customer credits	(107		)
Other	(14		)
2015 net revenue		$5,829

The retail electric price variance is primarily due to:


•	formula rate plan increases at Entergy Louisiana, as approved by the LPSC, effective December 2014 and January 2015;


•	an increase in energy efficiency rider revenue primarily due to increases in the energy efficiency rider at Entergy Arkansas, as approved by the APSC, effective July 2015 and July 2014, and new energy efficiency riders at Entergy Louisiana and Entergy Mississippi that began in the fourth quarter 2014; and


•	an annual net rate increase at Entergy Mississippi of $16 million, effective February 2015, as a result of the MPSC order in the June 2014 rate case.

See Note 2 to the financial statements for a discussion of rate and regulatory proceedings.

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Management’s Financial Discussion and Analysis

The volume/weather variance is primarily due to an increase of 1,402 GWh, or 1%, in billed electricity usage, including an increase in industrial usage and the effect of more favorable weather. The increase in industrial sales was primarily due to expansion in the chemicals industry and the addition of new customers, partially offset by decreased demand primarily due to extended maintenance outages for existing chemicals customers.

The Waterford 3 replacement steam generator provision is due to a regulatory charge of approximately $32 million recorded in 2015 related to the uncertainty associated with the resolution of the Waterford 3 replacement steam generator project. See Note 2 to the financial statements for a discussion of the Waterford 3 replacement steam generator prudence review proceeding.

The MISO deferral variance is primarily due to the deferral in 2014 of non-fuel MISO-related charges, as approved by the LPSC and the MPSC. The deferral of non-fuel MISO-related charges is partially offset in other operation and maintenance expenses. See Note 2 to the financial statements for further discussion of the recovery of non-fuel MISO-related charges.

The Louisiana business combination customer credits variance is due to a regulatory liability of $107 million recorded by Entergy in October 2015 as a result of the Entergy Gulf States Louisiana and Entergy Louisiana business combination. Consistent with the terms of the stipulated settlement in the business combination proceeding, electric customers of Entergy Louisiana will realize customer credits associated with the business combination; accordingly, in October 2015, Entergy recorded a regulatory liability of $107 million ($66 million net-of-tax). See Note 2 to the financial statements for further discussion of the business combination and customer credits.

Entergy Wholesale Commodities

Following is an analysis of the change in net revenue comparing 2015 to 2014.



	Amount
	(In Millions)

2014 net revenue		$2,224
Nuclear realized price changes	(310		)
Vermont Yankee shutdown in December 2014	(305		)
Nuclear volume, excluding Vermont Yankee effect	20
Other	37
2015 net revenue		$1,666

As shown in the table above, net revenue for Entergy Wholesale Commodities decreased by approximately $558 million in 2016 primarily due to:


•	lower realized wholesale energy prices, primarily due to significantly higher Northeast market power prices in 2014, and lower capacity prices in 2015; and


•	a decrease in net revenue as a result of Vermont Yankee ceasing power production in December 2014.

The decrease was partially offset by higher volume in the Entergy Wholesale Commodities nuclear fleet, excluding Vermont Yankee, resulting from fewer refueling outage days in 2015 as compared to 2014, partially offset by more unplanned outage days in 2015 as compared to 2014.

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Management’s Financial Discussion and Analysis

Following are key performance measures for Entergy Wholesale Commodities for 2015 and 2014.



	2015	2014
Owned capacity (MW) (a)	4,880	6,068
GWh billed	39,745	44,424
Average revenue per MWh	$51.88	$60.84

Entergy Wholesale Commodities Nuclear Fleet
Capacity factor	91%	91%
GWh billed	35,859	40,253
Average revenue per MWh	$51.49	$60.35
Refueling Outage Days:
FitzPatrick	—	44
Indian Point 2	—	24
Indian Point 3	23	—
Palisades	32	56
Pilgrim	34	—


(a)	The reduction in owned capacity is due to the retirement of the 605 MW Vermont Yankee plant in December 2014 and the sale of the 583 MW Rhode Island State Energy Center in December 2015.

Other Income Statement Items

Utility

Other operation and maintenance expenses increased from $2,276 million for 2014 to $2,443 million for 2015 primarily due to:

•

an increase of $59 million in nuclear generation expenses primarily due to an increase in regulatory compliance costs, higher labor costs, and an overall higher scope of work done in 2015. The increase in regulatory compliance costs is primarily related to additional NRC inspection activities in 2015 as a result of the NRC’s March 2015 decision to move ANO into the “multiple/repetitive degraded cornerstone column” of the NRC’s reactor oversight process action matrix. See “ANO Damage, Outage, and NRC Reviews” below for a discussion of the ANO stator incident and subsequent NRC reviews;

•

an increase of $28 million in compensation and benefits costs primarily due to an increase in net periodic pension and other postretirement benefit costs as a result of lower discount rates and changes in retirement and mortality assumptions, partially offset by a decrease in the accrual for incentive-based compensation. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs;


•	an increase of $27 million in energy efficiency costs, including the effects of true-ups to energy efficiency filings for fixed costs to be collected from customers;


•	an increase of $26 million in distribution expenses primarily due to higher vegetation maintenance and higher labor costs in 2015 as compared to 2014; and


•	an increase of $24 million in transmission expenses primarily due to an increase in the amount of transmission costs allocated by MISO. See Note 2 to the financial statements for further information on the recovery of these costs.

The increase was partially offset by a decrease of $23 million in storm damage provisions primarily at Entergy Mississippi. See Note 2 to the financial statements for a discussion of storm cost recovery.

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The asset write-offs, impairments, and related charges variance is due to the following activity:

•

the $45 million ($28 million net-of-tax) write-off in 2015 to recognize that a portion of the assets associated with the Waterford 3 replacement steam generator project was no longer probable of recovery and the $16 million ($11 million net-of-tax) write-off in 2014 due to the uncertainty at the time associated with the resolution of the Waterford 3 replacement steam generator project prudence review;


•	the $23.5 million ($15.3 million net-of-tax) write-off in 2015 of the regulatory asset associated with the Spindletop gas storage facility as a result of the approval of the System Agreement termination settlement agreement; and


•	the $56 million ($37 million net-of-tax) write-off in 2014 of Entergy Mississippi’s regulatory asset associated with new nuclear generation development costs.

See Note 2 to the financial statements for further discussion of the asset write-offs.

Taxes other than income taxes increased primarily due to increases in ad valorem taxes, payroll taxes, and franchise taxes.

Depreciation and amortization expenses increased primarily due to additions to plant in service, including the Ninemile Unit 6 project, which was placed in service in December 2014, and higher depreciation rates at Entergy Mississippi effective February 2015, as approved by the MPSC.

Interest expense increased primarily due to net debt issuances in the fourth quarter 2014 by certain Utility operating companies including the issuance by Entergy Louisiana in November 2014 of $250 million of 4.95% Series first mortgage bonds due January 2045 and the issuance by Entergy Arkansas in December 2014 of $250 million of 4.95% Series first mortgage bonds due December 2044.

Other expenses increased primarily due to increases in decommissioning expenses in 2015 as a result of revised decommissioning cost studies in 2014 for Grand Gulf, ANO 1, ANO 2, and Waterford 3. See Note 9 to the financial statements for further discussion of the revised decommissioning cost studies.

Entergy Wholesale Commodities

Other operation and maintenance expenses decreased from $1,023 million for 2014 to $899 million for 2015 primarily due to the shutdown of Vermont Yankee, which ceased power production in December 2014. The decrease was partially offset by an increase of $12 million in compensation and benefits costs primarily due to an increase in net periodic pension and other postretirement benefit costs as a result of lower discount rates and changes in retirement and mortality assumptions, partially offset by a decrease in the accrual for incentive-based compensation. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs.

The asset write-offs, impairments, and related charges variance is primarily due to $2,036 million ($1,317 million net-of-tax) in 2015 of impairment and related charges to write down the carrying values of certain Entergy Wholesale Commodities’ plants and related assets to their fair values, partially offset by $107 million ($69 million net-of-tax) in 2014 of impairment charges related to Vermont Yankee primarily resulting from the effects of an updated decommissioning cost study completed in the third quarter 2014. See Note 14 to the financial statements for further discussion of these charges.

Taxes other than income taxes decreased primarily due to the shutdown of Vermont Yankee, which ceased power production in December 2014.

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Depreciation and amortization expenses decreased primarily due to decreases in depreciable asset balances as a result of the shutdown of Vermont Yankee, which ceased power production in December 2014. See Note 14 to the financial statements for further discussion of impairment of long-lived assets.

Other income decreased primarily due to $37 million ($24 million net-of-tax) in 2015 of impairment and related charges resulting from the write-down of the carrying values of the generating assets of Entergy’s equity method investee Top Deer Wind Ventures, LLC to their fair values, partially offset by higher realized gains on decommissioning trust fund investments in 2015 as compared to 2014, including portfolio reallocations for the Vermont Yankee nuclear decommissioning trust funds.

Other expenses decreased primarily due to a decrease in nuclear refueling outage costs that are being amortized over the estimated period to the next outage as a result of the impairments and related charges in 2015 to write down the carrying values of the FitzPatrick and Pilgrim plants and related assets and the shutdown of Vermont Yankee, which ceased power production in December 2014. See Note 14 to the financial statements for further discussion of the impairment and related charges.

Income Taxes

See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates, and for additional discussion regarding income taxes.

The effective income tax rate for 2014 was 38%. The difference in the effective income tax rate versus the statutory rate of 35% for 2014 was primarily due to state income taxes, certain book and tax differences related to utility plant items, and the provision for uncertain tax positions, partially offset by a deferred state income tax reduction related to a New York tax law change and book and tax differences related to the allowance for equity funds used during construction.

ANO Damage, Outage, and NRC Reviews

In March 2013, during a scheduled refueling outage at ANO 1, a contractor-owned and operated heavy-lifting apparatus collapsed while moving the generator stator out of the turbine building. The collapse resulted in the death of an ironworker and injuries to several other contract workers, caused ANO 2 to shut down, and damaged the ANO turbine building. The total cost of assessment, restoration of off-site power, site restoration, debris removal, and replacement of damaged property and equipment was approximately $95 million. Entergy Arkansas is pursuing its options for recovering damages that resulted from the stator drop, including its insurance coverage and legal action. During 2014, Entergy Arkansas collected $50 million from Nuclear Electric Insurance Limited (NEIL), a mutual insurance company that provides property damage coverage to the members’ nuclear generating plants. Litigation remains pending.

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duration of the refueling outage. In February 2014 the APSC approved Entergy Arkansas’s request to exclude from the calculation of its revised energy cost rate $65.9 million of deferred fuel and purchased energy costs incurred in 2013 as a result of the ANO stator incident. The APSC authorized Entergy Arkansas to retain the $65.9 million in its deferred fuel balance with recovery to be reviewed in a later period after more information regarding various claims associated with the ANO stator incident is available.

Shortly after the stator incident, the NRC deployed an augmented inspection team to review the plant’s response. In July 2013 a second team of NRC inspectors visited ANO to evaluate certain items that were identified as requiring follow-up inspection to determine whether performance deficiencies existed. In March 2014 the NRC issued an inspection report on the follow-up inspection that discussed two preliminary findings, one that was preliminarily determined to be “red with high safety significance” for Unit 1 and one that was preliminarily determined to be “yellow with substantial safety significance” for Unit 2, with the NRC indicating further that these preliminary findings may warrant additional regulatory oversight. This report also noted that one additional item related to flood barrier effectiveness was still under review.

In March 2015, after several NRC inspections and regulatory conferences, the NRC issued a letter notifying Entergy of its decision to move ANO into the “multiple/repetitive degraded cornerstone column,” or Column 4, of the NRC’s Reactor Oversight Process Action Matrix. Placement into Column 4 requires significant additional NRC inspection activities at the ANO site, including a review of the site’s root cause evaluation associated with flood barrier effectiveness and stator issues, an assessment of the effectiveness of the site’s corrective action program, an additional design basis inspection, a safety culture assessment, and possibly other inspection activities consistent with the NRC’s Inspection Procedure. Entergy Arkansas incurred incremental costs of approximately $53 million in 2015 to prepare for the NRC inspection that began in early 2016. Excluding remediation and response costs that may result from the additional NRC inspection activities, Entergy Arkansas also incurred approximately $44 million in 2016 in support of NRC inspection activities and to implement Entergy Arkansas’s performance improvement initiatives developed in 2015. A lesser amount of incremental expense is expected to be ongoing annually after 2016, until ANO transitions out of Column 4.

The NRC completed the supplemental inspection required for ANO’s Column 4 designation in February 2016, and published its inspection report in June 2016. In its inspection report, the NRC concluded that the ANO site is being operated safely and that Entergy understands the depth and breadth of performance concerns associated with ANO’s performance decline. Also in June 2016, the NRC issued a confirmatory action letter to confirm the actions Entergy Arkansas has taken and will continue to take to improve performance at ANO. The NRC will verify the completion of those actions through quarterly follow-up inspections, the results of which will determine when ANO should transition out of Column 4.

Entergy Wholesale Commodities Exit from the Merchant Power Business

Entergy management has undertaken a strategy to manage and reduce the risk of the Entergy Wholesale Commodities business, which includes taking actions to reduce the size of the merchant fleet. Management evaluated the challenges for each of the plants based on a variety of factors such as their market for both energy and capacity, their size, their contracted positions, and the amount of investment required to continue to operate and maintain the safety and integrity of the plants, including the estimated asset retirement costs. Management continues to look for ways to mitigate the operational and decommissioning risks associated with the merchant power business. Assumptions regarding the operating life of the plants and the decommissioning timeline and process continue to be evaluated. Changes to current assumptions could result in revisions to the asset retirement obligations and affect compliance with certain NRC minimum financial assurance requirements for meeting obligations to decommission the plants. Increases in the asset retirement obligations could result in an increase in operating expense in the period of a revision. Assumptions regarding the possibility that a plant may have an operating life shorter than previously assumed will likely result in the need for additional contributions to decommissioning trust funds, or the posting of parent guarantees, letters of credit, or other surety mechanisms.

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Entergy Wholesale Commodities includes the ownership of the following nuclear reactors:



	Location	Market	Capacity	Planned Transaction
Vermont Yankee	Vernon, VT	ISO-NE	605 MW	Planned sale of shutdown plant in 2018
FitzPatrick	Oswego, NY	NYISO	838 MW	Planned sale in 2017
Palisades	Covert, MI	MISO	811 MW	Planned shutdown in 2018
Pilgrim	Plymouth, MA	ISO-NE	688 MW	Planned shutdown in 2019
Indian Point 2	Buchanan, NY	NYISO	1,028 MW	Planned shutdown in 2020
Indian Point 3	Buchanan, NY	NYISO	1,041 MW	Planned shutdown in 2021

Entergy Wholesale Commodities also includes the ownership of two non-operating nuclear facilities, Big Rock Point in Michigan and Indian Point 1 in New York that were acquired when Entergy purchased the Palisades and Indian Point 2 nuclear plants, respectively. These facilities are in various stages of the decommissioning process. In addition, Entergy Wholesale Commodities provides operations and management services, including decommissioning services, to nuclear power plants owned by other utilities in the United States. A relatively minor portion of the Entergy Wholesale Commodities business is the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers.

Shutdown and Planned Sale of Vermont Yankee

On December 29, 2014, the Vermont Yankee plant ceased power production and entered its decommissioning phase. In November 2016, Entergy entered into an agreement to sell 100% of the membership interests in Entergy Nuclear Vermont Yankee, LLC to a subsidiary of NorthStar. Entergy Nuclear Vermont Yankee is the owner of the Vermont Yankee plant and is in the Entergy Wholesale Commodities segment. The sale of Entergy Nuclear Vermont Yankee to NorthStar will include the transfer of the nuclear decommissioning trust fund and the asset retirement obligation for the spent fuel management and decommissioning of the plant.

Entergy Nuclear Vermont Yankee has an outstanding credit facility with borrowing capacity of $100 million to pay for dry fuel storage costs. This credit facility is guaranteed by Entergy Corporation. At or before closing, a subsidiary of Entergy will assume the obligations under the existing credit facility or enter into a new credit facility, and Entergy will guarantee the credit facility. At the closing of the sale transaction, NorthStar will pay $1,000 for the membership interests in Entergy Nuclear Vermont Yankee, and NorthStar will cause Entergy Nuclear Vermont Yankee to issue a promissory note to the Entergy entity selling the membership interests in Entergy Nuclear Vermont Yankee. The amount of the promissory note issued will be equal to the amount drawn under the credit facility or the amount drawn under the new credit facility, plus borrowing fees and costs incurred by Entergy in connection with such facility. The principal amount drawn under the outstanding credit facility was $45 million as of December 31, 2016, and the net book value of Entergy Nuclear Vermont Yankee, including unrealized gains on the decommissioning trust fund, as of December 31, 2016, was approximately $88 million.

Entergy plans to transfer all spent nuclear fuel to dry cask storage by the end of 2018, subject to obtaining necessary regulatory approvals, in advance of the planned transaction close. Under the sale agreement and related agreements to be entered into at the closing, NorthStar will commit to initiate decommissioning and site restoration by 2021 and complete those activities by 2030. The original completion date, as outlined in Entergy’s Post Shutdown Decommissioning Activities Report filed with the NRC, was 2075. Entergy Nuclear Vermont Yankee, under NorthStar ownership, will be required to repay the promissory note issued to Entergy with certain of the proceeds from the recovery of damages under its claims against the DOE related to spent nuclear fuel disposal, with any balance remaining due at partial site restoration, subject to extension not to exceed two years from partial site restoration.

The transaction is subject to certain closing conditions, including approval by the NRC; approval by the State of Vermont Public Service Board, including approval of site restoration standards that will be proposed as part of the

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transaction; the transfer of all spent nuclear fuel to dry fuel storage on the independent spent fuel storage installation; and that the market value of the fund assets held in the decommissioning trust fund for the Vermont Yankee Nuclear Power Station, less the hypothetical income tax on the aggregate unrealized net gain of such fund assets at closing, is equal to or exceeds $451.95 million, subject to adjustments. The transaction is expected to close by the end of 2018, subject to certain conditions, including the condition that Entergy contribute to the decommissioning trust fund if the value is less than provided for in the agreement with NorthStar.

Sale of Rhode Island State Energy Center

In December 2015, Entergy sold the Rhode Island State Energy Center, a 583 MW natural gas-fired combined-cycle generating plant owned by Entergy in the Entergy Wholesale Commodities segment. Entergy sold Rhode Island State Energy Center for approximately $490 million and realized a pre-tax gain of $154 million on the sale.

Sale of Top Deer Investment

In November 2016, Entergy sold its 50% membership interest in Top Deer Wind Ventures, LLC, a wind-powered electric generation joint venture owned by Entergy in the Entergy Wholesale Commodities segment and accounted for as an equity method investment. Entergy sold its 50% membership interest in Top Deer for approximately $0.5 million and realized a pre-tax loss of $0.2 million on the sale.

Planned Sale of FitzPatrick

In October 2015, Entergy determined that it would close the FitzPatrick plant. The original expectation was to shut down the FitzPatrick plant at the end of its fuel cycle in January 2017. See Note 14 to the financial statements for discussion of the impairment charges associated with the decision to cease operations earlier than expected.

In August 2016, Entergy entered into a trust transfer agreement with NYPA to transfer the decommissioning trust funds and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants to Entergy. When Entergy purchased Indian Point 3 and FitzPatrick in 2000 from NYPA, NYPA retained the decommissioning trust funds and the decommissioning liabilities. NYPA and Entergy subsidiaries executed decommissioning agreements, which specified their decommissioning obligations. NYPA had the right to require the Entergy subsidiaries to assume each of the decommissioning liabilities provided that it assigned the corresponding decommissioning trust, up to a specified level, to the Entergy subsidiaries. Under the original agreements, if the decommissioning liabilities were retained by NYPA, the Entergy subsidiaries would perform the decommissioning of the plants at a price equal to the lesser of a pre-specified level or the amount in the decommissioning trust funds. At the time of the acquisition of the plants Entergy recorded a contract asset that represented an estimate of the present value of the difference between the stipulated contract amount for decommissioning the plants less the decommissioning costs estimated in independent decommissioning cost studies. The asset was increased by monthly accretion based on the applicable discount rate necessary to ultimately provide for the estimated future value of the decommissioning contract. The monthly accretion was recorded as interest income. As a result of the agreement with NYPA, in the third quarter 2016, Entergy removed the contract asset from its balance sheet, and recorded receivables for the beneficial interests in the decommissioning trust funds and asset retirement obligations for the decommissioning liabilities. The asset retirement obligations are accreted monthly through a charge to decommissioning expense. The transaction was contingent upon receiving approval from the NRC, which was received in January 2017. The decommissioning trust funds for the Indian Point 3 and FitzPatrick plants were transferred to Entergy by NYPA in January 2017. See Note 9 to the financial statements for further discussion of Indian Point 3 and FitzPatrick’s decommissioning liabilities and see Note 16 to the financial statements for further discussion of the receivables for the beneficial interests in Indian Point 3 and FitzPatrick’s decommissioning trust funds.

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upon the signing of the agreement. The transaction is contingent upon, among other things, the expiration of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, the receipt of necessary regulatory approvals from the FERC, the NRC, and the Public Service Commission of the State of New York (NYPSC), and the receipt of a private letter ruling from the IRS. NRC approval has not yet been received, but all other necessary regulatory approvals have been received. Because certain specified conditions were satisfied in November 2016, including the continued effectiveness of the Clean Energy Standards/Zero Emissions Credit program (CES/ZEC), the establishment of certain long-term agreements on acceptable terms with the Energy Research and Development Authority of the State of New York in connection with the CES/ZEC program, and NYPSC approval of the transaction on acceptable terms, Entergy refueled the FitzPatrick plant in January and February 2017. Entergy expects to operate the FitzPatrick plant until the asset purchase agreement closing date. Entergy entered into a reimbursement agreement with Exelon pursuant to which Exelon will reimburse Entergy for specified out-of-pocket costs associated with the refueling and operation of FitzPatrick that otherwise would have been avoided had Entergy shut down FitzPatrick in January 2017. Pursuant to the reimbursement agreement, as of December 31, 2016 Exelon reimbursed Entergy $56 million for nuclear fuel expenses and $41 million for other operation and maintenance expenses associated with preparing to refuel FitzPatrick in 2017. In addition, Entergy entered into a transfer agreement whereby Exelon will be entitled to all revenues from FitzPatrick’s electricity and capacity sales for the period that commenced upon completion of the refueling outage through the asset purchase agreement closing date. If the asset purchase agreement is terminated, a termination fee of up to $30 million will be payable to Entergy under certain circumstances. If it is consummated, the transaction could result in a gain or loss because of fluctuations in the decommissioning trust fund earnings and asset retirement obligation accretion. Upon the closing of the sale, the FitzPatrick decommissioning trust along with the decommissioning obligation for that plant will be transfered to Exelon.

As a result of the agreement and the status of the necessary regulatory approvals, the assets and liabilities associated with the sale of FitzPatrick to Exelon are classified as held for sale on Entergy Corporation and Subsidiaries’ Consolidated Balance Sheet. As of December 31, 2016, the $785 million receivable for the beneficial interest in the decommissioning trust fund within other deferred debits and the $714 million asset retirement obligation within other non-current liabilities are classified as held for sale. The transaction also includes property, plant, and equipment with a net book value of zero.

Planned Shutdown of Palisades

Most of the Palisades output is sold under a power purchase agreement (PPA) with Consumers Energy, entered into when the plant was acquired in 2007, that is currently scheduled to expire in 2022. The PPA prices currently exceed market prices and escalate each year, up to $61.50/MWh in 2022.

In December 2016, Entergy reached an agreement with Consumers Energy to terminate the PPA for the Palisades plant on May 31, 2018. Pursuant to the PPA termination agreement, Consumers Energy will pay Entergy $172 million for the early termination of the PPA. The PPA termination agreement is subject to regulatory approvals. Separately, and assuming regulatory approvals are obtained for the PPA termination agreement, Entergy intends to shut down the Palisades nuclear power plant permanently on October 1, 2018, after refueling in the spring of 2017 and operating through the end of that fuel cycle. Entergy expects to enter into a new PPA with Consumers Energy under which the plant would continue to operate through October 1, 2018. See Note 14 to the financial statements for discussion of the impairment charges associated with the PPA termination agreement and the decision to cease operations earlier than expected.

Planned Shutdown of Pilgrim

In October 2015, Entergy determined that it would close the Pilgrim plant. The decision came after management’s extensive analysis of the economics and operating life of the plant following the NRC’s decision in September 2015 to place the plant in its “multiple/repetitive degraded cornerstone column” (Column 4) of its Reactor Oversight Process Action Matrix. The Pilgrim plant is expected to cease operations on May 31, 2019, after refueling in the spring of 2017 and operating through the end of that fuel cycle. See Note 14 to the financial statements for

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discussion of the impairment charges associated with the decision to cease operations earlier than expected and see Note 8 for further discussion on the placement of Pilgrim in Column 4.

Planned Shutdown of Indian Point 2 and Indian Point 3

Indian Point 2 and Indian Point 3 have been involved, and have faced opposition, in extensive licensing proceedings. In January 2017, Entergy announced that it reached a settlement with New York State to shut down Indian Point 2 by April 30, 2020 and Indian Point 3 by April 30, 2021. See further discussion of the licensing proceedings and the settlement reached with New York State in “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants” below.

As discussed above, in August 2016, Entergy entered into a trust transfer agreement with NYPA to transfer the decommissioning trust fund and decommissioning liability for the Indian Point 3 plant to Entergy. The decommissioning trust fund for the Indian Point 3 plant was transferred to Entergy by NYPA in January 2017.

See Note 14 to the financial statements for further discussion of the impairment charges associated with management’s evaluation of alternatives to the continued operation of the Indian Point plants.

Costs Associated with Entergy Wholesale Commodities Strategic Transactions

Entergy incurred approximately $95 million in costs in 2016 associated with these strategic decisions and transactions to exit the merchant power business, primarily employee retention and severance expenses and other benefits-related costs, and contracted economic development contributions. Entergy expects to incur employee retention and severance expenses of approximately $100 million in 2017, and approximately $235 million from 2018 through the end of 2021 associated with these strategic transactions. See Note 13 to the financial statements for further discussion of these costs.

Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants

The NRC operating license for Palisades expires in 2031, for Pilgrim expires in 2032, and for FitzPatrick expires in 2034. See Note 14 to the financial statements for additional discussion regarding the planned sales of the Vermont Yankee and FitzPatrick plants and the planned shutdowns and associated impairment and related charges for the Palisades and Pilgrim plants.

Indian Point NRC/ASLB Proceedings

In January 2017, Entergy reached a settlement with New York State, several State agencies, and Riverkeeper, Inc. under which Indian Point 2 and Indian Point 3 will cease commercial operation by April 30, 2020 and April 30, 2021, respectively, subject to certain conditions, including New York State’s withdrawal of opposition to Indian Point’s license renewals and issuance of contested permits and similar authorizations. See “Overview of Settlement” below for further discussion on the settlement with New York State.

In April 2007, Entergy submitted to the NRC a joint application to renew the operating licenses for Indian Point 2 and Indian Point 3 for an additional 20 years. The original expiration dates of the NRC operating licenses for Indian Point 2 and Indian Point 3 were in September 2013 and December 2015, respectively. Authorization to operate Indian Point 2 and Indian Point 3 rests on Entergy’s having timely filed a license renewal application that remains pending before the NRC. Each of Indian Point 2 and Indian Point 3 has now entered its “period of extended operation” after expiration of the plant’s initial license term under “timely renewal,” which is a federal statutory rule of general applicability providing for extension of a license for which a renewal application has been timely filed with the licensing agency. The license renewal application for Indian Point 2 and Indian Point 3 qualifies for timely renewal protection because it met NRC regulatory standards for timely filing.

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The scope of NRC license renewal applications is focused primarily on whether the licensee has in place aging management programs (detailed diagnostic analyses performed when and as prescribed) to ensure that passive systems, structures, and components (such as pipes and concrete and metal structures) can continue to perform their intended safety functions. Other aspects of nuclear plant operations (maintenance of active components like pumps and control systems, security, and emergency preparedness) are regulated by the NRC on an ongoing basis and, as such, are outside the scope of license renewal proceedings. The NRC also determines whether there are any environmental impacts that would affect license renewal.

Every application for renewal of a reactor operating license undergoes comprehensive NRC staff review to ensure the adequacy of the application and the aging management programs detailed in it. NRC staff’s conclusions following such review are set forth in a Final Safety Evaluation Report (FSER). Issuance of a renewed operating license is a “major federal action” under the National Environmental Policy Act, so NRC staff also are required to prepare an Environmental Impact Statement (EIS) regarding the proposed licensing action. The NRC has elected to address certain EIS issues on a generic basis via the rulemaking process. As a result, the EIS for a particular license renewal proceeding has two components: the Generic Environmental Impact Statement and a Final Supplemental Environmental Impact Statement (FSEIS) addressing site-specific EIS issues. Both the FSER and the FSEIS are subject to updating by NRC staff in an individual license renewal proceeding.

Where, as in the case of Indian Point, one or more intervenors proposes for admission contentions alleging errors and omissions in the applicant’s license renewal application or the NRC staff’s review of related safety and environmental issues, the NRC appoints an ASLB to determine whether the contentions satisfy threshold standards and, if so, to adjudicate such “admitted” contentions. Safety-related contentions address issues that will be or have been described in the FSER and environmental-related contentions address issues that will be or have been described in the FSEIS. Contentions may be proposed at any time before license issuance based on new and material information, subject to timeliness and admissibility standards. Final ASLB orders on admissibility or resolving contentions, whether after hearing or on summary disposition, are appealable to the NRC.

Various governmental and private intervenors sought and obtained party status to express opposition to renewal of the Indian Point 2 and Indian Point 3 licenses. The ASLB has admitted 16 consolidated contentions based on 21 contentions originally proposed by the State of New York or other parties. Thirteen “Track 1” contentions have been resolved in favor of Entergy, whether by the ASLB or by the NRC on appeal from an ASLB decision. Hearings on the three remaining contentions, which are designated “Track 2,” were conducted by the ASLB in November 2015. The ASLB scheduled the filing of post-hearing submissions through late-March 2016, but extended that schedule several times to allow the submission of supplemental testimony addressing the results of the 2016 reactor vessel internal inspection at Unit 2. That inspection led to the replacement of a substantial number of baffle former bolts, as described further in “Nuclear Matters” below. In January 2017 the ASLB issued an order suspending the schedule for completion of Track 2 filings following notification of the settlement with New York State.

Independent of the ASLB process, the NRC staff has performed its technical and environmental reviews of the Indian Point 2 and Indian Point 3 license renewal application. The NRC staff issued an FSER in August 2009, a supplement to the FSER in August 2011, an FSEIS in December 2010, a supplement to the FSEIS in June 2013, and a further supplement to the FSER in November 2014. In November 2014 the NRC staff advised of its proposed schedule for issuance of a further FSEIS supplement to address new information received by NRC staff since preparation and publication of the previous FSEIS supplement in June 2013. The NRC staff issued a draft of the new FSEIS supplement in December 2015. The target date for issuance of a final FSEIS supplement has not been announced. In addition, NRC staff has not formally announced whether it plans to issue a further FSEIS supplement addressing sensitivity analyses of severe accident mitigation alternatives that the NRC directed staff to perform as part of an order resolving appeal of one Track 1 contention in favor of NRC staff and Entergy.

Entergy will continue to work with the NRC staff as it completes its technical and environmental reviews of the Indian Point 2 and Indian Point 3 license renewal applications.

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Indian Point NYSDEC Water Quality Certification Proceedings

The New York State Department of Environmental Conservation (NYSDEC) has taken the position that Indian Point must obtain a new state-issued Clean Water Act Section 401 water quality certification as part of the license renewal process. Entergy submitted its application for a water quality certification to NYSDEC in April 2009, with a reservation of rights regarding the applicability of Section 401 in this case. Subsequently, Entergy submitted certain additional information in response to NYSDEC requests for additional information. In February 2010 the NYSDEC staff determined that Entergy’s water quality certification application was complete. In April 2010 the NYSDEC staff issued a proposed notice of denial of Entergy’s water quality certification application (the Notice). NYSDEC staff’s Notice triggered an administrative adjudicatory hearing before NYSDEC ALJs on the proposed Notice. Between 2011 and 2016, the ALJs conducted more than 50 days of trial on issues identified by NYSDEC staff as bases for denying Indian Point’s proposed water quality certificate, and those issues were briefed by the parties. Entergy also submitted information and analysis to the NRC indicating that a water quality certificate was not legally required for license renewal; NYSDEC disputed Entergy’s position. At the time the Indian Point settlement with New York State was reached, the ALJs had not issued a recommended decision to the Commissioner.

Under the Indian Point settlement, in January 2017, the NYSDEC Commissioner approved the NYSDEC staff’s earlier issuance of the water quality certification and water discharge permit, and the ALJs terminated the proceedings. The settlement agreement provides for issuance of a supplemental environmental analysis in May 2017 reflecting early shutdown.

Indian Point Coastal Zone Management Act Proceedings

In addition, before the NRC may issue renewed operating licenses it must resolve its obligation to address the requirements of the Coastal Zone Management Act (CZMA). Most commonly, those requirements are met by the applicant’s demonstration that the activity authorized by the federal permit being sought is consistent with the host state’s federally-approved coastal management policies. Entergy has undertaken three independent initiatives to resolve CZMA issues: “grandfathering;” “previous review;” and a “consistency certification.”

First, Entergy filed with the New York State Department of State (NYSDOS) in November 2012 a petition for declaratory order that Indian Point is grandfathered under either of two criteria prescribed by the New York Coastal Management Program, which sets forth the state coastal policies applied in a CZMA consistency review. NYSDOS denied the motion by order dated January 2013. Entergy appealed NYSDOS’s decision to the New York State courts. In November 2016 the New York Court of Appeals held that Indian Point was not grandfathered, and therefore subject to CZMA review by NYSDOS in conjunction with NRC license renewal.

Second, in July 2012, Entergy filed a supplement to the Indian Point license renewal applications currently pending before the NRC. Following a series of filings with the NRC, the NRC staff advised the ASLB in February 2015 that it was reviewing the information it had received regarding previous review and would provide further information when available.

Third, in December 2012, Entergy filed with NYSDOS a consistency determination explaining why Indian Point satisfies all applicable New York Coastal Management Program policies while noting that Entergy did not concede NYSDOS’s right to conduct a new CZMA review for Indian Point. In November 2014, Entergy filed with the NRC and with NYSDOS a notice withdrawing the consistency certification.

NYSDOS disputed the effectiveness of Entergy’s November 2014 notice withdrawing the consistency certification. In December 2014, Entergy and NYSDOS executed an agreement intended to preserve the parties’ respective positions on withdrawal which was extended several times; upon expiration of the last extension, NYSDOS issued an objection in November 2015. Entergy then filed with the National Oceanographic and Atmospheric Administration (NOAA), the agency within the U.S. Department of Commerce that has been delegated authority to act on CZMA appeals, a motion requesting a determination that Entergy’s November 2014 withdrawal notice was

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effective or, alternatively, an extension of the deadline for Entergy to file a notice of appeal and the consolidated record of proceedings which by law must be assembled by the federal licensing agency, here the NRC. In November 2015, after receiving papers in opposition from NYSDOS, NOAA issued a letter (1) deferring until after the New York Court of Appeals ruled on grandfathering the determination whether Entergy’s withdrawal notice was effective, and (2) extending until that time Entergy’s deadline for filing a notice of appeal and the consolidated record. In January 2016, Entergy filed suit in the U.S. District Court for the Northern District of New York challenging the New York State Department of Environmental Conservation’s objection to Entergy’s withdrawn Coastal Zone Management Act consistency certification on federal preemption grounds. Entergy’s complaint requested a determination that the objection, which cites nuclear safety concerns, is preempted and thus invalid. The NYSDOS filed a motion to dismiss Entergy’s lawsuit in March 2016, and Entergy filed its response in May 2016.

Overview of Settlement

The Indian Point settlement requires New York State agencies to issue environmental certifications needed for license renewal and a renewed water discharge permit based on current plant configuration. It also requires the New York State Attorney General and Riverkeeper to withdraw their Track 2 contentions pending before the ASLB. In exchange, Entergy commits to cease commercial operation of Indian Point 2 by April 30, 2020 and Indian Point 3 by April 30, 2021. Operations may be extended up to four years for each unit by mutual agreement of Entergy and New York State based on an exigent reliability need for Indian Point generation. See Note 14 to the financial statements for a discussion of the impairment and related charges associated with the settlement with New York State.

The settlement establishes a detailed timeline for implementation of steps necessary to allow Indian Point to receive renewed licenses and to implement Entergy’s commitment to shorten the life of the facility. Under that timeline, Indian Point expects to receive by the end of the first quarter 2017 a water quality certification and water discharge permit from NYSDEC and a concurrence from NYSDOS with a new CZMA consistency certification to be filed by Entergy. The settlement provides for issuance of a supplemental environmental analysis in May 2017 reflecting early shutdown. Consistent with the settlement, in January 2017 the NYSDEC Commissioner issued an order affirming the NYSDEC staff’s issuance of a final water quality certification and a final water discharge permit, and on the same day the ALJs terminated proceedings before them. Each of the water quality certification and CZMA concurrence will be filed with the NRC. In February 2017 the New York State Attorney General and Riverkeeper filed with the ASLB a motion to withdraw their pending Track 2 contentions. There is no schedule for the ASLB to act, but based on past practice the ASLB is expected to act by mid-2017. The NRC is not expected to be in a position to issue renewed licenses earlier than mid-2018, as its staff must first issue one, and potentially two, FSEIS.

In addition to contractually agreeing to cease commercial operations early, in February 2017 Entergy filed with the NRC an amendment to its license renewal application changing the term of the requested licenses to coincide with the latest possible extension by mutual agreement based on exigent reliability needs: April 30, 2024 for Indian Point 2 and April 30, 2025 for Indian Point 3. If Entergy reasonably determines that the NRC will treat the amendment other than as a routine amendment, Entergy may withdraw the amendment.

Other provisions of the settlement include termination of all investigations of Indian Point by the agencies signing the agreement, which include NYSDEC, NYSDOS, the New York State Department of Public Service, the New York State Department of Health, and the New York State Attorney General. The settlement recognizes the right of New York State agencies to pursue new investigations and enforcement actions with respect to new circumstances or existing conditions that become materially exacerbated.

Another provision of the settlement obligates Entergy to establish a $15 million fund for environmental projects and community support. Apportionment and allocation of funds to beneficiaries are to be determined by mutual agreement of New York State and Entergy. The settlement recognizes New York State’s right to perform an annual inspection of Indian Point, with scope and timing to be determined by mutual agreement.

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Management’s Financial Discussion and Analysis

Liquidity and Capital Resources

This section discusses Entergy’s capital structure, capital spending plans and other uses of capital, sources of capital, and the cash flow activity presented in the cash flow statement.

Capital Structure

Entergy’s capitalization is balanced between equity and debt, as shown in the following table. The increase in the debt to capital ratio for Entergy as of December 31, 2016 is primarily due to the issuance of long-term debt in 2016 and a decrease in retained earnings. See Entergy’s Consolidated Statements of Changes in Equity for details of the decrease in retained earnings.



	2016		2015
Debt to capital	64.8	%	59.1	%
Effect of excluding securitization bonds	(1.0	%)	(1.4	%)
Debt to capital, excluding securitization bonds (a)	63.8	%	57.7	%
Effect of subtracting cash	(2.0	%)	(2.7	%)
Net debt to net capital, excluding securitization bonds (a)	61.8	%	55.0	%


(a)	Calculation excludes the Arkansas, Louisiana, New Orleans and Texas securitization bonds, which are non-recourse to Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas, respectively.

Net debt consists of debt less cash and cash equivalents. Debt consists of notes payable and commercial paper, capital lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt, common shareholders’ equity, and subsidiaries’ preferred stock without sinking fund. Net capital consists of capital less cash and cash equivalents. Entergy uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy’s financial condition because the securitization bonds are non-recourse to Entergy, as more fully described in Note 5 to the financial statements. Entergy also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy’s financial condition because net debt indicates Entergy’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

Long-term debt, including the currently maturing portion, makes up most of Entergy’s total debt outstanding. Following are Entergy’s long-term debt principal maturities and estimated interest payments as of December 31, 2016. To estimate future interest payments for variable rate debt, Entergy used the rate as of December 31, 2016. The amounts below include payments on the Entergy Louisiana’s Waterford 3 lease obligation and System Energy’s Grand Gulf sale-leaseback transaction, which are included in long-term debt on the balance sheet.



Long-term debt maturities and estimated interest payments	2017		2018		2019		2020-2021		after 2021
	(In Millions)
Utility		$1,021		$1,390		$1,219		$2,299		$14,758
Entergy Wholesale Commodities	—		45		—		—		—
Parent and Other	87		87		87		1,287		1,518
Total		$1,108		$1,522		$1,306		$3,586		$16,276

Note 5 to the financial statements provides more detail concerning long-term debt outstanding.

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Entergy Corporation has in place a credit facility that has a borrowing capacity of $3.5 billion and expires in August 2021. Entergy Corporation also has the ability to issue letters of credit against 50% of the total borrowing capacity of the credit facility. The commitment fee is currently 0.225% of the undrawn commitment amount. Commitment fees and interest rates on loans under the credit facility can fluctuate depending on the senior unsecured debt ratings of Entergy Corporation. The weighted average interest rate for the year ended December 31, 2016 was 2.23% on the drawn portion of the facility.

As of December 31, 2016, amounts outstanding and capacity available under the $3.5 billion credit facility are:

A covenant in Entergy Corporation’s credit facility requires Entergy to maintain a consolidated debt ratio, as defined, of 65% or less of its total capitalization. The calculation of this debt ratio under Entergy Corporation’s credit facility is different than the calculation of the debt to capital ratio above. Entergy is currently in compliance with the covenant and expects to remain in compliance with this covenant. If Entergy fails to meet this ratio, or if Entergy or one of the Utility operating companies (except Entergy New Orleans) defaults on other indebtedness or is in bankruptcy or insolvency proceedings, an acceleration of the Entergy Corporation credit facility’s maturity date may occur.

Entergy Corporation has a commercial paper program with a Board-approved program limit of up to $1.5 billion. At December 31, 2016, Entergy Corporation had $344 million of commercial paper outstanding. The weighted-average interest rate for the year ended December 31, 2016 was 1.13%.

Capital lease obligations are a minimal part of Entergy’s overall capital structure. Following are Entergy’s payment obligations under those leases.



	2017	2018	2019	2020-2021	after 2021
	(In Millions)
Capital lease payments	$5	$4	$3	$6	$22

The capital leases are discussed in Note 10 to the financial statements.

Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, 2016 as follows:



Company	Expiration Date	Amount of Facility	Interest Rate (a)	Amount Drawn as of December 31, 2016	Letters of Credit Outstanding as of December 31, 2016
Entergy Arkansas	April 2017	$20 million (b)	2.02%	—	—
Entergy Arkansas	August 2021	$150 million (c)	2.02%	—	—
Entergy Louisiana	August 2021	$350 million (d)	2.02%	—	$6.4 million
Entergy Mississippi	May 2017	$10 million (e)	2.27%	—	—
Entergy Mississippi	May 2017	$20 million (e)	2.27%	—	—
Entergy Mississippi	May 2017	$35 million (e)	2.27%	—	—
Entergy Mississippi	May 2017	$37.5 million (e)	2.27%	—	—
Entergy New Orleans	November 2018	$25 million (f)	2.52%	—	$0.8 million
Entergy Texas	August 2021	$150 million (g)	2.27%	—	$4.7 million

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(a)	The interest rate is the rate as of December 31, 2016 that would be applied to outstanding borrowings under the facility.


(b)	Borrowings under this Entergy Arkansas credit facility may be secured by a security interest in its accounts receivable at Entergy Arkansas’s option.


(c)	The credit facility allows Entergy Arkansas to issue letters of credit against 50% of the borrowing capacity of the facility.


(d)	The credit facility allows Entergy Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility.


(e)	Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts receivable at Entergy Mississippi’s option.


(f)	The credit facility allows Entergy New Orleans to issue letters of credit against $10 million of the borrowing

capacity of the facility.


(g)	The credit facility allows Entergy Texas to issue letters of credit against 50% of the borrowing capacity of the facility.

Each of the credit facilities requires the Registrant Subsidiary borrower to maintain a debt ratio, as defined, of 65% or less of its total capitalization. Each Registrant Subsidiary is in compliance with this covenant.

In addition, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each entered into one or more uncommitted standby letter of credit facilities as a means to post collateral to support its obligations related to MISO. Following is a summary of the uncommitted standby letter of credit facilities as of December 31, 2016:



Company	Amount of Uncommitted Facility	Letter of Credit Fee	Letters of Credit Issued as of December 31, 2016 (a)
Entergy Arkansas	$25 million	0.70%		$1.0	million
Entergy Louisiana	$125 million	0.70%		$5.7	million
Entergy Mississippi	$40 million	0.70%		$7.1	million
Entergy New Orleans	$15 million	1.00%		$6.2	million
Entergy Texas	$50 million	0.70%		$14.7	million


(a)	As of December 31, 2016, letters of credit posted with MISO covered FTR exposure of $0.3 million for Entergy Arkansas and $0.1 million for Entergy Mississippi. See Note 15 to the financial statements for discussion of FTRs.

Entergy Nuclear Vermont Yankee has a credit facility guaranteed by Entergy Corporation with a borrowing capacity of $100 million which expires in January 2018. As of December 31, 2016, $45 million in cash borrowings were outstanding under the credit facility. Entergy Nuclear Vermont Yankee also has an uncommitted credit facility guaranteed by Entergy Corporation with a borrowing capacity of $85 million which expires in January 2018. As of December 31, 2016, there were no cash borrowings outstanding under the uncommitted credit facility. See Note 4 to the financial statements for additional discussion of the Vermont Yankee facilities.

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Management’s Financial Discussion and Analysis

Operating Lease Obligations and Guarantees of Unconsolidated Obligations

Entergy has a minimal amount of operating lease obligations and guarantees in support of unconsolidated obligations. Entergy’s guarantees in support of unconsolidated obligations are not likely to have a material effect on Entergy’s financial condition, results of operations, or cash flows. Following are Entergy’s payment obligations as of December 31, 2016 on non-cancelable operating leases with a term over one year:



	2017	2018	2019	2020-2021	after 2021
	(In Millions)
Operating lease payments	$76	$70	$67	$93	$91

The operating leases are discussed in Note 10 to the financial statements.

Summary of Contractual Obligations of Consolidated Entities



Contractual Obligations	2017		2018-2019		2020-2021		after 2021		Total
	(In Millions)
Long-term debt (a)		$1,108		$2,828		$3,586		$16,276		$23,798
Capital lease payments (b)		$5		$7		$6		$22		$40
Operating leases (b) (c)		$76		$137		$93		$91		$397
Purchase obligations (d)		$1,435		$1,868		$1,392		$3,127		$7,822


(a)	Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements.


(b)	Lease obligations are discussed in Note 10 to the financial statements.


(c)	Does not include power purchase agreements that are accounted for as leases that are included in purchase obligations.


(d)	Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. Almost all of the total are fuel and purchased power obligations.

In addition to the contractual obligations stated above, Entergy currently expects to contribute approximately $409 million to its pension plans and approximately $53 million to other postretirement plans in 2017, although the 2017 required pension contributions will be known with more certainty when the January 1, 2017 valuations are completed, which is expected by April 1, 2017. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.

Also in addition to the contractual obligations, Entergy has $978 million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

Capital Funds Agreement

Pursuant to an agreement with certain creditors, Entergy Corporation has agreed to supply System Energy with sufficient capital to:


•	maintain System Energy’s equity capital at a minimum of 35% of its total capitalization (excluding short-term debt);


•	permit the continued commercial operation of Grand Gulf;


•	pay in full all System Energy indebtedness for borrowed money when due; and


•	enable System Energy to make payments on specific System Energy debt, under supplements to the agreement assigning System Energy’s rights in the agreement as security for the specific debt.

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Management’s Financial Discussion and Analysis

Capital Expenditure Plans and Other Uses of Capital

Following are the amounts of Entergy’s planned construction and other capital investments by operating segment for 2017 through 2019.



Planned construction and capital investments	2017		2018		2019
	(In Millions)
Utility:
Generation		$1,390		$1,520		$1,465
Transmission	845		860		820
Distribution	755		800		805
Other	530		360		255
Total	3,520		3,540		3,345
Entergy Wholesale Commodities	230		130		60
Total		$3,750		$3,670		$3,405

Planned construction and capital investments refer to amounts Entergy plans to spend on routine capital projects that are necessary to support reliability of its service, equipment, or systems and to support normal customer growth, and includes spending for the nuclear and non-nuclear plants at Entergy Wholesale Commodities. In addition to routine capital projects, they also refer to amounts Entergy plans to spend on non-routine capital investments for which Entergy is either contractually obligated, has Board approval, or otherwise expects to make to satisfy regulatory or legal requirements. Amounts include the following types of construction and capital investments:


•	Investments, including the St. Charles Power Station, Lake Charles Power Station, New Orleans Power Station, and Montgomery County Power Station, discussed below, and potential construction of additional generation.


•	Entergy Wholesale Commodities investments associated with specific investments such as component replacements, software and security, and dry cask storage.


•	Investments in Entergy’s nuclear fleet. See “Nuclear Matters” below for discussion of this initiative.


•	Transmission spending to enhance reliability, reduce congestion, and enable economic growth.


•	Distribution spending to enhance reliability and improve service to customers, including initial investment to support advanced metering.

For the next several years, the Utility’s owned generating capacity is projected to be adequate to meet MISO reserve requirements; however, in the longer-term additional supply resources will be needed, and its supply plan initiative will continue to seek to transform its generation portfolio with new generation resources. Opportunities resulting from the supply plan initiative, including new projects or the exploration of alternative financing sources, could result in increases or decreases in the capital expenditure estimates given above. Estimated capital expenditures are also subject to periodic review and modification and may vary based on the ongoing effects of business restructuring, regulatory constraints and requirements, environmental regulations, business opportunities, market volatility, economic trends, changes in project plans, and the ability to access capital.

St. Charles Power Station

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preference to the self-build option, and that a 30-year capacity commitment was not warranted by current supply conditions. The request for proposal independent monitor also filed testimony and a report affirming that the St. Charles Power Station was selected through an objective and fair request for proposal that showed no undue preference to any proposal. An evidentiary hearing was held in April 2016, and in July 2016 an ALJ issued a final recommendation that the LPSC certify that the construction of St. Charles Power Station is in the public interest. The LPSC issued its order approving certification of St. Charles Power Station in December 2016. Construction is in progress and commercial operation is estimated to occur by mid-2019.

Lake Charles Power Station

In November 2016, Entergy Louisiana filed an application with the LPSC seeking certification that the public convenience and necessity would be served by the construction of the Lake Charles Power Station, a nominal 994 megawatt combined-cycle generating unit in Westlake, Louisiana, on land adjacent to the existing Nelson plant in Calcasieu Parish. The current estimated cost of the Lake Charles Power Station is $872 million, including estimated costs of transmission interconnection and other related costs. A procedural schedule has been issued, with an evidentiary hearing scheduled for May and June 2017. Subject to timely approval by the LPSC and receipt of other permits and approvals, commercial operation is estimated to occur by mid-2020.

New Orleans Power Station

In June 2016, Entergy New Orleans filed an application with the City Council seeking a public interest determination and authorization to construct the New Orleans Power Station, a 226 megawatt advanced combustion turbine in New Orleans, Louisiana, at the site of the existing Michoud generating facility, which facility was deactivated effective May 31, 2016. The current estimated cost of the New Orleans Power Station is $216 million. A procedural schedule has been established with a decision expected no later than April 2017. Subject to timely approval by the City Council and receipt of other permits and approvals, commercial operation is estimated to occur by late-2019. In January 2017 several intervenors filed testimony opposing the construction of the New Orleans Power Station on various grounds. In February 2017, Entergy New Orleans filed a motion to temporarily suspend the procedural schedule to allow for further analysis regarding its proposal, and that motion was granted. A status conference is scheduled in March 2017.

Montgomery County Power Station

In October 2016, Entergy Texas filed an application with the PUCT seeking certification that the public convenience and necessity would be served by the construction of the Montgomery County Power Station, a nominal 993 megawatt combined-cycle generating unit in Montgomery County, Texas on land adjacent to the existing Lewis Creek plant. The current estimated cost of the Montgomery County Power Station is $937 million, including estimated costs of transmission interconnection and network upgrades and other related costs. The independent monitor, who oversaw the request for proposal process, filed testimony and a report affirming that the Montgomery County Power Station was selected through an objective and fair request for proposal that showed no undue preference to any proposal. Discovery has commenced and a procedural schedule has been established for this proceeding, including an evidentiary hearing in May 2017. A PUCT decision regarding the application is expected by October 2017, pursuant to a Texas statute requiring the PUCT to issue an order regarding a certificate of convenience and necessity within 366 days of the filing. Subject to timely approval by the PUCT and receipt of other permits and approvals, commercial operation is estimated to occur by mid-2021.

Dividends and Stock Repurchases

Declarations of dividends on Entergy’s common stock are made at the discretion of the Board. Among other things, the Board evaluates the level of Entergy’s common stock dividends based upon earnings per share from the Utility operating segment and the Parent and Other portion of the business, financial strength, and future investment

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opportunities. At its January 2017 meeting, the Board declared a dividend of $0.87 per share. Entergy paid $612 million in 2016, $599 million in 2015, and $596 million in 2014 in cash dividends on its common stock.

In accordance with Entergy’s stock-based compensation plans, Entergy periodically grants stock options, restricted stock, performance units, and restricted stock unit awards to key employees, which may be exercised to obtain shares of Entergy’s common stock. According to the plans, these shares can be newly issued shares, treasury stock, or shares purchased on the open market. Entergy’s management has been authorized by the Board to repurchase on the open market shares up to an amount sufficient to fund the exercise of grants under the plans.

In addition to the authority to fund grant exercises, the Board has authorized share repurchase programs to enable opportunistic purchases in response to market conditions. In October 2010 the Board granted authority for a $500 million share repurchase program. As of December 31, 2016, $350 million of authority remains under the $500 million share repurchase program. The amount of repurchases may vary as a result of material changes in business results or capital spending or new investment opportunities, or if limitations in the credit markets continue for a prolonged period.

Sources of Capital

Entergy’s sources to meet its capital requirements and to fund potential investments include:


•	internally generated funds;


•	cash on hand ($1,188 million as of December 31, 2016);


•	securities issuances;


•	bank financing under new or existing facilities or commercial paper; and


•	sales of assets.

Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future.

Provisions within the articles of incorporation relating to preferred stock of certain of Entergy Corporation’s subsidiaries could restrict the payment of cash dividends or other distributions on their common and preferred stock. All debt and common and preferred equity issuances by the Registrant Subsidiaries require prior regulatory approval and their preferred equity and debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, and other agreements. Entergy believes that the Registrant Subsidiaries have sufficient capacity under these tests to meet foreseeable capital needs.

The FERC has jurisdiction over securities issuances by the Utility operating companies and System Energy, except securities with maturities longer than one year issued by Entergy Arkansas and Entergy New Orleans, which are subject to the jurisdiction of the APSC and the City Council, respectively. No regulatory approvals are necessary for Entergy Corporation to issue securities. The current FERC-authorized short-term borrowing limits are effective through October 2017. Entergy Louisiana, Entergy Mississippi, Entergy Texas, and System Energy have obtained long-term financing authorizations from the FERC that extend through October 2017. Entergy Arkansas has obtained long-term financing authorization from the APSC that extends through December 2018. Entergy New Orleans has obtained long-term financing authorization from the City Council that extends through June 2018. Entergy Arkansas, Entergy Louisiana, and System Energy each have obtained long-term financing authorizations from the FERC that extend through October 2017 for issuances by its respective nuclear fuel company variable interest entity. In addition to borrowings from commercial banks, the Registrant Subsidiaries may also borrow from the Entergy System money pool. The money pool is an intercompany borrowing arrangement designed to reduce Entergy’s subsidiaries’ dependence on external short-term borrowings. Borrowings from the money pool and external short-term borrowings combined may not exceed the FERC-authorized short-term borrowing limits. See Notes 4 and 5 to the financial statements for further discussion of Entergy’s borrowing limits, authorizations, and amounts outstanding.

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Hurricane Isaac

In June 2014 the LPSC voted to approve a series of orders which (i) quantified $290.8 million of Hurricane Isaac system restoration costs as prudently incurred; (ii) determined $290 million as the level of storm reserves to be re-established; (iii) authorized Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs; and (iv) granted other requested relief associated with storm reserves and Act 55 financing of Hurricane Isaac system restoration costs. Entergy Louisiana committed to pass on to customers a minimum of $30.8 million of customer benefits through annual customer credits of approximately $6.2 million for five years. Approvals for the Act 55 financings were obtained from the Louisiana Utilities Restoration Corporation and the Louisiana State Bond Commission. See Note 2 to the financial statements for a discussion of the August 2014 issuance of bonds under Act 55 of the Louisiana Legislature.

In May 2015, the City Council issued a financing order authorizing the issuance of securitization bonds to recover Entergy New Orleans’s Hurricane Isaac storm restoration costs of $31.8 million, including carrying costs, the costs of funding and replenishing the storm recovery reserve in the amount of $63.9 million, and approximately $3 million for estimated up-front financing costs associated with the securitization. See Note 5 to the financial statements for a discussion of the July 2015 issuance of the securitization bonds.

Cash Flow Activity

As shown in Entergy’s Consolidated Statements of Cash Flows, cash flows for the years ended December 31, 2016, 2015, and 2014 were as follows:



	2016			2015			2014
	(In Millions)
Cash and cash equivalents at beginning of period		$1,351			$1,422			$739

Net cash provided by (used in):
Operating activities	2,999			3,291			3,890
Investing activities	(3,850		)	(2,609		)	(2,955		)
Financing activities	688			(753		)	(252		)
Net increase (decrease) in cash and cash equivalents	(163		)	(71		)	683

Cash and cash equivalents at end of period		$1,188			$1,351			$1,422

Operating Activities

2016 Compared to 2015

Net cash provided by operating activities decreased by $292 million in 2016 primarily due to:


•	a decrease due to the timing of recovery of fuel and purchased power costs in 2016 as compared to 2015. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery;


•	lower Entergy Wholesale Commodities net revenue in 2016 as compared to 2015, as discussed previously; and

•

an increase of $83 million in interest paid in 2016 as compared to 2015 primarily due to an interest payment of $60 million made in March 2016 related to the purchase of a beneficial interest in the Waterford 3 leased assets and an increase in interest expense primarily due to 2016 net debt issuances by various Utility operating companies, partially offset by a decrease in interest paid in 2016 on the Grand Gulf sale-leaseback obligation. See Note 10 to the financial statements for a discussion of Entergy Louisiana’s purchase of a beneficial interest

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in the Waterford 3 leased assets and for details of the Grand Gulf lease obligation. See Note 5 to the financial statements for a discussion of long-term debt.

The decrease was partially offset by:


•	higher Utility net revenues in 2016 as compared to 2015, as discussed above;


•	proceeds of $102 million received in 2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation;


•	a decrease of $46 million in spending on nuclear refueling outages in 2016 as compared to 2015; and


•	a decrease of $19 million in spending related to the shutdown of Vermont Yankee, which ceased power production in December 2014.

2015 Compared to 2014

Net cash provided by operating activities decreased by $599 million in 2015 primarily due to:


•	lower Entergy Wholesale Commodities net revenues in 2015 as compared to 2014, as discussed previously;


•	proceeds of $310 million received from the Louisiana Utilities Restoration Corporation in August 2014 as a result of the Louisiana Act 55 storm cost financing. See Note 2 to the financial statements and “Hurricane Isaac” above for a discussion of the Act 55 storm cost financing;


•	spending of $78 million in 2015 on activities related to the decommissioning of Vermont Yankee, which ceased power production in December 2014;


•	an increase of $52 million in interest paid in 2015 primarily due to an increase in interest paid on the Grand Gulf sale-leaseback obligation. See Note 10 to the financial statements for details of the Grand Gulf lease obligation;


•	an increase in spending of $48 million in 2015 related to Vermont Yankee, including the severance and retention payments accrued in 2014 and defueling activities that took place after the plant ceased power production in December 2014; and


•	an increase in income tax payments of $26 million primarily due to payments made in 2015 for the final settlement of amounts outstanding associated with the 2006-2007 IRS audit. See Note 3 to the financial statements for a discussion of the finalized tax and interest computations for the 2006-2007 IRS audit.

The decrease was partially offset by:


•	an increase due to the timing of recovery of fuel and purchased power costs in 2015;


•	higher Utility net revenues in 2015 as compared to 2014, as discussed above; and


•	a decrease of $46 million in storm spending in 2015 as compared to 2014.

Investing Activities

2016 Compared to 2015

Net cash flow used in investing activities increased by $1,241 million in 2016 primarily due to:


•	the purchase of the Union Power Station for approximately $949 million in March 2016. See Note 14 to the financial statements for discussion of the Union Power Station purchase;


•	proceeds of approximately $490 million from the sale in December 2015 of Rhode Island State Energy Center. See Note 14 to the financial statements for further discussion of the sale; and


•	an increase of $279 million in construction expenditures, primarily in the Utility business. The increase in construction expenditures in the Utility business is primarily due to an increase of $114 million in transmission construction expenditures primarily due to an overall higher scope of work performed on transmission projects

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in 2016 as compared to 2015, an increase of $106 million in nuclear construction expenditures primarily due to a higher scope of work on various nuclear projects in 2016 as compared to 2015, an increase of $95 million in fossil-fueled generation construction expenditures primarily due to spending on the St. Charles Power Station project in 2016, an increase of $79 million in distribution construction expenditures primarily due to a higher scope of non-storm related work performed in 2016 as compared to the same period in 2015 and higher storm restoration spending in 2016, and an increase of $65 million in information technology construction expenditures due to various information technology projects and upgrades in 2016. The increase was partially offset by a decrease of $148 million in spending related to compliance with NRC post-Fukushima requirements in the Utility and Entergy Wholesale Commodities businesses.

The increase was partially offset by:


•	a decrease of $179 million in nuclear fuel purchases due to variations from year to year in the timing and pricing of fuel reload requirements, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle;


•	an increase of $151 million in proceeds received from the DOE in 2016 as compared to the prior year resulting from litigation regarding spent nuclear fuel storage costs that were previously capitalized. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation;


•	a $71 million NYPA value sharing payment in 2015. See Note 14 to the financial statements for further discussion of Entergy’s NYPA value sharing agreements; and


•	the deposit of $64 million into Entergy New Orleans’s storm reserve escrow accounts in 2015.

2015 Compared to 2014

Net cash flow used in investing activities decreased by $346 million in 2015 primarily due to:


•	proceeds of approximately $490 million from the sale in December 2015 of Rhode Island State Energy Center. See Note 14 to the financial statements for further discussion of the sale;


•	the deposit of a total of $64 million into Entergy New Orleans’s storm reserve escrow accounts in 2015 compared to the deposit of a total of $268 million into Entergy Louisiana’s storm reserve escrow accounts in 2014;


•	$58 million in disbursements from the Vermont Yankee decommissioning trust funds to Entergy in 2015; and


•	a decrease in nuclear fuel purchases due to variations from year to year in the timing and pricing of fuel reload requirements, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle.

The decrease was partially offset by:


•	an increase in construction expenditures primarily due to an overall higher scope of work on various projects in 2015 as compared to 2014 and compliance with NRC post-Fukushima requirements, partially offset by a decrease in storm restoration spending and a decrease in spending on the Ninemile Unit 6 project;


•	a change in collateral deposit activity, reflected in the “Decrease (increase) in other investments” line on the Consolidated Statements of Cash Flows, as Entergy received net deposits of $47 million in 2014. Entergy Wholesale Commodities’ forward sales contracts are discussed in the “Market and Credit Risk Sensitive Instruments” section below; and


•	a decrease of $16 million in insurance proceeds primarily due to $13 million received in 2015 related to the unplanned outage event that occurred at the Baxter Wilson (Unit 1) power plant in September 2013; and


•	$12 million received in 2015 for property damages related to the generator stator incident at ANO compared to $37 million received in 2014 for property damages related to the generator stator incident at ANO. See Note 8 to the financial statements for a discussion of the ANO stator incident.

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Management’s Financial Discussion and Analysis

Financing Activities

2016 Compared to 2015

Entergy’s financing activities provided $688 million of cash for 2016 compared to using $753 million of cash for 2015 primarily due to the following activity:


•	long-term debt activity providing approximately $1,489 million of cash in 2016 compared to providing $41 million of cash in 2015. Included in the long-term debt activity is net repayments of borrowings of $135 million in 2016 compared to net borrowings of $140 million in 2015 on the Entergy Corporation long-term credit facility;


•	the issuance of $110 million of preferred stock in 2015. See Note 6 to the financial statements for further discussion;


•	$100 million of common stock repurchased in 2015, as discussed above;


•	a net increase of $41 million in 2016 in short-term borrowings by the nuclear fuel company variable interest entities; and

•

an increase of $21 million in the repurchase or redemption of preferred stock. In September 2015, Entergy Louisiana redeemed its $100 million 6.95% Series preferred membership interests, of which $16 million was owned by Entergy Louisiana Holdings, an Entergy subsidiary, and Entergy Gulf States Louisiana repurchased its $10 million Series A 8.25% preferred membership interests as part of a multi-step process to effectuate the Entergy Louisiana and Entergy Gulf States Louisiana business combination. See Note 2 to the financial statements for a discussion of the combination. In 2016, Entergy Arkansas redeemed its $75 million of 6.45% Series preferred stock and its $10 million of 6.08% Series preferred stock and Entergy Mississippi redeemed its $30 million of 6.25% Series preferred stock.

2015 Compared to 2014

Net cash flow used in financing activities increased $501 million in 2015 primarily due to:


•	long-term debt activity providing approximately $41 million of cash in 2015 compared to providing $777 million of cash in 2014. Included in the long-term debt activity is $140 million in 2015 and $440 million in 2014 for the repayment of borrowings on the Entergy Corporation long-term credit facility;


•	a decrease of $171 million in treasury stock issuances in 2015 primarily due to a larger amount of previously repurchased Entergy Corporation stock issued in 2014 to satisfy stock option exercises;


•	a net decrease of $154 million in 2015 in short-term borrowings by the nuclear fuel company variable interest entities; and

•

the repurchase or redemption of $94 million of preferred membership interests in 2015. Entergy Louisiana redeemed its $100 million 6.95% Series preferred membership interests, of which $16 million was owned by Entergy Louisiana Holdings, an Entergy subsidiary, and repurchased its $10 million Series A 8.25% preferred membership interests as part of a multi-step process to effectuate the Entergy Louisiana and Entergy Gulf States Louisiana business combination. See Note 2 to the financial statements for a discussion of the business combination.

The increase was partially offset by:


•	net repayments of $62 million of commercial paper in 2015 compared to net repayments of $561 million of commercial paper in 2014;


•	the issuance of $110 million of preferred stock in 2015. See Note 6 to the financial statements for further discussion of preferred stock issuances; and


•	a decrease of $83 million of common stock repurchased in 2015 as compared to 2014, as discussed above.

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For the details of Entergy’s commercial paper program and the nuclear fuel company variable interest entities’ short-term borrowings, see Note 4 to the financial statements. See Note 5 to the financial statements for details of long-term debt.

Rate, Cost-recovery, and Other Regulation

State and Local Rate Regulation and Fuel-Cost Recovery

The rates that the Utility operating companies and System Energy charge for their services significantly influence Entergy’s financial position, results of operations, and liquidity. These companies are regulated and the rates charged to their customers are determined in regulatory proceedings. Governmental agencies, including the APSC, the City Council, the LPSC, the MPSC, the PUCT, and the FERC, are primarily responsible for approval of the rates charged to customers. Following is a summary of the Utility operating companies’ authorized returns on common equity:



Company		Authorized Return on Common Equity

Entergy Arkansas		9.25% - 10.25%
Entergy Louisiana		9.15% - 10.75% Electric; 9.45% - 10.45% Gas
Entergy Mississippi		9.89% - 11.97%
Entergy New Orleans		10.7% - 11.5% Electric; 10.25% - 11.25% Gas
Entergy Texas		9.8%

The Utility operating companies’ base rate, fuel and purchased power cost recovery, and storm cost recovery proceedings are discussed in Note 2 to the financial statements.

Federal Regulation

The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including rates for System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. The current return on equity under the Unit Power Sales Agreement is 10.94%. Prior to each operating company’s termination of participation in the System Agreement (Entergy Arkansas in December 2013, Entergy Mississippi in November 2015, and Entergy Louisiana, Entergy New Orleans, and Entergy Texas each in August 2016), the Utility operating companies engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which was a rate schedule approved by the FERC. Certain of the Utility operating companies’ retail regulators are pursuing litigation involving the System Agreement at the FERC and in federal courts. See Note 2 to the financial statements for discussion of the System Agreement proceedings and a complaint filed with the FERC challenging System Energy’s return on equity.

Market and Credit Risk Sensitive Instruments

Market risk is the risk of changes in the value of commodity and financial instruments, or in future net income or cash flows, in response to changing market conditions. Entergy holds commodity and financial instruments that are exposed to the following significant market risks.


•	The commodity price risk associated with the sale of electricity by the Entergy Wholesale Commodities business.


•	The interest rate and equity price risk associated with Entergy’s investments in pension and other postretirement benefit trust funds. See Note 11 to the financial statements for details regarding Entergy’s pension and other postretirement benefit trust funds.

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•	The interest rate and equity price risk associated with Entergy’s investments in nuclear plant decommissioning trust funds, particularly in the Entergy Wholesale Commodities business. See Note 16 to the financial statements for details regarding Entergy’s decommissioning trust funds.


•	The interest rate risk associated with changes in interest rates as a result of Entergy’s outstanding indebtedness. Entergy manages its interest rate exposure by monitoring current interest rates and its debt outstanding in relation to total capitalization. See Notes 4 and 5 to the financial statements for the details of Entergy’s debt outstanding.

The Utility has limited exposure to the effects of market risk because it operates primarily under cost-based rate regulation. To the extent approved by their retail regulators, the Utility operating companies use commodity and financial instruments to hedge the exposure to price volatility inherent in their purchased power, fuel, and gas purchased for resale costs that are recovered from customers.

Entergy’s commodity and financial instruments are also exposed to credit risk. Credit risk is the risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement. Entergy is also exposed to a potential demand on liquidity due to credit support requirements within its supply or sales agreements.

Commodity Price Risk

Power Generation

As a wholesale generator, Entergy Wholesale Commodities’ core business is selling energy, measured in MWh, to its customers. Entergy Wholesale Commodities enters into forward contracts with its customers and also sells energy in the day ahead or spot markets. In addition to selling the energy produced by its plants, Entergy Wholesale Commodities sells unforced capacity, which allows load-serving entities to meet specified reserve and related requirements placed on them by the ISOs in their respective areas. Entergy Wholesale Commodities’ forward physical power contracts consist of contracts to sell energy only, contracts to sell capacity only, and bundled contracts in which it sells both capacity and energy. While the terminology and payment mechanics vary in these contracts, each of these types of contracts requires Entergy Wholesale Commodities to deliver MWh of energy, make capacity available, or both. In addition to its forward physical power contracts, Entergy Wholesale Commodities also uses a combination of financial contracts, including swaps, collars, and options, to manage forward commodity price risk. Certain hedge volumes have price downside and upside relative to market price movement. The contracted minimum, expected value, and sensitivities are provided in the table below to show potential variations. The sensitivities may not reflect the total maximum upside potential from higher market prices. The information contained in the following table represents projections at a point in time and will vary over time based on numerous factors, such as future market prices, contracting activities, and generation. Following is a summary of Entergy Wholesale Commodities’ current forward capacity and generation contracts as well as total revenue projections based on market prices as of December 31, 2016.

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Entergy Wholesale Commodities Nuclear Portfolio



	2017	2018	2019	2020	2021
Energy
Percent of planned generation under contract (a):
Unit-contingent (b)	87%	66%	5%	—%	—%
Firm LD (c)	10%	—%	—%	—%	—%
Offsetting positions (d)	(10%)	(10%)	—%	—%	—%
Total	87%	56%	5%	—%	—%
Planned generation (TWh) (e) (f)	27.3	26.7	18.8	11.7	2.9
Average revenue per MWh on contracted volumes:
Minimum	$43.7	$36.4	$53.2	$—	$—
Expected based on market prices as of December 31, 2016	$44.0	$36.4	$53.2	$—	$—
Sensitivity: -/+ $10 per MWh market price change	$43.8-$44.5	$34.9-$37.8	$53.2	$—	$—

Capacity
Percent of capacity sold forward (g):
Bundled capacity and energy contracts (h)	22%	10%	—%	—%	—%
Capacity contracts (i)	31%	23%	12%	—%	—%
Total	53%	33%	12%	—%	—%
Planned net MW in operation (average) (f)	3,568	3,365	2,356	1,384	347
Average revenue under contract per kW per month (applies to capacity contracts only)	$4.9	$9.4	$11.1	$—	$—

Total Nuclear Energy and Capacity Revenues (j)
Expected sold and market total revenue per MWh	$50.6	$44.6	$44.4	$43.6	$48.1
Sensitivity: -/+ $10 per MWh market price change	$49.5-$52.0	$39.3-$49.9	$34.9-$53.9	$33.6-$53.6	$38.1-$58.1


(a)	Percent of planned generation output sold or purchased forward under contracts, forward physical contracts, forward financial contracts, or options that mitigate price uncertainty that may require regulatory approval or approval of transmission rights. Positions that are not classified as hedges are netted in the planned generation under contract.

(b)

Transaction under which power is supplied from a specific generation asset; if the asset is not operating, the seller is generally not liable to buyer for any damages. Certain unit-contingent sales include a guarantee of availability. Availability guarantees provide for the payment to the power purchaser of contract damages, if incurred, in the event the seller fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. All of Entergy’s outstanding guarantees of availability provide for dollar limits on Entergy’s maximum liability under such guarantees.

(c)

Transaction that requires receipt or delivery of energy at a specified delivery point (usually at a market hub not associated with a specific asset) or settles financially on notional quantities; if a party fails to deliver or receive energy, defaulting party must compensate the other party as specified in the contract, a portion of which may be capped through the use of risk management products. This also includes option transactions that may expire without being exercised.


(d)	Transactions for the purchase of energy, generally to offset a Firm LD transaction.

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(e)	Amount of output expected to be generated by Entergy Wholesale Commodities resources considering plant operating characteristics, outage schedules, and expected market conditions that affect dispatch.

(f)

Assumes the sale of FitzPatrick to Exelon in the second quarter 2017, planned shutdown of Palisades on October 1, 2018, planned shutdown of Pilgrim on May 31, 2019, planned shutdown of Indian Point 2 on April 30, 2020, and planned shutdown of Indian Point 3 on April 30, 2021. Assumes NRC license renewals for two units, as follows (with current license expirations in parentheses): Indian Point 2 (September 2013 and now operating under its period of extended operations while its application is pending) and Indian Point 3 (December 2015 and now operating under its period of extended operations while its application is pending). For a discussion regarding the planned sale of the FitzPatrick plant and planned shutdown of the Palisades, Pilgrim, Indian Point 2, and Indian Point 3 plants, see “Entergy Wholesale Commodities Exit from the Merchant Power Business” above. For a discussion regarding the license renewals for Indian Point 2 and Indian Point 3, see “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants” above.


(g)	Percent of planned qualified capacity sold to mitigate price uncertainty under physical or financial transactions.


(h)	A contract for the sale of installed capacity and related energy, priced per megawatt-hour sold.


(i)	A contract for the sale of an installed capacity product in a regional market.


(j)	Includes assumptions on converting a portion of the portfolio to contracted with fixed price cost or discount and excludes non-cash revenue from the amortization of the Palisades below-market purchased power agreement, mark-to-market activity, and service revenues.

Entergy estimates that a positive $10 per MWh change in the annual average energy price in the markets in which the Entergy Wholesale Commodities nuclear business sells power, based on the respective year-end market conditions, planned generation volumes, and hedged positions, would have a corresponding effect on pre-tax income of $37 million in 2017 and would have had a corresponding effect on pre-tax income of $99 million in 2016. A negative $10 per MWh change in the annual average energy price in the markets based on the respective year-end market conditions, planned generation volumes, and hedged positions, would have a corresponding effect on pre-tax income of ($31) million in 2017 and would have had a corresponding effect on pre-tax income of ($74) million in 2016.

Entergy’s purchase of the FitzPatrick and Indian Point 3 plants from NYPA included value sharing agreements with NYPA. In October 2007, NYPA and the subsidiaries that own the FitzPatrick and Indian Point 3 plants amended and restated the value sharing agreements to clarify and amend certain provisions of the original terms. Under the amended value sharing agreements, the Entergy subsidiaries agreed to make annual payments to NYPA based on the generation output of the Indian Point 3 and FitzPatrick plants from January 2007 through December 2014. Entergy subsidiaries paid NYPA $6.59 per MWh for power sold from Indian Point 3, up to an annual cap of $48 million, and $3.91 per MWh for power sold from FitzPatrick, up to an annual cap of $24 million. The annual payment for each year’s output was due by January 15 of the following year. Entergy recorded the liability for payments to NYPA as power is generated and sold by Indian Point 3 and FitzPatrick. In 2014, Entergy Wholesale Commodities recorded a liability of approximately $72 million for generation during that year. An amount equal to the liability was recorded each year to the plant asset account as contingent purchase price consideration for the plants.

Some of the agreements to sell the power produced by Entergy Wholesale Commodities’ power plants contain provisions that require an Entergy subsidiary to provide credit support to secure its obligations under the agreements. The Entergy subsidiary is required to provide credit support based upon the difference between the current market prices and contracted power prices in the regions where Entergy Wholesale Commodities sells power. The primary form of credit support to satisfy these requirements is an Entergy Corporation guaranty. Cash and letters of credit are also acceptable forms of credit support. At December 31, 2016, based on power prices at that time, Entergy had liquidity exposure of $128 million under the guarantees in place supporting Entergy Wholesale Commodities transactions and $8 million of posted cash collateral. In the event of a decrease in Entergy Corporation’s credit rating to below investment grade, based on power prices as of December 31, 2016, Entergy would have been required to provide approximately $57 million of additional cash or letters of credit under some of the agreements. As of December 31, 2016, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $238 million for a $1 per MMBtu increase in gas prices in both the short-and long-term markets.

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As of December 31, 2016, substantially all of the credit exposure associated with the planned energy output under contract for Entergy Wholesale Commodities nuclear plants through 2021 is with counterparties or their guarantors that have public investment grade credit ratings.

Nuclear Matters

In 2016, Entergy conducted a comprehensive evaluation of the Entergy nuclear fleet and determined that it is necessary to increase investments in its nuclear plants to position the fleet to meet its operational goals. These investments will result in increased operating and capital costs associated with operating Entergy’s nuclear plants going forward. The preliminary estimates of the increase to planned capital costs for 2017 through 2019 identified through and associated with this initiative are estimated to be $870 million for Utility. The preliminary estimates indicate that the capital costs identified through this initiative for Entergy Wholesale Commodities are expected to have a minimal effect on Entergy’s preliminary capital investment plan estimate for 2017 through 2019. The current estimates of the capital costs identified through this initiative are included in Entergy’s preliminary capital investment plan estimate for 2017 through 2019 given in “Liquidity and Capital Resources - Capital Expenditure Plans and Other Uses of Capital” above. The increase to planned other operation and maintenance expenses identified through and associated with this initiative is preliminarily estimated to be approximately $125 million in 2017 for Utility, with a similar level of expenses expected to continue going forward, and approximately $25 million in 2017 for Entergy Wholesale Commodities, with a similar level of expenses expected to continue going forward while the merchant nuclear plants are operating. In addition, nuclear refueling outage expenses are expected to increase going forward for both Utility and Entergy Wholesale Commodities.

The nuclear industry continues to address susceptibility to stress corrosion cracking of certain materials within the plant systems. The issue is applicable at all nuclear units to varying degrees and is managed in accordance with industry standard practices and guidelines that include in-service examinations, replacements, and mitigation strategies. Developments in the industry or identification of issues at the nuclear units could require unanticipated remediation efforts that cannot be quantified in advance.

ANO

See “ANO Damage, Outage, and NRC Reviews” above and Note 8 to the financial statements for discussion of the NRC’s decision to move ANO into the “multiple/repetitive degraded cornerstone column,” or Column 4, of the NRC’s Reactor Oversight Process Action Matrix, and the resulting significant additional NRC inspection activities at the ANO site.

Pilgrim

See Note 8 to the financial statements for discussion of the NRC’s decision in September 2015 to place Pilgrim in Column 4 of its Reactor Oversight Process Action Matrix due to its finding of continuing weaknesses in Pilgrim’s corrective action program that contributed to repeated unscheduled shutdowns and equipment failures.

Indian Point

During the scheduled refueling and maintenance outage at Indian Point Unit 2 in the first quarter 2016, comprehensive inspections were done as part of the aging management program that calls for an in-depth inspection of the reactor vessel. Inspections of more than 2,000 bolts in the reactor’s removable insert liner identified issues with roughly 11% of the bolts that required further analysis. Entergy replaced bolts as appropriate, and the unit returned to service on June 16, 2016. The repair costs were accounted for as deferred refueling outage costs and will be amortized over the plant’s subsequent fuel cycle. In addition to the repair costs, Entergy lost net revenue due to the plant being offline. Entergy estimates the negative effect on earnings was approximately $51 million pre-tax in second quarter 2016. Entergy evaluated the scope and duration of Indian Point 3’s scheduled refueling outage planned for 2017. Based on the results of that evaluation and analysis, Entergy is extending Indian Point 3’s 2017 outage by 20 days.

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Grand Gulf

Grand Gulf began a maintenance outage on September 8, 2016 to replace a residual heat removal pump. Although the pump had been replaced, on September 27, 2016 management decided to keep the plant in an outage for additional training and other steps to support management’s operational goals. Grand Gulf returned to service on January 31, 2017.

Based on the plant’s recent performance indicators, in November 2016 the NRC placed Grand Gulf in the “regulatory response column,” or Column 2, of its Reactor Oversight Process Action Matrix. Additionally, in October 2016 the NRC commenced a special inspection to investigate the circumstances surrounding the unplanned unavailability of an alternate heat removal system during the September 2016 replacement of the heat removal pump and to evaluate the licensee’s actions to address the causes of the event. Depending upon the findings of the NRC and the plant’s performance indicators, there is risk that the NRC could move Grand Gulf into the “degraded cornerstone column,” or Column 3, of the NRC’s Reactor Oversight Action Matrix.

Critical Accounting Estimates

The preparation of Entergy’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in these assumptions and measurements could produce estimates that would have a material effect on the presentation of Entergy’s financial position, results of operations, or cash flows.

Nuclear Decommissioning Costs

Entergy subsidiaries own nuclear generation facilities in both the Utility and Entergy Wholesale Commodities operating segments. Regulations require Entergy subsidiaries to decommission the nuclear power plants after each facility is taken out of service, and cash is deposited in trust funds during the facilities’ operating lives in order to provide for this obligation. Entergy conducts periodic decommissioning cost studies to estimate the costs that will be incurred to decommission the facilities. The following key assumptions have a significant effect on these estimates.

•

Timing - In projecting decommissioning costs, two assumptions must be made to estimate the timing of plant decommissioning. First, the date of the plant’s retirement must be estimated for those plants that do not have an announced shutdown date. The estimate may include assumptions regarding the possibility that the plant may have an operating life shorter than the operating license expiration, as well as assumptions regarding the probability that the plant’s license will be renewed for those plants that have not yet received operating license renewal. Second, an assumption must be made whether all decommissioning activity will proceed immediately upon plant retirement, or whether the plant will be placed in SAFSTOR status. SAFSTOR is decommissioning a facility by placing it in a safe, stable condition that is maintained until it is subsequently decontaminated and dismantled to levels that permit license termination, normally within 60 years from permanent cessation of operations. A change of assumption regarding either the probability of license renewal, the period of continued operation, or the use of a SAFSTOR period can change the present value of the asset retirement obligations.

•

Cost Escalation Factors - Entergy’s current decommissioning cost studies include an assumption that decommissioning costs will escalate over present cost levels by factors ranging from approximately 2% to 3% annually. A 50-basis point change in this assumption could change the estimated present value of the decommissioning liabilities by approximately 5% to 15%. The timing assumption influences the significance of the effect of a change in the estimated inflation or cost escalation rate because the effect increases with the length of time assumed before decommissioning activity ends.


•	Spent Fuel Disposal - Federal law requires the DOE to provide for the permanent storage of spent nuclear fuel, and legislation has been passed by Congress to develop a repository at Yucca Mountain, Nevada. The DOE

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has not yet begun accepting spent nuclear fuel and is in non-compliance with federal law. The DOE continues to delay meeting its obligation and Entergy’s nuclear plant owners are continuing to pursue damage claims against the DOE for its failure to provide timely spent fuel storage. Until a federal site is available, however, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities. The costs of developing and maintaining these facilities during the decommissioning period can have a significant effect (as much as an average of 20% to 30% of total estimated decommissioning costs). Entergy’s decommissioning studies include cost estimates for spent fuel storage. These estimates could change in the future, however, based on the expected timing of when the DOE begins to fulfill its obligation to receive and store spent nuclear fuel. See Note 8 to the financial statements for further discussion of Entergy’s spent nuclear fuel litigation.

•

Technology and Regulation - Over the past several years, more practical experience with the actual decommissioning of nuclear facilities has been gained and that experience has been incorporated into Entergy’s current decommissioning cost estimates. Given the long duration of decommissioning projects, additional experience, including technological advancements in decommissioning, could occur, however, and affect current cost estimates. In addition, if regulations regarding nuclear decommissioning were to change, this could significantly affect cost estimates.

•

Interest Rates - The estimated decommissioning costs that are the basis for the recorded decommissioning liability are discounted to present value using a credit-adjusted risk-free rate. When the decommissioning liability is revised, increases in cash flows are discounted using the current credit-adjusted risk-free rate. Decreases in estimated cash flows are discounted using the credit-adjusted risk-free rate used previously in estimating the decommissioning liability that is being revised. Therefore, to the extent that a revised cost study results in an increase in estimated cash flows, a change in interest rates from the time of the previous cost estimate will affect the calculation of the present value of the revised decommissioning liability.

Revisions of estimated decommissioning costs that decrease the liability also result in a decrease in the asset retirement cost asset. For the non-rate-regulated portions of Entergy’s business, these reductions will immediately reduce operating expenses in the period of the revision if the reduction of the liability exceeds the amount of the undepreciated asset retirement cost asset at the date of the revision. Revisions of estimated decommissioning costs that increase the liability result in an increase in the asset retirement cost asset, which is then depreciated over the asset’s remaining economic life. For a plant in the non-rate-regulated portions of Entergy’s business for which the plant’s value is impaired, however, including a plant that is shutdown, or is nearing its shutdown date, the increase in the liability is likely to immediately increase operating expense in the period of the revision and not increase the asset retirement cost asset. See Note 14 to the financial statements for further discussion of impairment of long-lived assets and Note 9 to the financial statements for further discussion of asset retirement obligations.

Utility Regulatory Accounting

Entergy’s Utility operating companies and System Energy are subject to retail regulation by their respective state and local regulators and to wholesale regulation by the FERC. Because these regulatory agencies set the rates the Utility operating companies and System Energy are allowed to charge customers based on allowable costs, including a reasonable return on equity, the Utility operating companies and System Energy apply accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs that have been deferred because it is probable such amounts will be returned to customers through future regulated rates. See Note 2 to the financial statements for a discussion of rate and regulatory matters, including details of Entergy’s and the Registrant Subsidiaries’ regulatory assets and regulatory liabilities.

For each regulatory jurisdiction in which they conduct business, the Utility operating companies and System Energy assess whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in

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applicable regulatory and political environments. If the assessments made by the Utility operating companies and System Energy are ultimately different than actual regulatory outcomes, it could materially affect the results of operations, financial position, and cash flows of Entergy or the Registrant Subsidiaries.

Unbilled Revenue

As discussed in Note 1 to the financial statements, Entergy records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month’s estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period, in addition to changes in certain components of the calculation.

Impairment of Long-lived Assets and Trust Fund Investments

Entergy has significant investments in long-lived assets in both of its operating segments, and Entergy evaluates these assets against the market economics and under the accounting rules for impairment when there are indications that an impairment may exist. This evaluation involves a significant degree of estimation and uncertainty. In the Entergy Wholesale Commodities business, Entergy’s investments in merchant generation assets are subject to impairment if adverse market or regulatory conditions arise, particularly if it leads to a decision or an expectation that Entergy will operate a plant for a shorter period than previously expected; if there is a significant adverse change in the physical condition of a plant; if investment in a plant significantly exceeds previously-expected amounts; or, for Indian Point 2 and Indian Point 3, if their operating licenses are not renewed.

If an asset is considered held for use, and Entergy concludes that events and circumstances are present indicating that an impairment analysis should be performed under the accounting standards, the sum of the expected undiscounted future cash flows from the asset are compared to the asset’s carrying value. The carrying value of the asset includes any capitalized asset retirement cost associated with the decommissioning liability; therefore, changes in assumptions that affect the decommissioning liability can increase or decrease the carrying value of the asset subject to impairment. If the expected undiscounted future cash flows exceed the carrying value, no impairment is recorded. If the expected undiscounted future cash flows are less than the carrying value and the carrying value exceeds the fair value, Entergy is required to record an impairment charge to write the asset down to its fair value. If an asset is considered held for sale, an impairment is required to be recognized if the fair value (less costs to sell) of the asset is less than its carrying value.

The expected future cash flows are based on a number of key assumptions, including:


•	Future power and fuel prices - Electricity and gas prices can be very volatile. This volatility increases the imprecision inherent in the long-term forecasts of commodity prices that are a key determinant of estimated future cash flows.


•	Market value of generation assets - Valuing assets held for sale requires estimating the current market value of generation assets. While market transactions provide evidence for this valuation, these transactions are relatively infrequent, the market for such assets is volatile, and the value of individual assets is affected by factors unique to those assets.


•	Future operating costs - Entergy assumes relatively minor annual increases in operating costs. Technological or regulatory changes that have a significant effect on operations could cause a significant change in these assumptions.


•	Timing and the life of the asset - Entergy assumes an expected life of the asset. A change in the timing assumption, whether due to management decisions regarding operation of the plant, the regulatory process, or operational or other factors, could have a significant effect on the expected future cash flows and result in a significant effect on operations.

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Management’s Financial Discussion and Analysis

See Note 14 to the financial statements for a discussion of the impairments of the Palisades, Indian Point 2 and 3, FitzPatrick, and Pilgrim plants.

Entergy evaluates investment securities in the Entergy Wholesale Commodities’ nuclear decommissioning trust funds with unrealized losses at the end of each period to determine whether an other-than-temporary impairment has occurred. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs. If Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary-impairment is considered to have occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss). The assessment of whether an investment in an equity security has suffered an other than temporary impairment is based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time. Entergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. As discussed in Note 1 to the financial statements, unrealized losses on equity securities that are considered other-than-temporarily impaired are recorded in earnings for Entergy Wholesale Commodities. See Note 16 to the financial statements for details on the decommissioning trust funds.

Taxation and Uncertain Tax Positions

Management exercises significant judgment in evaluating the potential tax effects of Entergy’s operations, transactions, and other events. Entergy accounts for uncertain income tax positions using a recognition model under a two-step approach with a more likely-than-not recognition threshold and a measurement approach based on the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement. Management evaluates each tax position based on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to determine whether available information supports the assertion that the recognition threshold has been met. Additionally, measurement of unrecognized tax benefits to be recorded in the consolidated financial statements is based on the probability of different potential outcomes. Income tax expense and tax positions recorded could be significantly affected by events such as additional transactions contemplated or consummated by Entergy as well as audits by taxing authorities of the tax positions taken in transactions. Management believes that the financial statement tax balances are accounted for and adjusted appropriately each quarter as necessary in accordance with applicable authoritative guidance; however, the ultimate outcome of tax matters could result in favorable or unfavorable effects on the consolidated financial statements. Entergy’s income taxes, including unrecognized tax benefits, open audits, and other significant tax matters are discussed in Note 3 to the financial statements.

It is possible that significant changes will be made to the Internal Revenue Code in 2017. Both the U.S. House of Representatives and the Trump administration have advanced proposals. Based on current proposals, a reduction in the statutory rate would be offset by modification or elimination of certain tax deductions. Entergy is monitoring the legislative progress. It is possible that such legislative changes would have a significant effect on the financial position, results of operations, or cash flows of Entergy and the Registrant Subsidiaries.

Qualified Pension and Other Postretirement Benefits

Entergy sponsors qualified, defined benefit pension plans that cover substantially all employees, including cash balance plans and final average pay plans. Additionally, Entergy currently provides other postretirement health care and life insurance benefits for substantially all full-time employees whose most recent date of hire or rehire is before July 1, 2014 and who reach retirement age and meet certain eligibility requirements while still working for Entergy.

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Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

Entergy’s reported costs of providing these benefits, as described in Note 11 to the financial statements, are affected by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate for the Utility and Entergy Wholesale Commodities segments.

Assumptions

Key actuarial assumptions utilized in determining qualified pension and other postretirement health care and life insurance costs include discount rates, projected healthcare cost rates, expected long-term rate of return on plan assets, rate of increase in future compensation levels, retirement rates and mortality rates.

Annually, Entergy reviews and, when necessary, adjusts the assumptions for the pension and other postretirement plans. Every three-to-five years, a formal actuarial assumption experience study that compares assumptions to the actual experience of the pension and other postretirement health care and life insurance plans is conducted. The falling interest rate environment over the past few years and volatility in the financial equity markets have affected Entergy’s funding and reported costs for these benefits.

Discount rates

In selecting an assumed discount rate to calculate benefit obligations, Entergy uses a yield curve based on high-quality corporate debt. Before 2016 the discount rates used to estimate the service cost and interest cost components of benefit costs were the same as the weighted-average discount rate used to measure the benefit obligation at the beginning of the year. In 2016, Entergy refined its approach to estimating the service cost and interest cost components. Under the refined approach, instead of using the weighted-average benefit obligation discount rate at the beginning of the year, the 2016 service and interest costs’ expected cash flows were discounted by the applicable spot rates. The refinement had the effect of lowering 2016 qualified pension costs by $61 million and 2016 other postretirement health care and life insurance benefit costs by $15 million.

Projected health care cost trend rates

Entergy’s health care cost trend is affected by both medical cost inflation, and with respect to capped costs under the plan, the effects of general inflation. Entergy reviews actual recent cost trends and projected future trends in establishing its health care cost trend rates.

Expected long-term rate of return on plan assets

In determining its expected long-term rate of return on plan assets used in the calculation of benefit plan costs, Entergy reviews past performance, current and expected future asset allocations, and capital market assumptions of its investment consultant and investment managers. Entergy conducts periodic asset/liability studies in order to set its target asset allocations.

Since 2003, Entergy has targeted an asset allocation for its qualified pension plan assets of roughly 65% equity securities and 35% fixed-income securities. In 2011, Entergy adopted a liability driven investment strategy for its pension assets, which recommended that the target asset allocation adjust dynamically over time, based on the funded status of the plan, from its current allocation to an ultimate allocation of 45% equity and 55% fixed income securities. The ultimate asset allocation is expected to be attained when the plan is 105% funded.

The current target allocations for both Entergy’s non-taxable other postretirement assets and its taxable other postretirement assets are 65% equity securities and 35% fixed-income securities. During the first quarter 2017, Entergy will be implementing a new asset allocation strategy, which will result in an overall shift to more fixed income in the non-taxable trusts and no material changes in asset allocation to the taxable trust.

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Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

Retirement and mortality rates

In December 2016 the Internal Revenue Service issued proposed mortality regulations for single employer plans for determining cash contribution requirements, as established by the Employee Retirement Income Security Act of 1974, as amended and the Internal Revenue Code of 1986, as amended. The proposed regulations would be effective for plan years beginning on or after January 1, 2018, and, as such, have no impact on 2017 plan year minimum required contributions. The proposed regulations are generally anticipated to increase the 2018 minimum funding target liability for most pension plans by about 4% to 8%. The new mortality tables were adopted for accounting in 2014.

Costs and Sensitivities

The estimated 2017 and actual 2016 qualified pension and other postretirement costs and related underlying assumptions and sensitivities are shown below:



Costs	Estimated 2017	2016
	(In Millions)
Qualified pension cost	$214	$215
Other postretirement cost	$26	$20

Assumptions	2017	2016
Discount rates
Qualified pension
Service cost	4.75%	5.00%
Interest cost	3.73%	3.90%
Other postretirement
Service cost	4.60%	4.92%
Interest cost	3.61%	3.78%

Expected long-term rates of return
Qualified pension assets	7.50%	7.75%
Other postretirement - non-taxable assets	6.50% - 6.90%	7.75%
Other postretirement - taxable assets	5.75%	6.00%

Weighted-average rate of future compensation	3.98%	4.23%

Assumed health care cost trend rates
Pre-65 retirees	6.55%	6.75%
Post-65 retirees	7.25%	7.55%
Ultimate rate	4.75%	4.75%
Year ultimate rate is reached and beyond	2026	2024

Actual asset returns have an effect on Entergy’s qualified pension and other postretirement costs. In 2016, Entergy’s actual average annual return on qualified pension assets was approximately 8.80% and for other postretirement assets was approximately 7.20%, as compared with the 2016 expected long-term rates of return discussed above. For 2017, Entergy decreased its expected long-term rate of return assumptions, to take into account changes in capital market assumptions and results of asset allocation studies.

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Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

The following chart reflects the sensitivity of qualified pension cost and qualified pension projected benefit obligation to changes in certain actuarial assumptions (dollars in millions):



Actuarial Assumption	Change in Assumption	Impact on 2017 Qualified Pension Cost		Impact on 2016 Qualified Projected Benefit Obligation
	Increase/(Decrease)
Discount rate	(0.25%)		$24		$235
Rate of return on plan assets	(0.25%)		$14	$-
Rate of increase in compensation	0.25%		$6		$33

The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in millions):



Actuarial Assumption	Change in Assumption	Impact on 2017 Postretirement Benefit Cost		Impact on 2016 Accumulated Postretirement Benefit Obligation
	Increase/(Decrease)
Discount rate	(0.25%)		$4		$50
Health care cost trend	0.25%		$6		$41

Each fluctuation above assumes that the other components of the calculation are held constant.

Accounting Mechanisms

In accordance with pension accounting standards, Entergy utilizes a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are amortized into expense only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees. Additionally, accounting standards allow for the deferral of prior service costs/credits arising from plan amendments that attribute an increase or decrease in benefits to employee service in prior periods. Prior service costs/credits are then amortized into expense over the average future working life of active employees. Certain decisions, including workforce reductions, plan amendments, and plant shutdowns may significantly reduce the expense amortization period and result in immediate recognition of certain previously-deferred costs and gains/losses in the form of curtailment gains or losses. Similarly, payments made to settle benefit obligations can also result in recognition in the form of settlement losses or gains.

Entergy calculates the expected return on pension and other postretirement benefit plan assets by multiplying the long-term expected rate of return on assets by the market-related value (MRV) of plan assets. Entergy determines the MRV of pension plan assets by calculating a value that uses a 20-quarter phase-in of the difference between actual and expected returns. For other postretirement benefit plan assets Entergy uses fair value when determining MRV.

Accounting standards require an employer to recognize in its balance sheet the funded status of its benefit plans. See Note 11 to the financial statements for a further discussion of Entergy’s funded status.

Funding

Entergy’s pension funding in 2016 was $390 million. Entergy estimates pension contributions will be approximately $409 million in 2017; although the 2017 required pension contributions will be known with more certainty when the January 1, 2017 valuations are completed, which is expected by April 1, 2017.

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Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

Minimum required funding calculations as determined under Pension Protection Act guidance are performed annually as of January 1 of each year and are based on measurements of the assets and funding liabilities as measured at that date. Any excess of the funding liability over the calculated fair market value of assets results in a funding shortfall that, under the Pension Protection Act, must be funded over a seven-year rolling period. The Pension Protection Act also imposes certain plan limitations if the funded percentage, which is based on calculated fair market values of assets divided by funding liabilities, does not meet certain thresholds. For funding purposes, asset gains and losses are smoothed in to the calculated fair market value of assets and the funding liability is based upon a weighted average 24-month corporate bond rate published by the U.S. Treasury; therefore, periodic changes in asset returns and interest rates can affect funding shortfalls and future cash contributions.

Moving Ahead for Progress in the 21st Century Act (MAP-21) became federal law in July 2012. Under the law, the segment rates used to calculate funding liabilities must be within a corridor of the 25-year average of prior segment rates. The interest rate corridor applies to the determination of minimum funding requirements and benefit restrictions. These pension funding stabilization provisions will provide for a near-term reduction in minimum funding requirements for single employer defined benefit plans in response to the historically low interest rates that existed when the law was enacted. The law did not reduce contribution requirements over the long term. The interest rate stabilization periods of MAP-21 were extended by the Highway and Transportation Funding Act in 2014 and the Bipartisan Budget Act in 2015.

Federal Healthcare Legislation

In 2010 the Patient Protection and Affordable Care Act (PPACA), as amended, imposed a 40% excise tax on per capita medical benefit costs that exceed certain thresholds. The excise tax is due to take effect in 2018. There are many technical issues, however, that have not been finalized. In 2017, under the new Presidential administration, the PPACA is expected to be further amended or repealed and replaced. Entergy will continue to monitor developments to determine the possible effect on Entergy.

Other Contingencies

As a company with multi-state utility operations, Entergy is subject to a number of federal and state laws and regulations and other factors and conditions in the areas in which it operates, which potentially subject it to environmental, litigation, and other risks. Entergy periodically evaluates its exposure for such risks and records a reserve for those matters which are considered probable and estimable in accordance with generally accepted accounting principles.

Environmental

Entergy must comply with environmental laws and regulations applicable to air emissions, water discharges, solid and hazardous waste, toxic substances, protected species, and other environmental matters. Under these various laws and regulations, Entergy could incur substantial costs to comply or address any impacts to the environment. Entergy conducts studies to determine the extent of any required remediation and has recorded liabilities based upon its evaluation of the likelihood of loss and expected dollar amount for each issue. Additional sites or issues could be identified which require environmental remediation or corrective action for which Entergy could be liable. The amounts of environmental liabilities recorded can be significantly affected by the following external events or conditions.


•	Changes to existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters.


•	The identification of additional impacts, sites, issues, or the filing of other complaints in which Entergy may be asserted to be a potentially responsible party.


•	The resolution or progression of existing matters through the court system or resolution by the EPA or relevant state or local authority.

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Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

Litigation

Entergy is regularly named as a defendant in a number of lawsuits involving employment, customers, and injuries and damages issues, among other matters. Entergy periodically reviews the cases in which it has been named as defendant and assesses the likelihood of loss in each case as probable, reasonably possible, or remote and records liabilities for cases that have a probable likelihood of loss and the loss can be estimated. Given the environment in which Entergy operates, and the unpredictable nature of many of the cases in which Entergy is named as a defendant, the ultimate outcome of the litigation to which Entergy is exposed has the potential to materially affect the results of operations, financial position, and cash flows of Entergy or the Registrant Subsidiaries.

New Accounting Pronouncements

In May 2014 the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” The ASU’s core principle is that “an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.” The ASU details a five-step model that should be followed to achieve the core principle. With FASB issuance of ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” ASU 2014-09 is effective for Entergy for the first quarter 2018. Entergy is evaluating its transition approach (which will either be a full retrospective or a modified retrospective transition method) and the effects of the new guidance, most significantly on its accounting for contributions in aid of construction. Entergy’s evaluation of ASU 2014-09 has not identified any effects that it expects will affect materially its results of operations, financial position, or cash flows. Entergy will continue to monitor, however, the development of industry specific application guidance that could have an effect on this assessment.

In January 2016 the FASB issued ASU No. 2016-01 “Financial Instruments (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities.” The ASU requires investments in equity securities, excluding those accounted for under the equity method or resulting in consolidation of the investee, to be measured at fair value with changes recognized in net income. The ASU requires a qualitative assessment to identify impairments of investments in equity securities that do not have a readily determinable fair value. ASU 2016-01 is effective for Entergy for the first quarter 2018. Entergy expects that ASU 2016-01 will affect its results of operations by requiring unrealized gains and losses on investments in equity securities held by the nuclear decommissioning trust funds to be recorded in earnings rather than in other comprehensive income. In accordance with the regulatory treatment of the decommissioning trust funds of Entergy Arkansas, Entergy Louisiana, and System Energy, an offsetting amount of unrealized gains/losses will continue to be recorded in other regulatory liabilities/assets. Entergy is evaluating the ASU for other effects on the results of operations, financial position, and cash flows.

In February 2016 the FASB issued ASU No. 2016-02, “Leases (Topic 842).” The ASU’s core principle is that “a lessee should recognize the assets and liabilities that arise from leases.” The ASU considers that “all leases create an asset and a liability,” and accordingly requires recording the assets and liabilities related to all leases with a term greater than 12 months. ASU 2016-02 is effective for Entergy for the first quarter 2019, with early adoption permitted. Entergy expects that ASU 2016-02 will affect its financial position by increasing the assets and liabilities recorded relating to its operating leases. Entergy is evaluating ASU 2016-02 for other effects on its results of operations, financial position, and cash flows, as well as the potential to early adopt the ASU.

In March 2016 the FASB issued ASU No. 2016-09, “Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting.” The ASU seeks to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The statement is effective beginning in 2017 and Entergy will prospectively recognize all income tax effects related to share-based payments through the income statement. Entergy expects to record approximately $12 million in income tax expense in the first quarter of 2017 related to implementing ASU 2016-09.

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Entergy Corporation and Subsidiaries

Management’s Financial Discussion and Analysis

In June 2016 the FASB issued ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” The ASU requires entities to record a valuation allowance on financial instruments recorded at amortized cost or classified as available-for-sale debt securities for the total credit losses expected over the life of the instrument. Increases and decreases in the valuation allowance will be recognized immediately in earnings. ASU 2016-13 is effective for Entergy for the first quarter 2020. Entergy is evaluating ASU 2016-13 for the expected effects on its results of operations, financial position, and cash flows.

In October 2016 the FASB issued ASU No. 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory.” The ASU requires entities to recognize the income tax consequences of intra-entity asset transfers, other than inventory, at the time the transfer occurs. ASU 2016-16 is effective for Entergy for the first quarter 2018 and will affect its statement of financial position by requiring recognition of deferred tax assets or liabilities arising from intra-entity asset transfers. Entergy is evaluating ASU 2016-16 for other effects on its results of operations, financial position, and cash flows.

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ENTERGY CORPORATION AND SUBSIDIARIES

REPORT OF MANAGEMENT

Management of Entergy Corporation and its subsidiaries has prepared and is responsible for the financial statements and related financial information included in this document. To meet this responsibility, management establishes and maintains a system of internal controls over financial reporting designed to provide reasonable assurance regarding the preparation and fair presentation of financial statements in accordance with generally accepted accounting principles. This system includes communication through written policies and procedures, an employee Code of Entegrity, and an organizational structure that provides for appropriate division of responsibility and training of personnel. This system is also tested by a comprehensive internal audit program.

Entergy management assesses the design and effectiveness of Entergy’s internal control over financial reporting on an annual basis. In making this assessment, management uses the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. The 2013 COSO Framework was utilized for management’s assessment. Management acknowledges, however, that all internal control systems, no matter how well designed, have inherent limitations and can provide only reasonable assurance with respect to financial statement preparation and presentation.

Entergy Corporation’s independent registered public accounting firm, Deloitte & Touche LLP, has issued an attestation report on the effectiveness of Entergy Corporation’s internal control over financial reporting as of December 31, 2016.

In addition, the Audit Committee of the Board of Directors, composed solely of independent Directors, meets with the independent auditors, internal auditors, management, and internal accountants periodically to discuss internal controls, and auditing and financial reporting matters. The Audit Committee appoints the independent auditors annually, seeks shareholder ratification of the appointment, and reviews with the independent auditors the scope and results of the audit effort. The Audit Committee also meets periodically with the independent auditors and the chief internal auditor without management present, providing free access to the Audit Committee.

Based on management’s assessment of internal controls using the 2013 COSO criteria, management believes that Entergy and each of the Registrant Subsidiaries maintained effective internal control over financial reporting as of December 31, 2016. Management further believes that this assessment, combined with the policies and procedures noted above, provides reasonable assurance that Entergy’s and each of the Registrant Subsidiaries’ financial statements are fairly and accurately presented in accordance with generally accepted accounting principles.



LEO P. DENAULT Chairman of the Board and Chief Executive Officer of Entergy Corporation	ANDREW S. MARSH Executive Vice President and Chief Financial Officer of Entergy Corporation, Entergy Arkansas, Inc., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., Entergy Texas, Inc., and System Energy Resources, Inc.
RICHARD C. RILEY Chairman of the Board, President, and Chief Executive Officer of Entergy Arkansas, Inc.	PHILLIP R. MAY, JR. Chairman of the Board, President, and Chief Executive Officer of Entergy Louisiana, LLC
HALEY R. FISACKERLY Chairman of the Board, President, and Chief Executive Officer of Entergy Mississippi, Inc.	CHARLES L. RICE, JR. Chairman of the Board, President, and Chief Executive Officer of Entergy New Orleans, Inc.
SALLIE T. RAINER Chair of the Board, President, and Chief Executive Officer of Entergy Texas, Inc.	THEODORE H. BUNTING, JR. Chairman of the Board, President, and Chief Executive Officer of System Energy Resources, Inc.

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ENTERGY CORPORATION AND SUBSIDIARIES
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON

	2016			2015			2014			2013			2012
	(In Thousands, Except Percentages and Per Share Amounts)

Operating revenues		$10,845,645			$11,513,251			$12,494,921			$11,390,947			$10,302,079
Net income (loss)		($564,503	)		($156,734	)		$960,257			$730,572			$868,363
Earnings (loss) per share:
Basic		($3.26	)		($0.99	)		$5.24			$3.99			$4.77
Diluted		($3.26	)		($0.99	)		$5.22			$3.99			$4.76
Dividends declared per share		$3.42			$3.34			$3.32			$3.32			$3.32
Return on common equity	(6.73		%)	(1.83		%)	9.58		%	7.56		%	9.33		%
Book value per share, year-end		$45.12			$51.89			$55.83			$54.00			$51.72
Total assets		$45,904,434			$44,647,681			$46,414,455			$43,290,290			$43,087,339
Long-term obligations (a)		$14,695,422			$13,456,742			$12,627,180			$12,265,971			$12,026,207

(a) Includes long-term debt (excluding currently maturing debt), non-current capital lease obligations, and subsidiary preferred stock without sinking fund that is not presented as equity on the balance sheet.

	2016			2015			2014			2013			2012
	(Dollars In Millions)

Utility electric operating revenues:
Residential		$3,288			$3,518			$3,555			$3,396			$3,022
Commercial	2,362			2,516			2,553			2,415			2,174
Industrial	2,327			2,462			2,623			2,405			2,034
Governmental	217			223			227			218			198
Total retail	8,194			8,719			8,958			8,434			7,428
Sales for resale	236			249			330			210			179
Other	437			341			304			298			264
Total		$8,867			$9,309			$9,592			$8,942			$7,871

Utility billed electric energy sales (GWh):
Residential	35,112			36,068			35,932			35,169			34,664
Commercial	29,197			29,348			28,827			28,547			28,724
Industrial	45,739			44,382			43,723			41,653			41,181
Governmental	2,547			2,514			2,428			2,412			2,435
Total retail	112,595			112,312			110,910			107,781			107,004
Sales for resale	11,054			9,274			9,462			3,020			3,200
Total	123,649			121,586			120,372			110,801			110,204

Entergy Wholesale Commodities:
Operating revenues		$1,850			$2,062			$2,719			$2,313			$2,326
Billed electric energy sales (GWh)	35,881			39,745			44,424			45,127			46,178

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Entergy Corporation and Subsidiaries

New Orleans, Louisiana

We have audited the accompanying consolidated balance sheets of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 2016 and 2015, and the related consolidated statements of operations, comprehensive income (loss), cash flows, and changes in equity for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Corporation and Subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Corporation’s internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2017 expressed an unqualified opinion on the Corporation’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 24, 2017

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ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS

	For the Years Ended December 31,
	2016			2015			2014
	(In Thousands, Except Share Data)
OPERATING REVENUES
Electric		$8,866,659			$9,308,678			$9,591,902
Natural gas	129,348			142,746			181,794
Competitive businesses	1,849,638			2,061,827			2,721,225
TOTAL	10,845,645			11,513,251			12,494,921

OPERATING EXPENSES
Operation and Maintenance:
Fuel, fuel-related expenses, and gas purchased for resale	1,809,200			2,452,171			2,632,558
Purchased power	1,220,527			1,390,805			1,915,414
Nuclear refueling outage expenses	208,678			251,316			267,679
Other operation and maintenance	3,296,711			3,354,981			3,310,536
Asset write-offs, impairments, and related charges	2,835,637			2,104,906			179,752
Decommissioning	327,425			280,272			272,621
Taxes other than income taxes	592,502			619,422			604,606
Depreciation and amortization	1,347,187			1,337,276			1,318,638
Other regulatory charges (credits) - net	94,243			175,304			(13,772		)
TOTAL	11,732,110			11,966,453			10,488,032

Gain on sale of asset	—			154,037			—

OPERATING INCOME (LOSS)	(886,465		)	(299,165		)	2,006,889

OTHER INCOME
Allowance for equity funds used during construction	67,563			51,908			64,802
Interest and investment income	145,127			187,062			147,686
Miscellaneous - net	(41,617		)	(95,997		)	(42,016		)
TOTAL	171,073			142,973			170,472

INTEREST EXPENSE
Interest expense	700,545			670,096			661,083
Allowance for borrowed funds used during construction	(34,175		)	(26,627		)	(33,576		)
TOTAL	666,370			643,469			627,507

INCOME (LOSS) BEFORE INCOME TAXES	(1,381,762		)	(799,661		)	1,549,854

Income taxes	(817,259		)	(642,927		)	589,597

CONSOLIDATED NET INCOME (LOSS)	(564,503		)	(156,734		)	960,257

Preferred dividend requirements of subsidiaries	19,115			19,828			19,536

NET INCOME (LOSS) ATTRIBUTABLE TO ENTERGY CORPORATION		($583,618	)		($176,562	)		$940,721

Earnings (loss) per average common share:
Basic		($3.26	)		($0.99	)		$5.24
Diluted		($3.26	)		($0.99	)		$5.22

Basic average number of common shares outstanding	178,885,660			179,176,356			179,506,151
Diluted average number of common shares outstanding	178,885,660			179,176,356			180,296,885

See Notes to Financial Statements.

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ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

	For the Years Ended December 31,
	2016			2015			2014
	(In Thousands)

Net Income (Loss)		($564,503	)		($156,734	)		$960,257

Other comprehensive income (loss)
Cash flow hedges net unrealized gain (loss)
(net of tax expense (benefit) of ($55,298), $3,752, and $96,141)	(101,977		)	7,852			179,895
Pension and other postretirement liabilities
(net of tax expense (benefit) of ($3,952), $61,576, and ($152,763))	(2,842		)	103,185			(281,566		)
Net unrealized investment gains (losses)
(net of tax expense (benefit) of $57,277, ($45,904), and $66,594)	62,177			(59,138		)	89,439
Foreign currency translation
(net of tax benefit of $689, $345, and $404)	(1,280		)	(641		)	(751		)
Other comprehensive income (loss)	(43,922		)	51,258			(12,983		)

Comprehensive Income (Loss)	(608,425		)	(105,476		)	947,274
Preferred dividend requirements of subsidiaries	19,115			19,828			19,536
Comprehensive Income (Loss) Attributable to Entergy Corporation		($627,540	)		($125,304	)		$927,738

See Notes to Financial Statements.

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ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
	2016			2015			2014
	(In Thousands)

OPERATING ACTIVITIES
Consolidated net income (loss)		($564,503	)		($156,734	)		$960,257
Adjustments to reconcile consolidated net income (loss) to net cash flow provided by operating activities:
Depreciation, amortization, and decommissioning, including nuclear fuel amortization	2,123,291			2,117,236			2,127,892
Deferred income taxes, investment tax credits, and non-current taxes accrued	(836,257		)	(820,350		)	596,935
Asset write-offs, impairments, and related charges	2,835,637			2,104,906			123,527
Gain on sale of asset	—			(154,037		)	—
Changes in working capital:
Receivables	(96,975		)	38,152			98,493
Fuel inventory	38,210			(12,376		)	3,524
Accounts payable	174,421			(135,211		)	(12,996		)
Prepaid taxes and taxes accrued	(28,963		)	81,969			(62,985		)
Interest accrued	(7,335		)	(11,445		)	25,013
Deferred fuel costs	(241,896		)	298,725			(70,691		)
Other working capital accounts	31,197			(113,701		)	112,390
Changes in provisions for estimated losses	20,905			42,566			301,871
Changes in other regulatory assets	(48,469		)	262,317			(1,061,537		)
Changes in other regulatory liabilities	158,031			61,241			87,654
Changes in pensions and other postretirement liabilities	(136,919		)	(446,418		)	1,308,166
Other	(421,676		)	134,344			(647,952		)
Net cash flow provided by operating activities	2,998,699			3,291,184			3,889,561

INVESTING ACTIVITIES
Construction/capital expenditures	(2,780,222		)	(2,500,860		)	(2,119,191		)
Allowance for equity funds used during construction	68,345			53,635			68,375
Nuclear fuel purchases	(314,706		)	(493,604		)	(537,548		)
Payment for purchase of plant	(949,329		)	—			—
Proceeds from sale of assets	—			487,406			10,100
Insurance proceeds received for property damages	20,968			24,399			40,670
Changes in securitization account	4,007			(5,806		)	1,511
NYPA value sharing payment	—			(70,790		)	(72,000		)
Payments to storm reserve escrow account	(1,544		)	(69,163		)	(276,057		)
Receipts from storm reserve escrow account	—			5,916			—
Decrease in other investments	9,055			571			46,983
Litigation proceeds for reimbursement of spent nuclear fuel storage costs	169,085			18,296			—
Proceeds from nuclear decommissioning trust fund sales	2,408,920			2,492,176			1,872,115
Investment in nuclear decommissioning trust funds	(2,484,627		)	(2,550,958		)	(1,989,446		)
Net cash flow used in investing activities	(3,850,048		)	(2,608,782		)	(2,954,488		)

See Notes to Financial Statements.

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ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
	2016			2015			2014
	(In Thousands)

FINANCING ACTIVITIES
Proceeds from the issuance of:
Long-term debt	6,800,558			3,502,189			3,100,069
Preferred stock of subsidiary	—			107,426			—
Treasury stock	33,114			24,366			194,866
Retirement of long-term debt	(5,311,324		)	(3,461,518		)	(2,323,313		)
Repurchase of common stock	—			(99,807		)	(183,271		)
Repurchase / redemptions of preferred stock	(115,283		)	(94,285		)	—
Changes in credit borrowings and commercial paper - net	(79,337		)	(104,047		)	(448,475		)
Other	(6,872		)	(9,136		)	23,579
Dividends paid:
Common stock	(611,835		)	(598,897		)	(596,117		)
Preferred stock	(20,789		)	(19,758		)	(19,511		)
Net cash flow provided by (used in) financing activities	688,232			(753,467		)	(252,173		)


Net increase (decrease) in cash and cash equivalents	(163,117		)	(71,065		)	682,900

Cash and cash equivalents at beginning of period	1,350,961			1,422,026			739,126

Cash and cash equivalents at end of period		$1,187,844			$1,350,961			$1,422,026

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for:
Interest - net of amount capitalized		$746,779			$663,630			$611,376
Income taxes		$95,317			$103,589			$77,799

See Notes to Financial Statements.

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ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS

	December 31,
	2016			2015
	(In Thousands)

CURRENT ASSETS
Cash and cash equivalents:
Cash		$129,579			$63,497
Temporary cash investments	1,058,265			1,287,464
Total cash and cash equivalents	1,187,844			1,350,961
Accounts receivable:
Customer	654,995			608,491
Allowance for doubtful accounts	(11,924		)	(39,895		)
Other	158,419			178,364
Accrued unbilled revenues	368,677			321,940
Total accounts receivable	1,170,167			1,068,900
Deferred fuel costs	108,465			—
Fuel inventory - at average cost	179,600			217,810
Materials and supplies - at average cost	698,523			873,357
Deferred nuclear refueling outage costs	146,221			211,512
Prepayments and other	193,448			344,872
TOTAL	3,684,268			4,067,412

OTHER PROPERTY AND INVESTMENTS
Investment in affiliates - at equity	198			4,341
Decommissioning trust funds	5,723,897			5,349,953
Non-utility property - at cost (less accumulated depreciation)	233,641			219,999
Other	469,664			468,704
TOTAL	6,427,400			6,042,997

PROPERTY, PLANT, AND EQUIPMENT
Electric	45,191,216			44,467,159
Property under capital lease	619,527			952,465
Natural gas	413,224			392,032
Construction work in progress	1,378,180			1,456,735
Nuclear fuel	1,037,899			1,345,422
TOTAL PROPERTY, PLANT AND EQUIPMENT	48,640,046			48,613,813
Less - accumulated depreciation and amortization	20,718,639			20,789,452
PROPERTY, PLANT AND EQUIPMENT - NET	27,921,407			27,824,361

DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Regulatory asset for income taxes - net	761,280			775,528
Other regulatory assets (includes securitization property of $600,996 as of December 31, 2016 and $714,044 as of December 31, 2015)	4,769,913			4,704,796
Deferred fuel costs	239,100			238,902
Goodwill	377,172			377,172
Accumulated deferred income taxes	117,885			54,903
Other	1,606,009			561,610
TOTAL	7,871,359			6,712,911

TOTAL ASSETS		$45,904,434			$44,647,681

See Notes to Financial Statements.

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ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY

	December 31,
	2016			2015
	(In Thousands)

CURRENT LIABILITIES
Currently maturing long-term debt		$364,900			$214,374
Notes payable and commercial paper	415,011			494,348
Accounts payable	1,285,577			1,071,798
Customer deposits	403,311			419,407
Taxes accrued	181,114			210,077
Interest accrued	187,229			194,565
Deferred fuel costs	102,753			235,986
Obligations under capital leases	2,423			2,709
Pension and other postretirement liabilities	76,942			62,513
Other	180,836			184,181
TOTAL	3,200,096			3,089,958

NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued	7,495,290			8,306,865
Accumulated deferred investment tax credits	227,147			234,300
Obligations under capital leases	24,582			27,001
Other regulatory liabilities	1,572,929			1,414,898
Decommissioning and asset retirement cost liabilities	5,992,476			4,790,187
Accumulated provisions	481,636			460,727
Pension and other postretirement liabilities	3,036,010			3,187,357
Long-term debt (includes securitization bonds of $661,175 as of December 31, 2016 and $774,696 as of December 31, 2015)	14,467,655			13,111,556
Other	1,121,619			449,856
TOTAL	34,419,344			31,982,747

Commitments and Contingencies

Subsidiaries’ preferred stock without sinking fund	203,185			318,185

COMMON EQUITY
Common stock, $.01 par value, authorized 500,000,000 shares; issued 254,752,788 shares in 2016 and in 2015	2,548			2,548
Paid-in capital	5,417,245			5,403,758
Retained earnings	8,195,571			9,393,913
Accumulated other comprehensive income (loss)	(34,971		)	8,951
Less - treasury stock, at cost (75,623,363 shares in 2016 and 76,363,763 shares in 2015)	5,498,584			5,552,379
TOTAL	8,081,809			9,256,791

TOTAL LIABILITIES AND EQUITY		$45,904,434			$44,647,681

See Notes to Financial Statements.

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ENTERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Years Ended December 31, 2016, 2015, and 2014

				Common Shareholders’ Equity
	Subsidiaries’ Preferred Stock			Common Stock		Treasury Stock			Paid-in Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
	(In Thousands)

Balance at December 31, 2013		$94,000			$2,548		($5,533,942	)		$5,368,131		$9,825,053			($29,324	)		$9,726,466

Consolidated net income (a)	19,536			—		—			—		940,721			—			960,257
Other comprehensive loss	—			—		—			—		—			(12,983		)	(12,983		)
Common stock repurchases	—			—		(183,271		)	—		—			—			(183,271		)
Common stock issuances related to stock plans	—			—		219,687			7,222		—			—			226,909
Common stock dividends declared	—			—		—			—		(596,117		)	—			(596,117		)
Preferred dividend requirements of subsidiaries (a)	(19,536		)	—		—			—		—			—			(19,536		)

Balance at December 31, 2014		$94,000			$2,548		($5,497,526	)		$5,375,353		$10,169,657			($42,307	)		$10,101,725

Consolidated net income (loss) (a)	19,828			—		—			—		(176,562		)	—			(156,734		)
Other comprehensive income	—			—		—			—		—			51,258			51,258
Common stock repurchases	—			—		(99,807		)	—		—			—			(99,807		)
Preferred stock repurchases / redemptions	(94,000		)	—		—			—		(285		)	—			(94,285		)
Common stock issuances related to stock plans	—			—		44,954			28,405		—			—			73,359
Common stock dividends declared	—			—		—			—		(598,897		)	—			(598,897		)
Preferred dividend requirements of subsidiaries (a)	(19,828		)	—		—			—		—			—			(19,828		)

Balance at December 31, 2015		$—			$2,548		($5,552,379	)		$5,403,758		$9,393,913			$8,951			$9,256,791

Consolidated net income (loss) (a)	19,115			—		—			—		(583,618		)	—			(564,503		)
Other comprehensive loss	—			—		—			—		—			(43,922		)	(43,922		)
Common stock issuances related to stock plans	—			—		53,795			13,487		—			—			67,282
Common stock dividends declared	—			—		—			—		(611,835		)	—			(611,835		)
Subsidiaries' capital stock redemptions	—			—		—			—		(2,889		)	—			(2,889		)
Preferred dividend requirements of subsidiaries (a)	(19,115		)	—		—			—		—			—			(19,115		)

Balance at December 31, 2016		$—			$2,548		($5,498,584	)		$5,417,245		$8,195,571			($34,971	)		$8,081,809

See Notes to Financial Statements.
(a) Consolidated net income and preferred dividend requirements of subsidiaries include $19.1 million for 2016, $14.9 million for 2015, and $12.9 million for 2014 of preferred dividends on subsidiaries’ preferred stock without sinking fund that is not presented as equity.

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ENTERGY CORPORATION AND SUBSIDIARIES

NOTES TO FINANCIAL STATEMENTS

NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

The accompanying consolidated financial statements include the accounts of Entergy Corporation and its subsidiaries. As required by generally accepted accounting principles in the United States of America, all intercompany transactions have been eliminated in the consolidated financial statements. Entergy’s Registrant Subsidiaries (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy) also include their separate financial statements in this Form 10-K. The Registrant Subsidiaries and many other Entergy subsidiaries also maintain accounts in accordance with FERC and other regulatory guidelines.

Use of Estimates in the Preparation of Financial Statements

In conformity with generally accepted accounting principles in the United States of America, the preparation of Entergy Corporation’s consolidated financial statements and the separate financial statements of the Registrant Subsidiaries requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Adjustments to the reported amounts of assets and liabilities may be necessary in the future to the extent that future estimates or actual results are different from the estimates used.

Revenues and Fuel Costs

Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas generate, transmit, and distribute electric power primarily to retail customers in Arkansas, Louisiana, Mississippi, and Texas, respectively. Entergy Louisiana also distributes natural gas to retail customers in and around Baton Rouge, Louisiana. Entergy New Orleans sells both electric power and natural gas to retail customers in the City of New Orleans, including Algiers. Prior to October 1, 2015, Entergy Louisiana was the electric power supplier for Algiers. The Entergy Wholesale Commodities segment derives almost all of its revenue from sales of electric power generated by plants owned by subsidiaries in that segment.

Entergy recognizes revenue from electric power and natural gas sales when power or gas is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, Entergy’s Utility operating companies accrue an estimate of the revenues for energy delivered since the latest billings. The Utility operating companies calculate the estimate based upon several factors including billings through the last billing cycle in a month, actual generation in the month, historical line loss factors, and prices in effect in Entergy’s Utility operating companies’ various jurisdictions. Changes are made to the inputs in the estimate as needed to reflect changes in billing practices. Each month the estimated unbilled revenue amounts are recorded as revenue and unbilled accounts receivable, and the prior month’s estimate is reversed. Therefore, changes in price and volume differences resulting from factors such as weather affect the calculation of unbilled revenues from one period to the next, and may result in variability in reported revenues from one period to the next as prior estimates are reversed and new estimates recorded.

Entergy records revenue from sales under rates implemented subject to refund less estimated amounts accrued for probable refunds when Entergy believes it is probable that revenues will be refunded to customers based upon the status of the rate proceeding.

Entergy’s Utility operating companies’ rate schedules include either fuel adjustment clauses or fixed fuel factors, which allow either current recovery in billings to customers or deferral of fuel costs until the costs are billed to customers. Where the fuel component of revenues is billed based on a pre-determined fuel cost (fixed fuel factor), the fuel factor remains in effect until changed as part of a general rate case, fuel reconciliation, or fixed fuel factor filing. System Energy’s operating revenues are intended to recover from Entergy Arkansas, Entergy Louisiana, Entergy

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf. The capital costs are computed by allowing a return on System Energy’s common equity funds allocable to its net investment in Grand Gulf, plus System Energy’s effective interest cost for its debt allocable to its investment in Grand Gulf.

Accounting for MISO transactions

In December 2013, Entergy joined MISO, a regional transmission organization that maintains functional control over the combined transmission systems of its members and manages one of the largest energy markets in the U.S. In the MISO market, Entergy offers its generation and bids its load into the market on an hourly basis. MISO settles these hourly offers and bids based on locational marginal prices, which is pricing for energy at a given location based on a market clearing price that takes into account physical limitations on the transmission system, generation, and demand throughout the MISO region. MISO evaluates the market participants’ energy offers and demand bids to economically and reliably dispatch the entire MISO system. Entergy nets purchases and sales within the MISO market on an hourly basis and reports in operating revenues when in a net selling position and in operating expenses when in a net purchasing position.

Property, Plant, and Equipment

Property, plant, and equipment is stated at original cost. Depreciation is computed on the straight-line basis at rates based on the applicable estimated service lives of the various classes of property. For the Registrant Subsidiaries, the original cost of plant retired or removed, less salvage, is charged to accumulated depreciation. Normal maintenance, repairs, and minor replacement costs are charged to operating expenses. Substantially all of the Registrant Subsidiaries’ plant is subject to mortgage liens.

Electric plant includes the portions of Grand Gulf and Waterford 3 that have been sold and leased back. For financial reporting purposes, these sale and leaseback arrangements are reflected as financing transactions. In March 2016, Entergy Louisiana completed the first step in a two-step transaction to purchase the undivided interests in Waterford 3 that were previously being leased by acquiring a beneficial interest in the Waterford 3 leased assets. In February 2017 the leases were terminated and the leased assets transferred to Entergy Louisiana. See Note 10 to the financial statements for further discussion of Entergy Louisiana’s purchase of the Waterford 3 leased assets.

Net property, plant, and equipment for Entergy (including property under capital lease and associated accumulated amortization) by business segment and functional category, as of December 31, 2016 and 2015, is shown below:



2016	Entergy		Utility		Entergy Wholesale Commodities		Parent & Other
	(In Millions)
Production
Nuclear		$6,948		$6,524		$424		$—
Other	4,047		4,000		47		—
Transmission	5,226		5,223		3		—
Distribution	7,648		7,648		—		—
Other	1,636		1,521		111		4
Construction work in progress	1,378		1,334		44		—
Nuclear fuel	1,038		817		221		—
Property, plant, and equipment - net		$27,921		$27,067		$850		$4

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Entergy Corporation and Subsidiaries

Notes to Financial Statements



2015	Entergy		Utility		Entergy Wholesale Commodities		Parent & Other
	(In Millions)
Production
Nuclear		$8,672		$6,606		$2,066		$—
Other	3,176		3,127		49		—
Transmission	4,431		4,408		23		—
Distribution	7,207		7,207		—		—
Other	1,536		1,422		111		3
Construction work in progress	1,457		1,327		130		—
Nuclear fuel	1,345		857		489		—
Property, plant, and equipment - net		$27,824		$24,954		$2,868		$3

Depreciation rates on average depreciable property for Entergy approximated 2.8% in 2016, 2.9% in 2015, and 2.8% in 2014. Included in these rates are the depreciation rates on average depreciable Utility property of 2.6% in 2016, 2.7% in 2015, and 2.5% 2014, and the depreciation rates on average depreciable Entergy Wholesale Commodities property of 5.2% in 2016, 5.4% in 2015, and 5.5% in 2014.

Entergy amortizes nuclear fuel using a units-of-production method. Nuclear fuel amortization is included in fuel expense in the income statements.

“Non-utility property - at cost (less accumulated depreciation)” for Entergy is reported net of accumulated depreciation of $169 million and $164 million as of December 31, 2016 and 2015, respectively.

Construction expenditures included in accounts payable is $253 million and $234 million at December 31, 2016 and 2015, respectively.

Net property, plant, and equipment for the Registrant Subsidiaries (including property under capital lease and associated accumulated amortization) by company and functional category, as of December 31, 2016 and 2015, is shown below:



2016	Entergy Arkansas		Entergy Louisiana		Entergy Mississippi		Entergy New Orleans		Entergy Texas		System Energy
	(In Millions)
Production
Nuclear		$1,201		$3,540		$—		$—		$—		$1,783
Other	801		1,966		537		213		483		—
Transmission	1,491		1,925		740		79		943		45
Distribution	2,144		2,632		1,242		414		1,216		—
Other	216		517		201		188		106		25
Construction work in progress	304		670		118		25		111		44
Nuclear fuel	307		250		—		—		—		260
Property, plant, and equipment - net		$6,464		$11,500		$2,838		$919		$2,859		$2,157

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Entergy Corporation and Subsidiaries

Notes to Financial Statements



2015	Entergy Arkansas		Entergy Louisiana		Entergy Mississippi		Entergy New Orleans			Entergy Texas		System Energy
	(In Millions)
Production
Nuclear		$1,192		$3,611		$—		$—			$—		$1,803
Other	597		1,551		529		(13		)	463		—
Transmission	1,223		1,693		658		65			723		46
Distribution	1,997		2,488		1,166		400			1,156		—
Other	179		483		199		184			104		17
Construction work in progress	388		421		114		29			211		93
Nuclear fuel	286		387		—		—			—		184
Property, plant, and equipment - net		$5,862		$10,634		$2,666		$665			$2,657		$2,143

Depreciation rates on average depreciable property for the Registrant Subsidiaries are shown below:



	Entergy Arkansas	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy
2016	2.5%	2.3%	3.1%	3.4%	2.5%	2.8%
2015	2.6%	2.3%	3.2%	3.0%	2.6%	2.8%
2014	2.4%	2.2%	2.6%	3.2%	2.5%	3.0%

Non-utility property - at cost (less accumulated depreciation) for Entergy Louisiana is reported net of accumulated depreciation of $154.4 million and $150.1 million as of December 31, 2016 and 2015, respectively. Non-utility property - at cost (less accumulated depreciation) for Entergy Mississippi is reported net of accumulated depreciation of $0.5 million and $0.5 million as of December 31, 2016 and 2015, respectively. Non-utility property - at cost (less accumulated depreciation) for Entergy Texas is reported net of accumulated depreciation of $4.9 million and $4.9 million as of December 31, 2016 and 2015, respectively.

As of December 31, 2016, construction expenditures included in accounts payable are $40.9 million for Entergy Arkansas, $114.8 million for Entergy Louisiana, $11.5 million for Entergy Mississippi, $2.3 million for Entergy New Orleans, $9.3 million for Entergy Texas, and $6.2 million for System Energy. As of December 31, 2015, construction expenditures included in accounts payable are $43 million for Entergy Arkansas, $68.6 million for Entergy Louisiana, $11.4 million for Entergy Mississippi, $1.5 million for Entergy New Orleans, $33.1 million for Entergy Texas, and $6.8 million for System Energy.

Jointly-Owned Generating Stations

Certain Entergy subsidiaries jointly own electric generating facilities with affiliates or third parties. All parties are required to provide their own financing. The investments, fuel expenses, and other operation and maintenance expenses associated with these generating stations are recorded by the Entergy subsidiaries to the extent of their respective undivided ownership interests. As of December 31, 2016, the subsidiaries’ investment and accumulated depreciation in each of these generating stations were as follows:

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Entergy Corporation and Subsidiaries

Notes to Financial Statements



Generating Stations		Fuel Type	Total Megawatt Capability (a)	Ownership			Investment		Accumulated Depreciation
							(In Millions)
Utility business:
Entergy Arkansas -
Independence	Unit 1	Coal	839	31.50	%			$134		$103
Independence	Common Facilities	Coal		15.75	%			$34		$27
White Bluff	Units 1 and 2	Coal	1,635	57.00	%			$521		$365
Ouachita (b)	Common Facilities	Gas	493	66.67	%			$172		$148
Union (c)	Units 1 and 2 Common Facilities	Gas		50.00	%			$1		$—
Union (c)	Common Facilities	Gas		25.00	%			$25		$1
Entergy Louisiana -
Roy S. Nelson	Unit 6	Coal	550	40.25	%			$277		$189
Roy S. Nelson	Unit 6 Common Facilities	Coal		18.65	%			$14		$6
Big Cajun 2	Unit 3	Coal	588	24.15	%			$150		$113
Big Cajun 2	Unit 3 Common Facilities	Coal		8.05	%			$5		$2
Ouachita (b)	Common Facilities	Gas	248	33.33	%			$90		$75
Acadia	Common Facilities	Gas	557	50.00	%			$19		$—
Union (c)	Common Facilities	Gas		50.00	%			$50		$1
Entergy Mississippi -
Independence	Units 1 and 2 and Common Facilities	Coal	1,681	25.00	%			$257		$155
Entergy New Orleans -
Union (c)	Units 1 and 2 Common Facilities	Gas		50.00	%			$1		$—
Union (c)	Common Facilities	Gas		25.00	%			$25		$1
Entergy Texas -
Roy S. Nelson	Unit 6	Coal	550	29.75	%			$198		$113
Roy S. Nelson	Unit 6 Common Facilities	Coal		13.79	%			$6		$2
Big Cajun 2	Unit 3	Coal	588	17.85	%			$113		$74
Big Cajun 2	Unit 3 Common Facilities	Coal		5.95	%			$3		$1
System Energy -
Grand Gulf	Unit 1	Nuclear	1,401	90.00	%	(d)		$4,917		$3,063
Entergy Wholesale Commodities:
Independence	Unit 2	Coal	842	14.37	%			$71		$49
Independence	Common Facilities	Coal		7.18	%			$16		$12
Roy S. Nelson	Unit 6	Coal	550	10.90	%			$112		$60
Roy S. Nelson	Unit 6 Common Facilities	Coal		5.05	%			$2		$1

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Entergy Corporation and Subsidiaries

Notes to Financial Statements


(a)	“Total Megawatt Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.


(b)	Ouachita Units 1 and 2 are owned 100% by Entergy Arkansas and Ouachita Unit 3 is owned 100% by Entergy Louisiana. The investment and accumulated depreciation numbers above are only for the common facilities and not for the generating units.


(c)	Union Unit 1 is owned 100% by Entergy New Orleans, Union Unit 2 is owned 100% by Entergy Arkansas, Union Units 3 and 4 are owned 100% by Entergy Louisiana. The investment and accumulated depreciation numbers above are only for the specified common facilities and not for the generating units.


(d)	Includes a leasehold interest held by System Energy. System Energy’s Grand Gulf lease obligations are discussed in Note 10 to the financial statements.

Nuclear Refueling Outage Costs

Nuclear refueling outage costs are deferred during the outage and amortized over the estimated period to the next outage because these refueling outage expenses are incurred to prepare the units to operate for the next operating cycle without having to be taken off line. Because the value of their long-lived assets are impaired, and their remaining estimated operating lives significantly reduced, in the future the Entergy Wholesale Commodities nuclear plants will charge nuclear refueling outage costs directly to expense when incurred.

Allowance for Funds Used During Construction (AFUDC)

AFUDC represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction by the Registrant Subsidiaries. AFUDC increases both the plant balance and earnings and is realized in cash through depreciation provisions included in the rates charged to customers.

Income Taxes

Entergy Corporation and the majority of its subsidiaries file a United States consolidated federal income tax return. Entergy Louisiana, LLC is not a member of the Entergy Corporation federal tax filing group but, rather, is included in the Entergy Utility Holding Company, LLC consolidated federal income tax filing group. Each tax-paying entity records income taxes as if it were a separate taxpayer and consolidating adjustments are allocated to the tax filing entities in accordance with Entergy’s intercompany income tax allocation agreements. Deferred income taxes are recorded for temporary differences between the book and tax basis of assets and liabilities, and for certain losses and credits available for carryforward.

Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates in the period in which the tax or rate was enacted.

The benefits of investment tax credits are deferred and amortized over the average useful life of the related property, as a reduction of income tax expense, for such credits associated with regulated operations in accordance with ratemaking treatment.

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Notes to Financial Statements

Earnings (Loss) per Share

The following table presents Entergy’s basic and diluted earnings per share calculation included on the consolidated statements of operations:



	For the Years Ended December 31,
	2016						2015						2014
	(In Millions, Except Per Share Data)
				$/share						$/share					$/share
Net income (loss) attributable to Entergy Corporation		($583.6	)					($176.6	)					$940.7
Basic earnings (loss) per average common share	178.9				($3.26	)	179.2				($0.99	)	179.5			$5.24
Average dilutive effect of:
Stock options	—			—			—			—			0.3		(0.01		)
Other equity plans	—			—			—			—			0.5		(0.01		)
Diluted earnings (loss) per average common shares	178.9				($3.26	)	179.2				($0.99	)	180.3			$5.22

The calculation of diluted earnings (loss) per share excluded 7,137,210 options outstanding at December 31, 2016, 7,399,820 options outstanding at December 31, 2015, and 5,743,013 options outstanding at December 31, 2014 because they were antidilutive.

Stock-based Compensation Plans

Entergy grants stock options, restricted stock, performance units, and restricted stock unit awards to key employees of the Entergy subsidiaries under its Equity Ownership Plans, which are shareholder-approved stock-based compensation plans. These plans are described more fully in Note 12 to the financial statements. The cost of the stock-based compensation is charged to income over the vesting period. Awards under Entergy’s plans generally vest over 3 years.

Accounting for the Effects of Regulation

Entergy’s Utility operating companies and System Energy are rate-regulated enterprises whose rates meet three criteria specified in accounting standards. The Utility operating companies and System Energy have rates that (i) are approved by a body (its regulator) empowered to set rates that bind customers; (ii) are cost-based; and (iii) can be charged to and collected from customers. These criteria may also be applied to separable portions of a utility’s business, such as the generation or transmission functions, or to specific classes of customers. Because the Utility operating companies and System Energy meet these criteria, each of them capitalizes costs that would otherwise be charged to expense if the rate actions of its regulator make it probable that those costs will be recovered in future revenue. Such capitalized costs are reflected as regulatory assets in the accompanying financial statements. When an enterprise concludes that recovery of a regulatory asset is no longer probable, the regulatory asset must be removed from the entity’s balance sheet.

An enterprise that ceases to meet the three criteria for all or part of its operations should report that event in its financial statements. In general, the enterprise no longer meeting the criteria should eliminate from its balance sheet all regulatory assets and liabilities related to the applicable operations. Additionally, if it is determined that a regulated enterprise is no longer recovering all of its costs, it is possible that an impairment may exist that could require further write-offs of plant assets.

Entergy Louisiana does not apply regulatory accounting standards to the Louisiana retail deregulated portion of River Bend, the 30% interest in River Bend formerly owned by Cajun, and its steam business, unless specific cost

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

recovery is provided for in tariff rates. The Louisiana retail deregulated portion of River Bend is operated under a deregulated asset plan representing a portion (approximately 15%) of River Bend plant costs, generation, revenues, and expenses established under a 1992 LPSC order. The plan allows Entergy Louisiana to sell the electricity from the deregulated assets to Louisiana retail customers at 4.6 cents per kWh or off-system at higher prices, with certain provisions for sharing incremental revenue above 4.6 cents per kWh between customers and shareholders.

Regulatory Asset for Income Taxes

Accounting standards for income taxes provide that a regulatory asset or liability be recorded if it is probable that the currently determinable future increase or decrease in regulatory income tax expense will be recovered from or reimbursed to customers through future rates. The primary source of Entergy’s regulatory asset for income taxes is related to the ratemaking treatment of the tax effects of book depreciation for the equity component of AFUDC that has been capitalized to property, plant, and equipment but for which there is no corresponding tax basis. Equity-AFUDC is a component of property, plant, and equipment that is included in rate base when the plant is placed in service.

Cash and Cash Equivalents

Entergy considers all unrestricted highly liquid debt instruments with an original maturity of three months or less at date of purchase to be cash equivalents.

Allowance for Doubtful Accounts

The allowance for doubtful accounts reflects Entergy’s best estimate of losses on the accounts receivable balances. The allowance is based on accounts receivable agings, historical experience, and other currently available evidence. Utility operating company customer accounts receivable are written off consistent with approved regulatory requirements.

Investments

Entergy records decommissioning trust funds on the balance sheet at their fair value. Because of the ability of the Registrant Subsidiaries to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, the Registrant Subsidiaries record an offsetting amount in other regulatory liabilities/assets for the unrealized gains/(losses) on investment securities. For the 30% interest in River Bend formerly owned by Cajun, Entergy Louisiana has recorded an offsetting amount in other deferred credits for the unrealized gains/(losses). Decommissioning trust funds for Pilgrim, Indian Point 1, Indian Point 2, Vermont Yankee, and Palisades do not meet the criteria for regulatory accounting treatment. Accordingly, unrealized gains recorded on the assets in these trust funds are recognized in the accumulated other comprehensive income component of shareholders’ equity because these assets are classified as available for sale. Unrealized losses (where cost exceeds fair market value) on the assets in these trust funds are also recorded in the accumulated other comprehensive income component of shareholders’ equity unless the unrealized loss is other than temporary and therefore recorded in earnings. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs. Further, if Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary impairment is considered to have occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss). The assessment of whether an investment in an equity security has suffered an other-than-temporary impairment is based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time. Entergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. See Note 16 to the financial statements for details on the decommissioning trust funds.

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Notes to Financial Statements

Equity Method Investments

Entergy owns investments that are accounted for under the equity method of accounting because Entergy’s ownership level results in significant influence, but not control, over the investee and its operations. Entergy records its share of the investee’s comprehensive earnings and losses in income and as an increase or decrease to the investment account. Any cash distributions are charged against the investment account. Entergy discontinues the recognition of losses on equity investments when its share of losses equals or exceeds its carrying amount for an investee plus any advances made or commitments to provide additional financial support.

Derivative Financial Instruments and Commodity Derivatives

The accounting standards for derivative instruments and hedging activities require that all derivatives be recognized at fair value on the balance sheet, either as assets or liabilities, unless they meet various exceptions including the normal purchase/normal sale criteria. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction. Due to regulatory treatment, an offsetting regulatory asset or liability is recorded for changes in fair value of recognized derivatives for the Registrant Subsidiaries.

Contracts for commodities that will be physically delivered in quantities expected to be used or sold in the ordinary course of business, including certain purchases and sales of power and fuel, meet the normal purchase, normal sales criteria and are not recognized on the balance sheet. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered.

For other contracts for commodities in which Entergy is hedging the variability of cash flows related to a variable-rate asset, liability, or forecasted transactions that qualify as cash flow hedges, the changes in the fair value of such derivative instruments are reported in other comprehensive income. To qualify for hedge accounting, the relationship between the hedging instrument and the hedged item must be documented to include the risk management objective and strategy and, at inception and on an ongoing basis, the effectiveness of the hedge in offsetting the changes in the cash flows of the item being hedged. Gains or losses accumulated in other comprehensive income are reclassified to earnings in the periods when the underlying transactions actually occur. The ineffective portions of all hedges are recognized in current-period earnings. Changes in the fair value of derivative instruments that are not designated as cash flow hedges are recorded in current-period earnings on a mark-to-market basis.

Entergy has determined that contracts to purchase uranium do not meet the definition of a derivative under the accounting standards for derivative instruments because they do not provide for net settlement and the uranium markets are not sufficiently liquid to conclude that forward contracts are readily convertible to cash. If the uranium markets do become sufficiently liquid in the future and Entergy begins to account for uranium purchase contracts as derivative instruments, the fair value of these contracts would be accounted for consistent with Entergy’s other derivative instruments. See Note 15 to the financial statements for further details on Entergy’s derivative instruments and hedging activities.

Fair Values

The estimated fair values of Entergy’s financial instruments and derivatives are determined using historical prices, bid prices, market quotes, and financial modeling. Considerable judgment is required in developing the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that Entergy could realize in a current market exchange. Gains or losses realized on financial instruments held by regulated businesses may be reflected in future rates and therefore do not affect net income. Entergy considers the carrying amounts of most financial instruments classified as current assets and liabilities to be a reasonable estimate of their fair value because of the short maturity of these instruments. See Note 15 to the financial statements for further discussion of fair value.

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

Impairment of Long-lived Assets

Entergy periodically reviews long-lived assets held in all of its business segments whenever events or changes in circumstances indicate that recoverability of these assets is uncertain. Generally, the determination of recoverability is based on the undiscounted net cash flows expected to result from such operations and assets. Projected net cash flows depend on the expected operating life of the assets, the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for energy and capacity over the remaining life of the assets. Because the values of their long-lived assets are impaired, and their remaining estimated operating lives significantly reduced, in the future the Entergy Wholesale Commodities nuclear plants will charge expenditures for capital assets directly to expense when incurred. See Note 14 to the financial statements for further discussions of the impairments of the Entergy Wholesale Commodities nuclear plants.

River Bend AFUDC

The River Bend AFUDC gross-up is a regulatory asset that represents the incremental difference imputed by the LPSC between the AFUDC actually recorded by Entergy Louisiana on a net-of-tax basis during the construction of River Bend and what the AFUDC would have been on a pre-tax basis. The imputed amount was only calculated on that portion of River Bend that the LPSC allowed in rate base and is being amortized through August 2025.

Reacquired Debt

The premiums and costs associated with reacquired debt of Entergy’s Utility operating companies and System Energy (except that portion allocable to the deregulated operations of Entergy Louisiana) are included in regulatory assets and are being amortized over the life of the related new issuances, or over the life of the original debt issuance if the debt is not refinanced, in accordance with ratemaking treatment.

Taxes Imposed on Revenue-Producing Transactions

Governmental authorities assess taxes that are both imposed on and concurrent with a specific revenue-producing transaction between a seller and a customer, including, but not limited to, sales, use, value added, and some excise taxes. Entergy presents these taxes on a net basis, excluding them from revenues, unless required to report them differently by a regulatory authority.

Presentation of Preferred Stock without Sinking Fund

Accounting standards regarding non-controlling interests and the classification and measurement of redeemable securities require the classification of preferred securities between liabilities and shareholders’ equity on the balance sheet if the holders of those securities have protective rights that allow them to gain control of the board of directors in certain circumstances. These rights would have the effect of giving the holders the ability to potentially redeem their securities, even if the likelihood of occurrence of these circumstances is considered remote. The Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans articles of incorporation provide, generally, that the holders of each company’s preferred securities may elect a majority of the respective company’s board of directors if dividends are not paid for a year, until such time as the dividends in arrears are paid. Therefore, Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans present their preferred securities outstanding between liabilities and shareholders’ equity on the balance sheet. Entergy Louisiana, a limited liability company, had outstanding preferred securities with similar protective rights with respect to unpaid dividends, but provided for the election of board members that would not constitute a majority of the board; and its preferred securities were therefore classified as a component of members’ equity. In September 2015, Entergy Louisiana redeemed or repurchased and canceled its preferred membership interests as part of a multi-step process to effectuate the Entergy Louisiana and Entergy Gulf States Louisiana business combination. See Note 2 to the financial statements for a discussion of the business combination.

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Notes to Financial Statements

The outstanding preferred securities of Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans, and Entergy Utility Holding Company (a Utility subsidiary) and Entergy Finance Holding (an Entergy Wholesale Commodities subsidiary), whose preferred holders also have protective rights, are similarly presented between liabilities and equity on Entergy’s consolidated balance sheets. The preferred dividends or distributions paid by all subsidiaries are reflected for all periods presented outside of consolidated net income.

New Accounting Pronouncements

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

immediately in earnings. ASU 2016-13 is effective for Entergy for the first quarter 2020. Entergy is evaluating ASU 2016-13 for the expected effects on its results of operations, financial position, and cash flows.

NOTE 2. RATE AND REGULATORY MATTERS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Regulatory Assets and Regulatory Liabilities

Regulatory assets represent probable future revenues associated with costs that Entergy expects to recover from customers through the regulatory ratemaking process under which the Utility business operates. Regulatory liabilities represent probable future reductions in revenues associated with amounts that Entergy expects to benefit customers through the regulatory ratemaking process under which the Utility business operates. In addition to the regulatory assets and liabilities that are specifically disclosed on the face of the balance sheets, the tables below provide detail of “Other regulatory assets” and “Other regulatory liabilities” that are included on Entergy’s and the Registrant Subsidiaries’ balance sheets as of December 31, 2016 and 2015:

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Entergy Corporation and Subsidiaries

Notes to Financial Statements

Other Regulatory Assets

Entergy



	2016		2015
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$2,635.5		$2,574.9
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	677.2		589.1
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 – Storm Cost Recovery Filings with Retail Regulators) (Note 5)	637.0		717.8
Removal costs - recovered through depreciation rates (Note 9) (a)	353.9		273.3
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy)	100.0		121.1
Unamortized loss on reacquired debt - recovered over term of debt	91.4		66.7
Transition to competition costs - recovered over a 15-year period through February 2021	47.9		57.4
New nuclear generation development costs (Note 2 - New Nuclear Generation Development Costs) (b)	43.7		51.1
MISO costs - recovery through retail rate mechanisms (Note 2 - Retail Rate Proceedings)	36.2		65.2
Retail rate deferrals - recovered through rate riders as rates are redetermined by retail regulators	22.1		32.2
Human capital management costs - recovery through retail rate mechanisms (Note 2 - Retail Rate Proceedings)	17.3		28.3
Other	107.7		127.7
Entergy Total		$4,769.9		$4,704.8

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Notes to Financial Statements

Entergy Arkansas



	2016		2015
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$786.6		$766.5
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	322.9		288.0
Removal costs - recovered through depreciation rates (Note 9) (a)	128.5		85.7
Storm damage costs - recovered either through securitization or retail rates (Note 5 - Entergy Arkansas Securitization Bonds)	88.9		97.2
Unamortized loss on reacquired debt - recovered over term of debt	27.6		23.0
ANO Fukushima and Flood Barrier costs - recovered through retail rates through February 2026 (Note 2 - Retail Rate Proceedings) (b)	16.1		—
MISO costs - recovery through retail rates through 2018 (Note 2 - Retail Rate Proceedings) (b)	11.1		17.5
Retail rate deferrals - recovered through rate riders as rates are redetermined annually	10.1		18.1
Lake Catherine 4 reliability and sustainability cost deferral - recovery expected through retail rates (b)	9.8		10.4
Incremental ice storm costs - recovered through 2032	7.9		8.4
Human capital management costs - recovery through retail rates through June 2017 (Note 2 - Retail Rate Proceedings) (b)	7.0		10.4
Other	11.5		8.6
Entergy Arkansas Total		$1,428.0		$1,333.8

Entergy Louisiana



	2016		2015
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (a)		$715.7		$718.7
Asset Retirement Obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a)	199.4		180.8
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy)	97.8		119.2
New nuclear generation development costs - recovery through formula rate plan beginning December 2014 through November 2022 (Note 2 - New Nuclear Generation Development Costs) (b)	43.1		50.4
Unamortized loss on reacquired debt - recovered over term of debt	27.0		19.2
MISO costs - recovery through the MISO cost recovery mechanism beginning December 2014 through November 2017 (Note 2 - Retail Rate Proceedings)	21.8		41.1
Business combination external costs deferral - recovery through formula rate plan beginning December 2015 through November 2025 (b)	15.2		16.1
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC)	14.8		16.7
Human capital management costs - recovery through formula rate plan beginning December 2014 through November 2017 (Note 2 - Retail Rate Proceedings)	10.0		17.6
Other	23.3		38.1
Entergy Louisiana Total		$1,168.1		$1,217.9

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Notes to Financial Statements

Entergy Mississippi



	2016		2015
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$217.2		$216.1
Removal costs - recovered through depreciation rates (Note 9) (a)	82.0		77.5
Unamortized loss on reacquired debt - recovered over term of debt	18.9		7.1
Retail rate deferrals - recovered through rate riders as rates are redetermined annually	9.3		7.6
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a)	7.2		6.7
Other	7.6		13.7
Entergy Mississippi Total		$342.2		$328.7

Entergy New Orleans



	2016		2015
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)		$108.8		$103.7
Storm damage costs, including hurricane costs - recovered through retail rates and securitization (Note 2 - Storm Cost Recovery Filings with Retail Regulators)	93.6		104.0
Removal costs - recovered through depreciation rates (Note 9) (a)	40.1		29.4
Retail rate deferrals - recovered through rate riders as rates are redetermined monthly or annually	4.3		3.1
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a)	4.2		4.0
Unamortized loss on reacquired debt - recovered over term of debt	3.4		1.6
Michoud plant maintenance – recovered over a 7-year period through September 2018	3.3		5.2
Rate case costs - recovered over a 6-year period through September 2021 (Note 2 - Retail Rate Proceedings)	3.0		3.2
Other	7.4		11.1
Entergy New Orleans Total		$268.1		$265.3

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Notes to Financial Statements

Entergy Texas



	2016		2015
	(In Millions)
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 5 - Entergy Texas Securitization Bonds)		$442.4		$516.2
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a)	201.7		193.6
Transition to competition costs - recovered over a 15-year period through February 2021	47.9		57.4
Removal costs - recovered through depreciation rates (Note 9) (a)	33.5		25.8
Unamortized loss on reacquired debt - recovered over term of debt	9.0		9.4
Rate case costs - recovered through retail rates (b)	0.5		3.8
Other	5.2		6.7
Entergy Texas Total		$740.2		$812.9

System Energy



	2016		2015
	(In Millions)
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Other Postretirement Benefits) (a)		$193.5		$178.0
Asset retirement obligation - recovery dependent upon timing of decommissioning (Note 9) (a)	142.5		108.6
Removal costs - recovered through depreciation rates (Note 9) (a)	69.7		54.8
Unamortized loss on reacquired debt - recovered over term of debt	5.5		6.4
System Energy Total		$411.2		$347.8


(a)	Does not earn a return on investment, but is offset by related liabilities.


(b)	Does not earn a return on investment.

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Notes to Financial Statements

Other Regulatory Liabilities

Entergy



	2016		2015
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$735.5		$611.7
Vidalia purchased power agreement (Note 8)	202.4		222.6
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators)	165.5		156.0
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates beginning December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination)	83.5		105.2
Waterford 3 replacement steam generator provision (Note 2 - Retail Rate Proceedings)	68.0		31.7
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions)	67.9		67.9
Removal costs - returned to customers through depreciation rates (Note 9) (a)	53.9		68.3
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and FERC	44.4		44.4
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement	39.3		46.4
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)	32.7		28.2
Other	79.8		32.5
Entergy Total		$1,572.9		$1,414.9

Entergy Arkansas



	2016		2015
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$280.8		$236.1
Other	25.1		6.8
Entergy Arkansas Total		$305.9		$242.9

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Notes to Financial Statements

Entergy Louisiana



	2016		2015
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a)		$235.4		$196.9
Vidalia purchased power agreement (Note 8)	202.4		222.6
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators)	165.5		156.0
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates beginning December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination)	83.5		105.2
Waterford 3 replacement steam generator provision (Note 2 - Retail Rate Proceedings)	68.0		31.7
Removal costs - returned to customers through depreciation rates (Note 9) (a)	53.9		68.3
Asset Retirement Obligation - return to customers dependent upon timing of decommissioning (Note 9) (a)	32.7		28.2
Gas hedging costs - refunded through fuel rates (Note 15 - Derivatives)	10.9		—
Other	28.7		9.7
Entergy Louisiana Total		$881.0		$818.6

Entergy Texas



	2016		2015
	(In Millions)
Transition to competition costs - returned to customers through rate riders when rates are redetermined periodically		$6.2		$6.4
Other	2.3		—
Entergy Texas Total		$8.5		$6.4

System Energy



	2016		2015
	(In Millions)
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a)		$219.3		$178.7
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions)	67.9		67.9
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and FERC	44.4		44.4
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement	39.3		46.4
System Energy Total		$370.9		$337.4


(a)	Offset by related asset.

Fuel and purchased power cost recovery

Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas are allowed to recover fuel and purchased power costs through fuel mechanisms included in electric and gas rates that are recorded as fuel cost recovery revenues. The difference between revenues collected and the current fuel and purchased power costs is generally recorded as “Deferred fuel costs” on the Utility operating companies’ financial statements. The

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Notes to Financial Statements

table below shows the amount of deferred fuel costs as of December 31, 2016 and 2015 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.



	2016			2015
	(In Millions)
Entergy Arkansas (a)		$163.6			$57.8
Entergy Louisiana (b)		$119.9			$102.9
Entergy Mississippi		$7.0			($107.8	)
Entergy New Orleans (b)		$8.9			($24.9	)
Entergy Texas		($54.5	)		($25.1	)


(a)	Includes $66.9 million in 2016 and $66.7 million in 2015 of fuel and purchased power costs, which do not currently earn a return on investment and whose recovery periods are indeterminate but are expected to be recovered over a period greater than twelve months.


(b)	Includes $168.1 million in each year for Entergy Louisiana and $4.1 million in each year for Entergy New Orleans of fuel, purchased power, and capacity costs, which do not currently earn a return on investment and whose recovery periods are indeterminate but are expected to be recovered over a period greater than twelve months.

Entergy Arkansas

Production Cost Allocation Rider

The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings, which are discussed in the “System Agreement Cost Equalization Proceedings” section below. These costs cause an increase in Entergy Arkansas’s deferred fuel cost balance because Entergy Arkansas pays the costs over seven months but collects them from customers over twelve months.

In May 2014, Entergy Arkansas filed its annual redetermination of the production cost allocation rider to recover the $3 million unrecovered retail balance as of December 31, 2013 and the $67.8 million System Agreement bandwidth remedy payment made in May 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period. In June 2014 the APSC suspended the annual redetermination of the production cost allocation rider and scheduled a hearing in September 2014. Upon a joint motion of the parties, the APSC canceled the September 2014 hearing and in January 2015 the APSC issued an order approving Entergy Arkansas’s request for recovery of the $3 million under-recovered amount based on the true-up of the production cost allocation rider and the $67.8 million May 2014 System Agreement bandwidth remedy payment subject to refund with interest, with recovery of these payments concluding with the last billing cycle in December 2015. The APSC also found that Entergy Arkansas is entitled to carrying charges pursuant to the current terms of the production cost allocation rider. Entergy Arkansas made its compliance filing pursuant to the order in January 2015 and the APSC issued its approval order, also in January 2015. The redetermined rate went into effect with the first billing cycle of February 2015.

In May 2015, Entergy Arkansas filed its annual redetermination of the production cost allocation rider, which included a $38 million payment made by Entergy Arkansas as a result of the FERC’s February 2014 order related to the comprehensive bandwidth recalculation for calendar year 2006, 2007, and 2008 production costs. The redetermined rate for the 2015 production cost allocation rider update was added to the redetermined rate from the 2014 production cost allocation rider update and the combined rate was effective with the first billing cycle of July 2015. This combined rate was effective through December 2015. The collection of the remainder of the redetermined rate for the 2015 production cost allocation rider update continued through June 2016.

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Notes to Financial Statements

In May 2016, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the production cost allocation rider true-up adjustment of the 2014 and 2015 unrecovered retail balance in the amount of $1.9 million. Additionally, the redetermined rates reflected the recovery of a $1.9 million System Agreement bandwidth remedy payment resulting from a compliance filing pursuant to the FERC’s December 2015 order related to test year 2009 production costs. The rates for the 2016 production cost allocation rider update became effective with the first billing cycle of July 2016, and rates will be effective through June 2017.

Energy Cost Recovery Rider

Entergy Arkansas’s retail rates include an energy cost recovery rider to recover fuel and purchased energy costs in monthly customer bills. The rider utilizes the prior calendar-year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over- or under-recovery, including carrying charges, of the energy costs for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs.

In October 2005 the APSC initiated an investigation into Entergy Arkansas’s interim energy cost recovery rate. The investigation focused on Entergy Arkansas’s 1) gas contracting, portfolio, and hedging practices; 2) wholesale purchases during the period; 3) management of the coal inventory at its coal generation plants; and 4) response to the contractual failure of the railroads to provide coal deliveries. In March 2006 the APSC extended its investigation to cover the costs included in Entergy Arkansas’s March 2006 annual energy cost rate filing, and a hearing was held in the APSC investigation in October 2006.

In January 2007 the APSC issued an order in its review of the energy cost rate. The APSC found that Entergy Arkansas failed to maintain an adequate coal inventory level going into the summer of 2005 and that Entergy Arkansas should be responsible for any incremental energy costs that resulted from two outages caused by employee and contractor error. The coal plant generation curtailments were caused by railroad delivery problems and Entergy Arkansas resolved litigation with the railroad regarding the delivery problems. The APSC staff was directed to perform an analysis with Entergy Arkansas’s assistance to determine the additional fuel and purchased energy costs associated with these findings and file the analysis within sixty days of the order. After a final determination of the costs is made by the APSC, Entergy Arkansas will be directed to refund that amount with interest to its customers as a credit on the energy cost recovery rider. Entergy Arkansas requested rehearing of the order.

In February 2010 the APSC denied Entergy Arkansas’s request for rehearing, and held a hearing in September 2010 to determine the amount of damages, if any, that should be assessed against Entergy Arkansas. A decision is pending. Entergy Arkansas expects the amount of damages, if any, to have an immaterial effect on its results of operations, financial position, or cash flows.

The APSC also established a separate docket to consider the resolved railroad litigation, and in February 2010 it established a procedural schedule that concluded with testimony through September 2010. The testimony was filed, and the APSC will decide the case based on the record in the proceeding.

In January 2014, Entergy Arkansas filed a motion with the APSC relating to its redetermination of its energy cost rate that was subsequently filed in March 2014. In that motion, Entergy Arkansas requested that the APSC authorize Entergy Arkansas to exclude $65.9 million of deferred fuel and purchased energy costs incurred in 2013 from the redetermination of its 2014 energy cost rate. The $65.9 million is an estimate of the incremental fuel and replacement energy costs that Entergy Arkansas incurred as a result of the ANO stator incident. Entergy Arkansas requested that the APSC authorize Entergy Arkansas to retain that amount in its deferred fuel balance, with recovery to be reviewed in a later period after more information is available regarding various claims associated with the ANO stator incident. The APSC approved Entergy Arkansas’s request in February 2014. See the “ANO Damage, Outage, and NRC Reviews” section in Note 8 to the financial statements for further discussion of the ANO stator incident.

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Notes to Financial Statements

Entergy Louisiana

Entergy Louisiana recovers electric fuel and purchased power costs for the billing month based upon the level of such costs incurred two months prior to the billing month. Entergy Louisiana’s purchased gas adjustments include estimates for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.

In April 2010 the LPSC authorized its staff to initiate an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through the fuel adjustment clause by Entergy Louisiana for the period from 2005 through 2009. The LPSC staff issued its audit report in January 2013. The LPSC staff recommended that Entergy Louisiana refund approximately $1.9 million, plus interest, to customers and realign the recovery of approximately $1 million from Entergy Louisiana’s fuel adjustment clause to base rates. The recommended refund was made by Entergy Louisiana in May 2013 in the form of a credit to customers through its fuel adjustment clause filing. Two parties intervened in the proceeding. A procedural schedule was established for the identification of issues by the intervenors and for Entergy Louisiana to submit comments regarding the LPSC Staff report and any issues raised by intervenors. One intervenor sought further proceedings regarding certain issues it raised in its comments on the LPSC staff report. Entergy Louisiana filed responses to both the LPSC staff report and the issues raised by the intervenor. After conducting additional discovery, in April 2016 the LPSC staff consultant issued its supplemental audit report, which concluded that Entergy Louisiana was not imprudent on the issues raised by the intervenor. The intervenor has stated that it does not intend to pursue these issues further. In October 2016 the LPSC staff filed testimony affirming the recommendation in its audit report on the lone remaining issue that nuclear dry fuel storage costs should be realigned to base rates. The parties agreed to remove that remaining issue to a separate docket because the same issue is outstanding in the Entergy Gulf States Louisiana audit for the same time period. In November 2016 the LPSC approved the resolution of this audit and the creation of a new docket for the resolution of the proper method of recovery for nuclear dry fuel storage costs. In December 2016 the LPSC opened a new docket in order to resolve the issue regarding the proper methodology for the recovery of nuclear dry fuel storage costs. A procedural schedule has been established for this new docket, including an evidentiary hearing in June 2017.

In December 2011 the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates. The audit includes a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 2005 through 2009. In March 2016 the LPSC staff consultant issued its audit report. In its report, the LPSC staff consultant recommended that Entergy Louisiana refund approximately $8.6 million, plus interest, to customers and realign the recovery of approximately $12.7 million from Entergy Gulf States Louisiana’s fuel adjustment clause to base rates. In September 2016 the LPSC staff filed testimony stating that is was no longer recommending a disallowance of $3.4 million of the $8.6 million discussed above, but otherwise maintained positions from its report. Subsequently, the parties entered into a settlement, which was approved by the LPSC in November 2016. The settlement recognizes the dry cask storage recovery method issue will be addressed in the separate proceeding opened by the LPSC, and provides for a refund of $5 million to legacy Entergy Gulf States Louisiana customers and resolves all other issues raised in the audit.

In July 2014 the LPSC authorized its staff to initiate an audit of Entergy Gulf States Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period from 2010 through 2013. Discovery commenced in July 2015.

In July 2014 the LPSC authorized its staff to initiate an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed by Entergy Louisiana through its fuel adjustment clause for the period from 2010 through 2013. Discovery commenced in July 2015.

In June 2016 the LPSC staff provided notice of an audit of Entergy Louisiana’s fuel adjustment clause filings and purchased gas adjustment clause filings. In recognition of the business combination that occurred in 2015, the audit notice was issued to Entergy Louisiana and will also include a review of charges to legacy Entergy Gulf States Louisiana customers prior to the business combination. The audit includes a review of the reasonableness of charges

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Notes to Financial Statements

flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2014 through 2015 and charges flowed through Entergy Louisiana’s purchased gas adjustment clause for the period from 2012 through 2015. Discovery has not commenced.

Entergy Mississippi

Entergy Mississippi’s rate schedules include an energy cost recovery rider that is adjusted annually to reflect accumulated over- or under-recoveries. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.

Entergy Mississippi had a deferred fuel balance of $60.4 million as of March 31, 2014. In May 2014, Entergy Mississippi filed for an interim adjustment under its energy cost recovery rider. The interim adjustment proposed a net energy cost factor designed to collect over a six-month period the under-recovered deferred fuel balance as of March 31, 2014 and also reflected a natural gas price of $4.50 per MMBtu. In May 2014, Entergy Mississippi and the Public Utilities Staff entered into a joint stipulation in which Entergy Mississippi agreed to a revised net energy cost factor that reflected the proposed interim adjustment with a reduction in costs recovered through the energy cost recovery rider associated with the suspension of the DOE nuclear waste storage fee. In June 2014 the MPSC approved the joint stipulation and allowed Entergy Mississippi’s interim adjustment. In November 2014, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. Due to lower gas prices and a lower deferred fuel balance, the redetermined annual factor was a decrease from the revised interim net energy cost factor. In January 2015 the MPSC approved the redetermined annual factor effective January 30, 2015.

Entergy Mississippi had a deferred fuel over-recovery balance of $58.3 million as of May 31, 2015, along with an under-recovery balance of $12.3 million under the power management rider. Pursuant to those tariffs, in July 2015, Entergy Mississippi filed for interim adjustments under both the energy cost recovery rider and the power management rider to flow through to customers the approximately $46 million net over-recovery over a six-month period. In August 2015, the MPSC approved the interim adjustments effective with September 2015 bills. In November 2015, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included a projected over-recovery balance of $48 million projected through January 31, 2016. In January 2016 the MPSC approved the redetermined annual factor effective February 1, 2016. The MPSC further ordered, however, that due to the significant change in natural gas price forecasts since Entergy Mississippi’s filing in November 2015 Entergy Mississippi shall file a revised fuel factor with the MPSC no later than February 1, 2016. Pursuant to that order, Entergy Mississippi submitted a revised fuel factor. Additionally, because Entergy Mississippi’s projected over-recovery balance for the period ending January 31, 2016 was $68 million, in February 2016, Entergy Mississippi filed for another interim adjustment to the energy cost factor effective April 2016 to flow through to customers the projected over-recovery balance over a six-month period. That interim adjustment was approved by the MPSC in February 2016 effective for April 2016 bills.

In November 2016, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an over-recovery of less than $2 million as of September 30, 2016. In January 2017 the MPSC approved the annual factor effective with February 2017 bills. Also in January 2017 the MPSC certified to the Mississippi Legislature the audit reports of its independent auditors for the fuel year ending September 30, 2016. In its order, the MPSC expressly reserved the right to review and determine the recoverability of any and all purchased power expenditures made during fiscal year 2016.

Mississippi Attorney General Complaint

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Notes to Financial Statements

defendant Entergy companies removed the Attorney General’s lawsuit to U.S. District Court in Jackson, Mississippi. The Mississippi attorney general moved to remand the matter to state court. In August 2012 the District Court issued an opinion denying the Attorney General’s motion for remand, finding that the District Court has subject matter jurisdiction under the Class Action Fairness Act.

The defendant Entergy companies answered the complaint and filed a counterclaim for relief based upon the Mississippi Public Utilities Act and the Federal Power Act. In May 2009 the defendant Entergy companies filed a motion for judgment on the pleadings asserting grounds of federal preemption, the exclusive jurisdiction of the MPSC, and factual errors in the Attorney General’s complaint. In September 2012 the District Court heard oral argument on Entergy’s motion for judgment on the pleadings.

In January 2014 the U.S. Supreme Court issued a decision in which it held that cases brought by attorneys general as the sole plaintiff to enforce state laws were not considered “mass actions” under the Class Action Fairness Act, so as to establish federal subject matter jurisdiction. One day later the Attorney General renewed his motion to remand the Entergy case back to state court, citing the U.S. Supreme Court’s decision. The defendant Entergy companies responded to that motion reiterating the additional grounds asserted for federal question jurisdiction, and the District Court held oral argument on the renewed motion to remand in February 2014. In April 2015 the District Court entered an order denying the renewed motion to remand, holding that the District Court has federal question subject matter jurisdiction. The Attorney General appealed to the U.S. Fifth Circuit Court of Appeals the denial of the motion to remand. In July 2015 the Fifth Circuit issued an order denying the appeal, and the Attorney General subsequently filed a petition for rehearing of the request for interlocutory appeal, which was also denied. In December 2015 the District Court ordered that the parties submit to the court undisputed and disputed facts that are material to the Entergy defendants’ motion for judgment on the pleadings, as well as supplemental briefs regarding the same. Those filings were made in January 2016.

In September 2016 the Attorney General filed a mandamus petition with the U.S. Fifth Circuit Court of Appeals in which the Attorney General asked the Fifth Circuit to order the chief judge to reassign this case to another judge. In September 2016 the District Court denied the Entergy companies’ motion for judgment on the pleadings. The Entergy companies filed a motion seeking to amend the District Court’s order denying the Entergy companies’ motion for judgment on the pleadings and allowing an interlocutory appeal. In October 2016 the Fifth Circuit granted the Attorney General’s motion for writ of mandamus and directed the chief judge to assign the case to a new judge. The case was reassigned in October 2016. In January 2017 the District Court denied the Entergy companies’ motion to amend the order denying the motion for judgment on the pleadings, and the parties are in the process of preparing a proposed case management order.

Entergy New Orleans

Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.

Due to higher fuel costs associated in part with the extended Grand Gulf outage and the partially simultaneous Union Power Block 1 planned outage, for the December 2016, January 2017, and February 2017 billing months, the City Council authorized Entergy New Orleans to cap the fuel adjustment charge billed to customers at $0.035 per kWh and to defer billing of all fuel costs in excess of the capped amount by including such costs in the over- or under-recovery account.

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Notes to Financial Statements

Entergy Texas

Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, not recovered in base rates. Semi-annual revisions of the fixed fuel factor are made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT.

In August 2014, Entergy Texas filed an application seeking PUCT approval to implement an interim fuel refund of approximately $24.6 million for over-collected fuel costs incurred during the months of November 2012 through April 2014. This refund resulted from (i) applying $48.6 million in bandwidth remedy payments that Entergy Texas received in May 2014 related to the June - December 2005 period to Entergy Texas’s $8.7 million under-recovered fuel balance as of April 30, 2014 and (ii) netting that fuel balance against the $15.3 million bandwidth remedy payment that Entergy Texas made related to calendar year 2013 production costs. Also in August 2014, Entergy Texas filed an unopposed motion for interim rates to implement these refunds for most customers over a two-month period commencing with September 2014. The PUCT issued its order approving the interim relief in August 2014 and Entergy Texas completed the refunds in October 2014. Parties intervened in this matter, and all parties agreed that the proceeding should be bifurcated such that the proposed interim refund would become final in a separate proceeding, which refund was approved by the PUCT in March 2015. In July 2015 certain parties filed briefs in the open proceeding asserting that Entergy Texas should refund to retail customers an additional $10.9 million in bandwidth remedy payments Entergy Texas received related to calendar year 2006 production costs. In October 2015 an ALJ issued a proposal for decision recommending that the additional $10.9 million in bandwidth remedy payments be refunded to retail customers. In January 2016 the PUCT issued its order affirming the ALJ’s recommendation, and Entergy Texas filed a motion for rehearing of the PUCT’s decision, which the PUCT denied. In March 2016, Entergy Texas filed a complaint in Federal District Court for the Western District of Texas and a petition in the Travis County (State) District Court appealing the PUCT’s decision. The federal appeal was heard in December 2016, and the Federal District Court granted Entergy Texas’s requested relief. In January 2017 the PUCT and an intervenor filed petitions for appeal to the U.S. Court of Appeals for the Fifth Circuit of the Federal District Court ruling. The State District Court appeal remains pending. In April 2016, Entergy Texas filed with the PUCT an application to refund to customers approximately $56.2 million. The refund resulted from (i) $41.8 million of fuel cost recovery over-collections through February 2016, (ii) the $10.9 million in bandwidth remedy payments, discussed above, that Entergy Texas received related to calendar year 2006 production costs, and (iii) $3.5 million in bandwidth remedy payments that Entergy Texas received related to 2006-2008 production costs. In June 2016, Entergy Texas filed an unopposed settlement agreement that added additional over-recovered fuel costs for the months of March and April 2016. The settlement resulted in a $68 million refund. The ALJ approved the refund on an interim basis to be made to most customers over a four-month period beginning with the first billing cycle of July 2016. In July 2016 the PUCT issued an order approving the interim refund.

In July 2016, Entergy Texas filed an application to reconcile its fuel and purchased power costs for the period April 1, 2013 through March 31, 2016. Under a recent PUCT rule change, a fuel reconciliation is required to be filed at least once every three years and outside of a base rate case filing. During the reconciliation period, Entergy Texas incurred approximately $1.77 billion in Texas jurisdictional eligible fuel and purchased power expenses, net of certain revenues credited to such expenses and other adjustments. Entergy Texas estimated an over-recovery balance of approximately $19.3 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning Apri1 2016. Entergy Texas also noted, however, that the estimated $19.3 million over collection was being refunded to customers as a portion of the interim fuel refund beginning with the first billing cycle of July 2016, discussed above. Entergy Texas also is requesting a prudence finding for each of the fuel-related contracts and arrangements entered into or modified during the reconciliation period that have not been reviewed by the PUCT in a prior proceeding. In December 2016, Entergy Texas entered into a stipulation and settlement agreement resulting in a $6 million disallowance not associated with any particular issue raised and a refund of the over-recovery balance of $21 million as of November 30, 2016, to customers beginning April 2017 through June 2017. This settlement was developed concurrently with the stipulation and settlement agreement in the 2016 transmission cost recovery factor rider amendment discussed below, and the terms and conditions in both settlements are interdependent. PUCT action on the stipulations and settlement agreements is pending.

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At the PUCT’s April 2013 open meeting, the PUCT Commissioners discussed their view that a purchased power capacity rider was good public policy. The PUCT issued an order in May 2013 adopting the rule allowing for a purchased power capacity rider, subject to an offsetting adjustment for load growth. The rule, as adopted, also includes a process for obtaining pre-approval by the PUCT of purchased power agreements. Entergy Texas has not exercised the option to recover its capacity costs under the new rider mechanism, but will continue to evaluate the benefits of utilizing the new rider to recover future capacity costs.

Retail Rate Proceedings

Filings with the APSC (Entergy Arkansas)

Retail Rates

2013 Base Rate Filing

In March 2013, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. The filing assumed Entergy Arkansas’s transition to MISO in December 2013, and requested a rate increase of $174 million, including $49 million of revenue being transferred from collection in riders to base rates. The filing also proposed a new transmission rider and a capacity cost recovery rider. The filing requested a 10.4% return on common equity. In September 2013, Entergy Arkansas filed testimony reflecting an updated rate increase request of $145 million, with no change to its requested return on common equity of 10.4%. Hearings in the proceeding began in October 2013, and in December 2013 the APSC issued an order. The order authorized a base rate increase of $81 million and included an authorized return on common equity of 9.3%. The order allowed Entergy Arkansas to amortize its human capital management costs over a three-and-a-half year period. New rates under the January 2014 order were implemented in the first billing cycle of March 2014 and were effective as of January 2014. Additionally, in January 2014, Entergy Arkansas filed a petition for rehearing or clarification of several aspects of the APSC’s order, including the 9.3% authorized return on common equity. In February 2014 the APSC granted Entergy Arkansas’s petition for the purpose of considering the additional evidence identified by Entergy Arkansas. In August 2014 the APSC issued an order amending certain aspects of the original order, including providing for a 9.5% authorized return on common equity. Pursuant to the August 2014 order, revised rates were effective for all bills rendered after December 31, 2013 and were implemented in the first billing cycle of October 2014.

2015 Base Rate Filing

In April 2015, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. The filing notified the APSC of Entergy Arkansas’s intent to implement a forward test year formula rate plan pursuant to Arkansas legislation passed in 2015, and requested a retail rate increase of $268.4 million, with a net increase in revenue of $167 million. The filing requested a 10.2% return on common equity. In September 2015 the APSC staff and intervenors filed direct testimony, with the APSC staff recommending a revenue requirement of $217.9 million and a 9.65% return on common equity. In December 2015, Entergy Arkansas, the APSC staff, and certain of the intervenors in the rate case filed with the APSC a joint motion for approval of a settlement of the case that proposed a retail rate increase of approximately $225 million with a net increase in revenue of approximately $133 million; an authorized return on common equity of 9.75%; and a formula rate plan tariff that provides a +/- 50 basis point band around the 9.75% allowed return on common equity. A significant portion of the rate increase is related to Entergy Arkansas’s acquisition in March 2016 of Union Power Station Power Block 2 for a base purchase price of $237 million. The settlement agreement also provided for amortization over a 10-year period of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance. A settlement hearing was held in January 2016. In February 2016 the APSC approved the settlement with one exception that reduced the retail rate increase proposed in the settlement by $5 million. The settling parties agreed to the APSC modifications in February 2016. The new rates were effective February 24, 2016 and began billing with the first billing cycle of April 2016. In March 2016, Entergy Arkansas made a compliance filing regarding the new rates that included an interim base rate adjustment surcharge, effective with the first billing cycle of April 2016,

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to recover the incremental revenue requirement for the period February 24, 2016 through March 31, 2016. The interim base rate adjustment surcharge was designed to recover a total of $21.1 million over the nine-month period from April 2016 through December 2016.

2016 Formula Rate Plan Filing

In July 2016, Entergy Arkansas filed with the APSC its 2016 formula rate plan filing showing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2017 test period to be below the formula rate plan bandwidth. The filing requested a $67.7 million revenue requirement increase to achieve Entergy Arkansas’s target earned return on common equity of 9.75%. In October 2016, Entergy Arkansas filed with the APSC revised formula rate plan attachments with an updated request for a $54.4 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors, as well as three additional adjustments identified as appropriate by Entergy Arkansas. In November 2016 a hearing was held and the APSC issued an order directing the parties to brief certain issues. In December 2016 the APSC approved the settlement agreement and the $54.4 million revenue requirement increase with approximately $25 million of the $54.4 million revenue requirement subject to possible future adjustment and refund to customers with interest. The APSC requested supplemental information for some of Entergy Arkansas’s requested nuclear expenditures. The APSC indicated that a procedural schedule would be set by subsequent order to obtain the additional information. In December 2016 the APSC approved Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2017.

Advanced Metering Infrastructure (AMI) Filing

In September 2016, Entergy Arkansas filed an application seeking an order from the APSC finding that Entergy Arkansas’s deployment of AMI is in the public interest. Entergy Arkansas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Arkansas’s modernized power grid. The filing identified a number of quantified and unquantified benefits, and Entergy Arkansas provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal net benefit to customers of $431 million. Entergy Arkansas also sought to continue to include in rate base the remaining book value at December 31, 2015, approximately $57 million, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Arkansas proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Subject to approval by the APSC, deployment of the communications network is expected to begin in 2018. Entergy Arkansas proposed to include the AMI deployment costs and the quantified benefits in future formula rate plan filings. In order to have certainty around its 2018 projected AMI deployment costs, Entergy Arkansas sought an order from the APSC prior to the hearing on its expected 2017 formula rate plan filing in the fourth quarter 2017. In January 2017 the APSC approved a procedural schedule that provides for a hearing in August 2017.

Filings with the LPSC (Entergy Louisiana)

Retail Rates - Electric

2013 Rate Cases

In connection with its decision to extend the formula rate plan to the 2011 test year, the LPSC required that a base rate case be filed by Entergy Gulf States Louisiana, and the required filing was made in February 2013. The filing anticipated Entergy Gulf States Louisiana’s integration into MISO. In the filing Entergy Gulf States Louisiana requested, among other relief:


•	authorization to increase the revenue it collects from customers by approximately $24 million;


•	an authorized return on common equity of 10.4%;

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•	authorization to increase depreciation rates embedded in the proposed revenue requirement; and,

•

authorization to implement a three-year formula rate plan: with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Gulf States Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC.

Following a hearing before an ALJ and the ALJ’s issuance of a Report of Proceedings, in December 2013 the LPSC approved an unopposed settlement of the proceeding. Major terms of the settlement included approval of a three-year formula rate plan (effective for test years 2014-2016) modeled after the formula rate plan in effect for Entergy Gulf States Louisiana for 2011, including the following: (1) a midpoint return on equity of 9.95% plus or minus 80 basis points, with 60/40 sharing of earnings outside of the bandwidth; (2) recovery outside of the sharing mechanism for the non-fuel MISO-related costs, additional capacity revenue requirement, extraordinary items, such as the Ninemile 6 project, and certain special recovery items; (3) three-year amortization of costs to achieve savings associated with the human capital management strategic imperative, with savings to be reflected as they are realized in subsequent years; (4) eight-year amortization of costs incurred in connection with potential development of a new nuclear unit at River Bend, without carrying costs, beginning December 2014, provided, however, that amortization of these costs shall not result in a future rate increase; (5) no change in rates related to test year 2013, except with respect to recovery of the non-fuel MISO-related costs and any changes to the additional capacity revenue requirement; and (6) no increase in rates related to test year 2014, except for those items eligible for recovery outside of the earnings sharing mechanism. Existing depreciation rates did not change. Implementation of rate changes for items recoverable outside of the earnings sharing mechanism occurred in December 2014.

Pursuant to the rate case settlement approved by the LPSC in December 2013, Entergy Gulf States Louisiana submitted a compliance filing in May 2014 reflecting the effects of the estimated MISO cost recovery mechanism revenue requirement and adjustment of the additional capacity mechanism. In November 2014, Entergy Gulf States Louisiana submitted an additional compliance filing updating the estimated MISO cost recovery mechanism for the most recent actual data. Based on this updated filing, a net increase of $5.8 million in formula rate plan revenue to be collected over nine months was implemented in December 2014. The compliance filings were subject to LPSC review in accordance with the review process set forth in Entergy Gulf States Louisiana’s formula rate plan.

In November 2011 the LPSC approved a one-year extension of Entergy Louisiana’s formula rate plan. In connection with its decision to extend the formula rate plan to the 2011 test year, the LPSC required that a base rate case be filed by Entergy Louisiana, and the required filing was made on February 15, 2013. The filing anticipated Entergy Louisiana’s integration into MISO. In the filing Entergy Louisiana requested, among other relief:


•	authorization to increase the revenue it collects from customers by approximately $145 million (which does not take into account a revenue offset of approximately $2 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service);


•	an authorized return on common equity of 10.4%;


•	authorization to increase depreciation rates embedded in the proposed revenue requirement; and

•

authorization to implement a three-year formula rate plan: with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC.

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Following a hearing before an ALJ and the ALJ’s issuance of a Report of Proceedings, in December 2013 the LPSC approved an unopposed settlement of the proceeding. The settlement provided for a $10 million rate increase effective with the first billing cycle of December 2014. Major terms of the settlement included approval of a three-year formula rate plan (effective for test years 2014-2016) modeled after the formula rate plan in effect for Entergy Louisiana for 2011, including the following: (1) a midpoint return on equity of 9.95% plus or minus 80 basis points, with 60/40 sharing of earnings outside of the bandwidth; (2) recovery outside of the sharing mechanism for the non-fuel MISO-related costs, additional capacity revenue requirement, extraordinary items, such as the Ninemile 6 project, and certain special recovery items; (3) three-year amortization of costs to achieve savings associated with the human capital management strategic imperative, with savings reflected as they are realized in subsequent years; (4) eight-year amortization of costs incurred in connection with potential development of a new nuclear unit at River Bend, without carrying costs, beginning December 2014, provided, however, that amortization of these costs shall not result in a future rate increase; (5) recovery of non-fuel MISO-related costs and any changes to the additional capacity revenue requirement related to test year 2013 effective with the first billing cycle of December 2014; and (6) a cumulative $30 million cap on cost of service increases over the three-year formula rate plan cycle, except for those items outside of the sharing mechanism. Existing depreciation rates did not change.

Pursuant to the rate case settlement approved by the LPSC in December 2013, Entergy Louisiana submitted a compliance filing in May 2014 reflecting the effects of the $10 million agreed-upon increase in formula rate plan revenue, the estimated MISO cost recovery mechanism revenue requirement, and the adjustment of the additional capacity mechanism. In November 2014, Entergy Louisiana submitted an additional compliance filing updating the estimated MISO cost recovery mechanism for the most recent actual data, as well as providing for a refund and prospective reduction in rates for the true-up of the estimated revenue requirement for the Waterford 3 replacement steam generator project. Based on this updated filing, a net increase of $41.6 million in formula rate plan revenue to be collected over nine months was implemented in December 2014. The compliance filings were subject to LPSC review in accordance with the review process set forth in Entergy Louisiana’s formula rate plan. LPSC staff identified five issues, of which one remains in the compliance proceeding. That issue pertains to Entergy Louisiana’s method of collecting the agreed-upon $10 million increase. No procedural schedule has been established, however, to address the issue. By stipulation among the parties, the final issue raised by the LPSC staff regarding the appropriate level of refunds related to the Waterford 3 replacement steam generator project will be resolved in connection with the Waterford 3 prudence review proceedings discussed below.

2014 Formula Rate Plan Filing

In connection with the approval of the business combination of Entergy Gulf States Louisiana and Entergy Louisiana, the LPSC authorized the filing of a single, joint, formula rate plan evaluation report for Entergy Gulf States Louisiana’s and Entergy Louisiana’s 2014 calendar year operations. The joint evaluation report was filed in September 2015 and reflects an earned return on common equity of 9.09%. As such, no adjustment to base formula rate plan revenue was required. The following adjustments were required under the formula rate plan, however: a decrease in the additional capacity mechanism for Entergy Louisiana of $17.8 million; an increase in the additional capacity mechanism for Entergy Gulf States Louisiana of $4.3 million; and a reduction of $5.5 million to the MISO cost recovery mechanism to collect approximately $35.7 million on a combined-company basis. Under the order approving the business combination, following completion of the prescribed review period, rates were implemented with the first billing cycle of December 2015, subject to refund. See “Entergy Louisiana and Entergy Gulf States Louisiana Business Combination” below for further discussion of the business combination.

2015 Formula Rate Plan Filing

In May 2016, Entergy Louisiana filed its formula rate plan evaluation report for its 2015 calendar year operations. The evaluation report reflects an earned return on common equity of 9.07%. As such, no adjustment to base formula rate plan revenue is required. The following other adjustments, however, are required under the formula rate plan: an increase in the legacy Entergy Louisiana additional capacity mechanism of $14.2 million; a separate increase in legacy Entergy Louisiana revenue of $10 million primarily to reflect the effects of the termination of the

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System Agreement; an increase in the legacy Entergy Gulf States Louisiana additional capacity mechanism of $0.5 million; a decrease in legacy Entergy Gulf States Louisiana revenue of $58.7 million primarily to reflect the effects of the termination of the System Agreement; and an increase of $11 million to the MISO cost recovery mechanism. Rates were implemented with the first billing cycle of September 2016, subject to refund. Following implementation of the as-filed rates in September 2016, there have been several interim updates to Entergy Louisiana’s formula rate plan, including the most recent adjustment submitted in December 2016, reflecting implementation of the settlement of the Waterford 3 replacement steam generator project prudence review described below. Also pursuant to Entergy Louisiana’s formula rate plan rider, in November 2016, Entergy Louisiana submitted a request for LPSC authorization to extend the recovery mechanism for net revenues and expenses incurred in connection with Entergy Louisiana’s participation in MISO. The MISO cost recovery mechanism was initially approved on an interim basis to remain in place through the rate effective period of Entergy Louisiana’s test year 2015 formula rate plan filing. A procedural schedule has been established, including a hearing in July 2017.

Waterford 3 Replacement Steam Generator Project

Following the completion of the Waterford 3 replacement steam generator project, the LPSC undertook a prudence review in connection with a filing made by Entergy Louisiana in April 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs. In July 2014 the LPSC Staff filed testimony recommending potential project and replacement power cost disallowances of up to $71 million, citing a need for further explanation or documentation from Entergy Louisiana. An intervenor filed testimony recommending disallowance of $141 million of incremental project costs, claiming the steam generator fabricator was imprudent. Entergy Louisiana provided further documentation and explanation requested by the LPSC staff. An evidentiary hearing was held in December 2014. At the hearing the parties maintained the positions reflected in pre-filed testimony. Entergy Louisiana believed that the replacement steam generator costs were prudently incurred and applicable legal principles supported their recovery in rates. Nevertheless, Entergy Louisiana recorded a write-off of $16 million of Waterford 3’s plant balance in December 2014 because of the uncertainty at the time associated with the resolution of the prudence review. In December 2015 the ALJ issued a proposed recommendation, which was subsequently finalized, concluding that Entergy Louisiana prudently managed the Waterford 3 replacement steam generator project, including the selection, use, and oversight of contractors, and could not reasonably have anticipated the damage to the steam generators. Nevertheless, the ALJ concluded that Entergy Louisiana was liable for the conduct of its contractor and subcontractor and, therefore, recommended a disallowance of $67 million in capital costs. Additionally, the ALJ concluded that Entergy Louisiana did not sufficiently justify the incurrence of $2 million in replacement power costs during the replacement outage. Although the ALJ’s recommendation had not yet been considered by the LPSC, after considering the progress of the proceeding in light of the ALJ recommendation, Entergy Louisiana recorded in the fourth quarter 2015 approximately $77 million in charges, including a $45 million asset write-off and a $32 million regulatory charge, to reflect that a portion of the assets associated with the Waterford 3 replacement steam generator project was no longer probable of recovery. Entergy Louisiana maintained that the ALJ’s recommendation contains significant factual and legal errors.

In October 2016 the parties reached a settlement in this matter. This settlement was approved by the LPSC in December 2016. The settlement effectively provides for an agreed-upon disallowance of $67 million of plant, which had been previously written off by Entergy Louisiana, as discussed above. The settlement also requires a refund of approximately $71 million to be given through a one-time credit included in customers’ bills in January 2017. Of the $71 million of refunds, $68 million was credited to customers through Entergy Louisiana’s formula rate plan, outside of sharing, and $3 million through its fuel adjustment clause. Entergy Louisiana had previously recorded a provision of $48 million for this refund. The previously-recorded provision included the cumulative revenues recorded through December 2016 related to the $67 million of disallowed plant. An additional regulatory charge of $23 million was recorded in fourth quarter 2016 to reflect the effects of the settlement. The settlement also provides that Entergy Louisiana can retain the value associated with potential service credits agreed to by the project contractor, to the extent they are realized in the future.

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Ninemile 6

In July 2014, Entergy Gulf States Louisiana and Entergy Louisiana filed an unopposed stipulation with the LPSC, which was subsequently approved, that estimated a first year revenue requirement associated with Ninemile 6 and provided a mechanism to update the revenue requirement as the in-service date approached. In late-December 2014, roughly contemporaneous with the unit's placement in service, a final updated estimated revenue requirement of $26.8 million for Entergy Gulf States Louisiana and $51.1 million for Entergy Louisiana was filed. The December 2014 estimate forms the basis of rates implemented effective with the first billing cycle of January 2015. In July 2015, Entergy Louisiana submitted to the LPSC a compliance filing including an estimate at completion, inclusive of interconnection costs and transmission upgrades, of approximately $648 million, or $76 million less than originally estimated, along with other project details and supporting evidence, to enable the LPSC to review the prudence of Entergy Louisiana’s management of the project. Testimony filed by the LPSC staff generally supports the prudence of the management of the project and recovery of the costs incurred to complete the project. The LPSC staff had questioned the warranty coverage for one element of the project. In October 2016 all parties agreed to a stipulation providing that 100% of Ninemile 6 construction costs was prudently incurred and is eligible for recovery from customers, but reserving the LPSC’s rights to review the prudence of Entergy Louisiana’s actions regarding one element of the project. This stipulation was approved by the LPSC in January 2017.

Union Power Station

In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC for approval of the acquisition and cost recovery of two power blocks of the Union Power Station for an expected base purchase price of approximately $237 million per power block, subject to adjustments. In September 2015, Entergy Gulf States Louisiana agreed to settlement terms with all parties for Entergy Gulf States Louisiana’s purchase of the two power blocks. In October 2015 the LPSC voted unanimously to approve the uncontested settlement which finds, among other things, that acquisition of Power Blocks 3 and 4 is in the public interest and, therefore, prudent. The business combination of Entergy Gulf States Louisiana and Entergy Louisiana received regulatory approval and closed in October 2015 making Entergy Louisiana the named purchaser of Power Blocks 3 and 4 of the Union Power Station. In March 2016, Entergy Louisiana acquired Power Blocks 3 and 4 of Union Power Station for an aggregate purchase price of approximately $474 million and implemented rates to collect the estimated first-year revenue requirement with the first billing cycle of March 2016.

As a term of the LPSC-approved settlement authorizing the purchase of Power Blocks 3 and 4 of the Union Power Station, Entergy Louisiana agreed to make a filing with the LPSC to review its decisions to deactivate Ninemile 3 and Willow Glen 2 and 4 and its decision to retire Little Gypsy 1. In January 2016, Entergy Louisiana made its compliance filing with the LPSC. Entergy Louisiana, LPSC staff, and intervenors participated in a technical conference in March 2016 where Entergy Louisiana presented information on its deactivation/retirement decisions for these four units in addition to information on the current deactivation decisions for the ten-year planning horizon. Parties have requested further proceedings on the prudence of the decision to deactivate Willow Glen 2 and 4. No party contests the prudence of the decision to deactivate Willow Glen 2 and 4 or suggests reactivation of these units; however, issues have been raised related to Entergy Louisiana’s deactivation process. This matter is pending before an ALJ.

Retail Rates - Gas

In January 2014, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2013. The filing showed an earned return on common equity of 5.47%, which results in a $1.5 million rate increase. In April 2014 the LPSC staff issued a report indicating “that Entergy Gulf States Louisiana has properly determined its earnings for the test year ended September 30, 2013.” The $1.5 million rate increase was implemented effective with the first billing cycle of April 2014.

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for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by the LPSC staff and inclusion of certain customer safeguards required by the LPSC staff, in December 2014, Entergy Gulf States Louisiana and the LPSC staff submitted a joint settlement for implementation of an accelerated gas pipe replacement program providing for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a rider to recover the investment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is subject to the following conditions, among others: a ten-year term; application of any earnings in excess of 10.45% as an offset to the revenue requirement of the infrastructure rider; adherence to a specified spending plan, within plus or minus 20% annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding 10%; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015.

In January 2015, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2014. The filing showed an earned return on common equity of 7.20%, which resulted in a $706 thousand rate increase. In April 2015 the LPSC issued findings recommending two adjustments to Entergy Gulf States Louisiana’s as-filed results, and an additional recommendation that does not affect current year results. The LPSC staff’s recommended adjustments increase the earned return on equity for the test year to 7.24%. Entergy Gulf States Louisiana accepted the LPSC staff’s recommendations and a revenue increase of $688 thousand was implemented with the first billing cycle of May 2015.

In January 2016, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2015. The filing showed an earned return on common equity of 10.22%, which is within the authorized bandwidth, therefore requiring no change in rates. In March 2016 the LPSC staff issued its report stating that the 2015 gas rate stabilization plan filing was in compliance with the exception of several issues that required additional information, explanation, or clarification for which the LPSC staff had reserved the right to further review. In July 2016 the parties to the proceeding filed an unopposed joint report and motion for entry of order accepting the report that indicates no outstanding issues remained in the filing. In February 2016, Entergy Louisiana filed a motion requesting to extend the term of the gas rate stabilization plan in substantially similar form for an additional three-year term and included a request for sharing of non-jurisdictional compressed natural gas revenues. Following discovery and the filing of testimony by the LPSC Staff, Entergy Louisiana and the LPSC submitted a joint motion for hearing an uncontested stipulated settlement resolving the proceeding. A hearing on the stipulation was held in November 2016. The ALJ issued a report of proceedings that was presented with the parties’ stipulation to the LPSC for consideration. The stipulation approving Entergy Louisiana’s requested extension of the rate stabilization plan was approved by the LPSC in December 2016.

In January 2017, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2016. The filing of the evaluation report for test year 2016 reflects an earned return on common equity of 6.37%. As part of the filing, pursuant to the extraordinary cost provision of the rate stabilization plan, Entergy Louisiana is seeking to recover approximately $1.5 million in deferred operation and maintenance expenses incurred to restore service and repair damage resulting from flooding and widespread rainfall in southeast Louisiana that occurred in August 2016. Entergy Louisiana seeks to recover the prudently incurred August 2016 storm restoration costs over ten years, outside of the rate stabilization plan sharing provisions. As a result, Entergy Louisiana’s filing seeks an annual increase in revenue of $1.4 million. The filing is subject to review by the LPSC staff with resulting rates to be implemented with the first billing cycle of May 2017.

Advanced Metering Infrastructure (AMI) Filing

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network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Louisiana’s modernized power grid. The filing identified a number of quantified and unquantified benefits, and Entergy Louisiana provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $607 million. Entergy Louisiana also sought to continue to include in rate base the remaining book value at December 31, 2015, approximately $92 million, of the existing electric meters and also to depreciate those assets using current depreciation rates. Entergy Louisiana proposed a 15-year useful life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Assuming LPSC approval is received in 2017, the communications network deployment is expected to begin by late-2018, after the necessary information technology infrastructure is in place. Entergy Louisiana proposed to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022.

Filings with the MPSC (Entergy Mississippi)

Formula Rate Plan Filings

In June 2014, Entergy Mississippi filed its first general rate case before the MPSC in almost 12 years. The rate filing laid out Entergy Mississippi’s plans for improving reliability, modernizing the grid, maintaining its workforce, stabilizing rates, utilizing new technologies, and attracting new industry to its service territory. Entergy Mississippi requested a net increase in revenue of $49 million for bills rendered during calendar year 2015, including $30 million resulting from new depreciation rates to update the estimated service life of assets. In addition, the filing proposed, among other things: 1) realigning cost recovery of the Attala and Hinds power plant acquisitions from the power management rider to base rates; 2) including certain MISO-related revenues and expenses in the power management rider; 3) power management rider changes that reflect the changes in costs and revenues that will accompany Entergy Mississippi’s withdrawal from participation in the System Agreement; and 4) a formula rate plan forward test year to allow for known changes in expenses and revenues for the rate effective period. Entergy Mississippi proposed maintaining the current authorized return on common equity of 10.59%.

In October 2014, Entergy Mississippi and the Mississippi Public Utilities Staff entered into and filed joint stipulations that addressed the majority of issues in the proceeding. The stipulations provided for:


•	an approximate $16 million net increase in revenues, which reflected an agreed upon 10.07% return on common equity;

•

revision of Entergy Mississippi’s formula rate plan by providing Entergy Mississippi with the ability to reflect known and measurable changes to historical rate base and certain expense amounts; resolving uncertainty around and obviating the need for an additional rate filing in connection with Entergy Mississippi’s withdrawal from participation in the System Agreement; updating depreciation rates; and moving costs associated with the Attala and Hinds generating plants from the power management rider to base rates;


•	recovery of non-fuel MISO-related costs through a separate rider for that purpose;

•

a deferral of $6 million in other operation and maintenance expenses associated with the unplanned Baxter Wilson outage in September 2013, and a determination that the regulatory asset should accrue carrying costs, with amortization of the regulatory asset over two years beginning in February 2015, and a provision that the capital costs will be reflected in rate base. The final accounting of costs to return the unit to service and insurance proceeds were to be addressed in Entergy Mississippi’s next formula rate plan filing. Subsequently, the MPSC ordered final review of the Baxter Wilson accounting be completed in a separate docket; and

•

consolidation of the new nuclear generation development costs proceeding with the general rate case proceeding for hearing purposes and a determination that Entergy Mississippi would not further pursue, except as noted below, recovery of the costs that were approved for deferral by the MPSC in November 2011. The stipulations state, however, that, if Entergy Mississippi decides to move forward with nuclear development in Mississippi, it can at that time re-present for consideration by the MPSC only those costs directly associated with the existing early site permit (ESP), to the extent that the costs are verifiable and prudent and the ESP is still valid and relevant to any such option pursued. See “New Nuclear Generation Development Costs - Entergy

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Mississippi” below for further discussion of the new nuclear generation development costs proceeding and subsequent write-off in 2014 of the regulatory asset related to those costs.

In December 2014 the MPSC issued an order accepting the stipulations in their entirety and approving the revenue adjustments and rate changes effective with February 2015 bills.

In March 2016, Entergy Mississippi submitted its formula rate plan 2016 test year filing showing Entergy Mississippi’s projected earned return for the 2016 calendar year to be below the formula rate plan bandwidth. The filing showed a $32.6 million rate increase was necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 9.96%, within the formula rate plan bandwidth. In June 2016 the MPSC approved Entergy Mississippi’s joint stipulation with the Mississippi Public Utilities Staff. The joint stipulation provided for a total revenue increase of $23.7 million. The revenue increase includes a $19.4 million increase through the formula rate plan, resulting in a return on common equity point of adjustment of 10.07%. The revenue increase also includes $4.3 million in incremental ad valorem tax expenses to be collected through an updated ad valorem tax adjustment rider. The revenue increase and ad valorem tax adjustment rider were effective with the July 2016 bills.

Advanced Metering Infrastructure (AMI) Filing

In November 2016, Entergy Mississippi filed an application seeking an order from the MPSC granting a certificate of public convenience and necessity and finding that Entergy Mississippi’s deployment of AMI is in the public interest. Entergy Mississippi proposed to replace existing meters with advanced meters that enable two-way data communication; to design and build a secure and reliable network to support such communications; and to implement support systems. AMI is intended to serve as the foundation of Entergy Mississippi’s modernized power grid. The filing identified a number of quantified and unquantified benefits, and Entergy Mississippi provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal benefit to customers of $496 million over a 15 year period, which when netted against the costs of AMI results in $183 million of net customer benefits. Entergy Mississippi also sought to continue to include in rate base the remaining book value at December 31, 2015, approximately $56 million, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Mississippi proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019, subject to approval by the MPSC, with deployment of the communications network expected to begin in 2018. Entergy Mississippi proposed to include the AMI deployment costs and the quantified benefits in existing rate mechanisms, primarily through future formula rate plan filings and/or future energy cost recovery rider schedule re-determinations, as applicable.

Filings with the City Council

(Entergy Louisiana and Entergy New Orleans)

In March 2013, Entergy Louisiana filed a rate case for the Algiers area, which is in New Orleans and is regulated by the City Council. Entergy Louisiana requested a rate increase of $13 million over three years, including a 10.4% return on common equity and a formula rate plan mechanism identical to its LPSC request. In January 2014 the City Council Advisors filed direct testimony recommending a rate increase of $5.56 million over three years, including an 8.13% return on common equity. In June 2014 the City Council unanimously approved a settlement that includes the following:


•	a $9.3 million base rate revenue increase to be phased in on a levelized basis over four years;


•	recovery of an additional $853 thousand annually through a MISO recovery rider; and


•	the adoption of a four-year formula rate plan requiring the filing of annual evaluation reports in May of each year, commencing May 2015, with resulting rates being implemented in October of each year. The formula rate plan includes a midpoint target authorized return on common equity of 9.95% with a +/- 40 basis point bandwidth.

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The rate increase was effective with bills rendered on and after the first billing cycle of July 2014. Additional compliance filings were made with the City Council in October 2014 for approval of the form of certain rate riders, including among others, a Ninemile 6 non-fuel cost recovery interim rider, allowing for contemporaneous recovery of capacity costs related to the commencement of commercial operation of the Ninemile 6 generating unit and a purchased power capacity cost recovery rider. The monthly Ninemile 6 cost recovery interim rider was implemented in December 2014 to initially collect $915 thousand from Entergy Louisiana customers in the Algiers area. See “Algiers Asset Transfer” below for discussion of the transfer from Entergy Louisiana to Entergy New Orleans of certain assets that serve Algiers customers.

(Entergy New Orleans)

Retail Rates

See “Algiers Asset Transfer ” below for discussion of the Algiers asset transfer. As a provision of the settlement agreement approved by the City Council in May 2015 providing for the Algiers asset transfer, it was agreed that, with limited exceptions, no action may be taken with respect to Entergy New Orleans’s base rates until rates are implemented from a base rate case that must be filed for its electric and gas operations in 2018. This provision eliminated the formula rate plan applicable to Algiers operations. The limited exceptions include continued implementation of the remaining two years of the four-year phased-in rate increase for the Algiers area and certain exceptional cost increases or decreases in the base revenue requirement. An additional provision of the settlement agreement allows for continued recovery of the revenue requirement associated with the capacity and energy from Ninemile 6 received by Entergy New Orleans under a power purchase agreement with Entergy Louisiana (Algiers PPA). The settlement authorizes Entergy New Orleans to recover the remaining revenue requirement related to the Algiers PPA through base rates charged to Algiers customers. The settlement also provided for continued implementation of the Algiers MISO recovery rider.

In addition to the Algiers PPA, Entergy New Orleans has a separate power purchase agreement with Entergy Louisiana for 20% of the capacity and energy from Ninemile 6 (Ninemile PPA), which commenced operation in December 2014. Initially, recovery of the non-fuel costs associated with the Ninemile PPA was authorized through a special Ninemile 6 rider billed to only Entergy New Orleans customers outside of Algiers.

In August 2015, Entergy New Orleans filed an application with the City Council seeking authorization to proceed with the purchase of Union Power Block 1, with an expected base purchase price of approximately $237 million, subject to adjustments, and seeking approval of the recovery of the associated costs. In November 2015 the City Council issued written resolutions and an order approving an agreement in principle between Entergy New Orleans and City Council advisors providing that the purchase of Union Power Block 1 and related assets by Entergy New Orleans is prudent and in the public interest. The City Council authorized expansion of the terms of the purchased power and capacity acquisition cost recovery rider to recover the non-fuel purchased power expense from Ninemile 6, the revenue requirement associated with the purchase of Power Block 1 of the Union Power Station, and a credit to customers of $400 thousand monthly beginning June 2016 in recognition of the decrease in other operation and maintenance expenses that would result with the deactivation of Michoud Units 2 and 3. In March 2016, Entergy New Orleans purchased Power Block 1 of the Union Power Station for approximately $237 million and initiated recovery of these costs with March 2016 bills. In July 2016, Entergy New Orleans and the City Council Utility Committee agreed to a temporary increase in the Michoud credit to customers to a total of $1.4 million monthly for August 2016 through December 2016.

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will be allowed to recover its lost contribution to fixed costs and to earn an incentive for meeting program goals. In January 2015 the City Council approved extending the Energy Smart program through March 2015 and using $1.2 million of rough production cost equalization funds to cover program costs for the extended period. Additionally, the City Council approved funding for the Energy Smart program from April 2015 through March 2017 using the remainder of the approximately $12.8 million of 2014 rough production cost equalization funds, with any remaining costs being recovered through the fuel adjustment clause. This funding methodology was modified in November 2015 when the City Council directed Entergy New Orleans to use a combination of guaranteed customer savings related to a prior agreement with the City Council and rough production cost equalization funds to cover program costs prior to recovering any costs through the fuel adjustment clause. In February 2017, Entergy New Orleans filed a proposed implementation plan for the Energy Smart program from April 2017 through March 2020. As part of the proposal, Entergy New Orleans requested that the City Council identify its desired level of funding for the program during this time period and approve a cost recovery mechanism.

Internal Restructuring

In July 2016, Entergy New Orleans filed an application with the City Council seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy New Orleans to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. The restructuring is subject to regulatory review and approval by the City Council and the FERC. In the application, Entergy New Orleans had proposed to credit retail customers $5 million in each of the years 2016 and 2017 if the City Council approved the application in 2016, and to credit retail customers $5 million in each of the years 2018, 2019, and 2020, if an application that is yet to be filed with the FERC is approved by December 31, 2018. When it became clear that City Council approval would not be obtained in 2016, Entergy New Orleans agreed in testimony that it would extend its proposal to credit customers if City Council approval was obtained in the first quarter 2017. Entergy New Orleans still expects that the restructuring can be consummated by December 31, 2017, if the necessary approvals are obtained. In February 2017 the procedural schedule was suspended to allow for settlement discussions. It is not anticipated that NRC approval will be required to engage in the proposed internal restructuring. In January 2017, Entergy Louisiana, through Entergy Corporation’s nuclear operations organization, Entergy Operations, Inc. made a filing, however, with the NRC notifying it of the internal restructuring.

It is currently contemplated that Entergy New Orleans would undertake a multi-step restructuring, which would include the following:


•	Entergy New Orleans would redeem its outstanding preferred stock at a price of approximately $21 million, which includes an expected call premium of approximately $819,000, plus any accumulated and unpaid dividends.


•	Entergy New Orleans would convert from a Louisiana corporation to a Texas corporation.

•

Under the Texas Business Organizations Code (TXBOC), Entergy New Orleans will allocate substantially all of its assets to a new subsidiary, Entergy New Orleans Power, LLC, a Texas limited liability company (Entergy New Orleans Power), and Entergy New Orleans Power will assume substantially all of the liabilities of Entergy New Orleans, in a transaction regarded as a merger under the TXBOC. Entergy New Orleans will remain in existence and hold the membership interests in Entergy New Orleans Power.


•	Entergy New Orleans will contribute the membership interests in Entergy New Orleans Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy New Orleans Power will be a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.


•	Entergy New Orleans will change its name to Entergy Utility Group, Inc., and Entergy New Orleans Power will then change its name to Entergy New Orleans, LLC.

Upon the completion of the restructuring, Entergy New Orleans, LLC will hold substantially all of the assets, and will have assumed substantially all of the liabilities, of Entergy New Orleans. Entergy New Orleans may modify or supplement the steps to be taken to effectuate the restructuring.

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Notes to Financial Statements

Advanced Metering Infrastructure (AMI) Filing

In October 2016, Entergy New Orleans filed an application seeking a finding from the City Council that Entergy New Orleans’s deployment of advanced electric and gas metering infrastructure is in the public interest. Entergy New Orleans proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy New Orleans’s modernized power grid. The filing identified a number of quantified and unquantified benefits, and Entergy New Orleans provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $101 million. Entergy New Orleans also sought to continue to include in rate base the remaining book value at December 31,2015, approximately $21 million, of the existing electric meters and also to depreciate those assets using current depreciation rates. Entergy New Orleans proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Subject to approval by the City Council, deployment of the information technology infrastructure is expected to begin in 2017 and deployment of the communications network is expected to begin in 2018. Entergy New Orleans proposes to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022. In January 2017 the City Council approved a procedural schedule that provides for a hearing in July 2017.

Filings with the PUCT and Texas Cities (Entergy Texas)

Retail Rates

2011 Rate Case

In November 2011, Entergy Texas filed a rate case requesting a $112 million base rate increase reflecting a 10.6% return on common equity based on an adjusted June 2011 test year. The rate case also proposed a purchased power recovery rider. On January 12, 2012, the PUCT voted not to address the purchased power recovery rider in the rate case, but the PUCT voted to set a baseline in the rate case proceeding that would be applicable if a purchased power capacity rider is approved in a separate proceeding. In April 2012 the PUCT Staff filed direct testimony recommending a base rate increase of $66 million and a 9.6% return on common equity. The PUCT Staff, however, subsequently filed a statement of position in the proceeding indicating that it was still evaluating the position it would ultimately take in the case regarding Entergy Texas’s recovery of purchased power capacity costs and Entergy Texas’s proposal to defer its MISO transition expenses. In April 2012, Entergy Texas filed rebuttal testimony indicating a revised request for a $105 million base rate increase. A hearing was held in late-April through early-May 2012.

In September 2012 the PUCT issued an order approving a $28 million rate increase, effective July 2012. The order includes a finding that “a return on common equity (ROE) of 9.80 percent will allow [Entergy Texas] a reasonable opportunity to earn a reasonable return on invested capital.” The order also provides for increases in depreciation rates and the annual storm reserve accrual. The order also reduced Entergy Texas’s proposed purchased power capacity costs, stating that they are not known and measurable; reduced Entergy Texas’s regulatory assets associated with Hurricane Rita; excluded from rate recovery capitalized financially-based incentive compensation; included $1.6 million of MISO transition expense in base rates, and reduced Entergy’s Texas’s fuel reconciliation recovery by $4 million because it disagreed with the line-loss factor used in the calculation. After considering the progress of the proceeding in light of the PUCT order, Entergy Texas recorded in the third quarter 2012 an approximate $24 million charge to recognize that assets associated with Hurricane Rita, financially-based incentive compensation, and fuel recovery are no longer probable of recovery. Entergy Texas continues to believe that it is entitled to recover these prudently incurred costs, however, and it filed a motion for rehearing regarding these and several other issues in the PUCT’s order on October 4, 2012. Several other parties also filed motions for rehearing of the PUCT’s order. The PUCT subsequently denied rehearing of substantive issues. Several parties, including Entergy Texas, appealed various aspects of the PUCT’s order to the Travis County District Court. A hearing was held in July 2014. In October 2014 the Travis County District Court issued an order upholding the PUCT’s decision except as to the line-loss factor issue referenced above, which was found in favor of Entergy Texas. In November 2014, Entergy Texas and other parties,

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including the PUCT, appealed the Travis County District Court decision to the Third Court of Appeals. Oral argument before the court panel was held in September 2015. In April 2016 the Third Court of Appeals issued its opinion affirming the District Court’s decision on all points. Entergy Texas petitioned the Texas Supreme Court to hear its appeal of the Third Court’s ruling. That petition is pending.

2013 Rate Case

In September 2013, Entergy Texas filed a rate case requesting a $38.6 million base rate increase reflecting a 10.4% return on common equity based on an adjusted test year ending March 31, 2013. The rate case also proposed (1) a rough production cost equalization adjustment rider recovering Entergy Texas’s payment to Entergy New Orleans to achieve rough production cost equalization based on calendar year 2012 production costs and (2) a rate case expense rider recovering the cost of the 2013 rate case and certain costs associated with previous rate cases. The rate case filing also included a request to reconcile $0.9 billion of fuel and purchased power costs and fuel revenues covering the period July 2011 through March 2013. The fuel reconciliation also reflects special circumstances fuel cost recovery of approximately $22 million of purchased power capacity costs. In January 2014 the PUCT staff filed direct testimony recommending a retail rate reduction of $0.3 million and a 9.2% return on common equity. In March 2014, Entergy Texas filed an Agreed Motion for Interim Rates. The motion explained that the parties to this proceeding have agreed that Entergy Texas should be allowed to implement new rates reflecting an $18.5 million base rate increase, effective for usage on and after April 1, 2014, as well as recovery of charges for rough production cost equalization and rate case expenses. In March 2014 the State Office of Administrative Hearings, the body assigned to hear the case, approved the motion. In April 2014, Entergy Texas filed a unanimous stipulation in this case. Among other things, the stipulation provides for an $18.5 million base rate increase, provides for recovery over three years of the calendar year 2012 rough production cost equalization charges and rate case expenses, and states a 9.8% return on common equity. In addition, the stipulation finalizes the fuel and purchased power reconciliation covering the period July 2011 through March 2013, with the parties stipulating an immaterial fuel disallowance. No special circumstances recovery of purchased power capacity costs was allowed. In April 2014 the State Office of Administrative Hearings remanded the case back to the PUCT for final processing. In May 2014 the PUCT approved the stipulation. No motions for rehearing were filed during the statutory rehearing period.

Other Filings

In September 2014, Entergy Texas filed for a distribution cost recovery factor (DCRF) rider based on a law that was passed in 2011 allowing for the recovery of increases in capital costs associated with distribution plant. Entergy Texas requested collection of approximately $7 million annually from retail customers. The parties reached a unanimous settlement authorizing recovery of $3.6 million annually commencing with usage on and after January 1, 2015. A State Office of Administrative Hearings ALJ issued an order in December 2014 authorizing this recovery on an interim basis and remanded the case to the PUCT. In February 2015 the PUCT entered a final order, making the settlement final and the interim rates permanent. In September 2015, Entergy Texas filed to amend its distribution cost recovery factor rider. Entergy Texas requested an increase in recovery under the rider of $6.5 million, for a total collection of $10.1 million annually from retail customers. In October 2015 intervenors and PUCT staff filed testimony opposing, in part, Entergy Texas’s request. In November 2015, Entergy Texas and the parties filed an unopposed settlement agreement and supporting documents. The settlement established an annual revenue requirement of $8.65 million for the amended DCRF rider, with the resulting rates effective for usage on and after January 1, 2016. The PUCT approved the settlement agreement in February 2016.

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that the PUCT disallow approximately $2 million from Entergy Texas’s $13 million request, but recommending that the PUCT not accept the load growth offset. In April 2016 the PUCT voted to allow Entergy Texas’s TCRF rates to become effective as of April 14, 2016 when those rates are finally approved, but did not otherwise address the proposal for decision. In May 2016 the PUCT deferred final consideration of Entergy Texas’s TCRF application and opened the record to consider additional evidence to be provided by Entergy Texas and potentially other parties regarding the rate-making treatment of spare transmission-level transformers that are transferred among the Utility operating companies. In June 2016 the PUCT indicated that it would take up in a future rulemaking project the issue of whether a load growth adjustment should apply to a TCRF. In July 2016 the PUCT issued an order generally accepting the proposal for decision but declining to adjust the TCRF baseline in two instances as recommended by the ALJ, which resulted in a total annual allowance of approximately $10.5 million. The PUCT also ordered its staff and Entergy Texas to track all spare autotransformer transfers going forward so that it could address the appropriate accounting treatment and prudence of such transfers in Entergy Texas’s next base rate case. Entergy Texas implemented the TCRF rider beginning with September 2016 bills.

In September 2016, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The proposed amended TCRF rider is designed to collect approximately $29.5 million annually from Entergy Texas’s retail customers. This amount includes the approximately $10.5 million annually that Entergy Texas is currently authorized to collect through the TCRF rider, as discussed above. In September 2016 the PUCT suspended the effective date of the tariff change to March 2017. In December 2016, concurrent with the 2016 fuel reconciliation stipulation and settlement agreement discussed above, Entergy Texas and the PUCT reached a settlement agreeing to the amended TCRF annual revenue requirement of $29.5 million. As discussed above, the terms of the two settlements are interdependent. PUCT action on the stipulations and settlement agreements is pending.

Entergy Louisiana and Entergy Gulf States Louisiana Business Combination

Entergy Louisiana and Entergy Gulf States Louisiana filed an application with the LPSC in September 2014 seeking authorization to undertake the transactions that would result in the combination of Entergy Louisiana and Entergy Gulf States Louisiana into a single public utility. In the application, Entergy Louisiana and Entergy Gulf States Louisiana identified potential benefits, including enhanced economic and customer diversity, enhanced geographic and supply diversity, and greater administrative efficiency. In the initial proceedings with the LPSC, Entergy Louisiana and Entergy Gulf States Louisiana estimated that the business combination could produce up to $128 million in measurable customer benefits during the first ten years following the transaction’s close including proposed guaranteed customer credits of $97 million in the first nine years. In April 2015 the LPSC staff and intervenors filed testimony in the LPSC business combination proceeding. The testimony recommended an extensive set of conditions that would be required in order to recommend that the LPSC find that the business combination was in the public interest. The LPSC staff’s primary concern appeared to be potential shifting in fuel costs between Entergy Louisiana and Entergy Gulf States Louisiana customers. In May 2015, Entergy Louisiana and Entergy Gulf States Louisiana filed rebuttal testimony. After the testimony was filed with the LPSC, the parties engaged in settlement discussions that ultimately led to the execution of an uncontested stipulated settlement (“stipulated settlement”), which was filed with the LPSC in July 2015. Through the stipulated settlement, the parties agreed to terms upon which to recommend that the LPSC find that the business combination was in the public interest. The stipulated settlement, which was either joined, or unopposed, by all parties to the LPSC proceeding, represents a compromise of stakeholder positions and was the result of an extensive period of analysis, discovery, and negotiation. The stipulated settlement provides $107 million in guaranteed customer benefits during the first nine years following the transaction’s close. Additionally, the combined company will honor the 2013 Entergy Louisiana and Entergy Gulf States Louisiana rate case settlements, including the commitments that (1) there will be no rate increase for legacy Entergy Gulf States Louisiana customers for the 2014 test year, and (2) through the 2016 test year formula rate plan, Entergy Louisiana (as a combined entity) will not raise rates by more than $30 million, net of the $10 million rate increase included in the Entergy Louisiana legacy formula rate plan. The stipulated settlement also describes the process for implementing a fuel-tracking mechanism that is designed to address potential effects arising from the shifting of fuel costs between legacy Entergy Louisiana and legacy Entergy Gulf States Louisiana customers as a result of the combination of those companies’ fuel adjustment clauses. Specifically, the fuel tracker would reallocate such cost shifts as between legacy customers of the companies

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Notes to Financial Statements

on an after-the-fact basis, and the calculation of the fuel tracker will be submitted annually in a compliance filing. The stipulated settlement also provides that Entergy Gulf States Louisiana and Entergy Louisiana are permitted to defer certain external costs that were incurred to achieve the business combination’s customer benefits. The deferred amount, which shall not exceed $25 million, will be subject to a prudence review and amortized over a 10-year period. In 2015 deferrals of $16 million for these external costs were recorded. A hearing on the stipulated settlement in the LPSC proceeding was held in July 2015. In August 2015 the LPSC approved the business combination.

In April 2015 the FERC approved applications requesting authorization for the business combination. In August 2015 the NRC approved the applications for the River Bend and Waterford 3 license transfers as part of the steps to complete the business combination.

On October 1, 2015, the businesses formerly conducted by Entergy Louisiana and Entergy Gulf States Louisiana were combined into a single public utility. With the completion of the business combination, Entergy Louisiana holds substantially all of the assets, and has assumed the liabilities, of Entergy Louisiana and Entergy Gulf States Louisiana. The combination was accounted for as a transaction between entities under common control. See Note 3 to the financial statements for further discussion of the customer credits resulting from the business combination.

Algiers Asset Transfer (Entergy Louisiana and Entergy New Orleans)

In October 2014, Entergy Louisiana and Entergy New Orleans filed an application with the City Council seeking authorization to undertake a transaction that would result in the transfer from Entergy Louisiana to Entergy New Orleans of certain assets that supported the provision of service to Entergy Louisiana’s customers in Algiers. In April 2015 the FERC issued an order approving the Algiers assets transfer. In May 2015 the parties filed a settlement agreement authorizing the Algiers assets transfer and the settlement agreement was approved by a City Council resolution in May 2015. On September 1, 2015, Entergy Louisiana transferred its Algiers assets to Entergy New Orleans for a purchase price of approximately $85 million. Entergy New Orleans paid Entergy Louisiana $59.6 million, including final true-ups, from available cash and issued a note payable to Entergy Louisiana in the amount of $25.5 million.

System Agreement Cost Equalization Proceedings

Prior to the termination of the System Agreement, the Utility operating companies historically engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement. Entergy Arkansas terminated its participation in the System Agreement in December 2013. Entergy Mississippi terminated its participation in the System Agreement in November 2015. The System Agreement terminated with respect to its remaining participants in August 2016.

Although the System Agreement has terminated, certain of the Utility operating companies’ retail regulators are pursuing litigation involving the System Agreement at the FERC and in federal courts. The proceedings include challenges to the allocation of costs as defined by the System Agreement and other matters.

In June 2005 the FERC issued a decision in System Agreement litigation that had been commenced by the LPSC, and essentially affirmed its decision in a December 2005 order on rehearing. The FERC decision concluded, among other things, that:


•	The System Agreement no longer roughly equalizes total production costs among the Utility operating companies.


•	In order to reach rough production cost equalization, the FERC imposed a bandwidth remedy by which each company’s total annual production costs will have to be within +/- 11% of Entergy System average total annual production costs.


•	In calculating the production costs for this purpose under the FERC’s order, output from the Vidalia hydroelectric power plant will not reflect the actual Vidalia price for the year but is priced at that year’s average

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price paid by Entergy Louisiana for the exchange of electric energy under Service Schedule MSS-3 of the System Agreement, thereby reducing the amount of Vidalia costs reflected in the comparison of the Utility operating companies’ total production costs.


•	The remedy ordered by FERC in 2005 required no refunds and became effective based on calendar year 2006 production costs and the first reallocation payments were made in 2007.

The FERC’s decision reallocates total production costs of the Utility operating companies whose relative total production costs expressed as a percentage of Entergy System average production costs are outside an upper or lower bandwidth. Under the current circumstances, this will be accomplished by payments from Utility operating companies whose production costs are more than 11% below Entergy System average production costs to Utility operating companies whose production costs are more than the Entergy System average production cost, with payments going first to those Utility operating companies whose total production costs are farthest above the Entergy System average.

The LPSC, APSC, MPSC, and the Arkansas Electric Energy Consumers appealed the FERC’s December 2005 decision to the United States Court of Appeals for the D.C. Circuit. Entergy and the City of New Orleans intervened in the various appeals. The D.C. Circuit issued its decision in April 2008. The D.C. Circuit concluded that the FERC’s orders had failed to adequately explain both its conclusion that it was prohibited from ordering refunds for the 20-month period from September 13, 2001 - May 2, 2003 and its determination to implement the bandwidth remedy commencing on January 1, 2006, rather than June 1, 2005. The D.C. Circuit remanded the case to the FERC for further proceedings on these issues.

In October 2011, the FERC issued an order addressing the D.C. Circuit remand on these two issues. On the first issue, the FERC concluded that it did have the authority to order refunds, but decided that it would exercise its equitable discretion and not require refunds for the 20-month period from September 13, 2001 - May 2, 2003. Because the ruling on refunds relied on findings in the interruptible load proceeding, which is discussed in a separate section below, the FERC concluded that the refund ruling will be held in abeyance pending the outcome of the rehearing requests in that proceeding. On the second issue, the FERC reversed its prior decision and ordered that the prospective bandwidth remedy begin on June 1, 2005 (the date of its initial order in the proceeding) rather than January 1, 2006, as it had previously ordered. Pursuant to the October 2011 order, Entergy was required to calculate the additional bandwidth payments for the period June - December 2005 utilizing the bandwidth formula tariff prescribed by the FERC that was filed in a December 2006 compliance filing and accepted by the FERC in an April 2007 order. As is the case with bandwidth remedy payments, these payments and receipts will ultimately be paid by Utility operating company customers to other Utility operating company customers. In March 2015, in light of the December 2014 decision by the D.C. Circuit in the interruptible load proceeding, Entergy filed with the FERC a motion to establish briefing schedule on refund issues and an initial brief addressing refund issues. The initial brief argued that the FERC, in response to the D.C. Circuit decision, should clarify its policy on refunds and find that refunds are not required in this proceeding. In October 2015 the FERC issued three orders related to the commencement of the remedy on June 1, 2005 and the inclusion of interest on the amount for the period June 1, 2005 through December 31, 2005. Specifically, the FERC rejected Entergy Services’s request for rehearing of its decision to include interest on the amount for the seven-month period. The FERC also rejected Entergy Services’s request for rehearing of the order rejecting the compliance filing with regard to the issue of interest. Finally, the FERC set for hearing and settlement procedures the 2014 compliance filing that included the bandwidth calculation for the seven months June 1, 2005 through December 31, 2005. In setting the compliance filing for hearing, the FERC rejected the APSC’s protest that Entergy Arkansas should not be subject to the filing because Entergy Arkansas would be making the payments during a period following its exit from the System Agreement. The hearing on the bandwidth calculation for the seven months June 1, 2005 through December 31, 2005 occurred in July 2016. The presiding judge issued an initial decision in November 2016. In the initial decision, the presiding judge agreed with the Utility operating companies’ position that: (1) interest on the bandwidth payments for the 2005 test period shall be accrued from June 1, 2006 until the date that the bandwidth payments for that calculation are paid consistent with how the Utility operating companies performed the calculation; and (2) a portion of Entergy Louisiana’s 2001-vintage Louisiana state net operating loss accumulated deferred income tax that results from the Vidalia tax deduction should be excluded from the 2005 test period bandwidth calculation.

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Various participants filed briefs on exceptions and/or briefs opposing exceptions related to the initial decision, including the LPSC, the APSC, the FERC trial staff, and Entergy Services. The initial decision is pending before the FERC.

In December 2011, Entergy filed with the FERC its compliance filing that provides the payments and receipts among the Utility operating companies pursuant to the FERC’s October 2011 order. The filing shows the following payments/receipts among the Utility operating companies:



	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$156
Entergy Louisiana	($75)
Entergy Mississippi	($33)
Entergy New Orleans	($5)
Entergy Texas	($43)

Entergy Arkansas made its payment in January 2012. In February 2012, Entergy Arkansas filed for an interim adjustment to its production cost allocation rider requesting that the $156 million payment be collected from customers over the 22-month period from March 2012 through December 2013. In March 2012 the APSC issued an order stating that the payment can be recovered from retail customers through the production cost allocation rider, subject to refund. The LPSC and the APSC have requested rehearing of the FERC’s October 2011 order. In December 2013 the LPSC filed a petition for a writ of mandamus at the United States Court of Appeals for the D.C. Circuit. In its petition, the LPSC requested that the D.C. Circuit issue an order compelling the FERC to issue a final order on pending rehearing requests. In January 2014 the D.C. Circuit denied the LPSC’s petition. The APSC, the LPSC, the PUCT, and other parties intervened in the December 2011 compliance filing proceeding, and the APSC and the LPSC also filed protests.

In February 2014 the FERC issued a rehearing order addressing its October 2011 order. The FERC denied the LPSC’s request for rehearing on the issues of whether the bandwidth remedy should be made effective earlier than June 1, 2005, and whether refunds should be ordered for the 20-month refund effective period. The FERC granted the LPSC’s rehearing request on the issue of interest on the bandwidth payments/receipts for the June - December 2005 period, requiring that interest be accrued from June 1, 2006 until the date those bandwidth payments/receipts are made. Also in February 2014 the FERC issued an order rejecting the December 2011 compliance filing that calculated the bandwidth payments/receipts for the June - December 2005 period. The FERC order required a new compliance filing that calculates the bandwidth payments/receipts for the June - December 2005 period based on monthly data for the seven individual months including interest pursuant to the February 2014 rehearing order. Entergy has sought rehearing of the February 2014 orders with respect to the FERC’s determinations regarding interest. In April 2014 the LPSC filed a petition for review of the FERC’s October 2011 and February 2014 orders with the U.S. Court of Appeals for the D.C. Circuit. The appeal is pending.

In April and May 2014, Entergy filed with the FERC an updated compliance filing that provides the payments and receipts among the Utility operating companies pursuant to the FERC’s February 2014 orders. The filing shows the following net payments and receipts, including interest, among the Utility operating companies:



	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$68
Entergy Louisiana	($10)
Entergy Mississippi	($11)
Entergy New Orleans	$2
Entergy Texas	($49)

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These payments were made in May 2014. The LPSC, City Council, and APSC have filed protests. As discussed above, the hearing on the bandwidth calculation for the seven months June 1, 2005 through December 31, 2005 occurred in July 2016.

Rough Production Cost Equalization Rates

Each May since 2007 Entergy has filed with the FERC the rates to implement the FERC’s orders in the System Agreement proceeding. These filings show the following payments/receipts among the Utility operating companies are necessary to achieve rough production cost equalization as defined by the FERC’s orders:



	Payments (Receipts)
	2007			2008			2009			2010			2011			2012			2013			2014
	(In Millions)
Entergy Arkansas		$252			$252			$390			$41			$77			$41			$—			$—
Entergy Louisiana		($211	)		($160	)		($247	)		($22	)		($12	)		($41	)		$—			$—
Entergy Mississippi		($41	)		($20	)		($24	)		($19	)		($40	)		$—			$—			$—
Entergy New Orleans		$—			($7	)		$—			$—			($25	)		$—			($15	)		($15	)
Entergy Texas		($30	)		($65	)		($119	)		$—			$—			$—			$15			$15

The Utility operating companies record, as necessary, accounts payable or accounts receivable to reflect the rough production cost equalization payments and receipts required to implement the FERC’s remedy. When accounts payable are recorded, a corresponding regulatory asset is recorded for the right to collect the payments from customers. When accounts receivable are recorded, a corresponding regulatory liability is recorded for the obligations to pass the receipts on to customers. No payments were required in 2016 or 2015 to implement the FERC’s remedy based on calendar year 2015 production costs and 2014 production costs, respectively. Entergy Arkansas ceased participating in the System Agreement on December 18, 2013 and was not part of the calendar year 2013 or 2014 production costs calculations. The System Agreement terminated in August 2016.

The APSC has approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas. Entergy Texas is recovering its 2013 rough production cost equalization payment over three years beginning April 2014. Entergy Texas included its 2014 rough production cost equalization payment as a component of an interim fuel refund made in 2014. Management believes that any changes in the allocation of production costs resulting from the FERC’s decision and related retail proceedings should result in similar rate changes for retail customers, subject to specific circumstances that have caused trapped costs.

Comprehensive Bandwidth Recalculation for 2007, 2008, and 2009 Rate Filing Proceedings

In July 2014 the FERC issued four orders in connection with various Service Schedule MSS-3 rough production cost equalization formula compliance filings and rehearing requests. Specifically, the FERC accepted Entergy Services’ revised methodologies for calculating certain cost components of the formula and affirmed its prior ruling requiring interest on the true-up amounts. The FERC directed that a comprehensive recalculation of the formula be performed for the filing years 2007, 2008, and 2009 based on calendar years 2006, 2007, and 2008 production costs. In September 2014, Entergy filed with the FERC its compliance filing that provides the payments and receipts, including interest, among the Utility operating companies pursuant to the FERC’s orders for the 2007, 2008, and 2009 rate filing proceedings. The filing shows the following additional payments/receipts among the Utility operating companies:

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	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$38
Entergy Louisiana	($38)
Entergy Mississippi	$16
Entergy New Orleans	($1)
Entergy Texas	($15)

Entergy Arkansas and Entergy Mississippi made the payments in September and October 2014.

The FERC proceedings that resulted from rate filings made in 2007, 2008, and 2009 have been resolved by various orders issued by the FERC and appellate courts. See below for a discussion of rate filings since 2009 and the comprehensive recalculation filing directed by the FERC in the proceeding related to the 2010 rate filing.

2010 Rate Filing Based on Calendar Year 2009 Production Costs

In May 2010, Entergy filed with the FERC the 2010 rates in accordance with the FERC’s orders in the System Agreement proceeding, and supplemented the filing in September 2010. Several parties intervened in the proceeding at the FERC, including the LPSC and the City Council, which also filed protests. In July 2010 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2010, subject to refund, and set the proceeding for hearing and settlement procedures. Settlement procedures have been terminated, and the ALJ scheduled hearings to begin in March 2011. Subsequently, in January 2011 the ALJ issued an order directing the parties and FERC Staff to show cause why this proceeding should not be stayed pending the issuance of FERC decisions in the prior production cost proceedings currently before the FERC on review. In March 2011 the ALJ issued an order placing this proceeding in abeyance. In October 2013 the FERC issued an order granting clarification and denying rehearing with respect to its October 2011 rehearing order in this proceeding. The FERC clarified that in a bandwidth proceeding parties can challenge erroneous inputs, implementation errors, or prudence of cost inputs, but challenges to the bandwidth formula itself must be raised in a Federal Power Act section 206 complaint or section 205 filing. Subsequently in October 2013 the presiding ALJ lifted the stay order holding in abeyance the hearing previously ordered by the FERC and directing that the remaining issues proceed to a hearing on the merits. The hearing was held in March 2014 and the presiding ALJ issued an initial decision in September 2014. Briefs on exception were filed in October 2014. In December 2015 the FERC issued an order affirming the initial decision in part and rejecting the initial decision in part. Among other things, the December 2015 order directs Entergy Services to submit a compliance filing, the results of which may affect the rough production cost equalization filings made for the June - December 2005, 2006, 2007, and 2008 test periods. In January 2016 the LPSC, the APSC, and Entergy Services filed requests for rehearing of the FERC’s December 2015 order. In February 2016, Entergy Services submitted the compliance filing ordered in the December 2015 order. The result of the true-up payments and receipts for the recalculation of production costs resulted in the following payments/receipts among the Utility operating companies:



	Payments (Receipts)
	(In Millions)
Entergy Arkansas	$2
Entergy Louisiana	$6
Entergy Mississippi	($4)
Entergy New Orleans	($1)
Entergy Texas	($3)

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In September 2016 the FERC accepted the February 2016 compliance filing subject to a further compliance filing made in November 2016. The further compliance filing is required as a result of an order also issued in September 2016 ruling on the January 2016 rehearing requests filed by the LPSC, the APSC, and Entergy Services. In the order addressing the rehearing requests, the FERC granted the LPSC’s rehearing request and directed that interest be calculated on the payment/receipt amounts based on the 2009 production costs. The FERC also granted the APSC’s and Entergy Services’s rehearing request and ordered the removal of both securitized asset accumulated deferred income taxes and contra-securitization accumulated deferred income taxes from the calculation. In November 2016, Entergy Services submitted its compliance filing in response to the FERC’s order on rehearing. The compliance filing included a revised refund calculation of the true-up payments and receipts based on 2009 test year data and interest calculations. The LPSC protested the interest calculations and the compliance filing is pending an order from the FERC.

2011 Rate Filing Based on Calendar Year 2010 Production Costs

In May 2011, Entergy filed with the FERC the 2011 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. In July 2011 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2011, subject to refund, set the proceeding for hearing procedures, and then held those procedures in abeyance pending FERC decisions in the prior production cost proceedings currently before the FERC on review. In January 2014 the LPSC filed a petition for a writ of mandamus at the United States Court of Appeals for the Fifth Circuit. In its petition, the LPSC requested that the Fifth Circuit issue an order compelling the FERC to issue a final order in several proceedings related to the System Agreement, including the 2011 rate filing based on calendar year 2010 production costs and the 2012 and 2013 rate filings discussed below. In March 2014 the Fifth Circuit rejected the LPSC’s petition for a writ of mandamus. In December 2014 the FERC rescinded its earlier abeyance order and consolidated the 2011 rate filing with the 2012, 2013, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

2012 Rate Filing Based on Calendar Year 2011 Production Costs

In May 2012, Entergy filed with the FERC the 2012 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. In August 2012 the FERC accepted Entergy’s proposed rates for filing, effective June 2012, subject to refund, set the proceeding for hearing procedures, and then held those procedures in abeyance pending FERC decisions in the prior production cost proceedings currently before the FERC on review. In December 2014 the FERC rescinded its earlier abeyance order and consolidated the 2012 rate filing with the 2011, 2013, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

2013 Rate Filing Based on Calendar Year 2012 Production Costs

In May 2013, Entergy filed with the FERC the 2013 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. The City Council intervened and filed comments related to including the outcome of a related FERC proceeding in the 2013 cost equalization calculation. In August 2013 the FERC issued an order accepting the 2013 rates, effective June 1, 2013, subject to refund, set the proceeding for hearing procedures, and then held those procedures in abeyance pending FERC decisions in the prior production cost proceedings currently before the FERC on review. In December 2014 the FERC rescinded its earlier abeyance order and consolidated the 2013 Rate Filing with the 2011, 2012, and 2014 Rate Filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

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2014 Rate Filing Based on Calendar Year 2013 Production Costs

In May 2014, Entergy filed with the FERC the 2014 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which also filed a protest. The City Council intervened and filed comments. In December 2014 the FERC issued an order accepting the 2014 rates, effective June 1, 2014, subject to refund, set the proceeding for hearing procedures, and consolidated the 2014 Rate Filing with the 2011, 2012, and 2013 Rate Filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.

Consolidated 2011, 2012, 2013, and 2014 Rate Filing Proceedings

As discussed above, in December 2014 the FERC consolidated the 2011, 2012, 2013, and 2014 rate filings for settlement and hearing procedures. In May 2015, Entergy filed direct testimony in the consolidated rate filings and the LPSC filed direct testimony concerning its complaint proceeding that is consolidated with the rate filings, challenging certain components of the pending bandwidth calculations for prior years. In July 2015 the parties filed direct and answering testimony. Among other issues with the pending bandwidth calculations, the LPSC challenged the administration of the accounting for joint account sales of energy in the intra-system bill. In August and September 2015 the parties filed additional rounds of testimony in the consolidated hearing for the 2011, 2012, 2013, and 2014 rate filings. In October 2015 the LPSC withdrew its testimony challenging the accounting for joint account sales of energy. The hearings occurred in November 2015, and an initial decision from the ALJ was issued in July 2016. In the initial decision, the ALJ generally agreed with Entergy’s bandwidth calculations with one exception on the accounting related to the Waterford 3 sale/leaseback. Briefs were filed in September 2016.

Utility Operating Company Termination of System Agreement Participation

Entergy Arkansas and Entergy Mississippi ceased participating in the System Agreement effective December 18, 2013 and November 7, 2015, respectively. Entergy Louisiana, Entergy New Orleans, and Entergy Texas terminated participation in the System Agreement on August 31, 2016, which resulted in the termination of the System Agreement in its entirety pursuant to a settlement agreement approved by the FERC in December 2015.

In December 2013, the FERC set one issue for hearing involving whether and how the benefits associated with settlement with Union Pacific regarding certain coal delivery issues should be allocated among Entergy Arkansas and the other Utility operating companies post-termination of the System Agreement. In December 2014 a FERC ALJ issued an initial decision finding that Entergy Arkansas would realize benefits after December 18, 2013 from the 2008 settlement agreement between Entergy Services, Entergy Arkansas, and Union Pacific, related to certain coal delivery issues. The ALJ further found that all of the Utility operating companies should share in those benefits pursuant to the methodology proposed by the MPSC. The Utility operating companies and other parties to the proceeding filed briefs on exceptions and/or briefs opposing exceptions with the FERC challenging various aspects of the December 2014 initial decision. In March 2016 the FERC issued an opinion affirming the December 2014 initial decision with regard to the determination that there were benefits related to the Union Pacific settlement, which were realized post Entergy Arkansas’s December 2013 withdrawal from the System Agreement, that should be shared with the other Utility operating companies utilizing the methodology proposed by the MPSC and trued-up to actual coal volumes purchased. In May 2016, Entergy made a compliance filing that provided the calculation of Union Pacific settlement benefits utilizing the methodology adopted by the initial decision, trued-up for the actual volumes of coal purchased. The payments were made in May 2016. In August 2016 the FERC issued an order accepting Entergy’s compliance filing. Also in August 2016 the APSC filed a petition for review of the FERC’s March 2016 and August 2016 orders with the U.S. Court of Appeals for the D.C. Circuit.

In connection with the System Agreement termination settlement agreement, the purchase power agreements, referred to as the jurisdictional separation plan PPAs, between Entergy Texas and Entergy Gulf States Louisiana that were put in place for certain legacy gas units at the time of Entergy Gulf States’s separation into Entergy Texas and Entergy Gulf States Louisiana terminated effective with the System Agreement termination. Similarly, the purchase

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power agreement between Entergy Gulf States Louisiana and Entergy Texas for the Calcasieu unit also terminated. In March 2016, Entergy Services filed with the FERC the notices of termination. The jurisdictional separation plan PPAs were the means by which Entergy Texas received payment for its receivable associated with Entergy Louisiana’s Spindletop gas storage facility regulatory asset. As a result of the System Agreement termination settlement agreement, effective with the termination date, Entergy Texas no longer receives payments from Entergy Louisiana related to the Spindletop storage facility which resulted in a write-off recorded in 2015 by Entergy Texas of $23.5 million ($15.3 million net-of-tax). Upon termination of the System Agreement, other purchase power agreements entered into under Service Schedule MSS-4 of the System Agreement were replaced with updated agreements under a FERC-jurisdictional tariff effective September 1, 2016.

Interruptible Load Proceeding

In April 2007 the U.S. Court of Appeals for the D.C. Circuit issued its opinion in the LPSC’s appeal of the FERC’s March 2004 and April 2005 orders related to the treatment under the System Agreement of the Utility operating companies’ interruptible loads. In its opinion the D.C. Circuit concluded that the FERC (1) acted arbitrarily and capriciously by allowing the Utility operating companies to phase-in the effects of the elimination of the interruptible load over a 12-month period of time; (2) failed to adequately explain why refunds could not be ordered under Section 206(c) of the Federal Power Act; and (3) exercised appropriately its discretion to defer addressing the cost of sulfur dioxide allowances until a later time. The D.C. Circuit remanded the matter to the FERC for a more considered determination on the issue of refunds. The FERC issued its order on remand in September 2007, in which it directed Entergy to make a compliance filing removing all interruptible load from the computation of peak load responsibility commencing April 1, 2004 and to issue any necessary refunds to reflect this change. In addition, the order directed the Utility operating companies to make refunds for the period May 1995 through July 1996. In November 2007 the Utility operating companies filed a refund report describing the refunds to be issued pursuant to the FERC’s orders. The LPSC filed a protest to the refund report in December 2007, and the Utility operating companies filed an answer to the protest in January 2008. The refunds were made in October 2008 by the Utility operating companies that owed refunds to the Utility operating companies that were due a refund under the decision. The APSC and the Utility operating companies appealed the FERC decisions to the D.C. Circuit.

Following the filing of petitioners’ initial briefs, the FERC filed a motion requesting the D.C. Circuit hold the appeal of the FERC’s decisions ordering refunds in the interruptible load proceeding in abeyance and remand the record to the FERC. The D.C. Circuit granted the FERC’s unopposed motion in June 2009. In December 2009 the FERC established a paper hearing to determine whether the FERC had the authority and, if so, whether it would be appropriate to order refunds resulting from changes in the treatment of interruptible load in the allocation of capacity costs by the Utility operating companies. In August 2010 the FERC issued an order stating that it has the authority and refunds are appropriate. The APSC, MPSC, and Entergy requested rehearing of the FERC’s decision. In June 2011 the FERC issued an order granting rehearing in part and denying rehearing in part, in which the FERC determined to invoke its discretion to deny refunds. The FERC held that in this case where “the Entergy system as a whole collected the proper level of revenue, but, as was later established, incorrectly allocated peak load responsibility among the various Entergy operating companies….the Commission will apply here our usual practice in such cases, invoking our equitable discretion to not order refunds, notwithstanding our authority to do so.” The LPSC has requested rehearing of the FERC’s June 2011 decision. In July 2011 the refunds made in the fourth quarter 2009 described above were reversed. In October 2011 the FERC issued an “Order Establishing Paper Hearing” inviting parties that oppose refunds to file briefs within 30 days addressing the LPSC’s argument that FERC precedent supports refunds under the circumstances present in this proceeding. Parties that favor refunds were then invited to file reply briefs within 21 days of the date that the initial briefs are due. Briefs were submitted and the matter is pending.

In September 2010 the FERC had issued an order setting the refund report filed in the proceeding in November 2007 for hearing and settlement judge procedures. In May 2011, Entergy filed a settlement agreement that resolved all issues relating to the refund report set for hearing. In June 2011 the settlement judge certified the settlement as uncontested and the settlement agreement is currently pending before the FERC. In July 2011, Entergy filed an

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amended/corrected refund report and a motion to defer action on the settlement agreement until after the FERC rules on the LPSC’s rehearing request regarding the June 2011 decision denying refunds.

Prior to the FERC’s June 2011 order on rehearing, Entergy Arkansas filed an application in November 2010 with the APSC for recovery of the refund that it paid. The APSC denied Entergy Arkansas’s application, and also denied Entergy Arkansas’s petition for rehearing. If the FERC were to order Entergy Arkansas to pay refunds on rehearing in the interruptible load proceeding the APSC’s decision would trap FERC-approved costs at Entergy Arkansas with no regulatory-approved mechanism to recover them. In August 2011, Entergy Arkansas filed a complaint in the United States District Court for the Eastern District of Arkansas asking for a declaratory judgment that the rejection of Entergy Arkansas’s application by the APSC is preempted by the Federal Power Act. The APSC filed a motion to dismiss the complaint. In April 2012 the United States district court dismissed Entergy Arkansas’s complaint without prejudice stating that Entergy Arkansas’s claim is not ripe for adjudication and that Entergy Arkansas did not have standing to bring suit at this time.

In March 2013 the FERC issued an order denying the LPSC’s request for rehearing of the FERC’s June 2011 order wherein the FERC concluded it would exercise its discretion and not order refunds in the interruptible load proceeding. Based on its review of the LPSC’s request for rehearing and the briefs filed as part of the paper hearing established in October 2011, the FERC affirmed its earlier ruling and declined to order refunds under the circumstances of the case. In May 2013 the LPSC filed a petition for review with the U.S. Court of Appeals for the D.C. Circuit seeking review of FERC prior orders in the Interruptible Load Proceeding that concluded that the FERC would exercise its discretion and not order refunds in the proceeding. Oral argument was held on the appeal in the D.C. Circuit in September 2014. In December 2014 the D.C. Circuit issued an order on the LPSC’s appeal and remanded the case back to the FERC. The D.C. Circuit rejected the LPSC’s argument that there is a presumption in favor of refunds, but it held that the FERC had not adequately explained its decision to deny refunds and directed the FERC “to consider the relevant factors and weigh them against one another.” In March 2015, Entergy filed with the FERC a motion to establish a briefing schedule on remand and an initial brief on remand to address the December 2014 decision by the D.C. Circuit. The initial brief on remand argued that the FERC, in response to the D.C. Circuit decision, should clarify its policy on refunds and find that refunds are not required in the interruptible load proceeding.

In April 2016 the FERC issued an order on remand that addressed the December 2014 decision by the D.C. Circuit in the interruptible load proceeding. The order on remand affirmed the FERC’s denial of refunds for the 15-month refund effective period. The FERC explained and clarified its policies regarding refunds and concluded that the evidence in the record demonstrated that the relevant equitable factors favored not requiring refunds in this case. The FERC also noted that, under Section 206(c) of the Federal Power Act, in a Section 206 proceeding involving two or more electric utility companies of a registered holding company system, the FERC may order refunds only if it determines the refunds would not cause the registered holding company to experience any reduction in revenues resulting from an inability of an electric utility company in the system to recover the resulting increase in costs. The FERC stated it was not able to find that the Entergy system would not experience a reduction in revenues if refunds were awarded in this proceeding, which further supported the denial of refunds. In May 2016 the LPSC filed a request for rehearing of the FERC’s April 2016 order. In September 2016 the FERC issued an order denying the LPSC’s request for rehearing and reaffirming its denial of refunds for the 15-month refund effective period. The LPSC has appealed the April and September 2016 orders to the U.S. Court of Appeals for the D.C. Circuit.

Entergy Arkansas Opportunity Sales Proceeding

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merits without hearing because the LPSC has failed to meet its burden of showing any violation of the System Agreement and failed to produce any evidence of imprudent action by the Entergy System. In their response, the Utility operating companies explained that the System Agreement clearly contemplates that the Utility operating companies may make sales to third parties for their own account, subject to the requirement that those sales be included in the load (or load shape) for the applicable Utility operating company. The FERC subsequently ordered a hearing in the proceeding.

The LPSC filed direct testimony in the proceeding alleging, among other things, (1) that Entergy violated the System Agreement by permitting Entergy Arkansas to make non-requirements sales to non-affiliated third parties rather than making such energy available to the other Utility operating companies’ customers; and (2) that over the period 2000 - 2009, these non-requirements sales caused harm to the Utility operating companies’ customers and these customers should be compensated for this harm by Entergy. In subsequent testimony, the LPSC modified its original damages claim in favor of quantifying damages by re-running intra-system bills. The Utility operating companies believe the LPSC’s allegations are without merit. A hearing in the matter was held in August 2010.

In December 2010 the ALJ issued an initial decision. The ALJ found that the System Agreement allowed for Entergy Arkansas to make the sales to third parties but concluded that the sales should be accounted for in the same manner as joint account sales. The ALJ concluded that “shareholders” should make refunds of the damages to the Utility operating companies, along with interest. Entergy disagreed with several aspects of the ALJ’s initial decision and in January 2011 filed with the FERC exceptions to the decision.

The FERC issued a decision in June 2012 and held that, while the System Agreement is ambiguous, it does provide authority for individual Utility operating companies to make opportunity sales for their own account and Entergy Arkansas made and priced these sales in good faith. The FERC found, however, that the System Agreement does not provide authority for an individual Utility operating company to allocate the energy associated with such opportunity sales as part of its load, but provides a different allocation authority. The FERC further found that the after-the-fact accounting methodology used to allocate the energy used to supply the sales was inconsistent with the System Agreement. Quantifying the effect of the FERC’s decision will require re-running intra-system bills for a ten-year period, and the FERC in its decision established further hearing procedures to determine the calculation of the effects. In July 2012, Entergy and the LPSC filed requests for rehearing of the FERC’s June 2012 decision, which are pending with the FERC.

As required by the procedural schedule established in the calculation proceeding, Entergy filed its direct testimony that included a proposed illustrative re-run, consistent with the directives in FERC’s order, of intra-system bills for 2003, 2004, and 2006, the three years with the highest volume of opportunity sales. Entergy’s proposed illustrative re-run of intra-system bills shows that the potential cost for Entergy Arkansas would be up to $12 million for the years 2003, 2004, and 2006, excluding interest, and the potential benefit would be significantly less than that for each of the other Utility operating companies. Entergy’s proposed illustrative re-run of the intra-system bills also shows an offsetting potential benefit to Entergy Arkansas for the years 2003, 2004, and 2006 resulting from the effects of the FERC’s order on System Agreement Service Schedules MSS-1, MSS-2, and MSS-3, and the potential offsetting cost would be significantly less than that for each of the other Utility operating companies. Entergy provided to the LPSC an illustrative intra-system bill recalculation as specified by the LPSC for the years 2003, 2004, and 2006, and the LPSC then filed answering testimony in December 2012. In its testimony the LPSC claims that the damages, excluding interest, that should be paid by Entergy Arkansas to the other Utility operating company’s customers for 2003, 2004, and 2006 are $42 million to Entergy Gulf States, Inc., $7 million to Entergy Louisiana, $23 million to Entergy Mississippi, and $4 million to Entergy New Orleans. The FERC staff and certain intervenors filed direct and answering testimony in February 2013. In April 2013, Entergy filed its rebuttal testimony in that proceeding, including a revised illustrative re-run of the intra-system bills for the years 2003, 2004, and 2006. The revised calculation determines the re-pricing of the opportunity sales based on consideration of moveable resources only and the removal of exchange energy received by Entergy Arkansas, which increases the potential cost for Entergy Arkansas over the three years 2003, 2004, and 2006 by $2.3 million from the potential costs identified in the Utility operating companies’ prior filings in September and October 2012. A hearing was held in May 2013 to quantify the effect of repricing the opportunity sales in accordance with the FERC’s decision.

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In August 2013 the presiding judge issued an initial decision in the calculation proceeding. The initial decision concludes that the methodology proposed by the LPSC, rather than the methodologies proposed by Entergy or the FERC Staff, should be used to calculate the payments that Entergy Arkansas is to make to the other Utility operating companies. The initial decision also concludes that the other System Agreement service schedules should not be adjusted and that payments by Entergy Arkansas should not be reflected in the rough production cost equalization bandwidth calculations for the applicable years. The initial decision does recognize that the LPSC’s methodology would result in an inequitable windfall to the other Utility operating companies and, therefore, concludes that any payments by Entergy Arkansas should be reduced by 20%. The LPSC, APSC, City Council, and FERC staff filed briefs on exceptions and/or briefs opposing exceptions. Entergy filed a brief on exceptions requesting that FERC reverse the initial decision and a brief opposing certain exceptions taken by the LPSC and FERC staff.

In April 2016 the FERC issued orders addressing the requests for rehearing filed in July 2012 and the ALJ’s August 2013 initial decision. The first order denies Entergy’s request for rehearing and affirms FERC’s earlier rulings that Entergy’s original methodology for allocating energy costs to the opportunity sales was incorrect and, as a result, Entergy Arkansas must make payments to the other Utility operating companies to put them in the same position that they would have been in absent the incorrect allocation. The FERC clarified that interest should be included with the payments. The second order affirmed in part, and reversed in part, the rulings in the ALJ’s initial decision regarding the methodology that should be used to calculate the payments Entergy Arkansas is to make to the other Utility operating companies. The FERC affirmed the ALJ’s ruling that a full re-run of intra-system bills should be performed, but required that methodology be modified so that the sales have the same priority for purposes of energy allocation as joint account sales. The FERC reversed the ALJ’s decision that any payments by Entergy Arkansas should be reduced by 20%. The FERC also reversed the ALJ’s decision that adjustments to other System Agreement service schedules and excess bandwidth payments should not be taken into account when calculating the payments to be made by Entergy Arkansas. The FERC held that such adjustments and excess bandwidth payments should be taken into account, but ordered further proceedings before an ALJ to address whether a cap on any reduction due to bandwidth payments was necessary and to implement the other adjustments to the calculation methodology.

The effect of the FERC’s decisions, if upheld, is that Entergy Arkansas will make payments to some or all of the other Utility operating companies. As part of the further proceedings required by the FERC, Entergy has performed an initial re-run of the intra-system bills for the ten-year period (2000-2009) to attempt to quantify the effects of the FERC's rulings. The ALJ will issue an initial decision and FERC will issue an order reviewing that decision. No payments will be made or received by the Utility operating companies until the FERC issues an order reviewing that initial decision and Entergy submits a subsequent filing to comply with that order. Because further proceedings are required, the amount and recipients of payments by Entergy Arkansas are unknown at this time. Based on testimony previously submitted in the case, however, in the first quarter 2016 Entergy Arkansas recorded a liability of $87 million for its estimated increased costs and payment to the other Utility operating companies, including interest. This estimate is subject to change depending on how the FERC resolves the issues that are still outstanding in the case. Entergy Arkansas’s increased costs will be attributed to Entergy Arkansas’s retail and wholesale businesses, and it is not probable that Entergy Arkansas will recover the wholesale portion. Therefore Entergy Arkansas recorded a regulatory asset of approximately $75 million, which represents its estimate of the retail portion of the costs.

In May 2016, Entergy Services filed a request for rehearing of the FERC’s April 2016 order addressing the requests for rehearing filed in July 2012. Entergy Services also filed a request for clarification and/or rehearing of the FERC’s April 2016 order addressing the ALJ’s August 2013 initial decision. The APSC and the LPSC also filed requests for rehearing of the FERC’s April 2016 order. Also, in May 2016 a procedural schedule was established with a hearing in May 2017 and an initial decision expected in August 2017. Pursuant to that procedural schedule, Entergy Services re-ran intra-system bills for the ten-year period to quantify the effects of the FERC's ruling. In November 2016 the LPSC submitted testimony disputing certain aspects of the calculations, and Entergy Services submitted answering testimony in January 2017. In February 2017 the FERC staff filed testimony and Entergy Services filed responsive testimony.

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Complaint Against System Energy

In January 2017 the APSC and MPSC filed a complaint with the FERC against System Energy. The complaint seeks a reduction in the return on equity component of the Unit Power Sales Agreement pursuant to which System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. Entergy Arkansas also sells some of its Grand Gulf capacity and energy to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under separate agreements. The current return on equity under the Unit Power Sales Agreement is 10.94%. The complaint alleges that the return on equity is unjust and unreasonable because current capital market and other considerations indicate that it is excessive. The complaint requests the FERC to institute proceedings to investigate the return on equity and establish a lower return on equity, and also requests that the FERC establish January 23, 2017 as a refund effective date. The complaint includes return on equity analysis that purports to establish that the range of reasonable return on equity for System Energy is between 8.37% and 8.67%. System Energy answered the complaint in February 2017 and disputes a return on equity of 8.37% to 8.67% is just and reasonable. Action by the FERC is pending.

Storm Cost Recovery Filings with Retail Regulators

Entergy Louisiana

Hurricane Isaac

In August 2012, Hurricane Isaac caused extensive damage to portions of Entergy’s service area in Louisiana, and to a lesser extent in Mississippi and Arkansas. The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages. In June 2014 the LPSC voted to approve a series of orders which (i) quantified $290.8 million of Hurricane Isaac system restoration costs as prudently incurred; (ii) determined $290 million as the level of storm reserves to be re-established; (iii) authorized Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs; and (iv) granted other requested relief associated with storm reserves and Act 55 financing of Hurricane Isaac system restoration costs. Entergy Louisiana committed to pass on to customers a minimum of $30.8 million of customer benefits through annual customer credits of approximately $6.2 million for five years. Approvals for the Act 55 financings were obtained from the Louisiana Utilities Restoration Corporation (LURC) and the Louisiana State Bond Commission.

In August 2014 the Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA) issued $314.85 million in bonds under Louisiana Act 55. From the $309 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $16 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $293 million directly to Entergy Louisiana. Entergy Louisiana used the $293 million received from the LURC to acquire 2,935,152.69 Class C preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 7.5% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2014, and the membership interests have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1.75 billion.

Entergy and Entergy Louisiana do not report the bonds on their balance sheets because the bonds are the obligation of the LCDA and there is no recourse against Entergy or Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Louisiana collects a system restoration charge on behalf of the LURC, and remits the collections to the bond indenture trustee. Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.

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Hurricane Gustav and Hurricane Ike

In September 2008, Hurricane Gustav and Hurricane Ike caused catastrophic damage to Entergy’s service territory. In December 2009, Entergy Louisiana entered into a stipulation agreement with the LPSC staff that provided for total recoverable costs of approximately $628 million, including carrying costs. Under this stipulation, Entergy Louisiana agreed not to recover $11.6 million of its storm restoration spending. The stipulation also permitted replenishing Entergy Louisiana’s storm reserve in the amount of $290 million when the Act 55 financings were accomplished. In March and April 2010, Entergy Louisiana and other parties to the proceeding filed with the LPSC an uncontested stipulated settlement that included these terms and also included Entergy Louisiana’s proposal under the Act 55 financings, which included a commitment to pass on to customers a minimum of $43.3 million of customer benefits through a prospective annual rate reduction of $8.7 million for five years. In April 2010 the LPSC approved the settlement and subsequently issued financing orders and a ratemaking order intended to facilitate the implementation of the Act 55 financings. In June 2010 the Louisiana State Bond Commission approved the Act 55 financing.

In July 2010, the LCDA issued two series totaling $713.0 million in bonds under Act 55. From the $702.7 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $290 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $412.7 million directly to Entergy Louisiana. From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana used $412.7 million to acquire 4,126,940.15 Class B preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 9% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2010, and the membership interests have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion.

Entergy and Entergy Louisiana do not report the bonds on their balance sheets because the bonds are the obligation of the LCDA, and there is no recourse against Entergy or Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Louisiana collects a system restoration charge on behalf of the LURC, and remits the collections to the bond indenture trustee. Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.

Hurricane Katrina and Hurricane Rita

In August and September 2005, Hurricanes Katrina and Rita caused catastrophic damage to large portions of the Utility’s service territories in Louisiana, Mississippi, and Texas, including the effect of extensive flooding that resulted from levee breaks in and around the greater New Orleans area.

In March 2008, Entergy Louisiana and the LURC filed at the LPSC an application requesting that the LPSC grant a financing order authorizing the financing of Entergy Louisiana storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 55. The Louisiana Act 55 financing is expected to produce additional customer benefits as compared to traditional securitization. Entergy Louisiana also filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and savings to customers via a storm cost offset rider. In April 2008 the Louisiana Public Facilities Authority (LPFA), which is the issuer of the bonds pursuant to the Act 55 financing, approved requests for the Act 55 financing. Also in April 2008, Entergy Louisiana and the LPSC staff filed with the LPSC an uncontested stipulated settlement that included Entergy Louisiana’s proposal under the Act 55 financing, which included a commitment to pass on to customers a minimum of $40 million of customer benefits through a prospective annual rate reduction of $8 million for five years. The LPSC subsequently approved the settlement and issued two financing orders and one ratemaking order intended to facilitate implementation of the Act 55 financing. In May 2008 the Louisiana State Bond Commission granted final approval of the Act 55 financing.

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In July 2008 the LPFA issued $687.7 million in bonds under the aforementioned Act 55. From the $679 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $152 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $527 million directly to Entergy Louisiana. From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $545 million, including $17.8 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 5,449,861.85 Class A preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 10% annual distribution rate. In August 2008, the LPFA issued $278.4 million in bonds under the aforementioned Act 55. From the $274.7 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $87 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $187.7 million directly to Entergy Louisiana. From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $189.4 million, including $1.7 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 1,893,918.39 Class A preferred, non-voting, membership interest units of Entergy Holdings Company LLC that carry a 10% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2008 and have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion. In February 2012, Entergy Louisiana sold 500,000 of its Class A preferred membership units in Entergy Holdings Company LLC, a wholly-owned Entergy subsidiary, to a third party in exchange for $51 million plus accrued but unpaid distributions on the units. The 500,000 preferred membership units are mandatorily redeemable in January 2112.

Entergy and Entergy Louisiana do not report the bonds on their balance sheets because the bonds are the obligation of the LPFA, and there is no recourse against Entergy or Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Louisiana collect a system restoration charge on behalf of the LURC, and remits the collections to the bond indenture trustee. Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.

Entergy Mississippi

In July 2013, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation, wherein both parties agreed that approximately $32 million in storm restoration costs incurred in 2011 and 2012 were prudently incurred and chargeable to the storm damage provision, while approximately $700,000 in prudently incurred costs were more properly recoverable through the formula rate plan. Entergy Mississippi and the Mississippi Public Utilities Staff also agreed that the storm damage provision should be increased from $750,000 per month to $1.75 million per month. In September 2013 the MPSC approved the joint stipulation with the increase in the storm damage provision effective with October 2013 bills. In February 2015, Entergy Mississippi provided notice to the Mississippi Public Utilities Staff that the storm damage provision would be set to zero effective with the March 2015 billing cycle as a result of Entergy Mississippi’s storm damage provision balance exceeding $15 million as of January 31, 2015, but would return to its current level when the storm damage provision balance becomes less than $10 million. As of April 30, 2016, Entergy Mississippi’s storm damage provision balance was less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with June 2016 bills. As of September 30, 2016, however, Entergy Mississippi’s storm damage provision balance again exceeded $15 million. Accordingly the storm damage provision was reset to zero beginning with the November 2016 billing cycle and will remain at zero until the balance again becomes less than $10 million, at which time it will return to its prior level.

Entergy New Orleans

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other things, that Entergy New Orleans’s prudently-incurred storm recovery costs were $49.3 million, of which $31.7 million, net of reimbursements from the storm reserve escrow account, remained recoverable from Entergy New Orleans’s electric customers. The resolution also directed Entergy New Orleans to file an application to securitize the unrecovered Council-approved storm recovery costs of $31.7 million pursuant to the Louisiana Electric Utility Storm Recovery Securitization Act (Louisiana Act 64). In addition, the resolution found that it was reasonable for Entergy New Orleans to include in the principal amount of its potential securitization the costs to fund and replenish Entergy New Orleans’s storm reserve in an amount that achieved the Council-approved funding level of $75 million. In January 2015, in compliance with that directive, Entergy New Orleans filed with the City Council an application requesting that the City Council grant a financing order authorizing the financing of Entergy New Orleans’s storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 64. In May 2015 the parties entered into an agreement in principle and the City Council issued a financing order authorizing Entergy New Orleans to issue storm recovery bonds in the aggregate amount of $98.7 million, including $31.8 million for recovery of Entergy New Orleans’s Hurricane Isaac storm recovery costs, including carrying costs, $63.9 million to fund and replenish Entergy New Orleans’s storm reserve, and approximately $3 million for estimated up-front financing costs associated with the securitization. See Note 5 to the financial statements for discussion of the issuance of the securitization bonds in July 2015.

New Nuclear Generation Development Costs

Entergy Louisiana

Entergy Louisiana and Entergy Gulf States Louisiana were developing a project option for new nuclear generation at River Bend. In March 2010, Entergy Louisiana and Entergy Gulf States Louisiana filed with the LPSC seeking approval to continue the limited development activities necessary to preserve an option to construct a new unit at River Bend. At its June 2012 meeting the LPSC voted to uphold an ALJ recommendation that the request of Entergy Louisiana and Entergy Gulf States Louisiana be declined on the basis that the LPSC’s rule on new nuclear development does not apply to activities to preserve an option to develop and on the further grounds that the companies improperly engaged in advanced preparation activities prior to certification. The LPSC directed that Entergy Louisiana and Entergy Gulf States Louisiana be permitted to seek recovery of these costs in their upcoming rate case filings that were subsequently filed in February 2013. In the resolution of the rate case proceeding the LPSC provided for an eight-year amortization of costs incurred in connection with the potential development of new nuclear generation at River Bend, without carrying costs, beginning in December 2014, provided, however, that amortization of these costs shall not result in a future rate increase. As of December 31, 2016, Entergy Louisiana has a regulatory asset of $43.1 million on its balance sheet related to these new nuclear generation development costs.

Entergy Mississippi

Pursuant to the Mississippi Baseload Act and the Mississippi Public Utilities Act, Entergy Mississippi had been developing and preserving a project option for new nuclear generation at Grand Gulf Nuclear Station. In October 2010, Entergy Mississippi filed an application with the MPSC requesting that the MPSC determine that it was in the public interest to preserve the option to construct new nuclear generation at Grand Gulf and that the MPSC approve the deferral of Entergy Mississippi’s costs incurred to date and in the future related to this project, including the accrual of AFUDC or similar carrying charges. In October 2011, Entergy Mississippi and the Mississippi Public Utilities Staff filed with the MPSC a joint stipulation that the MPSC approved in November 2011. The stipulation stated that there should be a deferral of the $57 million of costs incurred through September 2011 in connection with planning, evaluation, monitoring, and other and related generation resource development activities for new nuclear generation at Grand Gulf.

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state, however, that, if Entergy Mississippi decides to move forward with nuclear development in Mississippi, it can at that time re-present for consideration by the MPSC only those costs directly associated with the existing early site permit (ESP), to the extent that the costs are verifiable and prudent and the ESP is still valid and relevant to any such option pursued. After considering the progress of the new nuclear generation costs proceeding in light of the joint stipulations, Entergy Mississippi recorded in 2014 a $56.2 million pre-tax charge to recognize that the regulatory asset associated with new nuclear generation development is no longer probable of recovery. In December 2014 the MPSC issued an order accepting in their entirety the October 2014 stipulations, including the findings and terms of the stipulations regarding new nuclear generation development costs.

Texas Power Price Lawsuit

In August 2003 a lawsuit was filed in the district court of Chambers County, Texas by Texas residents on behalf of a purported class of the Texas retail customers of Entergy Gulf States, Inc. who were billed and paid for electric power from January 1, 1994 to the present. The named defendants include Entergy Corporation, Entergy Services, Entergy Power, Entergy Power Marketing Corp., and Entergy Arkansas. Entergy Gulf States, Inc. was not a named defendant, but was alleged to be a co-conspirator. The court granted the request of Entergy Gulf States, Inc. to intervene in the lawsuit to protect its interests.

Plaintiffs allege that the defendants implemented a “price gouging accounting scheme” to sell to plaintiffs and similarly situated utility customers higher priced power generated by the defendants while rejecting less expensive power offered from off-system suppliers. In particular, plaintiffs allege that the defendants manipulated and continue to manipulate the dispatch of generation so that power is purchased from affiliated expensive resources instead of buying cheaper off-system power.

Plaintiffs stated in their pleadings that customers in Texas were charged at least $57 million above prevailing market prices for power. Plaintiffs seek actual, consequential and exemplary damages, costs and attorneys’ fees, and disgorgement of profits. The plaintiffs’ experts have tendered a report calculating damages in a large range, from $153 million to $972 million in present value, under various scenarios as of the date of the report. The Entergy defendants have tendered expert reports challenging the assumptions, methodologies, and conclusions of the plaintiffs’ expert reports.

In March 2012 the state district court found that the case met the requirements to be maintained as a class action under Texas law. In April 2012 the court entered an order certifying the class. The defendants appealed the order to the Texas Court of Appeals – First District and oral argument was held in May 2013. In November 2014 the Texas Court of Appeals - First District reversed the state district court’s class certification order and dismissed the case holding that the state district court lacked subject matter jurisdiction to address the issues. Plaintiffs filed a motion for rehearing and a motion for rehearing en banc. In May 2015 the Court of Appeals granted plaintiffs’ motion for rehearing, withdrew its prior opinion, and set the case for resubmission in June 2015. In July 2015 the Court of Appeals issued a new opinion again finding that the plaintiffs’ claims fall within the exclusive jurisdiction of the FERC and, therefore, the trial court lacked subject matter jurisdiction over the case. The Court of Appeals ordered that the state district court dismiss all claims against the Entergy defendants. In September 2015 plaintiffs filed a petition for review at the Supreme Court of Texas. In September 2016 the Supreme Court denied the plaintiffs’ petition for review. In December 2016 the trial court entered a final judgment of dismissal bringing this matter to a conclusion.

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NOTE 3. INCOME TAXES (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Income taxes for 2016, 2015, and 2014 for Entergy Corporation and Subsidiaries consist of the following:



	2016			2015			2014
	(In Thousands)
Current:
Federal		$45,249			$77,166			$90,061
Foreign	68			97			90
State	(14,960		)	157,829			(12,637		)
Total	30,357			235,092			77,514
Deferred and non-current - net	(840,465		)	(864,799		)	528,326
Investment tax credit adjustments - net	(7,151		)	(13,220		)	(16,243		)
Income taxes		($817,259	)		($642,927	)		$589,597

Income taxes for 2016, 2015, and 2014 for Entergy’s Registrant Subsidiaries consist of the following:



2016	Entergy Arkansas			Entergy Louisiana			Entergy Mississippi		Entergy New Orleans			Entergy Texas			System Energy
	(In Thousands)
Current:
Federal		($14,748	)		($124,113	)		$10,603		($91,067	)		$19,656			$29,628
State	2,805			10,757			2,257		566			1,374			(25,825		)
Total	(11,943		)	(113,356		)	12,860		(90,501		)	21,030			3,803
Deferred and non-current - net	120,942			208,157			46,984		119,345			42,982			71,051
Investment tax credit adjustments - net	(1,226		)	(5,067		)	4,010		(139		)	(915		)	(3,793		)
Income taxes		$107,773			$89,734			$63,854		$28,705			$63,097			$71,061



2015	Entergy Arkansas			Entergy Louisiana			Entergy Mississippi			Entergy New Orleans			Entergy Texas			System Energy
	(In Thousands)
Current:
Federal		$66,966			$101,382			$25,628			($9,346	)		$53,313			($63,302	)
State	6,265			35,406			6,832			1,784			2,450			26,755
Total	73,231			136,788			32,460			(7,562		)	55,763			(36,547		)
Deferred and non-current - net	(31,463		)	47,220			31,149			32,890			(17,599		)	93,491
Investment tax credit adjustments - net	(1,227		)	(5,337		)	(1,737		)	(138		)	(914		)	(3,867		)
Income taxes		$40,541			$178,671			$61,872			$25,190			$37,250			$53,077

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2014	Entergy Arkansas			Entergy Louisiana			Entergy Mississippi			Entergy New Orleans			Entergy Texas			System Energy
	(In Thousands)
Current:
Federal		($34,258	)		($44,909	)		$8,103			($1,428	)		$48,610			$19,908
State	(678		)	(1,191		)	7,474			510			4,877			15,379
Total	(34,936		)	(46,100		)	15,577			(918		)	53,487			35,287
Deferred and non-current - net	119,841			236,794			42,305			14,592			(2,418		)	53,501
Investment tax credit adjustments - net	(1,276		)	(5,642		)	(2,172		)	(224		)	(1,425		)	(5,478		)
Income taxes		$83,629			$185,052			$55,710			$13,450			$49,644			$83,310

Total income taxes for Entergy Corporation and Subsidiaries differ from the amounts computed by applying the statutory income tax rate to income before income taxes. The reasons for the differences for the years 2016, 2015, and 2014 are:



	2016			2015			2014
	(In Thousands)
Net income (loss) attributable to Entergy Corporation		($583,618	)		($176,562	)		$940,721
Preferred dividend requirements of subsidiaries	19,115			19,828			19,536
Consolidated net income (loss)	(564,503		)	(156,734		)	960,257
Income taxes	(817,259		)	(642,927		)	589,597
Income (loss) before income taxes		($1,381,762	)		($799,661	)		$1,549,854
Computed at statutory rate (35%)		($483,617	)		($279,881	)		$542,449
Increases (reductions) in tax resulting from:
State income taxes net of federal income tax effect	40,581			29,944			44,708
Regulatory differences - utility plant items	33,581			32,089			39,321
Equity component of AFUDC	(23,647		)	(18,191		)	(21,108		)
Amortization of investment tax credits	(10,889		)	(11,136		)	(12,211		)
Flow-through / permanent differences	(19,307		)	(7,872		)	(18,003		)
New York tax law change (a)	—			—			(21,500		)
Louisiana business combination	—			(333,655		)	—
Entergy Wholesale Commodities restructuring (b)	(237,760		)	—			—
Act 55 financing settlement (d)	(63,477		)	—			—
Provision for uncertain tax positions (c) (d)	(67,119		)	(56,683		)	32,573
Valuation allowance	11,411			—			—
Other - net	2,984			2,458			3,368
Total income taxes as reported		($817,259	)		($642,927	)		$589,597
Effective Income Tax Rate	59.1		%	80.4		%	38.0		%

(a)

In March 2014, New York enacted legislation that substantially modified various aspects of New York tax law. The most significant effect of the legislation for Entergy was the adoption of full water’s-edge unitary combined reporting, meaning that all of Entergy’s domestic entities will be included in New York’s combined filing group. The effect of the tax law change resulted in a deferred state income tax reduction of approximately $21.5 million as shown in the table above.


(b)	See “Other Tax Matters” below for discussion of the Entergy Wholesale Commodities restructuring.


(c)	See “Income Tax Audits - 2008-2009 IRS Audit” below for discussion of the most significant items for 2015.


(d)	See “Income Tax Audits - 2010-2011 IRS Audit” below for discussion of the most significant items for 2016.

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Total income taxes for the Registrant Subsidiaries differ from the amounts computed by applying the statutory income tax rate to income before taxes. The reasons for the differences for the years 2016, 2015, and 2014 are:



2016	Entergy Arkansas			Entergy Louisiana			Entergy Mississippi			Entergy New Orleans			Entergy Texas			System Energy
	(In Thousands)
Net income		$167,212			$622,047			$109,184			$48,849			$107,538			$96,744
Income taxes	107,773			89,734			63,854			28,705			63,097			71,061
Pretax income		$274,985			$711,781			$173,038			$77,554			$170,635			$167,805
Computed at statutory rate (35%)		$96,245			$249,123			$60,563			$27,144			$59,722			$58,732
Increases (reductions) in tax resulting from:
State income taxes net of federal income tax effect	11,652			29,014			5,592			3,543			449			7,001
Regulatory differences - utility plant items	10,971			8,094			(1,154		)	2,329			4,140			9,201
Equity component of AFUDC	(5,985		)	(9,774		)	(2,030		)	(412		)	(2,666		)	(2,780		)
Amortization of investment tax credits	(1,201		)	(5,019		)	(160		)	(132		)	(900		)	(3,476		)
Flow-through / permanent differences	(3,848		)	(980		)	764			(3,609		)	634			(883		)
Act 55 financing settlement (a)	—			(61,620		)	—			—			(454		)	—
Non-taxable dividend income	—			(44,658		)	—			—			—			—
Provision for uncertain tax positions (a)	(717		)	(75,871		)	50			(300		)	1,926			3,151
Other - net	656			1,425			229			142			246			115
Total income taxes as reported		$107,773			$89,734			$63,854			$28,705			$63,097			$71,061
Effective Income Tax Rate	39.2		%	12.6		%	36.9		%	37.0		%	37.0		%	42.3		%



2015	Entergy Arkansas			Entergy Louisiana			Entergy Mississippi			Entergy New Orleans			Entergy Texas			System Energy
	(In Thousands)
Net income		$74,272			$446,639			$92,708			$44,925			$69,625			$111,318
Income taxes	40,541			178,671			61,872			25,190			37,250			53,077
Pretax income		$114,813			$625,310			$154,580			$70,115			$106,875			$164,395
Computed at statutory rate (35%)		$40,185			$218,859			$54,103			$24,540			$37,406			$57,538
Increases (reductions) in tax resulting from:
State income taxes net of federal income tax effect	6,643			23,650			5,219			2,887			1,621			6,403
Regulatory differences - utility plant items	7,299			3,013			2,383			2,201			3,703			12,167
Equity component of AFUDC	(4,979		)	(5,420		)	(1,083		)	(451		)	(1,987		)	(2,973		)
Amortization of investment tax credits	(1,201		)	(5,252		)	(160		)	(111		)	(900		)	(3,476		)
Flow-through / permanent differences	(4,062		)	2,460			431			(4,539		)	530			618
Non-taxable dividend income	—			(44,658		)	—			—			—			—
Provision for uncertain tax positions (b)	(3,978		)	(15,377		)	756			525			(3,365		)	(17,313		)
Other - net	634			1,396			223			138			242			113
Total income taxes as reported		$40,541			$178,671			$61,872			$25,190			$37,250			$53,077
Effective Income Tax Rate	35.3		%	28.6		%	40.0		%	35.9		%	34.9		%	32.3		%

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2014	Entergy Arkansas			Entergy Louisiana			Entergy Mississippi			Entergy New Orleans			Entergy Texas			System Energy
	(In Thousands)
Net income		$121,392			$446,022			$74,821			$31,030			$74,804			$96,334
Income taxes	83,629			185,052			55,710			13,450			49,644			83,310
Pretax income		$205,021			$631,074			$130,531			$44,480			$124,448			$179,644
Computed at statutory rate (35%)		$71,757			$220,876			$45,686			$15,568			$43,557			$62,875
Increases (reductions) in tax resulting from:
State income taxes net of federal income tax effect	9,591			11,666			5,180			1,562			3,221			6,877
Regulatory differences - utility plant items	8,653			7,487			4,448			777			4,165			13,791
Equity component of AFUDC	(2,533		)	(14,612		)	(833		)	(320		)	(1,035		)	(1,774		)
Amortization of investment tax credits	(1,251		)	(5,594		)	(260		)	(218		)	(1,412		)	(3,476		)
Flow-through / permanent differences	(5,082		)	(225		)	555			(4,458		)	393			(327		)
Non-taxable dividend income	—			(41,255		)	—			—			—			—
Provision for uncertain tax positions	1,881			5,336			718			405			522			5,235
Other - net	613			1,373			216			134			233			109
Total income taxes as reported		$83,629			$185,052			$55,710			$13,450			$49,644			$83,310
Effective Income Tax Rate	40.8		%	29.3		%	42.7		%	30.2		%	39.9		%	46.4		%


(a)	See “Income Tax Audits - 2010-2011 IRS Audit” below for discussion of the most significant items for Entergy Louisiana.


(b)	See “Income Tax Audits - 2008-2009 IRS Audit” below for discussion of the most significant items for Entergy Louisiana and System Energy.

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Significant components of accumulated deferred income taxes and taxes accrued for Entergy Corporation and Subsidiaries as of December 31, 2016 and 2015 are as follows:



	2016			2015
	(In Thousands)
Deferred tax liabilities:
Plant basis differences - net		($6,362,905	)		($6,804,225	)
Regulatory assets	(584,572		)	(646,392		)
Nuclear decommissioning trusts/receivables	(1,739,977		)	(1,254,463		)
Pension, net funding	(429,896		)	(365,111		)
Combined unitary state taxes	(33,063		)	(45,078		)
Power purchase agreements	(993		)	—
Other	(251,719		)	(315,844		)
Total	(9,403,125		)	(9,431,113		)
Deferred tax assets:
Nuclear decommissioning liabilities	1,399,468			828,983
Regulatory liabilities	255,272			284,432
Pension and other post-employment benefits	539,456			525,524
Sale and leaseback	135,866			139,720
Compensation	99,300			69,432
Accumulated deferred investment tax credit	92,375			95,248
Provision for allowances and contingencies	188,390			188,282
Power purchase agreements	—			38,401
Net operating loss carryforwards	334,025			360,188
Capital losses and miscellaneous tax credits	18,470			11,075
Valuation allowance	(104,277		)	(91,532		)
Other	59,079			68,204
Total	3,017,424			2,517,957
Non-current accrued taxes (including unrecognized tax benefits)	(991,704		)	(1,338,806		)
Accumulated deferred income taxes and taxes accrued		($7,377,405	)		($8,251,962	)

Entergy’s estimated tax attributes carryovers and their expiration dates as of December 31, 2016 are as follows:



Carryover Description	Carryover Amount	Year(s) of expiration

Federal net operating losses	$6.7 billion	2023-2036
State net operating losses	$7.8 billion	2017-2036
Miscellaneous federal and state credits	$89.9 million	2017-2036

As a result of the accounting for uncertain tax positions, the amount of the deferred tax assets reflected in the financial statements is less than the amount of the tax effect of the federal and state net operating loss carryovers, tax credit carryovers, and other tax attributes reflected on income tax returns. Because it is more likely than not that the benefit from certain state net operating loss carryovers will not be utilized, valuation allowances of $62 million as of December 31, 2016 and $46 million as of December 31, 2015 have been provided on the deferred tax assets relating to these state net operating loss carryovers. Additionally, valuation allowances totaling $42.3 million as of December 31, 2016 and $45.5 million as of December 31, 2015 have been provided on deferred tax assets related to federal and

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state jurisdictions in which Entergy does not currently expect to be able to utilize separate company tax return losses, preventing realization of such deferred tax assets.

Significant components of accumulated deferred income taxes and taxes accrued for the Registrant Subsidiaries as of December 31, 2016 and 2015 are as follows:



2016	Entergy Arkansas			Entergy Louisiana			Entergy Mississippi			Entergy New Orleans			Entergy Texas			System Energy
	(In Thousands)
Deferred tax liabilities:
Plant basis differences - net		($1,857,554	)		($2,357,599	)		($820,971	)		($177,242	)		($835,671	)		($651,394	)
Regulatory assets	(109,241		)	(219,750		)	(25,309		)	(36,301		)	(153,914		)	(39,879		)
Nuclear decommissioning trusts/receivables	(144,250		)	(119,544		)	—			—			—			(83,891		)
Pension, net funding	(123,889		)	(122,465		)	(34,284		)	(16,307		)	(28,371		)	(29,357		)
Deferred fuel	(14,774		)	(1,778		)	(12,770		)	(5,229		)	(2,808		)	(1,137		)
Other	(47,785		)	(22,136		)	(12,474		)	(18,536		)	(8,812		)	(2,051		)
Total	(2,297,493		)	(2,843,272		)	(905,808		)	(253,615		)	(1,029,576		)	(807,709		)
Deferred tax assets:
Regulatory liabilities	5,768			175,973			18,833			25,240			15,814			13,644
Nuclear decommissioning liabilities	124,206			55,408			—			—			—			53,113
Pension and other post-employment benefits	(24,467		)	145,401			(8,042		)	(12,070		)	(19,096		)	(1,182		)
Sale and leaseback	—			33,383			—			—			—			102,483
Accumulated deferred investment tax credit	13,848			54,509			3,315			239			4,527			15,936
Provision for allowances and contingencies	(1,497		)	124,309			21,817			36,466			5,904			—
Power purchase agreements	(3,094		)	29,827			1,905			—			140			—
Unbilled/deferred revenues	6,799			(35,006		)	5,085			3,751			11,902			—
Compensation	2,787			5,309			1,492			685			1,587			360
Net operating loss carryforwards	69,524			17,125			—			—			—			—
Capital losses and miscellaneous tax credits	2,074			—			4,487			—			—			—
Other	174			17,110			1,152			496			2,955			—
Total	196,122			623,348			50,044			54,807			23,733			184,354
Non-current accrued taxes (including unrecognized tax benefits)	(85,252		)	(471,194		)	(5,567		)	(136,145		)	(21,804		)	(489,510		)
Accumulated deferred income taxes and taxes accrued		($2,186,623	)		($2,691,118	)		($861,331	)		($334,953	)		($1,027,647	)		($1,112,865	)

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Notes to Financial Statements



2015	Entergy Arkansas			Entergy Louisiana			Entergy Mississippi			Entergy New Orleans			Entergy Texas			System Energy
	(In Thousands)
Deferred tax liabilities:
Plant basis differences - net		($1,710,444	)		($2,041,968	)		($781,427	)		($167,294	)		($778,270	)		($611,745	)
Regulatory assets	(108,422		)	(254,316		)	(24,918		)	(39,451		)	(172,117		)	(46,990		)
Nuclear decommissioning trusts	(121,326		)	(99,980		)	—			—			—			(68,370		)
Pension, net funding	(107,073		)	(109,709		)	(30,901		)	(14,459		)	(28,001		)	(25,791		)
Deferred fuel	(7,647		)	(2,513		)	(684		)	(175		)	2,050			(18		)
Power purchase agreements	—			—			—			—			—			—
Other	(38,683		)	(86,275		)	(5,625		)	(12,253		)	(10,109		)	(22,478		)
Total	(2,093,595		)	(2,594,761		)	(843,555		)	(233,632		)	(986,447		)	(775,392		)
Deferred tax assets:
Regulatory liabilities	18,369			215,154			7,787			20,888			7,307			14,927
Nuclear decommissioning liabilities	109,962			49,333			—			—			—			39,420
Pension and other post-employment benefits	(20,420		)	149,680			(6,628		)	(8,939		)	(16,703		)	(1,037		)
Sale and leaseback	—			37,236			—			—			—			102,484
Accumulated deferred investment tax credit	14,320			56,635			1,777			290			4,842			17,385
Provision for allowances and contingencies	1,024			123,007			18,735			33,843			7,266			134
Power purchase agreements	(1,279		)	13,840			1,901			13			575			—
Unbilled/deferred revenues	9,815			(32,365		)	7,154			2,126			10,851			—
Compensation	1,842			4,182			601			880			4,496			—
Net operating loss carryforwards	—			90,241			—			—			—			—
Other	128			21,982			1,995			316			1,672			—
Total	133,761			728,925			33,322			49,417			20,306			173,313
Non-current accrued taxes (including unrecognized tax benefits)	(22,978		)	(641,120		)	(402		)	(29,846		)	(40,693		)	(416,996		)
Accumulated deferred income taxes and taxes accrued		($1,982,812	)		($2,506,956	)		($810,635	)		($214,061	)		($1,006,834	)		($1,019,075	)

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Notes to Financial Statements

The Registrant Subsidiaries’ estimated tax attributes carryovers and their expiration dates as of December 31, 2016 are as follows:

Entergy Arkansas

Entergy Louisiana

Entergy Mississippi

Entergy New Orleans

Entergy Texas

System Energy

Federal net operating losses

$184 million

$4.4 billion

—

$34 million

—

$201 million

Year(s) of expiration

2028-2036

2036

N/A

2028-2036

N/A

2028-2036

State net operating losses

$80 million

$4.8 billion

—

$285 million

—

$175 million

Year(s) of expiration

2021

2029-2036

N/A

2032-2035

N/A

2035

Misc. federal credits

$2 million

—

$3 million

—

$2 million

Year(s) of expiration

2029-2036

N/A

2029-2036

N/A

2029-2036

State credits

—

$4.5 million

—

$3.4 million

$8.4 million

Year(s) of expiration

N/A

2018-2020

N/A

2026

2017-2020

Unrecognized tax benefits

Accounting standards establish a “more-likely-than-not” recognition threshold that must be met before a tax benefit can be recognized in the financial statements. If a tax deduction is taken on a tax return, but does not meet the more-likely-than-not recognition threshold, an increase in income tax liability, above what is payable on the tax return, is required to be recorded. A reconciliation of Entergy’s beginning and ending amount of unrecognized tax benefits is as follows:



	2016			2015			2014
	(In Thousands)
Gross balance at January 1		$2,611,585			$4,736,785			$4,593,224
Additions based on tax positions related to the current year	1,532,782			1,850,705			348,543
Additions for tax positions of prior years	368,404			59,815			11,637
Reductions for tax positions of prior years (a)	(265,653		)	(3,966,535		)	(213,401		)
Settlements	(337,263		)	(68,227		)	—
Lapse of statute of limitations	—			(958		)	(3,218		)
Gross balance at December 31	3,909,855			2,611,585			4,736,785
Offsets to gross unrecognized tax benefits:
Carryovers and refund claims	(2,922,085		)	(1,264,483		)	(4,295,643		)
Cash paid to taxing authorities	(10,000		)	—			—
Unrecognized tax benefits net of unused tax attributes, refund claims and payments (b)		$977,770			$1,347,102			$441,142


(a)	The primary reduction for 2015 is related to the nuclear decommissioning costs treatment discussed in “Income Tax Audits - 2008-2009 IRS Audit” below.


(b)	Potential tax liability above what is payable on tax returns

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The balances of unrecognized tax benefits include $1,240 million, $955 million, and $516 million as of December 31, 2016, 2015, and 2014, respectively, which, if recognized, would lower the effective income tax rates. Because of the effect of deferred tax accounting, the remaining balances of unrecognized tax benefits of $2,670 million, $1,657 million, and $4,221 million as of December 31, 2016, 2015, and 2014, respectively, if disallowed, would not affect the annual effective income tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.

Entergy accrues interest expense, if any, related to unrecognized tax benefits in income tax expense. Entergy’s December 31, 2016, 2015, and 2014 accrued balance for the possible payment of interest is approximately $30 million, $27 million, and $127 million, respectively.

A reconciliation of the Registrant Subsidiaries’ beginning and ending amount of unrecognized tax benefits for 2016, 2015, and 2014 is as follows:



2016	Entergy Arkansas			Entergy Louisiana			Entergy Mississippi			Entergy New Orleans			Entergy Texas			System Energy
	(In Thousands)
Gross balance at January 1, 2016		$25,445			$1,690,661			$19,482			$53,897			$13,462			$478,318
Additions based on tax positions related to the current year (a)	16,868			931,720			2,662			33,912			2,002			5,318
Additions for tax positions of prior years	2,463			157,586			336			129,784			2,888			601
Reductions for tax positions of prior years	(41,957		)	(144,068		)	(10,219		)	(29,821		)	(1,849		)	(10,266		)
Settlements	(316		)	(195,560		)	(55		)	(21,542		)	(557		)	(1,599		)
Gross balance at December 31, 2016	2,503			2,440,339			12,206			166,230			15,946			472,372
Offsets to gross unrecognized tax benefits:
Loss carryovers	—			(1,783,093		)	(2,373		)	(27,320		)	(376		)	(90,028		)
Unrecognized tax benefits net of unused tax attributes and payments		$2,503			$657,246			$9,833			$138,910			$15,570			$382,344



2015	Entergy Arkansas			Entergy Louisiana			Entergy Mississippi			Entergy New Orleans			Entergy Texas			System Energy
	(In Thousands)
Gross balance at January 1, 2015		$362,912			$1,205,929			$20,144			$53,763			$17,264			$258,242
Additions based on tax positions related to the current year (b)	2,196			1,367,058			566			472			657			472,304
Additions for tax positions of prior years	1,057			7,992			8,140			48			2,914			913
Reductions for tax positions of prior years	(340,720		)	(859,430		)	—			(386		)	(3,981		)	(253,141		)
Settlements	—			(30,888		)	(9,368		)	—			(3,392		)	—
Gross balance at December 31, 2015	25,445			1,690,661			19,482			53,897			13,462			478,318
Offsets to gross unrecognized tax benefits:
Loss carryovers	(3,613		)	(893,764		)	(1,016		)	(506		)	(276		)	(133,611		)
Unrecognized tax benefits net of unused tax attributes and payments		$21,832			$796,897			$18,466			$53,391			$13,186			$344,707

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2014	Entergy Arkansas			Entergy Louisiana			Entergy Mississippi			Entergy New Orleans			Entergy Texas			System Energy
	(In Thousands)
Gross balance at January 1, 2014		$347,713			$1,076,680			$16,186			$51,679			$13,017			$265,185
Additions based on tax positions related to the current year	14,511			151,249			3,928			2,235			4,225			2,744
Additions for tax positions of prior years	1,767			6,924			319			37			303			566
Reductions for tax positions of prior years	(1,079		)	(28,924		)	(289		)	(188		)	(267		)	(10,253		)
Settlements	—			—			—			—			(14		)	—
Gross balance at December 31, 2014	362,912			1,205,929			20,144			53,763			17,264			258,242
Offsets to gross unrecognized tax benefits:
Loss carryovers	(361,043		)	(739,988		)	(6,992		)	(20,735		)	(241		)	(163,124		)
Unrecognized tax benefits net of unused tax attributes and payments		$1,869			$465,941			$13,152			$33,028			$17,023			$95,118


(a)	The primary addition for Entergy Louisiana is related to the mark-to market treatment discussed in “Other Tax Matters” below.


(b)	The primary addition for Entergy Louisiana and System Energy is related to the nuclear decommissioning costs treatment discussed in “Other Tax Matters” below.

The Registrant Subsidiaries’ balances of unrecognized tax benefits included amounts which, if recognized, would have reduced income tax expense as follows:



	December 31,
	2016		2015		2014
	(In Millions)
Entergy Arkansas		$3.6		$4.5		$2.6
Entergy Louisiana		$473.3		$692.7		$267.3
Entergy Mississippi		$—		$8.1		$3.9
Entergy New Orleans		$33.6		$50.7		$50.7
Entergy Texas		$7.0		$5.2		$10.5
System Energy		$—		$0.7		$3.7

The Registrant Subsidiaries accrue interest and penalties related to unrecognized tax benefits in income tax expense. Penalties have not been accrued. Accrued balances for the possible payment of interest are as follows:



	December 31,
	2016		2015		2014
	(In Millions)
Entergy Arkansas		$1.4		$1.3		$17.0
Entergy Louisiana		$8.4		$9.3		$22.2
Entergy Mississippi		$0.8		$0.4		$2.8
Entergy New Orleans		$1.5		$1.8		$1.3
Entergy Texas		$1.2		$1.2		$1.0
System Energy		$3.7		$0.7		$23.8

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Income Tax Audits

Entergy and its subsidiaries file U.S. federal and various state and foreign income tax returns. IRS examinations are complete for years before 2012. All state taxing authorities’ examinations are completed for years before 2009.

2006-2007 IRS Audit

In the first quarter 2015, the IRS finalized tax and interest computations from the 2006-2007 audit that resulted in a reversal of Entergy’s provision for uncertain tax positions related to accrued interest of approximately $20 million, including decreases of approximately $4 million for Entergy Arkansas, $11 million for Entergy Louisiana, and $1 million for System Energy.

2008-2009 IRS Audit

In the fourth quarter 2009, Entergy filed Applications for Change in Accounting Method (the “2009 CAM”) for tax purposes with the IRS for certain costs under Section 263A of the Internal Revenue Code. In the Applications, Entergy proposed to treat the nuclear decommissioning liability associated with the operation of its nuclear power plants as a production cost properly includable in cost of goods sold. The effect of the 2009 CAM was a $5.7 billion reduction in 2009 taxable income. The 2009 CAM was adjusted to $9.3 billion in 2012.

In the fourth quarter 2012 the IRS disallowed the reduction to 2009 taxable income related to the 2009 CAM. In the third quarter 2013, the Internal Revenue Service issued its RAR for the tax years 2008-2009. As a result of the issuance of this RAR, Entergy and the IRS resolved all of the 2008-2009 issues described above except for the 2009 CAM. Entergy disagreed with the IRS’s disallowance of the 2009 CAM and filed a protest with the IRS Appeals Division in October 2013.

In August 2015, Entergy and the IRS agreed on the treatment of the 2009 position regarding nuclear decommissioning liabilities from the 2008-2009 audit. The agreement provides that Entergy is entitled to deduct approximately $118 million of the $9.3 billion claimed in 2009. The agreement effectively settled all matters pertaining to the 2009 tax year and increased Entergy’s 2009 federal income tax liability by $2.4 million.

2010-2011 IRS Audit

The IRS completed its examination of the 2010 and 2011 tax years and issued its 2010-2011 Revenue Agent Report (RAR) in June 2016. Entergy agreed to all proposed adjustments contained in the RAR. As a result of the issuance of the RAR, Entergy Louisiana was able to recognize previously unrecognized tax benefits as follows:

•

Entergy and the IRS agreed that $148.6 million of the proceeds received by Entergy Louisiana in 2010 from the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, for the financing of Hurricane Gustav and Hurricane Ike storm costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Louisiana Act 55) were not taxable. Because the treatment of the financing is settled, Entergy recognized previously unrecognized tax benefits totaling $63.5 million, of which Entergy Louisiana recorded $61.6 million. Entergy Louisiana also accrued a regulatory liability of $16.1 million ($9.9 million net-of-tax) in accordance with the terms of Entergy Louisiana’s previous settlement agreement approved by the LPSC regarding Entergy Louisiana’s obligation to pay to customers savings associated with the Act 55 financing.


•	Entergy and the IRS agreed upon the tax treatment of Entergy Louisiana’s regulatory liability related to the Vidalia purchased power agreement. As a result, Entergy Louisiana recognized a previously unrecognized tax benefit of $74.5 million.

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Other Tax Matters

Entergy regularly negotiates with the IRS to achieve settlements. The resolution of audit issues could result in significant changes to the amounts of unrecognized tax benefits in the next twelve months.

In October 2015 two of Entergy’s Louisiana utilities, Entergy Gulf States Louisiana and Entergy Louisiana, combined their businesses into a legal entity which is identified as Entergy Louisiana herein. The structure of the business combination generated both a permanent difference and a temporary difference under FASB ASC Topic 740. The permanent difference resulted from recognition of the Waterford 3 and River Bend decommissioning liabilities as part of the business combination. Recognition of such decommissioning liabilities required Entergy to also recognize a taxable gain. The taxable gain resulted in a temporary difference because the gain provided for an increase in tax basis. Entergy Louisiana maintained a carryover tax basis in the assets received; and, to the extent that the increase in tax basis will provide additional tax depreciation, Entergy recorded a deferred tax asset. Entergy Louisiana obtained the corresponding deferred tax asset in the business combination. The permanent tax benefit net of ancillary tax charges was approximately $334 million. Consistent with the terms of the stipulated settlement in the business combination proceeding, electric customers of Entergy Louisiana will realize customer credits associated with the business combination. Accordingly, in October 2015, Entergy recorded a regulatory liability of $107 million ($66 million net-of-tax) which partially offsets the effect of the aforementioned deferred tax asset. The deferred tax asset and the regulatory liability, net-of-tax, increased Entergy Louisiana’s member’s equity by $268 million. See Note 2 to the financial statements for further discussion of the business combination.

In the fourth quarter 2015, System Energy and Entergy Louisiana adopted a new method of accounting for income tax return purposes in which the companies’ nuclear decommissioning costs will be treated as production costs of electricity includable in cost of goods sold. The new method results in a reduction of taxable income of $1.2 billion for System Energy and $2.2 billion for Entergy Louisiana.

The Protecting Americans from Tax Hikes Act of 2015 was enacted in December 2015. The most significant provisions affecting Entergy and the Registrant Subsidiaries were a five-year extension of bonus depreciation and permanent extension of the research and experimentation tax credit. The effect of the bonus depreciation extension on 2015 increased Entergy’s tax net operating loss.

Entergy made a tax election to treat its subsidiary that owns one of the Entergy Wholesale Commodities nuclear power plants as a corporation for federal income tax purposes in the second quarter 2016. This resulted in a constructive contribution of all the assets and liabilities associated with the plant to a new subsidiary corporation for federal income tax purposes, and generated both permanent and temporary differences under the income tax accounting standards. The constructive contribution required Entergy to recognize the plant’s nuclear decommissioning liability for income tax purposes resulting in permanent differences. The accrual of the nuclear decommissioning liability required Entergy to recognize a gain for income tax purposes, a significant portion of which resulted in an increase in tax basis of the assets constructively contributed to the subsidiary. Recognition of the gain and the increase in tax basis of the assets represents a temporary difference. The permanent difference reduced income tax expense, net of unrecognized tax benefits, by $238 million.

In 2016, Entergy Louisiana elected mark-to-market income tax treatment for various wholesale electric power purchase and sale agreements, including Entergy Louisiana’s contract to purchase electricity from the Vidalia hydroelectric facility and from System Energy under the Unit Power Sales Agreement. The election resulted in a $2.2 billion deductible temporary difference.

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NOTE 4. REVOLVING CREDIT FACILITIES, LINES OF CREDIT, AND SHORT-TERM BORROWINGS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Entergy Corporation’s credit facility requires Entergy to maintain a consolidated debt ratio, as defined, of 65% or less of its total capitalization. Entergy is in compliance with this covenant. If Entergy fails to meet this ratio, or if Entergy Corporation or one of the Utility operating companies (except Entergy New Orleans) defaults on other indebtedness or is in bankruptcy or insolvency proceedings, an acceleration of the facility maturity date may occur.

Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, 2016 as follows:



Company	Expiration Date	Amount of Facility	Interest Rate (a)	Amount Drawn as of December 31, 2016	Letters of Credit Outstanding as of December 31, 2016
Entergy Arkansas	April 2017	$20 million (b)	2.02%	—	—
Entergy Arkansas	August 2021	$150 million (c)	2.02%	—	—
Entergy Louisiana	August 2021	$350 million (d)	2.02%	—	$6.4 million
Entergy Mississippi	May 2017	$10 million (e)	2.27%	—	—
Entergy Mississippi	May 2017	$20 million (e)	2.27%	—	—
Entergy Mississippi	May 2017	$35 million (e)	2.27%	—	—
Entergy Mississippi	May 2017	$37.5 million (e)	2.27%	—	—
Entergy New Orleans	November 2018	$25 million (f)	2.52%	—	$0.8 million
Entergy Texas	August 2021	$150 million (g)	2.27%	—	$4.7 million


(a)	The interest rate is the rate as of December 31, 2016 that would most likely be applied to outstanding borrowings under the facility.


(b)	Borrowings under this Entergy Arkansas credit facility may be secured by a security interest in its accounts receivable at Entergy Arkansas’s option.


(c)	The credit facility allows Entergy Arkansas to issue letters of credit against 50% of the borrowing capacity of the facility.


(d)	The credit facility allows Entergy Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility.

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(e)	Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts receivable at Entergy Mississippi’s option.


(f)	The credit facility allows Entergy New Orleans to issue letters of credit against $10 million of the borrowing capacity of the facility.


(g)	The credit facility allows Entergy Texas to issue letters of credit against 50% of the borrowing capacity of the facility.

The commitment fees on the credit facilities range from 0.075% to 0.275% of the undrawn commitment amount. Each of the credit facilities requires the Registrant Subsidiary borrower to maintain a debt ratio, as defined, of 65% or less of its total capitalization. Each Registrant Subsidiary is in compliance with this covenant.



Company	Amount of Uncommitted Facility	Letter of Credit Fee	Letters of Credit Issued as of December 31, 2016 (a)
Entergy Arkansas	$25 million	0.70%	$1.0 million
Entergy Louisiana	$125 million	0.70%	$5.7 million
Entergy Mississippi	$40 million	0.70%	$7.1 million
Entergy New Orleans	$15 million	1.00%	$6.2 million
Entergy Texas	$50 million	0.70%	$14.7 million


(a)	As of December 31, 2016, letters of credit posted with MISO covered financial transmission right exposure of $0.3 million for Entergy Arkansas and $0.1 million for Entergy Mississippi. See Note 15 to the financial statements for discussion of financial transmission rights.

The short-term borrowings of the Registrant Subsidiaries are limited to amounts authorized by the FERC. The current FERC-authorized limits are effective through October 31, 2017. In addition to borrowings from commercial banks, these companies may also borrow from the Entergy System money pool. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ dependence on external short-term borrowings. Borrowings from the money pool and external short-term borrowings combined may not exceed the FERC-authorized limits. The following are the FERC-authorized limits for short-term borrowings and the outstanding short-term borrowings as of December 31, 2016 (aggregating both money pool and external short-term borrowings) for the Registrant Subsidiaries:



	Authorized	Borrowings
	(In Millions)
Entergy Arkansas	$250	$51.2
Entergy Louisiana	$450	—
Entergy Mississippi	$175	—
Entergy New Orleans	$100	—
Entergy Texas	$200	—
System Energy	$200	—

Entergy Nuclear Vermont Yankee Credit Facilities

Entergy Nuclear Vermont Yankee has a credit facility guaranteed by Entergy Corporation with a borrowing capacity of $100 million which expires in January 2018. Entergy Nuclear Vermont Yankee does not have the ability

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to issue letters of credit against the credit facility. This facility provides working capital to Entergy Nuclear Vermont Yankee for general business purposes including, without limitation, the decommissioning of Vermont Yankee. The commitment fee is currently 0.20% of the undrawn commitment amount. As of December 31, 2016, $45 million in cash borrowings were outstanding under the credit facility. The weighted average interest rate for the year ended December 31, 2016 was 2.17% on the drawn portion of the facility.

Entergy Nuclear Vermont Yankee also has an uncommitted credit facility guaranteed by Entergy Corporation

with a borrowing capacity of $85 million which expires in January 2018. Entergy Nuclear Vermont Yankee does not have the ability to issue letters of credit against the credit facility. This facility provides an additional funding source to Entergy Nuclear Vermont Yankee for general business purposes including, without limitation, the decommissioning of Vermont Yankee. As of December 31, 2016, there were no cash borrowings outstanding under the credit facility. The rate as of December 31, 2016 that would most likely apply to outstanding borrowings under the facility was 2.27% on the drawn portion of the facility.

Variable Interest Entities (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)

See Note 17 to the financial statements for a discussion of the consolidation of the nuclear fuel company variable interest entities (VIE). To finance the acquisition and ownership of nuclear fuel, the nuclear fuel company VIEs have credit facilities and three of the four VIEs also issue commercial paper, details of which follow as of December 31, 2016:



Company	Expiration Date	Amount of Facility	Weighted Average Interest Rate on Borrowings (a)	Amount Outstanding as of December 31, 2016
	(Dollars in Millions)
Entergy Arkansas VIE	May 2019	$80	n/a		$—
Entergy Louisiana River Bend VIE	May 2019	$105	n/a		$—
Entergy Louisiana Waterford VIE	May 2019	$85	2.15%		$3.8	(b)
System Energy VIE	May 2019	$120	2.20%		$66.9	(b)


(a)	Includes letter of credit fees and bank fronting fees on commercial paper issuances by the nuclear fuel company

variable interest entities for Entergy Arkansas, Entergy Louisiana, and System Energy. The nuclear fuel company variable interest entity for Entergy Louisiana River Bend does not issue commercial paper, but borrows directly on its bank credit facility.

(b) Commercial paper, classified as a current liability.

The commitment fees on the credit facilities are currently 0.10% of the undrawn commitment amount for the Entergy Arkansas, Entergy Louisiana, and System Energy VIEs. Each credit facility requires the respective lessee of nuclear fuel (Entergy Arkansas, Entergy Louisiana, or Entergy Corporation as guarantor for System Energy) to maintain a consolidated debt ratio, as defined, of 70% or less of its total capitalization.

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The nuclear fuel company variable interest entities had notes payable that are included in debt on the respective balance sheets as of December 31, 2016 as follows:



Company	Description	Amount
Entergy Arkansas VIE	2.62% Series K due December 2017		$60	million
Entergy Arkansas VIE	3.65% Series L due July 2021		$90	million
Entergy Arkansas VIE	3.17% Series M due December 2023		$40	million
Entergy Louisiana River Bend VIE	3.25% Series Q due July 2017		$75	million
Entergy Louisiana River Bend VIE	3.38% Series R due August 2020		$70	million
Entergy Louisiana Waterford VIE	3.25% Series G due July 2017		$25	million
Entergy Louisiana Waterford VIE	3.92% Series H due February 2021		$40	million
Entergy Louisiana Waterford VIE	3.22% Series I due December 2023		$20	million
System Energy VIE	4.02% Series H due February 2017		$50	million
System Energy VIE	3.78% Series I due October 2018		$85	million

In February 2017 the System Energy nuclear fuel company variable interest entity redeemed, at maturity, its $50 million of 4.02% Series H notes.

In accordance with regulatory treatment, interest on the nuclear fuel company variable interest entities’ credit facilities, commercial paper, and long-term notes payable is reported in fuel expense.

Entergy Arkansas, Entergy Louisiana, and System Energy each have obtained long-term financing authorizations from the FERC that extend through October 2017 for issuances by its nuclear fuel company variable interest entities.

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NOTE 5. LONG - TERM DEBT (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Long-term debt for Entergy Corporation and subsidiaries as of December 31, 2016 and 2015 consisted of:



Type of Debt and Maturity	Weighted Average Interest Rate December 31, 2016	Interest Rate Ranges at December 31,		Outstanding at December 31,
Type of Debt and Maturity	Weighted Average Interest Rate December 31, 2016	2016	2015	2016			2015
				(In Thousands)
Mortgage Bonds
2016-2021	4.92%	2.55%-7.125%	3.25%-7.125%		$2,350,000			$2,350,000
2022-2026	3.85%	2.40%-5.59%	3.05%-5.66%	3,965,000			3,308,276
2028-2041	3.06%	2.85%-3.25%	5.65%-6.38%	1,125,000			1,270,827
2044-2066	5.00%	4.70%-5.625%	4.70%-6.00%	2,960,000			1,860,000
Governmental Bonds (a)
2017-2021	2.22%	1.55%-2.375%	1.55%-2.375%	99,700			99,700
2022-2030	3.98%	3.375%-5.875%	4.90%-5.875%	332,680			384,680
Securitization Bonds
2018-2024	3.90%	2.04%-5.93%	2.04%-5.93%	669,310			784,340
Variable Interest Entities Notes Payable (Note 4)
2016-2023	3.47%	2.62%-4.02%	1.38%-4.02%	555,000			570,600
Entergy Corporation Notes
due January 2017	n/a	—	4.70%	—			500,000
due September 2020	n/a	5.125%	5.125%	450,000			450,000
due July 2022	n/a	4.00%	4.00%	650,000			650,000
due September 2026	n/a	2.95%	—	750,000			—
Note Payable to NYPA	—	—	(b)	—			34,259
5 Year Credit Facility (Note 4)	n/a	2.23%	1.98%	700,000			835,000
Long-term DOE Obligation (c)	—	—	—	181,853			181,378
Waterford 3 Lease Obligation (d)	n/a	8.09%	7.45%	57,492			108,965
Waterford Series Collateral Trust Mortgage Notes due 2017 (d)	n/a	(e)	—	42,703			—
Grand Gulf Lease Obligation (d)	n/a	5.13%	5.13%	34,359			34,361
Vermont Yankee Credit Facility (Note 4)	n/a	2.17%	2.08%	44,500			12,000
Unamortized Premium and Discount - Net				(19,397		)	(12,067		)
Unamortized Debt Issuance Costs				(128,849		)	(110,349		)
Other				13,204			13,960
Total Long-Term Debt				14,832,555			13,325,930
Less Amount Due Within One Year				364,900			214,374
Long-Term Debt Excluding Amount Due Within One Year					$14,467,655			$13,111,556
Fair Value of Long-Term Debt (f)					$14,815,535			$13,578,511

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(a)	Consists of pollution control revenue bonds and environmental revenue bonds, some of which are secured by collateral first mortgage bonds.


(b)	These notes do not have a stated interest rate, but have an implicit interest rate of 4.8%.

(c)

Pursuant to the Nuclear Waste Policy Act of 1982, Entergy’s nuclear owner/licensee subsidiaries have contracts with the DOE for spent nuclear fuel disposal service. The contracts include a one-time fee for generation prior to April 7, 1983. Entergy Arkansas is the only Entergy company that generated electric power with nuclear fuel prior to that date and includes the one-time fee, plus accrued interest, in long-term debt.


(d)	See Note 10 to the financial statements for further discussion of the Waterford 3 lease obligation and Entergy Louisiana’s acquisition of the equity participant’s beneficial interest in the Waterford 3 leased assets and for further discussion of the Grand Gulf lease obligation.


(e)	This note does not have a stated interest rate, but has an implicit interest rate of 7.458%.

(f)

The fair value excludes lease obligations of $57 million at Entergy Louisiana and $34 million at System Energy, and long-term DOE obligations of $182 million at Entergy Arkansas, and includes debt due within one year. Fair values are classified as Level 2 in the fair value hierarchy discussed in Note 15 to the financial statements and are based on prices derived from inputs such as benchmark yields and reported trades.

The annual long-term debt maturities (excluding lease obligations and long-term DOE obligations) for debt outstanding as of December 31, 2016, for the next five years are as follows:



	Amount
	(In Thousands)
2017		$307,403
2018		$828,084
2019		$724,899
2020		$795,000
2021		$1,674,548

In November 2000, Entergy’s non-utility nuclear business purchased the FitzPatrick and Indian Point 3 power plants in a seller-financed transaction. As part of the purchase agreement with NYPA, Entergy recorded a liability representing the net present value of the payments Entergy would be liable to NYPA for each year that the FitzPatrick and Indian Point 3 power plants would run beyond their respective original NRC license expiration date. In October 2015, Entergy announced a planned shutdown of FitzPatrick at the end of its fuel cycle. As a result of the announcement, Entergy reduced this liability by $26.4 million pursuant to the terms of the purchase agreement. In August 2016, Entergy entered into a trust transfer agreement with NYPA to transfer the decommissioning trust funds and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants to Entergy. As part of the trust transfer agreement, the original decommissioning agreements were amended, and the Entergy subsidiaries’ obligation to make additional license extension payments to NYPA was eliminated. In the third quarter 2016, Entergy removed the note payable of $35.1 million from the consolidated balance sheet.

Entergy Louisiana, Entergy Mississippi, Entergy Texas, and System Energy have obtained long-term financing authorizations from the FERC that extend through October 2017. Entergy Arkansas has obtained long-term financing authorization from the APSC that extends through December 2018. Entergy New Orleans has obtained long-term financing authorization from the City Council that extends through June 2018.

Capital Funds Agreement

Pursuant to an agreement with certain creditors, Entergy Corporation has agreed to supply System Energy with sufficient capital to:


•	maintain System Energy’s equity capital at a minimum of 35% of its total capitalization (excluding short-term debt);

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•	permit the continued commercial operation of Grand Gulf;


•	pay in full all System Energy indebtedness for borrowed money when due; and


•	enable System Energy to make payments on specific System Energy debt, under a supplement to the agreement assigning System Energy’s rights in the agreement as security for the specific debt.

Long-term debt for the Registrant Subsidiaries as of December 31, 2016 and 2015 consisted of:



	2016			2015
	(In Thousands)
Entergy Arkansas
Mortgage Bonds:
3.75% Series due February 2021		$350,000			$350,000
3.05% Series due June 2023	250,000			250,000
3.7% Series due June 2024	375,000			375,000
5.66% Series due February 2025	—			175,000
3.5% Series due April 2026	380,000			—
5.9% Series due June 2033	—			100,000
6.38% Series due November 2034	—			60,000
5.75% Series due November 2040	—			225,000
4.95% Series due December 2044	250,000			250,000
4.9% Series due December 2052	200,000			200,000
4.75% Series due June 2063	125,000			125,000
4.875% Series due September 2066	410,000			—
Total mortgage bonds	2,340,000			2,110,000
Governmental Bonds (a):
1.55% Series due 2017, Jefferson County (d)	54,700			54,700
2.375% Series due 2021, Independence County (d)	45,000			45,000
Total governmental bonds	99,700			99,700
Variable Interest Entity Notes Payable (Note 4):
3.23% Series J due July 2016	—			55,000
2.62% Series K due December 2017	60,000			60,000
3.65% Series L due July 2021	90,000			90,000
3.17% Series M due December 2023	40,000			—
Total variable interest entity notes payable	190,000			205,000
Securitization Bonds:
2.30% Series Senior Secured due August 2021	49,548			62,966
Total securitization bonds	49,548			62,966
Other:
Long-term DOE Obligation (b)	181,853			181,378
Unamortized Premium and Discount – Net	984			(2,775		)
Unamortized Debt Issuance Costs	(34,357		)	(28,503		)
Other	2,057			2,073
Total Long-Term Debt	2,829,785			2,629,839
Less Amount Due Within One Year	114,700			55,000
Long-Term Debt Excluding Amount Due Within One Year		$2,715,085			$2,574,839
Fair Value of Long-Term Debt (c)		$2,623,910			$2,498,108

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	2016			2015
	(In Thousands)
Entergy Louisiana
Mortgage Bonds:
6.0% Series due May 2018		$375,000			$375,000
6.50% Series due September 2018	300,000			300,000
3.95% Series due October 2020	250,000			250,000
4.8% Series due May 2021	200,000			200,000
3.3% Series due December 2022	200,000			200,000
4.05% Series due September 2023	325,000			325,000
5.59% Series due October 2024	300,000			300,000
5.40% Series due November 2024	400,000			400,000
3.78% Series due April 2025	110,000			110,000
3.78% Series due April 2025	190,000			190,000
4.44% Series due January 2026	250,000			250,000
2.40% Series due October 2026	400,000			—
3.25% Series due April 2028	425,000			—
3.05% Series due June 2031	325,000			—
6.2% Series due July 2033	—			240,000
6.18% Series due March 2035	—			85,000
6.0% Series due March 2040	—			118,000
5.875% Series due June 2041	—			150,000
5.0% Series due July 2044	170,000			170,000
4.95% Series due January 2045	450,000			250,000
5.25% Series due July 2052	200,000			200,000
4.70% Series due June 2063	100,000			100,000
4.875% Series due September 2066	270,000			—
Total mortgage bonds	5,240,000			4,213,000
Governmental Bonds (a):
5.0% Series due 2028, Louisiana Public Facilities Authority (d)	—			83,680
5.0% Series due 2030, Louisiana Public Facilities Authority (d)	—			115,000
3.375 % Series due 2028, Louisiana Public Facilities Authority (d)	83,680			—
3.50% Series due 2030, Louisiana Public Facilities Authority (d)	115,000			—
Total governmental bonds	198,680			198,680
Variable Interest Entity Notes Payable (Note 4):
3.30% Series F due March 2016	—			20,000
3.25% Series G due July 2017	25,000			25,000
3.25% Series Q due July 2017	75,000			75,000
3.38% Series R due August 2020	70,000			70,000
3.92% Series H due February 2021	40,000			40,000
3.22% Series I due December 2023	20,000			—
Credit Facility due June 2016, weighted avg rate 1.38%	—			600
Total variable interest entity notes payable	230,000			230,600
Securitization Bonds:
2.04% Series Senior Secured due September 2023	100,972			122,568
Total securitization bonds	100,972			122,568
Other:
Waterford 3 Lease Obligation (Note 10) (e)	57,492			108,965
Waterford Series Collateral Trust Mortgage Notes due 2017 (Note 10) (f)	42,703			—
Unamortized Premium and Discount - Net	(14,917		)	(4,537		)
Unamortized Debt Issuance Costs	(48,972		)	(40,156		)
Other	6,833			7,042
Total Long-Term Debt	5,812,791			4,836,162
Less Amount Due Within One Year	200,198			29,372
Long-Term Debt Excluding Amount Due Within One Year		$5,612,593			$4,806,790
Fair Value of Long-Term Debt (c)		$5,929,488			$5,018,786

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	2016			2015
	(In Thousands)
Entergy Mississippi
Mortgage Bonds:
3.25% Series due June 2016		$—			$125,000
6.64% Series due July 2019	150,000			150,000
3.1% Series due July 2023	250,000			250,000
3.75% Series due July 2024	100,000			100,000
2.85% Series due June 2028	375,000			—
6.0% Series due November 2032	—			75,000
6.25% Series due April 2034	—			100,000
6.20% Series due April 2040	—			80,000
6.0% Series due May 2051	—			150,000
4.90% Series due October 2066	260,000			—
Total mortgage bonds	1,135,000			1,030,000
Governmental Bonds (a):
4.90% Series due 2022, Independence County (d)	—			30,000
Total governmental bonds	—			30,000
Other:
Unamortized Premium and Discount – Net	(766		)	(1,038		)
Unamortized Debt Issuance Costs	(13,318		)	(13,877		)
Total Long-Term Debt	1,120,916			1,045,085
Less Amount Due Within One Year	—			125,000
Long-Term Debt Excluding Amount Due Within One Year		$1,120,916			$920,085
Fair Value of Long-Term Debt (c)		$1,086,203			$1,087,326



	2016			2015
	(In Thousands)
Entergy New Orleans
Mortgage Bonds:
5.10% Series due December 2020		$25,000			$25,000
3.9% Series due July 2023	100,000			100,000
5.6% Series due September 2024	—			33,276
4.0% Series due June 2026	85,000			—
5.65% Series due September 2029	—			37,827
5.0% Series due December 2052	30,000			30,000
5.50% Series due April 2066	110,000			—
Total mortgage bonds	350,000			226,103
Securitization Bonds:
2.67% Series Senior Secured due June 2027	87,307			98,730
Total securitization bonds	87,307			98,730
Other:
Payable to Entergy Louisiana due November 2035	20,527			25,500
Unamortized Premium and Discount – Net	(245		)	(283		)
Unamortized Debt Issuance Costs	(8,595		)	(7,170		)
Total Long-Term Debt	448,994			342,880
Less Amount Due Within One Year	2,104			4,973
Long-Term Debt Excluding Amount Due Within One Year		$446,890			$337,907
Fair Value of Long-Term Debt (c)		$455,459			$351,040

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	2016			2015
	(In Thousands)
Entergy Texas
Mortgage Bonds:
7.125% Series due February 2019		$500,000			$500,000
2.55% Series due June 2021	125,000			—
4.1% Series due September 2021	75,000			75,000
5.15% Series due June 2045	250,000			250,000
5.625% Series due June 2064	135,000			135,000
Total mortgage bonds	1,085,000			960,000
Securitization Bonds:
5.79% Series Senior Secured, Series A due October 2018	23,584			49,614
3.65% Series Senior Secured, Series A due August 2019	74,899			117,462
5.93% Series Senior Secured, Series A due June 2022	114,400			114,400
4.38% Series Senior Secured, Series A due November 2023	218,600			218,600
Total securitization bonds	431,483			500,076
Other:
Unamortized Premium and Discount - Net	(1,579		)	(1,797		)
Unamortized Debt Issuance Costs	(10,809		)	(11,155		)
Other	4,312			4,843
Total Long-Term Debt	1,508,407			1,451,967
Less Amount Due Within One Year	—			—
Long-Term Debt Excluding Amount Due Within One Year		$1,508,407			$1,451,967
Fair Value of Long-Term Debt (c)		$1,600,156			$1,590,616



	2016			2015
	(In Thousands)
System Energy
Mortgage Bonds:
4.1% Series due April 2023		$250,000			$250,000
Total mortgage bonds	250,000			250,000
Governmental Bonds (a):
5.875% Series due 2022, Mississippi Business Finance Corp.	134,000			156,000
Total governmental bonds	134,000			156,000
Variable Interest Entity Notes Payable (Note 4):
4.02% Series H due February 2017	50,000			50,000
3.78% Series I due October 2018	85,000			85,000
Total variable interest entity notes payable	135,000			135,000
Other:
Grand Gulf Lease Obligation 5.13% (Note 10)	34,359			34,361
Unamortized Premium and Discount – Net	(503		)	(634		)
Unamortized Debt Issuance Costs	(1,727		)	(2,062		)
Other	3			2
Total Long-Term Debt	551,132			572,667
Less Amount Due Within One Year	50,003			2
Long-Term Debt Excluding Amount Due Within One Year		$501,129			$572,665
Fair Value of Long-Term Debt (c)		$529,520			$552,762

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(a)	Consists of pollution control revenue bonds and environmental revenue bonds.

(b)

(c)

The fair value excludes lease obligations of $57 million at Entergy Louisiana and $34 million at System Energy and long-term DOE obligations of $182 million at Entergy Arkansas, and includes debt due within one year. Fair values are classified as Level 2 in the fair value hierarchy discussed in Note 15 to the financial statements and are based on prices derived from inputs such as benchmark yields and reported trades.


(d)	The bonds are secured by a series of collateral mortgage bonds.


(e)	The interest rate as of December 31, 2016 was 8.09%. The interest rate as of December 31, 2015 was an overall implicit rate of 7.45% which included the equity portion of the lease obligation. See Note 10 to the financial statements for further discussion of Entergy Louisiana’s acquisition of the equity participant’s beneficial interest in the Waterford 3 leased assets in March 2016.


(f)	This note does not have a stated interest rate, but has an implicit interest rate of 7.458%.

The annual long-term debt maturities (excluding lease obligations and long-term DOE obligations) for debt outstanding as of December 31, 2016, for the next five years are as follows:



	Entergy Arkansas		Entergy Louisiana		Entergy Mississippi		Entergy New Orleans		Entergy Texas		System Energy
	(In Thousands)
2017		$114,700		$142,703		$—		$2,104		$—		$50,000
2018		$—		$675,000		$—		$2,077		$23,584		$85,000
2019		$—		$—		$150,000		$1,979		$574,899		$—
2020		$—		$320,000		$—		$26,838		$—		$—
2021		$534,548		$240,000		$—		$1,618		$200,000		$—

Entergy Arkansas Securitization Bonds

In June 2010 the APSC issued a financing order authorizing the issuance of bonds to recover Entergy Arkansas’s January 2009 ice storm damage restoration costs, including carrying costs of $11.5 million and $4.6 million of up-front financing costs. In August 2010, Entergy Arkansas Restoration Funding, LLC, a company wholly-owned and consolidated by Entergy Arkansas, issued $124.1 million of storm cost recovery bonds. The bonds have a coupon of 2.30%. Although the principal amount is not due until the date given in the tables above, Entergy Arkansas Restoration Funding expects to make principal payments on the bonds over the next four years in the amount of $13.8 million for 2017, $14.1 million for 2018, $14.4 million for 2019, and $7.3 million for 2020. With the proceeds, Entergy Arkansas Restoration Funding purchased from Entergy Arkansas the storm recovery property, which is the right to recover from customers through a storm recovery charge amounts sufficient to service the securitization bonds. The storm recovery property is reflected as a regulatory asset on the consolidated Entergy Arkansas balance sheet. The creditors of Entergy Arkansas do not have recourse to the assets or revenues of Entergy Arkansas Restoration Funding, including the storm recovery property, and the creditors of Entergy Arkansas Restoration Funding do not have recourse to the assets or revenues of Entergy Arkansas. Entergy Arkansas has no payment obligations to Entergy Arkansas Restoration Funding except to remit storm recovery charge collections.

Entergy Louisiana Securitization Bonds – Little Gypsy

In August 2011 the LPSC issued a financing order authorizing the issuance of bonds to recover Entergy Louisiana’s investment recovery costs associated with the canceled Little Gypsy repowering project. In September 2011, Entergy Louisiana Investment Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy Louisiana, issued $207.2 million of senior secured investment recovery bonds. The bonds have an interest

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rate of 2.04%. Although the principal amount is not due until the date given in the tables above, Entergy Louisiana Investment Recovery Funding expects to make principal payments on the bonds over the next five years in the amounts of $21.7 million for 2017, $22.3 million for 2018, $22.7 million for 2019, $23.2 million for 2020, and $11 million for 2021. With the proceeds, Entergy Louisiana Investment Recovery Funding purchased from Entergy Louisiana the investment recovery property, which is the right to recover from customers through an investment recovery charge amounts sufficient to service the bonds. In accordance with the financing order, Entergy Louisiana will apply the proceeds it received from the sale of the investment recovery property as a reimbursement for previously-incurred investment recovery costs. The investment recovery property is reflected as a regulatory asset on the consolidated Entergy Louisiana balance sheet. The creditors of Entergy Louisiana do not have recourse to the assets or revenues of Entergy Louisiana Investment Recovery Funding, including the investment recovery property, and the creditors of Entergy Louisiana Investment Recovery Funding do not have recourse to the assets or revenues of Entergy Louisiana. Entergy Louisiana has no payment obligations to Entergy Louisiana Investment Recovery Funding except to remit investment recovery charge collections.

Entergy New Orleans Securitization Bonds - Hurricane Isaac

In May 2015 the City Council issued a financing order authorizing the issuance of securitization bonds to recover Entergy New Orleans’s Hurricane Isaac storm restoration costs of $31.8 million, including carrying costs, the costs of funding and replenishing the storm recovery reserve in the amount of $63.9 million, and approximately $3 million of up-front financing costs associated with the securitization. In July 2015, Entergy New Orleans Storm Recovery Funding I, L.L.C., a company wholly owned and consolidated by Entergy New Orleans, issued $98.7 million of storm cost recovery bonds. The bonds have a coupon of 2.67%. Although the principal amount is not due until the date given in the tables above, Entergy New Orleans Storm Recovery Funding expects to make principal payments on the bonds over the next five years in the amounts of $10.6 million for 2017, $11 million for 2018, $11.2 million for 2019, $11.6 million for 2020, and $11.9 million for 2021.

With the proceeds, Entergy New Orleans Storm Recovery Funding purchased from Entergy New Orleans the storm recovery property, which is the right to recover from customers through a storm recovery charge amounts sufficient to service the securitization bonds. The storm recovery property is reflected as a regulatory asset on the consolidated Entergy New Orleans balance sheet. The creditors of Entergy New Orleans do not have recourse to the assets or revenues of Entergy New Orleans Storm Recovery Funding, including the storm recovery property, and the creditors of Entergy New Orleans Storm Recovery Funding do not have recourse to the assets or revenues of Entergy New Orleans. Entergy New Orleans has no payment obligations to Entergy New Orleans Storm Recovery Funding except to remit storm recovery charge collections.

Entergy Texas Securitization Bonds - Hurricane Rita

In April 2007 the PUCT issued a financing order authorizing the issuance of securitization bonds to recover $353 million of Entergy Texas’s Hurricane Rita reconstruction costs and up to $6 million of transaction costs, offset by $32 million of related deferred income tax benefits. In June 2007, Entergy Gulf States Reconstruction Funding I, LLC, a company that is now wholly-owned and consolidated by Entergy Texas, issued $329.5 million of senior secured transition bonds (securitization bonds) as follows:



	Amount
	(In Thousands)
Senior Secured Transition Bonds, Series A:
Tranche A-1 (5.51%) due October 2013		$93,500
Tranche A-2 (5.79%) due October 2018	121,600
Tranche A-3 (5.93%) due June 2022	114,400
Total senior secured transition bonds		$329,500

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Although the principal amount of each tranche is not due until the dates given above, Entergy Gulf States Reconstruction Funding expects to make principal payments on the bonds over the next five years in the amounts of $27.6 million for 2017, $29.2 million for 2018, $30.9 million for 2019, $32.8 million for 2020, and $17.5 million for 2021. Of the scheduled principal payments for 2017, $23.6 million are for Tranche A-2, and $4 million are for Tranche A-3. All of the scheduled principal payments for 2018-2021 are for Tranche A-3. Tranche A-1 has been paid.

With the proceeds, Entergy Gulf States Reconstruction Funding purchased from Entergy Texas the transition property, which is the right to recover from customers through a transition charge amounts sufficient to service the securitization bonds. The transition property is reflected as a regulatory asset on the consolidated Entergy Texas balance sheet. The creditors of Entergy Texas do not have recourse to the assets or revenues of Entergy Gulf States Reconstruction Funding, including the transition property, and the creditors of Entergy Gulf States Reconstruction Funding do not have recourse to the assets or revenues of Entergy Texas. Entergy Texas has no payment obligations to Entergy Gulf States Reconstruction Funding except to remit transition charge collections.

Entergy Texas Securitization Bonds - Hurricane Ike and Hurricane Gustav

In September 2009 the PUCT authorized the issuance of securitization bonds to recover $566.4 million of Entergy Texas’s Hurricane Ike and Hurricane Gustav restoration costs, plus carrying costs and transaction costs, offset by insurance proceeds. In November 2009, Entergy Texas Restoration Funding, LLC (Entergy Texas Restoration Funding), a company wholly-owned and consolidated by Entergy Texas, issued $545.9 million of senior secured transition bonds (securitization bonds), as follows:



	Amount
	(In Thousands)
Senior Secured Transition Bonds:
Tranche A-1 (2.12%) due February 2016		$182,500
Tranche A-2 (3.65%) due August 2019	144,800
Tranche A-3 (4.38%) due November 2023	218,600
Total senior secured transition bonds		$545,900

Although the principal amount of each tranche is not due until the dates given above, Entergy Texas Restoration Funding expects to make principal payments on the bonds over the next five years in the amount of $44.1 million for 2017, $45.8 million for 2018, $47.6 million for 2019, $49.8 million for 2020, and $52 million for 2021. All of the scheduled principal payments for 2017 are for Tranche A-2, $30.8 million of the scheduled principal payments for 2018 are for Tranche A-2 and $15 million are for Tranche A-3. All of the scheduled principle payments for 2019-2021 are for Tranche A-3. Tranche A-1 has been paid.

With the proceeds, Entergy Texas Restoration Funding purchased from Entergy Texas the transition property, which is the right to recover from customers through a transition charge amounts sufficient to service the securitization bonds. The transition property is reflected as a regulatory asset on the consolidated Entergy Texas balance sheet. The creditors of Entergy Texas do not have recourse to the assets or revenues of Entergy Texas Restoration Funding, including the transition property, and the creditors of Entergy Texas Restoration Funding do not have recourse to the assets or revenues of Entergy Texas. Entergy Texas has no payment obligations to Entergy Texas Restoration Funding except to remit transition charge collections.

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NOTE 6. PREFERRED EQUITY (Entergy Corporation, Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans)

The number of shares and units authorized and outstanding and dollar value of preferred stock, preferred membership interests, and non-controlling interest for Entergy Corporation subsidiaries as of December 31, 2016 and 2015 are presented below. All series of the Utility preferred stock are redeemable at the option of the related company.



	Shares/Units Authorized		Shares/Units Outstanding
	2016	2015	2016	2015	2016		2015
Entergy Corporation					(Dollars in Thousands)
Utility:
Preferred Stock or Preferred Membership Interests without sinking fund:
Entergy Arkansas, 4.32%-6.45% Series	313,500	3,413,500	313,500	3,413,500		$31,350		$116,350
Entergy Utility Holding Company, LLC, 7.5% Series (a)	110,000	110,000	110,000	110,000	107,425		107,425
Entergy Mississippi, 4.36%-6.25% Series	203,807	1,403,807	203,807	1,403,807	20,381		50,381
Entergy New Orleans, 4.36%-5.56% Series	197,798	197,798	197,798	197,798	19,780		19,780
Total Utility Preferred Stock or Preferred Membership Interests without sinking fund	825,105	5,125,105	825,105	5,125,105	178,936		293,936
Entergy Wholesale Commodities:
Preferred Stock without sinking fund:
Entergy Finance Holding, Inc. 8.75% (b)	250,000	250,000	250,000	250,000	24,249		24,249
Total Subsidiaries’ Preferred Stock without sinking fund	1,075,105	5,375,105	1,075,105	5,375,105		$203,185		$318,185

(a) Dollar amount outstanding is net of $2,575 thousand of preferred stock issuance costs.

(b) Dollar amount outstanding is net of $751 thousand of preferred stock issuance costs.

In October 2015, Entergy Utility Holding Company, LLC issued 110,000 shares of $1,000 par value 7.5% Series Preferred Membership Interests, all of which are outstanding as of December 31, 2016. The dividends are cumulative and payable quarterly. These units are redeemable on or after January 1, 2036, at Entergy Utility Holding Company, LLC’s option, at the fixed redemption price of $1,000 per share.

In December 2013, Entergy Finance Holding, Inc. issued 250,000 shares of $100 par value 8.75% Series Preferred Stock, all of which are outstanding as of December 31, 2016. The dividends are cumulative and payable quarterly. The preferred stock is redeemable on or after December 16, 2023, at Entergy Finance Holding, Inc.’s option, at the fixed redemption price of $100 per share.

The number of shares and units authorized and outstanding and dollar value of preferred stock for Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans as of December 31, 2016 and 2015 are presented below. All series of the Utility operating companies’ preferred stock are redeemable at the respective company’s option at the call prices presented. Dividends and distributions paid on all of Entergy’s preferred stock and membership interests series are eligible for the dividends received deduction.

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	Shares Authorized and Outstanding						Call Price per Share as of December 31,
	2016	2015	2016		2015		2016
Entergy Arkansas Preferred Stock			(Dollars in Thousands)
Without sinking fund:
Cumulative, $100 par value:
4.32% Series	70,000	70,000		$7,000		$7,000		$103.65
4.72% Series	93,500	93,500	9,350		9,350			$107.00
4.56% Series	75,000	75,000	7,500		7,500			$102.83
4.56% 1965 Series	75,000	75,000	7,500		7,500			$102.50
6.08% Series	—	100,000	—		10,000			$—
Cumulative, $25 par value:
6.45% Series	—	3,000,000	—		75,000			$—
Total without sinking fund	313,500	3,413,500		$31,350		$116,350



	Shares Authorized and Outstanding						Call Price per Share as of December 31,
	2016	2015	2016		2015		2016
Entergy Mississippi Preferred Stock			(Dollars in Thousands)
Without sinking fund:
Cumulative, $100 par value:
4.36% Series	59,920	59,920		$5,992		$5,992		$103.86
4.56% Series	43,887	43,887	4,389		4,389			$107.00
4.92% Series	100,000	100,000	10,000		10,000			$102.88
Cumulative, $25 par value
6.25% Series	—	1,200,000	—		30,000			$—
Total without sinking fund	203,807	1,403,807		$20,381		$50,381



	Shares Authorized and Outstanding						Call Price per Share as of December 31,
	2016	2015	2016		2015		2016
Entergy New Orleans Preferred Stock			(Dollars in Thousands)
Without sinking fund:
Cumulative, $100 par value:
4.36% Series	60,000	60,000		$6,000		$6,000		$104.58
4.75% Series	77,798	77,798	7,780		7,780			$105.00
5.56% Series	60,000	60,000	6,000		6,000			$102.59
Total without sinking fund	197,798	197,798		$19,780		$19,780

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NOTE 7. COMMON EQUITY (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Common Stock

Common stock and treasury stock shares activity for Entergy for 2016, 2015, and 2014 is as follows:



	2016			2015			2014
	Common Shares Issued	Treasury Shares		Common Shares Issued	Treasury Shares		Common Shares Issued	Treasury Shares
Beginning Balance, January 1	254,752,788	76,363,763		254,752,788	75,512,079		254,752,788	76,381,936
Repurchases	—	—		—	1,468,984		—	2,154,490
Issuances:
Employee Stock-Based Compensation Plans	—	(729,073	)	—	(610,409	)	—	(3,019,475	)
Directors’ Plan	—	(11,327	)	—	(6,891	)	—	(4,872	)
Ending Balance, December 31	254,752,788	75,623,363		254,752,788	76,363,763		254,752,788	75,512,079

Entergy Corporation reissues treasury shares to meet the requirements of the Stock Plan for Outside Directors (Directors’ Plan), three Equity Ownership Plans of Entergy Corporation and Subsidiaries, and certain other stock benefit plans. The Directors’ Plan awards to non-employee directors a portion of their compensation in the form of a fixed dollar value of shares of Entergy Corporation common stock.

In October 2010 the Board granted authority for a $500 million share repurchase program. As of December 31, 2016, $350 million of authority remains under the $500 million share repurchase program.

Dividends declared per common share were $3.42 in 2016, $3.34 in 2015, and $3.32 in 2014.

System Energy paid its parent, Entergy Corporation, distributions out of its common stock of $40 million in 2016 and $70 million in 2015.

Retained Earnings and Dividend Restrictions

Provisions within the articles of incorporation relating to preferred stock of each of Entergy Arkansas, Entergy Mississippi and Entergy New Orleans could restrict the payment of cash dividends or other distributions on their common and preferred equity if such payment were to occur when, or result in, a ratio of common stock equity to total capitalization of 25% or less. Entergy Corporation received dividend payments and distributions from subsidiaries totaling $165 million in 2016, $615 million in 2015, and $893 million in 2014.

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Comprehensive Income

Accumulated other comprehensive income (loss) is included in the equity section of the balance sheets of Entergy and Entergy Louisiana. The following table presents changes in accumulated other comprehensive income (loss) for Entergy for the year ended December 31, 2016 by component:



	Cash flow hedges net unrealized gain (loss)			Pension and other postretirement liabilities			Net unrealized investment gain (loss)			Foreign currency translation			Total Accumulated Other Comprehensive Income (Loss)
	(In Thousands)

Beginning balance, January 1, 2016		$105,970			($466,604	)		$367,557			$2,028			$8,951
Other comprehensive income (loss) before reclassifications	87,740			(26,997		)	68,465			(1,280		)	127,928
Amounts reclassified from accumulated other comprehensive income (loss)	(189,717		)	24,155			(6,288		)	—			(171,850		)
Net other comprehensive income (loss) for the period	(101,977		)	(2,842		)	62,177			(1,280		)	(43,922		)
Ending balance, December 31, 2016		$3,993			($469,446	)		$429,734			$748			($34,971	)

The following table presents changes in accumulated other comprehensive income (loss) for Entergy for the year ended December 31, 2015 by component:



	Cash flow hedges net unrealized gain (loss)			Pension and other postretirement liabilities			Net unrealized investment gain (loss)			Foreign currency translation			Total Accumulated Other Comprehensive Income (Loss)
	(In Thousands)

Beginning balance, January 1, 2015		$98,118			($569,789	)		$426,695			$2,669			($42,307	)
Other comprehensive income (loss) before reclassifications	(151,740		)	71,054			(34,186		)	(641		)	(115,513		)
Amounts reclassified from accumulated other comprehensive income (loss)	159,592			32,131			(24,952		)	—			166,771
Net other comprehensive income (loss) for the period	7,852			103,185			(59,138		)	(641		)	51,258
Ending balance, December 31, 2015		$105,970			($466,604	)		$367,557			$2,028			$8,951

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The following table presents changes in accumulated other comprehensive income (loss) for Entergy Louisiana for the year ended December 31, 2016:



	Pension and Other Postretirement Liabilities
	(In Thousands)

Beginning balance, January 1, 2016		($56,412	)
Other comprehensive income (loss) before reclassifications	8,926
Amounts reclassified from accumulated other comprehensive income (loss)	(956		)
Net other comprehensive income (loss) for the period	7,970
Ending balance, December 31, 2016		($48,442	)

The following table presents changes in accumulated other comprehensive income (loss) for Entergy Louisiana for the year ended December 31, 2015:



	Pension and Other Postretirement Liabilities
	(In Thousands)

Beginning balance, January 1, 2015		($79,223	)
Other comprehensive income (loss) before reclassifications	21,180
Amounts reclassified from accumulated other comprehensive income (loss)	1,631
Net other comprehensive income (loss) for the period	22,811
Ending balance, December 31, 2015		($56,412	)

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Total reclassifications out of accumulated other comprehensive income (loss) (AOCI) for Entergy for the years ended December 31, 2016 and 2015 are as follows:



	Amounts reclassified from AOCI						Income Statement Location
	2016			2015
	(In Thousands)
Cash flow hedges net unrealized gain (loss)
Power contracts		$293,268			($243,555	)	Competitive business operating revenues
Interest rate swaps	(1,395		)	(1,971		)	Miscellaneous - net
Total realized gain (loss) on cash flow hedges	291,873			(245,526		)
	(102,156		)	85,934			Income taxes
Total realized gain (loss) on cash flow hedges (net of tax)		$189,717			($159,592	)

Pension and other postretirement liabilities
Amortization of prior-service costs		$29,414			$23,920		(a)
Acceleration of prior-service cost due to curtailment	(1,045		)	(374		)	(a)
Amortization of loss	(60,693		)	(70,296		)	(a)
Settlement loss	(2,007		)	(1,401		)	(a)
Total amortization	(34,331		)	(48,151		)
	10,176			16,020			Income taxes
Total amortization (net of tax)		($24,155	)		($32,131	)

Net unrealized investment gain (loss)
Realized gain (loss)		$12,329			$48,926		Interest and investment income
	(6,041		)	(23,974		)	Income taxes
Total realized investment gain (loss) (net of tax)		$6,288			$24,952

Total reclassifications for the period (net of tax)		$171,850			($166,771	)



(a)	These accumulated other comprehensive income (loss) components are included in the computation of net periodic pension and other postretirement cost. See Note 11 to the financial statements for additional details.

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Total reclassifications out of accumulated other comprehensive income (loss) (AOCI) for Entergy Louisiana for the years ended December 31, 2016 and 2015 are as follows:



	Amounts reclassified from AOCI						Income Statement Location
	2016			2015
	(In Thousands)

Pension and other postretirement liabilities
Amortization of prior-service costs		$7,786			$7,464		(a)
Amortization of loss	(6,281		)	(10,140		)	(a)
Settlement loss	—			(14		)	(a)
Total amortization	1,505			(2,690		)
	(549		)	1,059			Income taxes
Total amortization (net of tax)	956			(1,631		)

Total reclassifications for the period (net of tax)		$956			($1,631	)



(a)	These accumulated other comprehensive income (loss) components are included in the computation of net periodic pension and other postretirement cost. See Note 11 to the financial statements for additional details.

NOTE 8. COMMITMENTS AND CONTINGENCIES (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Entergy and the Registrant Subsidiaries are involved in a number of legal, regulatory, and tax proceedings before various courts, regulatory commissions, and governmental agencies in the ordinary course of business. While management is unable to predict the outcome of such proceedings, management does not believe that the ultimate resolution of these matters will have a material effect on Entergy’s results of operations, cash flows, or financial condition. Entergy discusses regulatory proceedings in Note 2 to the financial statements and discusses tax proceedings in Note 3 to the financial statements.

Vidalia Purchased Power Agreement

Entergy Louisiana has an agreement extending through the year 2031 to purchase energy generated by a hydroelectric facility known as the Vidalia project. Entergy Louisiana made payments under the contract of approximately $158.7 million in 2016, $146 million in 2015, and $152.8 million in 2014. If the maximum percentage (94%) of the energy is made available to Entergy Louisiana, current production projections would require estimated payments of approximately $129 million in 2017, and a total of $1.81 billion for the years 2018 through 2031. Entergy Louisiana currently recovers the costs of the purchased energy through its fuel adjustment clause.

In an LPSC-approved settlement related to tax benefits from the tax treatment of the Vidalia contract, Entergy Louisiana agreed to credit rates by $11 million each year for up to 10 years, beginning in October 2002. In October 2011 the LPSC approved a settlement under which Entergy Louisiana agreed to provide credits to customers by crediting billings an additional $20.235 million per year for 15 years beginning January 2012. Entergy Louisiana recorded a regulatory charge and a corresponding regulatory liability to reflect this obligation.

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ANO Damage, Outage, and NRC Reviews

In addition, Entergy Arkansas incurred replacement power costs for ANO 2 power during its outage and incurred incremental replacement power costs for ANO 1 power because the outage extended beyond the originally-planned duration of the refueling outage. In February 2014 the APSC approved Entergy Arkansas’s request to exclude from the calculation of its revised energy cost rate $65.9 million of deferred fuel and purchased energy costs incurred in 2013 as a result of the ANO stator incident. The APSC authorized Entergy Arkansas to retain the $65.9 million in its deferred fuel balance with recovery to be reviewed in a later period after more information regarding various claims associated with the ANO stator incident is available.

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Pilgrim NRC Oversight and Planned Shutdown

In September 2015 the NRC placed Pilgrim in its “multiple/repetitive degraded cornerstone column” (Column 4) of its Reactor Oversight Process Action Matrix due to its finding of continuing weaknesses in Pilgrim’s corrective action program that contributed to repeated unscheduled shutdowns and equipment failures. The preliminary estimate of direct costs of Pilgrim’s response to a planned NRC enhanced inspection ranges from $45 million to $60 million, of which $28.6 million was incurred in 2016 in operation and maintenance expense. The estimate does not include potential capital expenditures, which will be charged directly to expense when incurred, or other costs to address issues that may arise in the inspection.

Entergy determined in October 2015 that it would close Pilgrim no later than June 1, 2019 because of poor market conditions that led to reduced revenues, a poor market design that failed to properly compensate nuclear generators for the benefits they provide, and increased operational costs. The decision came after management’s extensive analysis of the economics and operating life of the plant following the NRC’s decision to place the plant in Column 4. Entergy determined in April 2016 that it intends to refuel Pilgrim in 2017 and then cease operations May 31, 2019. Pilgrim currently has approximately 677 MW of Capacity Supply Obligations in ISO New England through May 2019.

See Note 14 to the financial statements for discussion of the impairment of the Pilgrim plant and related long-lived assets.

Spent Nuclear Fuel Litigation

Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors. Entergy’s nuclear owner/licensee subsidiaries have been charged fees for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected Entergy companies entered into contracts with the DOE, whereby the DOE is to furnish disposal services at a cost of one mill per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date. Entergy considers all costs incurred for the disposal of spent nuclear fuel, except accrued interest, to be proper components of nuclear fuel expense. Provisions to recover such costs have been or will be made in applications to regulatory authorities for the Utility plants. Following the defunding of the Yucca Mountain spent fuel repository program, the National Association of Regulatory Utility Commissioners and others sued the government seeking cessation of collection of the one mill per net kWh generated and sold after April 7, 1983 fee. In November 2013 the D.C. Circuit Court of Appeals ordered the DOE to submit a proposal to Congress to reset the fee to zero until the DOE complies with the Nuclear Waste Policy Act or Congress enacts an alternative waste disposal plan. In January 2014 the DOE submitted the proposal to Congress under protest, and also filed a petition for rehearing with the D.C. Circuit. The petition for rehearing was denied. The zero spent fuel fee went into effect prospectively in May 2014. Management cannot predict the potential timing or magnitude of future spent fuel fee revisions that may occur.

Because the DOE has not begun accepting spent fuel, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts. As a result of the DOE’s failure to begin disposal of spent nuclear fuel in 1998 pursuant to the Nuclear Waste Policy Act of 1982 and the spent fuel disposal contracts, Entergy’s nuclear owner/licensee subsidiaries have incurred and will continue to incur damages. Beginning in November 2003 these subsidiaries have pursued litigation to recover the damages caused by the DOE’s delay in performance. Following are details of final judgments recorded by Entergy in 2016 related to Entergy’s nuclear owner licensee subsidiaries’ litigation with the DOE.

In December 2015 the U.S. Court of Federal Claims issued a judgment in the amount of $81 million in favor of Entergy Nuclear Indian Point 3 and Entergy Nuclear FitzPatrick in the first round Indian Point 3/FitzPatrick damages case, and Entergy received the payment from the U.S. Treasury in June 2016. The effect of recording the Indian Point 3 proceeds was a reduction to plant, other operation and maintenance expense, and depreciation expense. The Indian

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Point 3 damages awarded included $45 million related to costs previously capitalized and $2 million related to costs previously recorded as other operation and maintenance expense. Of the $45 million, Entergy recorded $8 million as a reduction to previously-recorded depreciation expense. Entergy reduced its Indian Point 3 plant asset balance by the remaining $37 million. The effect of recording the FitzPatrick proceeds was a reduction to plant and other operation and maintenance expense. The FitzPatrick damages awarded included $32 million related to costs previously capitalized and $2 million related to costs previously recorded as other operation and maintenance expense. Of the $32 million, Entergy recorded $1 million as a reduction to previously-recorded depreciation expense, a $10 million reduction to bring its remaining FitzPatrick plant asset balance to zero, and the excess was recorded as a reduction to other operations and maintenance expense. See Note 14 for further discussion on the fair value analysis performed for FitzPatrick and the related impairment charge.

In April 2016 the U.S. Court of Federal Claims issued a partial judgment in the amount of $42 million in favor of Entergy Louisiana and against the DOE in the first round River Bend damages case. Entergy Louisiana received payment from the U.S. Treasury in August 2016. The effects of recording the final judgment in the third quarter 2016 were reductions to plant, nuclear fuel expense, other operation and maintenance expense, and depreciation expense. The River Bend damages awarded included $17 million related to costs previously capitalized, $23 million related to costs previously recorded as nuclear fuel expense, and $2 million related to costs previously recorded as other operation and maintenance expense. Of the $17 million, Entergy Louisiana recorded $3 million as a reduction to previously-recorded depreciation expense. Entergy Louisiana reduced its River Bend plant asset balance by the remaining $14 million. In September 2016 the U.S. Court of Federal Claims issued a further judgment in the River Bend case in the amount of $5 million. Entergy Louisiana recorded a receivable for that amount, and subsequently received payment from the U.S. Treasury in January 2017. The River Bend damages awarded included $2 million related to costs previously recorded as nuclear fuel expense and $3 million related to costs previously recorded as other operation and maintenance expense.

In May 2016, Entergy Nuclear Vermont Yankee and the DOE entered into a stipulation agreement and the U.S. Court of Federal Claims issued a judgment in the amount of $19 million in favor of Entergy Nuclear Vermont Yankee and against the DOE in the second round Vermont Yankee damages case. Entergy received payment from the U.S. Treasury in June 2016. The effect of recording the proceeds was a reduction to other operation and maintenance expense and depreciation expense. The damages awarded included $15 million related to costs previously capitalized and $4 million related to costs previously recorded as other operation and maintenance expense. Of the $15 million, Entergy recorded $2 million as a reduction to previously-recorded depreciation expense. The remaining $13 million would have been recorded as a reduction to Vermont Yankee’s plant asset balance, but was recorded as a reduction to other operation and maintenance expense because Vermont Yankee’s plant asset balance is fully impaired.

In June 2016 the U.S. Court of Federal Claims issued a final judgment in the amount of $49 million in favor of System Energy and against the DOE in the second round Grand Gulf damages case. System Energy received payment from the U.S. Treasury in August 2016. The effects of recording the judgment in the third quarter 2016 were reductions to plant, nuclear fuel expense, other operation and maintenance expense, and depreciation expense. The amounts of Grand Gulf damages awarded related to System Energy’s 90% ownership of Grand Gulf included $16 million related to costs previously capitalized, $19 million related to costs previously recorded as nuclear fuel expense, and $9 million related to costs previously recorded as other operation and maintenance expense. Of the $16 million, System Energy recorded $5 million as a reduction to previously-recorded depreciation expense. System Energy reduced its Grand Gulf plant asset balance by the remaining $11 million.

In July 2016 the U.S. Court of Federal Claims issued a final judgment in the amount of $31 million in favor of Entergy Arkansas and against the DOE in the second round ANO damages case. Entergy Arkansas received payment from the U.S. Treasury in October 2016. The effects of recording the judgment were reductions to plant, nuclear fuel expense, and other operation and maintenance expense. The ANO damages awarded included $6 million related to costs previously capitalized, $19 million related to costs previously recorded as nuclear fuel expense, $5 million related to costs previously recorded as other operation and maintenance expense, and $1 million related to costs previously recorded as taxes other than income taxes.

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In August 2016 the U.S. Court of Federal Claims issued a partial judgment in the amount of $53 million in favor of Entergy Louisiana and against the DOE in the first round Waterford 3 damages case. Entergy Louisiana received payment from the U.S. Treasury in November 2016. The effects of recording the judgment were reductions to plant, nuclear fuel expense, other operation and maintenance expense, and depreciation expense. The Waterford 3 damages awarded included $41 million related to costs previously capitalized, $10 million related to costs previously recorded as nuclear fuel expense, and $2 million related to costs previously recorded as other operation and maintenance expense. Of the $41 million, Entergy Louisiana recorded $3 million as a reduction to previously-recorded depreciation expense.

In September 2016 the U.S. Court of Federal Claims issued a judgment in the Entergy Nuclear Palisades case in the amount of $14 million. Entergy Nuclear Palisades recorded a receivable for that amount, and subsequently received payment from the U.S. Treasury in January 2017. The effects of recording the judgment were reductions to plant and other operation and maintenance expenses. The Palisades damages awarded included $11 million related to costs previously capitalized and $3 million related to costs previously recorded as other operation and maintenance expense. Of the $11 million, Entergy recorded $1 million as a reduction to previously-recorded depreciation expense. Entergy reduced its Palisades plant asset balance by the remaining $10 million. The Court previously issued a partial judgment in the case in the amount of $21 million, which was paid by the U.S. Treasury in October 2015.

In October 2016 the U.S. Court of Federal Claims issued a judgment in the second round Entergy Nuclear Indian Point 2 case in the amount of $34 million. Entergy Nuclear Indian Point 2 recorded a receivable for that amount, and subsequently received payment from the U.S. Treasury in January 2017. The effects of recording the judgment were reductions to plant and other operation and maintenance expenses. The Indian Point 2 damages awarded included $14 million related to costs previously capitalized, $15 million related to costs previously recorded as other operation and maintenance expense, $3 million related to previously recorded decommissioning expense, and $2 million related to costs previously recorded as taxes other than income taxes. Of the $14 million, Entergy recorded $3 million as a reduction to previously-recorded depreciation expense. Entergy reduced its Indian Point 2 plant asset balance by the remaining $11 million.

Management cannot predict the timing or amount of any potential recoveries on other claims filed by Entergy subsidiaries, and cannot predict the timing of any eventual receipt from the DOE of the U.S. Court of Federal Claims damage awards.

Nuclear Insurance

Third Party Liability Insurance

The Price-Anderson Act requires that reactor licensees purchase insurance and participate in a secondary insurance pool that provides insurance coverage for the public in the event of a nuclear power plant accident. The costs of this insurance are borne by the nuclear power industry. Congress amended and renewed the Price-Anderson Act in 2005 for a term through 2025. The Price-Anderson Act requires nuclear power plants to show evidence of financial protection in the event of a nuclear accident. This protection must consist of two layers of coverage:

The primary level is private insurance underwritten by American Nuclear Insurers (ANI) and provides public liability insurance coverage of $450 million for each operating reactor (prior to January 1, 2017, the primary level of insurance was $375 million). If this amount is not sufficient to cover claims arising from an accident, the second level, Secondary Financial Protection, applies. In 2016 the NRC approved Vermont Yankee’s exemption request to lower their limits from $375 million to $100 million effective April 15, 2016.

Within the Secondary Financial Protection level, each nuclear reactor has a contingent obligation to pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary level, regardless of proximity to the incident or fault, up to a maximum of approximately $127.3 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.273 billion). This retrospective premium is payable at a rate currently set at approximately $19 million per year per incident per nuclear power reactor.

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In the event that one or more acts of terrorism cause a nuclear power plant accident, which results in third-party damages – off-site property and environmental damage, off-site bodily injury, and on-site third-party bodily injury (i.e. contractors), the primary level provided by ANI combined with the Secondary Financial Protection would provide approximately $13 billion in coverage. The Terrorism Risk Insurance Reauthorization Act of 2007 created a government program that provides for up to $100 billion in coverage in excess of existing coverage for a terrorist event. Under current law, the Terrorism Risk Insurance Act extends through 2020.

Currently, 102 nuclear reactors are participating in the Secondary Financial Protection program. Effective April 15, 2016 the NRC granted Vermont Yankee’s exemption request and it was allowed to withdraw from participation in this layer of financial protection. The Secondary Financial Protection program provides approximately $13 billion in secondary layer insurance coverage to compensate the public in the event of a nuclear power reactor accident. The Price-Anderson Act provides that all potential liability for a nuclear accident is limited to the amounts of insurance coverage available under the primary and secondary layers.

Entergy Arkansas and Entergy Louisiana each have two licensed reactors. System Energy has one licensed reactor (10% of Grand Gulf is owned by a non-affiliated company (Cooperative Energy) that would share on a pro-rata basis in any retrospective premium assessment to System Energy under the Price-Anderson Act). The Entergy Wholesale Commodities segment includes the ownership, operation, and decommissioning of nuclear power reactors and the ownership of the shutdown Indian Point 1 reactor and Big Rock Point facility.

Property Insurance

Entergy’s nuclear owner/licensee subsidiaries are members of NEIL, a mutual insurance company that provides property damage coverage, including decontamination and premature decommissioning expense, to the members’ nuclear generating plants. The property damage insurance limits procured by Entergy for its Utility plants and Entergy Wholesale Commodity plants are in compliance with the financial protection requirements of the NRC.

As of December 31, 2016, the Utility plants (ANO 1 and 2, Grand Gulf, River Bend, and Waterford 3) had property damage insurance limits as follows: $1.5 billion per occurrence at each plant with an additional $100 million per occurrence that is shared among the plants. Property damage from flood, earthquake, and volcanic eruption is excluded from the first $500 million in coverage for ANO 1 and 2 and Grand Gulf. Property damage from earthquake and volcanic eruption is excluded from the first $500 million in coverage for River Bend and Waterford 3.

As of December 31, 2016, the Entergy Wholesale Commodities’ plants (FitzPatrick, Pilgrim, Palisades, Indian Point, Vermont Yankee, and Big Rock Point) had property damage insurance limits as follows: Vermont Yankee - $50 million per occurrence; Big Rock Point - $500 million per occurrence; FitzPatrick, Pilgrim, and Palisades - $1.115 billion per occurrence (FitzPatrick and Pilgrim’s coverage for non-nuclear, non-radiological property damage is limited to $500 million per occurrence); and Indian Point - $1.5 billion per occurrence (Indian Point has additional coverage of $100 million per occurrence, which brings its total insurance to $1.6 billion). Property damage from flood, earthquake, and volcanic eruption is excluded from the first $500 million in coverage for FitzPatrick and Pilgrim. Property damage from earthquake and volcanic eruption is excluded from the first $500 million in coverage for Indian Point.

In addition, Waterford 3, Grand Gulf, and the Entergy Wholesale Commodities plants, with the exception of Vermont Yankee, are also covered under NEIL’s Accidental Outage Coverage program. Accidental outage coverage provides indemnification for the actual cost incurred in the event of an unplanned outage resulting from property damage covered under the NEIL Primary Property Insurance policy, subject to a deductible period. The indemnification for the actual cost incurred is based on market power prices at the time of the loss. For non-nuclear events, the maximum indemnity, under this policy, is limited to $327.6 million per occurrence. After the deductible period has passed, weekly indemnities for an unplanned outage, covered under NEIL’s Accidental Outage Coverage program, would be paid according to the amounts listed below:

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•	100% of the weekly indemnity for each week for the first payment period of 52 weeks; then


•	80% of the weekly indemnity for each week for the second payment period of 52 weeks; and thereafter


•	80% of the weekly indemnity for an additional 58 weeks for the third and final payment period.

Under the property damage and accidental outage insurance programs, all NEIL insured plants could be subject to assessments should losses exceed the accumulated funds available from NEIL. Effective April 1, 2016, the maximum amounts of such possible assessments per occurrence were as follows:



	Assessments
	(In Millions)
Utility:
Entergy Arkansas	$53.6
Entergy Louisiana	$56.1
Entergy Mississippi	$0.10
Entergy New Orleans	$0.10
Entergy Texas	N/A
System Energy	$25.3

Entergy Wholesale Commodities	$—

Potential assessments for the Entergy Wholesale Commodities plants are covered by insurance obtained through NEIL’s reinsurers.

NRC regulations provide that the proceeds of this insurance must be used, first, to render the reactor safe and stable, and second, to complete decontamination operations. Only after proceeds are dedicated for such use and regulatory approval is secured would any remaining proceeds be made available for the benefit of plant owners or their creditors.

In the event that one or more acts of terrorism causes property damage under one or more or all nuclear insurance policies issued by NEIL (including, but not limited to, those described above) within 12 months from the date the first property damage occurs, the maximum recovery under all such nuclear insurance policies shall be an aggregate of $3.24 billion plus the additional amounts recovered for such losses from reinsurance, indemnity, and any other sources applicable to such losses.

Conventional Property Insurance

Entergy’s conventional property insurance program provides coverage on a system-wide basis for Entergy’s non-nuclear assets. The insurance program provides coverage up to $400 million for all perils on a per occurrence, “each and every loss” basis in excess of a $20 million self-insured retention with the exception of the following perils: earthquake shock, flood, and Named Windstorm (including associated storm surge). For the perils of earthquake shock and flood, the insurance program provides coverage up to $400 million on an annual aggregate basis in excess of a $40 million self-insured retention, and for the peril of a Named Windstorm (including associated storm surge), the insurance program provides coverage up to $125 million on an annual aggregate basis in excess of a $40 million self-insured retention. The coverage provided by the insurance program for the Entergy New Orleans gas distribution system is limited to $50 million per occurrence and is subject to the same annual aggregate limits and retentions listed above for the perils of earthquake shock, flood, and Named Windstorm (including associated storm surge).

Covered property generally includes power plants, substations, facilities, inventories, and gas distribution-related properties. Excluded property generally includes transmission and distribution lines, poles, and towers for substations valued at $5 million or less, coverage for named windstorm and associated storm surge is excluded. This coverage is in place for Entergy Corporation, the Registrant Subsidiaries, and certain other Entergy subsidiaries,

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including the owners of the nuclear power plants in the Entergy Wholesale Commodities segment. Entergy also purchases $300 million in terrorism insurance coverage for its conventional property. The Terrorism Risk Insurance Reauthorization Act of 2007 created a government program that provides for up to $100 billion in coverage in excess of existing coverage for a terrorist event. As discussed above, the Terrorism Risk Insurance Reauthorization Act of 2007 expired on December 31, 2014. However, The Terrorism Risk Insurance Reauthorization Act of 2015 was signed into law by the President of the United States on January 12, 2015 thereby extending the Terrorism Risk Insurance Act for six years until December 31, 2020.

In addition to the conventional property insurance program, Entergy has purchased additional coverage ($20 million per occurrence) for some of its non-regulated, non-generation assets. This policy serves to buy-down the $20 million deductible and is placed on a scheduled location basis. The applicable deductibles are generally $100,000 to $250,000 for the locations scheduled in the policy, with the following exceptions: 1) locations where damage is caused by a Named Windstorm (including associated storm surge) and locations with values in excess of $20 million are subject to a $500,000 deductible; and 2) three scheduled locations at two nuclear sites are subject to a $2.5 million deductible, which coincides with the nuclear property insurance deductible at each of the respective nuclear sites.

Gas System Rebuild Insurance Proceeds (Entergy New Orleans)

Entergy New Orleans received insurance proceeds in 2007 for future construction expenditures associated with rebuilding its gas system, and the October 2006 City Council resolution approving the settlement of Entergy New Orleans’s rate and storm-cost recovery filings requires Entergy New Orleans to record those proceeds in a designated sub-account of other deferred credits until the proceeds are spent on the rebuild project. This other deferred credit is shown as “Gas system rebuild insurance proceeds” on Entergy New Orleans’s balance sheet.

Employment and Labor-related Proceedings

The Registrant Subsidiaries and other Entergy subsidiaries are responding to various lawsuits in both state and federal courts and to other labor-related proceedings filed by current and former employees, recognized bargaining representatives, and third parties not selected for open positions or providing services directly or indirectly to one or more of the Registrant Subsidiaries and other Entergy subsidiaries. Generally, the amount of damages being sought is not specified in these proceedings. These actions include, but are not limited to, allegations of wrongful employment actions; wage disputes and other claims under the Fair Labor Standards Act or its state counterparts; claims of race, gender, age, and disability discrimination; disputes arising under collective bargaining agreements; unfair labor practice proceedings and other administrative proceedings before the National Labor Relations Board or concerning the National Labor Relations Act; claims of retaliation; claims of harassment and hostile work environment; and claims for or regarding benefits under various Entergy Corporation-sponsored plans. Entergy and the Registrant Subsidiaries are responding to these lawsuits and proceedings and deny liability to the claimants. Management believes that loss exposure has been and will continue to be handled so that the ultimate resolution of these matters will not be material, in the aggregate, to the financial position, results of operation, or cash flows of Entergy or the Utility operating companies.

Asbestos Litigation (Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas)

Numerous lawsuits have been filed in federal and state courts, primarily by contractor employees who worked in the 1940-1980s timeframe, primarily against Entergy Texas, and to a lesser extent the other Utility operating companies, as premises owners of power plants, for damages caused by alleged exposure to asbestos. Many other defendants are named in these lawsuits as well. Currently, there are approximately 80 lawsuits involving approximately 600 claimants. Management believes that adequate provisions have been established to cover any exposure. Additionally, negotiations continue with insurers to recover reimbursements. Management believes that loss exposure has been and will continue to be handled so that the ultimate resolution of these matters will not be material, in the aggregate, to the financial position, results of operation, or cash flows of the Utility operating companies.

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Grand Gulf - Related Agreements

Capital Funds Agreement (Entergy Corporation and System Energy)

System Energy has entered into agreements with Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans whereby they are obligated to purchase their respective entitlements of capacity and energy from System Energy’s interest in Grand Gulf, and to make payments that, together with other available funds, are adequate to cover System Energy’s operating expenses. System Energy would have to secure funds from other sources, including Entergy Corporation’s obligations under the Capital Funds Agreement, to cover any shortfalls from payments received from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under these agreements.

Unit Power Sales Agreement (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

System Energy has agreed to sell all of its share of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans in accordance with specified percentages (Entergy Arkansas-36%, Entergy Louisiana-14%, Entergy Mississippi-33%, and Entergy New Orleans-17%) as ordered by the FERC. Charges under this agreement are paid in consideration for the purchasing companies’ respective entitlement to receive capacity and energy and are payable irrespective of the quantity of energy delivered. The agreement will remain in effect until terminated by the parties and the termination is approved by the FERC, most likely upon Grand Gulf’s retirement from service. In December 2016 the NRC granted the extension of Grand Gulf’s operating license to 2044. Monthly obligations are based on actual capacity and energy costs. The average monthly payments for 2016 under the agreement are approximately $16.7 million for Entergy Arkansas, $6.7 million for Entergy Louisiana, $14.3 million for Entergy Mississippi, and $8.1 million for Entergy New Orleans. See Note 2 to the financial statements for discussion of the complaint filed with the FERC against System Energy seeking a reduction in the return on equity component of the Unit Power Sales Agreement.

Availability Agreement (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans are individually obligated to make payments or subordinated advances to System Energy in accordance with stated percentages (Entergy Arkansas-17.1%, Entergy Louisiana-26.9%, Entergy Mississippi-31.3%, and Entergy New Orleans-24.7%) in amounts that, when added to amounts received under the Unit Power Sales Agreement or otherwise, are adequate to cover all of System Energy’s operating expenses as defined, including an amount sufficient to amortize the cost of Grand Gulf 2 over 27 years (See Reallocation Agreement terms below) and expenses incurred in connection with a permanent shutdown of Grand Gulf. System Energy has assigned its rights to payments and advances to certain creditors as security for certain obligations. Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement have exceeded the amounts payable under the Availability Agreement. Accordingly, no payments under the Availability Agreement have ever been required. If Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments.

Reallocation Agreement (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)

System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans entered into the Reallocation Agreement relating to the sale of capacity and energy from Grand Gulf and the related costs, in which Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans agreed to assume all of Entergy Arkansas’s

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responsibilities and obligations with respect to Grand Gulf under the Availability Agreement. FERC’s decision allocating a portion of Grand Gulf capacity and energy to Entergy Arkansas supersedes the Reallocation Agreement as it relates to Grand Gulf. Responsibility for any Grand Gulf 2 amortization amounts has been individually allocated (Entergy Louisiana-26.23%, Entergy Mississippi-43.97%, and Entergy New Orleans-29.80%) under the terms of the Reallocation Agreement. However, the Reallocation Agreement does not affect Entergy Arkansas’s obligation to System Energy’s lenders under the assignments referred to in the preceding paragraph. Entergy Arkansas would be liable for its share of such amounts if Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans were unable to meet their contractual obligations. No payments of any amortization amounts will be required so long as amounts paid to System Energy under the Unit Power Sales Agreement, including other funds available to System Energy, exceed amounts required under the Availability Agreement, which is expected to be the case for the foreseeable future.

NOTE 9. ASSET RETIREMENT OBLIGATIONS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Accounting standards require companies to record liabilities for all legal obligations associated with the retirement of long-lived assets that result from the normal operation of the assets. For Entergy, substantially all of its asset retirement obligations consist of its liability for decommissioning its nuclear power plants. In addition, an insignificant amount of removal costs associated with non-nuclear power plants is also included in the decommissioning line item on the balance sheets.

These liabilities are recorded at their fair values (which are the present values of the estimated future cash outflows) in the period in which they are incurred, with an accompanying addition to the recorded cost of the long-lived asset. The asset retirement obligation is accreted each year through a charge to expense, to reflect the time value of money for this present value obligation. The accretion will continue through the completion of the asset retirement activity. The amounts added to the carrying amounts of the long-lived assets will be depreciated over the useful lives of the assets. The application of accounting standards related to asset retirement obligations is earnings neutral to the rate-regulated business of the Registrant Subsidiaries.

In accordance with ratemaking treatment and as required by regulatory accounting standards, the depreciation provisions for the Registrant Subsidiaries include a component for removal costs that are not asset retirement obligations under accounting standards. In accordance with regulatory accounting principles, the Registrant Subsidiaries have recorded regulatory assets (liabilities) in the following amounts to reflect their estimates of the difference between estimated incurred removal costs and estimated removal costs recovered in rates:



	December 31,
	2016	2015
	(In Millions)
Entergy Arkansas	$128.5	$85.7
Entergy Louisiana	($53.9)	($68.3)
Entergy Mississippi	$82.0	$77.5
Entergy New Orleans	$40.1	$29.4
Entergy Texas	$33.5	$25.8
System Energy	$69.7	$54.8

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The cumulative decommissioning and retirement cost liabilities and expenses recorded in 2016 and 2015 by Entergy were as follows:



	Liabilities as of December 31, 2015		Liabilities Incurred			Accretion		Change in Cash Flow Estimate			Spending			Liabilities as of December 31, 2016 (a)
	(In Millions)
Utility:
Entergy Arkansas		$872.3		$—			$53.6		$—			($1.5	)		$924.4
Entergy Louisiana		$1,027.9		$—			$54.8		$—			$—			$1,082.7
Entergy Mississippi		$8.3		$—			$0.4		$—			$—			$8.7
Entergy New Orleans		$2.7		$—			$0.2		$—			$—			$2.9
Entergy Texas		$6.1		$—			$0.4		$—			$—			$6.5
System Energy		$803.4		$—			$50.8		$—			$—			$854.2
Entergy Wholesale Commodities:
Big Rock Point		$28.0		$—			$2.2		$10.1			($2.4	)		$37.9
FitzPatrick		$—		$696.2	(b)		$18.1		$—			$—			$714.3
Indian Point 1		$197.9		$—			$17.1		($0.3	)		($7.1	)		$207.6
Indian Point 2		$390.1		$—			$33.0		$230.0			$—			$653.1
Indian Point 3		$—		$466.3	(b)		$12.1		$162.7			$—			$641.1
Palisades		$342.0		$—			$29.5		$128.8			$—			$500.3
Pilgrim		$551.2		$—			$48.4		$3.2			($0.5	)		$602.3
Vermont Yankee		$560.0		$—			$39.3		$—			($128.8	)		$470.5
Other (c)		$0.3		$—			$—		$—			$—			$0.3



	Liabilities as of December 31, 2014		Liabilities Incurred			Accretion		Change in Cash Flow Estimate			Spending			Liabilities as of December 31, 2015
	(In Millions)
Utility:
Entergy Arkansas		$818.4		$3.5	(c)		$50.4		$—			$—			$872.3
Entergy Louisiana		$950.3		$1.9	(c)		$51.0		$24.7			$—			$1,027.9
Entergy Mississippi		$6.8		$1.1	(c)		$0.4		$—			$—			$8.3
Entergy New Orleans		$2.5		$—			$0.2		$—			$—			$2.7
Entergy Texas		$4.6		$1.4	(c)		$0.3		($0.2	)		$—			$6.1
System Energy		$757.9		$—			$48.0		($2.5	)		$—			$803.4
Entergy Wholesale Commodities:
Big Rock Point		$27.8		$—			$2.2		$—			($2.0	)		$28.0
Indian Point 1		$188.9		$—			$16.3		$—			($7.3	)		$197.9
Indian Point 2		$359.7		$—			$30.4		$—			$—			$390.1
Palisades		$352.0		$—			$25.2		($35.2	)		$—			$342.0
Pilgrim		$383.1		$—			$33.3		$134.8			$—			$551.2
Vermont Yankee		$606.3		$—			$46.1		$—			($92.4	)		$560.0
Other (c)		$—		$—			$0.3		$—			$—			$0.3

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(a)	Entergy Wholesale Commodities includes $714.3 million of asset retirement obligation for FitzPatrick which is classified as held for sale within other non-current liabilities on the consolidated balance sheet. See Note 14 to the financial statements for discussion of the agreement to sell the FitzPatrick plant to Exelon.


(b)	See “Entergy Wholesale Commodities” in “Nuclear Plant Decommissioning” below for additional discussion regarding the decommissioning agreements with NYPA and the associated asset retirement obligations.


(c)	See “Coal Combustion Residuals” below for additional discussion regarding the asset retirement obligations related to coal combustion residuals management.

Nuclear Plant Decommissioning

Entergy periodically reviews and updates estimated decommissioning costs. The actual decommissioning costs may vary from the estimates because of the timing of plant decommissioning, regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment. As described below, during 2016 and 2015, Entergy updated decommissioning cost estimates for certain nuclear power plants.

Utility

In the fourth quarter 2015, Entergy Louisiana recorded a revision to its estimated decommissioning cost liability for Waterford 3 as a result of a revised decommissioning cost study. The revised estimate resulted in a $24.9 million increase in its decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.

In the fourth quarter 2015, System Energy recorded a revision to its estimated decommissioning cost liability for Grand Gulf as a result of a revised decommissioning cost study. The revised estimate resulted in a $2.5 million reduction in its decommissioning cost liability, along with a corresponding reduction in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.

Entergy Wholesale Commodities

In August 2013 the Board approved a plan to close and decommission Vermont Yankee at the end of 2014. As a result of the settlement agreement entered into by Entergy and the state of Vermont, Entergy reassessed its assumptions regarding the timing of cash flows. Entergy Vermont Yankee provided to the Vermont parties, in 2014, a site assessment study of the costs and tasks of radiological decommissioning, spent nuclear fuel management, and site restoration for Vermont Yankee. Entergy Vermont Yankee filed its Post-Shutdown Decommissioning Activities Report (PSDAR) for Vermont Yankee with the NRC in December 2014. As part of the development of the site assessment study and PSDAR, Entergy obtained a revised decommissioning cost study in the third quarter 2014. The revised estimate, along with reassessment of the assumptions regarding the timing of decommissioning cash flows, resulted in a $101.6 million increase in the decommissioning cost liability and a corresponding impairment charge, recorded in September 2014.

Vermont Yankee submitted notification of permanent cessation of operations and permanent removal of fuel from the reactor in January 2015 after final shutdown in December 2014. Vermont Yankee’s future certifications to satisfy the NRC’s financial assurance requirements will now be based on the site specific cost estimate, including the estimated cost of managing spent fuel, rather than the NRC minimum formula for estimating decommissioning costs. Filings with the NRC for planned shutdown activities will determine whether any other financial assurance may be required and will specifically address funding for spent fuel management, which will be required until the federal government takes possession of the fuel and removes it from the site, per its current obligation.

Entergy expects that amounts available in Vermont Yankee’s decommissioning trust fund, including expected earnings, together with the credit facilities entered into in January 2015 that are expected to be repaid with recoveries from DOE litigation related to spent fuel storage, will be sufficient to cover Vermont Yankee’s expected costs of decommissioning, spent fuel management costs, and site restoration. In June 2015 the NRC staff issued an exemption

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from its regulations to allow Vermont Yankee to use its decommissioning trust fund to pay for approximately $225 million of estimated future spent fuel management costs that will not be paid for using funds from the credit facilities. In August 2015, Vermont and two Vermont utilities filed a petition in the U.S. Court of Appeals for the D.C. Circuit challenging the NRC’s issuance of that exemption. In February 2016 the court dismissed the petition as premature because Vermont and the utilities had requested the NRC to reconsider a number of issues related to Vermont Yankee's use of the decommissioning trust fund including its use to pay for spent fuel management expenses pursuant to the exemption granted in June 2015. In October 2016 the NRC denied Vermont's and the utilities' request for a hearing and other relief but directed the NRC staff to conduct an assessment of any environmental impacts associated with the exemption.

In the second quarter 2015, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Palisades as a result of a revised decommissioning cost study. The revised estimate resulted in a $77.6 million reduction in the decommissioning cost liability, along with a corresponding reduction in the related asset retirement cost asset.

In the fourth quarter 2015, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Palisades as a result of a revised decommissioning cost study. The revised estimate resulted in a $42.4 million increase in the decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset. The increase in the estimated decommissioning cost liability resulted from the change in expectation regarding the timing of decommissioning cash flows. The asset retirement cost asset was included in the Palisades carrying value that was written down to fair value in the fourth quarter 2015.

In the fourth quarter 2016, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Palisades as a result of a revised decommissioning cost study. The revised estimate resulted in a $129 million increase in the decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset. The increase in the estimated decommissioning cost liability resulted from the change in expectation regarding the timing of decommissioning cash flows due to the decision to cease operations of the plant on October 1, 2018, subject to regulatory approval. The asset retirement cost asset was included in the Palisades carrying value that was written down to fair value in the fourth quarter 2016. See Note 14 to the financial statements for discussion of the impairment of the value and planned shutdown of the Palisades plant.

In the third quarter 2015, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Pilgrim as a result of a revised decommissioning cost study. The revised estimate resulted in a $134 million increase in the decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset. The increase in the estimated decommissioning cost liability resulted from the change in expectation regarding the timing of decommissioning cash flows due to the decision to cease operations of the plant no later than June 2019. The asset retirement cost asset was included in the Pilgrim carrying value that was written down to fair value in the third quarter 2015. See Note 14 to the financial statements for discussion of the impairment of the value and planned shutdown of the Pilgrim plant.

For the Indian Point 3 and FitzPatrick plants purchased in 2000 from NYPA, NYPA retained the decommissioning trust funds and the decommissioning liabilities. NYPA and Entergy subsidiaries executed decommissioning agreements, which specified their decommissioning obligations. NYPA had the right to require the Entergy subsidiaries to assume each of the decommissioning liabilities provided that it assigned the corresponding decommissioning trust, up to a specified level, to the Entergy subsidiaries. Under the original agreements, if the decommissioning liabilities were retained by NYPA, the Entergy subsidiaries would perform the decommissioning of the plants at a price equal to the lesser of a pre-specified level or the amount in the decommissioning trust funds. At the time of the acquisition of the plants Entergy recorded a contract asset that represented an estimate of the present value of the difference between the stipulated contract amount for decommissioning the plants less the decommissioning costs estimated in independent decommissioning cost studies. The asset was increased by monthly accretion based on the applicable discount rate necessary to ultimately provide for the estimated future value of the decommissioning contract. The monthly accretion was recorded as interest income.

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In the third quarter 2015, Entergy Wholesale Commodities recorded a revision to the contract asset for the FitzPatrick plant. Due to a change in expectation regarding the timing of decommissioning cash flows, the result was a write down of the contract asset from $335 million to $131 million, for a charge of $204 million.

In August 2016, Entergy entered into a trust transfer agreement with NYPA to transfer the decommissioning trust funds and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants to Entergy. As a result of the agreement with NYPA, in the third quarter 2016 Entergy removed the contract asset from its balance sheet, and recorded receivables for the beneficial interests in the decommissioning trust funds and asset retirement obligations for the decommissioning liabilities. The transaction was contingent upon receiving approval from the NRC, which was received in January 2017. The decommissioning trust funds for the Indian Point 3 and FitzPatrick plants were transferred to Entergy by NYPA in January 2017.

In the fourth quarter 2016, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liabilities for Indian Point 1, Indian Point 2, and Indian Point 3 as a result of revised decommissioning cost studies. The revised estimates resulted in a $392 million increase in the decommissioning cost liabilities, along with a corresponding increase in the related asset retirement cost assets. The increase in the estimated decommissioning cost liabilities resulted from the change in expectation regarding the timing of decommissioning cash flows due to the decision to cease operations of the Indian Point 2 plant no later than April 2020 and the Indian Point 3 plant no later than April 2021. The asset retirement cost assets were included in the carrying value that was written down to fair value in the fourth quarter 2016. See Note 14 to the financial statements for discussion of the impairment of the value and planned shutdown of Indian Point Energy Center.

As the Entergy Wholesale Commodities nuclear plants individually transition to decommissioning, the Entergy Wholesale Commodities plant owners will submit filings with the NRC for planned shutdown activities. These filings with the NRC will determine whether any other financial assurance may be required. The plants’ owners are required to provide the NRC with a biennial report (annually for units that have shut down or will shut down within five years), based on values as of December 31, addressing the owners’ ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, the Entergy Wholesale Commodities plant owners may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met.

Entergy maintains decommissioning trust funds that are committed to meeting its obligations for the costs of decommissioning the nuclear power plants. The fair values of the decommissioning trust funds and the related asset retirement obligation regulatory assets (liabilities) of Entergy as of December 31, 2016 and 2015 are as follows:



	2016			2015
	Decommissioning Trust Fair Values		Regulatory Asset (Liability)	Decommissioning Trust Fair Values		Regulatory Asset (Liability)
	(In Millions)			(In Millions)
Utility:
ANO 1 and ANO 2		$834.7	$316.3		$771.3		$280.3
River Bend		$712.8	($28.4)		$651.7		($26.8	)
Waterford 3		$427.9	$172.8		$390.6		$158.5
Grand Gulf		$780.5	$142.5		$701.5		$108.6
Entergy Wholesale Commodities		$2,968.0	$—		$2,834.9		$—

As a result of the agreement with NYPA discussed above, in the third quarter 2016, Entergy removed the contract asset from its balance sheet, and recorded receivables of $1.5 billion for the beneficial interests in the decommissioning trust funds for Indian Point 3 and FitzPatrick. At December 31, 2016, the fair values of the

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decommissioning trust funds held by NYPA were $719 million for the Indian Point 3 plant and $785 million for the FitzPatrick plant. The fair values are based on the trust statements received from NYPA and are valued by the fund administrator using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value hierarchy. The receivables for the beneficial interests in the decommissioning trust funds are recorded in other deferred debits on the consolidated balance sheet.

Coal Combustion Residuals

In June 2010 the EPA issued a proposed rule on coal combustion residuals (CCRs) that contained two primary regulatory options: (1) regulating CCRs destined for disposal in landfills or received (including stored) in surface impoundments as so-called “special wastes” under the hazardous waste program of RCRA Subtitle C; or (2) regulating CCRs destined for disposal in landfills or surface impoundments as non-hazardous wastes under Subtitle D of RCRA. Under both options, CCRs that are beneficially reused in certain processes would remain excluded from hazardous waste regulation. In April 2015 the EPA published the final CCR rule with the material being regulated under the second scenario presented above - as non-hazardous wastes regulated under RCRA Subtitle D. The final regulations create new compliance requirements including modified storage, new notification and reporting practices, product disposal considerations, and CCR unit closure criteria. Entergy believes that on-site disposal options will be available at its facilities, to the extent needed for CCR that cannot be transferred for beneficial reuse. In December 2016, the Water Infrastructure Improvements for the Nation Act was signed into law, which authorizes states to regulate coal ash rather than leaving primary enforcement to citizen suit actions. States may submit to the EPA proposals for permit programs. Entergy is monitoring state agency actions and will participate in the regulatory development process.

NOTE 10. LEASES (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

General

As of December 31, 2016, Entergy had capital leases and non-cancelable operating leases for equipment, buildings, vehicles, and fuel storage facilities with minimum lease payments as follows (excluding power purchase agreement operating leases, nuclear fuel leases, and the Grand Gulf and Waterford 3 sale and leaseback transactions, all of which are discussed elsewhere):



Year	Operating Leases		Capital Leases
	(In Thousands)
2017		$76,663		$4,694
2018	69,620		3,255
2019	67,218		3,124
2020	51,127		3,065
2021	41,531		2,887
Years thereafter	90,787		21,891
Minimum lease payments	396,946		38,916
Less: Amount representing interest	—		11,934
Present value of net minimum lease payments		$396,946		$26,982

Total rental expenses for all leases (excluding power purchase agreement operating leases, nuclear fuel leases, and the Grand Gulf and Waterford 3 sale and leaseback transactions) amounted to $44.4 million in 2016, $63.9 million in 2015, and $59 million in 2014.

As of December 31, 2016 the Registrant Subsidiaries had a capital lease and non-cancelable operating leases for equipment, buildings, vehicles, and fuel storage facilities with minimum lease payments as follows (excluding

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power purchase agreement operating leases, nuclear fuel leases, and the Grand Gulf and Waterford 3 lease obligations, all of which are discussed elsewhere):

Capital Leases



Year	Entergy Mississippi
	(In Thousands)
2017		$1,570
2018	131
2019	—
2020	—
2021	—
Years thereafter	—
Minimum lease payments	1,701
Less: Amount representing interest	111
Present value of net minimum lease payments		$1,590

Operating Leases



Year	Entergy Arkansas		Entergy Louisiana		Entergy Mississippi		Entergy New Orleans		Entergy Texas
	(In Thousands)
2017		$17,648		$23,947		$8,014		$2,324		$5,361
2018	14,667		22,053		7,171		2,065		4,882
2019	15,419		22,461		6,830		1,882		3,841
2020	8,871		16,700		5,878		1,627		2,335
2021	6,697		12,097		4,200		1,218		1,546
Years thereafter	25,818		22,966		5,865		1,864		2,009
Minimum lease payments		$89,120		$120,224		$37,958		$10,980		$19,974

Rental Expenses



Year	Entergy Arkansas		Entergy Louisiana		Entergy Mississippi		Entergy New Orleans		Entergy Texas		System Energy
	(In Millions)
2016		$8.0		$17.8		$4.0		$0.9		$2.8		$1.6
2015		$13.6		$21.8		$5.4		$1.6		$4.0		$2.9
2014		$12.0		$20.7		$4.3		$1.2		$3.8		$2.0

In addition to the above rental expense, railcar operating lease payments and oil tank facilities lease payments are recorded in fuel expense in accordance with regulatory treatment. Railcar operating lease payments were $3.4 million in 2016, $4.7 million in 2015, and $4.8 million in 2014 for Entergy Arkansas and $0.3 million in 2016, $1.1 million in 2015, and $1.7 million in 2014 for Entergy Louisiana. Oil tank facilities lease payments for Entergy Mississippi were $1.6 million in 2016, $1.6 million in 2015, and $1.6 million in 2014.

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Power Purchase Agreements

As of December 31, 2016, Entergy Texas had a power purchase agreement that is accounted for as an operating lease under the accounting standards. The lease payments are recovered in fuel expense in accordance with regulatory treatment. The minimum lease payments under the power purchase agreement are as follows:



Year	Entergy Texas (a)		Entergy
	(In Thousands)
2017		$29,772		$29,772
2018	30,458		30,458
2019	31,159		31,159
2020	31,876		31,876
2021	32,609		32,609
Years thereafter	10,180		10,180
Minimum lease payments		$166,054		$166,054


(a)	Amounts reflect 100% of minimum payments. Under a separate contract, Entergy Louisiana purchases 50% of the capacity and energy from the power purchase agreement from Entergy Texas.

Total capacity expense under the power purchase agreement accounted for as an operating lease at Entergy Texas was $26.1 million in 2016, $29.9 million in 2015, and $29.2 million in 2014.

Sales and Leaseback Transactions

Waterford 3 Lease Obligation

In 1989, in three separate but substantially identical transactions, Entergy Louisiana sold and leased back undivided interests in Waterford 3 for the aggregate sum of $353.6 million. The leases expire in July 2017. Entergy Louisiana is required to report the sale-leaseback as a financing transaction in its financial statements.

In December 2015, Entergy Louisiana agreed to purchase the undivided interests in Waterford 3 that were previously being leased. The purchase was accomplished in a two-step transaction in which Entergy Louisiana first acquired the equity participant’s beneficial interest in the leased assets, followed by a termination of the leases and transfer of the leased assets to Entergy Louisiana when the outstanding lessor debt is paid.

In March 2016, Entergy Louisiana completed the first step in the two-step transaction by acquiring the equity participant’s beneficial interest in the leased assets. Entergy Louisiana paid $60 million in cash and $52 million through the issuance of a non-interest bearing collateral trust mortgage note, payable in installments through July 2017. Entergy Louisiana continued to make payments on the lessor debt that remained outstanding and which matured in January 2017. The combination of payments on the $52 million collateral trust mortgage note issued and the debt service on the lessor debt is equal in timing and amount to the remaining lease payments due from the closing of the transaction through the end of the lease term in July 2017.

Throughout the term of the lease, Entergy Louisiana had accrued a liability for the amount it expected to pay to retain the use of the undivided interests in Waterford 3 at the end of the lease term. Since the sale-leaseback transaction was accounted for as a financing transaction, the accrual of this liability was accounted for as additional interest expense. As of December 2015, the balance of this liability was $62.7 million. Upon entering into the agreement to purchase the equity participant’s beneficial interest in the undivided interests, Entergy Louisiana reduced the balance of the

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liability to $60 million, and recorded the $2.7 million difference as a credit to interest expense. The $60 million remaining liability was eliminated upon payment of the cash portion of the purchase price.

As of December 31, 2016, Entergy Louisiana, in connection with the Waterford 3 lease obligation, had a future minimum lease payment (reflecting an interest rate of 8.09%) of $57.5 million, including $2.3 million in interest, due January 2017 that is recorded as long-term debt.

In February 2017 the leases were terminated and the leased assets were conveyed to Entergy Louisiana.

Grand Gulf Lease Obligations

In 1988, in two separate but substantially identical transactions, System Energy sold and leased back undivided ownership interests in Grand Gulf for the aggregate sum of $500 million. The initial term of the leases expired in July 2015. System Energy renewed the leases for fair market value with renewal terms expiring in July 2036. At the end of the new lease renewal terms, System Energy has the option to repurchase the leased interests in Grand Gulf or renew the leases at fair market value. In the event that System Energy does not renew or purchase the interests, System Energy would surrender such interests and their associated entitlement of Grand Gulf’s capacity and energy.

System Energy is required to report the sale-leaseback as a financing transaction in its financial statements. For financial reporting purposes, System Energy expenses the interest portion of the lease obligation and the plant depreciation. However, operating revenues include the recovery of the lease payments because the transactions are accounted for as a sale and leaseback for ratemaking purposes. Consistent with a recommendation contained in a FERC audit report, System Energy initially recorded as a net regulatory asset the difference between the recovery of the lease payments and the amounts expensed for interest and depreciation and continues to record this difference as a regulatory asset or liability on an ongoing basis, resulting in a zero net balance for the regulatory asset at the end of the lease term. The amount was a net regulatory liability of $55.6 million and $55.6 million as of December 31, 2016 and 2015, respectively.

As of December 31, 2016, System Energy, in connection with the Grand Gulf sale and leaseback transactions, had future minimum lease payments (reflecting an implicit rate of 5.13%) that are recorded as long-term debt, as follows:



	Amount
	(In Thousands)

2017		$17,188
2018	17,188
2019	17,188
2020	17,188
2021	17,188
Years thereafter	257,812
Total	343,752
Less: Amount representing interest	309,393
Present value of net minimum lease payments		$34,359

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NOTE 11. RETIREMENT, OTHER POSTRETIREMENT BENEFITS, AND DEFINED CONTRIBUTION PLANS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Qualified Pension Plans

Entergy has nine qualified pension plans covering substantially all employees. The “Entergy Corporation Retirement Plan for Non-Bargaining Employees,” “Entergy Corporation Retirement Plan for Bargaining Employees,” “Entergy Corporation Retirement Plan II for Non-Bargaining Employees,” “Entergy Corporation Retirement Plan II for Bargaining Employees,” “Entergy Corporation Retirement Plan III,” “Entergy Corporation Retirement Plan IV for Non-Bargaining Employees,” and “Entergy Corporation Retirement Plan IV for Bargaining Employees” are non-contributory final average pay plans and provide pension benefits that are based on employees’ credited service and compensation during employment. Effective December 31, 2016, the Entergy Corporation Retirement Plan IV for Non-Bargaining Employees was merged with and into the Entergy Corporation Retirement Plan II for Non-Bargaining Employees. There is no loss of vesting or benefit options or reduction of accrued benefits to affected participants as a result of this plan merger. Non-bargaining employees whose most recent date of hire is after June 30, 2014 participate in the “Entergy Corporation Cash Balance Plan for Non-Bargaining Employees.” Certain bargaining employees hired or rehired after June 30, 2014, or such later date provided for in their applicable collective bargaining agreements, participate in the “Entergy Corporation Cash Balance Plan for Bargaining Employees.” The Registrant Subsidiaries participate in these four plans: “Entergy Corporation Retirement Plan for Non-Bargaining Employees,” “Entergy Corporation Retirement Plan for Bargaining Employees,” “Entergy Corporation Cash Balance Plan for Non-Bargaining Employees,” and “Entergy Cash Balance Plan for Bargaining Employees.”

The assets of the seven final average pay qualified pension plans are held in a master trust established by Entergy, and the assets of the two cash balance pension plans are held in a second master trust established by Entergy. Each pension plan has an undivided beneficial interest in each of the investment accounts in its respective master trust that is maintained by a trustee. Use of the master trusts permits the commingling of the trust assets of the pension plans of Entergy Corporation and its Registrant Subsidiaries for investment and administrative purposes. Although assets in the master trusts are commingled, the trustee maintains supporting records for the purpose of allocating the trust level equity in net earnings (loss) and the administrative expenses of the investment accounts in each trust to the various participating pension plans in that particular trust. The fair value of the trusts’ assets is determined by the trustee and certain investment managers. For each trust, the trustee calculates a daily earnings factor, including realized and unrealized gains or losses, collected and accrued income, and administrative expenses, and allocates earnings to each plan in the master trusts on a pro rata basis.

Within each pension plan, the record of each Registrant Subsidiary’s beneficial interest in the plan assets is maintained by the plan’s actuary and is updated quarterly. Assets for each Registrant Subsidiary are increased for investment net income and contributions, and are decreased for benefit payments. A plan’s investment net income/loss (i.e. interest and dividends, realized and unrealized gains and losses and expenses) is allocated to the Registrant Subsidiaries participating in that plan based on the value of assets for each Registrant Subsidiary at the beginning of the quarter adjusted for contributions and benefit payments made during the quarter.

Entergy Corporation and its subsidiaries fund pension plans in an amount not less than the minimum required contribution under the Employee Retirement Income Security Act of 1974, as amended, and the Internal Revenue Code of 1986, as amended. The assets of the plans include common and preferred stocks, fixed-income securities, interest in a money market fund, and insurance contracts. The Registrant Subsidiaries’ pension costs are recovered from customers as a component of cost of service in each of their respective jurisdictions.

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Components of Qualified Net Pension Cost and Other Amounts Recognized as a Regulatory Asset and/or Accumulated Other Comprehensive Income (AOCI)

Entergy Corporation and its subsidiaries’ total 2016, 2015, and 2014 qualified pension costs and amounts recognized as a regulatory asset and/or other comprehensive income, including amounts capitalized, included the following components:



	2016			2015			2014
	(In Thousands)
Net periodic pension cost:
Service cost - benefits earned during the period		$143,244			$175,046			$140,436
Interest cost on projected benefit obligation	261,613			302,777			290,076
Expected return on assets	(389,465		)	(394,618		)	(361,462		)
Amortization of prior service cost	1,079			1,561			1,600
Recognized net loss	195,298			235,922			145,095
Curtailment loss	3,084			374			—
Special termination benefit	—			76			732
Net periodic pension costs		$214,853			$321,138			$216,477
Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)
Arising this period:
Net loss		$203,229			$50,762			$1,389,912
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
Amortization of prior service cost	(1,079		)	(1,561		)	(1,600		)
Acceleration of prior service cost to curtailment	(1,045		)	(374		)	—
Amortization of net loss	(195,298		)	(235,922		)	(145,095		)
Total		$5,807			($187,095	)		$1,243,217
Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax)		$220,660			$134,043			$1,459,694
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year:
Prior service cost		$261			$1,079			$1,561
Net loss		$227,720			$195,321			$237,013

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The Registrant Subsidiaries’ total 2016, 2015, and 2014 qualified pension costs and amounts recognized as a regulatory asset and/or other comprehensive income, including amounts capitalized, for their employees included the following components:



2016	Entergy Arkansas			Entergy Louisiana			Entergy Mississippi			Entergy New Orleans			Entergy Texas			System Energy
	(In Thousands)
Net periodic pension cost:
Service cost - benefits earned during the period		$20,724			$28,194			$6,250			$2,625			$5,664			$6,263
Interest cost on projected benefit obligation	52,219			59,478			15,245			7,256			14,228			11,966
Expected return on assets	(79,087		)	(88,383		)	(23,923		)	(10,748		)	(24,248		)	(17,836		)
Recognized net loss	43,745			47,783			11,938			6,460			9,358			10,415
Net pension cost		$37,601			$47,072			$9,510			$5,593			$5,002			$10,808
Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)
Arising this period:
Net loss		$60,968			$46,742			$10,942			$5,463			$3,816			$20,805
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
Amortization of net loss	(43,745		)	(47,783		)	(11,938		)	(6,460		)	(9,358		)	(10,415		)
Total		$17,223			($1,041	)		($996	)		($997	)		($5,542	)		$10,390
Total recognized as net periodic pension (income)/cost regulatory asset, and/or AOCI (before tax)		$54,824			$46,031			$8,514			$4,596			($540	)		$21,198
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year
Net loss		$46,560			$49,417			$12,213			$6,632			$9,241			$11,857

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2015	Entergy Arkansas			Entergy Louisiana			Entergy Mississippi			Entergy New Orleans			Entergy Texas			System Energy
	(In Thousands)
Net periodic pension cost:
Service cost - benefits earned during the period		$26,646			$34,396			$7,929			$3,395			$6,582			$7,827
Interest cost on projected benefit obligation	61,885			69,465			18,007			8,432			17,414			13,970
Expected return on assets	(80,102		)	(90,803		)	(24,420		)	(10,899		)	(24,887		)	(18,271		)
Recognized net loss	54,254			59,802			14,896			8,053			12,950			13,055
Net pension cost		$62,683			$72,860			$16,412			$8,981			$12,059			$16,581
Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)
Arising this period:
Net loss		$16,687			$16,618			$6,329			$1,853			($4,488	)		$101
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
Amortization of net loss	(54,254		)	(59,802		)	(14,896		)	(8,053		)	(12,950		)	(13,055		)
Total		($37,567	)		($43,184	)		($8,567	)		($6,200	)		($17,438	)		($12,954	)
Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax)		$25,116			$29,676			$7,845			$2,781			($5,379	)		$3,627
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year
Net loss		$43,747			$47,809			$11,938			$6,460			$9,358			$10,414

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2014	Entergy Arkansas			Entergy Louisiana			Entergy Mississippi			Entergy New Orleans			Entergy Texas			System Energy
	(In Thousands)
Net periodic pension cost:
Service cost - benefits earned during the period		$20,090			$25,706			$6,094			$2,666			$5,142			$5,785
Interest cost on projected benefit obligation	59,537			66,984			17,273			8,164			17,746			13,561
Expected return on assets	(73,218		)	(83,746		)	(22,794		)	(10,019		)	(23,723		)	(16,619		)
Amortization of prior service cost	—			—			—			—			—			2
Recognized net loss	35,956			40,446			9,415			5,796			9,356			9,500
Net pension cost		$42,365			$49,390			$9,988			$6,607			$8,521			$12,229
Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax)
Arising this period:
Net gain		$300,907			$318,932			$88,199			$38,161			$65,363			$60,763
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year:
Amortization of prior service cost	—			—			—			—			—			(2		)
Amortization of net loss	(35,956		)	(40,446		)	(9,415		)	(5,796		)	(9,356		)	(9,500		)
Total		$264,951			$278,486			$78,784			$32,365			$56,007			$51,261
Total recognized as net periodic pension income, regulatory asset, and/or AOCI (before tax)		$307,316			$327,876			$88,772			$38,972			$64,528			$63,490
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year
Net loss		$54,254			$59,802			$14,896			$8,053			$12,950			$13,055

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Qualified Pension Obligations, Plan Assets, Funded Status, Amounts Recognized in the Balance Sheet

Qualified pension obligations, plan assets, funded status, amounts recognized in the Consolidated Balance Sheets for Entergy Corporation and its Subsidiaries as of December 31, 2016 and 2015 are as follows:



	2016			2015
	(In Thousands)
Change in Projected Benefit Obligation (PBO)
Balance at January 1		$6,848,238			$7,230,542
Service cost	143,244			175,046
Interest cost	261,613			302,777
Curtailment	2,039			—
Special termination benefit	—			76
Actuarial (gain)/loss	209,360			(460,986		)
Employee contributions	23			524
Benefits paid	(321,950		)	(399,741		)
Balance at December 31		$7,142,567			$6,848,238
Change in Plan Assets
Fair value of assets at January 1		$4,707,433			$4,827,966
Actual return on plan assets	395,596			(117,130		)
Employer contributions	390,100			395,814
Employee contributions	23			524
Benefits paid	(321,950		)	(399,741		)
Fair value of assets at December 31		$5,171,202			$4,707,433
Funded status		($1,971,365	)		($2,140,805	)
Amount recognized in the balance sheet
Non-current liabilities		($1,971,365	)		($2,140,805	)
Amount recognized as a regulatory asset
Net loss		$2,326,349			$2,300,222
Amount recognized as AOCI (before tax)
Prior service cost		$659			$2,784
Net loss	619,276			637,472
		$619,935			$640,256

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Qualified pension obligations, plan assets, funded status, amounts recognized in the Balance Sheets for the Registrant Subsidiaries as of December 31, 2016 and 2015 are as follows:



2016	Entergy Arkansas			Entergy Louisiana			Entergy Mississippi			Entergy New Orleans			Entergy Texas			System Energy
	(In Thousands)
Change in Projected Benefit Obligation (PBO)
Balance at January 1		$1,400,511			$1,564,710			$408,604			$191,064			$383,627			$311,542
Service cost	20,724			28,194			6,250			2,625			5,664			6,263
Interest cost	52,219			59,478			15,245			7,256			14,228			11,966
Actuarial (gain)/loss	62,187			48,357			11,343			5,573			4,274			20,661
Benefits paid	(81,331		)	(76,506		)	(22,241		)	(9,054		)	(21,427		)	(15,051		)
Balance at December 31		$1,454,310			$1,624,233			$419,201			$197,464			$386,366			$335,381
Change in Plan Assets
Fair value of assets at January 1		$959,618			$1,071,234			$292,297			$129,975			$298,378			$212,006
Actual return on plan assets	80,306			89,998			24,325			10,858			24,705			17,692
Employer contributions	82,999			84,421			19,968			10,709			15,920			20,497
Benefits paid	(81,331		)	(76,506		)	(22,241		)	(9,054		)	(21,427		)	(15,051		)
Fair value of assets at December 31		$1,041,592			$1,169,147			$314,349			$142,488			$317,576			$235,144
Funded status		($412,718	)		($455,086	)		($104,852	)		($54,976	)		($68,790	)		($100,237	)
Amounts recognized in the balance sheet (funded status)
Non-current liabilities		($412,718	)		($455,086	)		($104,852	)		($54,976	)		($68,790	)		($100,237	)
Amounts recognized as regulatory asset
Net loss		$701,774			$686,337			$189,409			$94,944			$153,544			$169,897
Amounts recognized as AOCI (before tax)
Net loss		$—			$51,660			$—			$—			$—			$—

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2015	Entergy Arkansas			Entergy Louisiana			Entergy Mississippi			Entergy New Orleans			Entergy Texas			System Energy
	(In Thousands)
Change in Projected Benefit Obligation (PBO)
Balance at January 1		$1,485,718			$1,666,535			$432,169			$202,555			$418,498			$334,312
Service cost	26,646			34,396			7,929			3,395			6,582			7,827
Interest cost	61,885			69,465			18,007			8,432			17,414			13,970
Actuarial (gain)/loss	(87,617		)	(101,361		)	(25,492		)	(12,289		)	(36,862		)	(23,720		)
Benefits paid	(86,121		)	(104,325		)	(24,009		)	(11,029		)	(22,005		)	(20,847		)
Balance at December 31		$1,400,511			$1,564,710			$408,604			$191,064			$383,627			$311,542
Change in Plan Assets
Fair value of assets at January 1		$977,521			$1,113,359			$301,250			$133,344			$310,713			$217,621
Actual return on plan assets	(24,201		)	(27,175		)	(7,401		)	(3,243		)	(7,487		)	(5,550		)
Employer contributions	92,419			89,375			22,457			10,903			17,157			20,782
Benefits paid	(86,121		)	(104,325		)	(24,009		)	(11,029		)	(22,005		)	(20,847		)
Fair value of assets at December 31		$959,618			$1,071,234			$292,297			$129,975			$298,378			$212,006
Funded status		($440,893	)		($493,476	)		($116,307	)		($61,089	)		($85,249	)		($99,536	)
Amounts recognized in the balance sheet (funded status)
Non-current liabilities		($440,893	)		($493,476	)		($116,307	)		($61,089	)		($85,249	)		($99,536	)
Amounts recognized as regulatory asset
Net loss		$684,552			$687,305			$190,406			$95,941			$159,085			$159,508
Amounts recognized as AOCI (before tax)
Net loss		$—			$51,733			$—			$—			$—			$—

Accumulated Pension Benefit Obligation

The accumulated benefit obligation for Entergy’s qualified pension plans was $6.7 billion and $6.3 billion at December 31, 2016 and 2015, respectively.

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The qualified pension accumulated benefit obligation for each of the Registrant Subsidiaries for their employees as of December 31, 2016 and 2015 was as follows:



	December 31,
	2016		2015
	(In Thousands)
Entergy Arkansas		$1,379,265		$1,309,903
Entergy Louisiana		$1,513,884		$1,436,535
Entergy Mississippi		$396,081		$379,775
Entergy New Orleans		$186,247		$176,692
Entergy Texas		$365,251		$359,687
System Energy		$315,131		$286,917

Other Postretirement Trusts



2016	Level 1			Level 2			Level 3		Total
	(In Thousands)
Equity securities:
Common collective trust (c)										$368,704
Fixed income securities:
U.S. Government securities	30,632		(b)	43,097		(a)	—		73,729
Corporate debt instruments	—			58,787		(a)	—		58,787
Registered investment companies	3,123		(d)	—			—		3,123
Other	—			45,389		(f)	—		45,389
Total investments		$33,755			$147,273			$—		$549,732
Other pending transactions									104
Plus: Other postretirement assets included in the investments of the qualified pension trust									46,824
Total fair value of other postretirement assets										$596,660

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2015	Level 1			Level 2			Level 3		Total
	(In Thousands)
Equity securities:
Common collective trust (c)										$348,604
Fixed income securities:
U.S. Government securities	33,789		(b)	42,222		(a)	—		76,011
Corporate debt instruments	—			62,629		(a)	—		62,629
Registered investment companies	3,572		(d)	—			—		3,572
Other	—			49,677		(f)	—		49,677
Total investments		$37,361			$154,528			$—		$540,493
Other pending transactions									480
Plus: Other postretirement assets included in the investments of the qualified pension trust									38,096
Total fair value of other postretirement assets										$579,069


(a)	Certain preferred stocks and certain fixed income debt securities (corporate, government, and securitized) are stated at fair value as determined by broker quotes.


(b)	Common stocks, certain preferred stocks, and certain fixed income debt securities (government) are stated at fair value determined by quoted market prices.

(c)

The common collective trusts hold investments in accordance with stated objectives. The investment strategy of the trusts is to capture the growth potential of equity markets by replicating the performance of a specified index. Net asset value per share of common collective trusts estimate fair value. Certain of these common collective trusts are not publicly quoted, and are valued by the fund administrators using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table.


(d)	Registered investment companies are money market mutual funds with a stable net asset value of one dollar per share. Registered investment companies may hold investments in domestic and international bond markets or domestic equities and estimate fair value using net asset value per share.


(e)	Certain of these registered investment companies are not publicly quoted, and are valued by the fund administrators using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table.


(f)	The other remaining assets are U.S. municipal and foreign government bonds stated at fair value as determined by broker quotes.


(g)	The unallocated insurance contract investments are recorded at contract value, which approximates fair value. The contract value represents contributions made under the contract, plus interest, less funds used to pay benefits and contract expenses, and less distributions to the master trust.

(h)

103-12 investment entities hold investments in accordance with stated objectives. The investment strategy of the investment entities is to capture the growth potential of international equity markets by replicating the performance of a specified index. 103-12 investment entities estimate fair value using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table.

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Estimated Future Benefit Payments

Based upon the assumptions used to measure Entergy’s qualified pension and other postretirement benefit obligations at December 31, 2016, and including pension and other postretirement benefits attributable to estimated future employee service, Entergy expects that benefits to be paid and the Medicare Part D subsidies to be received over the next ten years for Entergy Corporation and its subsidiaries will be as follows:



	Estimated Future Benefits Payments
	Qualified Pension		Non-Qualified Pension		Other Postretirement (before Medicare Subsidy)		Estimated Future Medicare Subsidy Receipts
	(In Thousands)
Year(s)
2017		$316,770		$31,687		$83,638		$330
2018		$328,101		$12,251		$88,235		$1,069
2019		$343,982		$11,428		$92,511		$1,204
2020		$362,642		$13,183		$95,167		$1,357
2021		$375,354		$11,321		$98,043		$1,518
2022 - 2026		$2,128,911		$79,373		$510,419		$10,336

Based upon the same assumptions, Entergy expects that benefits to be paid and the Medicare Part D subsidies to be received over the next ten years for the Registrant Subsidiaries for their employees will be as follows:



Estimated Future Qualified Pension Benefits Payments	Entergy Arkansas		Entergy Louisiana		Entergy Mississippi		Entergy New Orleans		Entergy Texas		System Energy
	(In Thousands)
Year(s)
2017		$76,603		$73,648		$21,416		$8,829		$20,614		$14,314
2018		$77,401		$75,927		$21,944		$9,129		$21,230		$14,681
2019		$78,484		$78,351		$22,423		$9,467		$21,753		$15,147
2020		$79,804		$81,148		$23,135		$9,979		$22,429		$15,747
2021		$81,382		$84,705		$23,801		$10,577		$23,048		$16,359
2022 - 2026		$436,154		$479,274		$127,886		$60,044		$122,832		$98,295



Estimated Future Non-Qualified Pension Benefits Payments	Entergy Arkansas		Entergy Louisiana		Entergy Mississippi		Entergy New Orleans		Entergy Texas
	(In Thousands)
Year(s)
2017		$242		$233		$137		$20		$773
2018		$351		$222		$126		$20		$741
2019		$282		$211		$124		$51		$716
2020		$318		$200		$245		$34		$799
2021		$282		$189		$167		$36		$690
2022 - 2026		$2,192		$776		$901		$361		$3,637

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Estimated Future Other Postretirement Benefits Payments (before Medicare Part D Subsidy)	Entergy Arkansas		Entergy Louisiana		Entergy Mississippi		Entergy New Orleans		Entergy Texas		System Energy
	(In Thousands)
Year(s)
2017		$16,195		$19,284		$4,522		$4,054		$7,137		$3,331
2018		$16,505		$19,986		$4,772		$4,086		$7,576		$3,392
2019		$16,524		$20,700		$4,859		$4,126		$7,904		$3,505
2020		$16,410		$21,218		$5,032		$4,084		$8,155		$3,555
2021		$16,610		$21,804		$5,192		$4,065		$8,443		$3,706
2022 - 2026		$82,670		$114,287		$26,500		$19,532		$42,855		$19,376



Estimated Future Medicare Part D Subsidy	Entergy Arkansas		Entergy Louisiana		Entergy Mississippi		Entergy New Orleans		Entergy Texas		System Energy
	(In Thousands)
Year(s)
2017		$73		$75		$26		$18		$30		$10
2018		$235		$242		$83		$53		$93		$33
2019		$265		$268		$91		$56		$100		$40
2020		$296		$297		$99		$59		$108		$47
2021		$325		$330		$107		$61		$115		$54
2022 - 2026		$2,119		$2,193		$666		$353		$723		$424

Contributions

Entergy currently expects to contribute approximately $408.6 million to its qualified pension plans and approximately $53.1 million to other postretirement plans in 2017. The expected 2017 pension and other postretirement plan contributions of the Registrant Subsidiaries for their employees are shown below. The 2017 required pension contributions will be known with more certainty when the January 1, 2017 valuations are completed, which is expected by April 1, 2017.

The Registrant Subsidiaries expect to contribute approximately the following to the qualified pension and other postretirement plans for their employees in 2017:



	Entergy Arkansas		Entergy Louisiana		Entergy Mississippi		Entergy New Orleans		Entergy Texas		System Energy
	(In Thousands)
Pension Contributions		$79,386		$87,702		$19,117		$9,904		$17,000		$18,096
Other Postretirement Contributions		$525		$19,284		$140		$3,669		$3,231		$690

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Actuarial Assumptions

The significant actuarial assumptions used in determining the pension PBO and the other postretirement benefit APBO as of December 31, 2016 and 2015 were as follows:



	2016	2015
Weighted-average discount rate:
Qualified pension	4.30% - 4.49% Blended 4.39%	4.51% - 4.79% Blended 4.67%
Other postretirement	4.30%	4.60%
Non-qualified pension	3.63%	3.84%
Weighted-average rate of increase in future compensation levels	3.98%	4.23%
Assumed health care trend rate:
Pre-65	6.55%	6.75%
Post-65	7.25%	7.55%
Ultimate rate	4.75%	4.75%
Year ultimate rate is reached and beyond:
Pre-65	2026	2024
Post-65	2026	2024

The significant actuarial assumptions used in determining the net periodic pension and other postretirement benefit costs for 2016, 2015, and 2014 were as follows:



	2016	2015	2014
Weighted-average discount rate:
Qualified pension:
Service cost	5.00%	4.27%	5.14%
Interest cost	3.90%	4.27%	5.14%
Other postretirement:
Service cost	4.92%	4.23%	5.05%
Interest cost	3.78%	4.23%	5.05%
Non-qualified pension:
Service cost	3.65%	3.61%	4.29%
Interest cost	3.10%	3.61%	4.29%
Weighted-average rate of increase in future compensation levels	4.23%	4.23%	4.23%
Expected long-term rate of return on plan assets:
Pension assets	7.75%	8.25%	8.50%
Other postretirement non-taxable assets	7.75%	8.05%	8.30%
Other postretirement taxable assets	6.00%	6.25%	6.50%
Assumed health care trend rate:
Pre-65	6.75%	7.10%	7.25%
Post-65	7.55%	7.70%	7.00%
Ultimate rate	4.75%	4.75%	4.75%
Year ultimate rate is reached and beyond:
Pre-65	2024	2023	2022
Post-65	2024	2023	2022

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In 2016, Entergy refined its approach to estimating the service cost and interest cost components of qualified pension, other postretirement, and non-qualified pension costs. Under the refined approach, instead of using the weighted-average obligation discount rates at the beginning of the year, 2016 service cost and interest costs’ expected cash flows were discounted by the applicable spot rates. The refinement in approach was a change in accounting estimate and, accordingly, the effect was reflected prospectively. The measurement of the benefit obligation was not affected.

With respect to the mortality assumptions, Entergy used the RP-2014 Employee and Healthy Annuitant Tables (adjusted to base year 2006) with a fully generational MP-2016 projection scale, in determining its December 31, 2016 pension plans’ PBOs and other postretirement benefit APBO. Entergy used the RP-2014 Employee and Healthy Annuitant Tables (adjusted to base year 2006) with a fully generational MP-2015 projection scale, in determining its December 31, 2015 pension plans’ PBOs and other postretirement benefit APBO.

Entergy’s health care cost trend is affected by both medical cost inflation, and with respect to capped costs, the effects of general inflation. A one percentage point change in Entergy’s assumed health care cost trend rate for 2016 would have the following effects:



	1 Percentage Point Increase				1 Percentage Point Decrease
2016	Impact on the APBO		Impact on the sum of service costs and interest cost		Impact on the APBO			Impact on the sum of service costs and interest cost
	Increase /(Decrease) (In Thousands)
Entergy Corporation and its subsidiaries		$173,057		$12,281		($144,460	)		($9,928	)

The Registrant Subsidiaries’ health care cost trend is affected by both medical cost inflation, and with respect to capped costs, the effects of general inflation. A one percentage point change in the assumed health care cost trend rate for 2016 would have the following effects for the Registrant Subsidiaries for their employees:



	1 Percentage Point Increase				1 Percentage Point Decrease
2016	Impact on the APBO		Impact on the sum of service costs and interest cost		Impact on the APBO			Impact on the sum of service costs and interest cost
	Increase/(Decrease) (In Thousands)
Entergy Arkansas		$25,743		$1,609		($21,520	)		($1,313	)
Entergy Louisiana		$37,874		$2,910		($31,510	)		($2,343	)
Entergy Mississippi		$7,997		$625		($6,710	)		($498	)
Entergy New Orleans		$4,941		$259		($4,184	)		($214	)
Entergy Texas		$14,187		$758		($11,896	)		($619	)
System Energy		$7,750		$489		($6,401	)		($394	)

Defined Contribution Plans

Entergy sponsors the Savings Plan of Entergy Corporation and Subsidiaries (System Savings Plan). The System Savings Plan is a defined contribution plan covering eligible employees of Entergy and certain of its subsidiaries. The participating employing Entergy subsidiary makes matching contributions to the System Savings Plan for all eligible participating employees in an amount equal to either 70% or 100% of the participants’ basic contributions, up to 6% of their eligible earnings per pay period. The matching contribution is allocated to investments as directed by the employee.

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Entergy also sponsors the Savings Plan of Entergy Corporation and Subsidiaries IV (established in March 2002), the Savings Plan of Entergy Corporation and Subsidiaries VI (established in April 2007), and the Savings Plan of Entergy Corporation and Subsidiaries VII (established in April 2007) to which matching contributions are also made. The plans are defined contribution plans that cover eligible employees, as defined by each plan, of Entergy and certain of its subsidiaries.

Entergy’s subsidiaries’ contributions to defined contribution plans collectively were $47 million in 2016, $44.4 million in 2015, and $43.3 million in 2014. The majority of the contributions were to the System Savings Plan.

The Registrant Subsidiaries’ 2016, 2015, and 2014 contributions to defined contribution plans for their employees were as follows:



Year	Entergy Arkansas		Entergy Louisiana		Entergy Mississippi		Entergy New Orleans		Entergy Texas
	(In Thousands)
2016		$3,528		$4,746		$1,997		$708		$1,778
2015		$3,242		$4,324		$1,920		$721		$1,620
2014		$3,044		$4,133		$1,855		$710		$1,563

NOTE 12. STOCK-BASED COMPENSATION (Entergy Corporation)

Entergy grants stock options, restricted stock, performance units, and restricted stock unit awards to key employees of the Entergy subsidiaries under its Equity Ownership Plans which are shareholder-approved stock-based compensation plans. The Equity Ownership Plan, as restated in February 2003, expired December 31, 2016. Effective January 1, 2007, Entergy’s shareholders approved the 2007 Equity Ownership and Long-Term Cash Incentive Plan (2007 Plan). The maximum aggregate number of common shares that were available for issuance from the 2007 Plan for stock-based awards was 7,000,000 with no more than 2,000,000 available for non-option grants. The 2007 Plan, which only applied to awards granted between January 1, 2007 and May 5, 2011, will expire after 10 years. Effective May 6, 2011, Entergy’s shareholders approved the 2011 Equity Ownership and Long-Term Cash Incentive Plan (2011 Plan). The maximum number of common shares that were available for issuance from the 2011 Plan for stock-based awards was 5,500,000 with no more than 2,000,000 available for incentive stock option grants. The 2011 Plan, which only applied to awards granted between May 6, 2011 and May 7, 2015, will expire after 10 years. Effective May 8, 2015, Entergy’s shareholders approved the 2015 Equity Ownership and Long-Term Cash Incentive Plan (2015 Plan). The maximum number of common shares that can be issued from the 2015 Plan for stock-based awards is 6,900,000 with no more than 1,500,000 available for incentive stock option grants. The 2015 Plan, which only applies to awards granted on or after May 6, 2011, will expire after 10 years. As of December 31, 2016, there were 5,192,463 authorized shares remaining for stock-based awards, including 1,500,000 for incentive stock option grants.

Stock Options

Stock options are granted at exercise prices that equal the closing market price of Entergy Corporation common stock on the date of grant. Generally, stock options granted will become exercisable in equal amounts on each of the first three anniversaries of the date of grant. Unless they are forfeited previously under the terms of the grant, options expire 10 years after the date of the grant if they are not exercised.

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The following table includes financial information for stock options for each of the years presented:



	2016	2015	2014
	(In Millions)
Compensation expense included in Entergy’s consolidated net income	$4.4	$4.3	$4.1
Tax benefit recognized in Entergy’s consolidated net income	$1.7	$1.6	$1.6
Compensation cost capitalized as part of fixed assets and inventory	$0.7	$0.7	$0.7

Entergy determines the fair value of the stock option grants by considering factors such as lack of marketability, stock retention requirements, and regulatory restrictions on exercisability in accordance with accounting standards. The stock option weighted-average assumptions used in determining the fair values are as follows:



	2016	2015	2014
Stock price volatility	20.38%	23.62%	24.67%
Expected term in years	7.25	7.06	6.95
Risk-free interest rate	1.77%	1.59%	2.16%
Dividend yield	4.50%	4.50%	4.75%
Dividend payment per share	$3.42	$3.34	$3.32

Stock price volatility is calculated based upon the daily public stock price volatility of Entergy Corporation common stock over a period equal to the expected term of the award. The expected term of the options is based upon historical option exercises and the weighted average life of options when exercised and the estimated weighted average life of all vested but unexercised options. In 2008, Entergy implemented stock ownership guidelines for its senior executive officers. These guidelines require an executive officer to own shares of Entergy Corporation common stock equal to a specified multiple of his or her salary. Until an executive officer achieves this ownership position the executive officer is required to retain 75% of the net-of-tax net profit upon exercise of the option to be held in Entergy Corporation common stock. The reduction in fair value of the stock options due to this restriction is based upon an estimate of the call option value of the reinvested gain discounted to present value over the applicable reinvestment period.

A summary of stock option activity for the year ended December 31, 2016 and changes during the year are presented below:



	Number of Options		Weighted- Average Exercise Price	Aggregate Intrinsic Value	Weighted- Average Contractual Life
Options outstanding as of January 1, 2016	7,399,820		$84.19
Options granted	696,900		$70.56
Options exercised	(488,131	)	$67.83
Options forfeited/expired	(471,379	)	$69.99
Options outstanding as of December 31, 2016	7,137,210		$84.91	$—	3.35 years
Options exercisable as of December 31, 2016	6,011,816		$86.96	$—	2.38 years
Weighted-average grant-date fair value of options granted during 2016	$7.40

The weighted-average grant-date fair value of options granted during the year was $11.41 for 2015 and $8.71 for 2014. The total intrinsic value of stock options exercised was $5 million during 2016, $5 million during 2015, and $26 million during 2014. The intrinsic value, which has no effect on net income, of the outstanding stock options exercised is calculated by the positive difference between the weighted average exercise price of the stock options granted and Entergy Corporation’s common stock price as of December 31, 2016. Because Entergy’s year-end stock

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price was less than the weighted average exercise price, the aggregate intrinsic value of stock options outstanding as of December 31, 2016 was zero. The intrinsic value of “in the money” stock options is $11 million as of December 31, 2016. Entergy recognizes compensation cost over the vesting period of the options based on their grant-date fair value. The total fair value of options that vested was approximately $5 million during 2016, $4 million during 2015, and $4 million during 2014. Cash received from option exercises was $33 million for the year ended December 31, 2016. The tax benefits realized from options exercised was $2 million for the year ended December 31, 2016.

The following table summarizes information about stock options outstanding as of December 31, 2016:



				Options Outstanding			Options Exercisable
Range of				As of	Weighted-Average Remaining Contractual Life-Yrs.	Weighted Average Exercise Price	Number Exercisable as of	Weighted Average Exercise Price
Exercise Prices				12/31/2016	Weighted-Average Remaining Contractual Life-Yrs.	Weighted Average Exercise Price	12/31/2016	Weighted Average Exercise Price
	$51	-	$64.99	798,308	6.68	$63.75	627,893	$63.90
	$65	-	$78.99	2,853,753	4.66	$74.47	2,161,853	$75.72
	$79	-	$91.99	2,050,549	1.84	$91.40	1,787,470	$91.62
	$92	-	$108.20	1,434,600	1.06	$108.20	1,434,600	$108.20
	$51	-	$108.20	7,137,210	3.35	$84.91	6,011,816	$86.96

Stock-based compensation cost related to non-vested stock options outstanding as of December 31, 2016 not yet recognized is approximately $6 million and is expected to be recognized over a weighted-average period of 1.70 years.

Restricted Stock Awards

In January 2016 the Board approved and Entergy granted 370,000 restricted stock awards under the 2015 Equity Ownership and Long-term Cash Incentive Plan. The restricted stock awards were made effective as of January 28, 2016 and were valued at $70.56 per share, which was the closing price of Entergy Corporation’s common stock on that date. One-third of the restricted stock awards will vest upon each anniversary of the grant date and are expensed ratably over the three year vesting period. Shares of restricted stock have the same dividend and voting rights as other common stock and are considered issued and outstanding shares of Entergy upon vesting.

The following table includes information about the restricted stock awards outstanding as of December 31, 2016:



	Shares		Weighted-Average Grant Date Fair Value Per Share
Outstanding shares at January 1, 2016	642,729		$75.88
Granted	401,358		$70.89
Vested	(324,862	)	$71.83
Forfeited	(35,751	)	$77.38
Outstanding shares at December 31, 2016	683,474		$74.80

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The following table includes financial information for restricted stock for each of the years presented:



	2016	2015	2014
	(In Millions)
Compensation expense included in Entergy’s consolidated net income	$19.8	$19.5	$19.3
Tax benefit recognized in Entergy’s consolidated net income	$7.6	$7.5	$7.5
Compensation cost capitalized as part of fixed assets and inventory	$4.5	$3.9	$3.1

The total fair value of the restricted stock awards granted was $29 million, $29 million, and $24 million for the years ended December 31, 2016, 2015, and 2014, respectively.

The total fair value of the restricted stock awards vested was $23 million, $29 million, and $17 million for the years ended December 31, 2016, 2015, and 2014, respectively.

Long-Term Performance Unit Program

Entergy grants long-term incentive awards earned under its stock benefit plans in the form of performance units, which represents the value of one share of Entergy Corporation common stock at the end of the three-year performance period, plus dividends accrued during the performance period. The Long-Term Performance Unit Program specifies a minimum, target, and maximum achievement level, the achievement of which will determine the number of performance units that may be earned. Entergy measures performance by assessing Entergy’s total shareholder return relative to the total shareholder return of the companies in the Philadelphia Utility Index. There is no payout for performance that falls within the lowest quartile of performance of the peer companies. For top quartile performance, a maximum payout of 200% of target is earned.

The costs of incentive awards are charged to income over the 3-year period. In January 2016 the Board approved and Entergy granted 199,800 performance units under the 2015 Equity Ownership and Long-Term Cash Incentive Plan. The performance units were made effective as of January 28, 2016, and were valued at $84.52 per share. Shares of the performance units have the same dividend and voting rights as other common stock, are considered issued and outstanding shares of Entergy upon vesting, and are expensed ratably over the 3-year vesting period.

The following table includes information about the long-term performance units outstanding at the target level as of December 31, 2016:



	Shares		Weighted-Average Grant Date Fair Value Per Share
Outstanding shares at January 1, 2016	568,482		$75.33
Granted	241,236		$85.26
Vested	(54,103	)	$65.36
Forfeited	(184,064	)	$70.53
Outstanding shares at December 31, 2016	571,551		$82.02

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The following table includes financial information for the long-term performance units for each of the years presented:



	2016	2015		2014
	(In Millions)
Compensation expense included in Entergy’s consolidated net income	$12.3		$11.8		$10.7
Tax benefit recognized in Entergy’s consolidated net income	$4.8		$4.5		$4.1
Compensation cost capitalized as part of fixed assets and inventory	$2.9		$2.3		$1.5

The total fair value of the long-term performance units granted was $21 million, $16 million and $16 million for the years ended December 31, 2016, 2015, and 2014, respectively.

In January 2016, Entergy issued 54,103 shares of Entergy Corporation common stock at a share price of $68.09 for awards earned and dividends accrued under the 2013-2015 Long-Term Performance Unit Program. In January 2015, Entergy issued 105,503 shares of Entergy Corporation common stock at a share price of $88.67 for awards earned and dividends accrued under the 2012-2014 Long-Term Performance Unit Program. There was no payout in 2014 for the performance units applicable to the 2011-2013 Long-Term Performance Unit Program.

Restricted Stock Unit Awards

Entergy grants restricted stock unit awards earned under its stock benefit plans in the form of stock units that are subject to time-based restrictions. The restricted stock units may be settled in shares of Entergy Corporation common stock or the cash value of shares of Entergy Corporation common stock at the time of vesting. The costs of restricted stock unit awards are charged to income over the restricted period, which varies from grant to grant. The average vesting period for restricted stock unit awards granted is 42 months. As of December 31, 2016, there were 181,650 unvested restricted stock units that are expected to vest over an average period of 30 months.

The following table includes information about the restricted stock unit awards outstanding as of December 31, 2016:



	Shares		Weighted-Average Grant Date Fair Value Per Share
Outstanding shares at January 1, 2016	145,018		$72.03
Granted	70,800		$76.25
Vested	(30,668	)	$70.66
Forfeited	(3,500	)	$66.83
Outstanding shares at December 31, 2016	181,650		$74.94

The following table includes financial information for restricted stock unit awards for each of the years presented:



	2016	2015	2014
	(In Millions)
Compensation expense included in Entergy’s consolidated net income	$2.2	$0.9	$2.2
Tax benefit recognized in Entergy’s consolidated net income	$0.8	$0.4	$0.9
Compensation cost capitalized as part of fixed assets and inventory	$0.4	$0.3	$0.3

The total fair value of the restricted stock unit awards granted was $5 million, $4 million, and $3 million for the years ended December 31, 2016, 2015, and 2014, respectively.

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The total fair value of the restricted stock unit awards vested was $2 million, $4 million, and $3 million for the years ended December 31, 2016, 2015, and 2014, respectively.

Entergy paid $2 million, $1 million, and $2 million for the years ended December 31, 2016, 2015, and 2014, respectively, for awards under the Restricted Stock Units Awards Plan.

NOTE 13. BUSINESS SEGMENT INFORMATION (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Entergy’s reportable segments as of December 31, 2016 are Utility and Entergy Wholesale Commodities. Utility includes the generation, transmission, distribution, and sale of electric power in portions of Arkansas, Louisiana, Mississippi, and Texas, and natural gas utility service in portions of Louisiana. Entergy Wholesale Commodities includes the ownership, operation, and decommissioning of nuclear power plants located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. Entergy Wholesale Commodities also includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. “All Other” includes the parent company, Entergy Corporation, and other business activity.

Entergy’s segment financial information is as follows:



2016	Utility		Entergy Wholesale Commodities*			All Other			Eliminations			Consolidated
	(In Thousands)
Operating revenues		$8,996,106		$1,849,638			$—			($99	)		$10,845,645
Asset write-offs, impairments, and related charges		$—		$2,835,637			$—			$—			$2,835,637
Depreciation, amortization, & decommissioning		$1,298,043		$374,922			$1,647			$—			$1,674,612
Interest and investment income		$189,994		$108,466			$27,385			($180,718	)		$145,127
Interest expense		$557,546		$22,858			$139,090			($53,124	)		$666,370
Income taxes		$424,388		($1,192,263	)		($49,384	)		$—			($817,259	)
Consolidated net income (loss)		$1,151,133		($1,493,124	)		($94,917	)		($127,595	)		($564,503	)
Total assets		$41,098,751		$6,696,038			$1,283,816			($3,174,171	)		$45,904,434
Investment in affiliates - at equity		$198		$—			$—			$—			$198
Cash paid for long-lived asset additions		$3,754,225		$289,639			$393			$—			$4,044,257

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2015	Utility		Entergy Wholesale Commodities*			All Other			Eliminations			Consolidated
	(In Thousands)
Operating revenues		$9,451,486		$2,061,827			$—			($62	)		$11,513,251
Asset write-offs, impairments, and related charges		$68,672		$2,036,234			$—			$—			$2,104,906
Depreciation, amortization, & decommissioning		$1,238,832		$376,560			$2,156			$—			$1,617,548
Interest and investment income		$191,546		$148,654			$34,303			($187,441	)		$187,062
Interest expense		$543,132		$26,788			$129,750			($56,201	)		$643,469
Income taxes		$16,761		($610,339	)		($49,349	)		$—			($642,927	)
Consolidated net income (loss)		$1,114,516		($1,065,657	)		($74,353	)		($131,240	)		($156,734	)
Total assets		$38,356,906		$8,210,183			($461,505	)		($1,457,903	)		$44,647,681
Investment in affiliates - at equity		$199		$4,142			$—			$—			$4,341
Cash paid for long-lived asset additions		$2,495,194		$569,824			$236			$—			$3,065,254



2014	Utility		Entergy Wholesale Commodities*		All Other			Eliminations			Consolidated
	(In Thousands)
Operating revenues		$9,773,822		$2,719,404		$1,821			($126	)		$12,494,921
Asset write-offs, impairments, and related charges		$72,225		$107,527		$—			$—			$179,752
Depreciation, amortization, & decommissioning		$1,170,122		$417,435		$3,702			$—			$1,591,259
Interest and investment income		$171,217		$113,959		$22,159			($159,649	)		$147,686
Interest expense		$531,729		$16,646		$120,908			($41,776	)		$627,507
Income taxes		$472,148		$176,988		($59,539	)		$—			$589,597
Consolidated net income (loss)		$846,496		$294,521		($62,887	)		($117,873	)		$960,257
Total assets		$38,186,286		$10,279,500		($659,207	)		($1,392,124	)		$46,414,455
Investment in affiliates - at equity		$199		$36,035		$—			$—			$36,234
Cash paid for long-lived asset additions		$2,113,631		$615,021		$87			$—			$2,728,739

Businesses marked with * are sometimes referred to as the “competitive businesses.” Eliminations are primarily intersegment activity. Almost all of Entergy’s goodwill is related to the Utility segment.

On December 29, 2014, the Vermont Yankee plant ceased power production and entered its decommissioning phase. In December 2015, Rhode Island State Energy Center, a natural gas-fired combined cycle generating plant, was sold. In October 2015 management announced the intention to shutdown the FitzPatrick plant in 2017 and the Pilgrim plant in 2019, earlier than previously expected. In 2016 management announced the planned sale of Vermont Yankee in 2018, the planned sale of FitzPatrick in 2017, and the planned termination of the Consumers Energy power purchase agreement for the Palisades plant in 2018 and the subsequent plan to shut down the Palisades plant in 2018, earlier than expected. In January 2017 management announced a settlement with New York State to shut down Indian Point 2 in 2020 and Indian Point 3 in 2021, both earlier than expected. Management expects these transactions to result in the cessation of merchant power generation at all Entergy Wholesale Commodities nuclear power plants owned and operated by Entergy by 2021. Entergy will continue to have the obligation to decommission the nuclear plants owned by Entergy.

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These decisions and transactions resulted in asset impairments, employee retention and severance expenses and other benefits-related costs, and contracted economic development contributions. The employee retention and severance expenses and other benefits-related costs, and contracted economic development contributions are included in "Other operation and maintenance" in the consolidated statement of operations. Total restructuring charges in 2016 were comprised of the following:



	Restructuring Costs		Paid In Cash		Non-Cash Portion		Remaining Accrual
	(In Millions)
Employee retention and severances expenses and other benefits-related costs		$74.2		$0.9		$3.1		$70.2
Economic development costs	21.3		—		—		21.3
Total		$95.5		$0.9		$3.1		$91.5

In addition, Entergy Wholesale Commodities incurred $2.8 billion in 2016 and $2 billion in 2015 of impairment and other related charges associated with these strategic decisions and transactions. See Note 14 to the financial statements for further discussion of these impairment charges.

In addition, Entergy Wholesale Commodities expects to incur employee retention and severance expenses of approximately $100 million in 2017 and approximately $235 million from 2018 through the end of 2021 associated with these strategic transactions.

Geographic Areas

For the years ended December 31, 2016, 2015, and 2014, the amount of revenue Entergy derived from outside of the United States was insignificant. As of December 31, 2016 and 2015, Entergy had no long-lived assets located outside of the United States.

Registrant Subsidiaries

Each of the Registrant Subsidiaries has one reportable segment, which is an integrated utility business, except for System Energy, which is an electricity generation business. Each of the Registrant Subsidiaries’ operations is managed on an integrated basis by that company because of the substantial effect of cost-based rates and regulatory oversight on the business process, cost structures, and operating results.

NOTE 14. ACQUISITIONS, DISPOSITIONS, AND IMPAIRMENT OF LONG-LIVED ASSETS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans)

Acquisitions

Union Power Station

In March 2016, Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans purchased the Union Power Station, a 1,980 MW (summer rating) power generation facility located near El Dorado, Arkansas, from Union Power Partners, L.P. The Union Power Station consists of four natural gas-fired, combined-cycle gas turbine power blocks, each rated at 495 MW (summer rating). Entergy Louisiana purchased two of the power blocks and a 50% undivided ownership interest in certain assets related to the facility, and Entergy Arkansas and Entergy New Orleans each purchased one power block and a 25% undivided ownership interest in such related assets. The aggregate purchase price for the Union Power Station was approximately $949 million (approximately $237 million for each power block and associated assets).

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Palisades Purchased Power Agreement

Entergy’s purchase of the Palisades plant in 2007 included a unit-contingent, 15-year purchased power agreement (PPA) with Consumers Energy for 100% of the plant’s output, excluding any future uprates. Prices under the PPA range from $43.50/MWh in 2007 to $61.50/MWh in 2022, and the average price under the PPA is $51/MWh. For the PPA, which was at below-market prices at the time of the acquisition, Entergy will amortize a liability to revenue over the life of the agreement. The amount that will be amortized each period is based upon the present value, calculated at the date of acquisition, of each year’s difference between revenue under the agreement and revenue based on estimated market prices. Amounts amortized to revenue were $13 million in 2016, $15 million in 2015, and $16 million in 2014. In December 2016, Entergy announced that it has reached an agreement with Consumers Energy to terminate the PPA early, on May 31, 2018, subject to regulatory approvals. Because of entering into the early termination agreement, Entergy expects to amortize approximately $43 million of the liability to revenue in 2017 and $29 million to revenue in 2018. The timing of the liability amortization could fluctuate further depending upon if, and when, regulatory approval of the early termination agreement is received. See further discussion of the Palisades transaction below.

NYPA Value Sharing Agreements

Entergy’s purchase of the FitzPatrick and Indian Point 3 plants from NYPA included value sharing agreements with NYPA. In October 2007, Entergy subsidiaries and NYPA amended and restated the value sharing agreements to clarify and amend certain provisions of the original terms. Under the amended value sharing agreements, Entergy subsidiaries made annual payments to NYPA based on the generation output of the Indian Point 3 and FitzPatrick plants from January 2007 through December 2014. Entergy subsidiaries paid NYPA $6.59 per MWh for power sold from Indian Point 3, up to an annual cap of $48 million, and $3.91 per MWh for power sold from FitzPatrick, up to an annual cap of $24 million. The annual payment for each year’s output was due by January 15 of the following year. Entergy recorded the liability for payments to NYPA as power was generated and sold by Indian Point 3 and FitzPatrick. An amount equal to the liability was recorded to the plant asset account as contingent purchase price consideration for the plants. In 2014, Entergy Wholesale Commodities recorded approximately $72 million as plant for generation.

Dispositions

Vermont Yankee

In November 2016, Entergy entered into an agreement to sell 100% of the membership interests in Entergy Nuclear Vermont Yankee, LLC to a subsidiary of NorthStar. Entergy Nuclear Vermont Yankee is the owner of the Vermont Yankee plant and is in the Entergy Wholesale Commodities segment. The sale of Entergy Nuclear Vermont Yankee to NorthStar will include the transfer of the nuclear decommissioning trust fund and the asset retirement obligation for the spent fuel management and decommissioning of the plant.

Entergy Nuclear Vermont Yankee has an outstanding credit facility with borrowing capacity of $100 million to pay for dry fuel storage costs. This credit facility is guaranteed by Entergy Corporation. At or before closing, a subsidiary of Entergy will assume the obligations under the existing credit facility or enter into a new credit facility and Entergy will guarantee the credit facility. At the closing of the sale transaction, NorthStar will pay $1,000 for the membership interests in Entergy Nuclear Vermont Yankee, and NorthStar will cause Entergy Nuclear Vermont Yankee to issue a promissory note to the Entergy entity selling the membership interests in Entergy Nuclear Vermont Yankee. The amount of the promissory note issued will be equal to the amount drawn under the credit facility or the amount drawn under the new credit facility, plus borrowing fees and costs incurred by Entergy in connection with such facility. The principal amount drawn under the outstanding credit facility was $45 million as of December 31, 2016, and the net book value of Entergy Nuclear Vermont Yankee, including unrealized gains on the decommissioning trust fund, as of December 31, 2016, was approximately $88 million.

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The transaction is subject to certain closing conditions, including approval by the NRC; approval by the State of Vermont Public Service Board, including approval of revised site restoration standards that will be proposed as part of the transaction; the transfer of all spent nuclear fuel to dry fuel storage on the independent spent fuel storage installation; and that the market value of the fund assets held in the decommissioning trust fund for the Vermont Yankee Nuclear Power Station, less the hypothetical income tax on the aggregate unrealized net gain of such fund assets at closing, is equal to or exceeds $451.95 million, subject to adjustments. The transaction is expected to close by the end of 2018, subject to certain conditions, including the condition that Entergy contribute to the decommissioning trust fund if the value is less than provided for in the agreement with NorthStar.

FitzPatrick

In August 2016, Entergy entered into an agreement to sell the FitzPatrick plant to Exelon. The transaction is expected to close in the first half of 2017. The purchase price is $100 million and the assumption by Exelon of certain liabilities related to the FitzPatrick plant, with an additional $10 million non-refundable signing fee, which was paid upon the signing of the agreement. The transaction is contingent upon, among other things, the expiration of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, the receipt of necessary regulatory approvals from the FERC, the NRC, and the Public Service Commission of the State of New York (NYPSC), and the receipt of a private letter ruling from the IRS. NRC approval has not yet been received, but all other necessary regulatory approvals have been received. Because certain specified conditions were satisfied in November 2016, including the continued effectiveness of the Clean Energy Standards/Zero Emissions Credit program (CES/ZEC), the establishment of certain long-term agreements on acceptable terms with the Energy Research and Development Authority of the State of New York in connection with the CES/ZEC program, and NYPSC approval of the transaction on acceptable terms, Entergy refueled the FitzPatrick plant in January and February 2017. Entergy expects to operate the FitzPatrick plant until the asset purchase agreement closing date. Entergy entered into a reimbursement agreement with Exelon pursuant to which Exelon will reimburse Entergy for specified out-of-pocket costs associated with the refueling and operation of FitzPatrick that otherwise would have been avoided had Entergy shut down FitzPatrick in January 2017. Pursuant to the reimbursement agreement, as of December 31, 2016 Exelon reimbursed Entergy $56 million for nuclear fuel expenses and $41 million for other operation and maintenance expenses associated with preparing to refuel FitzPatrick in 2017. If the asset purchase agreement is terminated, a termination fee of up to $30 million will be payable to Entergy under certain circumstances. If it is consummated, the transaction could result in a gain or loss because of fluctuations in the decommissioning trust fund earnings and asset retirement obligation accretion. Upon the closing of the sale, the FitzPatrick decommissioning trust along with the decommissioning obligation for that plant will be transfered to Exelon.

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Top Deer

Rhode Island State Energy Center

Impairment of Long-lived Assets

2016 Impairment Conclusions

In December 2016, Entergy reached an agreement with Consumers Energy to terminate the PPA for the Palisades plant after May 2018. The agreement is subject to regulatory approvals. Assuming regulatory approvals are obtained Entergy determined that it will close the Palisades plant on October 1, 2018, after refueling in the spring of 2017 and operating through the end of that fuel cycle. As a result of the PPA termination and its intention to shut down the plant, Entergy tested the recoverability of the plant and related assets as of December 31, 2016.

Indian Point 2 and Indian Point 3 have an application pending for renewed NRC licenses. Various parties, including the State of New York, expressed opposition to renewal of the licenses. Under federal law, nuclear power plants may continue to operate beyond their original license expiration dates while their timely filed renewal applications are pending NRC approval. Indian Point 2 reached the expiration date of its original NRC operating license on September 28, 2013, and Indian Point 3 reached the expiration date of its original NRC operating license on December 12, 2015. Upon expiration of their operating licenses, each plant entered into a period of extended operation under the timely renewal rule.

In January 2017, Entergy announced that it reached a settlement with New York State to shut down Indian Point 2 by April 30, 2020 and Indian Point 3 by April 30, 2021, and resolve all New York State-initiated legal challenges to Indian Point’s operating license renewal. As part of the settlement, New York State has agreed to issue Indian Point’s water quality certification and Coastal Zone Management Act consistency certification and to withdraw its objection to license renewal before the NRC. New York State also has agreed to issue a water discharge permit, which is required regardless of whether the plant is seeking a renewed NRC license. The shutdowns are conditioned, among other things, upon such actions being taken by New York State. As a result of its evaluation of alternatives to the continued operation of the Indian Point plants, and taking into consideration the status of negotiations with the State of New York, Entergy tested the recoverability of the plants and related assets as of December 31, 2016.

Under generally accepted accounting principles the determination of an asset’s recoverability is based on the probability-weighted undiscounted net cash flows expected to be generated by the plant and related assets. Projected net cash flows primarily depend on the status of the operations of the plant and pending legal and state regulatory matters, as well as projections of future revenues and costs over the estimated remaining life of the plant.

The tests for Palisades and Indian Point indicated that the probability-weighted undiscounted net cash flows did not exceed the carrying values of the plants and related assets as of December 31, 2016.

As of December 31, 2016 the estimated fair value of the Palisades plant and related long-lived assets is $206 million, while the carrying value was $558 million, resulting in an impairment charge of $352 million. Materials and supplies were evaluated and written down by $48 million. In summary, as of December 31, 2016, the total impairment

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loss and related charges for Palisades is $400 million ($258 million net-of-tax). The pre-impairment carrying value of $558 million includes the effect of a $129 million increase in Palisades’ estimated decommissioning cost liability and the related asset retirement cost asset. The increase in the estimated decommissioning cost liability primarily resulted from the change in expectation regarding the timing of decommissioning cash flows. See Note 9 to the financial statements for further discussion regarding the Palisades decommissioning cost revision.

As of December 31, 2016 the estimated fair value of the Indian Point plants and related long-lived assets is $433 million, while the carrying value was $2,619 million, resulting in an impairment charge of $2,186 million. Materials and supplies were evaluated and written down by $157 million. In summary, as of December 31, 2016, the total impairment loss and related charges for Indian Point is $2,343 million ($1,511 million net-of-tax). The pre-impairment carrying value of $2,619 million includes the effect of a $392 million increase in Indian Point’s estimated decommissioning cost liability and the related asset retirement cost asset. The increase in the estimated decommissioning cost liability primarily resulted from the change in expectation regarding the timing of decommissioning cash flows. See Note 9 to the financial statements for further discussion regarding the Indian Point decommissioning cost revision.

2015 Impairment Conclusions

Entergy determined in October 2015 that it would close FitzPatrick at the end of its current fuel cycle, which was planned for January 27, 2017, because of poor market conditions that led to reduced revenues, a poor market design that failed to properly compensate nuclear generators for the benefits they provide, and increased operational costs. This decision came after management’s extensive analysis of whether it was advisable economically to refuel the plant, as scheduled, in the fall of 2016. Entergy also had discussions with the State of New York regarding the future of FitzPatrick. Because of the uncertainty regarding the refueling decision and its implications to the plant’s expected operating life, Entergy tested the recoverability of the plant and related assets as of September 30, 2015. See above for further information on the subsequent decision to sell the FitzPatrick plant.

Entergy determined in October 2015 that it would close Pilgrim no later than June 1, 2019 because of poor market conditions that led to reduced revenues, a poor market design that failed to properly compensate nuclear generators for the benefits they provide, and increased operational costs. The decision came after management’s extensive analysis of the economics and operating life of the plant following the NRC’s decision in September 2015 to place the plant in its “multiple/repetitive degraded cornerstone column” (Column 4) of its Reactor Oversight Process Action Matrix. Because of the uncertainty regarding the plant’s operating life created by the NRC’s decision and management’s analysis of the plant, Entergy tested the recoverability of the plant and related assets as of September 30, 2015.

Due to the announced plant closures in October 2015, as well as the continued challenging market price trend, the high level of investment required to continue to operate the Entergy Wholesale Commodities plants, and the inadequate compensation provided to nuclear generators for their capacity benefits under the current market design, Entergy tested the recoverability of the plant and related assets of the two remaining operating nuclear power generating facilities in the Entergy Wholesale Commodities business, Palisades and Indian Point, in the fourth quarter 2015. For purposes of that evaluation, Entergy considered a number of factors associated with the facilities’ continued operation, including the status of the associated NRC licenses, the status of state regulatory issues, existing power purchase agreements, and the supply region in which the nuclear facilities sell energy and capacity.

The tests for FitzPatrick and Pilgrim indicated that the probability-weighted undiscounted net cash flows did not exceed the carrying values of the plants and related assets as of September 30, 2015.

The test for Palisades indicated the probability-weighted undiscounted net cash flows did not exceed the carrying value of the plant and related assets as of December 31, 2015.

The test for Indian Point indicated that the probability-weighted undiscounted net cash flows exceeded the carrying value of the plant and related assets as of December 31, 2015. As such, the carrying value of Indian Point

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was not impaired as of December 31, 2015. As of December 31, 2015, the net carrying value of Indian Point, including nuclear fuel, was $2,360 million.

As of September 30, 2015, the estimated fair value of the FitzPatrick plant and related long-lived assets was $29 million, while the carrying value was $742 million, resulting in an impairment charge of $713 million. Materials and supplies were evaluated and written down by $48 million. In addition, FitzPatrick had a contract asset recorded for an agreement between Entergy subsidiaries and NYPA entered when Entergy subsidiaries purchased FitzPatrick from NYPA in 2000 and NYPA retained the decommissioning trusts and the decommissioning liabilities. The agreement gave NYPA the right to require the Entergy subsidiaries to assume the decommissioning liability provided that it assigns the decommissioning trust, up to a specified level, to Entergy. If NYPA retained the decommissioning liabilities, the Entergy subsidiaries would perform the decommissioning of the plant at a price equal to the lesser of a pre-specified level or the amount in the decommissioning trusts. The contract asset represented an estimate of the present value of the difference between the Entergy subsidiaries’ stipulated contract amount for decommissioning the plants less the decommissioning costs estimated in independent decommissioning cost studies. See Note 9 for further discussion of the contract asset. Due to a change in expectation regarding the timing of decommissioning cash flows, the result was a write down of the contract asset from $335 million to $131 million, for a charge of $204 million. In summary, as of September 30, 2015, the impairment and related charges for FitzPatrick was $965 million ($624 million net-of-tax).

As of September 30, 2015, the estimated fair value of the Pilgrim plant and related long-lived assets is $65 million, while the carrying value was $718 million, resulting in an impairment charge of $653 million. Materials and supplies were evaluated and written down by $24 million. In summary, as of September 30, 2015, the total impairment loss and related charges for Pilgrim was $677 million ($438 million net-of-tax). The pre-impairment carrying value of $718 million includes the effect of a $134 million increase in Pilgrim’s estimated decommissioning cost liability and the related asset retirement cost asset. The increase in the estimated decommissioning cost liability primarily resulted from the change in expectation regarding the timing of decommissioning cash flows. See Note 9 to the financial statements for further discussion regarding the Pilgrim decommissioning cost revision.

As of December 31, 2015, the estimated fair value of the Palisades plant and related long-lived assets was $463 million, while the carrying value was $859 million, resulting in an impairment charge of $396 million ($256 million net-of-tax). The pre-impairment carrying value of $859 million includes the effect of a $42 million increase in Palisades’ estimated decommissioning cost liability and the related asset retirement cost asset. The increase in the estimated decommissioning cost liability primarily resulted from the assessment of the estimated decommissioning cash flows that occurred in conjunction with the impairment analysis. See Note 9 to the financial statements for further discussion regarding the Palisades decommissioning cost revision.

2014 Impairment Conclusion

In August 2013, the Board approved a plan to close and decommission Vermont Yankee at the end of its fuel cycle at the end of 2014. As a result of the decision to shut down the plant, Entergy recognized impairment and other related charges during the third quarter 2013 to write down the carrying value of Vermont Yankee and related assets to their fair values. As part of the development of the site assessment study and PSDAR, Entergy obtained a revised decommissioning cost study in the third quarter 2014. The revised estimate, along with reassessment of the assumptions regarding the timing of decommissioning cash flows, resulted in a $101.6 million increase in the decommissioning cost liability and a corresponding impairment charge, recorded in September 2014. See Note 9 to the financial statements for further discussion regarding the Vermont Yankee decommissioning cost revisions.

Overall Regarding All Impairments

The impairments and other related charges are recorded as a separate line item in Entergy’s consolidated statements of operations and are included within the results of the Entergy Wholesale Commodities segment. In addition to the impairments and other related charges, Entergy expects to incur additional charges through 2021 associated with these strategic transactions. See Note 13 to the financial statements for further discussion of these additional charges.

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The fair value analyses for FitzPatrick, Indian Point, Pilgrim, and Palisades were performed based on the income approach, a discounted cash flow method, to determine the amount of impairment. The estimates of fair value were based on the prices that Entergy would expect to receive in hypothetical sales of the FitzPatrick, Indian Point, Pilgrim, and Palisades plants and related assets to a market participant. In order to determine these prices, Entergy used significant observable inputs, including quoted forward power and gas prices, where available. Significant unobservable inputs, such as projected long-term pre-tax operating margins (cash basis) and estimated weighted average costs of capital, were also used in the estimation of fair value. In addition, Entergy made certain assumptions regarding future tax deductions associated with the plants and related assets, the amount and timing of recoveries from future litigation with the DOE related to spent fuel storage costs, and the expected operating life of the plant. Based on the use of significant unobservable inputs, the fair value measurement for the entirety of the asset group, and for each type of asset within the asset group, are classified as Level 3 in the fair value hierarchy discussed in Note 15 to the financial statements.

The following table sets forth a description of significant unobservable inputs used in the valuation of the FitzPatrick, Indian Point, Pilgrim, and Palisades plants and related assets:



Significant Unobservable Inputs	Amount	Weighted Average
2016
Weighted average cost of capital
Indian Point (a)	7.0%-7.5%	7.2%
Palisades	6.5%	6.5%

Long-term pre-tax operating margin (cash basis)
Indian Point	19.7%	19.7%
Palisades (b) (c)	17.8%-38.8%	34.6%

2015
Weighted average cost of capital
FitzPatrick	7.5%	7.5%
Pilgrim (d)	7.5%-8.0%	7.9%
Palisades	7.5%	7.5%

Long-term pre-tax operating margin (cash basis)
FitzPatrick	10.2%	10.2%
Pilgrim (d)	2.4%-10.6%	8.1%
Palisades (b)	30.8%	30.8%


(a)	The cash flows extending through the 2021 shutdown at Indian Point 3 were assigned a higher discount factor to incorporate the increased risk associated with longer operations.


(b)	Most of the Palisades output is sold under a 15-year power purchase agreement, entered at the plant’s acquisition in 2007, that originally was scheduled to expire in 2022. The power purchase agreement prices currently exceed market prices and escalate each year, up to $61.50/MWh in 2022.


(c)	The fair value of Palisades at December 31, 2016 is based on the probability weighting of whether the PPA will terminate before the originally scheduled termination in 2022.


(d)	The fair value of Pilgrim was based on the probability weighting of two potential scenarios.

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Entergy’s Accounting Policy and Entergy Wholesale Commodities Accounting group, which reports to the Chief Accounting Officer, was primarily responsible for determining the valuation of the FitzPatrick, Indian Point, Pilgrim, and Palisades plants and related assets, in consultation with external advisors. Entergy’s Accounting Policy group obtained and reviewed information from other Entergy departments with expertise on the various inputs and assumptions that were necessary to calculate the fair values of the asset groups.

NOTE 15. RISK MANAGEMENT AND FAIR VALUES (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Market Risk

In the normal course of business, Entergy is exposed to a number of market risks. Market risk is the potential loss that Entergy may incur as a result of changes in the market or fair value of a particular commodity or instrument. All financial and commodity-related instruments, including derivatives, are subject to market risk including commodity price risk, equity price, and interest rate risk. Entergy uses derivatives primarily to mitigate commodity price risk, particularly power price and fuel price risk.

The Utility has limited exposure to the effects of market risk because it operates primarily under cost-based rate regulation. To the extent approved by their retail regulators, the Utility operating companies use derivative instruments to hedge the exposure to price volatility inherent in their purchased power, fuel, and gas purchased for resale costs that are recovered from customers.

Entergy’s exposure to market risk is determined by a number of factors, including the size, term, composition, and diversification of positions held, as well as market volatility and liquidity. For instruments such as options, the time period during which the option may be exercised and the relationship between the current market price of the underlying instrument and the option’s contractual strike or exercise price also affects the level of market risk. A significant factor influencing the overall level of market risk to which Entergy is exposed is its use of hedging techniques to mitigate such risk. Hedging instruments and volumes are chosen based on ability to mitigate risk associated with future energy and capacity prices; however, other considerations are factored into hedge product and volume decisions including corporate liquidity, corporate credit ratings, counterparty credit risk, hedging costs, firm settlement risk, and product availability in the marketplace. Entergy manages market risk by actively monitoring compliance with stated risk management policies as well as monitoring the effectiveness of its hedging policies and strategies. Entergy’s risk management policies limit the amount of total net exposure and rolling net exposure during the stated periods. These policies, including related risk limits, are regularly assessed to ensure their appropriateness given Entergy’s objectives.

Derivatives

Some derivative instruments are classified as cash flow hedges due to their financial settlement provisions while others are classified as normal purchase/normal sale transactions due to their physical settlement provisions. Normal purchase/normal sale risk management tools include power purchase and sales agreements, fuel purchase agreements, capacity contracts, and tolling agreements. Financially-settled cash flow hedges can include natural gas and electricity swaps and options and interest rate swaps. Entergy may enter into financially-settled swap and option contracts to manage market risk that may or may not be designated as hedging instruments.

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Entergy enters into derivatives to manage natural risks inherent in its physical or financial assets or liabilities. Electricity over-the-counter instruments and futures contracts that financially settle against day-ahead power pool prices are used to manage price exposure for Entergy Wholesale Commodities generation. The maximum length of time over which Entergy is currently hedging the variability in future cash flows with derivatives for forecasted power transactions at December 31, 2016 is approximately 2.25 years. Planned generation currently under contract from Entergy Wholesale Commodities nuclear power plants is 87% for 2017, of which approximately 59% is sold under financial derivatives and the remainder under normal purchase/normal sale contracts. Total planned generation for 2017 is 27.3 TWh.

Entergy may use standardized master netting agreements to help mitigate the credit risk of derivative instruments. These master agreements facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Cash, letters of credit, and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds an established threshold. The threshold represents an unsecured credit limit, which may be supported by a parental/affiliate guaranty, as determined in accordance with Entergy’s credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.

Certain of the agreements to sell the power produced by Entergy Wholesale Commodities power plants contain provisions that require an Entergy subsidiary to provide credit support to secure its obligations depending on the mark-to-market values of the contracts. The primary form of credit support to satisfy these requirements is an Entergy Corporation guarantee. As of December 31, 2016, derivative contracts with 3 counterparties were in a liability position (approximately $8 million total). In addition to the corporate guarantee, $2 million in cash collateral was required to be posted by the Entergy subsidiary to its counterparties. As of December 31, 2015, derivative contracts with 2 counterparties were in a liability position (approximately $2 million total). As of December 31, 2015, $9 million in cash collateral was required to be posted by the Entergy subsidiary to its counterparties and $68 million was required to be posted by its counterparties to the Entergy subsidiary. If the Entergy Corporation credit rating falls below investment grade, the effect of the corporate guarantee is typically ignored and Entergy would have to post collateral equal to the estimated outstanding liability under the contract at the applicable date.

Entergy manages fuel price volatility for its Louisiana jurisdictions (Entergy Louisiana and Entergy New Orleans) and Entergy Mississippi through the purchase of short-term natural gas swaps that financially settle against NYMEX futures. These swaps are marked-to-market through fuel expense with offsetting regulatory assets or liabilities. All benefits or costs of the program are recorded in fuel costs. The notional volumes of these swaps are based on a portion of projected annual exposure to gas for electric generation at Entergy Louisiana and Entergy Mississippi and projected winter purchases for gas distribution at Entergy Louisiana and Entergy New Orleans. The total volume of natural gas swaps outstanding as of December 31, 2016 is 37,970,000 MMBtu for Entergy, including 30,940,000 MMBtu for Entergy Louisiana, 6,540,000 MMBtu for Entergy Mississippi, and 490,000 MMBtu for Entergy New Orleans. Credit support for these natural gas swaps is covered by master agreements that do not require collateralization based on mark-to-market value, but do carry adequate assurance language that may lead to collateralization requests.

During the second quarter 2016, Entergy participated in the annual financial transmission right (FTR) auction process for the MISO planning year of June 1, 2016 through May 31, 2017. FTRs are derivative instruments which represent economic hedges of future congestion charges that will be incurred in serving Entergy’s customer load. They are not designated as hedging instruments. Entergy initially records FTRs at their estimated fair value and subsequently adjusts the carrying value to their estimated fair value at the end of each accounting period prior to settlement. Unrealized gains or losses on FTRs held by Entergy Wholesale Commodities are included in operating revenues. The Utility operating companies recognize regulatory liabilities or assets for unrealized gains or losses on FTRs. The total volume of FTRs outstanding as of December 31, 2016 is 46,216 GWh for Entergy, including 10,540 GWh for Entergy Arkansas, 19,467 GWh for Entergy Louisiana, 7,535 GWh for Entergy Mississippi, 2,234 GWh for Entergy New Orleans, and 6,248 GWh for Entergy Texas. Credit support for FTRs held by the Utility operating companies is covered by cash and/or letters of credit issued by each Utility operating company as required by MISO. Credit support for FTRs held

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by Entergy Wholesale Commodities is covered by cash. As of December 31, 2016, letters of credit posted with MISO covered the FTR exposure for Entergy Arkansas and Entergy Mississippi. As of December 31, 2015, no cash or letters of credit were required to be posted for FTR exposure for the Utility operating companies or Entergy Wholesale Commodities, respectively.

The fair values of Entergy’s derivative instruments in the consolidated balance sheet as of December 31, 2016 are shown in the table below. Certain investments, including those not designated as hedging instruments, are subject to master netting agreements and are presented in the balance sheet on a net basis in accordance with accounting guidance for derivatives and hedging.



Instrument	Balance Sheet Location	Fair Value (a)	Offset (b)	Net (c) (d)	Business
		(In Millions)
Derivatives designated as hedging instruments

Assets:
Electricity swaps and options	Prepayments and other (current portion)	$25	($14)	$11	Entergy Wholesale Commodities
Electricity swaps and options	Other deferred debits and other assets (non-current portion)	$6	($6)	$—	Entergy Wholesale Commodities

Liabilities:
Electricity swaps and options	Other current liabilities (current portion)	$11	($10)	$1	Entergy Wholesale Commodities
Electricity swaps and options	Other non-current liabilities (non-current portion)	$16	($7)	$9	Entergy Wholesale Commodities



Derivatives not designated as hedging instruments

Assets:
Electricity swaps and options	Prepayments and other (current portion)	$18	($13)	$5	Entergy Wholesale Commodities
Electricity swaps and options	Other deferred debits and other assets (non-current portion)	$5	($5)	$—	Entergy Wholesale Commodities
Natural gas swaps	Prepayments and other	$13	$—	$13	Utility
Financial transmission rights	Prepayments and other	$22	($1)	$21	Utility and Entergy Wholesale Commodities

Liabilities:
Electricity swaps and options	Other current liabilities (current portion)	$18	($17)	$1	Entergy Wholesale Commodities
Electricity swaps and options	Other non-current liabilities (non-current portion)	$4	($4)	$—	Entergy Wholesale Commodities

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The fair values of Entergy’s derivative instruments in the consolidated balance sheet as of December 31, 2015 are shown in the table below. Certain investments, including those not designated as hedging instruments, are subject to master netting agreements and are presented in the balance sheet on a net basis in accordance with accounting guidance for derivatives and hedging.



Instrument	Balance Sheet Location	Fair Value (a)	Offset (b)	Net (c) (d)	Business
		(In Millions)
Derivatives designated as hedging instruments

Assets:
Electricity swaps and options	Prepayments and other (current portion)	$173	($34)	$139	Entergy Wholesale Commodities
Electricity swaps and options	Other deferred debits and other assets (non-current portion)	$17	($2)	$15	Entergy Wholesale Commodities

Liabilities:
Electricity swaps and options	Other current liabilities (current portion)	$14	($14)	$—	Entergy Wholesale Commodities
Electricity swaps and options	Other non-current liabilities (non-current portion)	$2	($2)	$—	Entergy Wholesale Commodities



Derivatives not designated as hedging instruments

Assets:
Electricity swaps and options	Prepayments and other (current portion)	$54	($13)	$41	Entergy Wholesale Commodities
Financial transmission rights	Prepayments and other	$24	($1)	$23	Utility and Entergy Wholesale Commodities

Liabilities:
Electricity swaps and options	Other current liabilities (current portion)	$38	($32)	$6	Entergy Wholesale Commodities
Natural gas swaps	Other current liabilities	$9	$—	$9	Utility


(a)	Represents the gross amounts of recognized assets/liabilities


(b)	Represents the netting of fair value balances with the same counterparty


(c)	Represents the net amounts of assets/liabilities presented on the Entergy Consolidated Balance Sheets


(d)	Excludes cash collateral in the amount of $2 million posted as of December 31, 2016 and $9 million posted and $68 million held as of December 31, 2015.

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The effects of Entergy’s derivative instruments designated as cash flow hedges on the consolidated statements of operations for the years ended December 31, 2016, 2015, and 2014 are as follows:



Instrument	Amount of gain recognized in other comprehensive income	Income Statement location	Amount of gain (loss) reclassified from accumulated other comprehensive income into income (a)
	(In Millions)		(In Millions)
2016
Electricity swaps and options	$135	Competitive business operating revenues	$293

2015
Electricity swaps and options	$254	Competitive business operating revenues	($244)

2014
Electricity swaps and options	$81	Competitive business operating revenues	($193)


(a)	Before taxes of $103 million, ($85) million, and ($68) million, for the years ended December 31, 2016, 2015, and 2014, respectively

At each reporting period, Entergy measures its hedges for ineffectiveness. Any ineffectiveness is recognized in earnings during the period. The ineffective portion of cash flow hedges is recorded in competitive businesses operating revenues. The change in fair value of Entergy’s cash flow hedges due to ineffectiveness was ($356) thousand, $150 thousand, and $7 million for the years ended December 31, 2016, 2015, and 2014, respectively.

Based on market prices as of December 31, 2016, unrealized gains recorded in AOCI on cash flow hedges relating to power sales totaled ($9) million of net unrealized gains. Approximately ($15) million is expected to be reclassified from AOCI to operating revenues in the next twelve months. The actual amount reclassified from AOCI, however, could vary due to future changes in market prices.

Entergy may effectively liquidate a cash flow hedge instrument by entering into a contract offsetting the original hedge, and then de-designating the original hedge in this situation. Gains or losses accumulated in other comprehensive income prior to de-designation continue to be deferred in other comprehensive income until they are included in income as the original hedged transaction occurs. From the point of de-designation, the gains or losses on the original hedge and the offsetting contract are recorded as assets or liabilities on the balance sheet and offset as they flow through to earnings.

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The effects of Entergy’s derivative instruments not designated as hedging instruments on the consolidated statements of operations for the years ended December 31, 2016, 2015, and 2014 are as follows:



Instrument	Amount of gain (loss) recognized in accumulated other comprehensive income		Income Statement location		Amount of gain (loss) recorded in the income statement
	(In Millions)				(In Millions)
2016
Natural gas swaps	$—		Fuel, fuel-related expenses, and gas purchased for resale	(a)	$11
Financial transmission rights	$—		Purchased power expense	(b)	$125
Electricity swaps and options	$—	(c)	Competitive business operating revenues		($11)

2015
Natural gas swaps	$—		Fuel, fuel-related expenses, and gas purchased for resale	(a)	($41)
Financial transmission rights	$—		Purchased power expense	(b)	$166
Electricity swaps and options	$12	(c)	Competitive business operating revenues		($19)

2014
Natural gas swaps	$—		Fuel, fuel-related expenses, and gas purchased for resale	(a)	($8)
Financial transmission rights	$—		Purchased power expense	(b)	$229
Electricity swaps and options	($13)	(c)	Competitive business operating revenues		$56


(a)	Due to regulatory treatment, the natural gas swaps are marked-to-market through fuel, fuel-related expenses, and gas purchased for resale and then such amounts are simultaneously reversed and recorded as an offsetting regulatory asset or liability. The gains or losses recorded as fuel expenses when the swaps are settled are recovered or refunded through fuel cost recovery mechanisms.

(b)

Due to regulatory treatment, the changes in the estimated fair value of financial transmission rights for the Utility operating companies are recorded through purchased power expense and then such amounts are simultaneously reversed and recorded as an offsetting regulatory asset or liability. The gains or losses recorded as purchased power expense when the financial transmission rights for the Utility operating companies are settled are recovered or refunded through fuel cost recovery mechanisms.


(c)	Amount of gain (loss) recognized in accumulated other comprehensive income from electricity swaps and options de-designated as hedged items.

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The fair values of the Registrant Subsidiaries’ derivative instruments not designated as hedging instruments on their balance sheets as of December 31, 2016 and 2015 are as follows:



Instrument	Balance Sheet Location	Fair Value (a)	Registrant
		(In Millions)
2016
Assets:
Natural gas swaps	Prepayments and other	$10.9	Entergy Louisiana
Natural gas swaps	Prepayments and other	$2.3	Entergy Mississippi
Natural gas swaps	Prepayments and other	$0.2	Entergy New Orleans

Financial transmission rights	Prepayments and other	$5.4	Entergy Arkansas
Financial transmission rights	Prepayments and other	$8.5	Entergy Louisiana
Financial transmission rights	Prepayments and other	$3.2	Entergy Mississippi
Financial transmission rights	Prepayments and other	$1.1	Entergy New Orleans
Financial transmission rights	Prepayments and other	$3.1	Entergy Texas

2015
Assets:
Financial transmission rights	Prepayments and other	$7.9	Entergy Arkansas
Financial transmission rights	Prepayments and other	$8.5	Entergy Louisiana
Financial transmission rights	Prepayments and other	$2.4	Entergy Mississippi
Financial transmission rights	Prepayments and other	$1.5	Entergy New Orleans
Financial transmission rights	Prepayments and other	$2.2	Entergy Texas

Liabilities:
Natural gas swaps	Other current liabilities	$7.0	Entergy Louisiana
Natural gas swaps	Other current liabilities	$1.3	Entergy Mississippi
Natural gas swaps	Other current liabilities	$0.5	Entergy New Orleans


(a)	As of December 31, 2016, letters of credit posted with MISO covered financial transmission right exposure of $0.3 million for Entergy Arkansas and $0.1 million for Entergy Mississippi. No cash or letters of credit were required to be posted for financial transmission right exposure as of December 31, 2015.

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The effects of the Registrant Subsidiaries’ derivative instruments not designated as hedging instruments on their income statements for the years ended December 31, 2016, 2015, and 2014 are as follows:



Instrument	Income Statement Location	Amount of gain (loss) recorded in the income statement		Registrant
		(In Millions)
2016
Natural gas swaps	Fuel, fuel-related expenses, and gas purchased for resale	$8.4	(a)	Entergy Louisiana
Natural gas swaps	Fuel, fuel-related expenses, and gas purchased for resale	$3.1	(a)	Entergy Mississippi
Natural gas swaps	Fuel, fuel-related expenses, and gas purchased for resale	($0.4)	(a)	Entergy New Orleans

Financial transmission rights	Purchased power	$23.2	(b)	Entergy Arkansas
Financial transmission rights	Purchased power	$69.7	(b)	Entergy Louisiana
Financial transmission rights	Purchased power	$16.6	(b)	Entergy Mississippi
Financial transmission rights	Purchased power	$4.1	(b)	Entergy New Orleans
Financial transmission rights	Purchased power	$10.2	(b)	Entergy Texas

2015
Natural gas swaps	Fuel, fuel-related expenses, and gas purchased for resale	($33.2)	(a)	Entergy Louisiana
Natural gas swaps	Fuel, fuel-related expenses, and gas purchased for resale	($6.1)	(a)	Entergy Mississippi
Natural gas swaps	Fuel, fuel-related expenses, and gas purchased for resale	($1.4)	(a)	Entergy New Orleans

Financial transmission rights	Purchased power	$68.7	(b)	Entergy Arkansas
Financial transmission rights	Purchased power	$55.4	(b)	Entergy Louisiana
Financial transmission rights	Purchased power	$16.5	(b)	Entergy Mississippi
Financial transmission rights	Purchased power	$8.5	(b)	Entergy New Orleans
Financial transmission rights	Purchased power	$16.8	(b)	Entergy Texas

2014
Natural gas swaps	Fuel, fuel-related expenses, and gas purchased for resale	($5.5)	(a)	Entergy Louisiana
Natural gas swaps	Fuel, fuel-related expenses, and gas purchased for resale	($2.5)	(a)	Entergy Mississippi
Natural gas swaps	Fuel, fuel-related expenses, and gas purchased for resale	($0.2)	(a)	Entergy New Orleans

Financial transmission rights	Purchased power	$21.6	(b)	Entergy Arkansas
Financial transmission rights	Purchased power	$103.5	(b)	Entergy Louisiana
Financial transmission rights	Purchased power	$19.0	(b)	Entergy Mississippi
Financial transmission rights	Purchased power	$16.5	(b)	Entergy New Orleans
Financial transmission rights	Purchased power	$65.8	(b)	Entergy Texas

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(a)	Due to regulatory treatment, the natural gas swaps are marked-to-market through fuel, fuel-related expenses, and gas purchased for resale and then such amounts are simultaneously reversed and recorded as an offsetting regulatory asset or liability. The gains or losses recorded as fuel expenses when the swaps are settled are recovered or refunded through fuel cost recovery mechanisms.

(b)

Fair Values

The estimated fair values of Entergy’s financial instruments and derivatives are determined using historical prices, bid prices, market quotes, and financial modeling. Considerable judgment is required in developing the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that Entergy could realize in a current market exchange. Gains or losses realized on financial instruments other than those instruments held by the Entergy Wholesale Commodities business are reflected in future rates and therefore do not affect net income. Entergy considers the carrying amounts of most financial instruments classified as current assets and liabilities to be a reasonable estimate of their fair value because of the short maturity of these instruments.

Accounting standards define fair value as an exit price, or the price that would be received to sell an asset or the amount that would be paid to transfer a liability in an orderly transaction between knowledgeable market participants at the date of measurement. Entergy and the Registrant Subsidiaries use assumptions or market input data that market participants would use in pricing assets or liabilities at fair value. The inputs can be readily observable, corroborated by market data, or generally unobservable. Entergy and the Registrant Subsidiaries endeavor to use the best available information to determine fair value.

Accounting standards establish a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy establishes the highest priority for unadjusted market quotes in an active market for the identical asset or liability and the lowest priority for unobservable inputs.

Effective first quarter 2016, Entergy retrospectively adopted ASU 2015-07, which simplifies the disclosure for fair value investments by removing the requirement to categorize within the fair value hierarchy investments for which fair value is measured using the net asset value per share as a practical expedient. For all periods presented the common trust funds have not been assigned a level and are presented within the fair value tables only as a reconciling item to the total fair value of investments.

The three levels of the fair value hierarchy are:

•

Level 1 - Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the entity has the ability to access at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of individually owned common stocks, cash equivalents (temporary cash investments, securitization recovery trust account, and escrow accounts), debt instruments, and gas hedge contracts. Cash equivalents includes all unrestricted highly liquid debt instruments with an original or remaining maturity of three months or less at the date of purchase.

•

Level 2 - Level 2 inputs are inputs other than quoted prices included in Level 1 that are, either directly or indirectly, observable for the asset or liability at the measurement date. Assets are valued based on prices derived by independent third parties that use inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads. Prices are reviewed and can be challenged with the independent parties and/or

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overridden by Entergy if it is believed such would be more reflective of fair value. Level 2 inputs include the following:

- quoted prices for similar assets or liabilities in active markets;

- quoted prices for identical assets or liabilities in inactive markets;

- inputs other than quoted prices that are observable for the asset or liability; or


-	inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 2 consists primarily of individually-owned debt instruments.


•	Level 3 - Level 3 inputs are pricing inputs that are generally less observable or unobservable from objective sources. These inputs are used with internally developed methodologies to produce management’s best estimate of fair value for the asset or liability. Level 3 consists primarily of FTRs and derivative power contracts used as cash flow hedges of power sales at merchant power plants.

The values for power contract assets or liabilities are based on both observable inputs including public market prices and interest rates, and unobservable inputs such as implied volatilities, unit contingent discounts, expected basis differences, and credit adjusted counterparty interest rates. They are classified as Level 3 assets and liabilities. The valuations of these assets and liabilities are performed by the Business Unit Risk Control group and the Accounting Policy and Entergy Wholesale Commodities Accounting group. The primary functions of the Business Unit Risk Control group include: gathering, validating and reporting market data, providing market risk analyses and valuations in support of Entergy Wholesale Commodities’ commercial transactions, developing and administering protocols for the management of market risks, and implementing and maintaining controls around changes to market data in the energy trading and risk management system. The Business Unit Risk Control group is also responsible for managing the energy trading and risk management system, forecasting revenues, forward positions and analysis. The Accounting Policy and Entergy Wholesale Commodities Accounting group performs functions related to market and counterparty settlements, revenue reporting and analysis and financial accounting. The Business Unit Risk Control group reports to the Vice President and Treasurer while the Accounting Policy and Entergy Wholesale Commodities Accounting group reports to the Chief Accounting Officer.

The amounts reflected as the fair value of electricity swaps are based on the estimated amount that the contracts are in-the-money at the balance sheet date (treated as an asset) or out-of-the-money at the balance sheet date (treated as a liability) and would equal the estimated amount receivable to or payable by Entergy if the contracts were settled at that date. These derivative contracts include cash flow hedges that swap fixed for floating cash flows for sales of the output from the Entergy Wholesale Commodities business. The fair values are based on the mark-to-market comparison between the fixed contract prices and the floating prices determined each period from quoted forward power market prices. The differences between the fixed price in the swap contract and these market-related prices multiplied by the volume specified in the contract and discounted at the counterparties’ credit adjusted risk free rate are recorded as derivative contract assets or liabilities. For contracts that have unit contingent terms, a further discount is applied based on the historical relationship between contract and market prices for similar contract terms.

The amounts reflected as the fair values of electricity options are valued based on a Black Scholes model, and are calculated at the end of each month for accounting purposes. Inputs to the valuation include end of day forward market prices for the period when the transactions will settle, implied volatilities based on market volatilities provided by a third party data aggregator, and U.S. Treasury rates for a risk-free return rate. As described further below, prices and implied volatilities are reviewed and can be adjusted if it is determined that there is a better representation of fair value.

On a daily basis, the Business Unit Risk Control group calculates the mark-to-market for electricity swaps and options. The Business Unit Risk Control group also validates forward market prices by comparing them to other sources of forward market prices or to settlement prices of actual market transactions. Significant differences are

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analyzed and potentially adjusted based on these other sources of forward market prices or settlement prices of actual market transactions. Implied volatilities used to value options are also validated using actual counterparty quotes for Entergy Wholesale Commodities transactions when available, and uses multiple sources of market implied volatilities. Moreover, on at least a monthly basis, the Office of Corporate Risk Oversight confirms the mark-to-market calculations and prepares price scenarios and credit downgrade scenario analysis. The scenario analysis is communicated to senior management within Entergy and within Entergy Wholesale Commodities. Finally, for all proposed derivative transactions, an analysis is completed to assess the risk of adding the proposed derivative to Entergy Wholesale Commodities’ portfolio. In particular, the credit and liquidity effects are calculated for this analysis. This analysis is communicated to senior management within Entergy and Entergy Wholesale Commodities.

The values of FTRs are based on unobservable inputs, including estimates of congestion costs in MISO between applicable generation and load pricing nodes based on the 50th percentile of historical prices. They are classified as Level 3 assets and liabilities. The valuations of these assets and liabilities are performed by the Business Unit Risk Control group. The values are calculated internally and verified against the data published by MISO. Entergy’s Accounting Policy and Entergy Wholesale Commodities Accounting group reviews these valuations for reasonableness, with the assistance of others within the organization with knowledge of the various inputs and assumptions used in the valuation. The Business Unit Risk Control groups report to the Vice President and Treasurer. The Accounting Policy and Entergy Wholesale Commodities Accounting group reports to the Chief Accounting Officer.

The following tables set forth, by level within the fair value hierarchy, Entergy’s assets and liabilities that are accounted for at fair value on a recurring basis as of December 31, 2016 and December 31, 2015. The assessment of the significance of a particular input to a fair value measurement requires judgment and may affect their placement within the fair value hierarchy levels.



2016	Level 1		Level 2		Level 3		Total
	(In Millions)
Assets:
Temporary cash investments		$1,058		$—		$—		$1,058
Decommissioning trust funds (a):
Equity securities	480		—		—		480
Debt securities	985		1,228		—		2,213
Common trusts (b)							3,031
Power contracts	—		—		16		16
Securitization recovery trust account	46		—		—		46
Escrow accounts	433		—		—		433
Gas hedge contracts	13		—		—		13
Financial transmission rights	—		—		21		21
		$3,015		$1,228		$37		$7,311
Liabilities:
Power contracts		$—		$—		$11		$11

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2015	Level 1		Level 2		Level 3		Total
	(In Millions)
Assets:
Temporary cash investments		$1,287		$—		$—		$1,287
Decommissioning trust funds (a):
Equity securities	468		—		—		468
Debt securities	1,061		1,094		—		2,155
Common trusts (b)							2,727
Power contracts	—		—		195		195
Securitization recovery trust account	50		—		—		50
Escrow accounts	425		—		—		425
Financial transmission rights	—		—		23		23
		$3,291		$1,094		$218		$7,330
Liabilities:
Power contracts		$—		$—		$6		$6
Gas hedge contracts	9		—		—		9
		$9		$—		$6		$15


(a)	The decommissioning trust funds hold equity and fixed income securities. Equity securities are invested to approximate the returns of major market indices. Fixed income securities are held in various governmental and corporate securities. See Note 16 to the financial statements for additional information on the investment portfolios.


(b)	Common trust funds are not publicly quoted, and are valued by the fund administrators using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table. The fund administrator of these investments allows daily trading at the net asset value and trades settle at a later date.

The following table sets forth a reconciliation of changes in the net assets (liabilities) for the fair value of derivatives classified as Level 3 in the fair value hierarchy for the years ended December 31, 2016, 2015, and 2014:



	2016						2015						2014
	Power Contracts			Financial transmission rights			Power Contracts			Financial transmission rights			Power Contracts			Financial transmission rights
	(In Millions)
Balance as of January 1,		$189			$23			$215			$47			($133	)		$34
Total gains (losses) for the period (a)
Included in earnings	(10		)	—			(20		)	(1		)	55			2
Included in OCI	135			—			254			—			131			—
Included as a regulatory liability/asset	—			68			—			63			—			119
Issuances of financial transmission rights	—			55			—			80			—			121
Purchases	—			—			15			—			17			—
Settlements	(309		)	(125		)	(275		)	(166		)	145			(229		)
Balance as of December 31,		$5			$21			$189			$23			$215			$47

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(a)	Change in unrealized gains or losses for the period included in earnings for derivatives held at the end of the reporting period is $0.2 million, $3 million, and $120 million for the years ended December 31, 2016, 2015, and 2014, respectively.

The following table sets forth a description of the types of transactions classified as Level 3 in the fair value hierarchy and significant unobservable inputs to each which cause that classification, as of December 31, 2016:



Transaction Type	Fair Value as of December 31, 2016	Significant Unobservable Inputs	Range from Average %	Effect on Fair Value
	(In Millions)			(In Millions)
Power contracts - electricity swaps	$5	Unit contingent discount	+/-4%	$—

The following table sets forth an analysis of each of the types of unobservable inputs impacting the fair value of items classified as Level 3 within the fair value hierarchy, and the sensitivity to changes to those inputs:



Significant Unobservable Input	Transaction Type	Position	Change to Input	Effect on Fair Value

Unit contingent discount	Electricity swaps	Sell	Increase (Decrease)	Decrease (Increase)
Implied volatility	Electricity options	Sell	Increase (Decrease)	Increase (Decrease)
Implied volatility	Electricity options	Buy	Increase (Decrease)	Increase (Decrease)

The following table sets forth, by level within the fair value hierarchy, the Registrant Subsidiaries’ assets that are accounted for at fair value on a recurring basis as of December 31, 2016 and December 31, 2015. The assessment of the significance of a particular input to a fair value measurement requires judgment and may affect its placement within the fair value hierarchy levels.

Entergy Arkansas



2016	Level 1		Level 2		Level 3		Total
	(In Millions)
Assets:
Decommissioning trust funds (a):
Equity securities		$3.6		$—		$—		$3.6
Debt securities	112.5		196.8		—		309.3
Common trusts (b)							521.8
Securitization recovery trust account	4.1		—		—		4.1
Escrow accounts	7.1		—		—		7.1
Financial transmission rights	—		—		5.4		5.4
		$127.3		$196.8		$5.4		$851.3

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2015	Level 1		Level 2		Level 3		Total
	(In Millions)
Assets:
Decommissioning trust funds (a):
Equity securities		$3.0		$—		$—		$3.0
Debt securities	110.5		193.4		—		303.9
Common trusts (b)							464.4
Securitization recovery trust account	4.2		—		—		4.2
Escrow accounts	12.2		—		—		12.2
Financial transmission rights	—		—		7.9		7.9
		$129.9		$193.4		$7.9		$795.6

Entergy Louisiana



2016	Level 1		Level 2		Level 3		Total
	(In Millions)
Assets:
Temporary cash investments		$163.9		$—		$—		$163.9
Decommissioning trust funds (a):
Equity securities	13.9		—		—		13.9
Debt securities	132.3		292.5		—		424.8
Common trusts (b)							702.0
Escrow accounts	305.7		—		—		305.7
Securitization recovery trust account	2.8		—		—		2.8
Gas hedge contracts	10.9		—		—		10.9
Financial transmission rights	—		—		8.5		8.5
		$629.5		$292.5		$8.5		$1,632.5



2015	Level 1		Level 2		Level 3		Total
	(In Millions)
Assets:
Temporary cash investments		$34.8		$—		$—		$34.8
Decommissioning trust funds (a):
Equity securities	7.1		—		—		7.1
Debt securities	161.1		248.8		—		409.9
Common trusts (b)							625.3
Escrow accounts	290.4		—		—		290.4
Securitization recovery trust account	3.2		—		—		3.2
Financial transmission rights	—		—		8.5		8.5
		$496.6		$248.8		$8.5		$1,379.2

Liabilities:
Gas hedge contracts		$7.0		$—		$—		$7.0

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Entergy Mississippi



2016	Level 1		Level 2		Level 3		Total
	(In Millions)
Assets:
Temporary cash investments		$76.8		$—		$—		$76.8
Escrow accounts	31.8		—		—		31.8
Gas hedge contracts	2.3		—		—		2.3
Financial transmission rights	—		—		3.2		3.2
		$110.9		$—		$3.2		$114.1



2015	Level 1		Level 2		Level 3		Total
	(In Millions)
Assets:
Temporary cash investments		$144.2		$—		$—		$144.2
Escrow accounts	41.7		—		—		41.7
Financial transmission rights	—		—		2.4		2.4
		$185.9		$—		$2.4		$188.3

Liabilities:
Gas hedge contracts		$1.3		$—		$—		$1.3

Entergy New Orleans



2016	Level 1		Level 2		Level 3		Total
	(In Millions)
Assets:
Temporary cash investments		$103.0		$—		$—		$103.0
Securitization recovery trust account	1.7		—		—		1.7
Escrow accounts	88.6		—		—		88.6
Gas hedge contracts	0.2		—		—		0.2
Financial transmission rights	—		—		1.1		1.1
		$193.5		$—		$1.1		$194.6



2015	Level 1		Level 2		Level 3		Total
	(In Millions)
Assets:
Temporary cash investments		$87.8		$—		$—		$87.8
Securitization recovery trust account	4.6		—		—		4.6
Escrow accounts	81.0		—		—		81.0
Financial transmission rights	—		—		1.5		1.5
		$173.4		$—		$1.5		$174.9

Liabilities:
Gas hedge contracts		$0.5		$—		$—		$0.5

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Entergy Texas



2016	Level 1		Level 2		Level 3		Total
	(In Millions)
Assets:
Temporary cash investments		$5.0		$—		$—		$5.0
Securitization recovery trust account	37.5		—		—		37.5
Financial transmission rights	—		—		3.1		3.1
		$42.5		$—		$3.1		$45.6



2015	Level 1		Level 2		Level 3		Total
	(In Millions)
Assets:
Securitization recovery trust account		$38.2		$—		$—		$38.2
Financial transmission rights	—		—		2.2		2.2
		$38.2		$—		$2.2		$40.4

System Energy



2016	Level 1		Level 2		Level 3		Total
	(In Millions)
Assets:
Temporary cash investments		$245.1		$—		$—		$245.1
Decommissioning trust funds (a):
Equity securities	0.3		—		—		0.3
Debt securities	248.3		58.3		—		306.6
Common trusts (b)							473.6
		$493.7		$58.3		$—		$1,025.6



2015	Level 1		Level 2		Level 3		Total
	(In Millions)
Assets:
Temporary cash investments		$222.0		$—		$—		$222.0
Decommissioning trust funds (a):
Equity securities	1.8		—		—		1.8
Debt securities	218.6		59.2		—		277.8
Common trusts (b)							421.9
		$442.4		$59.2		$—		$923.5


(a)	The decommissioning trust funds hold equity and fixed income securities. Equity securities are invested to approximate the returns of major market indices. Fixed income securities are held in various governmental and corporate securities. See Note 16 to the financial statements for additional information on the investment portfolios.


(b)	Common trust funds are not publicly quoted, and are valued by the fund administrators using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table. The fund administrator of these investments allows daily trading at the net asset value and trades settle at a later date.

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	Entergy Arkansas			Entergy Louisiana			Entergy Mississippi			Entergy New Orleans			Entergy Texas
	(In Millions)

Balance as of January 1,		$7.9			$8.5			$2.4			$1.5			$2.2
Issuances of financial transmission rights	18.8			18.1			5.9			2.8			9.3
Gains (losses) included as a regulatory liability/asset	1.9			51.6			11.5			0.9			1.8
Settlements	(23.2		)	(69.7		)	(16.6		)	(4.1		)	(10.2		)
Balance as of December 31,		$5.4			$8.5			$3.2			$1.1			$3.1



	Entergy Arkansas			Entergy Louisiana			Entergy Mississippi			Entergy New Orleans			Entergy Texas
	(In Millions)

Balance as of January 1,		$0.7			$25.5			$3.4			$4.1			$12.3
Issuances of financial transmission rights	7.0			48.3			5.4			7.3			11.4
Gains (losses) included as a regulatory liability/asset	68.9			(9.9		)	10.1			(1.4		)	(4.7		)
Settlements	(68.7		)	(55.4		)	(16.5		)	(8.5		)	(16.8		)
Balance as of December 31,		$7.9			$8.5			$2.4			$1.5			$2.2

NOTE 16. DECOMMISSIONING TRUST FUNDS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)

Entergy holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The NRC requires Entergy subsidiaries to maintain trusts to fund the costs of decommissioning ANO 1, ANO 2, River Bend, Waterford 3, Grand Gulf, Pilgrim, Indian Point 1, Indian Point 2, Vermont Yankee, and Palisades. The funds are invested primarily in equity securities, fixed-rate debt securities, and cash and cash equivalents.

In August 2016, Entergy entered into a trust transfer agreement with NYPA to transfer the decommissioning trust funds and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants to Entergy. The transaction was contingent upon receiving approval from the NRC, which was received in January 2017. As a result of the

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agreement with NYPA, in the third quarter 2016, Entergy removed the contract asset from its balance sheet, and recorded receivables for the beneficial interests in the decommissioning trust funds and recorded asset retirement obligations for the decommissioning liabilities. At December 31, 2016, the fair values of the decommissioning trust funds held by NYPA were $719 million for the Indian Point 3 plant and $785 million for the FitzPatrick plant. The fair values are based on the trust statements received from NYPA and are valued by the fund administrator using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value hierarchy. For Indian Point 3, the receivable for the beneficial interest in the decommissioning trust fund is recorded in other deferred debits on the consolidated balance sheet. For FitzPatrick, the receivable for the beneficial interest in the decommissioning trust fund is classified as held for sale within other deferred debits on the consolidated balance sheet. The decommissioning trust funds for the Indian Point 3 and FitzPatrick plants were transferred to Entergy by NYPA in January 2017. See Note 9 to the financial statements for further discussion of the decommissioning agreements with NYPA and see Note 14 to the financial statements for further discussion of the sale of FitzPatrick.

The securities held as of December 31, 2016 and 2015 are summarized as follows:



	2016						2015
	Fair Value		Total Unrealized Gains		Total Unrealized Losses		Fair Value		Total Unrealized Gains		Total Unrealized Losses
	(In Millions)
Equity Securities		$3,511		$1,673		$1		$3,195		$1,396		$2
Debt Securities	2,213		34		27		2,155		41		17
Total		$5,724		$1,707		$28		$5,350		$1,437		$19

The fair values of the decommissioning trust funds related to the Entergy Wholesale Commodities nuclear plants as of December 31, 2016 are $443 million for Indian Point 1, $564 million for Indian Point 2, $412 million for Palisades, $960 million for Pilgrim, and $584 million for Vermont Yankee. The fair values of the decommissioning trust funds for the Registrant Subsidiaries’ nuclear plants are detailed below.

Deferred taxes on unrealized gains/(losses) are recorded in other comprehensive income (loss) for the decommissioning trusts which do not meet the criteria for regulatory accounting treatment as described above. Unrealized gains/(losses) above are reported before deferred taxes of $399 million and $342 million as of December 31, 2016 and 2015, respectively. The amortized cost of debt securities was $2,212 million as of December 31, 2016 and $2,124 million as of December 31, 2015. As of December 31, 2016, the debt securities have an average coupon rate of approximately 3.21%, an average duration of approximately 5.89 years, and an average maturity of approximately 9.39 years. The equity securities are generally held in funds that are designed to approximate or somewhat exceed the

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return of the Standard & Poor’s 500 Index. A relatively small percentage of the equity securities are held in funds intended to replicate the return of the Wilshire 4500 Index or the Russell 3000 Index.

The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2016 and 2015:



	2016								2015
	Equity Securities				Debt Securities				Equity Securities				Debt Securities
	Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses
	(In Millions)
Less than 12 months		$23		$1		$1,169		$26		$54		$2		$1,031		$15
More than 12 months	1		—		20		1		1		—		61		2
Total		$24		$1		$1,189		$27		$55		$2		$1,092		$17

The unrealized losses in excess of twelve months on equity securities above relate to Entergy’s Utility operating companies and System Energy.

The fair value of debt securities, summarized by contractual maturities, as of December 31, 2016 and 2015 are as follows:



	2016		2015
	(In Millions)
less than 1 year		$125		$77
1 year - 5 years	763		857
5 years - 10 years	719		704
10 years - 15 years	109		124
15 years - 20 years	73		50
20 years+	424		343
Total		$2,213		$2,155

During the years ended December 31, 2016, 2015, and 2014, proceeds from the dispositions of securities amounted to $2,409 million, $2,492 million, and $1,872 million, respectively. During the years ended December 31, 2016, 2015, and 2014, gross gains of $32 million, $72 million, and $39 million, respectively, and gross losses of $13 million, $13 million, and $8 million, respectively, were reclassified out of other comprehensive income into earnings.

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Entergy Arkansas

Entergy Arkansas holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held as of December 31, 2016 and 2015 are summarized as follows:



	2016						2015
	Fair Value		Total Unrealized Gains		Total Unrealized Losses		Fair Value		Total Unrealized Gains		Total Unrealized Losses
	(In Millions)
Equity Securities		$525.4		$281.5		$—		$467.4		$234.4		$0.2
Debt Securities	309.3		3.4		4.2		303.9		4.1		2.2
Total		$834.7		$284.9		$4.2		$771.3		$238.5		$2.4

The amortized cost of debt securities was $310.1 million as of December 31, 2016 and $301.8 million as of December 31, 2015. As of December 31, 2016, the debt securities have an average coupon rate of approximately 2.65%, an average duration of approximately 5.37 years, and an average maturity of approximately 6.31 years. The equity securities are generally held in funds that are designed to approximate the return of the Standard & Poor’s 500 Index. A relatively small percentage of the equity securities are held in funds intended to replicate the return of the Wilshire 4500 Index.



	2016								2015
	Equity Securities				Debt Securities				Equity Securities				Debt Securities
	Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses
	(In Millions)
Less than 12 months		$—		$—		$146.7		$4.2		$7.8		$0.2		$111.4		$1.7
More than 12 months	—		—		—		—		—		—		18.5		0.5
Total		$—		$—		$146.7		$4.2		$7.8		$0.2		$129.9		$2.2

The fair value of debt securities, summarized by contractual maturities, as of December 31, 2016 and 2015 are as follows:



	2016		2015
	(In Millions)
less than 1 year		$16.7		$1.8
1 year - 5 years	106.2		145.2
5 years - 10 years	161.2		138.5
10 years - 15 years	7.7		2.4
15 years - 20 years	1.0		2.0
20 years+	16.5		14.0
Total		$309.3		$303.9

During the years ended December 31, 2016, 2015, and 2014, proceeds from the dispositions of securities amounted to $197.4 million, $213 million, and $181.5 million, respectively. During the years ended December 31,

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2016, 2015, and 2014, gross gains of $1.8 million, $5.9 million, and $8.7 million, respectively, and gross losses of $0.8 million, $0.3 million, and $0.3 million, respectively, were recorded in earnings.

Entergy Louisiana

Entergy Louisiana holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held as of December 31, 2016 and 2015 are summarized as follows:



	2016						2015
	Fair Value		Total Unrealized Gains		Total Unrealized Losses		Fair Value		Total Unrealized Gains		Total Unrealized Losses
	(In Millions)
Equity Securities		$715.9		$346.6		$—		$632.4		$283.7		$0.2
Debt Securities	424.8		8.0		5.0		409.9		13.2		2.4
Total		$1,140.7		$354.6		$5.0		$1,042.3		$296.9		$2.6

The amortized cost of debt securities was $421.9 million as of December 31, 2016 and $399.2 million as of December 31, 2015. As of December 31, 2016, the debt securities have an average coupon rate of approximately 3.78%, an average duration of approximately 5.59 years, and an average maturity of approximately 10.99 years. The equity securities are generally held in funds that are designed to approximate the return of the Standard & Poor’s 500 Index. A relatively small percentage of the equity securities are held in funds intended to replicate the return of the Wilshire 4500 Index.



	2016								2015
	Equity Securities				Debt Securities				Equity Securities				Debt Securities
	Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses
	(In Millions)
Less than 12 months		$—		$—		$198.8		$4.8		$9.4		$0.2		$124.0		$2.0
More than 12 months	—		—		4.8		0.2		—		—		7.4		0.4
Total		$—		$—		$203.6		$5.0		$9.4		$0.2		$131.4		$2.4

The fair value of debt securities, summarized by contractual maturities, as of December 31, 2016 and 2015 are as follows:



	2016		2015
	(In Millions)
less than 1 year		$31.4		$27.1
1 year - 5 years	99.1		124.0
5 years - 10 years	122.8		114.3
10 years - 15 years	41.4		39.3
15 years - 20 years	30.9		26.5
20 years+	99.2		78.7
Total		$424.8		$409.9

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During the years ended December 31, 2016, 2015, and 2014, proceeds from the dispositions of securities amounted to $219.2 million, $123.5 million, and $216.7 million, respectively. During the years ended December 31, 2016, 2015, and 2014, gross gains of $3.9 million, $1.9 million, and $2.2 million, respectively, and gross losses of $0.4 million, $0.3 million, and $0.3 million, respectively, were recorded in earnings.

System Energy

System Energy holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held as of December 31, 2016 and 2015 are summarized as follows:



	2016						2015
	Fair Value		Total Unrealized Gains		Total Unrealized Losses		Fair Value		Total Unrealized Gains		Total Unrealized Losses
	(In Millions)
Equity Securities		$473.9		$221.9		$0.1		$423.7		$179.2		$0.3
Debt Securities	306.6		2.0		4.5		277.8		2.2		2.3
Total		$780.5		$223.9		$4.6		$701.5		$181.4		$2.6

The amortized cost of debt securities was $309.1 million as of December 31, 2016 and $270.7 million as of December 31, 2015. As of December 31, 2016, the debt securities have an average coupon rate of approximately 1.89%, an average duration of approximately 5.04 years, and an average maturity of approximately 6.30 years. The equity securities are generally held in funds that are designed to approximate the return of the Standard & Poor’s 500 Index. A relatively small percentage of the equity securities are held in funds intended to replicate the return of the Wilshire 4500 Index.



	2016								2015
	Equity Securities				Debt Securities				Equity Securities				Debt Securities
	Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses		Fair Value		Gross Unrealized Losses
	(In Millions)
Less than 12 months		$—		$—		$220.9		$4.4		$8.3		$0.2		$200.4		$2.2
More than 12 months	—		0.1		0.8		0.1		0.9		0.1		5.0		0.1
Total		$—		$0.1		$221.7		$4.5		$9.2		$0.3		$205.4		$2.3

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The fair value of debt securities, summarized by contractual maturities, as of December 31, 2016 and 2015 are as follows:



	2016		2015
	(In Millions)
less than 1 year		$6.6		$2.0
1 year - 5 years	188.2		181.2
5 years - 10 years	78.5		63.0
10 years - 15 years	1.3		4.4
15 years - 20 years	7.8		1.6
20 years+	24.2		25.6
Total		$306.6		$277.8

During the years ended December 31, 2016, 2015, and 2014, proceeds from the dispositions of securities amounted to $499.3 million, $390.4 million, and $392.9 million, respectively. During the years ended December 31, 2016, 2015, and 2014, gross gains of $3.5 million, $3.3 million, and $1.8 million, respectively, and gross losses of $1.7 million, $0.5 million, and $0.9 million, respectively, were recorded in earnings.

Other-than-temporary impairments and unrealized gains and losses

Entergy evaluates investment securities in the Entergy Wholesale Commodities’ nuclear decommissioning trust funds with unrealized losses at the end of each period to determine whether an other-than-temporary impairment has occurred. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs. Further, if Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary impairment is considered to have occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss). Entergy did not have any material other-than-temporary impairments relating to credit losses on debt securities for the years ended December 31, 2016, 2015, and 2014. The assessment of whether an investment in an equity security has suffered an other-than-temporary impairment is based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time. Entergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. Entergy did not record material charges to other income in 2016, 2015, and 2014, respectively, resulting from the recognition of the other-than-temporary impairment of certain equity securities held in its decommissioning trust funds.

NOTE 17. VARIABLE INTEREST ENTITIES (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Under applicable authoritative accounting guidance, a variable interest entity (VIE) is an entity that conducts a business or holds property that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or where equity holders do not receive expected losses or returns. An entity may have an interest in a VIE through ownership or other contractual rights or obligations, and is required to consolidate a VIE if it is the VIE’s primary beneficiary. The primary beneficiary of a VIE is the entity that has the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance, and has the obligation to absorb losses or has the right to residual returns that would potentially be significant to the entity.

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Notes to Financial Statements

Entergy Arkansas, Entergy Louisiana, and System Energy consolidate the respective companies from which they lease nuclear fuel, usually in a sale and leaseback transaction. This is because Entergy directs the nuclear fuel companies with respect to nuclear fuel purchases, assists the nuclear fuel companies in obtaining financing, and, if financing cannot be arranged, the lessee (Entergy Arkansas, Entergy Louisiana, or System Energy) is responsible to repurchase nuclear fuel to allow the nuclear fuel company (the VIE) to meet its obligations. During the term of the arrangements, none of the Entergy operating companies have been required to provide financial support apart from their scheduled lease payments. See Note 4 to the financial statements for details of the nuclear fuel companies’ credit facility and commercial paper borrowings and long-term debt that are reported by Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy. These amounts also represent Entergy’s and the respective Registrant Subsidiary’s maximum exposure to losses associated with their respective interests in the nuclear fuel companies.

Entergy Gulf States Reconstruction Funding I, LLC, and Entergy Texas Restoration Funding, LLC, companies wholly-owned and consolidated by Entergy Texas, are variable interest entities and Entergy Texas is the primary beneficiary. In June 2007, Entergy Gulf States Reconstruction Funding issued senior secured transition bonds (securitization bonds) to finance Entergy Texas’s Hurricane Rita reconstruction costs. In November 2009, Entergy Texas Restoration Funding issued senior secured transition bonds (securitization bonds) to finance Entergy Texas’s Hurricane Ike and Hurricane Gustav restoration costs. With the proceeds, the variable interest entities purchased from Entergy Texas the transition property, which is the right to recover from customers through a transition charge amounts sufficient to service the securitization bonds. The transition property is reflected as a regulatory asset on the consolidated Entergy Texas balance sheet. The creditors of Entergy Texas do not have recourse to the assets or revenues of the variable interest entities, including the transition property, and the creditors of the variable interest entities do not have recourse to the assets or revenues of Entergy Texas. Entergy Texas has no payment obligations to the variable interest entities except to remit transition charge collections. See Note 5 to the financial statements for additional details regarding the securitization bonds.

Entergy Arkansas Restoration Funding, LLC, a company wholly-owned and consolidated by Entergy Arkansas, is a variable interest entity and Entergy Arkansas is the primary beneficiary. In August 2010, Entergy Arkansas Restoration Funding issued storm cost recovery bonds to finance Entergy Arkansas’s January 2009 ice storm damage restoration costs. With the proceeds, Entergy Arkansas Restoration Funding purchased from Entergy Arkansas the storm recovery property, which is the right to recover from customers through a storm recovery charge amounts sufficient to service the securitization bonds. The storm recovery property is reflected as a regulatory asset on the consolidated Entergy Arkansas balance sheet. The creditors of Entergy Arkansas do not have recourse to the assets or revenues of Entergy Arkansas Restoration Funding, including the storm recovery property, and the creditors of Entergy Arkansas Restoration Funding do not have recourse to the assets or revenues of Entergy Arkansas. Entergy Arkansas has no payment obligations to Entergy Arkansas Restoration Funding except to remit storm recovery charge collections. See Note 5 to the financial statements for additional details regarding the storm cost recovery bonds.

Entergy Louisiana Investment Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy Louisiana, is a variable interest entity and Entergy Louisiana is the primary beneficiary. In September 2011, Entergy Louisiana Investment Recovery Funding issued investment recovery bonds to recover Entergy Louisiana’s investment recovery costs associated with the canceled Little Gypsy repowering project. With the proceeds, Entergy Louisiana Investment Recovery Funding purchased from Entergy Louisiana the investment recovery property, which is the right to recover from customers through an investment recovery charge amounts sufficient to service the bonds. The investment recovery property is reflected as a regulatory asset on the consolidated Entergy Louisiana balance sheet. The creditors of Entergy Louisiana do not have recourse to the assets or revenues of Entergy Louisiana Investment Recovery Funding, including the investment recovery property, and the creditors of Entergy Louisiana Investment Recovery Funding do not have recourse to the assets or revenues of Entergy Louisiana. Entergy Louisiana has no payment obligations to Entergy Louisiana Investment Recovery Funding except to remit investment recovery charge collections. See Note 5 to the financial statements for additional details regarding the investment recovery bonds.

Entergy New Orleans Storm Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy New Orleans, is a variable interest entity, and Entergy New Orleans is the primary beneficiary. In July 2015,

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Notes to Financial Statements

Entergy New Orleans Storm Recovery Funding issued storm cost recovery bonds to recover Entergy New Orleans’s Hurricane Isaac storm restoration costs, including carrying costs, the costs of funding and replenishing the storm recovery reserve, and up-front financing costs associated with the securitization. With the proceeds, Entergy New Orleans Storm Recovery Funding purchased from Entergy New Orleans the storm recovery property, which is the right to recover from customers through a storm recovery charge amounts sufficient to service the securitization bonds. The storm recovery property is reflected as a regulatory asset on the consolidated Entergy New Orleans balance sheet. The creditors of Entergy New Orleans do not have recourse to the assets or revenues of Entergy New Orleans Storm Recovery Funding, including the storm recovery property, and the creditors of Entergy New Orleans Storm Recovery Funding do not have recourse to the assets or revenues of Entergy New Orleans. Entergy New Orleans has no payment obligations to Entergy New Orleans Storm Recovery Funding except to remit storm recovery charge collections. See Note 5 to the financial statements for additional details regarding the securitization bonds.

Entergy Louisiana was considered to hold a variable interest in the lessor from which it leased an undivided interest in the Waterford 3 nuclear plant. After Entergy Louisiana acquired a beneficial interest in the leased assets in March 2016, however, the lessor was no longer considered a variable interest entity. Entergy Louisiana made payments on its lease, including interest, of $9.2 million through March 2016, $28.8 million in 2015, and $31 million in 2014. See Note 10 to the financial statements for a discussion of Entergy Louisiana’s purchase of the Waterford 3 leased assets.

System Energy is considered to hold a variable interest in the lessor from which it leases an undivided interest in the Grand Gulf nuclear plant. System Energy is the lessee under this arrangement, which is described in more detail in Note 10 to the financial statements. System Energy made payments on its lease, including interest, of $17.2 million in 2016, $52.3 million in 2015, and $51.6 million in 2014. The lessor is a bank acting in the capacity of owner trustee for the benefit of equity investors in the transaction pursuant to trust agreement entered solely for the purpose of facilitating the lease transaction. It is possible that System Energy may be considered as the primary beneficiary of the lessor, but Entergy is unable to apply the authoritative accounting guidance with respect to this VIE because the lessor is not required to, and could not, provide the necessary financial information to consolidate the lessor. Because Entergy accounts for this leasing arrangement as a capital financing, however, Entergy believes that consolidating the lessor would not materially affect the financial statements. In the unlikely event of default under a lease, remedies available to the lessor include payment by the lessee of the fair value of the undivided interest in the plant, payment of the present value of the basic rent payments, or payment of a predetermined casualty value. Entergy believes, however, that the obligations recorded on the balance sheet materially represent the company’s potential exposure to loss.

Entergy has also reviewed various lease arrangements, power purchase agreements, including agreements for renewable power, and other agreements that represent variable interests in other legal entities which have been determined to be variable interest entities. In these cases, Entergy has determined that it is not the primary beneficiary of the related VIE because it does not have the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance, or it does not have the obligation to absorb losses or the right to residual returns that would potentially be significant to the entity, or both.

NOTE 18. TRANSACTIONS WITH AFFILIATES (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Each Registrant Subsidiary purchases electricity from or sells electricity to the other Registrant Subsidiaries, or both, under rate schedules filed with FERC. The Registrant Subsidiaries receive management, technical, advisory, operating, and administrative services from Entergy Services; and receive management, technical, and operating services from Entergy Operations. These transactions are on an “at cost” basis.

As described in Note 1 to the financial statements, all of System Energy’s operating revenues consist of billings to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.

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Notes to Financial Statements

As described in Note 4 to the financial statements, the Registrant Subsidiaries participate in Entergy’s money pool and earn interest income from the money pool. As described in Note 2 to the financial statements, Entergy Louisiana receives preferred membership interest distributions from Entergy Holdings Company.

The tables below contain the various affiliate transactions of the Utility operating companies, System Energy, and other Entergy affiliates.

Intercompany Revenues



	Entergy Arkansas		Entergy Louisiana		Entergy Mississippi		Entergy New Orleans		Entergy Texas		System Energy
	(In Millions)
2016		$49.4		$376.6		$2.9		$30.3		$180.2		$548.3
2015		$127.9		$420.2		$86.0		$66.1		$259.1		$632.4
2014		$131.2		$440.2		$169.8		$80.1		$316.1		$664.4

Intercompany Operating Expenses



	Entergy Arkansas		Entergy Louisiana		Entergy Mississippi		Entergy New Orleans		Entergy Texas		System Energy
	(In Millions)
2016		$467.4		$670.8		$256.5		$276.7		$343.7		$146.0
2015		$508.5		$929.4		$331.8		$278.4		$413.7		$155.1
2014		$596.6		$1,027.6		$367.6		$249.5		$445.3		$156.7

Intercompany Interest and Investment Income



	Entergy Louisiana		Entergy Mississippi		System Energy
	(In Millions)

2016		$127.7		$0.1		$0.1
2015		$133.6		$—		$—
2014		$117.9		$—		$—

Transactions with Equity Method Investees

EWO Marketing, LLC, an indirect wholly-owned subsidiary of Entergy, paid capacity charges and gas transportation to RS Cogen in the amounts of $24.7 million in 2016, $24.5 million in 2015, and $23.1 million in 2014.

Entergy’s operating transactions with its other equity method investees were not significant in 2016, 2015, or 2014.

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Notes to Financial Statements

NOTE 19. QUARTERLY FINANCIAL DATA (UNAUDITED) (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Operating results for the four quarters of 2016 and 2015 for Entergy Corporation and subsidiaries were:



	Operating Revenues		Operating Income (Loss)			Consolidated Net Income (Loss)			Net Income (Loss) Attributable to Entergy Corporation
	(In Thousands)
2016:
First Quarter		$2,609,852		$498,218			$235,242			$229,966
Second Quarter		$2,462,562		$442,258			$572,590			$567,314
Third Quarter		$3,124,703		$772,060			$393,204			$388,170
Fourth Quarter		$2,648,528		($2,599,001	)		($1,765,539	)		($1,769,068	)
2015:
First Quarter		$2,920,090		$542,769			$302,929			$298,050
Second Quarter		$2,713,231		$377,383			$153,722			$148,843
Third Quarter		$3,371,406		($965,016	)		($718,233	)		($723,027	)
Fourth Quarter		$2,508,523		($254,300	)		$104,849			$99,573

Earnings (loss) per average common share



	2016						2015
	Basic			Diluted			Basic			Diluted
First Quarter		$1.29			$1.28			$1.66			$1.65
Second Quarter		$3.17			$3.16			$0.83			$0.83
Third Quarter		$2.17			$2.16			($4.04	)		($4.04	)
Fourth Quarter		($9.89	)		($9.86	)		$0.56			$0.56

Results of operations for 2016 include $2,836 million ($1,829 million net-of-tax) of impairment and related charges primarily to write down the carrying values of the Entergy Wholesale Commodities’ Palisades, Indian Point 2, and Indian Point 3 plants and related assets to their fair values. See Note 14 to the financial statements for further discussion of the impairment and related charges. Results of operations for 2016 also include a reduction of income tax expense, net of unrecognized tax benefits, of $238 million as a result of a tax election to treat a subsidiary that owns one of the Entergy Wholesale Commodities nuclear power plants as a corporation for federal income tax purposes; income tax benefits as a result of the settlement of the 2010-2011 IRS audit, including a $75 million tax benefit recognized by Entergy Louisiana related to the treatment of the Vidalia purchased power agreement and a $54 million net benefit recognized by Entergy Louisiana related to the treatment of proceeds received in 2010 for the financing of Hurricane Gustav and Hurricane Ike storm costs pursuant to Louisiana Act 55; and a reduction in expenses of $100 million ($64 million net-of-tax) due to the effects of recording in 2016 the final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. See Note 3 to the financial statements for additional discussion of the income tax items and Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.

Results of operations for 2015 includes $2,036 million ($1,317 million net-of-tax) of impairment and related charges primarily to write down the carrying values of the Entergy Wholesale Commodities’ FitzPatrick, Pilgrim, and Palisades plants and related assets to their fair values. See Note 14 to the financial statements for further discussion of the impairment and related charges. As a result of the Entergy Louisiana and Entergy Gulf States Louisiana business

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Notes to Financial Statements

combination, results of operations for 2015 also include two items that occurred in October 2015: 1) a deferred tax asset and resulting net increase in tax basis of approximately $334 million and 2) a regulatory liability of $107 million ($66 million net-of-tax) as a result of customer credits to be realized by electric customers of Entergy Louisiana, consistent with the terms of the stipulated settlement in the business combination proceeding. See Note 2 to the financial statements for further discussion of the business combination and customer credits. Results of operations for 2015 also include the sale in December 2015 of the 583 MW Rhode Island State Energy Center for a realized gain of $154 million ($100 million net-of-tax) on the sale and the $77 million ($47 million net-of-tax) write-off and regulatory charges to recognize that a portion of the assets associated with the Waterford 3 replacement steam generator project is no longer probable of recovery. See Note 2 to the financial statements for further discussion of the Waterford 3 write-off.

The business of the Utility operating companies is subject to seasonal fluctuations with the peak periods occurring during the third quarter. Operating results for the Registrant Subsidiaries for the four quarters of 2016 and 2015 were:

Operating Revenues



	Entergy Arkansas		Entergy Louisiana		Entergy Mississippi		Entergy New Orleans		Entergy Texas		System Energy
	(In Thousands)
2016:
First Quarter		$465,373		$955,145		$263,046		$149,340		$378,304		$137,693
Second Quarter		$504,252		$999,034		$248,138		$164,920		$412,922		$151,323
Third Quarter		$654,599		$1,249,452		$309,739		$201,336		$442,085		$114,039
Fourth Quarter		$462,384		$973,417		$273,726		$149,867		$382,308		$145,236
2015:
First Quarter		$511,253		$1,069,191		$360,815		$156,626		$411,211		$156,039
Second Quarter		$551,809		$1,074,598		$344,975		$160,752		$402,921		$163,101
Third Quarter		$714,353		$1,298,482		$410,743		$209,733		$498,249		$155,899
Fourth Quarter		$476,149		$974,875		$280,452		$144,335		$394,822		$157,366

Operating Income (Loss)



	Entergy Arkansas			Entergy Louisiana		Entergy Mississippi		Entergy New Orleans		Entergy Texas		System Energy
	(In Thousands)
2016:
First Quarter		$54,378			$181,618		$41,573		$21,880		$41,269		$47,466
Second Quarter		$73,447			$193,752		$61,890		$26,913		$58,039		$45,020
Third Quarter		$188,660			$312,951		$88,312		$42,279		$107,964		$43,886
Fourth Quarter		$29,843			$111,066		$32,464		$8,807		$38,338		$44,781
2015:
First Quarter		$36,656			$185,776		$54,839		$20,745		$44,013		$47,784
Second Quarter		$55,149			$191,068		$58,086		$20,154		$44,064		$45,470
Third Quarter		$109,236			$294,436		$74,264		$34,734		$86,624		$47,135
Fourth Quarter		($21,635	)		$47,052		$24,717		$9,337		$8,944		$45,239

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Notes to Financial Statements

Net Income (Loss)



	Entergy Arkansas			Entergy Louisiana		Entergy Mississippi		Entergy New Orleans		Entergy Texas			System Energy
	(In Thousands)
2016:
First Quarter		$19,294			$111,606		$17,118		$11,167		$14,562			$25,958
Second Quarter		$33,891			$253,325		$32,194		$11,843		$24,058			$25,090
Third Quarter		$110,148			$189,506		$46,612		$23,701		$56,133			$22,370
Fourth Quarter		$3,879			$67,610		$13,260		$2,138		$12,785			$23,326
2015:
First Quarter		$17,865			$126,109		$24,935		$11,292		$16,591			$25,533
Second Quarter		$21,525			$108,981		$26,279		$10,895		$14,890			$21,860
Third Quarter		$55,662			$187,140		$36,576		$19,163		$43,314			$25,223
Fourth Quarter		($20,780	)		$24,409		$4,918		$3,575		($5,170	)		$38,702

Earnings (Loss) Applicable to Common Equity



	Entergy Arkansas			Entergy Louisiana		Entergy Mississippi		Entergy New Orleans
	(In Thousands)
2016:
First Quarter		$17,576			$111,606		$16,411		$10,926
Second Quarter		$32,173			$253,325		$31,487		$11,602
Third Quarter		$108,672			$189,506		$45,905		$23,460
Fourth Quarter		$3,521			$67,610		$12,938		$1,896
2015:
First Quarter		$16,147			$124,165		$24,228		$11,051
Second Quarter		$19,807			$107,037		$25,572		$10,654
Third Quarter		$53,944			$185,290		$35,869		$18,922
Fourth Quarter		($22,499	)		$24,410		$4,211		$3,333

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ENTERGY’S BUSINESS

Entergy is an integrated energy company engaged primarily in electric power production and retail distribution operations. Entergy owns and operates power plants with approximately 30,000 MW of electric generating capacity, including nearly 10,000 MW of nuclear power. Entergy delivers electricity to 2.9 million utility customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy had annual revenues of $10.8 billion in 2016 and had more than 13,000 employees as of December 31, 2016.

Entergy operates primarily through two business segments: Utility and Entergy Wholesale Commodities.


•	The Utility business segment includes the generation, transmission, distribution, and sale of electric power in portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans; and operation of a small natural gas distribution business.

•

The Entergy Wholesale Commodities business segment includes the ownership, operation, and decommissioning of nuclear power plants located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. Entergy Wholesale Commodities also provides services to other nuclear power plant owners and owns interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the Merchant Power Business” for discussion of the operation and planned shutdown or sale of each of the Entergy Wholesale Commodities nuclear power plants.

See Note 13 to the financial statements for financial information regarding Entergy’s business segments.

Strategy

Entergy’s mission is to operate a world-class energy business that creates sustainable value for its owners, customers, employees, and communities. Entergy aspires to achieve top quartile total shareholder returns in a socially and environmentally responsible fashion by leveraging the scale and expertise inherent in its operations. Entergy’s current scope includes electricity generation, transmission, and distribution as well as natural gas distribution. Entergy focuses on operational excellence with an emphasis on safety, reliability, customer service, sustainability, cost efficiency, risk management, and engaged employees. Entergy also continually seeks opportunities to grow its utility business to benefit all stakeholders and to optimize its portfolio of assets in an ever-dynamic market through periodic buy, build, hold, or disposal decisions. To accomplish this, Entergy has established strategic imperatives for each business segment. For the Utility, the strategic imperative is to modernize its operations, maintain reliability, and better serve its customers while growing the business. For Entergy Wholesale Commodities, the strategic imperative is to continue to manage the risk of its operating portfolio as Entergy completes its exit from the merchant power business.

Utility

The Utility business segment includes five wholly-owned retail electric utility subsidiaries: Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas. These companies generate, transmit, distribute and sell electric power to retail and wholesale customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy Louisiana and Entergy New Orleans also provide natural gas utility services to customers in and around Baton Rouge, Louisiana, and New Orleans, Louisiana, respectively. Also included in the Utility is System Energy, a wholly-owned subsidiary of Entergy Corporation that owns or leases 90 percent of Grand Gulf. System Energy sells its power and capacity from Grand Gulf at wholesale to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. The five retail utility subsidiaries are each regulated by the FERC and by state utility commissions, or, in the case of Entergy New Orleans, the City Council. System Energy is regulated by the FERC because all of its transactions are at wholesale. The overall generation portfolio of the Utility, which relies heavily on natural gas and nuclear generation, is consistent with Entergy’s strong support for the environment.

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Customers

As of December 31, 2016, the Utility operating companies provided retail electric and gas service to customers in Arkansas, Louisiana, Mississippi, and Texas, as follows:



		Electric Customers			Gas Customers
	Area Served	(In Thousands)	(%)		(In Thousands)	(%)
Entergy Arkansas	Portions of Arkansas	707	25	%
Entergy Louisiana	Portions of Louisiana	1,072	37	%	93	47	%
Entergy Mississippi	Portions of Mississippi	447	16	%
Entergy New Orleans	City of New Orleans	198	7	%	106	53	%
Entergy Texas	Portions of Texas	444	15	%
Total customers		2,868	100	%	199	100	%

Electric Energy Sales

The electric energy sales of the Utility operating companies are subject to seasonal fluctuations, with the peak sales period normally occurring during the third quarter of each year. On July 21, 2016, Entergy reached a 2016 peak demand of 21,387 MWh, compared to the 2015 peak of 21,730 MWh recorded on July 29, 2015. Selected electric energy sales data is shown in the table below:

Selected 2016 Electric Energy Sales Data



	Entergy Arkansas	Entergy Louisiana	Entergy Mississippi	Entergy New Orleans	Entergy Texas	System Energy	Entergy (a)
	(In GWh)
Sales to retail customers	20,638	54,599	13,443	5,734	18,182	—	112,595
Sales for resale:
Affiliates	1,609	7,345	—	1,071	4,625	5,384	—
Others	7,115	1,690	1,021	141	1,086	—	11,054
Total	29,362	63,634	14,464	6,946	23,893	5,384	123,649
Average use per residential customer (kWh)	12,933	14,956	15,013	12,534	15,035	—	14,316


(a)	Includes the effect of intercompany eliminations.

The following table illustrates the Utility operating companies’ 2016 combined electric sales volume as a percentage of total electric sales volume, and 2016 combined electric revenues as a percentage of total 2016 electric revenue, each by customer class.



Customer Class	% of Sales Volume	% of Revenue
Residential	28.4	37.1
Commercial	23.6	26.6
Industrial (a)	37.0	26.2
Governmental	2.1	2.4
Wholesale/Other	8.9	7.7


(a)	Major industrial customers are primarily in the petroleum refining and chemical industries.

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See “Selected Financial Data” for each of the Utility operating companies for the detail of their sales by customer class for 2012-2016.

Selected 2016 Natural Gas Sales Data

Entergy New Orleans and Entergy Louisiana provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Louisiana sold 10,102,437 and 6,288,105 Mcf, respectively, of natural gas to retail customers in 2016. In 2016, 99% of Entergy Louisiana’s operating revenue was derived from the electric utility business, and only 1% from the natural gas distribution business. For Entergy New Orleans, 88% of operating revenue was derived from the electric utility business and 12% from the natural gas distribution business in 2016.

Following is data concerning Entergy New Orleans’s 2016 retail operating revenue sources.



Customer Class	Electric Operating Revenue	Natural Gas Operating Revenue
Residential	43%	48%
Commercial	38%	27%
Industrial	6%	7%
Governmental/Municipal	13%	18%

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Retail Rate Regulation

General (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas)

Each Utility operating company regularly participates in retail rate proceedings. The status of material retail rate proceedings is described in Note 2 to the financial statements. Certain aspects of the Utility operating companies’ retail rate mechanisms are discussed below.



	Rate base (in billions)	Current authorized return on common equity	Weighted average cost of capital (after-tax)	Equity ratio	Regulatory construct

Entergy Arkansas	$6.609 (a)	9.25% -10.25%	4.54%	30.91%	- forward test year formula rate plan - riders: MISO, capacity, Grand Gulf, energy efficiency, fuel and purchased power

Entergy Louisiana (electric)	$7.4 (b)	9.15% - 10.75%	7.75%	53.10%	- formula rate plan - riders/specific recovery: MISO, capacity, fuel, Ninemile 6 and Union outside of sharing

Entergy Louisiana (gas)	$0.055 (c)	9.45% - 10.45%	7.54%	51.63%	- gas rate stabilization plan - rider: gas infrastructure

Entergy Mississippi	$1.979 (d)	9.89% - 11.97%	7.96%	48.22%	- formula rate plan with forward-looking features - riders: power management, Grand Gulf, fuel, MISO, unit power cost, storm damage, energy efficiency, ad valorem tax adjustment

Entergy New Orleans (electric)	$0.299 (e)	10.7% - 11.5%	8.58%	50.08%	- rate case - riders/specific recovery: fuel, capacity

Entergy New Orleans (gas)	$0.089 (f)	10.25% - 11.25%	8.40%	50.08%	- rate case - rider: purchased gas

Entergy Texas	$1.634 (g)	9.8%	8.22%	48.6%	- rate case - riders: fuel, distribution and transmission, RPCE payments and rate case expenses, among others

System Energy	$1.307 (h)	10.94%	8.92%	65%	- monthly cost of service

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(a)	Based on 2017 forward test year.


(b)	Based on December 31, 2015 test year and excludes approximately $475 million first-year average rate base for Union.


(c)	Based on September 30, 2015 test year.


(d)	Based on 2016 forward test year.


(e)	Based on December 31, 2011 test year and excludes approximately $228 million first-year average rate base for Union.


(f)	Based on December 31, 2011 test year.


(g)	Based on March 31, 2013 adjusted test year.


(h)	Based on calculation as of December 31, 2016.

Entergy Arkansas

Fuel and Purchased Power Cost Recovery

Entergy Arkansas’s rate schedules include an energy cost recovery rider to recover fuel and purchased power costs in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery, including carrying charges, of the energy cost for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs. In December 2007 the APSC issued an order stating that Entergy Arkansas’s energy cost recovery rider will remain in effect, and any future termination of the rider would be subject to eighteen months advance notice by the APSC, which would occur following notice and hearing.

Entergy Louisiana

Fuel Recovery

Entergy Louisiana’s rate schedules include a fuel adjustment clause designed to recover the cost of fuel and purchased power costs. The fuel adjustment clause contains a surcharge or credit for deferred fuel expense and related carrying charges arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers, including carrying charges. See Note 2 to the financial statements for a discussion of proceedings related to audits of Entergy Louisiana’s fuel adjustment clause filings.

To help stabilize electricity costs, Entergy Louisiana received approval from the LPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Louisiana hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.

Entergy Louisiana’s gas rates include a purchased gas adjustment clause based on estimated gas costs for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.

To help stabilize retail gas costs, Entergy Louisiana received approval from the LPSC to hedge its exposure to natural gas price volatility for its gas purchased for resale through the use of financial instruments. Entergy Louisiana hedges approximately one-half of the projected natural gas volumes used to serve its natural gas customers for November through March. The hedge quantity is reviewed on an annual basis.

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Storm Cost Recovery

See Note 2 to the financial statements for a discussion of Entergy Louisiana’s filings to recover storm-related costs.

Entergy Mississippi

Fuel Recovery

Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power costs. The energy cost rate for each calendar year is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy costs as of the 12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.

Power Management Rider

In November 2005 the MPSC approved the purchase of the Attala power plant and recovery of the investment cost through Entergy Mississippi’s power management rider. Entergy Mississippi recovered the annual ownership costs of the Attala plant through the power management rider until resolution of its general rate case. In 2012 the MPSC approved the purchase of the Hinds power plant and recovery of the investment cost through Entergy Mississippi’s power management rider. Entergy Mississippi recovered the annual ownership costs of the Hinds plant through the power management rider until resolution of its general rate case. See Note 2 to the financial statements for a discussion of Entergy Mississippi’s 2014 general rate case. Included in the rate changes and revenue adjustments effective with February 2015 bills was the realignment of the annual ownership costs associated with the Attala plant and the Hinds plant from the power management rider to base rates.

To help stabilize electricity costs, Entergy Mississippi received approval from the MPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Mississippi hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.

Storm Cost Recovery

See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Mississippi’s storm-related costs.

Entergy New Orleans

Fuel Recovery

Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges. In October 2005 the City Council approved modification of the current gas cost collection mechanism effective November 2005 in order to address concerns regarding its fluctuations, particularly during the winter heating season. The modifications are intended to minimize fluctuations in gas rates during the winter months.

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To help stabilize gas costs, Entergy New Orleans seeks approval annually from the City Council to continue implementation of its natural gas hedging program consistent with the City Council’s stated policy objectives. The program uses financial instruments to hedge exposure to volatility in the wholesale price of natural gas purchased to serve Entergy New Orleans gas customers. Entergy New Orleans hedges up to 25% of actual gas sales made during the winter months.

Storm Cost Recovery

See Note 2 to the financial statements for a discussion of Entergy New Orleans’s efforts to recover storm-related costs.

Entergy Texas

Fuel Recovery

Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, that are not included in base rates. Semi-annual revisions of the fixed fuel factor are made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. The PUCT fuel cost proceedings are discussed in Note 2 to the financial statements.

Electric Industry Restructuring

In June 2009, a law was enacted in Texas that required Entergy Texas to cease all activities relating to Entergy Texas’s transition to competition. The law allows Entergy Texas to remain a part of the SERC Region, although it does not prevent Entergy Texas from joining another power region. The law provides that proceedings to certify a power region that Entergy Texas belongs to as a qualified power region can be initiated by the PUCT, or on motion by another party, when the conditions supporting such a proceeding exist. Under the law, the PUCT may not approve a transition to competition plan for Entergy Texas until the expiration of four years from the PUCT’s certification of Entergy Texas’s power region.

The law also contains provisions that allow Entergy Texas to take advantage of a cost recovery mechanism that permits annual filings for the recovery of reasonable and necessary expenditures for transmission infrastructure improvement and changes in wholesale transmission charges. This mechanism was previously available to other non-ERCOT Texas utility companies, but not to Entergy Texas.

The law further amended already existing law that had required Entergy Texas to propose for PUCT approval a tariff to allow eligible customers the ability to contract for competitive generation. The amending language in the law provides, among other things, that: 1) the tariff shall not be implemented in a manner that harms the sustainability or competitiveness of manufacturers who choose not to participate in the tariff; 2) Entergy Texas shall “purchase competitive generation service, selected by the customer, and provide the generation at retail to the customer” and 3) Entergy Texas shall provide and price transmission service and ancillary services under that tariff at a rate that is unbundled from its cost of service. The law directs that the PUCT may not issue an order on the tariff that is contrary to an applicable decision, rule, or policy statement of a federal regulatory agency having jurisdiction.

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Entergy Texas and the other parties to the PUCT proceeding to determine the design of the competitive generation tariff were involved in negotiations throughout 2011 and 2012 with the objective of resolving as many disputed issues as possible regarding the tariff. The PUCT determined that unrecovered costs that could be recovered through the rider consist only of those costs necessary to implement and administer the competitive generation program and do not include lost revenues or embedded generation costs. The PUCT also ruled that the amount of customer load that may be included in the competitive generation service program is limited to 115 MW. After additional negotiations, and ultimately the scheduling of a hearing to resolve remaining contested issues, the PUCT issued the order approving the competitive generation service rider in July 2013. Entergy Texas filed for rehearing of the PUCT’s July 2013 order, which the PUCT denied. Entergy Texas has since filed its appeal of that PUCT order to the Travis County District Court, which found in favor of the PUCT in an order issued in October 2014. In November 2014, Entergy Texas appealed the District Court’s order which moves the appeal to the Third Court of Appeals. Entergy Texas and opposing parties filed briefs and responses in the first quarter 2015. Oral argument was held in May 2015. In March 2016 the Court of Appeals upheld the District Court’s ruling favoring the PUCT. In May 2016, Entergy Texas filed with the Texas Supreme Court a petition for review of the Court of Appeals ruling. In January 2017, Entergy Texas filed its petitioner’s brief on the merits with the Texas Supreme Court. The appeal remains pending.

In September 2011 the PUCT adopted a proposed rule implementing a distribution cost recovery factor to recover capital and capital-related costs related to distribution infrastructure. The distribution cost recovery factor permits utilities once per year to implement an increase or decrease in rates above or below amounts reflected in base rates to reflect depreciation expense, federal income tax and other taxes, and return on investment. The distribution cost recovery factor rider may be changed a maximum of four times between base rate cases, and expires in September 2019, unless otherwise extended by the Texas Legislature.

Franchises

Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 incorporated cities and towns in Arkansas. These franchises are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas franchises are considered to be contracts and, therefore, are terminable pursuant to the terms of the franchise agreement and applicable statutes.

Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in East Baton Rouge Parish. Municipal franchise agreement terms range from 25 to 60 years while parish franchise terms range from 25 to 99 years.

Entergy Mississippi has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.

Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans’s electric and gas utility properties.

Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 27 counties in eastern Texas, and holds non-exclusive franchises to provide electric service in approximately 68 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire during 2017-2058.

The business of System Energy is limited to wholesale power sales. It has no distribution franchises.

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Property and Other Generation Resources

Owned Generating Stations

The total capability of the generating stations owned and leased by the Utility operating companies and System Energy as of December 31, 2016, is indicated below:



	Owned and Leased Capability MW(a)
Company	Total	Gas/Oil	Nuclear	Coal	Hydro
Entergy Arkansas	5,231	2,143	1,818	1,196	74
Entergy Louisiana	9,572	7,081	2,132	359	—
Entergy Mississippi	3,522	3,102	—	420	—
Entergy New Orleans	512	512	—	—	—
Entergy Texas	2,272	2,007	—	265	—
System Energy	1,272	—	1,272	—	—
Total	22,381	14,845	5,222	2,240	74


(a)	“Owned and Leased Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize.

Summer peak load for the Utility has averaged 21,566 MW over the previous decade.

The Utility operating companies’ load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections. These reviews consider existing and projected demand, the availability and price of power, the location of new load, the economy, environmental regulations, public policy goals, and the age and condition of Entergy’s existing infrastructure.

The Utility operating companies’ long-term resource strategy, the “Portfolio Transformation Strategy,” calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in the addition of about 6,800 MW of new long-term resources and the deactivation of over 4,800 MW of legacy generation. As MISO market participants, the Utility operating companies also participate in MISO’s Day Ahead and Real Time Energy and Ancillary Services markets to economically dispatch generation and purchase energy to serve customers reliably and at the lowest reasonable cost.

Other Generation Resources

RFP Procurements

The Utility operating companies from time to time issue requests for proposals (RFP) to procure supply-side resources from sources other than the spot market to meet the unique regional needs of the Utility operating companies. The RFPs issued by the Utility operating companies have sought resources needed to meet near-term MISO reliability requirements as well as longer-term requirements through a broad range of wholesale power products, including limited-term (1 to 3 years) and long-term contractual products and asset acquisitions. The RFP process has resulted in selections or acquisitions, including, among other things:


•	Entergy Louisiana’s June 2005 purchase of the 718 MW, gas-fired Perryville plant, of which 35% of the output is sold to Entergy Texas;


•	Entergy Arkansas’s September 2008 purchase of the 789 MW, combined-cycle, gas-fired Ouachita Generating Facility. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, owns one-third of the facility;

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•	Entergy Arkansas’s November 2012 purchase of the 620 MW, combined-cycle, gas-fired Hot Spring Energy facility;


•	Entergy Mississippi’s November 2012 purchase of the 450 MW, combined-cycle, gas-fired Hinds Energy facility;


•	Entergy Louisiana’s construction of the 560 MW, combined-cycle, gas turbine Ninemile 6 generating facility at its existing Ninemile Point electric generating station. The facility reached commercial operation in December 2014; and


•	Entergy Louisiana’s construction of the 980 MW, combined-cycle, gas turbine St. Charles generating facility at its existing Little Gypsy electric generating station. Entergy Louisiana received regulatory approval from the LPSC in November 2016 and the facility is scheduled to be in service by June 2019.

The selection of the Lake Charles Power Station and Montgomery County Power Station self-build projects from the RFP issued on behalf of Entergy Louisiana and the RFP issued on behalf of Entergy Texas, respectively, are currently going through the regulatory approval process and, subject to such approval, full notice to proceed is expected to be issued in summer 2017 for the Lake Charles Power Station and summer 2018 for the Montgomery County Power Station. Commercial operation is estimated to occur by mid-2020 for Lake Charles Power Station and mid-2021 for Montgomery County Power Station.

The RFP process has also resulted in the selection, or confirmation of the economic merits of, long-term purchased power agreements (PPAs), including, among others:


•	River Bend 30% life-of-unit PPA between Entergy Louisiana and Entergy New Orleans for 100 MW related to Entergy Louisiana’s unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;


•	Entergy Arkansas wholesale base load capacity life-of-unit PPAs executed in 2003 totaling approximately 220 MW between Entergy Arkansas and Entergy Louisiana (110 MW) and between Entergy Arkansas and Entergy New Orleans (110 MW) related to the sale of a portion of Entergy Arkansas’s coal and nuclear base load resources (which had not been included in Entergy Arkansas’s retail rates);


•	In December 2009, Entergy Texas and Exelon Generation Company, LLC executed a 10-year agreement for 150-300 MW from the Frontier Generating Station located in Grimes County, Texas;


•	In May 2011, Entergy Texas and Calpine Energy Services, L.P. executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. Entergy Louisiana purchases 50% of the facility’s capacity and energy from Entergy Texas. In July 2014, LS Power purchased the Carville Energy Center and replaced Calpine Energy Services as the counterparty to the agreement;

•

In September 2012, Entergy Gulf States Louisiana executed a 20-year agreement for 28 MW, with the potential to purchase an additional 9 MW when available, from Rain CII Carbon LLC’s pet coke calcining facility in Sulphur, Louisiana. The facility began commercial operation in May 2013. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with the facility;


•	In March 2013, Entergy Gulf States Louisiana executed a 20-year agreement for 8.5 MW from Agrilectric Power Partners, LP’s refurbished rice hull-fueled electric generation facility located in Lake Charles, Louisiana. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with Agrilectric;


•	In September 2013, Entergy Louisiana executed a 10-year agreement with TX LFG Energy, LP, a wholly-owned subsidiary of Montauk Energy Holdings, LLC, to purchase approximately 3 MW from its landfill gas-fueled power generation facility located in Cleveland, Texas;


•	Entergy Mississippi’s cost-based purchase, beginning in January 2013, of 90 MW from Entergy Arkansas’s share of Grand Gulf (only 60 MW of this PPA came through the RFP process). Cost recovery for the 90 MW was approved by the MPSC in January 2013;


•	In April 2015, Entergy Arkansas and Stuttgart Solar, LLC executed a 20-year agreement for 81 MW from a solar photovoltaic electric generation facility located near Stuttgart, Arkansas. The APSC has approved the project, and the expected commercial operation date is in June 2019; and

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•	In November 2016, Entergy Louisiana and LS Power executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. The transaction is pending regulatory approval.

In May 2016, Entergy Arkansas issued the RFP for Long-Term Renewable Generation Resources. This RFP is seeking up to 100 MW of renewable resources, beginning as early as June 2018, to help Entergy Arkansas meet its long-term generation resource needs and increase the depth and breadth of generation supply within its generation resource portfolio.

In June 2016, Entergy Services, on behalf of Entergy Louisiana, issued the RFP for Long-Term Renewable Generation Resources. This RFP is seeking up to 200 MW of renewable resources, beginning as early as June 2018 and as late as June 1, 2020, that can provide energy, fuel diversity, and other benefits to customers.

In July 2016, Entergy Services, on behalf of Entergy New Orleans, issued the RFP for Long-Term Renewable Generation Resources. This RFP is seeking up to 20 MW of renewable resources beginning as early as June 2018 and as late as June 1, 2020 that can provide increased depth and diversity to its generation resource portfolio. This RFP includes a self-build option for an aggregated solar photovoltaic resource located within Orleans Parish, Louisiana.

Other Procurements From Third Parties

The Utility operating companies have also made resource acquisitions outside of the RFP process, including Entergy Mississippi’s January 2006 acquisition of the 480 MW, combined-cycle, gas-fired Attala power plant; Entergy Gulf States Louisiana’s March 2008 acquisition of the 322 MW, simple-cycle, gas-fired Calcasieu Generating Facility; Entergy Louisiana’s April 2011 acquisition of the 580 MW, combined-cycle, gas-fired Acadia Energy Center Unit 2; and Entergy Arkansas’s (Power Block 2), Entergy Louisiana’s (Power Blocks 3 and 4), and Entergy New Orleans’s (Power Block 1) March 2016 acquisitions of the 1,980 MW (summer rating), natural gas-fired, combined-cycle gas turbine Union Power Station power blocks, each rated at 495 MW (summer rating). The Utility operating companies have also entered into various limited- and long-term contracts in recent years as a result of bilateral negotiations.

Interconnections

The Utility operating companies’ generating units are interconnected by a transmission system operating at various voltages up to 500 kV. These generating units consist primarily of steam-electric production facilities and are provided dispatch instructions by MISO. Entergy’s Utility operating companies are MISO market participants and are interconnected with many neighboring utilities. MISO is an essential link in the safe, cost-effective delivery of electric power across all or parts of 15 U.S. states and the Canadian province of Manitoba. As a Regional Transmission Organization, MISO assures consumers of unbiased regional grid management and open access to the transmission facilities under MISO’s functional supervision. In addition, the Utility operating companies are members of the SERC Reliability Corporation (SERC). SERC is a nonprofit corporation responsible for promoting and improving the reliability, adequacy, and critical infrastructure of the bulk power supply systems in all or portions of 16 central and southeastern states. SERC serves as a regional entity with delegated authority from the North American Electric Reliability Corporation (NERC) for the purpose of proposing and enforcing reliability standards within the SERC Region.

Gas Property

As of December 31, 2016, Entergy New Orleans distributed and transported natural gas for distribution within New Orleans, Louisiana, through approximately 2,500 miles of gas pipeline. As of December 31, 2016, the gas properties of Entergy Louisiana, which are located in and around Baton Rouge, Louisiana, were not material to Entergy Louisiana’s financial position.

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Title

The Utility operating companies’ generating stations are generally located on properties owned in fee simple. Most of the substations and transmission and distribution lines are constructed on private property or public rights-of-way pursuant to easements, servitudes, or appropriate franchises. Some substation properties are owned in fee simple. The Utility operating companies generally have the right of eminent domain, whereby they may perfect title to, or secure easements or servitudes on, private property for their utility operations.

Substantially all of the physical properties and assets owned by Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are subject to the liens of mortgages securing bonds issued by those companies. The Lewis Creek generating station is owned by GSG&T, Inc., a subsidiary of Entergy Texas, and is not subject to its mortgage lien. Lewis Creek is leased to and operated by Entergy Texas.

Fuel Supply

The sources of generation and average fuel cost per kWh for the Utility operating companies and System Energy for the years 2014-2016 were:



	Natural Gas		Nuclear		Coal		Purchased Power		MISO Purchases
Year	% of Gen	Cents Per kWh	% of Gen	Cents Per kWh	% of Gen	Cents Per kWh	% of Gen	Cents Per kWh	% of Gen	Cents Per kWh
2016	41	2.44	28	0.63	7	2.65	9	3.71	15	3.13
2015	35	2.65	31	0.85	7	2.85	11	3.63	16	3.24
2014	28	4.36	33	0.89	11	2.63	9	6.16	19	4.63

Actual 2016 and projected 2017 sources of generation for the Utility operating companies and System Energy, including certain power purchases from affiliates under life of unit power purchase agreements, including the Unit Power Sales Agreement, are:



	Natural Gas				Nuclear				Coal				Purchased Power (d)				MISO Purchases (e)
	2016		2017		2016		2017		2016		2017		2016		2017		2016		2017
Entergy Arkansas (a)	27	%	36	%	50	%	55	%	15	%	9	%	2	%	—		6	%	—
Entergy Louisiana	47	%	52	%	28	%	30	%	3	%	4	%	7	%	14	%	15	%	—
Entergy Mississippi (b)	51	%	59	%	14	%	35	%	13	%	6	%	—	%	—		22	%	—
Entergy New Orleans (b)	45	%	57	%	29	%	41	%	2	%	1	%	3	%	1	%	21	%	—
Entergy Texas	37	%	31	%	9	%	16	%	5	%	11	%	36	%	42	%	13	%	—
System Energy (c)	—		—		100	%	100	%	—		—		—		—		—		—
Utility (a) (b)	41	%	42	%	28	%	42	%	7	%	6	%	9	%	10	%	15	%	—


(a)	Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 2016 and is expected to provide about 1% of its generation in 2017.


(b)	Solar power is expected to provide less than 1% of each of Entergy Mississippi’s and Entergy New Orleans's generation in 2017.

(c)

Capacity and energy from System Energy’s interest in Grand Gulf is allocated as follows under the Unit Power Sales Agreement: Entergy Arkansas - 36%; Entergy Louisiana - 14%; Entergy Mississippi - 33%; and Entergy New Orleans - 17%. Pursuant to purchased power agreements, Entergy Arkansas is selling a portion of its owned capacity and energy from Grand Gulf to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.


(d)	Excludes MISO purchases.

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(e)

In December 2013, Entergy integrated its transmission system into the MISO RTO. Entergy offers all of its generation into the MISO energy market on a day-ahead and real-time basis and bids for power in the MISO energy market to serve the demand of its customers. All MISO related purchases and sales transactions are recorded on a net hourly position and therefore the volume of MISO purchased power is not projected for 2017.

Some of the Utility’s gas-fired plants are also capable of using fuel oil, if necessary. Although based on current economics the Utility does not expect fuel oil use in 2017, it is possible that various operational events including weather or pipeline maintenance may require the use of fuel oil.

Natural Gas

The Utility operating companies have long-term firm and short-term interruptible gas contracts for both supply and transportation. Over 50% of the Utility operating companies’ power plants maintain some level of long-term firm transportation. Short-term contracts and spot-market purchases satisfy additional gas requirements. Entergy Texas owns a gas storage facility that provides reliable and flexible natural gas service to certain generating stations.

Many factors, including wellhead deliverability, storage, pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the Utility operating companies will use alternate fuels, such as oil, or rely to a larger extent on coal, nuclear generation, and purchased power.

Coal

Entergy Arkansas has committed to five one- to three-year contracts that will supply approximately 85% of the total coal supply needs in 2017. These contracts are staggered in term so that not all contracts have to be renewed the same year. The remaining 15% of total coal requirements will be satisfied by contracts with a term of less than one year. Based on continued improved Powder River Basin (PRB) coal deliveries by rail and the high cost of alternate sources and modes of transportation, no alternative coal consumption is expected at Entergy Arkansas during 2017. Coal will be transported to Arkansas via an existing transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for 2017.

Entergy Louisiana has committed to five one- to three-year contracts that will supply approximately all of Nelson Unit 6 coal needs in 2017. If needed, additional PRB coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. For the same reasons as for Entergy Arkansas’s plants, no alternative coal consumption is expected at Nelson Unit 6 during 2017. Coal will be transported to Nelson primarily via a new transportation agreement that begins in 2017 and is expected to provide the majority of Entergy Louisiana’s rail transportation requirements for 2017.

For the year 2016, coal transportation delivery to Entergy Arkansas- and Entergy Louisiana-operated coal-fired units was adequate and it is expected that delivery times in 2017 will continue to be consistent through 2017. Both Entergy Arkansas and Entergy Louisiana control a sufficient number of railcars to satisfy the rail transportation requirement.

The operator of Big Cajun 2 - Unit 3, Louisiana Generating, LLC, has advised Entergy Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2017. Entergy Louisiana’s and Entergy Texas’s coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.

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Nuclear Fuel

The nuclear fuel cycle consists of the following:


•	mining and milling of uranium ore to produce a concentrate;


•	conversion of the concentrate to uranium hexafluoride gas;


•	enrichment of the uranium hexafluoride gas;


•	fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and


•	disposal of spent fuel.

The Registrant Subsidiaries that own nuclear plants, Entergy Arkansas, Entergy Louisiana, and System Energy, are responsible through a shared regulated uranium pool for contracts to acquire nuclear material to be used in fueling Entergy’s Utility nuclear units. These companies own the materials and services in this shared regulated uranium pool on a pro rata fractional basis determined by the nuclear generation capability of each company. Any liabilities for obligations of the pooled contracts are on a several but not joint basis. The shared regulated uranium pool maintains inventories of nuclear materials during the various stages of processing. The Registrant Subsidiaries purchase enriched uranium hexafluoride for their nuclear plant reload requirements at the average inventory cost from the shared regulated uranium pool. Entergy Operations, Inc. contracts separately for the fabrication of nuclear fuel as agent on behalf of each of the Registrant Subsidiaries that owns a nuclear plant. All contracts for the disposal of spent nuclear fuel are between the DOE and the owner of a nuclear power plant.

Based upon currently planned fuel cycles, the nuclear units in both the Utility and Entergy Wholesale Commodities segments have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable or fixed prices through most of 2017 or beyond. The nuclear fuel supply portfolio for the Entergy Wholesale Commodities segment is being adjusted to reflect reduced overall requirements related to the pending sale of the FitzPatrick plant and the planned permanent shutdowns of the Palisades, Pilgrim, Indian Point 2, and Indian Point 3 plants. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. There are a number of possible supply alternatives that may be accessed to mitigate any supplier performance failure, including potentially drawing upon Entergy’s inventory intended for later generation periods depending upon its risk management strategy at that time, although the pricing of any alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. In addition, some nuclear fuel contracts are on a non-fixed price basis subject to prevailing prices at the time of delivery.

The effects of market price changes may be reduced and deferred by risk management strategies, such as negotiation of floor and ceiling amounts for long-term contracts, buying for inventory or entering into forward physical contracts at fixed prices when Entergy believes it is appropriate and useful. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S.

Entergy’s ability to assure nuclear fuel supply also depends upon the performance reliability of conversion, enrichment, and fabrication services providers. There are fewer of these providers than for uranium. For conversion and enrichment services, like uranium, Entergy diversifies its supply by supplier and country and may take special measures as needed to ensure supply of enriched uranium for the reliable fabrication of nuclear fuel. For fabrication services, each plant is dependent upon the effective performance of the fabricator of that plant’s nuclear fuel, therefore, Entergy provides additional monitoring, inspection, and oversight for the fabrication process to assure reliability and quality.

Entergy Arkansas, Entergy Louisiana, and System Energy each have made arrangements to lease nuclear fuel and related equipment and services. The lessors, which are consolidated in the financial statements of Entergy and the applicable Registrant Subsidiary, finance the acquisition and ownership of nuclear fuel through credit agreements and

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the issuance of notes. These credit facilities are subject to periodic renewal, and the notes are issued periodically, typically for terms between three and seven years.

Natural Gas Purchased for Resale

Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with three interstate and three intrastate pipelines. Entergy New Orleans has a “no-notice” service gas purchase contract with Atmos Energy which guarantees Entergy New Orleans gas delivery at specific delivery points and at any volume within the minimum and maximum set forth in the contract amounts. The Atmos Energy gas supply is transported to Entergy New Orleans pursuant to a transportation service agreement with Gulf South Pipeline Co. This service is subject to FERC-approved rates. Entergy New Orleans also makes interruptible spot market purchases.

Entergy Louisiana purchased natural gas for resale in 2016 under a firm contract from Sequent Energy Management L.P. The gas is delivered through a combination of intrastate and interstate pipelines.

As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy Louisiana’s or Entergy New Orleans’s suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.

Federal Regulation of the Utility

State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies. The FERC regulates wholesale sales of electricity rates and interstate transmission of electricity, including System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. See Note 2 to the financial statements for further discussion of federal regulation proceedings.

System Agreement (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)

Prior to each operating company’s termination of participation in the System Agreement (Entergy Arkansas in December 2013, Entergy Mississippi in November 2015, and Entergy Louisiana, Entergy New Orleans, and Entergy Texas each in August 2016), the Utility operating companies engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which was a rate schedule approved by the FERC. Under the terms of the System Agreement, generating capacity and other power resources were jointly operated by the Utility operating companies that were participating in the System Agreement. The System Agreement provided, among other things, that parties having generating reserves greater than their allocated share of reserves (long companies) would receive payments from those parties having generating reserves that were less than their allocated share of reserves (short companies). Such payments were at amounts sufficient to cover certain of the long companies’ costs for intermediate and peaking oil/gas-fired generation, including operating expenses, fixed charges on debt, dividend requirements on preferred equity, and a fair rate of return on common equity investment. Under the System Agreement, the rates used to compensate long companies were based on costs associated with the long companies’ steam electric generating units fueled by oil or gas and having an annual average heat rate above 10,000 Btu/kWh. In addition, for all energy exchanged among the Utility operating companies under the System Agreement, the companies purchasing exchange energy were required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs. Entergy Arkansas terminated its participation in the System Agreement in December 2013. Entergy Mississippi terminated its participation in the System Agreement in November 2015. The System Agreement terminated with respect to its remaining participants in August 2016.

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challenges to the allocation of costs as defined by the System Agreement and other matters. See Note 2 to the financial statements for discussion of legal proceedings at the FERC and in federal courts involving the System Agreement.

Transmission and MISO Markets

On December 19, 2013, the Utility operating companies integrated into the MISO RTO. Although becoming a member of MISO does not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities, MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. MISO also exercises functional control of transmission planning and congestion management and provides schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the markets. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their generating facilities into the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. Each Utility operating company has its own transmission pricing zone and a formula rate template (included as Attachment O to the MISO tariff) used to establish transmission rates within MISO. The terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets and the allocation of transmission upgrade costs, are subject to regulation by FERC.

System Energy and Related Agreements

System Energy recovers costs related to its interest in Grand Gulf through rates charged to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans for capacity and energy under the Unit Power Sales Agreement (described below). In December 1995, System Energy commenced a rate proceeding at the FERC. In July 2001 the rate proceeding became final, with the FERC approving a prospective 10.94% return on equity. In 1998 the FERC approved requests by Entergy Arkansas and Entergy Mississippi to accelerate a portion of their Grand Gulf purchased power obligations. Entergy Arkansas’s and Entergy Mississippi’s acceleration of Grand Gulf purchased power obligations ceased effective July 2001 and July 2003, respectively, as approved by the FERC. See Note 2 to the financial statements for discussion of a complaint filed with the FERC in January 2017 regarding System Energy’s return on equity.

Unit Power Sales Agreement

The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy’s ownership and leasehold interests in Grand Gulf to Entergy Arkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy delivered. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenue. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf and the receipt of such payments. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers.

In the case of Entergy Arkansas and Entergy Louisiana, payments are also recovered through sales of electricity from their respective retained shares of Grand Gulf. Under a settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains 22% of its 36% share of Grand Gulf-related costs and recovers the remaining 78% of its share in rates. In the event that Entergy Arkansas is not able to sell its retained share to third parties, it may sell such energy to its retail customers at a price equal to its avoided cost, which is currently less than Entergy Arkansas’s cost from its retained share. Entergy Arkansas has life-of-resources purchased power agreements with Entergy Louisiana and Entergy New Orleans that sell a portion of the output of Entergy Arkansas’s retained share of Grand Gulf to those companies, with the remainder of the retained share being sold to Entergy Mississippi through a separate life-of-resources purchased power agreement. In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, Entergy Louisiana was granted rate relief with respect to costs associated with Entergy

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Louisiana’s share of capacity and energy from Grand Gulf, subject to certain terms and conditions. Entergy Louisiana retains and does not recover from retail ratepayers 18% of its 14% share of the costs of Grand Gulf capacity and energy and recovers the remaining 82% of its share in rates. Entergy Louisiana is allowed to recover through the fuel adjustment clause at 4.6 cents per kWh for the energy related to its retained portion of these costs. Alternatively, Entergy Louisiana may sell such energy to non-affiliated parties at prices above the fuel adjustment clause recovery amount, subject to the LPSC’s approval. Entergy Arkansas also has a life-of-resources purchased power agreement with Entergy Mississippi to sell a portion of the output of Entergy Arkansas’s non-retained share of Grand Gulf. Entergy Mississippi was granted rate relief for those purchases by the MPSC through its annual unit power cost rate mechanism.

Availability Agreement

The Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was entered into in 1974 in connection with the financing by System Energy of Grand Gulf. The Availability Agreement provides that System Energy make available to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy’s share of Grand Gulf.

Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also agreed severally to pay System Energy monthly for the right to receive capacity and energy from Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement) would at least equal System Energy’s total operating expenses for Grand Gulf (including depreciation at a specified rate and expenses incurred in a permanent shutdown of Grand Gulf) and interest charges.

The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would govern payments made under such agreement in the event of a shortfall of funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement.

System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for its one outstanding series of first mortgage bonds. In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making payments under the Availability Agreement (for example, if the FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allowed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances.

Each of the assignment agreements relating to the Availability Agreement provides that Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans will make payments directly to System Energy. However, if there is an event of default, those payments must be made directly to the holders of indebtedness that are the beneficiaries of such assignment agreements. The payments must be made pro rata according to the amount of the respective obligations secured.

The obligations of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans to make payments under the Availability Agreement are subject to the receipt and continued effectiveness of all necessary regulatory approvals. Sales of capacity and energy under the Availability Agreement would require that the Availability Agreement be submitted to the FERC for approval with respect to the terms of such sale. No such filing with the FERC has been made because sales of capacity and energy from Grand Gulf are being made pursuant to the Unit Power Sales Agreement. If, for any reason, sales of capacity and energy are made in the future pursuant to the Availability Agreement, the jurisdictional portions of the Availability Agreement would be submitted to the FERC for approval.

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Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement to System Energy have exceeded the amounts payable under the Availability Agreement and, therefore, no payments under the Availability Agreement have ever been required. If Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments because their Availability Agreement obligations exceed their Unit Power Sales Agreement obligations.

The Availability Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, without further consent of any assignees or other creditors.

Capital Funds Agreement

System Energy and Entergy Corporation have entered into the Capital Funds Agreement, whereby Entergy Corporation has agreed to supply System Energy with sufficient capital to (i) maintain System Energy’s equity capital at an amount equal to a minimum of 35% of its total capitalization (excluding short-term debt) and (ii) permit the continued commercial operation of Grand Gulf and pay in full all indebtedness for borrowed money of System Energy when due.

Entergy Corporation has entered into various supplements to the Capital Funds Agreement. System Energy has assigned its rights under such a supplement as security for its one outstanding series of first mortgage bonds. The supplement provides that permitted indebtedness for borrowed money incurred by System Energy in connection with the financing of Grand Gulf may be secured by System Energy’s rights under the Capital Funds Agreement on a pro rata basis (except for the Specific Payments, as defined below). In addition, in the supplements to the Capital Funds Agreement relating to the specific indebtedness being secured, Entergy Corporation has agreed to make cash capital contributions directly to System Energy sufficient to enable System Energy to make payments when due on such indebtedness (Specific Payments). However, if there is an event of default, Entergy Corporation must make those payments directly to the holders of indebtedness benefiting from the supplemental agreements. The payments (other than the Specific Payments) must be made pro rata according to the amount of the respective obligations benefiting from the supplemental agreements.

The Capital Funds Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, upon obtaining the consent, if required, of those holders of System Energy’s indebtedness then outstanding who have received the assignments of the Capital Funds Agreement. No such consent would be required to terminate the Capital Funds Agreement or the supplement thereto at this time.

Service Companies

Entergy Services, a corporation wholly-owned by Entergy Corporation, provides management, administrative, accounting, legal, engineering, and other services primarily to the Utility operating companies, but also provides services to Entergy Wholesale Commodities. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf, subject to the owner oversight of Entergy Arkansas, Entergy Louisiana, and System Energy, respectively. Entergy Services and Entergy Operations provide their services to the Utility operating companies and System Energy on an “at cost” basis, pursuant to cost allocation methodologies for these service agreements that were approved by the FERC.

Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas

Effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation into two vertically integrated utility companies, one operating under the sole retail jurisdiction of the PUCT, Entergy Texas, and the other

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operating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Entergy Texas owns all Entergy Gulf States, Inc. distribution and transmission assets located in Texas, the gas-fired generating plants located in Texas, undivided 42.5% ownership shares of Entergy Gulf States, Inc.’s 70% ownership interest in Nelson 6 and 42% ownership interest in Big Cajun 2, Unit 3, which are coal-fired generating plants located in Louisiana, and other assets and contract rights to the extent related to utility operations in Texas. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, owns all of the remaining assets that were owned by Entergy Gulf States, Inc. On a book value basis, approximately 58.1% of the Entergy Gulf States, Inc. assets were allocated to Entergy Gulf States Louisiana and approximately 41.9% were allocated to Entergy Texas.

Entergy Texas purchases from Entergy Louisiana pursuant to a life-of-unit purchased power agreement a 42.5% share of capacity and energy from the 70% of River Bend subject to retail regulation. Entergy Texas was allocated a share of River Bend’s nuclear and environmental liabilities that is identical to the share of the plant’s output purchased by Entergy Texas under the purchased power agreement. In connection with the termination of the System Agreement effective August 31, 2016, the purchased power agreements that were put in place for certain legacy units at the time of the jurisdictional separation were also terminated at that time. See Note 2 to the financial statements for additional discussion of the purchased power agreements.

Entergy Louisiana and Entergy Gulf States Louisiana Business Combination

On October 1, 2015, the businesses formerly conducted by Entergy Louisiana (Old Entergy Louisiana) and Entergy Gulf States Louisiana (Old Entergy Gulf States Louisiana) were combined into a single public utility. In order to effect the business combination, under the Texas Business Organizations Code (TXBOC), Old Entergy Louisiana allocated substantially all of its assets to a new subsidiary, Entergy Louisiana Power, LLC, a Texas limited liability company (New Entergy Louisiana), and New Entergy Louisiana assumed the liabilities of Old Entergy Louisiana, in a transaction regarded as a merger under the TXBOC. Under the TXBOC, Old Entergy Gulf States Louisiana allocated substantially all of its assets to a new subsidiary (New Entergy Gulf States Louisiana) and New Entergy Gulf States Louisiana assumed the liabilities of Old Entergy Gulf States Louisiana, in a transaction regarded as a merger under the TXBOC. New Entergy Gulf States Louisiana then merged into New Entergy Louisiana with New Entergy Louisiana surviving the merger. Thereupon, Old Entergy Louisiana changed its name from “Entergy Louisiana, LLC” to “EL Investment Company, LLC” and New Entergy Louisiana changed its name from “Entergy Louisiana Power, LLC” to “Entergy Louisiana, LLC” (Entergy Louisiana). With the completion of the business combination, Entergy Louisiana holds substantially all of the assets, and has assumed the liabilities, of Old Entergy Louisiana and Old Entergy Gulf States Louisiana. See Note 2 to the financial statements for additional discussion of the business combination.

Earnings Ratios of Registrant Subsidiaries

The Registrant Subsidiaries’ ratios of earnings to fixed charges and ratios of earnings to combined fixed charges and preferred dividends or distributions pursuant to Item 503 of SEC Regulation S-K are as follows:



	Ratios of Earnings to Fixed Charges Years Ended December 31,
	2016	2015	2014	2013	2012
Entergy Arkansas	3.32	2.04	3.08	3.62	3.79
Entergy Louisiana	3.57	3.36	3.44	3.30	2.61
Entergy Mississippi	3.96	3.59	3.23	3.19	2.79
Entergy New Orleans	4.61	4.90	3.55	1.85	2.91
Entergy Texas	2.92	2.22	2.39	1.94	1.76
System Energy	5.39	4.53	4.04	5.66	5.12

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	Ratios of Earnings to Combined Fixed Charges and Preferred Dividends or Distributions Years Ended December 31,
	2016	2015	2014	2013	2012
Entergy Arkansas	3.09	1.85	2.76	3.25	3.36
Entergy Louisiana	3.57	3.24	3.28	3.14	2.47
Entergy Mississippi	3.71	3.34	3.00	2.97	2.59
Entergy New Orleans	4.30	4.50	3.26	1.70	2.63

The Registrant Subsidiaries accrue interest expense related to unrecognized tax benefits in income tax expense and do not include it in fixed charges.

Entergy Wholesale Commodities

Entergy Wholesale Commodities includes the ownership, operation, and decommissioning of nuclear power plants, located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. Entergy Wholesale Commodities revenues are primarily derived from sales of energy and generation capacity from these plants. Entergy Wholesale Commodities also provides operations and management services, including decommissioning services, to nuclear power plants owned by other utilities in the United States. Entergy Wholesale Commodities also includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers.

On December 29, 2014, Entergy Wholesale Commodities’ Vermont Yankee plant was removed from the grid, after 42 years of operations. The decision to close and decommission Vermont Yankee was announced in August 2013, as a result of numerous issues including sustained low natural gas and wholesale energy prices, the high cost structure of the plant, and lack of a market structure that adequately compensates merchant nuclear plants for their environmental and fuel diversity benefits in the Northeast region. In November 2016, Entergy entered into an agreement to sell 100% of the membership interest in Entergy Nuclear Vermont Yankee, LLC to a subsidiary of NorthStar Group Services, Inc. (NorthStar). Entergy Nuclear Vermont Yankee is the owner of the Vermont Yankee plant. The sale of Entergy Nuclear Vermont Yankee to NorthStar will include the transfer of Entergy Nuclear Vermont Yankee’s nuclear decommissioning trust fund and the asset retirement obligation for spent fuel management and decommissioning of the plant. Entergy plans to transfer all spent nuclear fuel to dry cask storage by the end of 2018, subject to obtaining necessary regulatory approvals, in advance of the planned transaction close. Under the sale agreement and related agreements to be entered into at the closing, NorthStar will commit to initiate decommissioning and site restoration by 2021 and complete those activities, along with the partial restoration of the Vermont Yankee site, with the exception of the independent spent fuel storage installation and the switchyard, by 2030. The original completion date, as outlined in Entergy’s Post Shutdown Decommissioning Activities Report filed with the NRC, was 2075. The transaction is contingent upon certain closing conditions, including approval by the NRC; approval by the State of Vermont Public Service Board, including approval of site restoration standards that will be proposed as part of the transaction; the transfer of all spent nuclear fuel to dry fuel storage on the independent spent fuel storage installation; and that the market value of the fund assets held in the decommissioning trust fund for the Vermont Yankee Nuclear Power Station, less the hypothetical income tax on the aggregate unrealized net gain of such fund assets at closing, is equal to or exceeds $451.95 million, subject to adjustments.

In October 2015, Entergy determined that it would close the FitzPatrick plant earlier than expected. The original expectation was to shut down the FitzPatrick plant at the end of its fuel cycle in January 2017, but in August 2016, Entergy entered into an agreement to sell the FitzPatrick plant to Exelon, and the sale is expected to close in the first half of 2017. The transaction is contingent upon, among other things, the expiration of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, the receipt of necessary regulatory approvals from the FERC, the NRC, and the Public Service Commission of the State of New York (NYPSC), and the receipt of a private letter ruling from the IRS. NRC approval has not yet been received, but all other necessary regulatory approvals have been received. Because certain specified conditions were satisfied in November 2016,

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including the continued effectiveness of the Clean Energy Standards/Zero Emissions Credit program (CES/ZEC), the establishment of certain long-term agreements on acceptable terms with the Energy Research and Development Authority of the State of New York in connection with the CES/ZEC program, and NYPSC approval of the transaction on acceptable terms, Entergy refueled the FitzPatrick plant in January and February 2017.

In December 2015, Entergy Wholesale Commodities closed on the sale of its 583 MW Rhode Island State Energy Center (RISEC), in Johnston, Rhode Island. The base sales price, excluding adjustments, was approximately $490 million. Entergy Wholesale Commodities purchased RISEC for $346 million in December 2011.

In December 2016, Entergy announced that it reached an agreement with Consumers Energy to terminate the PPA for the Palisades plant on May 31, 2018. Pursuant to the PPA termination agreement, Consumers Energy will pay Entergy $172 million for the early termination of the PPA. The PPA termination agreement is subject to regulatory approvals. Separately, and assuming regulatory approvals are obtained for the PPA termination agreement, Entergy intends to shut down the Palisades nuclear power plant permanently on October 1, 2018, after refueling in the spring of 2017 and operating through the end of that fuel cycle. Entergy expects to enter into a new PPA with Consumers Energy under which the plant would continue to operate through October 1, 2018.

In January 2017, Entergy announced that it reached a settlement with New York State to shut down Indian Point 2 by April 30, 2020 and Indian Point 3 by April 30, 2021, and resolve all New York State-initiated legal challenges to Indian Point’s operating license renewal. As part of the settlement, New York State has agreed to issue Indian Point’s water quality certification and Coastal Zone Management Act consistency certification and to withdraw its objection to license renewal before the NRC. New York State also has agreed to issue a water discharge permit, which is required regardless of whether the plant is seeking a renewed NRC license. The shutdowns are conditioned, among other things, upon such actions being taken by New York State. Even without opposition, the NRC license renewal process is expected to continue at least into 2018.

With the settlement concerning Indian Point, Entergy now has announced plans for the disposition of all of the Entergy Wholesale Commodities nuclear power plants, including the sales of Vermont Yankee and FitzPatrick, and the earlier than previously expected shutdowns of Pilgrim, Palisades, Indian Point 2, and Indian Point 3. See “Entergy Wholesale Commodities Exit from the Merchant Power Business” for further discussion.

Property

Nuclear Generating Stations

Entergy Wholesale Commodities includes the ownership of the following nuclear power plants:

Power Plant

Market

In Service Year

Acquired

Location

Capacity - Reactor Type

License Expiration Date

Pilgrim (a)

IS0-NE

1972

July 1999

Plymouth, MA

688 MW - Boiling Water

2032 (a)

FitzPatrick (b)

NYISO

1975

Nov. 2000

Oswego, NY

838 MW - Boiling Water

2034 (b)

Indian Point 3 (c)

NYISO

1976

Nov. 2000

Buchanan, NY

1,041 MW - Pressurized Water

2015 (c)

Indian Point 2 (c)

NYISO

1974

Sept. 2001

Buchanan, NY

1,028 MW - Pressurized Water

2013 (c)

Vermont Yankee (d)

IS0-NE

1972

July 2002

Vernon, VT

605 MW - Boiling Water

2032 (d)

Palisades (e)

MISO

1971

Apr. 2007

Covert, MI

811 MW - Pressurized Water

2031 (e)

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(a)	In October 2015, Entergy determined that it would close the Pilgrim plant no later than June 1, 2019, as discussed above.


(b)	In October 2015, Entergy determined that it would close the FitzPatrick plant at the end of the fuel cycle, in January 2017, but in August 2016, Entergy entered into an agreement to sell the FitzPatrick plant to Exelon, and the sale is expected to close in the first half of 2017.

(c)


(d)	On December 29, 2014, the Vermont Yankee plant ceased power production. In November 2016, Entergy entered into an agreement to sell 100% of the membership interest in Entergy Nuclear Vermont Yankee, to NorthStar. Entergy Nuclear Vermont Yankee is the owner of the Vermont Yankee plant.

(e)

In December 2016, Entergy announced that it reached an agreement with Consumers Energy to terminate the PPA for the Palisades plant in 2018. Separately, and assuming regulatory approvals are obtained for the PPA termination agreement, Entergy intends to shut down the Palisades nuclear power plant permanently on October 1, 2018, after refueling in the spring of 2017 and operating through the end of that fuel cycle.

In April 2007, Entergy submitted to the NRC a joint application to renew the operating licenses for Indian Point 2 and Indian Point 3 for an additional 20 years. The original expiration dates of the NRC operating licenses for Indian Point 2 and Indian Point 3 were September 28, 2013 and December 12, 2015, respectively. Authorization to operate Indian Point 2 and Indian Point 3 rests on Entergy’s having timely filed a license renewal application that remains pending before the NRC. Indian Point 2 and Indian Point 3 have now entered their “period of extended operation” after expiration of the plants’ initial license term under “timely renewal,” which is a federal statutory rule of general applicability providing for extension of a license for which a renewal application has been timely filed with the licensing agency until the license renewal process has been completed. The license renewal application for Indian Point 2 and Indian Point 3 qualifies for timely renewal protection because it met NRC regulatory standards for timely filing. For additional discussion of the license renewal applications and the settlement with New York State, see “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Plants” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

Non-nuclear Generating Stations

In November 2016, Entergy sold its 50% membership interest in Top Deer Wind Ventures, LLC, a wind-powered electric generation joint venture owned in the Entergy Wholesale Commodities segment and accounted for as an equity method investment. Entergy sold its 50% membership interest in Top Deer for $0.5 million and realized a pre-tax loss of $0.2 million.

Entergy Wholesale Commodities includes the ownership, or interests in joint ventures that own, the following non-nuclear power plants:



Plant	Location	Ownership	Net Owned Capacity (a)	Type
Independence Unit 2; 842 MW	Newark, AR	14%	121 MW(b)	Coal
RS Cogen; 425 MW (c)	Lake Charles, LA	50%	213 MW	Gas/Steam
Nelson 6; 550 MW	Westlake, LA	11%	60 MW(b)	Coal


(a)	“Net Owned Capacity” refers to the nameplate rating on the generating unit.

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(b)	The owned MW capacity is the portion of the plant capacity owned by Entergy Wholesale Commodities. For a complete listing of Entergy’s jointly-owned generating stations, refer to “Jointly-Owned Generating Stations” in Note 1 to the financial statements.


(c)	Indirectly owned through interests in unconsolidated joint ventures.

Independent System Operators

The Pilgrim plant falls under the authority of the Independent System Operator (ISO) New England and the FitzPatrick and Indian Point plants fall under the authority of the New York Independent System Operator (NYISO). The Palisades plant falls under the authority of the MISO. The primary purpose of ISO New England, NYISO, and MISO is to direct the operations of the major generation and transmission facilities in their respective regions; ensure grid reliability; administer and monitor wholesale electricity markets; and plan for their respective region’s energy needs.

Energy and Capacity Sales

As part of the purchase of the Palisades plant in 2007, Entergy executed a 15-year PPA with the seller, Consumers Energy, for 100% of the plant’s output, excluding any future uprates. Under the purchased power agreement, Consumers Energy receives the value of any new environmental credits for the first ten years of the agreement. Palisades and Consumers Energy will share on a 50/50 basis the value of any new environmental credits for years 11 through 15 of the agreement. The environmental credits are defined as benefits from a change in law that causes capability of the plant as of the purchase date to become a tradable attribute (e.g., emission credit, renewable energy credit, environmental credit, “green” credit, etc.) or otherwise to have a market value. In December 2016, Entergy announced that it reached an agreement with Consumers Energy to terminate the PPA for the Palisades plant in 2018. See discussion above for additional details regarding the agreement.

Customers

Entergy Wholesale Commodities’ customers for the sale of both energy and capacity from its nuclear plants include retail power providers, utilities, electric power co-operatives, power trading organizations, and other power generation companies. These customers include Consolidated Edison and Consumers Energy, companies from which Entergy purchased plants, and ISO New England, NYISO, and MISO. Substantially all of the credit exposure associated with the planned energy output under contract for Entergy Wholesale Commodities nuclear plants is with counterparties or their guarantors that have public investment grade credit ratings.

Competition

The ISO New England and NYISO markets are highly competitive. Entergy Wholesale Commodities has numerous competitors in New England and New York, including generation companies affiliated with regulated utilities, other independent power producers, municipal and co-operative generators, owners of co-generation plants and wholesale power marketers. Entergy Wholesale Commodities is an independent power producer, which means it

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generates power for sale to third parties at day ahead or spot market prices to the extent that the power is not sold under a fixed price contract. Municipal and co-operative generators also generate power but use most of it to deliver power to their municipal or co-operative power customers. Owners of co-generation plants produce power primarily for their own consumption. Wholesale power marketers do not own generation; rather they buy power from generators or other market participants and resell it to retail providers or other market participants. Competition in the New England and New York power markets is affected by, among other factors, the amount of generation and transmission capacity in these markets. MISO does not have a centralized clearing capacity market, but load serving entities do meet the majority of their capacity needs through bilateral contracts and self-supply with a smaller portion coming through voluntary MISO auctions. The majority of Palisades’ current output is contracted to Consumers Energy through 2022, but in December 2016, Entergy announced that it reached an agreement with Consumers Energy to terminate the PPA for the Palisades plant on May 31, 2018. Entergy expects to enter into a new PPA with Consumers Energy under which the plant would continue to operate through the planned shutdown date of October 1, 2018. See discussion above for additional details regarding the PPA termination agreement. Entergy Wholesale Commodities does not expect to be materially affected by competition in the MISO market in the near term.

Seasonality

Entergy Wholesale Commodities’ revenues and operating income are subject to fluctuations during the year due to seasonal factors, weather conditions, and contract pricing. Refueling outages are generally scheduled for the spring and the fall, and cause volumetric decreases during those seasons. When outdoor and cooling water temperatures are lower, generally during colder months, Entergy Wholesale Commodities nuclear power plants operate more efficiently, and consequently, generate more electricity. Many of Entergy Wholesale Commodities’ contracts provide for shaped pricing over the course of the year. As a result of these factors, Entergy Wholesale Commodities’ revenues are typically higher in the first and third quarters than in the second and fourth quarters.

Fuel Supply

Nuclear Fuel

See “Fuel Supply - Nuclear Fuel” in the Utility portion of Part I, Item 1 for a discussion of the nuclear fuel cycle and markets. Entergy Nuclear Fuels Company, a wholly-owned subsidiary, is responsible for contracts to acquire nuclear materials, except for fuel fabrication, for Entergy Wholesale Commodities nuclear power plants, while Entergy Nuclear Operations, Inc. acts as the agent for the purchase of nuclear fuel assembly fabrication services. All contracts for the disposal of spent nuclear fuel are between the DOE and each of the nuclear power plant owners.

Other Business Activities

Entergy Nuclear Power Marketing, LLC (ENPM) was formed in 2005 to centralize the power marketing function for Entergy Wholesale Commodities nuclear plants. Upon its formation, ENPM entered into long-term power purchase agreements with the Entergy Wholesale Commodities subsidiaries that own nuclear power plants (generating subsidiaries). As part of a series of agreements, ENPM agreed to assume and/or otherwise service the existing power purchase agreements that were in effect between the generating subsidiaries and their customers. ENPM’s functions include origination of new energy and capacity transactions and generation scheduling.

Entergy Nuclear, Inc. can pursue service agreements with other nuclear power plant owners who seek the advantages of Entergy’s scale and expertise but do not necessarily want to sell their assets. Services provided by either Entergy Nuclear, Inc. or other Entergy Wholesale Commodities subsidiaries include engineering, operations and maintenance, fuel procurement, management and supervision, technical support and training, administrative support, and other managerial or technical services required to operate, maintain, and decommission nuclear electric power facilities. Entergy Nuclear, Inc. provided decommissioning services for the Maine Yankee nuclear power plant.

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TLG Services, a subsidiary of Entergy Nuclear, Inc., offers decommissioning, engineering, and related services to nuclear power plant owners.

In September 2003, Entergy agreed to provide plant operation support services for the 800 MW Cooper Nuclear Station located near Brownville, Nebraska. The original contract was to expire in 2014 corresponding to the original operating license life of the plant. In 2006 an Entergy subsidiary signed an agreement to provide license renewal services for the Cooper Nuclear Station. The Cooper Nuclear Station received its license renewal from the NRC in November 2010. Entergy continues to provide implementation services for the renewed license. In 2010 an Entergy subsidiary signed an agreement to extend the management support services to Cooper Nuclear Station by 15 years, through January 2029.

Regulation of Entergy’s Business

Federal Power Act

The Federal Power Act provides the FERC the authority to regulate:


•	the transmission and wholesale sale of electric energy in interstate commerce;


•	sale or acquisition of certain assets;


•	securities issuances;


•	the licensing of certain hydroelectric projects;


•	certain other activities, including accounting policies and practices of electric and gas utilities; and


•	changes in control of FERC jurisdictional entities or rate schedules.

The Federal Power Act gives the FERC jurisdiction over the rates charged by System Energy for Grand Gulf capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and over some of the rates charged by Entergy Arkansas and Entergy Louisiana. The FERC also regulates the provisions of the System Agreement, including the rates, and the provision of transmission service to wholesale market participants. The FERC also regulates the MISO RTO, an independent entity that maintains functional control over the combined transmission systems of its members and administers wholesale energy, capacity, and ancillary services markets for market participants in the MISO region, including the Utility operating companies. FERC regulation of the MISO RTO includes regulation of the design and implementation of the wholesale markets administered by the MISO RTO, as well as the rates, terms, and conditions of open access transmission service over the member systems and the allocation of costs associated with transmission upgrades.

Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 70 MW of capacity.

State Regulation

Utility

Entergy Arkansas is subject to regulation by the APSC, which includes the authority to:


•	oversee utility service;


•	set retail rates;


•	determine reasonable and adequate service;


•	control leasing;


•	control the acquisition or sale of any public utility plant or property constituting an operating unit or system;


•	set rates of depreciation;


•	issue certificates of convenience and necessity and certificates of environmental compatibility and public need; and

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•	regulate the issuance and sale of certain securities.

Additionally, Entergy Arkansas serves a limited number of retail customers in Tennessee and as a result, may be required to submit certain matters approved by the APSC for consideration by the Tennessee Regulatory Authority. Additionally, Entergy Arkansas maintains limited facilities in Missouri but does not provide retail electric service to customers in Missouri. Although Entergy Arkansas obtained a certificate with respect to its Missouri facilities, Entergy Arkansas is not subject to the retail rate or regulatory scheme in Missouri.

Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to:


•	utility service;


•	retail rates and charges;


•	certification of generating facilities;


•	certification of power or capacity purchase contracts;


•	audit of the fuel adjustment charge, environmental adjustment charge, and avoided cost payment to Qualifying Facilities;


•	integrated resource planning;


•	utility mergers and acquisitions and other changes of control; and


•	depreciation and other matters.

Prior to the transfer of the Algiers assets to Entergy New Orleans on September 1, 2015, Entergy Louisiana was also subject to the jurisdiction of the City Council with respect to such matters within Algiers in Orleans Parish, although the precise scope of that jurisdiction differed from that of the LPSC.

Entergy Mississippi is subject to regulation by the MPSC as to the following:


•	utility service;


•	service areas;


•	facilities;


•	certification of generating facilities and certain transmission projects;


•	retail rates;


•	fuel cost recovery;


•	depreciation rates; and


•	mergers and changes of control.

Entergy Mississippi is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station, which is located in Arkansas.

Entergy New Orleans is subject to regulation by the City Council as to the following:


•	utility service;


•	retail rates and charges;


•	standards of service;


•	depreciation;


•	issuance and sale of certain securities; and


•	other matters.

To the extent authorized by governing legislation, Entergy Texas is subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Texas is also subject to regulation by the PUCT as to:

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•	retail rates and service in unincorporated areas of its service territory, and in municipalities that have ceded jurisdiction to the PUCT;


•	customer service standards;


•	certification of certain transmission and generation projects; and


•	extensions of service into new areas.

Regulation of the Nuclear Power Industry

Atomic Energy Act of 1954 and Energy Reorganization Act of 1974

Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend and Waterford 3, and Grand Gulf, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC. Entergy subsidiaries in the Entergy Wholesale Commodities segment are subject to the NRC’s jurisdiction as the owners and operators of Pilgrim, Indian Point Energy Center, FitzPatrick, Vermont Yankee, and Palisades. Substantial capital expenditures, increased operating expenses, and/or higher decommissioning costs at Entergy’s nuclear plants because of revised safety requirements of the NRC could be required in the future.

Nuclear Waste Policy Act of 1982

Spent Nuclear Fuel

Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors. Entergy’s nuclear owner/licensee subsidiaries have been charged fees for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected Entergy companies entered into contracts with the DOE, whereby the DOE is to furnish disposal services at a cost of one mill per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date. Entergy Arkansas is the only one of the Utility operating companies that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 2016 of $181.9 million for the one-time fee. Entergy accepted assignment of the Pilgrim, FitzPatrick and Indian Point 3, Indian Point 1 and Indian Point 2, Vermont Yankee, Palisades, and Big Rock Point spent fuel disposal contracts with the DOE held by their previous owners. The previous owners have paid or retained liability for the fees for all generation prior to the purchase dates of those plants. The fees payable to the DOE may be adjusted in the future to assure full recovery. Entergy considers all costs incurred for the disposal of spent nuclear fuel, except accrued interest, to be proper components of nuclear fuel expense. Provisions to recover such costs have been or will be made in applications to regulatory authorities for the Utility plants. Entergy’s total spent fuel fees to date, including the one-time fee liability of Entergy Arkansas, have surpassed $1.6 billion (exclusive of amounts relating to Entergy plants that were paid or are owed by prior owners of those plants).

The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE is required by law to proceed with the licensing (the DOE filed the license application in June 2008) and, after the license is granted by the NRC, proceed with the repository construction and commencement of receipt of spent fuel. Because the DOE has not begun accepting spent fuel, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts. The DOE continues to delay meeting its obligation. Specific steps were taken to discontinue the Yucca Mountain project, including a motion to the NRC to withdraw the license application with prejudice and the establishment of a commission to develop recommendations for alternative spent fuel storage solutions. In August 2013 the U.S. Court of Appeals for the D.C. Circuit ordered the NRC to continue with the Yucca Mountain license review, but only to the extent of funds previously appropriated by Congress for that purpose and not yet used. This amount of money is not expected to be sufficient to complete the review. The government

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has taken no effective action to date related to the recommendations of the appointed spent fuel study commission. Accordingly, large uncertainty remains regarding the time frame under which the DOE will begin to accept spent fuel from Entergy’s facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at Entergy’s nuclear sites.

Following the defunding of the Yucca Mountain spent fuel repository program, the National Association of Regulatory Utility Commissioners and others sued the government seeking cessation of collection of the one mill per net kWh generated and sold after April 7, 1983 fee. In November 2013 the D.C. Circuit Court of Appeals ordered the DOE to submit a proposal to Congress to reset the fee to zero until the DOE complies with the Nuclear Waste Policy Act or Congress enacts an alternative waste disposal plan. In January 2014 the DOE submitted the proposal to Congress under protest, and also filed a petition for rehearing with the D.C. Circuit. The petition for rehearing was denied. The zero spent fuel fee went into effect prospectively in May 2014. Management cannot predict the potential timing or magnitude of future spent fuel fee revisions that may occur.

As a result of the DOE’s failure to begin disposal of spent nuclear fuel in 1998 pursuant to the Nuclear Waste Policy Act of 1982 and the spent fuel disposal contracts, Entergy’s nuclear owner/licensee subsidiaries have incurred and will continue to incur damages. These subsidiaries have been, and continue to be, involved in litigation to recover the damages caused by the DOE’s delay in performance. Through 2016, Entergy’s subsidiaries won and collected on judgments totaling over $500 million.

In April 2015 the U.S. Court of Federal Claims issued a judgment in the amount of $29 million in favor of Entergy Arkansas and against the DOE in the second round ANO damages case. Also in April 2015 the U.S. Court of Federal Claims issued a judgment in the amount of $44 million in favor of System Energy and against the DOE in the second round Grand Gulf damages case. In June 2015, Entergy Arkansas and System Energy appealed to the U.S. Court of Appeals for the Federal Circuit portions of those decisions relating to cask loading costs. In April 2016 the Federal Circuit issued a decision in both appeals in favor of Entergy Arkansas and System Energy, and remanded the cases back to the U.S. Court of Federal Claims. In June 2016 the U.S. Court of Federal Claims issued a final judgment in the amount of $49 million in favor of System Energy and against the DOE in the second round Grand Gulf damages case, and Entergy received the payment from the U.S. Treasury in August 2016. In July 2016 the U.S. Court of Federal Claims issued a final judgment in the amount of $31 million in favor of Entergy Arkansas and against the DOE in the second round ANO damages case, and Entergy received payment from the U.S. Treasury in October 2016.

In May 2015, the U.S. Court of Federal Claims issued a final partial summary judgment on a portion, $21 million, of the claims in the Palisades case. The DOE did not appeal that decision, and Entergy received the payment from the U.S. Treasury in October 2015.

In January 2016 the U.S. Court of Federal Claims issued a judgment in the amount of $49 million in favor of Entergy Louisiana and against the DOE in the first round Waterford 3 damages case. In April 2016, Entergy Louisiana appealed to the U.S. Court of Appeals for the Federal Circuit the portion of that decision relating to cask loading costs. After the ANO and Grand Gulf appeal was rendered, the U.S. Court of Appeals for the Federal Circuit remanded the Waterford 3 case back to the U.S. Court of Federal Claims for decision in accordance with the U.S. Court of Appeals ruling on cask loading costs. In August 2016 the U.S. Court of Federal Claims issued a final judgment in the Waterford 3 case in the amount of $53 million, and Entergy Louisiana received payment from the U.S. Treasury in November 2016.

In April 2016 the U.S. Court of Federal Claims issued a partial judgment in the amount of $42 million in favor of Entergy Louisiana and against the DOE in the first round River Bend damages case, reserving the issue of cask loading costs pending resolution of the appeal on the same issues in the Entergy Arkansas and System Energy cases.

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Entergy Louisiana received payment from the U.S. Treasury in August 2016. In September 2016 the U.S. Court of Federal Claims issued a further judgment in the River Bend case in the amount of $5 million. Entergy Louisiana received payment from the U.S. Treasury in January 2017.

In May 2016, Entergy Nuclear Vermont Yankee and the DOE entered into a stipulated agreement and the U.S. Court of Federal Claims issued a judgment in the amount of $19 million in favor of Entergy Nuclear Vermont Yankee and against the DOE in the second round Vermont Yankee damages case. Entergy received payment from the U.S. Treasury in June 2016.

In September 2016 the U.S. Court of Federal Claims issued a judgment in the Entergy Nuclear Palisades case in the amount of $14 million. Entergy Nuclear Palisades received payment from the U.S. Treasury in January 2017.

In October 2016 the U.S. Supreme Court of Federal Claims issued a judgment in the second round Entergy

Nuclear Indian Point 2 case in the amount of $34 million. Entergy Nuclear Indian Point 2 received payment from the U.S. Treasury in January 2017.

Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are providing their own spent fuel storage. Storage capability additions using dry casks began operations at Palisades in 1993, at ANO in 1996, at FitzPatrick in 2002, at River Bend in 2005, at Grand Gulf in 2006, at Indian Point and Vermont Yankee in 2008, at Waterford 3 in 2011, and at Pilgrim in 2015. These facilities will be expanded as needed.

Nuclear Plant Decommissioning

Entergy Arkansas, Entergy Louisiana, and System Energy are entitled to recover from customers through electric rates the estimated decommissioning costs for ANO, Waterford 3, and Grand Gulf, respectively. In addition, Entergy Louisiana and Entergy Texas are entitled to recover from customers through electric rates the estimated decommissioning costs for the portion of River Bend subject to retail rate regulation. The collections are deposited in trust funds that can only be used for future decommissioning costs. Entergy periodically reviews and updates the estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.

In July 2010 the LPSC approved increased decommissioning collections for Waterford 3 and the Louisiana regulated share of River Bend and in December 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. In December 2015 the APSC approved increased decommissioning collections for ANO 2 to address an identified shortfall. In December 2016 the APSC ordered continued collections for decommissioning for ANO 2, while finding that ANO 1’s decommissioning was adequately funded without continued collections. Entergy currently believes its decommissioning funding will be sufficient for its nuclear plants subject to retail rate regulation, although decommissioning cost inflation and trust fund performance will ultimately determine the adequacy of the funding amounts.

In November 2016, Entergy entered into an agreement to sell 100% of the membership interest in Entergy Nuclear Vermont Yankee to a subsidiary of NorthStar. Upon closing of the sale, NorthStar will assume ownership of Vermont Yankee and its decommissioning and site restoration trusts, together with complete responsibility for the facility’s decommissioning and site restoration. The sale is subject to certain closing conditions, including approval from the NRC and the State of Vermont Public Service Board. See Note 9 to the financial statements for further discussion of Vermont Yankee decommissioning costs and see “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion of the NorthStar transaction.

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For the Indian Point 3 and FitzPatrick plants purchased in 2000 from NYPA, NYPA retained the decommissioning trust funds and the decommissioning liabilities with the right to require the Entergy subsidiaries to assume each of the decommissioning liabilities provided that it assigns the corresponding decommissioning trust, up to a specified level, to the Entergy subsidiaries. In August 2016, Entergy entered into a trust transfer agreement with NYPA to transfer the decommissioning trust funds and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants to Entergy. The transaction was contingent upon receiving approval from the NRC, which was received in January 2017. The decommissioning trust funds for the Indian Point 3 and FitzPatrick plants were transferred to Entergy by NYPA in January 2017. In August 2016, Entergy also entered into an agreement to sell the FitzPatrick plant to Exelon. Upon the closing of that sale, the FitzPatrick decommissioning trust along with the decommissioning obligation for that plant will be transfered to Exelon. See “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion of the Exelon transaction.

In March 2016 filings with the NRC were made for certain Entergy subsidiaries’ nuclear plants reporting on decommissioning funding. Those reports showed that decommissioning funding for each of those nuclear plants met the NRC’s financial assurance requirements.

Additional information with respect to Entergy’s decommissioning costs and decommissioning trust funds is found in Note 9 and Note 16 to the financial statements.

Price-Anderson Act

The Price-Anderson Act requires that reactor licensees purchase and maintain the maximum amount of nuclear liability insurance available and participate in an industry assessment program called Secondary Financial Protection in order to protect the public in the event of a nuclear power plant accident. The costs of this insurance are borne by the nuclear power industry. Congress amended and renewed the Price-Anderson Act in 2005 for a term through 2025. The Price-Anderson Act limits the contingent liability for a single nuclear incident to a maximum assessment of approximately $127.3 million per reactor (with 102 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, Entergy Louisiana, System Energy, or an Entergy Wholesale Commodities company is liable, protection is afforded through a combination of private insurance and the Secondary Financial Protection program. In addition to this, insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units is also purchased. The Price-Anderson Act and insurance applicable to the nuclear programs of Entergy are discussed in more detail in Note 8 to the financial statements.

NRC Reactor Oversight Process

The NRC’s Reactor Oversight Process is a program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response. The NRC evaluates plant performance by analyzing two distinct inputs: inspection findings resulting from the NRC’s inspection program and performance indicators reported by the licensee. The evaluations result in the placement of each plant in one of the NRC’s Reactor Oversight Process Action Matrix columns: “licensee response column,” or Column 1, “regulatory response column,” or Column 2, “degraded cornerstone column,” or Column 3, and “multiple/repetitive degraded cornerstone column,” or Column 4. Plants in Column 1 are subject to normal NRC inspection activities. Plants in Column 2, Column 3, or Column 4 are subject to progressively increasing levels of inspection by the NRC with, in general, progressively increasing levels of associated costs. Waterford 3, River Bend, FitzPatrick, Indian Point 2, Indian Point 3, and Palisades are in Column 1. Grand Gulf is in Column 2. ANO 1 and 2 are in Column 4, and are subject to an extensive set of required NRC inspections. Pilgrim is also in Column 4 and is subject to an extensive, but limited, set of required NRC inspections. See Note 8 to the financial statements for further discussion of the placement of ANO 1 and 2, and Pilgrim in Column 4 of the NRC’s matrix.

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Environmental Regulation

Entergy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy’s businesses are in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance requirements and costs cannot be precisely estimated. Except to the extent discussed below, at this time compliance with federal, state, and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of Entergy’s businesses and is not expected to have a material effect on their competitive position, results of operations, cash flows, or financial position.

Clean Air Act and Subsequent Amendments

The Clean Air Act and its amendments establish several programs that currently or in the future may affect Entergy’s fossil-fueled generation facilities and, to a lesser extent, certain operations at nuclear and other facilities. Individual states also operate similar independent state programs or delegated federal programs that may include requirements more stringent than federal regulatory requirements. These programs include:


•	New source review and preconstruction permits for new sources of criteria air pollutants, greenhouse gases, and significant modifications to existing facilities;


•	Acid rain program for control of sulfur dioxide (SO₂) and nitrogen oxides (NO_x);


•	Nonattainment area programs for control of criteria air pollutants, which could include fee assessments for air pollutant emission sources under Section 185 of the Clean Air Act if attainment is not reached in a timely manner;


•	Hazardous air pollutant emissions reduction programs;


•	Interstate Air Transport;


•	Operating permit program for administration and enforcement of these and other Clean Air Act programs;


•	Regional Haze and Best Available Retrofit Technology programs; and


•	New and existing source standards for greenhouse gas emissions.

New Source Review (NSR)

Preconstruction permits are required for new facilities and for existing facilities that undergo a modification that results in a significant net emissions increase and is not classified as routine repair, maintenance, or replacement. Units that undergo certain non-routine modifications must obtain a permit modification and may be required to install additional air pollution control technologies. Entergy has an established process for identifying modifications requiring additional permitting approval and has followed the regulations and associated guidance provided by the states and the federal government with regard to the determination of routine repair, maintenance, and replacement. In recent years, however, the EPA has begun an enforcement initiative, aimed primarily at coal plants, to identify modifications that it does not consider routine for which the unit did not obtain a modified permit. Various courts and the EPA have been inconsistent in their judgments regarding modifications that are considered routine and on other legal issues that affect this program.

In February 2011, Entergy received a request from the EPA for several categories of information concerning capital and maintenance projects at the White Bluff and Independence facilities, both located in Arkansas, in order to determine compliance with the Clean Air Act, including New Source Review requirements and air permits issued by the Arkansas Department of Environmental Quality. In August 2011, Entergy’s Nelson facility, located in Louisiana, received a similar request for information from the EPA. In September 2015 a subsequent request for similar information was received for the White Bluff facility. Entergy responded to all requests. None of these EPA requests for information alleged that the facilities were in violation of law.

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Ozone Nonattainment

Entergy Texas operates one fossil-fueled generating unit (Lewis Creek) in a geographic area that is not in attainment of the currently-enforced national ambient air quality standards (NAAQS) for ozone. The nonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. Areas in nonattainment are classified as “marginal,” “moderate,” “serious,” or “severe.” When an area fails to meet the ambient air standard, the EPA requires state regulatory authorities to prepare state implementation plans meant to cause progress toward bringing the area into attainment with applicable standards.

The Houston-Galveston-Brazoria area was originally classified as “moderate” nonattainment under the 1997 8-hour ozone standard with an attainment date of June 15, 2010. In June 2007 the Texas governor petitioned the EPA to reclassify Houston-Galveston-Brazoria from “moderate” to “severe” and the EPA granted the request in October 2008. In February 2015 the Texas Commission on Environmental Quality (TCEQ) submitted a request to EPA for a finding, and in December 2015, the EPA issued the finding that the Houston-Galveston-Brazoria area is in attainment with the 1997 8-hour ozone standard. In April 2015 the EPA revoked the 1997 ozone NAAQS and in May 2016, the EPA issued a proposed rule approving a substitute for the Houston-Galveston-Brazoria area. This redesignation indicates that the area has attained the revoked 1997 8-hour ozone NAAQS due to permanent and enforceable emission reductions and that it will maintain that NAAQS for 10 years from the date of the approval. Final approval will result in the area no longer being subject to any remaining anti-backsliding or non-attainment new source review requirements associated with the revoked 1997 NAAQS.

In March 2008 the EPA revised the NAAQS for ozone, creating the potential for additional counties and parishes in which Entergy operates to be placed in nonattainment status. In April 2012 the EPA released its final non-attainment designations for the 2008 ozone NAAQS. In Entergy’s utility service area, the Houston-Galveston-Brazoria, Texas; Baton Rouge, Louisiana; and Memphis, Tennessee/Mississippi/Arkansas areas were designated as in “marginal” nonattainment. In August 2015 and January 2016, the EPA proposed determinations that the Baton Rouge and Memphis areas had attained the 2008 standard. In May 2016 the EPA finalized those determinations and extended the Houston-Galveston-Brazoria area’s attainment date for the 2008 Ozone standard to July 20, 2016. In December 2016 the EPA determined that the Houston-Galveston-Brazoria area had failed to attain the 2008 ozone standard by the 2016 attainment date. This finding reclassifies the HGB area from marginal to “moderate.”

In October 2015 the EPA issued a final rule lowering the primary and secondary NAAQS for ozone to a level of 70 parts per billion. States were required to assess their attainment status and recommend designations to the EPA by October 2016. The following counties and parishes in Entergy’s service territory were recommended for non-attainment: in Louisiana, Ascension Parish, East Baton Rouge Parish, West Baton Rouge Parish, Iberville Parish, and Livingston Parish; in Texas, Montgomery County. The EPA has one year to review these recommendations and make final designations. States are expected to file compliance plans by the end of 2018. The assessments likely will be based on data from 2014-2016. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and non-attainment with the new standard and, where necessary, in planning for compliance. Following designation approval by the EPA, states will be required to develop plans intended to return non-attainment areas to a condition of attainment. The timing for that action depends largely on the severity of non-attainment in a given area.

Potential SO₂ Nonattainment

The EPA issued a final rule in June 2010 adopting an SO₂ 1-hour national ambient air quality standard of 75 parts per billion. The EPA designations for counties in attainment and nonattainment were originally due in June 2012, but the EPA indicated that it would delay designations except for those areas with existing monitoring data from 2009 to 2011 indicating violations of the new standard. In August 2013 the EPA issued final designations for these areas. In Entergy’s utility service territory, only St. Bernard Parish in Louisiana is designated as non-attainment for the SO₂ 1-hour national ambient air quality standard of 75 parts per billion. Entergy does not have a generation asset in that parish. In July 2016 the EPA finalized another round of designations for areas with newly monitored violations of the

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2010 standard and those with stationary sources that emit over a threshold amount of SO₂. Counties and parishes in which Entergy owns and operates fossil generating facilities that were included in this round of designations include Independence County and Jefferson County, Arkansas and Calcasieu Parish, Louisiana. Independence County and Calcasieu Parish were designated “unclassifiable,” and Jefferson County was designated “unclassifiable/attainment.” In August 2015 the EPA issued a final data requirement rule for the SO₂ 1-hour standard. This rule will guide the process to be followed by the states and the EPA to determine the appropriate designation for the remaining unclassified areas in the country. Additional capital projects or operational changes may be required to continue operating Entergy facilities in areas eventually designated as in non-attainment of the standard or designated as contributing to non-attainment areas.

Hazardous Air Pollutants

The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which had a compliance date, with a widely granted one-year extension, of April 2016. The required controls have been installed and are operational at all affected Entergy units.

Cross-State Air Pollution

In March 2005 the EPA finalized the Clean Air Interstate Rule (CAIR), which was intended to reduce SO₂ and NO_x emissions from electric generation plants in order to improve air quality in twenty-nine eastern states. The rule required a combination of capital investment to install pollution control equipment and increased operating costs through the purchase of emission allowances. Entergy began implementation in 2007, including installation of controls at several facilities and the development of an emission allowance procurement strategy.

Based on several court challenges, CAIR and its subsequent versions, now known as the Cross State Air Pollution Rule (CSAPR), have been remanded to and modified by the EPA on multiple occasions. In July 2015 the D.C. Circuit invalidated the allowance budgets created by the EPA for several states, including Texas, and remanded that portion of the rule to the EPA for further action. The court did not stay or vacate the rule in the interim. CSAPR remains in effect.

The CSAPR Phase 1 implementation became effective January 1, 2015. Entergy has developed a compliance plan that could, over time, include both installation of controls at certain facilities and an emission allowance procurement strategy.

In September 2016 the EPA finalized the CSAPR Update Rule to address interstate transport for the 2008 ozone NAAQS. Starting in 2017 the final rule will require reductions in summer nitrogen oxides (NO_x) emissions. Several states, including Arkansas and Texas, filed a challenge to the Update Rule, which remains pending.

Regional Haze

In June 2005 the EPA issued its final Clean Air Visibility Rule (CAVR) regulations that potentially could result in a requirement to install SO₂ and NO_x pollution control technology as Best Available Retrofit Control Technology (BART) to continue operating certain of Entergy’s fossil generation units. The rule leaves certain CAVR determinations to the states.

In Arkansas, the Arkansas Department of Environmental Quality (ADEQ) prepared a State Implementation Plan (SIP) for Arkansas facilities to implement its obligations under the CAVR. In April 2012 the EPA finalized a decision addressing the Arkansas Regional Haze SIP, in which it disapproved a large portion of the Arkansas Regional Haze SIP, including the emission limits for NO_x and SO₂ at White Bluff. By Court order, the EPA had to issue a final federal implementation plan (FIP) for Arkansas Regional Haze by no later than August 31, 2016. In April 2015 the EPA published a proposed FIP for Arkansas, taking comment on requiring installation of scrubbers and low NO_x burners to continue operating both units at the White Bluff plant and both units at the Independence plant and NO_x controls to

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continue operating the Lake Catherine plant. Entergy filed comments by the deadline in August 2015. Among other comments, including opposition to the EPA’s proposed controls on the Independence units, Entergy proposed to meet more stringent SO₂ and NO_x limits at both White Bluff and Independence within three years of the effective date of the final FIP and to cease the use of coal at the White Bluff units in 2027 and 2028.

In September 2016 the EPA published the final Arkansas Regional Haze FIP. In most respects, the EPA finalized its original proposal but shortened the time for compliance for installation of the NO_x controls. The FIP requires an emission limitation consistent with SO₂ scrubbers at both White Bluff and Independence by October 2021 and NO_x controls by April 2018. The EPA declined to adopt Entergy’s proposals related to ceasing coal use as an alternative to SO₂ scrubbers for White Bluff SO₂ BART. For some or all of the FIP, Entergy anticipates that Arkansas will submit a state plan (SIP) to replace the FIP. In November 2016, Entergy and other interested parties such as the State of Arkansas filed petitions for administrative reconsideration and stay at EPA as well as petitions for judicial review to the U.S. Court of Appeals for the Eighth Circuit. In February 2016, Entergy, the State of Arkansas, and other parties requested the Court to judicially stay the FIP. A decision is expected in 2017.

In Louisiana, Entergy is working with the LDEQ and the EPA to revise the Louisiana SIP for regional haze, which was disapproved in part in 2012. A proposed federal implementation plan is likely to be issued in March 2017 with finalization in December 2017. At this time, it is premature to predict what controls, if any, might be required for compliance. Entergy continues to monitor the submission and to file comments in the process as appropriate.

Fine Particle (PM2.5) National Ambient Air Quality Standard

In December 2012 the EPA released regulations that lowered the NAAQS for fine particle pollution or PM2.5. In January 2015 the EPA finalized area designations for this standard. All areas in Entergy’s service territory were designated as “Unclassifiable/Attainment” for this standard. Entergy will continue to monitor and engage, as necessary, in the state’s implementation process in Entergy states.

NNew and Existing Source Performance Standards for Greenhouse Gas Emissions

As a part of a climate plan announced in June 2013, the EPA was directed to (i) reissue proposed carbon pollution standards for new power plants by September 20, 2013, with finalization of the rules to occur in a timely manner; (ii) issue proposed carbon pollution standards, regulations, or guidelines, as appropriate, for modified, reconstructed, and existing power plants no later than June 1, 2014; (iii) finalize those rules by no later than June 1, 2015; and (iv) include in the guidelines addressing existing power plants a requirement that states submit to the EPA the implementation plans required under Section 111(d) of the Clean Air Act and its implementing regulations by no later than June 30, 2016. In January 2014 the EPA issued the proposed New Source Performance Standards rule for new sources. In June 2014 the EPA issued proposed standards for existing power plants. Entergy has been actively engaged in the rulemaking process, having submitted comments to the EPA in December 2014. The EPA issued the final rule for both new and existing sources in August 2015, and it was published in the Federal Register in October 2015. The rule, also called the Clean Power Plan, requires states to develop compliance plans with the EPA’s emission standards. In February 2016 the U.S. Supreme Court issued a stay halting the effectiveness of the rule until the rule is reviewed by the D.C. Circuit and the U.S. Supreme Court. It is also expected that the current administration will make modifications to this program. The cost and schedule for implementation of the 111(d) implementation rule cannot be determined at this time and will depend largely on court decisions, administration modifications to the program, and any forthcoming state section 111 (d) implementation plans.

Potential Legislative, Regulatory, and Judicial Developments

In addition to the specific instances described above, there are a number of legislative and regulatory initiatives concerning air emissions, as well as other media, that are under consideration at the federal, state, and local level. Because of the nature of Entergy’s business, the imposition of any of these initiatives could affect Entergy’s

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operations. Entergy continues to monitor these initiatives and activities in order to analyze their potential operational and cost implications. These initiatives include:


•	designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards;

•

introduction of bills in Congress and development of regulations by the EPA proposing further limits on NO_x, SO₂, mercury, and carbon dioxide and other air emissions. New legislation or regulations applicable to stationary sources could take the form of market-based cap-and-trade programs, direct requirements for the installation of air emission controls onto air emission sources, or other or combined regulatory programs;


•	efforts in Congress or at the EPA to establish a mandatory federal carbon dioxide emission control structure or unit performance standards;


•	revisions to the estimates of the Social Cost of Carbon used for regulatory impact analysis of Federal laws and regulations;


•	implementation of the Regional Greenhouse Gas Initiative by several states in the northeastern United States and similar actions in other regions of the United States;


•	efforts on the state and federal level to codify renewable portfolio standards, a clean energy standard, or a similar mechanism requiring utilities to produce or purchase a certain percentage of their power from defined renewable energy sources or energy sources with lower emissions;


•	efforts to develop more stringent state water quality standards, effluent limitations for Entergy’s industry sector, stormwater runoff control regulations, and cooling water intake structure requirements;


•	efforts to restrict the previously-approved continued use of oil-filled equipment containing certain levels of PCBs;


•	efforts by certain external groups to encourage reporting and disclosure of carbon dioxide emissions and risk; and


•	the listing of additional species as threatened or endangered and the protection of critical habitat for these species.

Entergy continues to support national legislation that would increase planning certainty for electric utilities while addressing carbon dioxide emissions in a responsible and flexible manner. By virtue of its proportionally large investment in low-emitting gas-fired and nuclear generation technologies, Entergy has a low overall carbon dioxide emission “intensity,” or rate of carbon dioxide emitted per kilowatt-hour of electricity generated. In anticipation of the imposition of carbon dioxide emission limits on the electric industry in the future, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included establishment of a formal program to stabilize power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. Total carbon dioxide emissions representing Entergy’s ownership share of power plants in the United States were approximately 53.2 million tons in 2000 and 35.6 million tons in 2005. In 2006, Entergy changed its method of calculating emissions to include emissions from controllable power purchases as well as its ownership share of generation. Entergy established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases at 20% below 2000 levels through 2010. In 2011, Entergy extended this commitment through 2020. Total carbon dioxide emissions representing Entergy’s ownership share of power plants and controllable power purchases in the United States were approximately 46.1 tons in 2011, 45.5 million tons in 2012, 46.2 million tons in 2013, 42.4 million tons in 2014, 39.5 million tons in 2015, and 42.5 million tons in 2016. The decrease in this number from 2014 to 2015 is largely attributable to the impact on the calculation methodology of the Utility operating companies’ transition into the MISO system. Participation in this system resulted in fewer power purchases being classified as “controllable” and thus included in the calculation of the emissions total.

Entergy participates in the M.J. Bradley & Associates’ Annual Benchmarking Air Emissions Report, an annual analysis of the 100 largest U.S. electric power producers. The report is available on the M.J. Bradley website. Entergy’s CO₂ emissions are also third-party verified, and that certification is available on the American Carbon Registry website. Entergy participates annually in the Dow Jones Sustainability Index and in 2016 was listed on the North American Index.

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Nelson Unit 6 (Entergy Louisiana)

Entergy Louisiana has self-reported to the LDEQ an annual carbon monoxide (CO) emission limit deviation at the Nelson Unit 6 coal-fired facility for the years 2006-2010 and the failure to report these deviations in semi-annual reporting and in annual Title V compliance certifications. Entergy Louisiana is not required to monitor carbon monoxide emissions from Nelson Unit 6 using a continuous emissions monitoring system (CEMS). Stack tests performed in 2010 appear to indicate CO emissions in excess of the maximum hourly limit for three - 1 hour test runs; however, comparison of the 2010 stack tests with the most recent previous tests, from 2006, appear to indicate that the permit limits were calculated incorrectly in the Title V Permit application and should have been higher using the 2006 stack test as the basis. The 2010 test emission levels did not cause a violation of NAAQS. Additionally, the 2010 stack testing, which was performed in compliance with an EPA data request connected to the agency’s development of a new air emissions rule, was not taken during a period of normal and representative operations for Nelson 6. Entergy Louisiana has settled this matter with the LDEQ.

Clean Water Act

The 1972 amendments to the Federal Water Pollution Control Act (known as the Clean Water Act) provide the statutory basis for the National Pollutant Discharge Elimination System (NPDES) permit program and the basic structure for regulating the discharge of pollutants from point sources to waters of the United States. The Clean Water Act requires virtually all discharges of pollutants to waters of the United States to be permitted. Section 316(b) of the Clean Water Act regulates cooling water intake structures, section 401 of the Clean Water Act requires a water quality certification from the state in support of certain federal actions and approvals, and section 404 regulates the dredge and fill of waters of the United States, including jurisdictional wetlands.

NPDES Permits and Section 401 Water Quality Certifications

NPDES permits are subject to renewal every five years. Consequently, Entergy is currently in various stages of the data evaluation and discharge permitting process for its power plants.

For thirteen years, Entergy participated in an administrative permitting process with the New York State Department of Environmental Conservation (NYSDEC) for renewal of the Indian Point 2 and Indian Point 3 discharge permit. That proceeding recently was settled along with other ongoing proceedings. For a discussion of the recent Indian Point settlement, see “Entergy Wholesale Commodities Authorization to Operate Its Nuclear Power Plants” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

316(b) Cooling Water Intake Structures

The EPA finalized regulations in July 2004 governing the intake of water at large existing power plants employing cooling water intake structures. The rule sought to reduce perceived impacts on aquatic resources by requiring covered facilities to implement technology or other measures to meet EPA-targeted reductions in water use and corresponding perceived aquatic impacts. Entergy, other industry members and industry groups, environmental groups, and a coalition of northeastern and mid-Atlantic states challenged various aspects of the rule. After litigation, in May 2014, the EPA issued a new final 316(b) rule, followed by publication in the Federal Register in August 2014, with the final rule effective in October 2014. Entergy is developing a compliance plan for each affected facility in accordance with the requirements of the final rule.

Entergy filed as a co-petitioner with the Utility Water Act Group a petition for review of the final rule. The case will be heard in the U.S. Second Circuit Court of Appeals. Entergy expects briefing on the case to be finalized in early 2017.

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Coastal Zone Management Act

Before a federal licensing agency (such as the NRC) may issue a major license or permit for an activity within the federally designated coastal zone, the agency must be satisfied that the requirements of the Coastal Zone Management Act (CZMA), as applicable, have been met. In many cases, CZMA requirements are satisfied by the state’s written concurrence with a “consistency determination” filed by the federal license applicant explaining why the activity proposed to be federally licensed is consistent with the state’s coastal management program. For a discussion of the recent Indian Point settlement, including the CZMA proceedings related to Indian Point license renewal, see “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Plants” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

Federal Jurisdiction of Waters of the United States

In September 2013 the EPA and the U.S. Army Corps of Engineers announced the intention to propose a rule to clarify federal Clean Water Act jurisdiction over waters of the United States. The announcement was made in conjunction with the EPA’s release of a draft scientific report on the “connectivity” of waters that the agency says will inform the rulemaking - this report was finalized in January 2015. The Final Rule was published in the Federal Register in June 2015. The rule could significantly increase the number and types of waters included in the EPA’s and the U.S. Army Corps of Engineers’ jurisdiction, which in turn could pose additional permitting and pollutant management burdens on Entergy’s operations. Entergy is actively engaged with the EPA and the U.S. Army Corps of Engineers to identify issues that require clarification in expected technical and policy guidance documents. The final rule has been challenged in federal court by several parties, including over thirty states. In August 2015 the District Court for North Dakota issued a preliminary injunction staying the new rule in 13 states. In October 2015 the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the rule. Entergy will continue to monitor this rulemaking and ensure compliance with existing permitting processes. In response to the stay, EPA and the U.S. Army Corps resumed nationwide use of the agencies’ regulations as they existed prior to August 27, 2015.

Groundwater at Certain Nuclear Sites

The NRC requires nuclear power plants to monitor and report regularly the presence of radioactive material in the environment. Entergy joined other nuclear utilities and the Nuclear Energy Institute in 2006 to develop a voluntary groundwater monitoring and protection program. This initiative began after detection of very low levels of radioactive material, primarily tritium, in groundwater at several plants in the United States. Tritium is a radioactive form of hydrogen that occurs naturally and is also a byproduct of nuclear plant operations. In addition to tritium, other radionuclides have been found in site groundwater at nuclear plants.

As part of the groundwater monitoring and protection program, Entergy has: (1) performed reviews of plant groundwater characteristics (hydrology) and historical records of past events on site that may have potentially impacted groundwater; (2) implemented fleet procedures on how to handle events that could impact groundwater; and (3) installed groundwater monitoring wells and began periodic sampling. The program also includes protocols for notifying local officials if contamination is found. To date, radionuclides such as tritium have been detected at Arkansas Nuclear One, FitzPatrick, Indian Point, Palisades, Pilgrim, Grand Gulf, Vermont Yankee, and River Bend. Each of these sites has installed groundwater monitoring wells and implemented a program for testing groundwater at the sites for the presence of tritium and other radionuclides. Based on current information, the concentrations and locations of radionuclides detected at these plants pose no threat to public health or safety, but each site continues to evaluate the results from its groundwater monitoring program.

In February 2016, Entergy disclosed that elevated tritium levels had been detected in samples from several monitoring wells that are part of Indian Point’s groundwater monitoring program. Investigation of the source of elevated tritium has determined that the source is related to a temporary system to process water in preparation for the regularly scheduled refueling outage at Indian Point 2. The system was secured and is no longer in use and additional measures have been taken to prevent reoccurrence should the system be needed again. In June 2016, Indian Point detected trace

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amounts of cobalt 58 in a single well. This was associated with the draining and disassembly of a temporary heat exchanger operated in support of the Indian Point 2 outage. Oversight by NRC and other federal/state government bodies continues. The NRC has issued a Green Notice of Violation related to the adequacy of Entergy’s controls to prevent the introduction of radioactivity into the site groundwater.

Comprehensive Environmental Response, Compensation, and Liability Act of 1980

The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorizes the EPA to mandate clean-up by, or to collect reimbursement of clean-up costs from, owners or operators of sites at which hazardous substances may be or have been released. Certain private parties also may use CERCLA to recover response costs. Parties that transported hazardous substances to these sites or arranged for the disposal of the substances are also deemed liable by CERCLA. CERCLA has been interpreted to impose strict, joint and several liability on responsible parties. Many states have adopted programs similar to CERCLA. Entergy subsidiaries in the Utility and Entergy Wholesale Commodities businesses have sent waste materials to various disposal sites over the years, and releases have occurred at Entergy facilities. In addition, environmental laws now regulate certain of Entergy’s operating procedures and maintenance practices that historically were not subject to regulation. Some disposal sites used by Entergy subsidiaries have been the subject of governmental action under CERCLA or similar state programs, resulting in site clean-up activities. Entergy subsidiaries have participated to various degrees in accordance with their respective potential liabilities in such site clean-ups and have developed experience with clean-up costs. The affected Entergy subsidiaries have established provisions for the liabilities for such environmental clean-up and restoration activities. Details of CERCLA and similar state program liabilities that are not de minimis are discussed in the “Other Environmental Matters” section below.

Coal Combustion Residuals

The final regulations create new compliance requirements including modified storage, new notification and reporting practices, product disposal considerations, and CCR unit closure criteria. Entergy believes that on-site disposal options will be available at its facilities, to the extent needed for CCR that cannot be transferred for beneficial reuse. As of December 31, 2016, Entergy’s has recorded asset retirement obligations related to CCR management of $8.2 million, including $3.8 million at Entergy Arkansas, $1.7 million at Entergy Louisiana, $1.1 million at Entergy Mississippi, and $1.3 million at Entergy Texas.

In December 2016 the Water Infrastructure Improvements for the Nation Act was signed into law, which authorizes states to regulate coal ash rather than leaving primary enforcement to citizen suit actions. States may submit to the EPA proposals for a permit programs. Entergy is monitoring state agency actions and will participate in the regulatory development process.

Other Environmental Matters

Entergy Louisiana and Entergy Texas

Several class action and other lawsuits have been filed in state and federal courts seeking relief from Entergy Gulf States, Inc. and others for damages caused by the disposal of hazardous waste and for asbestos-related disease allegedly resulting from exposure on Entergy Gulf States, Inc.’s premises (see “Litigation” below).

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Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, currently is involved in the second phase of the remedial investigation of the Lake Charles Service Center site, located in Lake Charles, Louisiana. A manufactured gas plant (MGP) is believed to have operated at this site from approximately 1916 to 1931. Coal tar, a by-product of the distillation process employed at MGPs, apparently was routed to a portion of the property for disposal. The same area also has been used as a landfill. In 1999, Entergy Gulf States, Inc. signed a second administrative consent order with the EPA to perform a removal action at the site. In 2002 approximately 7,400 tons of contaminated soil and debris were excavated and disposed of from an area within the service center. In 2003 a cap was constructed over the remedial area to prevent the migration of contamination to the surface. In August 2005 an administrative order was issued by the EPA requiring that a 10-year groundwater study be conducted at this site. The groundwater monitoring study commenced in January 2006 and is continuing. The EPA released the second Five Year Review in 2015. The EPA believes that the current remediation technique is insufficient, and Entergy will need to utilize other remediation technologies on the site. In July 2015, Entergy submitted a Focused Feasibility Study to the EPA outlining the potential remedies and the suggested installation of a waterloo barrier. The estimated cost for this remedy is approximately $2 million. Entergy is awaiting comments and direction from the EPA on the Focused Feasibility Study and potential remedy selection. Entergy is continuing discussions with the EPA regarding the ongoing actions at the site.

Entergy Louisiana and Entergy New Orleans

Several class action and other suits have been filed in state and federal courts seeking relief from Entergy Louisiana and Entergy New Orleans and others for damages caused by the disposal of hazardous waste and for asbestos-related disease allegedly resulting from exposure on Entergy Louisiana’s and Entergy New Orleans’s premises (see “Litigation” below).

Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas

The Texas Commission on Environmental Quality (TCEQ) notified Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas that the TCEQ believes those entities are potentially responsible parties (PRPs) concerning contamination existing at the San Angelo Electric Service Company (SESCO) facility in San Angelo, Texas. The facility operated as a transformer repair and scrapping facility from the 1930s until 2003. Both soil and groundwater contamination exists at the site. Entergy subsidiaries sent transformers to this facility. Entergy Arkansas, Entergy Louisiana, and Entergy Texas responded to an information request from the TCEQ and continue to cooperate in this investigation. Entergy Louisiana and Entergy Texas joined a group of PRPs responding to site conditions in cooperation with the State of Texas, creating cost allocation models based on review of SESCO documents and employee interviews, and investigating contribution actions against other PRPs. Entergy Louisiana and Entergy Texas have agreed to contribute to the remediation of contaminated soil and groundwater at the site in a measure proportionate to those companies’ involvement at the site, while Entergy Arkansas likely will pay a de minimis amount. Current estimates, although variable depending on ultimate remediation design and performance, indicate that Entergy’s total share of remediation costs likely will be approximately $1.5 million to $2 million. Remediation activities continue at the site.

Entergy Mississippi, Entergy Louisiana, Entergy New Orleans, and Entergy Texas

The EPA notified Entergy Mississippi, Entergy Texas, and Entergy New Orleans that the EPA believes those entities are PRPs concerning contamination of an area known as “Devil’s Swamp Lake” near the Port of Baton Rouge, Louisiana. The area allegedly was contaminated by the operations of Rollins Environmental (LA), Inc, which operated a disposal facility to which many companies contributed waste. Documents provided by the EPA indicate that Entergy Louisiana may also be a PRP. Entergy continues to monitor this situation.

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Entergy Arkansas

In April 2014 an EF4 tornado impacted two substation transformers in Entergy Arkansas’s Mayflower EHV substation. The tornado caused a release of approximately 25,000 gallons of non-PCB transformer oils, which subsequently flowed into a creek on Entergy Arkansas property. A report was made to the National Response Center, and several environmental agencies responded. Entergy initiated spill response activities within hours of the release with eventual oversight of the EPA and Arkansas Department of Environmental Quality (ADEQ) personnel. At the direction of the agencies, Entergy Arkansas has installed several temporary monitoring and recovery wells throughout the site and has regularly pumped and sampled the wells to determine the site meets regulatory screening limits. Acceptable screening limits have been achieved and Entergy Arkansas has received notification from the ADEQ that the site remediation is sufficient. Entergy Arkansas has received confirmation from ADEQ of “No Further Action Required.” There are no additional cleanup liability issues expected for the site; however, minimal administrative oversight charges from EPA and ADEQ may still be outstanding.

Entergy Texas

In December 2016 a transformer inside the Hartburg, Texas Substation had an internal fault resulting in a release of approximately 15,000 gallons of non-PCB mineral oil. Cleanup ensued immediately; however, rain caused much of the oil to spread across the substation yard and into a nearby wetland. The Texas Commission on Environmental Quality (TCEQ) and the National Response Center were immediately notified, and TCEQ responded to the site approximately two hours after the cleanup was initiated. The remediation liability is estimated at $1.4 million; however, this number could fluctuate depending on the remediation extent and wetland mitigation requirements.

Entergy

In May 2015 a transformer at the Indian Point facility failed, resulting in a fire and the release of non-PCB oil to the ground surface. The fire was extinguished by the facility’s fire deluge system. No injuries occurred due to the transformer failure or company response. An estimated 3,000 gallons of oil were released into the facility’s discharge canal and the environment surrounding the transformer and discharge canal, including the Hudson River, as a result of the failure, fire, and fire suppression. Once the fire was extinguished, Indian Point personnel and contractors began recovering free-product from the damaged transformer, the transformer containment moat, and the area surrounding the transformer. The United States Coast Guard designated Entergy as the responsible party under the Oil Pollution Act of 1990 and assessed a $1,000 civil penalty for the discharge of oil into navigable waters. As required, Entergy established a claims process including a voluntary hotline. Entergy received no reports to the voluntary hotline or claims under the established claims process. Additional on-site remedial work including subsurface investigation continues, and the State of New York and/or the EPA may assess a penalty due to the release of oil to waters of the state. In September 2016, Indian Point personnel identified an oil sheen in the discharge canal. Further investigation revealed that an estimated 600 gallons of lubricating oil had leaked from the Indian Point 3 turbine system. The leaking component has been taken out of service and no oil has been discovered in the Hudson River. In October 2016 the New York Department of Environmental Conservation issued two notices of violation, one for each of these events, and a proposed order on consent for the 2015 event. In January 2017, Entergy and the New York Department of Environmental Conservation resolved this matter with an Order on Consent. The agreed Order requires Entergy to pay approximately $600 thousand in civil penalties, natural resource damages, and oversight costs. Additionally, Entergy will repair a 70-foot section of the discharge canal wall and will conduct daily visual inspections of the discharge canal wall to help identify additional material erosion or material structural deficiencies.

Litigation

Entergy uses legal and appropriate means to contest litigation threatened or filed against it, but certain states in which Entergy operates have proven to be unusually litigious environments. Judges and juries in Louisiana, Mississippi, and Texas have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs

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in personal injury, property damage, and business tort cases. The litigation environment in these states poses a significant business risk to Entergy.

Ratepayer and Fuel Cost Recovery Lawsuits (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)

Texas Power Price Lawsuit

See Note 2 to the financial statements for a discussion of this proceeding.

Mississippi Attorney General Complaint

See Note 2 to the financial statements for a discussion of this proceeding.

Asbestos Litigation (Entergy Louisiana and Entergy Texas)

See Note 8 to the financial statements for a discussion of this litigation.

Employment and Labor-related Proceedings (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

See Note 8 to the financial statements for a discussion of these proceedings.

Employees

Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2016, Entergy subsidiaries employed 13,513 people.



Utility:
Entergy Arkansas	1,242
Entergy Louisiana	1,696
Entergy Mississippi	709
Entergy New Orleans	269
Entergy Texas	619
System Energy	—
Entergy Operations	2,948
Entergy Services	3,126
Entergy Nuclear Operations	2,850
Other subsidiaries	54
Total Entergy	13,513

Approximately 4,900 employees are represented by the International Brotherhood of Electrical Workers, the Utility Workers Union of America, the International Brotherhood of Teamsters, the United Government Security Officers of America, and the International Union, Security, Police, Fire Professionals of America.

Availability of SEC filings and other information on Entergy’s website

Entergy electronically files reports with the SEC, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxies, and amendments to such reports. The public may read and copy any materials that Entergy files with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington,

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D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports, proxy and information statements, and other information regarding registrants that file electronically with the SEC at http://www.sec.gov.

Entergy uses its website, http://www.entergy.com, as a routine channel for distribution of important information, including news releases, analyst presentations and financial information. Filings made with the SEC are posted and available without charge on Entergy’s website as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. These filings include annual and quarterly reports on Forms 10-K and 10-Q (including related filings in XBRL format) and current reports on Form 8-K; proxy statements; and any amendments to those reports or statements. All such postings and filings are available on Entergy’s Investor Relations website free of charge. Entergy is providing the address to its Internet site solely for the information of investors and does not intend the address to be an active link. The contents of the website are not incorporated into this report.

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RISK FACTORS

Investors should review carefully the following risk factors and the other information in this Form 10-K. The risks that Entergy faces are not limited to those in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect Entergy’s financial condition, results of operations, and liquidity. See “FORWARD-LOOKING INFORMATION.”

Utility Regulatory Risks

(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

The terms and conditions of service, including electric and gas rates, of the Utility operating companies and System Energy are determined through regulatory approval proceedings that can be lengthy and subject to appeal that could result in delays in effecting rate changes and uncertainty as to ultimate results.

The rates that the Utility operating companies and System Energy charge reflect their capital expenditures, operations and maintenance costs, allowed rates of return, financing costs, and related costs of service. These rates significantly influence the financial condition, results of operations, and liquidity of Entergy and each of the Utility operating companies and System Energy. These rates are determined in regulatory proceedings and are subject to periodic regulatory review and adjustment upon the initiative of a regulator or affected stakeholders.

In addition, regulators can initiate proceedings to investigate the prudence of costs in the Utility operating companies’ base rates and examine, among other things, the reasonableness or prudence of the companies’ operation and maintenance practices, level of expenditures (including storm costs and costs associated with capital projects), allowed rates of return and rate base, proposed resource acquisitions, and previously incurred capital expenditures that the operating companies seek to place in rates. The regulators can disallow costs subject to their jurisdiction found not to have been prudently incurred or found not to have been incurred in compliance with applicable tariffs, creating some risk to the ultimate recovery of those costs. Regulatory proceedings relating to rates and other matters typically involve multiple parties seeking to limit or reduce rates. Traditional base rate proceedings, as opposed to formula rate plans, generally have long timelines, are primarily based on historical costs, and may or may not be limited in scope or duration by statute. The length of these base rate proceedings can cause the Utility operating companies and System Energy to experience regulatory lag in recovering costs through rates. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings.

The base rates of Entergy Texas are established in traditional base rate case proceedings. Apart from base rate proceedings, Entergy Texas has also filed to use rate riders to recover the revenue requirements associated with certain authorized historical costs. Specifically, Entergy Texas has recovered distribution-related capital investments through the distribution cost recovery factor rider mechanism, transmission-related capital investments and certain non-fuel MISO charges through the transmission cost recovery factor rider mechanism, and MISO fuel and energy-related costs through the fixed fuel factor mechanism. Entergy Texas is also required to make a filing every three years, at a minimum, reconciling its fuel and purchased power costs and fuel factor revenues. In the course of this reconciliation, the PUCT determines whether eligible fuel and fuel-related expenses and revenues are necessary and reasonable, and makes a prudence finding for each of the fuel-related contracts for the reconciliation period.

Between base rate cases, Entergy Arkansas and Entergy Mississippi are able to adjust base rates annually through formula rate plans that utilize a forward test year (Entergy Arkansas) or forward-looking features (Entergy Mississippi). In response to Entergy Arkansas’s application for a general change in rates in 2015, the APSC approved Entergy Arkansas’s proposed formula rate plan rider pursuant to its election to have its rates regulated under a formula rate review mechanism pursuant to legislation enacted by the Arkansas General Assembly in early 2015. The APSC approved the formula rate plan tariff including its use of a projected year test period and an initial five-year term. The initial five-year term expires in 2021 unless Entergy Arkansas requests, and the APSC approves, the extension of the formula rate plan tariff for an additional five years through 2026. In the event that Entergy Arkansas’ formula rate

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plan is terminated or is not extended beyond the initial term, Entergy Arkansas could file an application for a general change in rates that may include a request for continued regulation under a formula rate review mechanism. If Entergy Mississippi’s formula rate plan is terminated, it would revert to the more traditional rate case environment or seek approval of a new formula rate plan. Entergy Arkansas and Entergy Mississippi recover fuel and purchased energy and certain non-fuel costs through other APSC-approved and MPSC-approved tariffs, respectively.

Entergy Louisiana sets electric base rates annually through a formula rate plan using an historic test year. The form of the formula rate plan, on a combined basis, was approved in connection with the business combination of Entergy Louisiana and Entergy Gulf States Louisiana and largely followed the formula rate plans that were approved by the LPSC in connection with the full electric base rate cases filed by those companies in February 2013. The formula rate plan is approved for continued use through the test year 2016 filing. Entergy Louisiana’s electric formula rate plan increases are capped at a cumulative total of $30 million through the formula rate plan cycle. The LPSC also approved in the business combination Entergy Louisiana’s continuation of a mechanism to recover non-fuel MISO-related costs, which are calculated separately from the formula rate plan requirements, but embedded in the formula rate plan factor applied on customer bills. This recovery mechanism expires following the 2015 test year, and Entergy Louisiana has filed an application seeking to extend that mechanism, which is subject to review and approval by the LPSC. MISO fuel and energy-related costs are recoverable in Entergy Louisiana’s fuel adjustment clause. The formula rate plan retains exceptions from the rate cap/restrictions and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities, as well as purchase power agreements approved by the LPSC. In the event that the electric formula rate plans were terminated, or expired without renewal or extension, Entergy Louisiana would at that time revert to the more traditional rate case environment.

Entergy New Orleans previously operated under a formula rate plan that ended with the 2011 test year. Currently, based on a settlement agreement approved by the City Council, with limited exceptions, no action may be taken with respect to Entergy New Orleans’ base rates until rates are implemented from a base rate case that must be filed for its electric and gas operations in 2018. The limited exceptions include implementation of the final year of a four-year phased-in rate increase for its Algiers operations in the Fifteenth Ward of the City of New Orleans and certain exceptional cost increases or decreases in its base revenue requirement.

The Utility operating companies and System Energy, and the energy industry as a whole, have experienced a period of rising costs and investments, and an upward trend in spending, especially with respect to infrastructure investments, which is likely to continue in the foreseeable future and could result in more frequent rate cases and requests for, and the continuation of, cost recovery mechanisms. For information regarding rate case proceedings and formula rate plans applicable to the Utility operating companies, see Note 2 to the financial statements.

The Utility operating companies recover fuel, purchased power, and associated costs through rate mechanisms that are subject to risks of delay or disallowance in regulatory proceedings.

The Utility operating companies recover their fuel, purchased power, and associated costs from their customers through rate mechanisms subject to periodic regulatory review and adjustment. Because regulatory review can result in the disallowance of incurred costs found not to have been prudently incurred, including the cost of replacement power purchased when generators experience outages, with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs. Regulators can also initiate proceedings to investigate the continued usage or the adequacy and operation of the fuel and purchased power recovery clauses of the Utility operating companies and, therefore, there can be no assurance that existing recovery mechanisms will remain unchanged or in effect at all.

The Utility operating companies’ cash flows can be negatively affected by the time delays between when gas, power, or other commodities are purchased and the ultimate recovery from customers of the costs in rates. On occasion, when the level of incurred costs for fuel and purchased power rises very dramatically, some of the Utility operating companies may agree to defer recovery of a portion of that period’s fuel and purchased power costs for recovery at a later date, which could increase the near-term working capital and borrowing requirements of those companies. For

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a description of fuel and purchased power recovery mechanisms and information regarding the regulatory proceedings for fuel and purchased power costs recovery, see Note 2 to the financial statements.

There is uncertainty regarding the effect of the termination of the System Agreement on the Utility operating companies.

The Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating resources and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that had been approved by the FERC.

Entergy Arkansas’s participation in the System Agreement terminated in December 2013, and Entergy Mississippi’s participation in the System Agreement terminated in November 2015. Pursuant to a settlement agreement approved by the FERC in December 2015, the System Agreement terminated in its entirety with respect to the remaining Utility operating companies on August 31, 2016.

There is uncertainty regarding the long-term effect of the termination of the System Agreement on the Utility operating companies because of the significant effect of the agreement on the generation and transmission functions of the Utility operating companies and the significant period of time (over 30 years) that it has been in existence. In the absence of the System Agreement, there is uncertainty around the effectiveness of governance processes and the potential absence of federal authority to resolve certain issues among the Utility operating companies and their retail regulators.

In addition, although the System Agreement terminated in its entirety in August 2016, there are a number of outstanding System Agreement proceedings at the FERC that may require future adjustments, including challenges to the level and timing of payments made by Entergy Arkansas under the System Agreement. The outcome and timing of these FERC proceedings and resulting recovery and impact on rates cannot be predicted at this time.

For further information regarding the regulatory proceedings relating to the System Agreement, see Note 2 to the financial statements.

The Utility operating companies are subject to economic risks associated with participation in the MISO markets and the allocation of transmission upgrade costs. The operation of the Utility operating companies’ transmission system pursuant to the MISO RTO tariff and their participation in the MISO RTO’s wholesale markets may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.

On December 19, 2013, the Utility operating companies integrated into the MISO RTO. MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their generating facilities into the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. The Utility operating companies are subject to economic risks associated with participation in the MISO markets. MISO tariff rules and system conditions, including transmission congestion, could affect the Utility operating companies’ ability to sell power in certain regions and/or the economic value of such sales, and MISO market rules may change in ways that cause additional risk.

The Utility operating companies participate in the MISO regional transmission planning process and are subject to risks associated with planning decisions that MISO makes in the exercise of control over the planning of the Utility operating companies’ transmission assets that are under MISO’s functional control. The Utility operating companies pay transmission rates that reflect the cost of transmission projects that the Utility operating companies do not own, which could increase cash or financing needs. The terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets and the allocation of transmission upgrade costs, are subject to regulation by FERC. The operation of the Utility operating companies’ transmission system pursuant to the

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MISO tariff and their participation in the MISO wholesale markets may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements. In addition, orders from each of the Utility operating companies’ respective retail regulators generally require that the Utility operating companies make filings, within a specified period of their integration into MISO, setting forth the results of analysis of the costs and benefits of continued membership in MISO and/or requesting approval of their continued membership in MISO, and the outcome of such proceedings may affect the Utility operating companies’ continued membership in MISO.

(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)

A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather could have material effects on Entergy and those Utility operating companies affected by severe weather.

Entergy’s and its Utility operating companies’ results of operations, liquidity, and financial condition can be materially affected by the destructive effects of severe weather. Severe weather can also result in significant outages for the customers of the Utility operating companies and, therefore, reduced revenues for the Utility operating companies during the period of the outages. A delay or failure in recovering amounts for storm restoration costs incurred or revenues lost as a result of severe weather could have a material effect on Entergy and those Utility operating companies affected by severe weather.

Nuclear Operating, Shutdown and Regulatory Risks

(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)

Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities must consistently operate their nuclear power plants at high capacity factors in order to be successful, and lower capacity factors could materially affect Entergy’s and their results of operations, financial condition, and liquidity.

Nuclear capacity factors significantly affect the results of operations of certain Utility operating companies, System Energy, and Entergy Wholesale Commodities. Nuclear plant operations involve substantial fixed operating costs. Consequently, to be successful, a plant owner must consistently operate its nuclear power plants at high capacity factors. For the Utility operating companies that own nuclear plants, lower capacity factors can increase production costs by requiring the affected companies to generate additional energy, sometimes at higher costs, from their fossil facilities or purchase additional energy in the spot or forward markets in order to satisfy their supply needs. For the Entergy Wholesale Commodities nuclear plants, lower capacity factors directly affect revenues and cash flow from operations. Entergy Wholesale Commodities’ forward sales are comprised of various hedge products, many of which have some degree of operational-contingent price risk. Certain unit-contingent contracts guarantee specified minimum capacity factors. In the event plants with these contracts were operating below the guaranteed capacity factors, Entergy would be subject to price risk for the undelivered power. Further, Entergy Wholesale Commodities’ nuclear forward sales contracts can also be on a firm LD basis, which subjects Entergy to increasing price risk as capacity factors decrease. Many of these firm hedge products have damages risk, capped through the use of risk management products.

Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities nuclear plant owners periodically shut down their nuclear power plants to replenish fuel. Plant maintenance and upgrades are often scheduled during such refueling outages. If refueling outages last longer than anticipated or if unplanned outages arise, Entergy’s and their results of operations, financial condition, and liquidity could be materially affected.

Outages at nuclear power plants to replenish fuel require the plant to be “turned off.” Refueling outages generally are planned to occur once every 18 to 24 months and average approximately 30 days in duration. Plant maintenance and upgrades are often scheduled during such planned outages. When refueling outages last longer than anticipated or a plant experiences unplanned outages, capacity factors decrease and maintenance costs may

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increase. Lower than forecasted capacity factors may cause Entergy Wholesale Commodities to experience reduced revenues and may also create damages risk with certain hedge products as previously discussed.

Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities face risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication), and the risk of being unable to effectively manage these risks by purchasing from a diversified mix of sellers located in a diversified mix of countries could materially affect Entergy’s and their results of operations, financial condition, and liquidity.

Based upon currently planned fuel cycles, Entergy’s nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable prices through most of 2017 and beyond. The nuclear fuel supply portfolio for the Entergy Wholesale Commodities segment is being adjusted to reflect reduced overall requirements related to the planned permanent shutdown of the Palisades, Pilgrim, Indian Point 2 and Indian Point 3 plants and the planned sale of the FitzPatrick plant. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners and enrichers. While there are a number of possible alternate suppliers that may be accessed to mitigate any supplier performance failure, the pricing of any such alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. Entergy also may draw upon its own inventory intended for later generation periods, depending upon its risk management strategy at that time. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S. Market prices for nuclear fuel have been extremely volatile from time to time in the past. Although Entergy’s nuclear fuel contract portfolio provides a degree of hedging against market risks for several years, costs for nuclear fuel in the future cannot be predicted with certainty due to normal inherent market uncertainties, and price increases could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities.

Entergy’s ability to assure nuclear fuel supply also depends upon the performance and reliability of conversion, enrichment, and fabrication services providers. These service providers are fewer in number than uranium suppliers. For conversion and enrichment services, Entergy diversifies its supply by supplier and country and may take special measures to ensure a reliable supply of enriched uranium for fabrication into nuclear fuel. For fabrication services, each plant is dependent upon the performance of the fabricator of that plant’s nuclear fuel; therefore, Entergy relies upon additional monitoring, inspection, and oversight of the fabrication process to assure reliability and quality of its nuclear fuel. Certain of the suppliers and service providers are located in or dependent upon countries, such as Russia, in which deteriorating economic conditions or international sanctions could restrict the ability of such suppliers to continue to supply fuel or provide such services. The inability of such suppliers or service providers to perform such obligations could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities.

Entergy Arkansas, Entergy Louisiana, System Energy, and the Entergy Wholesale Commodities business face the risk that the NRC will change or modify its regulations, suspend, not renew, or revoke their licenses, or increase oversight of their nuclear plants, which could materially affect Entergy’s and their results of operations, financial condition, and liquidity.

Under the Atomic Energy Act and Energy Reorganization Act, the NRC regulates the operation of nuclear power plants. The NRC may modify, suspend, not renew, or revoke licenses, shut down a nuclear facility and impose civil penalties for failure to comply with the Atomic Energy Act, related regulations, or the terms of the licenses for nuclear facilities. A change in the Atomic Energy Act, other applicable statutes, or the applicable regulations or licenses, or the NRC’s interpretation thereof, may require a substantial increase in capital expenditures or may result in increased operating or decommissioning costs and could materially affect the results of operations, liquidity, or financial condition of Entergy (through Entergy Wholesale Commodities), its Utility operating companies, or System Energy. A change in the classification of a plant owned by one of these companies under the NRC’s Reactor Oversight Process, which is the NRC’s program to collect information about plant performance, assess the information for its safety significance,

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and provide for appropriate licensee and NRC response, also could cause the owner of the plant to incur material additional costs as a result of the increased oversight activity and potential response costs associated with the change in classification. For additional information concerning the current classification of the plants owned by Entergy Arkansas, Entergy Louisiana, System Energy, and the Entergy Wholesale Commodities business, see ENTERGY’S BUSINESS - Regulation of Entergy’s Business - Regulation of the Nuclear Power Industry - NRC Reactor Oversight Process in Part I, Item 1 and Note 8 to the financial statements.

Events at nuclear plants owned by one of these companies, as well as those owned by others, may lead to a change in laws or regulations or the terms of the applicable licenses, or the NRC’s interpretation thereof, or may cause the NRC to increase oversight activity or initiate actions to modify, suspend, or revoke licenses, shut down a nuclear facility, or impose civil penalties. As a result, if an incident were to occur at any nuclear generating unit, whether an Entergy nuclear generating unit or not, it could materially affect the financial condition, results of operations, and liquidity of Entergy, certain of the Utility operating companies, System Energy, or Entergy Wholesale Commodities. For example, the earthquake of March 11, 2011 that affected the Fukushima Daiichi nuclear plants in Japan resulted in the NRC issuing various orders requiring U.S. nuclear operators, including Entergy, to undertake plant modifications or perform additional analyses that, among other things, have resulted in increased capital and operating costs associated with operating Entergy’s nuclear plants, some of which have been material.

Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities are exposed to risks and costs related to operating and maintaining their nuclear power plants, and their failure to maintain operational efficiency at their nuclear power plants could materially affect Entergy’s and their results of operations, financial condition, and liquidity.

The nuclear generating units owned by certain of the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business began commercial operations in the 1970s-1980s. Older equipment may require more capital expenditures to keep each of these nuclear power plants operating safely and efficiently. This equipment is also likely to require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages, or any unanticipated capital expenditures, could result in increased costs, some of which costs may not be fully recoverable by the Utility operating companies and System Energy in regulatory proceedings. Operations at any of the nuclear generating units owned and operated by Entergy’s subsidiaries could degrade to the point where the affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. A decision may be made to close a unit rather than incur the expense of restarting it or returning the unit to full capacity. For the Utility operating companies and System Energy, this could result in certain costs being stranded and potentially not fully recoverable in regulatory proceedings. For Entergy Wholesale Commodities, this could result in lost revenue and increased fuel and purchased power expense to meet supply commitments and penalties for failure to perform under their contracts with customers. In addition, the operation and maintenance of Entergy’s nuclear facilities require the commitment of substantial human resources that can result in increased costs.

The nuclear industry continues to address susceptibility to stress corrosion cracking of certain materials within plant systems. The issue is applicable at all nuclear units to varying degrees and is managed in accordance with industry standard practices and guidelines that include in-service examinations, replacements, and mitigation strategies. Developments in the industry or identification of issues at the nuclear units could require unanticipated remediation efforts that cannot be quantified in advance.

Moreover, Entergy is becoming more dependent on fewer suppliers for key parts of Entergy’s nuclear power plants that may need to be replaced or refurbished. In addition, certain major parts have long lead-times to manufacture if an unplanned replacement is needed. This dependence on a reduced number of suppliers and long lead-times on certain major parts for unplanned replacements could result in delays in obtaining qualified replacement parts and, therefore, greater expense for Entergy.

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The costs associated with the storage of the spent nuclear fuel of certain of the Utility operating companies, System Energy, and the owners of the Entergy Wholesale Commodities nuclear power plants, as well as the costs of and their ability to fully decommission their nuclear power plants, could be significantly affected by the timing of the opening of a spent nuclear fuel disposal facility, as well as interim storage and transportation requirements.

Certain of the Utility operating companies, System Energy and the owners of the Entergy Wholesale Commodities nuclear plants incur costs on a periodic basis for the on-site storage of spent nuclear fuel. The approval of a license for a national repository for the disposal of spent nuclear fuel, such as the one proposed for Yucca Mountain, Nevada, or any interim storage facility, and the timing of such facility opening, will significantly affect the costs associated with on-site storage of spent nuclear fuel. For example, while the DOE is required by law to proceed with the licensing of Yucca Mountain and, after the license is granted by the NRC, to construct the repository and commence the receipt of spent fuel, the NRC licensing of the Yucca Mountain repository is effectively at a standstill. These actions may prolong the time before spent fuel is removed from Entergy’s plant sites. Because the DOE has not accomplished its objectives, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts, and Entergy has sued the DOE for such breach. Furthermore, Entergy is uncertain as to when the DOE plans to commence acceptance of spent fuel from its facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at the companies’ nuclear sites and maintenance costs on existing storage facilities may increase. The costs of on-site storage are also affected by regulatory requirements for such storage. In addition, the availability of a repository or other off-site storage facility for spent nuclear fuel may affect the ability to fully decommission the nuclear units and the costs relating to decommissioning. For further information regarding spent fuel storage, see the “Critical Accounting Estimates – Nuclear Decommissioning Costs – Spent Fuel Disposal” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy and Note 8 to the financial statements.

Certain of the Utility operating companies, System Energy, and the Entergy Wholesale Commodities nuclear plant owners may be required to pay substantial retrospective premiums imposed under the Price-Anderson Act in the event of a nuclear incident, and losses not covered by insurance could have a material effect on Entergy’s and their results of operations, financial condition, or liquidity.

Accidents and other unforeseen problems at nuclear power plants have occurred both in the United States and elsewhere. The Price-Anderson Act limits each reactor owner’s public liability (off-site) for a single nuclear incident to the payment of retrospective premiums into a secondary insurance pool of up to approximately $127.3 million per reactor. With 102 reactors currently participating, this translates to a total public liability cap of approximately $13 billion per incident. The limit is subject to change to account for the effects of inflation, a change in the primary limit of insurance coverage, and changes in the number of licensed reactors. As required by the Price-Anderson Act, the Utility operating companies, System Energy, and Entergy Wholesale Commodities carry the maximum available amount of primary nuclear off-site liability insurance with American Nuclear Insurers (which is $450 million for each operating site as of January 1, 2017). Claims for any nuclear incident exceeding that amount are covered under the retrospective premiums paid into the secondary insurance pool. As a result, in the event of a nuclear incident that causes damages (off-site) in excess of the primary insurance coverage, each owner of a nuclear plant reactor, including Entergy’s Utility operating companies, System Energy, and the Entergy Wholesale Commodities plant owners, regardless of fault or proximity to the incident, will be required to pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary insurance level, up to a maximum of approximately $127.3 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.273 billion). The retrospective premium payment is currently limited to approximately $19 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $127.3 million cap.

NEIL is a utility industry mutual insurance company, owned by its members. All member plants could be subject to an annual assessment (retrospective premium of up to 10 times current annual premium for all policies) should the surplus (reserve) be significantly depleted due to insured losses. As of December 31, 2016, the maximum annual assessment amounts total $135.2 million for the Utility plants and $127.4 million for the Entergy Wholesale Commodities plants. Retrospective premium insurance available through NEIL’s reinsurance treaty can cover the

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potential assessments and the Entergy Wholesale Commodities plants currently maintain the retrospective premium insurance to cover those potential assessments.

As an owner of nuclear power plants, Entergy participates in industry self-insurance programs and could be liable to fund claims should a plant owned by a different company experience a major event. Any resulting liability from a nuclear accident may exceed the applicable primary insurance coverage and require contribution of additional funds through the industry-wide program that could significantly affect the results of operations, financial condition, or liquidity of Entergy, certain of the Utility operating companies, System Energy, or the Entergy Wholesale Commodities subsidiaries.

Market performance and other changes may decrease the value of assets in the decommissioning trusts, which then could require significant additional funding.

Owners of nuclear generating plants have an obligation to decommission those plants. Certain of the Utility operating companies, System Energy, and owners of the Entergy Wholesale Commodities nuclear power plants maintain decommissioning trust funds for this purpose. Certain of the Utility operating companies collect funds from their customers, which are deposited into the trusts covering the units operated for or on behalf of those companies. Those rate collections, as adjusted from time to time by rate regulators, are generally based upon operating license lives and trust fund balances as well as estimated trust fund earnings and decommissioning costs. In connection with the acquisition of certain nuclear plants, the Entergy Wholesale Commodities plant owners also acquired decommissioning trust funds that are funded in accordance with NRC regulations. Assets in these trust funds are subject to market fluctuations, will yield uncertain returns that may fall below projected return rates, and may result in losses resulting from the recognition of impairments of the value of certain securities held in these trust funds. As part of the Pilgrim, Indian Point 1 and Indian Point 2, Vermont Yankee, and Palisades/Big Rock Point purchases, the former owners transferred decommissioning trust funds, along with the liability to decommission the plants, to the respective Entergy Wholesale Commodities nuclear power plant owners. In addition, the former owner of Indian Point 3 and FitzPatrick retained the decommissioning trusts and related liability to decommission these plants, but had the right to require the respective Entergy Wholesale Commodities nuclear plant owners to assume the decommissioning liability provided that it assigned the funds in the corresponding decommissioning trust, up to a specified level, to such owners. Alternatively, the former owner could have contracted with Entergy Nuclear, Inc. for the decommissioning work at a price equal to the funds in the corresponding decommissioning trust up to a specified amount. A request was made to the NRC for permission to transfer the Indian Point 3 and FitzPatrick decommissioning trusts to Entergy Nuclear Operations, Inc., which was received in January 2017. The decommissioning trusts and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants were transferred to Entergy Nuclear Operations, Inc. by the former owner in January 2017. As part of the Indian Point 1 and Indian Point 2 purchase, the Entergy Wholesale Commodities nuclear power plant owner also funded an additional $25 million to a supplemental decommissioning trust fund. As part of the Palisades transaction, the Entergy Wholesale Commodities business assumed responsibility for spent fuel at the decommissioned Big Rock Point nuclear plant, which is located near Charlevoix, Michigan. Once the spent fuel is removed from the site, the Entergy Wholesale Commodities business will dismantle the spent fuel storage facility and complete site decommissioning. Entergy is providing $5 million in credit support to provide financial assurance to the NRC for this obligation.

An early plant shutdown, poor investment results or higher than anticipated decommissioning costs could cause trust fund assets to be insufficient to meet the decommissioning obligations, with the result that the Entergy Wholesale Commodities nuclear plant owners may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. For further information regarding nuclear decommissioning costs, see the “Critical Accounting Estimates – Nuclear Decommissioning Costs” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy and Note 9 to the financial statements.

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Changes in NRC regulations or other binding regulatory requirements may cause increased funding requirements for nuclear plant decommissioning trusts.

NRC regulations require certain minimum financial assurance requirements for meeting obligations to decommission nuclear power plants. Those financial assurance requirements may change from time to time, and certain changes may result in a material increase in the financial assurance required for decommissioning the Utility operating companies’, System Energy’s, and owners of Entergy Wholesale Commodities nuclear power plants. Such changes could result in the need for additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. For further information regarding nuclear decommissioning costs, see the “Critical Accounting Estimates – Nuclear Decommissioning Costs” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy and Note 9 to the financial statements.

New or existing safety concerns regarding operating nuclear power plants and nuclear fuel could lead to restrictions upon the operation and decommissioning of Entergy’s nuclear power plants.

New and existing concerns are being expressed in public forums about the safety of nuclear generating units and nuclear fuel, in particular in the northeastern United States, which is where most of the current fleet of Entergy Wholesale Commodities nuclear power plants is located. These concerns have led to, and are expected to continue to lead to, various proposals to Federal regulators and governing bodies in some localities where Entergy’s subsidiaries own nuclear generating units for legislative and regulatory changes that could lead to the shutdown of nuclear units, denial of license renewal applications, restrictions on nuclear units as a result of unavailability of sites for spent nuclear fuel storage and disposal, or other adverse effects on owning, operating and decommissioning nuclear generating units. Entergy vigorously responds to these concerns and proposals. If any of the existing proposals, or any proposals that may arise in the future with respect to legislative and regulatory changes, become effective, they could have a material effect on Entergy’s results of operations, financial condition, and liquidity.

(Entergy Corporation)

A failure to obtain renewed licenses or other approvals required for the continued operation of the Entergy Wholesale Commodities’ Indian Point nuclear power plants could have a material effect on Entergy’s results of operations, financial condition, and liquidity and could lead to an increase in depreciation rates or an acceleration of the timing for the funding of decommissioning obligations.

The license renewal and related processes for the Entergy Wholesale Commodities’ Indian Point nuclear power plants have been and may continue to be the subject of significant public debate and regulatory and legislative review and scrutiny at the federal and, in certain cases, state level. The original expiration date of the operating license for Indian Point 2 was September 2013 and the original expiration date of the operating license for Indian Point 3 was December 2015. Because these plants filed timely license renewal applications, the NRC’s rules provide that these plants may continue to operate under their existing operating licenses until their renewal applications have been finally determined. Various parties have expressed opposition to renewal of these licenses. Renewal of the Indian Point licenses is the subject of ongoing proceedings before the Atomic Safety and Licensing Board (ASLB) of the NRC and, with respect to issues resolved by the ASLB, before the NRC on appeal.

The New York State Department of Environmental Conservation has taken the position that Indian Point 2 and Indian Point 3 must obtain a new state-issued Clean Water Act Section 401 water quality certification as part of the license renewal process. In addition, before the NRC may issue renewed operating licenses it must resolve its obligation to address the requirements of the Coastal Zone Management Act (CZMA). For further information regarding these environmental regulations see the “Regulation of Entergy’s Business - Environmental Regulation - Clean Water Act” section in Part I, Item 1. For additional discussion of the 401 and CZMA proceedings related to Indian Point license renewal, see the “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Plants” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis. In January 2017, Entergy

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announced that it plans to shut down Indian Point 2 in 2020 and Indian Point 3 in 2021. The early and orderly shutdown is part of a settlement under which New York State has agreed to drop legal challenges and support renewal of the operating licenses for Indian Point. For additional discussion of the settlement agreement with New York, see the “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Plants” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

If the NRC finally denies the applications for the renewal of operating licenses for the Indian Point nuclear power plants, or if Indian Point fails to obtain other approvals, Entergy’s results of operations, financial condition, and liquidity could be materially affected by loss of revenue and cash flow associated with the plant or plants until the proposed shutdown date, potential impairments of the carrying value of the plants, increased depreciation rates, and an accelerated need for decommissioning funds, which could require additional funding. In addition, Entergy may incur increased operating costs depending on any conditions that may be imposed in connection with license renewal. For further discussion regarding the license renewal processes for the Indian Point nuclear power plants, see the “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Plants” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

The decommissioning trust fund assets for the nuclear power plants owned by Entergy Wholesale Commodities nuclear plant owners may not be adequate to meet decommissioning obligations if one or more of their nuclear power plants is retired earlier than the anticipated shutdown date, the plants cost more to decommission than estimated, or if current regulatory requirements change, which then could require additional funding.

Under NRC regulations, Entergy Wholesale Commodities’ nuclear subsidiaries are permitted to project the NRC-required decommissioning amount, based on an NRC formula or a site-specific estimate, and the amount in each of the Entergy Wholesale Commodities nuclear power plant’s decommissioning trusts combined with other decommissioning financial assurances in place. The projections are made based on the operating license expiration date and the mid-point of the subsequent decommissioning process, or the anticipated actual completion of decommissioning if a site-specific estimate is used, for each of these nuclear power plants. As a result, if the projected amount of individual plants’ decommissioning trusts exceeds the NRC-required decommissioning amount, then its decommissioning obligations are considered to be funded in accordance with NRC regulations. If the projected costs do not sufficiently reflect the actual costs the applicable Entergy subsidiaries would be required to incur to decommission these nuclear power plants, or funding is otherwise inadequate, or if the formula, formula inputs, or site-specific estimate is changed to require increased funding, additional resources would be required. Furthermore, depending upon the level of funding available in the trust funds, the NRC may not permit the trust funds to be used to pay for related costs such as the management of spent nuclear fuel that are not included in the NRC’s formula. The NRC may also require a plan for the provision of separate funding for spent fuel management costs. In addition to NRC requirements, there are other decommissioning-related obligations for certain of the Entergy Wholesale Commodities nuclear power plants, which management believes it will be able to satisfy.

Entergy Wholesale Commodities subsidiaries have announced plans to sell the FitzPatrick nuclear power plant and shut down the Pilgrim, Palisades, Indian Point 2 and Indian Point 3 nuclear power plants earlier than the respective license expiration date of the plants (or the license expiration date assuming 20 year renewed licenses for Indian Point 2 and Indian Point 3). As discussed previously, the former owner of Indian Point 3 and FitzPatrick retained the decommissioning trusts and related liability to decommission these plants, but had the right to require the respective Entergy Wholesale Commodities nuclear plant owners to assume the decommissioning liability provided that it assigned the funds in the corresponding decommissioning trust, up to a specified level, to such owners. Alternatively, the former owner could have contracted with Entergy Nuclear, Inc. for the decommissioning work at a price equal to the funds in the corresponding decommissioning trust up to a specified amount. A request was made to the NRC for permission to transfer the Indian Point 3 and FitzPatrick decommissioning trusts to Entergy Nuclear Operations, Inc., which was received in January 2017. The decommissioning trusts and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants were transferred to Entergy Nuclear Operations, Inc. by the former owner in January 2017. As part of the Indian Point 1 and Indian Point 2 purchase, the Entergy Wholesale Commodities nuclear power plant owner also funded an additional $25 million to a supplemental decommissioning trust fund. If decommissioning of these

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plants were conducted without the full benefit of a safe storage period, or if funding is otherwise inadequate for an earlier decommissioning, the applicable Entergy subsidiary may be unable to rely upon only the decommissioning trust to fund the entire decommissioning obligation, which would require it to obtain funding from other sources.

Vermont Yankee submitted notification of permanent cessation of operations and permanent removal of fuel from the reactor in January 2015 after final shutdown in December 2014. The Post Shutdown Decommissioning Activities Report for Vermont Yankee, including a site specific cost estimate, was submitted to the NRC in December 2014. Vermont Yankee’s future certifications to satisfy the NRC’s financial assurance requirements will now be based on the site specific cost estimate, including the estimated cost of managing spent fuel, rather than the NRC minimum formula for estimating decommissioning costs. Entergy expects that amounts available in Vermont Yankee’s decommissioning trust fund, including expected earnings, together with the credit facilities entered into in January 2015 that are expected to be repaid with recoveries from DOE litigation related to spent fuel storage, will be sufficient to cover expected costs of decommissioning, spent fuel management costs, and site restoration. Future NRC filings will determine whether any other financial assurance may be required, including additional funding for spent fuel management, which will be required until the federal government takes possession of the fuel and removes it from the site, per its current obligation. In June 2015 the NRC granted an exemption allowing use of Vermont Yankee’s decommissioning trust funds for operational spent fuel management activities at that site. In August 2015, Vermont and two Vermont utilities filed a petition in the U.S. Court of Appeals for the D.C. Circuit challenging the NRC’s issuance of that exemption. In February 2016 the court dismissed the petition as premature because Vermont and the utilities had requested the NRC to reconsider a number of issues related to Vermont Yankee's use of the decommissioning trust fund including use to pay for spent fuel management expenses pursuant to the exemption granted in June 2015. In October 2016 the NRC denied Vermont's and the utilities' request for a hearing and other relief, including their challenge to the propriety of the exemption’s issuance, but directed the NRC staff to conduct an assessment of any environmental impacts associated with the exemption. In November 2016, Entergy announced that it has entered into a purchase and sale agreement with NorthStar Group Services, Inc. to sell to a NorthStar subsidiary 100% of the membership interests in Entergy Nuclear Vermont Yankee, the owner of the Vermont Yankee plant. The sale of Entergy Nuclear Vermont Yankee to NorthStar will include the transfer of Entergy Nuclear Vermont Yankee’s nuclear decommissioning trust and its obligations for spent fuel management and decommissioning and is subject to regulatory approvals and other closing conditions. See the “Entergy Wholesale Commodities Exit from the Merchant Power Business - Shutdown and Planned Sale of Vermont Yankee” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries and Note 14 to the financial statements for further information about the agreement to sell Entergy Nuclear Vermont Yankee to a subsidiary of NorthStar.

Further, federal or state regulatory changes, including mandated increases in decommissioning funding or changes in the methods or standards for decommissioning operations, may also increase the funding requirements of, or accelerate the timing for funding of, the obligations related to the decommissioning of Entergy Wholesale Commodities nuclear power plants or may restrict the decommissioning-related costs that can be paid from the decommissioning trusts. As a result, under any of these circumstances, Entergy’s results of operations, liquidity, and financial condition could be materially affected.

Entergy Wholesale Commodities nuclear power plants are exposed to price risk.

Entergy and its subsidiaries do not have a regulator-authorized rate of return on their capital investments in non-utility businesses. In particular, the sale of capacity and energy from the Entergy Wholesale Commodities nuclear power plants, unless otherwise contracted, is subject to the fluctuation of market power prices. In order to reduce future price risk to desired levels, Entergy Wholesale Commodities utilizes contracts that are unit-contingent and Firm LD and various products such as forward sales, options, and collars. As of December 31, 2016, Entergy Wholesale Commodities’ nuclear power generation plants had sold forward 87% in 2017, 56% in 2018, and 5% in 2019 of its generation portfolio’s planned energy output, reflecting the planned shutdown or sale of the Entergy Wholesale Commodities nuclear power plants by 2021.

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Market conditions such as product cost, market liquidity, and other portfolio considerations influence the product and contractual mix. The obligations under unit-contingent agreements depend on a generating asset that is operating; if the generation asset is not operating, the seller generally is not liable for damages. For some unit-contingent obligations, however, there is also a guarantee of availability that provides for the payment to the power purchaser of contract damages, if incurred, in the event the unit owner fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. Firm LD sales transactions may be exposed to substantial operational price risk, a portion of which may be capped through the use of risk management products, to the extent that the plants do not run as expected and market prices exceed contract prices.

Market prices may fluctuate substantially, sometimes over relatively short periods of time, and at other times experience sustained increases or decreases. Demand for electricity and its fuel stock can fluctuate dramatically, creating periods of substantial under- or over-supply. During periods of over-supply, prices might be depressed. Also, from time to time there may be political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, credit requirements, bidding rules and other mechanisms to address volatility and other issues in these markets.

The effects of sustained low natural gas prices and power market structure challenges have resulted in lower market prices for electricity in the power regions where the Entergy Wholesale Commodities nuclear power plants are located. In addition, currently the market design under which the plants operate does not adequately compensate merchant nuclear plants for their environmental and fuel diversity benefits in the region. These conditions were primary factors leading to Entergy’s decision to shut down (or sell) Entergy Wholesale Commodities’ nuclear power plants before the end of their operating licenses (or requested operating licenses for Indian Point 2 and Indian Point 3).

The price that different counterparties offer for various products including forward sales is influenced both by market conditions as well as the contract terms such as damage provisions, credit support requirements, and the number of available counterparties interested in contracting for the desired forward period. Depending on differences between market factors at the time of contracting versus current conditions, Entergy Wholesale Commodities’ contract portfolio may have average contract prices above or below current market prices, including at the expiration of the contracts, which may significantly affect Entergy Wholesale Commodities’ results of operations, financial condition, or liquidity. New hedges are generally layered into on a rolling forward basis, which tends to drive hedge over-performance to market in a falling price environment, and hedge underperformance to market in a rising price environment; however, hedge timing, product choice, and hedging costs will also affect these results. See the “Market and Credit Risk Sensitive Instruments” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries. Since Entergy Wholesale Commodities has announced the closure (or sale) of its nuclear plants, Entergy Wholesale Commodities may enter into fewer forward sales contracts for output from such plants.

Among the factors that could affect market prices for electricity and fuel, all of which are beyond Entergy’s control to a significant degree, are:


•	prevailing market prices for natural gas, uranium (and its conversion, enrichment, and fabrication), coal, oil, and other fuels used in electric generation plants, including associated transportation costs, and supplies of such commodities;


•	seasonality and realized weather deviations compared to normalized weather forecasts;


•	availability of competitively priced alternative energy sources and the requirements of a renewable portfolio standard;


•	changes in production and storage levels of natural gas, lignite, coal and crude oil, and refined products;


•	liquidity in the general wholesale electricity market, including the number of creditworthy counterparties available and interested in entering into forward sales agreements for Entergy’s full hedging term;


•	the actions of external parties, such as the FERC and local independent system operators and other state or Federal energy regulatory bodies, that may impose price limitations and other mechanisms to address some of the volatility in the energy markets;


•	electricity transmission, competing generation or fuel transportation constraints, inoperability, or inefficiencies;

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•	the general demand for electricity, which may be significantly affected by national and regional economic conditions;


•	weather conditions affecting demand for electricity or availability of hydroelectric power or fuel supplies;


•	the rate of growth in demand for electricity as a result of population changes, regional economic conditions, and the implementation of conservation programs or distributed generation;


•	regulatory policies of state agencies that affect the willingness of Entergy Wholesale Commodities customers to enter into long-term contracts generally, and contracts for energy in particular;


•	increases in supplies due to actions of current Entergy Wholesale Commodities competitors or new market entrants, including the development of new generation facilities, expansion of existing generation facilities, the disaggregation of vertically integrated utilities, and improvements in transmission that allow additional supply to reach Entergy Wholesale Commodities’ nuclear markets;


•	union and labor relations;


•	changes in Federal and state energy and environmental laws and regulations and other initiatives, such as the Regional Greenhouse Gas Initiative, including but not limited to, the price impacts of proposed emission controls;


•	changes in law resulting from federal or state energy legislation or legislation subjecting energy derivatives used in hedging and risk management transactions to governmental regulation; and


•	natural disasters, terrorist actions, wars, embargoes, and other catastrophic events.

The Entergy Wholesale Commodities business is subject to substantial governmental regulation and may be adversely affected by legislative, regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.

The Entergy Wholesale Commodities business is subject to extensive federal, state, and local laws and regulation. Compliance with the requirements under these various regulatory regimes may cause the Entergy Wholesale Commodities business to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines and/or civil or criminal liability.

Public utilities under the Federal Power Act are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. Each of the owners of the Entergy Wholesale Commodities nuclear power plants that generates electricity, as well as Entergy Nuclear Power Marketing, LLC, is a “public utility” under the Federal Power Act by virtue of making wholesale sales of electric energy and/or owning wholesale electric transmission facilities. The FERC has granted these generating and power marketing companies the authority to sell electricity at market-based rates. The FERC’s orders that grant the Entergy Wholesale Commodities’ generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that the Entergy Wholesale Commodities business can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, the Entergy Wholesale Commodities’ market-based sales are subject to certain market behavior rules, and if any of its generating and power marketing companies were deemed to have violated one of those rules, they would be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority and potential penalties of up to $1 million per day per violation. If the Entergy Wholesale Commodities’ generating or power marketing companies were to lose their market-based rate authority, such companies would be required to obtain the FERC’s acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have an adverse effect on the rates the Entergy Wholesale Commodities business charges for power from its facilities.

The Entergy Wholesale Commodities business is also affected by legislative and regulatory changes, as well as changes to market design, market rules, tariffs, cost allocations, and bidding rules imposed by the existing Independent System Operators. The Independent System Operators that oversee most of the wholesale power markets impose, and in the future may continue to impose, mitigation, including price limitations, offer caps and other mechanisms, to address some of the volatility and the potential exercise of market power in these markets. These types of price limitations and other regulatory mechanisms may have an adverse effect on the profitability of the Entergy Wholesale

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Commodities business’ generation facilities that sell energy and capacity into the wholesale power markets. For further information regarding federal, state and local laws and regulation applicable to the Entergy Wholesale Commodities business, see the “Regulation of Entergy’s Business” section in Part I, Item 1.

The regulatory environment applicable to the electric power industry is subject to changes as a result of restructuring initiatives at both the state and federal levels. Entergy cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on the Entergy Wholesale Commodities business. In addition, in some of these markets, interested parties have proposed material market design changes, including the elimination of a single clearing price mechanism and have raised claims that the competitive marketplace is not working because energy prices in wholesale markets exceed the marginal cost of operating nuclear power plants, as well as proposals to re-regulate the markets, impose a generation tax, or require divestitures by generating companies to reduce their market share. Other proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation process, which could require material changes to business planning models. If competitive restructuring of the electric power markets is reversed, modified, discontinued, or delayed, the Entergy Wholesale Commodities business’ results of operations, financial condition, and liquidity could be materially affected.

The power plants owned by the Entergy Wholesale Commodities business are subject to impairment charges in certain circumstances, which could have a material effect on Entergy’s results of operations, financial condition or liquidity.

Entergy reviews long-lived assets held in all of its business segments whenever events or changes in circumstances indicate that recoverability of these assets is uncertain. Generally, the determination of recoverability is based on the undiscounted net cash flows expected to result from the operations of such assets. Projected net cash flows depend on the expected operating life of the assets, the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for energy and capacity over the remaining life of the assets. In particular, the assets of the Entergy Wholesale Commodities business are subject to further impairment in connection with the closure or sale of the plants discussed below. Moreover, prior to the closure or sale of these plants, the failure of the Entergy Wholesale Commodities business to achieve forecasted operating results and cash flows, an unfavorable change in forecasted operating results or cash flows, a reduction in the expected remaining useful life of a unit (including if the operating licenses for the Indian Point power plants are not renewed by the NRC), or a decline in observable industry market multiples could all result in potential additional impairment charges for the affected assets.

On August 27, 2013, Entergy announced its plan to close and decommission Vermont Yankee. Vermont Yankee ceased power production in the fourth quarter 2014 at the end of a fuel cycle. This decision was approved by the Board in August 2013, and resulted in the recognition of impairment charges in 2013 and 2014. In October 2015, Entergy determined that it will close the Pilgrim and FitzPatrick plants. The Pilgrim plant will cease operations no later than June 1, 2019. FitzPatrick was expected to shut down at the end of its current fuel cycle, planned for January 27, 2017, but in August 2016, Entergy entered into an agreement to sell the FitzPatrick plant to Exelon Generation Company, LLC which will continue to operate the plant. During the third quarter 2015, Entergy recorded impairment and other related charges to write down the carrying values of the FitzPatrick and Pilgrim plants and related assets to their fair values. In addition, in the fourth quarter 2015, Entergy recorded impairment and other related charges to write down the carrying value of the Palisades plant and related assets to their fair value. In December 2016, Entergy reached an agreement with Consumers Energy to terminate the PPA for the Palisades plant in 2018. If the agreement receives regulatory approval, Palisades will shut down in 2018. In January 2017, Entergy announced that it reached a settlement with New York State and plans to close the Indian Point 2 plant in 2020 and the Indian Point 3 plant in 2021. As a result, in the fourth quarter of 2016, Entergy recorded impairment and other related charges to write down the carrying values of the Palisades and Indian Point 2 and Indian Point 3 plants and related assets to their fair value. In addition to the impairments and other related charges, Entergy has incurred severance and employee retention costs and expects to incur additional charges through 2021 relating to the decisions to shut down Vermont Yankee, Palisades, Pilgrim, Indian Point 2 and Indian Point 3, and the decision to sell FitzPatrick.

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If Entergy concludes that any of its nuclear power plants is unlikely to operate through its current useful life, which conclusion would be based on a variety of factors, such a conclusion could result in a further impairment of part or all of the carrying value of the plant. Any impairment charge taken by Entergy with respect to its long-lived assets, including the power plants owned by the Entergy Wholesale Commodities business, would likely be material in the quarter that the charge is taken and could otherwise have a material effect on Entergy’s results of operations, financial condition, or liquidity. For further information regarding evaluating long-lived assets for impairment, see the “Critical Accounting Estimates - Impairment of Long-lived Assets and Trust Fund Investments” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries and for further discussion of the impairment charges, see Note 14 to the financial statements.

General Business

(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)

Entergy and the Utility operating companies depend on access to the capital markets and, at times, may face potential liquidity constraints, which could make it more difficult to handle future contingencies such as natural disasters or substantial increases in gas and fuel prices. Disruptions in the capital and credit markets may adversely affect Entergy’s and its subsidiaries’ ability to meet liquidity needs, access capital and operate and grow their businesses, and the cost of capital.

Entergy’s business is capital intensive and dependent upon its ability to access capital at reasonable rates and other terms. At times there are also spikes in the price for natural gas and other commodities that increase the liquidity requirements of the Utility operating companies and Entergy Wholesale Commodities. In addition, Entergy’s and the Utility operating companies’ liquidity needs could significantly increase in the event of a hurricane or other weather-related or unforeseen disaster similar to that experienced in Entergy’s service territory with Hurricane Katrina and Hurricane Rita in 2005, Hurricane Gustav and Hurricane Ike in 2008, and Hurricane Isaac in 2012. The occurrence of one or more contingencies, including a delay in regulatory recovery of fuel or purchased power costs or storm restoration costs, higher than expected pension contributions, an acceleration of payments or decreased credit lines, less cash flow from operations than expected, or other unknown events, such as future storms, could cause the financing needs of Entergy and its subsidiaries to increase. In addition, accessing the debt capital markets more frequently in these situations may result in an increase in leverage. Material leverage increases could negatively affect the credit ratings of Entergy and the Utility operating companies, which in turn could negatively affect access to the capital markets.

The inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively affect Entergy and its subsidiaries’ ability to maintain and to expand their businesses. Events beyond Entergy’s control, such as the volatility and disruption in global capital and credit markets in 2008 and 2009, may create uncertainty that could increase its cost of capital or impair its ability to access the capital markets, including the ability to draw on its bank credit facilities. Entergy and its subsidiaries are unable to predict the degree of success they will have in renewing or replacing their credit facilities as they come up for renewal. Moreover, the size, terms, and covenants of any new credit facilities may not be comparable to, and may be more restrictive than, existing facilities. If Entergy and its subsidiaries are unable to access the credit and capital markets on terms that are reasonable, they may have to delay raising capital, issue shorter-term securities and/or bear an unfavorable cost of capital, which, in turn, could impact their ability to grow their businesses, decrease earnings, significantly reduce financial flexibility and/or limit Entergy Corporation’s ability to sustain its current common stock dividend level.

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(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

A downgrade in Entergy Corporation’s or its subsidiaries’ credit ratings could negatively affect Entergy Corporation’s and its subsidiaries’ ability to access capital and/or could require Entergy Corporation or its subsidiaries to post collateral, accelerate certain payments, or repay certain indebtedness.

There are a number of factors that rating agencies evaluate to arrive at credit ratings for each of Entergy Corporation and the Registrant Subsidiaries, including each Registrant’s regulatory framework, ability to recover costs and earn returns, diversification and financial strength and liquidity. If one or more rating agencies downgrade Entergy Corporation’s, any of the Utility operating companies’, or System Energy’s ratings, particularly below investment grade, borrowing costs would increase, the potential pool of investors and funding sources would likely decrease, and cash or letter of credit collateral demands may be triggered by the terms of a number of commodity contracts, leases, and other agreements.

Most of Entergy Corporation’s and its subsidiaries’ large customers, suppliers, and counterparties require sufficient creditworthiness to enter into transactions. If Entergy Corporation’s or its subsidiaries’ ratings decline, particularly below investment grade, or if certain counterparties believe Entergy Corporation or the Utility operating companies are losing creditworthiness and demand adequate assurance under fuel, gas, and purchased power contracts, the counterparties may require posting of collateral in cash or letters of credit, prepayment for fuel, gas or purchased power or accelerated payment, or counterparties may decline business with Entergy Corporation or its subsidiaries. At December 31, 2016, based on power prices at that time, Entergy had liquidity exposure of $128 million under the guarantees in place supporting Entergy Wholesale Commodities transactions and $8 million of posted cash collateral. In the event of a decrease in Entergy Corporation’s credit rating to below investment grade, based on power prices as of December 31, 2016, Entergy would have been required to provide approximately $57 million of additional cash or letters of credit under some of the agreements. In the event of a decrease in the credit ratings of Entergy’s Utility operating companies to below investment grade, those companies collectively could be required to provide up to $50 million of additional cash or letters of credit to MISO. As of December 31, 2016, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously received collateral from counterparties, would increase by $238 million for a $1 per MMBtu increase in gas prices in both the short- and long-term markets.

Entergy and its subsidiaries’ ability to successfully complete strategic transactions, including merger, acquisition, divestiture, joint venture, restructuring or other strategic transactions, is subject to significant risks, including the risk that required regulatory or governmental approvals may not be obtained, risks relating to unknown or undisclosed problems or liabilities, and the risk that for these or other reasons, Entergy and its subsidiaries may be unable to achieve some or all of the benefits that they anticipate from such transactions.

From time to time, Entergy and its subsidiaries have pursued and may continue to pursue strategic transactions including merger, acquisition, divestiture, joint venture, restructuring or other strategic transactions. In particular, as discussed in the “Entergy Wholesale Commodities Exit from the Merchant Power Business” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries, in August 2016, Entergy entered into an agreement to sell the FitzPatrick plant to Exelon Generation Company, LLC. Further, in November 2016, Entergy announced that it has entered into a purchase and sale agreement with NorthStar for the sale of 100% of the membership interests in Entergy Nuclear Vermont Yankee, which owns the Vermont Yankee plant. In addition, as part of Entergy’s plan to exit the merchant power business, it plans to shut down its remaining merchant nuclear power plants by 2021. These transactions are subject to regulatory approval and other material conditions or contingencies. The failure to complete these transactions or any future strategic transaction successfully or on a timely basis could have an adverse effect on Entergy’s financial condition, results of operations and the market’s perception of Entergy’s ability to execute its strategy. Further, these transactions, and any completed or future strategic transactions, involve substantial risks, including the following:

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•	the disposition of a business or asset may involve continued financial involvement in the divested business, such as through continuing equity ownership, transition service agreements, guarantees, indemnities, or other current or contingent financial obligations;

•

Entergy may encounter difficulty in finding buyers or executing alternative exit strategies on acceptable terms in a timely manner when it decides to sell an asset or a business, which could delay the accomplishment of its strategic objectives. Alternatively, Entergy may dispose of a business or asset at a price or on terms that are less than what it had anticipated, or with the exclusion of assets that must be divested or run off separately;


•	the disposition of a business could result in impairments and related write-offs of the carrying values of the relevant assets;


•	acquired businesses or assets may not produce revenues, earnings or cash flow at anticipated levels;


•	acquired businesses or assets could have environmental, permitting or other problems for which contractual protections prove inadequate;


•	Entergy and/or its subsidiaries may assume liabilities that were not disclosed to them, that exceed their estimates, or for which their rights to indemnification from the seller are limited;


•	the disposition of a business, including Entergy’s planned exit from the merchant power business, could divert management’s attention from other business concerns;


•	Entergy and/or its subsidiaries may be unable to obtain the necessary regulatory or governmental approvals to close a transaction, such approvals may be granted subject to terms that are unacceptable to them, or Entergy or its subsidiaries otherwise may be unable to achieve anticipated regulatory treatment of any such transaction or acquired business or assets; and


•	Entergy or its subsidiaries otherwise may be unable to achieve the full strategic and financial benefits that they anticipate from the transaction, or such benefits may be delayed or may not occur at all.

Entergy may not be successful in managing these or any other significant risks that it may encounter in acquiring or divesting a business, or engaging in other strategic transactions, which could have a material adverse effect on its business.

The construction of, and capital improvements to, power generation facilities involve substantial risks. Should construction or capital improvement efforts be unsuccessful, the financial condition, results of operations, or liquidity of Entergy and the Utility operating companies could be materially affected.

Entergy’s and the Utility operating companies’ ability to complete construction of power generation facilities in a timely manner and within budget is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, project management expertise and escalating costs for materials, labor, and environmental compliance. Delays in obtaining permits, shortages in materials and qualified labor, suppliers and contractors not performing as required under their contracts, changes in the scope and timing of projects, poor quality initial cost estimates from contractors, the inability to raise capital on favorable terms, changes in commodity prices affecting revenue, fuel costs, or materials costs, downward changes in the economy, changes in law or regulation, including environmental compliance requirements, and other events beyond the control of the Utility operating companies or the Entergy Wholesale Commodities business may occur that may materially affect the schedule, cost, and performance of these projects. If these projects are significantly delayed or become subject to cost overruns or cancellation, Entergy and the Utility operating companies could incur additional costs and termination payments, or face increased risk of potential write-off of the investment in the project. In addition, the Utility operating companies could be exposed to higher costs and market volatility, which could affect cash flow and cost recovery, should their respective regulators decline to approve the construction of new generation needed to meet the reliability needs of customers at the lowest reasonable cost. For further information regarding capital expenditure plans and other uses of capital in connection with the potential construction of additional generation supply sources within the Utility operating companies’ service territory, and as to the Entergy Wholesale Commodities business, see the “Capital Expenditure Plans and Other Uses of Capital” section of Management’s Financial Discussion and Analysis for Entergy and each of the Registrant Subsidiaries.

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The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business may incur substantial costs to fulfill their obligations related to environmental and other matters.

The businesses in which the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business operate are subject to extensive environmental regulation by local, state, and federal authorities. These laws and regulations affect the manner in which the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business conduct their operations and make capital expenditures. These laws and regulations also affect how the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business manage air emissions, discharges to water, wetlands impacts, solid and hazardous waste storage and disposal, cooling and service water intake, the protection of threatened and endangered species, hazardous materials transportation, and similar matters. Federal, state, and local authorities continually revise these laws and regulations, and the laws and regulations are subject to judicial interpretation and to the permitting and enforcement discretion vested in the implementing agencies. Developing and implementing plans for facility compliance with these requirements can lead to capital, personnel, and operation and maintenance expenditures. Violations of these requirements can subject the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, remediation and clean-up costs, civil penalties, and exposure to third parties’ claims for alleged health or property damages or for violations of applicable permits or standards. In addition, the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business potentially are subject to liability under these laws for the costs of remediation of environmental contamination of property now or formerly owned or operated by the Utility operating companies, System Energy, and Entergy Wholesale Commodities and of property contaminated by hazardous substances they generate. The Utility operating companies are currently involved in proceedings relating to sites where hazardous substances have been released and may be subject to additional proceedings in the future. The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business have incurred and expect to incur significant costs related to environmental compliance.

Emissions of nitrogen and sulfur oxides, mercury, particulates, greenhouse gases, and other regulated air emissions from generating plants are potentially subject to increased regulation, controls and mitigation expenses. In addition, existing air regulations and programs promulgated by the EPA often are challenged legally, sometimes resulting in large-scale changes to anticipated regulatory regimes and the resulting need to shift course, both operationally and economically, depending on the nature of the changes. Risks relating to global climate change, initiatives to compel greenhouse gas emission reductions, and water availability issues are discussed below.

Entergy and its subsidiaries may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals, or if Entergy and its subsidiaries fail to obtain, maintain, or comply with any such approval, the operation of its facilities could be stopped or become subject to additional costs. For further information regarding environmental regulation and environmental matters, see the “Regulation of Entergy’s Business – Environmental Regulation” section of Part I, Item 1.

The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business may incur substantial costs related to reliability standards.

Entergy’s business is subject to extensive and mandatory reliability standards. Such standards, which are established by the North American Electric Reliability Corporation (NERC), the SERC Reliability Corporation (SERC), and other regional enforcement entities, are approved by the FERC and frequently are reviewed, amended, and supplemented. Failure to comply with such standards could result in the imposition of fines or civil penalties, and potential exposure to third party claims for alleged violations of such standards. The standards, as well as the laws and regulations that govern them, are subject to judicial interpretation and to the enforcement discretion vested in the implementing agencies. In addition to exposure to civil penalties and fines, the Utility operating companies have incurred and expect to incur significant costs related to compliance with new and existing reliability standards, including costs associated with the Utility operating companies’ transmission system and generation assets. The changes to the

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reliability standards applicable to the electric power industry are ongoing, and Entergy cannot predict the ultimate effect that the reliability standards will have on its Utility and Entergy Wholesale Commodities.

(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)

The effects of weather and economic conditions, and the related impact on electricity and gas usage, may materially affect the Utility operating companies’ results of operations.

Temperatures above normal levels in the summer tend to increase electric cooling demand and revenues, and temperatures below normal levels in the winter tend to increase electric and gas heating demand and revenues. As a corollary, moderate temperatures in either season tend to decrease usage of energy and resulting revenues. Seasonal pricing differentials, coupled with higher consumption levels, typically cause the Utility operating companies to report higher revenues in the third quarter of the fiscal year than in the other quarters. Extreme weather conditions or storms, however, may stress the Utility operating companies’ generation facilities and transmission and distribution systems, resulting in increased maintenance and capital costs (and potential increased financing needs), limits on their ability to meet peak customer demand, increased regulatory oversight, and lower customer satisfaction. These extreme conditions could have a material effect on the Utility operating companies’ financial condition, results of operations, and liquidity.

Entergy’s electricity sales volumes are affected by a number of factors, including economic conditions, weather, customer bill sizes (large bills tend to induce conservation), trends in energy efficiency, new technologies and self generation alternatives, including the willingness and ability of large industrial customers to develop co-generation facilities that greatly reduce their demand from Entergy. Some of these factors are inherently cyclical or temporary in nature, such as the weather or economic conditions, and rarely have a long-lasting effect on Entergy’s operating results. Others, such as the increasing adoption of energy efficient appliances, new building codes, and new technologies are having a more permanent effect of reducing sales growth rates from historical norms. Distributed generation has not had a substantive impact on Entergy’s electricity sales yet, but further advances have the potential to do so in the future. Electricity sales to industrial customers, in particular, benefit from steady economic growth and favorable commodity prices and are also sensitive to changes in conditions in the markets in which its customers operate. Any negative change in any of these or other factors has the potential to result in slower sales growth or sales declines and increased bad debt expense, which could materially affect Entergy’s and the Utility operating companies’ results of operations, financial condition, and liquidity.

The effects of climate change and environmental and regulatory obligations intended to compel greenhouse gas emission reductions or to place a price on greenhouse gas emissions could materially affect the financial condition, results of operations, and liquidity of Entergy, the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business.

In an effort to address climate change concerns, federal, state, and local authorities are calling for additional laws and regulations aimed at known or suspected causes of climate change. For example, in response to the United States Supreme Court’s 2007 decision holding that the EPA has authority to regulate emissions of CO2 and other “greenhouse gases” under the Clean Air Act, the EPA, various environmental interest groups, and other organizations are focusing considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. In 2010, EPA promulgated its first regulations controlling greenhouse gas emissions from certain vehicles and from new and significantly modified stationary sources of emissions, including electric generating units. During 2012 and 2014, EPA proposed CO2 emission standards for new and existing sources; EPA finalized these standards in 2015. As examples of state action, in the Northeast, the Regional Greenhouse Gas Initiative (RGGI) establishes a cap on CO2 emissions from electric power plants and requires generators to purchase emission permits to cover their CO2 emissions, and a similar program has been developed in California. The impact that recent changes in the federal government will have on existing and pending environmental laws and regulations related to greenhouse gas emissions is currently unclear.

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Developing and implementing plans for compliance with greenhouse gas emissions reduction requirements can lead to additional capital, personnel, and operation and maintenance expenditures and could significantly affect the economic position of existing facilities and proposed projects; moreover, long-term planning to meet environmental requirements can be negatively impacted and costs may increase to the extent laws and regulations change prior to full implementation. These requirements could, in turn, lead to changes in the planning or operations of balancing authorities or organized markets in areas where the Utility operating companies, System Energy, or Entergy Wholesale Commodities do business. Violations of such requirements may subject Entergy Wholesale Commodities and the Utility operating companies to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, civil penalties, and exposure to third parties’ claims for alleged health or property damages or for violations of applicable permits or standards. To the extent Entergy believes any of these costs are recoverable in rates, however, additional material rate increases for customers could be resisted by Entergy’s regulators and, in extreme cases, Entergy’s regulators might deny or defer timely recovery of these costs. Future changes in environmental regulation governing the emission of CO2 and other greenhouse gases could make some of Entergy’s electric generating units uneconomical to maintain or operate, and could increase the difficulty that Entergy and its subsidiaries have with obtaining or maintaining required environmental regulatory approvals, which could also materially affect the financial condition, results of operations and liquidity of Entergy and its subsidiaries. In addition, lawsuits have occurred or are reasonably expected against emitters of greenhouse gases alleging that these companies are liable for personal injuries and property damage caused by climate change. These lawsuits may seek injunctive relief, monetary compensation, and punitive damages.

In addition to the regulatory and financial risks associated with climate change discussed above, potential physical risks from climate change include an increase in sea level, wind and storm surge damages, wetland and barrier island erosion, risks of flooding and changes in weather conditions, (such as increases in precipitation, drought, or changes in average temperatures), and potential increased impacts of extreme weather conditions or storms. Entergy subsidiaries own assets in, and serve, communities that are at risk from sea level rise, changes in weather conditions, storms, and loss of the protection offered by coastal wetlands. A significant portion of the nation’s oil and gas infrastructure is located in these areas and susceptible to storm damage that could be aggravated by wetland and barrier island erosion, which could give rise to fuel supply interruptions and price spikes. Entergy and its subsidiaries also face the risk that climate change could impact the availability and quality of water supply necessary for operations.

These and other physical changes could result in changes in customer demand, increased costs associated with repairing and maintaining generation facilities and transmission and distribution systems resulting in increased maintenance and capital costs (and potential increased financing needs), limits on the Entergy System’s ability to meet peak customer demand, increased regulatory oversight, and lower customer satisfaction. Also, to the extent that climate change adversely impacts the economic health of a region or results in energy conservation or demand side management programs, it may adversely impact customer demand and revenues. Such physical or operational risks could have a material effect on Entergy’s, Entergy Wholesale Commodities’, System Energy’s, and the Utility operating companies’ financial condition, results of operations, and liquidity.

Continued and future availability and quality of water for cooling, process, and sanitary uses could materially affect the financial condition, results of operations, and liquidity of the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business.

Water is a vital natural resource that is also critical to the Utility operating companies’, System Energy’s, and Entergy Wholesale Commodities’ business operations. Entergy’s facilities use water for cooling, boiler make-up, sanitary uses, potable supply, and many other uses. Two of Entergy’s Utility operating companies own and/or operate hydroelectric facilities. Accordingly, water availability and quality are critical to Entergy’s business operations. Impacts to water availability or quality could negatively impact both operations and revenues.

Entergy secures water through various mechanisms (ground water wells, surface waters intakes, municipal supply, etc.) and operates under the provisions and conditions set forth by the provider and/or regulatory authorities. Entergy also obtains and operates in substantial compliance with water discharge permits issued under

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various provisions of the Clean Water Act and/or state water pollution control provisions. Regulations and authorizations for both water intake and use and for waste discharge can become more stringent in times of water shortages, low flows in rivers, low lake levels, low groundwater aquifer volumes, and similar conditions. The increased use of water by industry, agriculture, and the population at large, population growth, and the potential impacts of climate change on water resources may cause water use restrictions that affect Entergy and its subsidiaries.

Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices, which could materially affect Entergy’s and its subsidiaries’ results of operations, financial condition, and liquidity.

To manage near-term financial exposure related to commodity price fluctuations, Entergy and its subsidiaries, including the Utility operating companies and the Entergy Wholesale Commodities business, may enter into contracts to hedge portions of their purchase and sale commitments, fuel requirements, and inventories of natural gas, uranium and its conversion and enrichment, coal, refined products, and other commodities, within established risk management guidelines. As part of this strategy, Entergy and its subsidiaries may utilize fixed- and variable-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. However, Entergy and its subsidiaries normally cover only a portion of the exposure of their assets and positions to market price volatility, and the coverage will vary over time. In addition, Entergy also elects to leave certain volumes during certain years unhedged. To the extent Entergy and its subsidiaries have unhedged positions, fluctuating commodity prices can materially affect Entergy’s and its subsidiaries’ results of operations and financial position.

Although Entergy and its subsidiaries devote a considerable effort to these risk management strategies, they cannot eliminate all the risks associated with these activities. As a result of these and other factors, Entergy and its subsidiaries cannot predict with precision the impact that risk management decisions may have on their business, results of operations, or financial position.

Entergy has guaranteed or indemnified the performance of a portion of the obligations relating to hedging and risk management activities. Reductions in Entergy’s or its subsidiaries’ credit quality or changes in the market prices of energy commodities could increase the cash or letter of credit collateral required to be posted in connection with hedging and risk management activities, which could materially affect Entergy’s or its subsidiaries’ liquidity and financial position.

The Utility operating companies and the Entergy Wholesale Commodities business are exposed to the risk that counterparties may not meet their obligations, which may materially affect the Utility operating companies and Entergy Wholesale Commodities.

The hedging and risk management practices of the Utility operating companies and the Entergy Wholesale Commodities business are exposed to the risk that counterparties that owe Entergy and its subsidiaries money, energy, or other commodities will not perform their obligations. Currently, some hedging agreements contain provisions that require the counterparties to provide credit support to secure all or part of their obligations to Entergy or its subsidiaries. If the counterparties to these arrangements fail to perform, Entergy or its subsidiaries may enforce and recover the proceeds from the credit support provided and acquire alternative hedging arrangements, which credit support may not always be adequate to cover the related obligations. In such event, Entergy and its subsidiaries might incur losses in addition to amounts, if any, already paid to the counterparties. In addition, the credit commitments of Entergy’s lenders under its bank facilities may not be honored for a variety of reasons, including unexpected periods of financial distress affecting such lenders, which could materially affect the adequacy of its liquidity sources.

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The Wall Street Transparency and Accountability Act of 2010 and rules and regulations promulgated under the act may adversely affect the ability of the Utility operating companies and the Entergy Wholesale Commodities business to utilize certain commodity derivatives for hedging and mitigating commercial risk.

The Wall Street Transparency and Accountability Act of 2010, which was enacted on July 21, 2010 as part of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Act), and the rules and regulations promulgated under the act impose governmental regulation on the over-the-counter derivative market, including the commodity swaps used by the Utility operating companies and the Entergy Wholesale Commodities business to hedge and mitigate commercial risk. Under the Act, certain swaps are subject to mandatory clearing and exchange trading requirements. Swap dealers and major market participants in the swap market are subject to capital, margin, registration, reporting, recordkeeping, and business conduct requirements with respect to their swap activities. Entergy is not a swap dealer or a major swap participant, and does not expect to qualify as either in the future. Non-swap dealers and non-major swap participants, such as Entergy, are subject to reporting, recordkeeping, and business conduct requirements (i.e., anti-manipulation, anti-disruptive trading practices, and whistleblower provisions) with respect to their swap activities. Position limits may also apply to certain swaps activities. Position limit rules promulgated by the Commodity Futures Trading Commission were vacated by the US District Court for the District of Columbia. The Commodity Futures Trading Commission has subsequently proposed new position limit rules. If the Commodity Futures Trading Commission’s issues final position limit rules, those rules may apply to certain of Entergy’s swaps activities.

The Act required the applicable regulators, which in the case of commodity swaps will be the Commodity Futures Trading Commission, to engage in substantial rulemaking in order to implement the provisions of the Act and such rulemaking has been largely completed. Both the Utility operating companies and the Entergy Wholesale Commodities business currently utilize commodity swaps to hedge and mitigate commodity price risk. It is not known whether the Act and regulations promulgated under the Act will have an adverse effect upon the market for the commodity swaps used by the Utility operating companies and the Entergy Wholesale Commodities business. However, to the extent that the Act and regulations promulgated under the Act have the effect of increasing the price of such commodity swaps or limiting or reducing the availability of such commodity swaps, whether through the imposition of additional capital, margin, or compliance costs upon market participants, the imposition of position limits, or otherwise, the financial performance of the Utility operating companies and/or the Entergy Wholesale Commodities business may be adversely affected. To the extent that the Utility operating companies and the Entergy Wholesale Commodities business may be required to post margin in connection with existing or future commodity swaps in addition to any margin currently posted by such entities, such entities may need to secure additional sources of capital to meet such liquidity needs or cease utilizing such commodity swaps.

Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding and result in increased benefit plan costs.

The performance of the capital markets affects the values of the assets held in trust under Entergy’s pension and postretirement benefit plans. A decline in the market value of the assets may increase the funding requirements relating to Entergy’s benefit plan liabilities and also result in higher benefit costs. As the value of the assets decreases, the “expected return on assets” component of benefit costs decreases, resulting in higher benefits costs. Additionally, asset losses are incorporated into benefit costs over time, thus increasing benefits costs. Volatility in the capital markets has affected the market value of these assets, which may affect Entergy’s planned levels of contributions in the future. Additionally, changes in interest rates affect the liabilities under Entergy’s pension and postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding and recognition of higher liability carrying costs. The funding requirements of the obligations related to the pension benefit plans can also increase as a result of changes in, among other factors, retirement rates, life expectancy assumptions, or Federal regulations. For further information regarding Entergy’s pension and other postretirement benefit plans, refer to the “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” section of Management’s Financial Discussion and Analysis for Entergy and each of its Registrant Subsidiaries and Note 11 to the financial statements.

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The litigation environment in the states in which certain Entergy subsidiaries operate poses a significant risk to those businesses.

Entergy and its subsidiaries are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, asbestos, hazardous material and ratepayer matters, and injuries and damages issues, among other matters. The states in which the Utility operating companies operate, in particular Louisiana, Mississippi, and Texas, have proven to be unusually litigious environments. Judges and juries in these states have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. Entergy and its subsidiaries use legal and appropriate means to contest litigation threatened or filed against them, but the litigation environment in these states poses a significant business risk.

Domestic or international terrorist attacks, including cyber attacks, and failures or breaches of Entergy’s and its subsidiaries’ technology systems may adversely affect Entergy’s results of operations.

As power generators and distributors, Entergy and its subsidiaries face heightened risk of an act or threat of terrorism, including physical and cyber attacks, either as a direct act against one of Entergy’s generation facilities, transmission operations centers, or distribution infrastructure used to manage and transport power to customers. An actual act could affect Entergy’s ability to operate, including its ability to operate the information technology systems and network infrastructure on which it relies to conduct its business. The Utility operating companies also face heightened risk of an act or threat by cyber criminals, intent on accessing personal information for the purpose of committing identity theft.

Entergy and its subsidiaries operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure in accordance with prescriptive standards. Despite the implementation of multiple layers of security by Entergy and its subsidiaries, technology systems remain vulnerable to potential threats that could lead to unauthorized access or loss of availability to critical systems essential to the reliable operation of Entergy’s electric system. If Entergy’s or its subsidiaries’ technology systems were compromised and unable to recover timely to a normal state of operations, Entergy or its subsidiaries may be unable to perform critical business functions that are essential to the company’s well-being and the health, safety, and security needs of its customers. In addition, an attack on its information technology infrastructure may result in a loss of its confidential, sensitive, and proprietary information, including personal information of its customers, employees, vendors, and others in Entergy’s care.

If any such attacks, failures or breaches were to occur, Entergy’s and the Utility operating companies’ business, financial condition, and results of operations could be materially and adversely affected. The risk of such attacks, failures, or breaches may cause Entergy and the Utility operating companies to incur increased capital and operating costs to implement increased security for its nuclear power plants and other facilities, such as additional physical facility security and additional security personnel, and for systems to protect its information technology and network infrastructure systems. Such events may also expose Entergy to an increased risk of judgments and fines.

Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s, the Utility operating companies’, and System Energy’s results of operations, financial condition and liquidity.

Entergy and its subsidiaries make judgments regarding the potential tax effects of various transactions and results of operations to estimate their obligations to taxing authorities. These tax obligations include income, franchise, real estate, sales and use, and employment-related taxes. These judgments include provisions for potential adverse outcomes regarding tax positions that have been taken. Entergy and its subsidiaries also estimate their ability to utilize tax benefits, including those in the form of carryforwards for which the benefits have already been reflected in the financial statements. Changes in federal, state, or local tax laws, adverse tax audit results or adverse tax rulings on positions taken by Entergy and its subsidiaries could negatively affect Entergy’s, the Utility operating companies’, and System Energy’s results of operations, financial condition, and liquidity.

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The Trump administration has included as part of its agenda a potential reform of U.S. tax laws, and House Republicans plan to advance their tax reform “blueprint.” Tax reform proposals call for, among other items, a reduction in the corporate federal income tax rate from the current 35% to as low as 15%, the immediate deduction of capital investment expenditures, and full or partial elimination of debt interest expense deductions. Further, for the Utility operating companies, regulators may impose rate reductions to provide the benefit of any income tax expense reductions to customers and refund “excess” deferred income taxes. For these reasons, Entergy, the Utility operating companies, and System Energy cannot predict the effect any potential changes may have on their future results of operations, cash flows, or financial position, and such changes could be significant.

For further information regarding Entergy’s income taxes, see Note 3 to the financial statements.

(Entergy New Orleans)

The effect of higher purchased gas cost charges to customers may adversely affect Entergy New Orleans’s results of operations and liquidity.

Gas rates charged to retail gas customers are comprised primarily of purchased gas cost charges, which provide no return or profit to Entergy New Orleans, and distribution charges, which provide a return or profit to the utility. Distribution charges are affected by the amount of gas sold to customers. Purchased gas cost charges, which comprise most of a customer’s bill and may be adjusted monthly, represent gas commodity costs that Entergy New Orleans recovers from its customers. Entergy New Orleans’s cash flows can be affected by differences between the time period when gas is purchased and the time when ultimate recovery from customers occurs. When purchased gas cost charges increase substantially reflecting higher gas procurement costs incurred by Entergy New Orleans, customer usage may decrease, especially in weaker economic times, resulting in lower distribution charges for Entergy New Orleans, which could adversely affect results of operations.

(System Energy)

System Energy owns and operates a single nuclear generating facility, and it is dependent on affiliated companies for all of its revenues.

System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf. Charges under the Unit Power Sales Agreement are paid by the Utility operating companies as consideration for their respective entitlements to receive capacity and energy. The useful economic life of Grand Gulf is finite and is limited by the terms of its operating license, which expires in November 2044. System Energy’s financial condition depends both on the receipt of payments from the Utility operating companies under the Unit Power Sales Agreement and on the continued commercial operation of Grand Gulf.

For information regarding the Unit Power Sales Agreement, the sale and leaseback transactions and certain other agreements relating to the Entergy System companies’ support of System Energy (including the Capital Funds Agreement), see Notes 8 and 10 to the financial statements and the “Utility - System Energy and Related Agreements” section of Part I, Item 1.

(Entergy Corporation)

As a holding company, Entergy Corporation depends on cash distributions from its subsidiaries to meet its debt service and other financial obligations and to pay dividends on its common stock.

Entergy Corporation is a holding company with no material revenue generating operations of its own or material assets other than the stock of its subsidiaries. Accordingly, all of its operations are conducted by its subsidiaries. Entergy Corporation’s ability to satisfy its financial obligations, including the payment of interest and principal on its outstanding debt, and to pay dividends on its common stock depends on the payment to it of dividends

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or distributions by its subsidiaries. The payments of dividends or distributions to Entergy Corporation by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings, and on any applicable legal, regulatory, or contractual limitations on subsidiaries’ ability to pay such dividends or distributions. Provisions in the articles of incorporation of certain of Entergy Corporation’s subsidiaries restrict the payment of cash dividends to Entergy Corporation. For further information regarding dividend or distribution restrictions to Entergy Corporation, see Note 7 to the financial statements.

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MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Net Income

2016 Compared to 2015

Net income increased $92.9 million primarily due to higher net revenue and lower other operation and maintenance expenses, partially offset by a higher effective income tax rate and higher depreciation and amortization expenses.

2015 Compared to 2014

Net income decreased $47.1 million primarily due to higher other operation and maintenance expenses, partially offset by higher net revenue.

Net Revenue

2016 Compared to 2015

Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 2016 to 2015.



	Amount
	(In Millions)

2015 net revenue		$1,362.2
Retail electric price	161.5
Other	(3.2		)
2016 net revenue		$1,520.5

The retail electric price variance is primarily due to an increase in base rates, as approved by the APSC. The new base rates were effective February 24, 2016 and began billing with the first billing cycle of April 2016. The increase includes an interim base rate adjustment surcharge, effective with the first billing cycle of April 2016, to recover the incremental revenue requirement for the period February 24, 2016 through March 31, 2016. A significant portion of the increase is related to the purchase of Power Block 2 of the Union Power Station. See Note 2 to the financial statements for further discussion of the rate case. See Note 14 to the financial statements for further discussion of the Union Power Station purchase.

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Management’s Financial Discussion and Analysis

2015 Compared to 2014

Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory credits. Following is an analysis of the change in net revenue comparing 2015 to 2014.



	Amount
	(In Millions)

2014 net revenue		$1,335.9
Volume/weather	12.7
Retail electric price	9.4
Asset retirement obligation	4.2
Net wholesale revenue	(7.8		)
Other	7.8
2015 net revenue		$1,362.2

The volume/weather variance is primarily due to an increase of 110 GWh, or 1%, in billed electricity usage, including the effect of more favorable weather on residential and commercial sales and an increase in industrial usage. The increase in industrial usage is primarily due to increased demand by existing customers primarily in the petroleum refining and primary metals industries.

The retail electric price variance is primarily due to an increase in the energy efficiency rider, as approved by the APSC, effective July 2014 and July 2015.

The asset retirement obligation affects net revenue because Entergy Arkansas records a regulatory charge or credit for the difference between asset retirement obligation-related expenses and trust earnings plus asset retirement obligation related costs collected in revenue. The variance is primarily caused by an increase in regulatory credits because of an increase in accretion expense.

The net wholesale revenue variance is primarily due to lower prices.

Other Income Statement Variances

2016 Compared to 2015

Nuclear refueling outage expenses increased primarily due to the amortization of higher costs associated with the most recent outages as compared to the previous outages.

Other operation and maintenance expenses decreased primarily due to:

•

a decrease of $21.6 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs;

•

the deferral of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance, as approved by the APSC as part of the 2015 rate case settlement. These costs are being amortized over a ten-year period beginning March 2016. See Note 2 to the financial statements for further discussion of the rate case settlement; and

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•	a decrease of $7.2 million in energy efficiency costs, including the effects of true-ups to the energy efficiency filings for fixed costs to be collected from customers and incentives recognized as a result of participation in energy efficiency programs.

The decrease was partially offset by an increase of $24.1 million in nuclear generation expenses primarily due to an overall higher scope of work done during plant outages and higher nuclear labor costs as compared to prior year and an increase of $8.2 million in fossil-fueled generation expenses primarily due to the purchase of Power Block 2 of the Union Power Station in March 2016. See Note 14 to the financial statements for discussion of the Union Power Station purchase.

Taxes other than income taxes decreased primarily due to a decrease in local franchise taxes resulting from lower residential and commercial revenues as compared to the prior year and a decrease in payroll taxes.

Depreciation and amortization expenses increased primarily due to additions to plant in service, including Power Block 2 of the Union Power Station purchased in March 2016.

Interest expense increased primarily due to:


•	$5.1 million in estimated interest expense recorded in connection with the FERC orders issued in April 2016 in the opportunity sales proceeding. See Note 2 to the financial statements for further discussion of the opportunity sales proceeding; and


•	the net issuance of $230 million of first mortgage bonds in 2016. See Note 5 to the financial statements for details of long-term debt.

2015 Compared to 2014

Nuclear refueling outage expenses increased primarily due to the amortization of higher expenses associated with the refueling outages at ANO 1 and 2.

Other operation and maintenance expenses increased primarily due to:

•

an increase of $43.4 million in nuclear generation expenses primarily due to an increase in regulatory compliance costs. The increase in regulatory compliance costs is primarily related to additional NRC inspection activities in 2015 as a result of the NRC’s March 2015 decision to move ANO into the “multiple/repetitive degraded cornerstone column” of the NRC’s Reactor Oversight Process Action Matrix. See “ANO Damage, Outage, and NRC Reviews” below for further discussion;


•	an increase of $15.3 million in distribution expenses primarily due to vegetation maintenance and higher labor costs;


•	an increase of $12.6 million in energy efficiency costs, including the effects of true-ups to the energy efficiency filings for fixed costs to be collected from customers;

•

an increase of $8.9 million in compensation and benefits costs primarily due to an increase in net periodic pension and other postretirement benefits costs as a result of lower discount rates and changes in retirement and mortality assumptions, partially offset by a decrease in the accrual for incentive-based compensation. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs; and


•	an increase of $6.6 million in fossil-fueled generation expenses due to an overall higher scope of work in 2015 as compared to 2014.

The increase was partially offset by a decrease of $6.5 million related to incentives recognized as a result of participation in energy efficiency programs.

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Management’s Financial Discussion and Analysis

Taxes other than income taxes increased primarily due to an increase in local franchise taxes resulting from higher residential and commercial revenues in 2015 as compared to 2014, an increase in payroll taxes, and an increase in ad valorem taxes resulting from higher assessments.

Depreciation and amortization expenses increased primarily due to additions to plant in service.

Other income increased primarily due to an increase in the allowance for equity funds used during construction resulting from increased transmission spending in 2015 as compared to 2014.

Interest expense increased primarily due to the issuance of $250 million of 4.95% Series first mortgage bonds in December 2014, partially offset by an increase in the allowance for borrowed funds used during construction resulting from increased transmission spending in 2015 as compared to 2014.

Income Taxes

The effective income tax rates for 2016, 2015, and 2014 were 39.2%, 35.3%, and 40.8%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.

ANO Damage, Outage, and NRC Reviews

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effectiveness and stator issues, an assessment of the effectiveness of the site’s corrective action program, an additional design basis inspection, a safety culture assessment, and possibly other inspection activities consistent with the NRC’s Inspection Procedure. Entergy Arkansas incurred incremental costs of approximately $53 million in 2015 to prepare for the NRC inspection that began in early 2016. Excluding remediation and response costs that may result from the additional NRC inspection activities, Entergy Arkansas also incurred approximately $44 million in 2016 in support of NRC inspection activities and to implement Entergy Arkansas’s performance improvement initiatives developed in 2015. A lesser amount of incremental expense is expected to be ongoing annually after 2016, until ANO transitions out of Column 4.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2016, 2015, and 2014 were as follows:



	2016			2015			2014
	(In Thousands)
Cash and cash equivalents at beginning of period		$9,135			$218,505			$127,022

Net cash provided by (used in):
Operating activities	676,511			474,890			403,826
Investing activities	(947,995		)	(685,274		)	(600,628		)
Financing activities	282,858			1,014			288,285
Net increase (decrease) in cash and cash equivalents	11,374			(209,370		)	91,483

Cash and cash equivalents at end of period		$20,509			$9,135			$218,505

Operating Activities

Net cash flow provided by operating activities increased $201.6 million in 2016 primarily due to:

•

income tax refunds of $135.7 million in 2016 compared to income tax payments of $103.3 million in 2015. Entergy Arkansas had income tax refunds in 2016 and income tax payments in 2015 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The 2016 income tax refunds resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit whereas the income tax payments in 2015 resulted primarily from final settlement of amounts outstanding associated with the 2006-2007 IRS audit as well as adjustments associated with the settlement of the 2008-2009 IRS audit. See Note 3 to the financial statements for a discussion of the income tax audits;


•	the timing of payments to vendors; and


•	an increase in net revenue.

The increase was partially offset by a decrease due to the timing of recovery of fuel and purchased power costs.

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Net cash flow provided by operating activities increased $71.1 million in 2015 primarily due to:

•

a $68 million payment made in May 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period and a $38 million payment made in September 2014 as a result of the compliance filing pursuant to the FERC’s orders related to the bandwidth payments/receipts for the comprehensive recalculation for 2007, 2008, and 2009. In 2015, Entergy Arkansas received $89.5 million in System Agreement bandwidth remedy collections from customers related to the filings. See Note 2 to the financial statements for a discussion of the System Agreement proceedings and related recovery from customers;


•	an increase due to the timing of recovery of fuel and purchased power costs; and


•	a decrease of $50 million in storm spending in 2015.

The increase was partially offset by:

•

income tax payments of $103.3 million in 2015 compared to income tax refunds of $48.9 million in 2014. Entergy Arkansas made income tax payments in 2015 and received income tax refunds in 2014 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The income tax payments in 2015 resulted primarily from final settlement of amounts outstanding associated with the 2006-2007 IRS audit as well as adjustments associated with the settlement of the 2008-2009 IRS audit whereas the income tax refunds in 2014 resulted primarily from the utilization of Entergy Arkansas’s net operating losses by the consolidated group. See Note 3 to the financial statements for a discussion of the income tax audits;

•

an increase in nuclear generation expenses primarily due to an increase in regulatory compliance costs. The increase in regulatory compliance costs is primarily related to additional NRC inspection activities in 2015 as a result of the NRC’s March 2015 decision to move ANO into the “multiple/repetitive degraded cornerstone column” of the NRC’s Reactor Oversight Process Action Matrix. See “ANO Damage, Outage, and NRC Reviews” above; and


•	an increase of $30 million in spending on nuclear refueling outages in 2015.

Investing Activities

Net cash flow used in investing activities increased $262.7 million in 2016 primarily due to the purchase of Power Block 2 of the Union Power Station in March 2016 for approximately $237 million. See Note 14 to the financial statements for discussion of the Union Power Station purchase. The increase was partially offset by the fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and service deliveries, and the timing of cash payments during the nuclear fuel cycle.

Net cash flow used in investing activities increased $84.6 million in 2015 primarily due to:


•	an increase in transmission construction expenditures primarily due to a higher scope of non-storm related work performed in 2015;


•	an increase in nuclear construction expenditures primarily due to a higher scope of work on various nuclear projects in 2015 as compared to 2014 and compliance with NRC post-Fukushima requirements;


•	an increase in distribution construction expenditures due to a higher scope of work performed in 2015;


•	an increase in information technology capital expenditures due to various technology projects and upgrades in 2015;


•	$11.7 million in insurance proceeds received in 2015 compared to $36.6 million received in 2014 for property damages related to the generator stator incident at ANO, as discussed above; and


•	money pool activity.

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The increase was partially offset by:


•	a decrease in transmission and distribution construction expenditures primarily due to higher storm restoration spending in 2014; and


•	fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle.

Decreases in Entergy Arkansas’s receivable from the money pool are a source of cash flow, and Entergy Arkansas’s receivable from the money pool decreased by $2.2 million in 2015 compared to decreasing by $15.3 million in 2014. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.

Financing Activities

Net cash flow provided by financing activities increased $281.8 million in 2016 primarily due to:


•	the net issuance of $189.1 million of long-term debt in 2016 compared to the net retirement of $13.2 million of long-term debt in 2015;


•	a $200 million capital contribution received from Entergy Corporation in March 2016 primarily in anticipation of Entergy Arkansas’s purchase of Power Block 2 of the Union Power Station; and


•	net repayments of $11.7 million on the Entergy Arkansas nuclear fuel company variable interest entity credit facility in 2016 compared to net repayments of $36.3 million in 2015.

The increase was partially offset by the redemption of $75 million of 6.45% Series preferred stock in 2016, the redemption of $10 million of 6.08% Series preferred stock in 2016, and money pool activity.

Decreases in Entergy Arkansas’s payable to the money pool are a use of cash flow, and Entergy Arkansas’s payable to the money pool decreased by $1.5 million in 2016 compared to increasing by $52.7 million in 2015.

Net cash flow provided by financing activities decreased $287.3 million in 2015 primarily due to:


•	the issuance of $250 million of 4.95% Series first mortgage bonds in December 2014;


•	the issuance of $90 million of 9% Series L notes by the nuclear fuel company variable interest entity in July 2014;


•	net repayments of $36.3 million on the Entergy Arkansas nuclear fuel company variable interest entity credit facility in 2015 compared to net borrowings of $48 million in 2014; and


•	the issuance of $375 million of 3.7% Series first mortgage bonds in March 2014, the proceeds of which were used to pay, prior to maturities, a $250 million term loan in March 2014 and $115 million of 5.0% Series first mortgage bonds in April 2014.

The decrease was partially offset by:


•	the retirement, at maturity, of $70 million of 5.69% Series I notes by the nuclear fuel company variable interest entity in July 2014;


•	money pool activity; and


•	a decrease of $10 million in common stock dividends paid in 2015 in anticipation of the purchase of Power Block 2 of the Union Power Station.

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Increases in Entergy Arkansas’s payable to the money pool are a source of cash flow, and Entergy Arkansas’s payable to the money pool increased by $52.7 million in 2015.

See Note 5 to the financial statements for details of long-term debt.

Capital Structure

Entergy Arkansas’s capitalization is balanced between equity and debt, as shown in the following table. The decrease in the debt to capital ratio for Entergy Arkansas is primarily due to the capital contribution received from Entergy Corporation in March 2016, partially offset by the issuance of long-term debt in 2016 and the redemption of $75 million of 6.45% Series preferred stock and $10 million of 6.08% Series preferred stock, as discussed above.



	December 31, 2016	December 31, 2015
Debt to capital	55.3%	56.8%
Effect of excluding the securitization bonds	(0.4%)	(0.6%)
Debt to capital, excluding securitization bonds (a)	54.9%	56.2%
Effect of subtracting cash	(0.2%)	(0.1%)
Net debt to net capital, excluding securitization bonds (a)	54.7%	56.1%


(a)	Calculation excludes the securitization bonds, which are non-recourse to Entergy Arkansas.

Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings and long-term debt, including the currently maturing portion. Capital consists of debt, preferred stock without sinking fund, and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Arkansas uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because the securitization bonds are non-recourse to Entergy Arkansas, as more fully described in Note 5 to the financial statements. Entergy Arkansas also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because net debt indicates Entergy Arkansas’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

Entergy Arkansas seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend, or both, in appropriate amounts to maintain the targeted capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Arkansas may issue incremental debt or reduce dividends, or both, to maintain its targeted capital structure. In addition, in certain infrequent circumstances, such as large transactions that would materially alter the capital structure if financed entirely with debt and reducing dividends, Entergy Arkansas may receive equity contributions to maintain the targeted capital structure.

Uses of Capital

Entergy Arkansas requires capital resources for:


•	construction and other capital investments;


•	debt and preferred stock maturities or retirements;


•	working capital purposes, including the financing of fuel and purchased power costs; and


•	dividend and interest payments.

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Following are the amounts of Entergy Arkansas’s planned construction and other capital investments.



	2017		2018		2019
	(In Millions)
Planned construction and capital investment:
Generation		$235		$190		$240
Transmission	145		140		140
Distribution	215		210		225
Other	115		80		50
Total		$710		$620		$655

Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.



	2017		2018-2019		2020-2021		after 2021		Total
	(In Millions)
Long-term debt (a)		$233		$233		$681		$4,046		$5,193
Operating leases		$18		$30		$15		$26		$89
Purchase obligations (b)		$523		$654		$513		$4,740		$6,430


(a)	Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements.


(b)	Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Arkansas, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which are discussed in Note 8 to the financial statements.

In addition to the contractual obligations given above, Entergy Arkansas currently expects to contribute approximately $79.4 million to its qualified pension plans and approximately $525 thousand to its other postretirement health care and life insurance plans in 2017, although the 2017 required pension contributions will be known with more certainty when the January 1, 2017 valuations are completed, which is expected by April 1, 2017. See “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.

Also in addition to the contractual obligations, Entergy Arkansas has $2.5 million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Arkansas includes specific investments, such as transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including initial investment to support advanced metering; resource planning, including potential generation projects; system improvements; investments in the nuclear fleet, as discussed below in “Nuclear Matters;” and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital. Management provides more information on long-term debt and preferred stock maturities in Notes 5 and 6 to the financial statements.

As discussed above in “Capital Structure,” Entergy Arkansas routinely evaluates its ability to pay dividends to Entergy Corporation from its earnings. Provisions in Entergy Arkansas’s articles of incorporation relating to preferred

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stock restrict the amount of retained earnings available for the payment of cash dividends or other distributions on its common and preferred stock.

Sources of Capital

Entergy Arkansas’s sources to meet its capital requirements include:


•	internally generated funds;


•	cash on hand;


•	debt or preferred stock issuances; and


•	bank financing under new or existing facilities.

Entergy Arkansas may refinance, redeem, or otherwise retire debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.

All debt and common and preferred stock issuances by Entergy Arkansas require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in Entergy Arkansas’s corporate charters, bond indentures, and other agreements. Entergy Arkansas has sufficient capacity under these tests to meet its foreseeable capital needs.

Entergy Arkansas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.

See Note 4 to the financial statements for a description of the money pool.

Entergy Arkansas has a credit facility in the amount of $150 million scheduled to expire in August 2021. Entergy Arkansas also has a $20 million credit facility scheduled to expire in April 2017. The $150 million credit facility allows Entergy Arkansas to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2016, there were no cash borrowings and no letters of credit outstanding under the credit facilities. In addition, Entergy Arkansas is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations under MISO. As of December 31, 2016, a $1 million letter of credit was outstanding under Entergy Arkansas’s uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.

The Entergy Arkansas nuclear fuel company variable interest entity has a credit facility in the amount of $80 million scheduled to expire in May 2019. As of December 31, 2016, no letters of credit were outstanding under the credit facility to support commercial paper issued by the Entergy Arkansas nuclear fuel company variable interest entity. See Note 4 to the financial statements for additional discussion of the nuclear fuel company variable interest entity credit facility.

Entergy Arkansas obtained authorizations from the FERC through October 2017 for short-term borrowings not to exceed an aggregate amount of $250 million at any time outstanding and long-term borrowings by its nuclear fuel company variable interest entity. See Note 4 to the financial statements for further discussion of Entergy Arkansas’s short-term borrowing limits. The long-term securities issuances of Entergy Arkansas are limited to amounts authorized by the APSC and the Tennessee Regulatory Authority; the current authorizations extend through December 2018.

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State and Local Rate Regulation and Fuel-Cost Recovery

Retail Rates

2013 Base Rate Filing

2015 Base Rate Filing

2016 Formula Rate Plan Filing

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Entergy Arkansas’s target earned return on common equity of 9.75%. In October 2016, Entergy Arkansas filed with the APSC revised formula rate plan attachments with an updated request for a $54.4 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors, as well as three additional adjustments identified as appropriate by Entergy Arkansas. In November 2016 a hearing was held and the APSC issued an order directing the parties to brief certain issues. In December 2016 the APSC approved the settlement agreement and the $54.4 million revenue requirement increase with approximately $25 million of the $54.4 million revenue requirement subject to possible future adjustment and refund to customers with interest. The APSC requested supplemental information for some of Entergy Arkansas’s requested nuclear expenditures. The APSC indicated that a procedural schedule would be set by subsequent order to obtain the additional information. In December 2016 the APSC approved Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2017.

Advanced Metering Infrastructure (AMI) Filing

Production Cost Allocation Rider

The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings. These costs cause an increase in Entergy Arkansas’s deferred fuel cost balance because Entergy Arkansas pays the costs over seven months but collects them from customers over twelve months. See Note 2 to the financial statements and Entergy Corporation and Subsidiaries “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - System Agreement” for discussions of the System Agreement proceedings.

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Energy Cost Recovery Rider

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In January 2014, Entergy Arkansas filed a motion with the APSC relating to its redetermination of its energy cost rate that was subsequently filed in March 2014. In that motion, Entergy Arkansas requested that the APSC authorize Entergy Arkansas to exclude $65.9 million of deferred fuel and purchased energy costs incurred in 2013 from the redetermination of its 2014 energy cost rate. The $65.9 million is an estimate of the incremental fuel and replacement energy costs that Entergy Arkansas incurred as a result of the ANO stator incident. Entergy Arkansas requested that the APSC authorize Entergy Arkansas to retain that amount in its deferred fuel balance, with recovery to be reviewed in a later period after more information is available regarding various claims associated with the ANO stator incident. The APSC approved Entergy Arkansas’s request in February 2014. See the “ANO Damage, Outage, and NRC Reviews” section above for further discussion of the ANO stator incident.

Opportunity Sales Proceeding

In June 2009 the LPSC filed a complaint requesting that the FERC determine that certain of Entergy Arkansas’s sales of electric energy to third parties: (a) violated the provisions of the System Agreement that allocate the energy generated by Entergy System resources, (b) imprudently denied the Entergy System and its ultimate consumers the benefits of low-cost Entergy System generating capacity, and (c) violated the provision of the System Agreement that prohibits sales to third parties by individual companies absent an offer of a right-of-first-refusal to other Utility operating companies. The LPSC’s complaint challenges sales made beginning in 2002 and requests refunds. In July 2009 the Utility operating companies filed a response to the complaint requesting that the FERC dismiss the complaint on the merits without hearing because the LPSC has failed to meet its burden of showing any violation of the System Agreement and failed to produce any evidence of imprudent action by the Entergy System. In their response, the Utility operating companies explained that the System Agreement clearly contemplates that the Utility operating companies may make sales to third parties for their own account, subject to the requirement that those sales be included in the load (or load shape) for the applicable Utility operating company. The FERC subsequently ordered a hearing in the proceeding.

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bills for 2003, 2004, and 2006, the three years with the highest volume of opportunity sales. Entergy’s proposed illustrative re-run of intra-system bills shows that the potential cost for Entergy Arkansas would be up to $12 million for the years 2003, 2004, and 2006, excluding interest, and the potential benefit would be significantly less than that for each of the other Utility operating companies. Entergy’s proposed illustrative re-run of the intra-system bills also shows an offsetting potential benefit to Entergy Arkansas for the years 2003, 2004, and 2006 resulting from the effects of the FERC’s order on System Agreement Service Schedules MSS-1, MSS-2, and MSS-3, and the potential offsetting cost would be significantly less than that for each of the other Utility operating companies. Entergy provided to the LPSC an illustrative intra-system bill recalculation as specified by the LPSC for the years 2003, 2004, and 2006, and the LPSC then filed answering testimony in December 2012. In its testimony the LPSC claims that the damages, excluding interest, that should be paid by Entergy Arkansas to the other Utility operating company’s customers for 2003, 2004, and 2006 are $42 million to Entergy Gulf States, Inc., $7 million to Entergy Louisiana, $23 million to Entergy Mississippi, and $4 million to Entergy New Orleans. The FERC staff and certain intervenors filed direct and answering testimony in February 2013. In April 2013, Entergy filed its rebuttal testimony in that proceeding, including a revised illustrative re-run of the intra-system bills for the years 2003, 2004, and 2006. The revised calculation determines the re-pricing of the opportunity sales based on consideration of moveable resources only and the removal of exchange energy received by Entergy Arkansas, which increases the potential cost for Entergy Arkansas over the three years 2003, 2004, and 2006 by $2.3 million from the potential costs identified in the Utility operating companies’ prior filings in September and October 2012. A hearing was held in May 2013 to quantify the effect of repricing the opportunity sales in accordance with the FERC’s decision.

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initial decision and Entergy submits a subsequent filing to comply with that order. Because further proceedings are required, the amount and recipients of payments by Entergy Arkansas are unknown at this time. Based on testimony previously submitted in the case, however, in the first quarter 2016 Entergy Arkansas recorded a liability of $87 million for its estimated increased costs and payment to the other Utility operating companies, including interest. This estimate is subject to change depending on how the FERC resolves the issues that are still outstanding in the case. Entergy Arkansas’s increased costs will be attributed to Entergy Arkansas’s retail and wholesale businesses, and it is not probable that Entergy Arkansas will recover the wholesale portion. Therefore Entergy Arkansas recorded a regulatory asset of approximately $75 million, which represents its estimate of the retail portion of the costs.

In May 2016, Entergy Services filed a request for rehearing of the FERC’s April 2016 order addressing the requests for rehearing filed in July 2012. Entergy Services also filed a request for clarification and/or rehearing of the FERC’s April 2016 order addressing the ALJ’s August 2013 initial decision. The APSC and the LPSC also filed requests for rehearing of the FERC’s April 2016 order. Also, in May 2016 a procedural schedule was established with a hearing in May 2017 and an initial decision expected in August 2017. Pursuant to that procedural schedule, Entergy Services re-ran intra-system bills for the ten-year period to quantify the effects of the FERC’s ruling. The LPSC submitted testimony disputing certain aspects of the calculations, and Entergy Services submitted answering testimony.

Federal Regulation

See the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.

Nuclear Matters

Entergy Arkansas owns and operates, through an affiliate, the ANO 1 and ANO 2 nuclear power plants. Entergy Arkansas is, therefore, subject to the risks related to owning and operating nuclear plants. These include risks from the use, storage, handling and disposal of high-level and low-level radioactive materials, regulatory requirement changes, including changes resulting from events at other plants, limitations on the amounts and types of insurance commercially available for losses in connection with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts. In the event of an unanticipated early shutdown of either ANO 1 or ANO 2, Entergy Arkansas may be required to file with the APSC a rate mechanism to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.

In 2016, Entergy conducted a comprehensive evaluation of the Entergy nuclear fleet and determined that it is necessary to increase investments in its nuclear plants to position the fleet to meet its operational goals. These investments will result in increased operating and capital costs associated with operating Entergy’s nuclear plants going forward. The preliminary estimates of the increase to planned capital costs for 2017 through 2019 identified through and associated with this initiative are estimated to be $290 million for Entergy Arkansas. The current estimates of the capital costs identified through this initiative are included in Entergy Arkansas’s preliminary capital investment plan estimate for 2017 through 2019 given in “Liquidity and Capital Resources - Uses of Capital” above. The increase to planned other operation and maintenance expenses identified through and associated with this initiative is preliminarily estimated to be approximately $35 million in 2017 for Entergy Arkansas, with a similar level of expenses expected to continue going forward. In addition, nuclear refueling outage expenses are expected to increase going forward.

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See “ANO Damage, Outage, and NRC Reviews” above for discussion of the NRC’s decision to move ANO into the “multiple/repetitive degraded cornerstone column” (Column 4) of the NRC’s Reactor Oversight Process Action Matrix, and the resulting significant additional NRC inspection activities at the ANO site.

Environmental Risks

Entergy Arkansas’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Arkansas is in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

The preparation of Entergy Arkansas’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy Arkansas’s financial position or results of operations.

Nuclear Decommissioning Costs

See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.

Utility Regulatory Accounting

See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.

Unbilled Revenue

See “Unbilled Revenue” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the unbilled revenue amounts.

Taxation and Uncertain Tax Positions

See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.

Qualified Pension and Other Postretirement Benefits

Entergy Arkansas’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity

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of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.

Cost Sensitivity

The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).



Actuarial Assumption	Change in Assumption	Impact on 2017 Qualified Pension Cost		Impact on 2016 Qualified Projected Benefit Obligation
		Increase/(Decrease)
Discount rate	(0.25%)		$3,184		$44,950
Rate of return on plan assets	(0.25%)		$2,724	$-
Rate of increase in compensation	0.25%		$1,323		$6,741

The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).



Actuarial Assumption	Change in Assumption	Impact on 2017 Postretirement Benefit Cost		Impact on 2016 Accumulated Postretirement Benefit Obligation
		Increase/(Decrease)
Discount rate	(0.25%)		$541		$7,812
Health care cost trend	0.25%		$892		$6,143

Each fluctuation above assumes that the other components of the calculation are held constant.

Costs and Funding

Total qualified pension cost for Entergy Arkansas in 2016 was $37.6 million. Entergy Arkansas anticipates 2017 qualified pension cost to be $37 million. In 2016, Entergy Arkansas refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $13.3 million. Entergy Arkansas contributed $83 million to its qualified pension plan in 2016 and estimates pension contributions will be approximately $79.4 million in 2017, although the 2017 required pension contributions will be known with more certainty when the January 1, 2017 valuations are completed, which is expected by April 1, 2017.

Total other postretirement health care and life insurance benefit income for Entergy Arkansas in 2016 was $5.9 million. Entergy Arkansas expects 2017 postretirement health care and life insurance benefit income of approximately $4 million. In 2016, Entergy Arkansas refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $2.5 million. Entergy Arkansas contributed $5.6 million to its other postretirement plans in 2016 and estimates 2017 contributions will be approximately $525 thousand.

The retirement and mortality rate assumptions are reviewed every three-to-five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans. The 2014 actuarial study reviewed plan experience from 2010 through 2013. As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies. These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of $106.9 million in the qualified pension benefit obligation and $16 million in the accumulated postretirement

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obligation. The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $15.4 million and other postretirement cost by approximately $2.2 million. In 2016, the mortality projection scale was updated to MP-2016, with no change in the base mortality table assumption.

Federal Healthcare Legislation

See “Qualified Pension and Other Postretirement Benefits - Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.

Other Contingencies

See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.

New Accounting Pronouncements

See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Entergy Arkansas, Inc. and Subsidiaries

Little Rock, Arkansas

We have audited the accompanying consolidated balance sheets of Entergy Arkansas, Inc. and Subsidiaries (the “Company”) as of December 31, 2016 and 2015, and the related consolidated income statements, consolidated statements of cash flows, and consolidated statements of changes in common equity (pages 321 through 326 and applicable items in pages 59 through 232) for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, and audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Arkansas, Inc. and Subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 24, 2017

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ENTERGY ARKANSAS, INC. AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENTS

	For the Years Ended December 31,
	2016			2015			2014
	(In Thousands)

OPERATING REVENUES
Electric		$2,086,608			$2,253,564			$2,172,391

OPERATING EXPENSES
Operation and Maintenance:
Fuel, fuel-related expenses, and gas purchased for resale	325,036			535,919			327,695
Purchased power	233,350			380,081			528,815
Nuclear refueling outage expenses	56,650			51,411			43,258
Other operation and maintenance	706,573			734,118			647,461
Decommissioning	53,610			50,414			46,972
Taxes other than income taxes	93,109			99,926			91,470
Depreciation and amortization	264,215			246,897			236,770
Other regulatory charges (credits) - net	7,737			(24,608		)	(20,054		)
TOTAL	1,740,280			2,074,158			1,902,387

OPERATING INCOME	346,328			179,406			270,004

OTHER INCOME
Allowance for equity funds used during construction	17,099			14,227			7,238
Interest and investment income	19,087			22,382			23,075
Miscellaneous - net	(1,446		)	(3,385		)	(5,144		)
TOTAL	34,740			33,224			25,169

INTEREST EXPENSE
Interest expense	115,311			105,622			93,921
Allowance for borrowed funds used during construction	(9,228		)	(7,805		)	(3,769		)
TOTAL	106,083			97,817			90,152

INCOME BEFORE INCOME TAXES	274,985			114,813			205,021

Income taxes	107,773			40,541			83,629

NET INCOME	167,212			74,272			121,392

Preferred dividend requirements	5,270			6,873			6,873

EARNINGS APPLICABLE TO COMMON STOCK		$161,942			$67,399			$114,519

See Notes to Financial Statements.

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ENTERGY ARKANSAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
	2016			2015			2014
	(In Thousands)
OPERATING ACTIVITIES
Net income		$167,212			$74,272			$121,392
Adjustments to reconcile net income to net cash flow provided by operating activities:
Depreciation, amortization, and decommissioning, including nuclear fuel amortization	414,933			400,156			387,945
Deferred income taxes, investment tax credits, and non-current taxes accrued	201,219			(4,330		)	130,132
Changes in assets and liabilities:
Receivables	(39,118		)	20,813			25,661
Fuel inventory	29,929			(11,791		)	(9,394		)
Accounts payable	143,645			(2,528		)	(120,097		)
Prepaid taxes and taxes accrued	37,485			(54,531		)	14,261
Interest accrued	(3,303		)	(367		)	(1,786		)
Deferred fuel costs	(105,741		)	151,332			(140,483		)
Other working capital accounts	(46,490		)	(44,784		)	72,411
Provisions for estimated losses	13,130			(137		)	(57		)
Other regulatory assets	(95,464		)	60,279			(367,234		)
Pension and other postretirement liabilities	(36,805		)	(110,936		)	252,639
Other assets and liabilities	(4,121		)	(2,558		)	38,436
Net cash flow provided by operating activities	676,511			474,890			403,826
INVESTING ACTIVITIES
Construction expenditures	(666,289		)	(624,546		)	(535,464		)
Allowance for equity funds used during construction	17,754			15,882			10,789
Nuclear fuel purchases	(102,050		)	(132,252		)	(195,092		)
Proceeds from sale of nuclear fuel	39,313			52,281			75,860
Proceeds from nuclear decommissioning trust fund sales	197,390			212,954			181,489
Investment in nuclear decommissioning trust funds	(213,093		)	(223,357		)	(190,062		)
Payment for purchase of plant	(237,323		)	—			—
Changes in money pool receivable - net	—			2,218			15,313
Changes in securitization account	64			(108		)	(261		)
Insurance proceeds	10,404			11,654			36,600
Other	5,835			—			200
Net cash flow used in investing activities	(947,995		)	(685,274		)	(600,628		)
FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	817,563			—			707,465
Retirement of long-term debt	(628,433		)	(13,234		)	(447,815		)
Capital contribution from parent	200,000			—			—
Redemption of preferred stock	(85,283		)	—			—
Change in money pool payable - net	(1,510		)	52,742			—
Changes in short-term borrowings - net	(11,690		)	(36,278		)	47,968
Dividends paid:
Common stock	—			—			(10,000		)
Preferred stock	(6,631		)	(6,873		)	(6,873		)
Other	(1,158		)	4,657			(2,460		)
Net cash flow provided by financing activities	282,858			1,014			288,285
Net increase (decrease) in cash and cash equivalents	11,374			(209,370		)	91,483
Cash and cash equivalents at beginning of period	9,135			218,505			127,022
Cash and cash equivalents at end of period		$20,509			$9,135			$218,505
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized		$112,912			$100,435			$90,285
Income taxes		($135,709	)		$103,296			($48,948	)
See Notes to Financial Statements.

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ENTERGY ARKANSAS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS

	December 31,
	2016			2015
	(In Thousands)

CURRENT ASSETS
Cash and cash equivalents:
Cash		$20,174			$9,066
Temporary cash investments	335			69
Total cash and cash equivalents	20,509			9,135
Securitization recovery trust account	4,140			4,204
Accounts receivable:
Customer	102,229			108,636
Allowance for doubtful accounts	(1,211		)	(34,226		)
Associated companies	35,286			32,987
Other	58,153			84,216
Accrued unbilled revenues	100,193			73,583
Total accounts receivable	294,650			265,196
Deferred fuel costs	96,690			—
Fuel inventory - at average cost	32,760			62,689
Materials and supplies - at average cost	182,600			169,919
Deferred nuclear refueling outage costs	81,313			67,834
Prepaid Taxes	—			30,291
Prepayments and other	14,293			15,145
TOTAL	726,955			624,413

OTHER PROPERTY AND INVESTMENTS
Decommissioning trust funds	834,735			771,313
Other	7,912			12,895
TOTAL	842,647			784,208

UTILITY PLANT
Electric	10,488,060			9,536,802
Property under capital lease	716			844
Construction work in progress	304,073			388,075
Nuclear fuel	307,352			286,341
TOTAL UTILITY PLANT	11,100,201			10,212,062
Less - accumulated depreciation and amortization	4,635,885			4,349,809
UTILITY PLANT - NET	6,464,316			5,862,253

DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Regulatory asset for income taxes - net	62,646			61,438
Other regulatory assets (includes securitization property of $41,164 as of December 31, 2016 and $54,450 as of December 31, 2015)	1,428,029			1,333,773
Deferred fuel costs	66,898			66,700
Other	14,626			14,989
TOTAL	1,572,199			1,476,900

TOTAL ASSETS		$9,606,117			$8,747,774

See Notes to Financial Statements.

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ENTERGY ARKANSAS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY

	December 31,
	2016		2015
	(In Thousands)

CURRENT LIABILITIES
Currently maturing long-term debt		$114,700		$55,000
Short-term borrowings	—		11,690
Accounts payable:
Associated companies	239,711		110,464
Other	185,153		177,758
Customer deposits	97,512		118,340
Taxes accrued	7,194		—
Interest accrued	16,580		19,883
Deferred fuel costs	—		8,853
Other	36,557		45,219
TOTAL	697,407		547,207

NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued	2,186,623		1,982,812
Accumulated deferred investment tax credits	35,305		36,506
Other regulatory liabilities	305,907		242,913
Decommissioning	924,353		872,346
Accumulated provisions	18,682		5,552
Pension and other postretirement liabilities	424,234		459,153
Long-term debt (includes securitization bonds of $48,139 as of December 31, 2016 and $61,249 as of December 31, 2015)	2,715,085		2,574,839
Other	13,854		18,438
TOTAL	6,624,043		6,192,559

Commitments and Contingencies

Preferred stock without sinking fund	31,350		116,350

COMMON EQUITY
Common stock, $0.01 par value, authorized 325,000,000 shares; issued and outstanding 46,980,196 shares in 2016 and 2015	470		470
Paid-in capital	790,243		588,493
Retained earnings	1,462,604		1,302,695
TOTAL	2,253,317		1,891,658

TOTAL LIABILITIES AND EQUITY		$9,606,117		$8,747,774

See Notes to Financial Statements.

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ENTERGY ARKANSAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY
For the Years Ended December 31, 2016, 2015, and 2014

	Common Equity
	Common Stock		Paid-in Capital		Retained Earnings			Total
	(In Thousands)

Balance at December 31, 2013		$470		$588,471		$1,130,777			$1,719,718
Net income	—		—		121,392			121,392
Common stock dividends	—		—		(10,000		)	(10,000		)
Preferred stock dividends	—		—		(6,873		)	(6,873		)
Balance at December 31, 2014		$470		$588,471		$1,235,296			$1,824,237
Net income	—		—		74,272			74,272
Preferred stock dividends	—		—		(6,873		)	(6,873		)
Other	—		22		—			22
Balance at December 31, 2015		$470		$588,493		$1,302,695			$1,891,658
Net income	—		—		167,212			167,212
Capital contributions from parent	—		200,000		—			200,000
Capital stock redemption	—		1,750		(2,033		)	(283		)
Preferred stock dividends	—		—		(5,270		)	(5,270		)
Balance at December 31, 2016		$470		$790,243		$1,462,604			$2,253,317

See Notes to Financial Statements.

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ENTERGY ARKANSAS, INC. AND SUBSIDIARIES
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON

	2016		2015		2014		2013		2012
	(In Thousands)

Operating revenues		$2,086,608		$2,253,564		$2,172,391		$2,190,159		$2,127,004
Net income		$167,212		$74,272		$121,392		$161,948		$152,365
Total assets		$9,606,117		$8,747,774		$8,777,655		$8,007,707		$7,797,123
Long-term obligations (a)		$2,746,435		$2,691,189		$2,757,423		$2,424,969		$1,887,923

(a) Includes long-term debt (excluding currently maturing debt) and preferred stock without sinking fund.

	2016		2015		2014		2013		2012
	(Dollars In Millions)

Electric Operating Revenues:
Residential		$789		$824		$755		$772		$766
Commercial	495		515		461		469		472
Industrial	446		477		424		433		439
Governmental	18		20		18		19		20
Total retail	1,748		1,836		1,658		1,693		1,697

Sales for resale:
Associated companies	49		128		131		346		320
Non-associated companies	118		195		282		83		49
Other	172		95		101		68		61
Total		$2,087		$2,254		$2,172		$2,190		$2,127

Billed Electric Energy Sales (GWh):
Residential	7,618		8,016		8,070		7,921		7,859
Commercial	5,988		6,020		5,934		5,929		6,046
Industrial	6,795		6,889		6,808		6,769		6,925
Governmental	237		235		238		241		257
Total retail	20,638		21,160		21,050		20,860		21,087

Sales for resale:
Associated companies	1,609		2,239		2,299		7,918		7,926
Non-associated companies	7,115		7,980		8,003		1,011		1,093
Total	29,362		31,379		31,352		29,789		30,106

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MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Net Income

2016 Compared to 2015

Net income increased $175.4 million primarily due to the effect of a settlement with the IRS related to the 2010-2011 IRS audit, which resulted in a $136.1 million reduction of income tax expense. Also contributing to the increase were lower other operation and maintenance expenses, higher net revenue, and higher other income. The increase was partially offset by higher depreciation and amortization expenses, higher interest expense, and higher nuclear refueling outage expenses.

2015 Compared to 2014

Net income increased slightly, by $0.6 million, primarily due to higher net revenue and a lower effective income tax rate, offset by higher other operation and maintenance expenses, higher depreciation and amortization expenses, lower other income, and higher interest expense.

Net Revenue

2016 Compared to 2015

Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges. Following is an analysis of the change in net revenue comparing 2016 to 2015.



	Amount
	(In Millions)

2015 net revenue		$2,408.8
Retail electric price	69.0
Transmission equalization	(6.5		)
Volume/weather	(6.7		)
Louisiana Act 55 financing savings obligation	(17.2		)
Other	(9.0		)
2016 net revenue		$2,438.4

The retail electric price variance is primarily due to an increase in formula rate plan revenues, implemented with the first billing cycle of March 2016, to collect the estimated first-year revenue requirement related to the purchase of Power Blocks 3 and 4 of the Union Power Station. See Note 2 to the financial statements for further discussion.

The transmission equalization variance is primarily due to changes in transmission investments, including Entergy Louisiana’s exit from the System Agreement in August 2016.

The volume/weather variance is primarily due to the effect of less favorable weather on residential sales, partially offset by an increase in industrial usage and an increase in volume during the unbilled period. The increase

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Management’s Financial Discussion and Analysis

in industrial usage is primarily due to increased demand from new customers and expansion projects, primarily in the chemicals industry.

The Louisiana Act 55 financing savings obligation variance results from a regulatory charge for tax savings to be shared with customers per an agreement approved by the LPSC. The tax savings resulted from the 2010-2011 IRS audit settlement on the treatment of the Louisiana Act 55 financing of storm costs for Hurricane Gustav and Hurricane Ike. See Note 3 to the financial statements for additional discussion of the settlement and benefit sharing.

2015 Compared to 2014



	Amount
	(In Millions)

2014 net revenue		$2,246.1
Retail electric price	180.0
Volume/weather	39.5
Waterford 3 replacement steam generator provision	(32.0		)
MISO deferral	(32.0		)
Other	7.2
2015 net revenue		$2,408.8

The retail electric price variance is primarily due to formula rate plan increases, as approved by the LPSC, effective December 2014 and January 2015. Entergy Louisiana’s formula rate plan increases are discussed in Note 2 to the financial statements.

The volume/weather variance is primarily due to an increase of 841 GWh, or 2%, in billed electricity usage, as a result of increased industrial usage primarily due to increased demand for existing large refinery customers, new customers, and expansion projects primarily in the chemicals industry, partially offset by a decrease in demand in the chemicals industry as a result of a seasonal outage for an existing customer.

The MISO deferral variance is due to the deferral in 2014 of non-fuel MISO-related charges, as approved by the LPSC. The deferral of non-fuel MISO-related charges is partially offset in other operation and maintenance expenses. See Note 2 to the financial statements for further discussion of the recovery of non-fuel MISO-related charges.

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Management’s Financial Discussion and Analysis

Other Income Statement Variances

2016 Compared to 2015

Nuclear refueling outage expenses increased primarily due to the amortization of higher expenses associated with the refueling outages at Waterford 3.

Other operation and maintenance expenses decreased primarily due to:


•	the $45 million write-off recorded in 2015 to recognize the portion of the assets associated with the Waterford 3 replacement steam generator project no longer probable of recovery. See Note 2 to the financial statements for further discussion of the prudence review proceeding; and

•

a decrease of $35 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement costs as a result of higher discount rates used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs.

The decrease was partially offset by an increase of $19.9 million in nuclear generation expenses primarily due to higher nuclear labor costs, including contract labor.

Depreciation and amortization expenses increased primarily due to additions to plant in service, including Power Blocks 3 and 4 of the Union Power Station purchased in March 2016.

Other income increased primarily due to an increase in the allowance for equity funds used during construction due to higher construction work in progress in 2016, which included the St. Charles Power Station project and increased distribution and transmission spending. The increase was also due to higher trust income in 2016 on the River Bend and Waterford 3 decommissioning trust fund investments.

Interest expense increased primarily due to:


•	the issuance in March 2016 of $425 million of 3.25% Series collateral trust mortgage bonds;


•	the issuance in March 2016 of $200 million of 4.95% Series first mortgage bonds; and


•	the issuance in October 2016 of $400 million of 2.40% Series collateral trust mortgage bonds.

The increase was partially offset by the refinancing at lower interest rates of certain first mortgage bonds. See Note 5 to the financial statements for details of long-term debt.

2015 Compared to 2014

Nuclear refueling outage expenses decreased primarily due to the amortization of lower expenses associated with the refueling outage at Waterford 3.

Other operation and maintenance expenses increased primarily due to:

•

the $45 million write-off recorded in 2015 to recognize that a portion of the assets associated with the Waterford 3 replacement steam generator project is no longer probable of recovery and the $16 million write-off recorded in 2014 due to the uncertainty at the time associated with the resolution of the Waterford 3 replacement steam generator project prudence review. See Note 2 to the financial statements for further discussion of the prudence review proceeding;

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Management’s Financial Discussion and Analysis


•	an increase of $19.9 million in nuclear generation expenses primarily due to an increased scope of work performed in 2015;

•

an increase of $14.6 million in compensation and benefits costs primarily due to an increase in net periodic pension and other postretirement benefits costs as a result of lower discount rates and changes in retirement and mortality assumptions, partially offset by a decrease in the accrual for incentive-based compensation. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs;


•	an increase of $11 million in transmission expenses primarily due to an increase in the amount of transmission costs allocated by MISO. There is no effect on net income due to the recovery of these costs through the MISO cost recovery mechanism. See Note 2 to the financial statements for further information on the recovery of these costs;


•	an increase of $9.4 million due to the amortization effective December 2014 of costs related to the transition and implementation of joining the MISO RTO; and


•	an increase resulting from losses of $1.7 million on the sale of surplus diesel inventory in 2015 compared to gains of $5.1 million on the sale of surplus oil inventory and $2.2 million on the sale of surplus diesel inventory in 2014.

The increase was partially offset by a decrease of $10.4 million related to the Entergy Louisiana and Entergy Gulf States Louisiana business combination, including the deferral recorded in 2015, as approved by the LPSC, of $15.8 million of certain external costs incurred. See Note 2 to the financial statements for a discussion of the recovery of the business combination costs.

Taxes other than income taxes increased primarily due to an increase in payroll taxes and ad valorem taxes, partially offset by lower local franchise taxes. Ad valorem taxes increased primarily due to higher assessments and higher millage rates. Local franchise taxes decreased primarily due to lower residential and commercial revenues as compared to prior year.

Depreciation and amortization expenses increased primarily due to additions to plant in service, including the Ninemile Unit 6 project, which was placed in service in December 2014.

Other income decreased primarily due to a decrease in the allowance for equity funds used during construction due to a higher construction work in progress balance in 2014, which included the Ninemile Unit 6 project and $7.6 million of carrying charges recorded in 2014 on storm restoration costs related to Hurricane Isaac as approved by the LPSC. The decrease was partially offset by an increase of $9.7 million due to income earned on preferred membership interests purchased from Entergy Holdings Company with the proceeds received in August 2014 from the Act 55 storm cost financing. See Note 2 to the financial statements for a discussion of the Act 55 storm cost financing.

Interest expense increased primarily due to:


•	the decrease in the allowance for borrowed funds used during construction due to a higher construction work in progress balance in 2014, including the Ninemile Unit 6 project, which was placed in service in December 2014;


•	the issuance of $250 million of 4.95% Series first mortgage bonds in November 2014; and


•	the issuance of two series totaling $300 million of 3.78% Series first mortgage bonds in July 2014.

The increase was partially offset by the retirement, at maturity, of $250 million of 1.875% Series first mortgage bonds in December 2014.

Income Taxes

The effective income tax rates for 2016, 2015, and 2014, were 12.6%, 28.6%, and 29.3%, respectively. The difference in the effective income tax rate of 12.6% for 2016 versus the statutory rate of 35% for 2016 was primarily

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due to the reversal of a portion of the provision for uncertain tax positions as a result of the settlement of the 2010-2011 IRS audit in the second quarter 2016 and book and tax differences related to the non-taxable income distributions earned on preferred membership interests, partially offset by state income taxes. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.

Louisiana Tax Legislation

In 2016 the Louisiana Legislature conducted special sessions which resulted in various corporate tax changes. A summary of the changes follows:


•	Restrictions were imposed on the utilization of Louisiana net operating loss carryovers. Entergy Louisiana has determined that no additional valuation allowance is necessary at this time on its Louisiana net operating loss carryovers.


•	Effective January 1, 2017, limited liability companies that elect to be taxed as corporations for federal income tax purposes and that conduct business in Louisiana will be subject to Louisiana franchise tax. Entergy currently estimates that its combined Louisiana franchise tax liability may increase in the range of $4 million to $10 million as a result of this change.


•	The Louisiana state sales tax rate was increased by 1% and certain tax exemptions were made temporarily inoperable. The combination of these two changes will likely increase Entergy Louisiana’s costs related to fuel, capital expenditures, and other operating expenses. These temporary provisions are currently scheduled to be in place through mid-2018.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2016, 2015, and 2014 were as follows:



	2016			2015			2014
	(In Thousands)
Cash and cash equivalents at beginning of period		$35,102			$320,516			$139,588

Net cash provided by (used in):
Operating activities	1,037,912			1,155,516			1,718,591
Investing activities	(1,474,065		)	(994,208		)	(1,330,041		)
Financing activities	614,901			(446,722		)	(207,622		)
Net increase (decrease) in cash and cash equivalents	178,748			(285,414		)	180,928

Cash and cash equivalents at end of period		$213,850			$35,102			$320,516

Operating Activities

Net cash flow provided by operating activities decreased $117.6 million in 2016 primarily due to:

•

an increase of $67.5 million in income tax payments in 2016. Entergy Louisiana had income tax payments of $156.6 million in 2016 and $89.1 million in 2015 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The 2016 income tax payments resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit, 2016 payments for state taxes resulting from the correlative effect of the final settlement of the 2006-2007 IRS audit, and the effect of net operating loss limitations discussed above in “Louisiana Tax Legislation.” The 2015 income tax payments

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resulted primarily from adjustments associated with the settlement of the 2008-2009 IRS Audit. See Note 3 to the financial statements for a discussion of the income tax audits;


•	an increase of $80.7 million in interest paid resulting from an increase in interest expense, including a payment of $60 million made in March 2016 related to the purchase of a beneficial interest in the Waterford 3 leased assets. See Note 10 to the financial statements for a discussion of the purchase of a beneficial interest in the Waterford 3 leased assets;


•	the timing of collections from customers and payments to vendors; and


•	a decrease due to the timing of recovery of fuel and purchased power costs in 2016.

The decrease was partially offset by proceeds of $37.8 million received in 2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed and a decrease of $30.5 million in spending on nuclear refueling outages in 2016. See Note 8 to the financial statements for a discussion of the spent nuclear fuel litigation.

Net cash flow provided by operating activities decreased $563.1 million in 2015 primarily due to:


•	proceeds of $309.5 million received in 2014 from the Louisiana Utilities Restoration Corporation as a result of the Louisiana Act 55 storm cost financing. See Note 2 to the financial statements and “Hurricane Isaac” below for a discussion of the Act 55 storm cost financing;

•

income tax payments of $89.1 million in 2015 and income tax refunds of $242.4 million in 2014. Entergy Louisiana had income tax payments in 2015 and income tax refunds in 2014 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The 2015 income tax payments were primarily due to adjustments associated with the settlement of the IRS Audit of the 2008-2009 tax years whereas the 2014 income tax refunds were primarily due to favorable adjustments allowed in the IRS Audit of the 2006-2007 tax years and a carryback of a 2008 net operating loss. See Note 3 to the financial statements for a discussion of the income tax audits; and


•	an increase of $17.1 million in spending on nuclear refueling outages in 2015.

The decrease was partially offset by increased net revenue, as discussed above.

Investing Activities

Net cash flow used in investing activities increased $479.9 million in 2016 primarily due to:


•	the purchase of Power Blocks 3 and 4 of the Union Power Station for an aggregate purchase price of approximately $475 million in March 2016. See Note 14 to the financial statements for discussion of the Union Power Station purchase;


•	an increase of $130.7 million in fossil-fueled generation construction expenditures primarily due to spending on the St. Charles Power Station project in 2016;


•	cash proceeds of $59.6 million received in 2015 from the transfer of Algiers assets to Entergy New Orleans in September 2015. See “State and Local Rate Regulation and Fuel-Cost Recovery - Retail Rates - Electric - Filings with the City Council” below for further discussion of the transfer;


•	an increase of $52 million in transmission construction expenditures due to a higher scope of work performed in 2016 as compared to the same period in 2015; and


•	an increase of $20.5 million due to various information technology projects and upgrades in 2016.

The increase was partially offset by:


•	fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and service deliveries, and the timing of cash payments during the nuclear fuel cycle;

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•	proceeds of $57.9 million received in 2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously capitalized. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and


•	a decrease of $16.9 million in nuclear construction expenditures primarily due to decreased spending on compliance with NRC post-Fukushima requirements.

Net cash flow used in investing activities decreased $335.8 million in 2015 primarily due to:


•	the investment in 2014 of $293.5 million in affiliate securities as a result of the Act 55 storm cost financing. See Note 2 to the financial statements and “Hurricane Isaac” below for a discussion of the Act 55 storm cost financing;


•	the deposit of $268.6 million into the storm reserve escrow account in 2014;


•	cash proceeds of $59.6 million from the transfer of Algiers assets to Entergy New Orleans in September 2015. See “State and Local Rate Regulation and Fuel-Cost Recovery - Retail Rates - Electric - Filings with the City Council” below for further discussion of the transfer; and


•	a decrease in fossil-fueled generation construction expenditures primarily due to decreased spending on the Ninemile Unit 6 project, which was placed in service in December 2014.

The decrease was partially offset by the following:


•	fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle;


•	an increase in nuclear expenditures primarily due to compliance with NRC post-Fukushima requirements and a higher scope of work on various nuclear projects in 2015;


•	an increase in distribution construction expenditures due to an increased scope of work performed in 2015;


•	an increase in information technology capital expenditures due to various technology projects and upgrades in 2015; and


•	money pool activity.

Increases in Entergy Louisiana’s receivable from the money pool are a use of cash flow, and Entergy Louisiana’s receivable from the money pool increased by $3.3 million in 2015 compared to decreasing by $16.8 million in 2014. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.

Financing Activities

Entergy Louisiana’s financing activities provided $614.9 million of cash in 2016 compared to using $446.7 million in 2015 primarily due to the following activity:


•	the net issuance of $961.2 million of long-term debt in 2016 compared to the net retirement of $103.4 million of long-term debt in 2015;


•	the redemption in September 2015 of $100 million of 6.95% Series and $10 million of 8.25% Series preferred membership interests in connection with the Entergy Louisiana and Entergy Gulf States Louisiana business combination;


•	net repayments of borrowings of $56.6 million on the nuclear fuel company variable interest entity’s credit facility in 2016 compared to net borrowings of $14.3 million in 2015; and


•	an increase of $59.5 million in common equity distributions in 2016. Equity distributions were lower in 2015 in anticipation of the purchase of Power Blocks 3 and 4 of the Union Power Station.

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Net cash flow used by financing activities increased $239.1 million in 2015 primarily due to:


•	the retirement of $104 million of long-term debt in 2015 compared to the net issuance of $239.4 million of long-term debt in 2014; and


•	the redemption in September 2015 of $100 million of 6.95% Series and $10 million of 8.25% Series preferred membership interests in connection with the Entergy Louisiana and Entergy Gulf States Louisiana business combination.

The increase was partially offset by a decrease of $261.5 million in common equity distributions in anticipation of the purchase of Power Blocks 3 and 4 of the Union Power Station.

See Note 5 to the financial statements for details of long-term debt.

Capital Structure

Entergy Louisiana’s capitalization is balanced between equity and debt, as shown in the following table. The increase in the debt to capital ratio for Entergy Louisiana is primarily due to the issuance of long-term debt in 2016.



	December 31, 2016		December 31, 2015
Debt to capital	53.4	%	50.8	%
Effect of excluding securitization bonds	(0.5	%)	(0.6	%)
Debt to capital, excluding securitization bonds (a)	52.9	%	50.2	%
Effect of subtracting cash	(0.9	%)	(0.2	%)
Net debt to net capital, excluding securitization bonds (a)	52.0	%	50.0	%


(a)	Calculation excludes the securitization bonds, which are non-recourse to Entergy Louisiana.

Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings and long-term debt, including the currently maturing portion. Capital consists of debt and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Louisiana uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy Louisiana’s financial condition because the securitization bonds are non-recourse to Entergy Louisiana, as more fully described in Note 5 to the financial statements. Entergy Louisiana also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Louisiana’s financial condition because net debt indicates Entergy Louisiana’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

Entergy Louisiana seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend, or both, in appropriate amounts to maintain the targeted capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Louisiana may issue incremental debt or reduce dividends, or both, to maintain its targeted capital structure. In addition, in certain infrequent circumstances, such as large transactions that would materially alter the capital structure if financed entirely with debt and reducing dividends, Entergy Louisiana may receive equity contributions to maintain the targeted capital structure.

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Uses of Capital

Entergy Louisiana requires capital resources for:


•	construction and other capital investments;


•	debt maturities or retirements;


•	working capital purposes, including the financing of fuel and purchased power costs; and


•	distribution and interest payments.

Following are the amounts of Entergy Louisiana’s planned construction and other capital investments.



	2017		2018		2019
	(In Millions)
Planned construction and capital investment:
Generation		$875		$820		$590
Transmission	410		400		375
Distribution	260		300		275
Other	175		115		70
Total		$1,720		$1,635		$1,310

Following are the amounts of Entergy Louisiana’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.



	2017		2018-2019		2020-2021		After 2021		Total
	(In Millions)
Long-term debt (a)		$475		$1,151		$980		$6,649		$9,255
Operating leases		$24		$44		$29		$23		$120
Purchase obligations (b)		$652		$1,094		$957		$5,215		$7,918


(a)	Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements.

(b)

Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Louisiana, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Vidalia purchased power agreement and the Unit Power Sales Agreement, both of which are discussed in Note 8 to the financial statements.

In addition to the contractual obligations given above, Entergy Louisiana currently expects to contribute approximately $87.7 million to its qualified pension plans and approximately $19.3 million to its other postretirement health care and life insurance plans in 2017, although the 2017 required pension contributions will be known with more certainty when the January 1, 2017 valuations are completed, which is expected by April 1, 2017. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.

Also, in addition to the contractual obligations, Entergy Louisiana has $657.2 million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Louisiana includes specific investments, such as the St. Charles Power Station and Lake Charles Power Station,

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each discussed below; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including initial investment to support advanced metering; resource planning, including potential generation projects; system improvements; investments in the nuclear fleet, as discussed below in “Nuclear Matters;” and other investments. Entergy’s Utility supply plan initiative will continue to seek to transform its generation portfolio with new or repowered generation resources. Opportunities resulting from the supply plan initiative, including new projects or the exploration of alternative financing sources, could result in increases or decreases in the capital expenditure estimates given above. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.

As an indirect, majority-owned subsidiary of Entergy Corporation, Entergy Louisiana pays distributions from its earnings at a percentage determined monthly.

St. Charles Power Station

In August 2015, Entergy Louisiana filed with the LPSC an application seeking certification that the public necessity and convenience would be served by the construction of the St. Charles Power Station, a nominal 980 megawatt combined-cycle generating unit, on land adjacent to the existing Little Gypsy plant in St. Charles Parish, Louisiana. It is currently estimated to cost $869 million to construct, including transmission interconnection and other related costs. Testimony was filed by LPSC staff and intervenors, with LPSC staff concluding that the construction of the project serves the public convenience and necessity. Three intervenors contended that Entergy Louisiana had not established that construction of the project is in the public interest, claiming that the request for proposal excluded consideration of certain resources that could be more cost effective, that the request for proposal provided undue preference to the self-build option, and that a 30-year capacity commitment was not warranted by current supply conditions. The request for proposal independent monitor also filed testimony and a report affirming that the St. Charles Power Station was selected through an objective and fair request for proposal that showed no undue preference to any proposal. An evidentiary hearing was held in April 2016, and in July 2016 an ALJ issued a final recommendation that the LPSC certify that the construction of St. Charles Power Station is in the public interest. The LPSC issued its order approving certification of St. Charles Power Station in December 2016. Construction is in progress and commercial operation is estimated to occur by mid-2019.

Lake Charles Power Station

Sources of Capital

Entergy Louisiana’s sources to meet its capital requirements include:


•	internally generated funds;


•	cash on hand;


•	debt or preferred membership issuances; and


•	bank financing under new or existing facilities.

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Entergy Louisiana may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest and distribution rates are favorable.

All debt and common and preferred membership interest issuances by Entergy Louisiana require prior regulatory approval. Preferred membership interest and debt issuances are also subject to issuance tests set forth in its bond indentures and other agreements. Entergy Louisiana has sufficient capacity under these tests to meet its foreseeable capital needs.

Entergy Louisiana’s receivables from the money pool were as follows as of December 31 for each of the following years.

See Note 4 to the financial statements for a description of the money pool.

Entergy Louisiana has a credit facility in the amount of $350 million scheduled to expire in August 2021. The credit facility allows Entergy Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2016, there were no cash borrowings and a $6.4 million letter of credit outstanding under the credit facility. In addition, Entergy Louisiana is party to an uncommitted letter of credit facility as a means to post collateral to support its obligations under MISO. As of December 31, 2016, a $5.7 million letter of credit was outstanding under Entergy Louisiana’s uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.

The Entergy Louisiana nuclear fuel company variable interest entities have two separate credit facilities, one in the amount of $105 million and one in the amount of $85 million, both scheduled to expire in May 2019. As of December 31, 2016, $3.8 million of letters of credit were outstanding under the credit facility to support a like amount of commercial paper issued by the Entergy Louisiana Waterford 3 nuclear fuel company variable interest entity and there were no cash borrowings outstanding under the credit facility for the Entergy Louisiana River Bend nuclear fuel company variable interest entity. See Note 4 to the financial statements for additional discussion of the nuclear fuel company variable interest entity credit facility.

Entergy Louisiana obtained authorizations from the FERC through October 2017 for the following:


•	short-term borrowings not to exceed an aggregate amount of $450 million at any time outstanding;


•	long-term borrowings and security issuances; and


•	long-term borrowings by its nuclear fuel company variable interest entities.

See Note 4 to the financial statements for further discussion of Entergy Louisiana’s short-term borrowing limits.

Hurricane Isaac

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Little Gypsy Repowering Project

In April 2007, Entergy Louisiana announced that it intended to pursue the solid fuel repowering of a 538 MW unit at its Little Gypsy plant. In March 2009 the LPSC voted in favor of a motion directing Entergy Louisiana to temporarily suspend the repowering project and, based upon an analysis of the project’s economic viability, to make a recommendation regarding whether to proceed with the project. This action was based upon a number of factors including the recent decline in natural gas prices, as well as environmental concerns, the unknown costs of carbon legislation and changes in the capital/financial markets. In April 2009, Entergy Louisiana complied with the LPSC’s directive and recommended that the project be suspended for an extended period of time of three years or more. In May 2009 the LPSC issued an order declaring that Entergy Louisiana’s decision to place the Little Gypsy project into a longer-term suspension of three years or more is in the public interest and prudent.

In October 2009, Entergy Louisiana made a filing with the LPSC seeking permission to cancel the Little Gypsy repowering project and seeking project cost recovery over a five-year period. In June 2010 and August 2010, the LPSC Staff and Intervenors filed testimony. The LPSC Staff (1) agreed that it was prudent to move the project from long-term suspension to cancellation and that the timing of the decision to suspend on a longer-term basis was not imprudent; (2) indicated that, except for $0.8 million in compensation-related costs, the costs incurred should be deemed prudent; (3) recommended recovery from customers over ten years but stated that the LPSC may want to consider 15 years; (4) allowed for recovery of carrying costs and earning a return on project costs, but at a reduced rate approximating the cost of debt, while also acknowledging that the LPSC may consider ordering no return; and (5) indicated that Entergy Louisiana should be directed to securitize project costs, if legally feasible and in the public interest. In the third quarter 2010, in accordance with accounting standards, Entergy Louisiana determined that it was probable that the Little Gypsy repowering project would be abandoned and accordingly reclassified $199.8 million of project costs from construction work in progress to a regulatory asset. A hearing on the issues, except for cost allocation among customer classes, was held before the ALJ in November 2010. In January 2011 all parties participated in a mediation on the disputed issues, resulting in a settlement of all disputed issues, including cost recovery and cost allocation. The settlement provides for Entergy Louisiana to recover $200 million as of March 31, 2011, and carrying costs on that amount on specified terms thereafter. The settlement also provides for Entergy Louisiana to recover the approved project costs by securitization. In April 2011, Entergy Louisiana filed an application with the LPSC to authorize the securitization of the investment recovery costs associated with the project and to issue a financing order by which Entergy Louisiana could accomplish such securitization. In August 2011 the LPSC issued an order approving the settlement and also issued a financing order for the securitization. See Note 5 to the financial statements for a discussion of the September 2011 issuance of the securitization bonds.

State and Local Rate Regulation and Fuel-Cost Recovery

The rates that Entergy Louisiana charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Louisiana is regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the LPSC, is primarily responsible for approval of the rates charged to customers.

Retail Rates - Electric

Filings with the LPSC

2013 Rate Cases

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•	authorization to increase the revenue it collects from customers by approximately $24 million;


•	an authorized return on common equity of 10.4%;


•	authorization to increase depreciation rates embedded in the proposed revenue requirement; and,

•


•	authorization to increase the revenue it collects from customers by approximately $145 million (which does not take into account a revenue offset of approximately $2 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service);


•	an authorized return on common equity of 10.4%;


•	authorization to increase depreciation rates embedded in the proposed revenue requirement; and

•

authorization to implement a three-year formula rate plan: with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the

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deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC.

2014 Formula Rate Plan Filing

In connection with the approval of the business combination of Entergy Gulf States Louisiana and Entergy Louisiana, the LPSC authorized the filing of a single, joint, formula rate plan evaluation report for Entergy Gulf States Louisiana’s and Entergy Louisiana’s 2014 calendar year operations. The joint evaluation report was filed in September 2015 and reflects an earned return on common equity of 9.09%. As such, no adjustment to base formula rate plan revenue was required. The following adjustments were required under the formula rate plan, however: a decrease in the additional capacity mechanism for Entergy Louisiana of $17.8 million; an increase in the additional capacity mechanism for Entergy Gulf States Louisiana of $4.3 million; and a reduction of $5.5 million to the MISO cost recovery mechanism, to collect approximately $35.7 million on a combined-company basis. Under the order approving the business combination, following completion of the prescribed review period, rates were implemented with the first billing cycle of December 2015, subject to refund.

2015 Formula Rate Plan Filing

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rate plan: an increase in the legacy Entergy Louisiana additional capacity mechanism of $14.2 million; a separate increase in legacy Entergy Louisiana revenue of $10 million primarily to reflect the effects of the termination of the System Agreement; an increase in the legacy Entergy Gulf States Louisiana additional capacity mechanism of $0.5 million; a decrease in legacy Entergy Gulf States Louisiana revenue of $58.7 million primarily to reflect the effects of the termination of the System Agreement; and an increase of $11 million to the MISO cost recovery mechanism. Rates were implemented with the first billing cycle of September 2016, subject to refund. Following implementation of the as-filed rates in September 2016, there have been several interim updates to Entergy Louisiana’s formula rate plan, including the most recent adjustment submitted in December 2016, reflecting implementation of the settlement of the Waterford 3 replacement steam generator project prudence review described below. Also pursuant to Entergy Louisiana’s formula rate plan rider, in November 2016, Entergy Louisiana submitted a request for LPSC authorization to extend the recovery mechanism for net revenues and expenses incurred in connection with Entergy Louisiana’s participation in MISO. The MISO cost recovery mechanism was initially approved on an interim basis to remain in place through the rate effective period of Entergy Louisiana’s test year 2015 formula rate plan filing. A procedural schedule has been established, including a hearing in July 2017.

Waterford 3 Replacement Steam Generator Project

In October 2016 the parties reached a settlement in this matter. This settlement was approved by the LPSC in December 2016. The settlement effectively provides for an agreed-upon disallowance of $67 million of plant, which had been previously written off by Entergy Louisiana, as discussed above. The settlement also requires a refund of approximately $71 million to be given through a one-time credit included in customers’ bills in January 2017. Of the $71 million of refunds, $68 million was credited to customers through Entergy Louisiana’s formula rate plan, outside of sharing, and $3 million through its fuel adjustment clause. Entergy Louisiana had previously recorded a provision of $48 million for this refund. The previously-recorded provision included the cumulative revenues through December 2016 related to the $67 million of disallowed plant. An additional regulatory charge of $23 million was recorded in fourth quarter 2016 to reflect the effects of the settlement. The settlement also provides that Entergy Louisiana can

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retain the value associated with potential service credits agreed to by the project contractor, to the extent they are realized in the future.

Ninemile 6

Union Power Station

In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC for approval of the acquisition and cost recovery of two power blocks of the Union Power Station for an expected base purchase price of approximately $237 million per power block, subject to adjustments. In September 2015, Entergy Gulf States Louisiana agreed to settlement terms with all parties for Entergy Gulf States Louisiana’s purchase of the two power blocks. In October 2015 the LPSC voted unanimously to approve the uncontested settlement which finds, among other things, that acquisition of Power Blocks 3 and 4 is in the public interest and, therefore, prudent. The business combination of Entergy Gulf States Louisiana and Entergy Louisiana received regulatory approval and closed in October 2015 making Entergy Louisiana the named purchaser of Power Blocks 3 and 4 of the Union Power Station. In March 2016, Entergy Louisiana acquired Power Blocks 3 and 4 of the Union Power Station for an aggregate purchase price of approximately $474 million and implemented rates to collect the estimated first-year revenue requirement with the first billing cycle of March 2016.

Advanced Metering Infrastructure (AMI) Filing

In November 2016, Entergy Louisiana filed an application seeking a finding from the LPSC that Entergy Louisiana’s deployment of advanced electric and gas metering infrastructure is in the public interest. Entergy Louisiana proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Louisiana’s modernized power grid. The filing identified a number of quantified and unquantified benefits,

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and Entergy Louisiana provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $607 million. Entergy Louisiana also sought to continue to include in rate base the remaining book value at December 31, 2015, approximately $92 million, of the existing electric meters and also to depreciate those assets using current depreciation rates. Entergy Louisiana proposed a 15-year useful life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Assuming LPSC approval is received in 2017, the communications network deployment is expected to begin by late-2018, after the necessary information technology infrastructure is in place. Entergy Louisiana proposed to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022.

Filings with the City Council

In March 2013, Entergy Louisiana filed a rate case for the Algiers area, which is in New Orleans and is regulated by the City Council. Entergy Louisiana requested a rate increase of $13 million over three years, including a 10.4% return on common equity and a formula rate plan mechanism identical to its LPSC request made in February 2013. In January 2014, the City Council Advisors filed direct testimony recommending a rate increase of $5.56 million over three years, including an 8.13% return on common equity. In June 2014 the City Council unanimously approved a settlement that includes the following:


•	a $9.3 million base rate revenue increase to be phased in on a levelized basis over four years;


•	recovery of an additional $853 thousand annually through a MISO recovery rider; and


•	adoption of a four-year formula rate plan requiring the filing of annual evaluation reports in May of each year, commencing May 2015, with resulting rates being implemented in October of each year. The formula rate plan includes a midpoint target authorized return on common equity of 9.95% with a +/- 40 basis point bandwidth.

The rate increase was effective with bills rendered on and after the first billing cycle of July 2014. Additional compliance filings were made with the Council in October 2014 for approval of the form of certain rate riders, including among others, a Ninemile 6 non-fuel cost recovery interim rider, allowing for contemporaneous recovery of capacity costs related to the commencement of commercial operation of the Ninemile 6 generating unit and a purchased power capacity cost recovery rider. The monthly Ninemile 6 cost recovery interim rider was implemented in December 2014 to initially collect $915 thousand from Entergy Louisiana customers in the Algiers area.

Retail Rates - Gas

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In accordance with the settlement of Entergy Gulf States Louisiana’s gas rate stabilization plan for the test year ended September 30, 2012, in August 2014, Entergy Gulf States Louisiana submitted for consideration a proposal for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by the LPSC staff and inclusion of certain customer safeguards required by the LPSC staff, in December 2014, Entergy Gulf States Louisiana and the LPSC staff submitted a joint settlement for implementation of an accelerated gas pipe replacement program providing for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a rider to recover the investment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is subject to the following conditions, among others: a ten-year term; application of any earnings in excess of 10.45% as an offset to the revenue requirement of the infrastructure rider; adherence to a specified spending plan, within plus or minus 20% annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding 10%; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015.

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Fuel and purchased power recovery

In April 2010 the LPSC authorized its staff to initiate an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through the fuel adjustment clause by Entergy Louisiana for the period from 2005 through 2009. The LPSC staff issued its audit report in January 2013. The LPSC staff recommended that Entergy Louisiana refund approximately $1.9 million, plus interest, to customers and realign the recovery of approximately $1 million from Entergy Louisiana’s fuel adjustment clause to base rates. The recommended refund was made by Entergy Louisiana in May 2013 in the form of a credit to customers through its fuel adjustment clause filing. Two parties intervened in the proceeding. A procedural schedule was established for the identification of issues by the intervenors and for Entergy Louisiana to submit comments regarding the LPSC Staff report and any issues raised by intervenors. One intervenor sought further proceedings regarding certain issues it raised in its comments on the LPSC staff report. Entergy Louisiana filed responses to both the LPSC staff report and the issues raised by the intervenor. After conducting additional discovery, in April 2016 the LPSC staff consultant issued its supplemental audit report, which concluded that Entergy Louisiana was not imprudent on the issues raised by the intervenor. The intervenor has stated that it does not intend to pursue these issues further. In October 2016 the LPSC staff filed testimony affirming the recommendation in its audit report on the lone remaining issue that nuclear dry fuel storage costs should be realigned to base rates. The parties agreed to remove that remaining issue to a separate docket because the same issue is outstanding the Entergy Gulf States Louisiana audit for the same time period. In November 2016, the LPSC approved the resolution of this audit and the creation of a new docket for the resolution of the proper method of recovery for nuclear dry fuel storage costs. In December 2016 the LPSC opened a new docket in order to resolve the issue regarding the proper methodology for the recovery of nuclear dry fuel storage costs. A procedural schedule has been established for this new docket, including an evidentiary hearing in June 2017.

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Other dockets

In March 2016 the LPSC opened two dockets to examine, on a generic basis, issues that it identified in connection with its review of Cleco Corporation’s acquisition by third party investors. The first docket is captioned “In re: Investigation of double leveraging issues for all LPSC-jurisdictional utilities,” and the second is captioned “In re: Investigation of tax structure issues for all LPSC-jurisdictional utilities.” In April 2016 the LPSC clarified that the concerns giving rise to the two dockets arose as a result of its review of the structure of the recently-approved Cleco-Macquarie transaction and that the specific intent of the directives is to seek more information regarding intra-corporate debt financing of a utility’s capital structure as well as the use of investment tax credits to mitigate the tax obligation at the parent level of a consolidated entity. No schedule has been set for either docket, but discovery has commenced.

Industrial and Commercial Customers

Entergy Louisiana’s large industrial and commercial customers continually explore ways to reduce their energy costs. In particular, cogeneration is an option available to a portion of Entergy Louisiana’s industrial customer base. Entergy Louisiana responds by working with industrial and commercial customers and negotiating electric service contracts to provide competitive rates that match specific customer needs and load profiles. Entergy Louisiana actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand, from both new and existing customers.

Federal Regulation

Nuclear Matters

Entergy Louisiana owns and, through an affiliate, operates the River Bend and Waterford 3 nuclear power plants. Entergy Louisiana is, therefore, subject to the risks related to owning and operating nuclear plants. These include risks from the use, storage, handling and disposal of high-level and low-level radioactive materials, regulatory requirement changes, including changes resulting from events at other plants, limitations on the amounts and types of insurance commercially available for losses in connection with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts. In the event of an unanticipated early shutdown of River Bend or Waterford 3, Entergy Louisiana may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. Waterford 3’s operating license is currently due to expire in December 2024. In March 2016, Entergy Louisiana filed an application with the NRC for an extension of Waterford 3’s operating license to 2044.

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expected to continue going forward. In addition, nuclear refueling outage expenses are expected to increase going forward.

Environmental Risks

Entergy Louisiana’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Louisiana is in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

The preparation of Entergy Louisiana’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy Louisiana’s financial position or results of operations.

Nuclear Decommissioning Costs

Utility Regulatory Accounting

Unbilled Revenue

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Entergy Louisiana, LLC and Subsidiaries

Management’s Financial Discussion and Analysis

Taxation and Uncertain Tax Positions

Qualified Pension and Other Postretirement Benefits

Entergy Louisiana’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.

Cost Sensitivity

The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).



Actuarial Assumption	Change in Assumption	Impact on 2017 Qualified Pension Cost	Impact on 2016 Projected Qualified Benefit Obligation
		Increase/(Decrease)
Discount rate	(0.25%)	$4,115		$53,261
Rate of return on plan assets	(0.25%)	$3,068	$-
Rate of increase in compensation	0.25%	$1,600		$9,232

The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).



Actuarial Assumption	Change in Assumption	Impact on 2017 Postretirement Benefit Cost		Impact on 2016 Accumulated postretirement Benefit Obligation
		Increase/(Decrease)
Discount rate	(0.25%)		$842		$10,567
Health care cost trend	0.25%		$1,413		$9,025

Each fluctuation above assumes that the other components of the calculation are held constant.

Costs and Funding

Total qualified pension cost for Entergy Louisiana in 2016 was $47.1 million. Entergy Louisiana anticipates 2017 qualified pension cost to be $44.3 million. In 2016, Entergy Louisiana refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $14.2 million. Entergy Louisiana contributed $84.4 million to its pension plans in 2016 and estimates pension contributions will be approximately $87.7 million in 2017, although the 2017 required pension contributions will be known with more certainty when the January 1, 2017 valuations are completed, which is expected by April 1, 2017.

Total postretirement health care and life insurance benefit costs for Entergy Louisiana in 2016 were $15.7 million. Entergy Louisiana expects 2017 postretirement health care and life insurance benefit costs of approximately

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Management’s Financial Discussion and Analysis

$12.6 million. In 2016, Entergy Louisiana refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $3.5 million. Entergy Louisiana contributed $16.6 million to its other postretirement plans in 2016 and estimates that 2017 contributions will be approximately $19.3 million.

The retirement and mortality rate assumptions are reviewed every three-to-five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans. The 2014 actuarial study reviewed plan experience from 2010 through 2013. As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies. These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of $121.6 million in the qualified pension benefit obligation and $21.5 million in the accumulated postretirement obligation. The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $18.1 million and other postretirement cost by approximately $2.8 million. In 2016, the mortality projection scale was updated to MP-2016, with no change in the base mortality table assumption.

Federal Healthcare Legislation

Other Contingencies

New Accounting Pronouncements

See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Members of

Entergy Louisiana, LLC and Subsidiaries

Jefferson, Louisiana

We have audited the accompanying consolidated balance sheets of Entergy Louisiana, LLC and Subsidiaries (the “Company”) as of December 31, 2016 and 2015 and the related consolidated income statements, and consolidated statements of comprehensive income, cash flows, and changes in equity (pages 353 through 358 and applicable items in pages 59 through 232) for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Louisiana, LLC and Subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 24, 2017

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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENTS

	For the Years Ended December 31,
	2016			2015			2014
	(In Thousands)

OPERATING REVENUES
Electric		$4,126,343			$4,361,524			$4,668,814
Natural gas	50,705			55,622			71,690
TOTAL	4,177,048			4,417,146			4,740,504

OPERATING EXPENSES
Operation and Maintenance:
Fuel, fuel-related expenses, and gas purchased for resale	804,433			850,869			1,029,793
Purchased power	890,058			1,129,910			1,508,104
Nuclear refueling outage expenses	51,361			44,480			51,790
Other operation and maintenance	923,779			997,546			907,308
Decommissioning	46,944			43,445			41,493
Taxes other than income taxes	165,665			167,966			159,594
Depreciation and amortization	451,290			437,036			408,073
Other regulatory charges (credits) - net	44,131			27,562			(43,484		)
TOTAL	3,377,661			3,698,814			4,062,671

OPERATING INCOME	799,387			718,332			677,833

OTHER INCOME
Allowance for equity funds used during construction	27,925			19,192			46,240
Interest and investment income	154,778			150,168			134,885
Miscellaneous - net	(11,597		)	(13,190		)	850
TOTAL	171,106			156,170			181,975

INTEREST EXPENSE
Interest expense	273,283			259,894			253,455
Allowance for borrowed funds used during construction	(14,571		)	(10,702		)	(24,721		)
TOTAL	258,712			249,192			228,734

INCOME BEFORE INCOME TAXES	711,781			625,310			631,074

Income taxes	89,734			178,671			185,052

NET INCOME	622,047			446,639			446,022

Preferred distribution requirements and other	—			5,737			7,796

EARNINGS APPLICABLE TO COMMON EQUITY		$622,047			$440,902			$438,226

See Notes to Financial Statements.

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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	For the Years Ended December 31,
	2016		2015		2014
	(In Thousands)

Net Income		$622,047		$446,639		$446,022

Other comprehensive income (loss)
Pension and other postretirement liabilities
(net of tax expense (benefit) of $5,034, $14,316, and ($25,984))	7,970		22,811		(41,386		)
Other comprehensive income (loss)	7,970		22,811		(41,386		)

Comprehensive Income		$630,017		$469,450		$404,636

See Notes to Financial Statements.

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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
	2016			2015			2014
	(In Thousands)
OPERATING ACTIVITIES
Net income		$622,047			$446,639			$446,022
Adjustments to reconcile net income to net cash flow provided by operating activities:
Depreciation, amortization, and decommissioning, including nuclear fuel amortization	620,211			593,635			580,742
Deferred income taxes, investment tax credits, and non-current taxes accrued	178,549			97,461			248,686
Changes in working capital:
Receivables	(102,200		)	(12,795		)	101,965
Fuel inventory	(2,693		)	(887		)	2,708
Accounts payable	(36,720		)	23,641			(28,422		)
Prepaid taxes and taxes accrued	(235,246		)	105,687			183,313
Interest accrued	1,218			2,933			3,567
Deferred fuel costs	(17,023		)	4,222			40,245
Other working capital accounts	6,462			(41,890		)	17,761
Changes in provisions for estimated losses	490			(8,946		)	274,349
Changes in other regulatory assets	57,579			130,762			(314,837		)
Changes in other regulatory liabilities	62,351			96,234			29,713
Changes in pension and other postretirement liabilities	(52,559		)	(98,695		)	299,319
Other	(64,554		)	(182,485		)	(166,540		)
Net cash flow provided by operating activities	1,037,912			1,155,516			1,718,591
INVESTING ACTIVITIES
Construction expenditures	(1,030,416		)	(845,227		)	(757,376		)
Allowance for equity funds used during construction	27,925			19,192			46,240
Insurance proceeds	10,564			—			—
Nuclear fuel purchases	(73,618		)	(244,040		)	(172,297		)
Proceeds from the sale of nuclear fuel	63,304			54,595			126,004
Payment for purchase of plant	(474,670		)	—			—
Investment in affiliates	—			—			(293,516		)
Payments to storm reserve escrow account	—			(308		)	(268,576		)
Changes in securitization account	351			(137		)	1,480
Proceeds from nuclear decommissioning trust fund sales	219,182			123,474			216,688
Investment in nuclear decommissioning trust funds	(257,209		)	(158,028		)	(245,446		)
Changes in money pool receivable - net	(16,349		)	(3,339		)	16,758
Proceeds from sale of assets	—			59,610			—
Litigation proceeds for reimbursement of spent nuclear fuel storage costs	57,934			—			—
Changes in other investments - net	(1,063		)	—			—
Net cash flow used in investing activities	(1,474,065		)	(994,208		)	(1,330,041		)
FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	2,450,063			77,172			751,565
Retirement of long-term debt	(1,488,870		)	(180,595		)	(512,180		)
Redemption of preferred membership interests	—			(110,286		)	—
Changes in credit borrowings - net	(56,562		)	14,322			28,310
Distributions paid:
Common equity	(285,500		)	(226,000		)	(487,502		)
Preferred membership interests	—			(6,082		)	(7,775		)
Other	(4,230		)	(15,253		)	19,960
Net cash flow provided by (used in) financing activities	614,901			(446,722		)	(207,622		)
Net increase (decrease) in cash and cash equivalents	178,748			(285,414		)	180,928
Cash and cash equivalents at beginning of period	35,102			320,516			139,588
Cash and cash equivalents at end of period		$213,850			$35,102			$320,516
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized		$324,456			$243,745			$241,436
Income taxes		$156,605			$89,124			($242,420	)
Non-cash financing activities:
Capital contribution from parent		$—			($267,826	)		$—
See Notes to Financial Statements.

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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS

	December 31,
	2016			2015
	(In Thousands)

CURRENT ASSETS
Cash and cash equivalents:
Cash		$49,972			$348
Temporary cash investments	163,878			34,754
Total cash and cash equivalents	213,850			35,102
Accounts receivable:
Customer	213,517			179,051
Allowance for doubtful accounts	(6,277		)	(4,209		)
Associated companies	155,794			94,418
Other	54,186			56,793
Accrued unbilled revenues	159,176			143,079
Total accounts receivable	576,396			469,132
Fuel inventory	50,738			48,045
Materials and supplies - at average cost	294,421			282,688
Deferred nuclear refueling outage costs	22,535			66,984
Prepaid taxes	110,104			—
Prepayments and other	41,687			28,294
TOTAL	1,309,731			930,245

OTHER PROPERTY AND INVESTMENTS
Investment in affiliate preferred membership interests	1,390,587			1,390,587
Decommissioning trust funds	1,140,707			1,042,293
Storm reserve escrow account	291,485			290,422
Non-utility property - at cost (less accumulated depreciation)	217,494			206,293
Other	28,844			14,776
TOTAL	3,069,117			2,944,371

UTILITY PLANT
Electric	18,827,532			17,629,077
Natural gas	172,816			159,252
Property under capital lease	—			341,514
Construction work in progress	670,201			420,874
Nuclear fuel	249,807			386,524
TOTAL UTILITY PLANT	19,920,356			18,937,241
Less - accumulated depreciation and amortization	8,420,596			8,302,774
UTILITY PLANT - NET	11,499,760			10,634,467

DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Regulatory asset for income taxes - net	470,480			478,243
Other regulatory assets (includes securitization property of $92,951 as of December 31, 2016 and $114,701 as of December 31, 2015)	1,168,058			1,217,874
Deferred fuel costs	168,122			168,122
Other	16,003			14,125
TOTAL	1,822,663			1,878,364

TOTAL ASSETS		$17,701,271			$16,387,447

See Notes to Financial Statements.

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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY

	December 31,
	2016			2015
	(In Thousands)

CURRENT LIABILITIES
Currently maturing long-term debt		$200,198			$29,372
Short-term borrowings	3,794			60,356
Accounts payable:
Associated companies	82,106			165,419
Other	358,741			276,280
Customer deposits	148,601			146,555
Taxes accrued	—			125,142
Interest accrued	75,598			74,380
Deferred fuel costs	48,211			65,234
Other	80,013			79,982
TOTAL	997,262			1,022,720

NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued	2,691,118			2,506,956
Accumulated deferred investment tax credits	126,741			131,760
Regulatory liability for income taxes - net	—			2,473
Other regulatory liabilities	880,974			818,623
Decommissioning	1,082,685			1,027,862
Accumulated provisions	310,772			310,282
Pension and other postretirement liabilities	780,278			833,185
Long-term debt (includes securitization bonds of $99,217 as of December 31, 2016 and $120,549 as of December 31, 2015)	5,612,593			4,806,790
Long-term payables - associated companies	—			1,073
Other	137,039			188,411
TOTAL	11,622,200			10,627,415

Commitments and Contingencies

EQUITY
Member’s equity	5,130,251			4,793,724
Accumulated other comprehensive loss	(48,442		)	(56,412		)
TOTAL	5,081,809			4,737,312

TOTAL LIABILITIES AND EQUITY		$17,701,271			$16,387,447

See Notes to Financial Statements.

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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
For the Years Ended December 31, 2016, 2015, and 2014

				Common Equity
	Preferred Membership Interests			Member’s Equity			Accumulated Other Comprehensive Income (Loss)			Total
	(In Thousands)

Balance at December 31, 2013		$110,000			$4,364,466			($37,837	)		$4,436,629
Net income	—			446,022			—			446,022
Contribution from parent	—			1,052			—			1,052
Other comprehensive loss	—			—			(41,386		)	(41,386		)
Distributions to parent	—			(320,601		)	—			(320,601		)
Distributions declared on common equity	—			(166,901		)	—			(166,901		)
Distributions declared on preferred membership interests	—			(7,796		)	—			(7,796		)
Other	—			(32		)	—			(32		)
Balance at December 31, 2014		$110,000			$4,316,210			($79,223	)		$4,346,987
Net income	—			446,639			—			446,639
Other comprehensive income	—			—			22,811			22,811
Preferred stock redemption	(110,000		)	—			—			(110,000		)
Non-cash contribution from parent	—			267,826			—			267,826
Distributions to parent	—			(226,000		)	—			(226,000		)
Distributions declared on preferred membership interests	—			(5,737		)	—			(5,737		)
Other	—			(5,214		)	—			(5,214		)
Balance at December 31, 2015		$—			$4,793,724			($56,412	)		$4,737,312
Net income	—			622,047			—			622,047
Other comprehensive loss	—			—			7,970			7,970
Distributions to parent	—			(285,500		)	—			(285,500		)
Other	—			(20		)	—			(20		)
Balance at December 31, 2016		$—			$5,130,251			($48,442	)		$5,081,809

See Notes to Financial Statements.

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ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON

	2016		2015		2014		2013		2012
	(In Thousands)

Operating revenues		$4,177,048		$4,417,146		$4,740,504		$4,399,511		$3,668,755
Net income		$622,047		$446,639		$446,022		$414,126		$440,058
Total assets		$17,701,271		$16,387,447		$16,423,825		$15,275,863		$14,779,578
Long-term obligations (a)		$5,612,593		$4,806,790		$4,882,813		$4,383,273		$4,213,537

(a) Includes long-term debt (excluding currently maturing debt).

	2016		2015		2014		2013		2012
	(Dollars In Millions)

Electric Operating Revenues:
Residential		$1,196		$1,292		$1,358		$1,304		$1,076
Commercial	930		989		1,044		1,003		831
Industrial	1,350		1,420		1,569		1,457		1,123
Governmental	67		67		70		68		56
Total retail	3,543		3,768		4,041		3,832		3,086
Sales for resale:
Associated companies	368		406		427		320		378
Non-associated companies	50		36		80		48		36
Other	165		152		121		140		120
Total		$4,126		$4,362		$4,669		$4,340		$3,620

Billed Electric Energy Sales (GWh):
Residential	13,810		14,399		14,415		14,026		13,879
Commercial	11,478		11,700		11,555		11,402		11,399
Industrial	28,517		27,713		27,025		25,734		25,306
Governmental	794		756		732		723		707
Total retail	54,599		54,568		53,727		51,885		51,291
Sales for resale:
Associated companies	7,345		7,500		6,240		5,168		6,426
Non-associated companies	1,690		770		1,051		979		1,006
Total	63,634		62,838		61,018		58,032		58,723

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ENTERGY MISSISSIPPI, INC.

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Net Income

2016 Compared to 2015

Net income increased $16.5 million primarily due to lower other operation and maintenance expenses, higher net revenues, and a lower effective income tax rate, partially offset by higher depreciation and amortization expenses.

2015 Compared to 2014

Net income increased $17.9 million primarily due to the write-off in 2014 of the regulatory assets associated with new nuclear generation development costs as a result of a joint stipulation entered into with the Mississippi Public Utilities Staff, subsequently approved by the MPSC, partially offset by higher depreciation and amortization expenses, higher taxes other than income taxes, higher other operation and maintenance expenses, and lower net revenue. See Note 2 to the financial statements for discussion of the new nuclear generation development costs and the joint stipulation.

Net Revenue

2016 Compared to 2015



	Amount
	(In Millions)

2015 net revenue		$696.3
Retail electric price	12.9
Volume/weather	4.7
Net wholesale revenue	(2.4		)
Reserve equalization	(2.8		)
Other	(3.3		)
2016 net revenue		$705.4

The retail electric price variance is primarily due to a $19.4 million net annual increase in revenues, as approved by the MPSC, effective with the first billing cycle of July 2016, and an increase in revenues collected through the storm damage rider. See Note 2 to the financial statements for more discussion on the formula rate plan and the storm damage rider.

The volume/weather variance is primarily due to an increase of 153 GWh, or 1%, in billed electricity usage, including an increase in industrial usage, partially offset by the effect of less favorable weather on residential and commercial sales. The increase in industrial usage is primarily due to expansion projects in the pulp and paper industry, increased demand for existing customers, primarily in the metals industry, and new customers in the wood products industry.

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Entergy Mississippi, Inc.

Management’s Financial Discussion and Analysis

The net wholesale revenue variance is primarily due to Entergy Mississippi’s exit from the System Agreement in November 2015.

The reserve equalization revenue variance is primarily due to the absence of reserve equalization revenue as compared to the same period in 2015 resulting from Entergy Mississippi’s exit from the System Agreement in November 2015.

2015 Compared to 2014



	Amount
	(In Millions)

2014 net revenue		$701.2
Volume/weather	8.9
Retail electric price	7.3
Net wholesale revenue	(2.7		)
Transmission equalization	(5.4		)
Reserve equalization	(5.5		)
Other	(7.5		)
2015 net revenue		$696.3

The volume/weather variance is primarily due to an increase of 86 GWh, or 1%, in billed electricity usage,

including the effect of more favorable weather on residential and commercial sales.

The retail electric price variance is primarily due to a $16 million net annual increase in revenues, effective February 2015, as a result of the MPSC order in the June 2014 rate case and an increase in revenues collected through the energy efficiency rider, partially offset by a decrease in revenues collected through the storm damage rider. The rate case included the realignment of certain costs from collection in riders to base rates. See Note 2 to the financial statements for a discussion of the rate case, the energy efficiency rider, and the storm damage rider.

The net wholesale revenue variance is primarily due to a wholesale customer contract termination in October 2015.

Transmission equalization revenue represents amounts received by Entergy Mississippi from certain other Entergy Utility operating companies, in accordance with the System Agreement, to allocate the costs of collectively planning, constructing, and operating Entergy’s bulk transmission facilities. The transmission equalization variance is primarily attributable to the realignment, effective February 2015, of these revenues from the determination of base rates to inclusion in a rider. Such revenues had a favorable effect on net revenue in 2014, but minimal effect in 2015. Entergy Mississippi exited the System Agreement in November 2015. See Note 2 to the financial statements for a discussion of the System Agreement.

Reserve equalization revenue represents amounts received by Entergy Mississippi from certain other Entergy Utility operating companies, in accordance with the System Agreement, to allocate the costs of collectively maintaining adequate electric generating capacity across the Entergy System. The reserve equalization variance is primarily attributable to the realignment, effective February 2015, of these revenues from the determination of base rates to inclusion in a rider. Such revenues had a favorable effect on net revenue in 2014, but minimal effect in 2015. Entergy

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Mississippi exited the System Agreement in November 2015. See Note 2 to the financial statements for a discussion of the System Agreement.

Other Income Statement Variances

2016 Compared to 2015

Other operation and maintenance expenses decreased primarily due to:


•	a decrease of $9.4 million in fossil-fueled generation expenses primarily due to a lower scope of work done during plant outages in 2016 as compared to the same period in 2015;

•

a decrease of $6.1 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs;


•	a decrease of $2 million due to lower write-offs of uncollectible customer accounts in 2016;


•	a decrease of $2 million in energy efficiency costs; and


•	several individually insignificant items.

The decrease was partially offset by an increase of $7.1 million in storm damage provisions and an increase of $6 million in distribution expenses primarily due to higher vegetation maintenance. See Note 2 to the financial statements for a discussion of storm cost recovery.

Depreciation and amortization expenses increased primarily due to additions to plant in service.

2015 Compared to 2014

Other operation and maintenance expenses increased primarily due to:


•	an increase of $5 million in distribution expenses primarily due to higher vegetation maintenance and higher labor costs in 2015 as compared to 2014;


•	an increase of $4.9 million in energy efficiency costs, which began in fourth quarter 2014;


•	an increase of $4.8 million in fossil-fueled generation expenses primarily due to a higher scope of work done during plant outages in 2015 as compared to 2014;


•	a $2.6 million loss recognized on the disposition of plant components;


•	an increase of $1.8 million in costs incurred in 2014 related to repairs as a result of a unplanned outage event that occurred at the Baxter Wilson (Unit 1) power plant in September 2013, including an offset for expected insurance proceeds and amortization of the repair costs in 2015 that were deferred in 2014 as approved by the MPSC; and

•

an increase of $1.7 million in compensation and benefits costs primarily due to an increase in net periodic pension and other postretirement benefits costs as a result of lower discount rates and changes in retirement and mortality assumptions, partially offset by a decrease in the accrual for incentive-based compensation. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs.

The increase was partially offset by a decrease of $17.6 million in storm damage provisions. See Note 2 to the financial statements for a discussion of storm cost recovery.

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The asset write-off variance is due to the $56.2 million ($36.7 million after-tax) write-off in 2014 of Entergy Mississippi’s regulatory assets associated with new nuclear generation development costs. See “New Nuclear Generation Development Costs” below and Note 2 to the financial statements for discussion of the new nuclear generation development costs.

Taxes other than income taxes increased primarily due to an increase in ad valorem taxes.

Depreciation and amortization expenses increased primarily due to additions to plant in service and higher depreciation rates in 2015, as approved by the MPSC.

Income Taxes

The effective income tax rates for 2016, 2015, and 2014 were 36.9%, 40.0%, and 42.7%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2016, 2015, and 2014 were as follows:



	2016			2015			2014
	(In Thousands)
Cash and cash equivalents at beginning of period		$145,605			$61,633			$31

Net cash provided by (used in):
Operating activities	212,280			372,279			303,463
Investing activities	(289,444		)	(245,127		)	(177,765		)
Financing activities	8,393			(43,180		)	(64,096		)
Net increase (decrease) in cash and cash equivalents	(68,771		)	83,972			61,602

Cash and cash equivalents at end of period		$76,834			$145,605			$61,633

Operating Activities

Net cash flow provided by operating activities decreased $160 million in 2016 primarily due to a decrease due to the timing of recovery of fuel and purchased power costs in 2016 as compared to the same period in 2015 and $15.3 million in insurance proceeds received in 2015 related to the unplanned outage event that occurred at the Baxter Wilson (Unit 1) power plant in September 2013. The decrease was partially offset by income tax refunds of $12.5 million in 2016 compared to income tax payments of $61.3 million in 2015. Entergy Mississippi had income tax refunds in 2016 and income tax payments in 2015 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The 2016 income tax refunds resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit whereas the income tax payments in 2015 were primarily due to the results of operations and the reversal of taxable temporary differences as well as final settlement of amounts outstanding associated with the 2006-2007 IRS audit. See Note 3 to the financial statements for a discussion of the income tax audits.

Net cash flow provided by operating activities increased $68.8 million in 2015 primarily due to:


•	an increase due to the timing of recovery of fuel and purchased power costs in 2015;

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•	System Agreement bandwidth remedy payments of $16.4 million made in September 2014 as a result of the compliance filing pursuant to the FERC’s orders related to the bandwidth payments/receipts for the 2007 - 2009 period;


•	$15.3 million in insurance proceeds received in 2015 related to the unplanned outage event that occurred at the Baxter Wilson (Unit 1) power plant in September 2013; and


•	the timing of collections from customers.

The increase was partially offset by:

•

an increase of $41.7 million in income tax payments in 2015. Entergy Mississippi had income tax payments in 2015 and 2014 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The income tax payments in 2015 were primarily due to the results of operations and the reversal of taxable temporary differences as well as final settlement of amounts outstanding associated with the 2006-2007 IRS audit. The 2014 payments resulted primarily from the reversal of taxable temporary differences for which Entergy Mississippi had previously claimed a tax deduction. See Note 3 to the financial statements for a discussion of this audit; and


•	System Agreement bandwidth remedy payments of $11.3 million received in 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period.

See Note 2 to the financial statements for a discussion of the System Agreement proceedings.

Investing Activities

Net cash flow used in investing activities increased $44.3 million in 2016 primarily due to:


•	an increase of $72.4 million in transmission construction expenditures primarily due to a higher scope of work performed in 2016 as compared to the same period in 2015;


•	insurance proceeds of $12.9 million received in 2015 related to the unplanned outage event that occurred at the Baxter Wilson (Unit 1) power plant in September 2013;


•	an increase of $11.4 million in distribution construction expenditures primarily due to a higher scope of non-storm related work performed in 2016 as compared to the same period in 2015; and


•	an increase of $10.1 million due to various information technology projects and upgrades.

The increase was partially offset by a decrease of $20.1 million in fossil-fueled generation construction expenditures primarily due to a decreased scope of work performed during plant outages in 2016 as compared to the same period in 2015 and money pool activity.

Decreases in Entergy Mississippi’s receivable from the money pool are a source of cash flow, and Entergy Mississippi’s receivable from the money pool decreased by $15.3 million in 2016 compared to increasing by $25.3 million in 2015. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.

Net cash flow used in investing activities increased $67.4 million in 2015 primarily due to:


•	an increase in transmission construction expenditures primarily due to a higher scope of work done in 2015;


•	an increase in information technology capital expenditures due to various technology projects and upgrades in 2015; and


•	money pool activity.

The increase was partially offset by $12.9 million of insurance proceeds received in 2015 related to the unplanned outage event that occurred at the Baxter Wilson (Unit 1) power plant in September 2013.

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Increases in Entergy Mississippi’s receivable from the money pool are a use of cash flow, and Entergy Mississippi’s receivable from the money pool increased by $25.3 million in 2015 compared to increasing by $0.6 million in 2014.

Financing Activities

Entergy Mississippi’s financing activities provided $8.4 million of cash in 2016 compared to using $43.2 million in 2015 primarily due to the net issuance of $61.4 million of long-term debt in 2016 and a decrease of $16 million in common stock dividends paid in 2016, partially offset by the redemption of $30 million of 6.25% Series preferred stock. The decrease in dividends paid was primarily because of lower operating cash flows and higher capital expenditures, each discussed above.

Net cash flow used in financing activities decreased $20.9 million in 2015 primarily due to a decrease of $21.4 million in common stock dividends paid. The decrease in dividends paid was primarily due to higher capital expenditures, as discussed above.

See Note 5 to the financial statements for details on long-term debt.

Capital Structure

Entergy Mississippi’s capitalization is balanced between equity and debt, as shown in the following table.



	December 31, 2016		December 31, 2015
Debt to capital	50.2	%	49.7	%
Effect of subtracting cash	(1.8	%)	(3.8	%)
Net debt to net capital	48.4	%	45.9	%

Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, capital lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt, preferred stock without sinking fund, and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Mississippi uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Mississippi’s financial condition. Entergy Mississippi uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Mississippi’s financial condition because net debt indicates Entergy Mississippi’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

Entergy Mississippi seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend, or both, in appropriate amounts to maintain the targeted capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Mississippi may issue incremental debt or reduce dividends, or both, to maintain its targeted capital structure. In addition, in certain infrequent circumstances, such as large transactions that would materially alter the capital structure if financed entirely with debt and reducing dividends, Entergy Mississippi may receive equity contributions to maintain the targeted capital structure.

Uses of Capital

Entergy Mississippi requires capital resources for:


•	construction and other capital investments;


•	debt and preferred stock maturities or retirements;

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•	working capital purposes, including the financing of fuel and purchased power costs; and


•	dividend and interest payments.

Following are the amounts of Entergy Mississippi’s planned construction and other capital investments.



	2017		2018		2019
	(In Millions)
Planned construction and capital investment:
Generation		$45		$50		$40
Transmission	170		135		85
Distribution	135		115		130
Other	60		40		25
Total		$410		$340		$280

Following are the amounts of Entergy Mississippi’s existing debt obligations and lease obligations (includes estimated interest payments) and other purchase obligations.



	2017		2018-2019		2020-2021		After 2021		Total
	(In Millions)
Long-term debt (a)		$45		$235		$70		$1,644		$1,994
Capital lease payments		$2		$—		$—		$—		$2
Operating leases		$8		$14		$10		$6		$38
Purchase obligations (b)		$240		$440		$421		$4,762		$5,863


(a)	Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements.


(b)	Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Mississippi, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which is discussed in Note 8 to the financial statements.

In addition to the contractual obligations given above, Entergy Mississippi currently expects to contribute approximately $19.1 million to its qualified pension plans and approximately $140 thousand to other postretirement health care and life insurance plans in 2017, although the 2017 required pension contributions will be known with more certainty when the January 1, 2017 valuations are completed, which is expected by April 1, 2017 See “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.

Also in addition to the contractual obligations, Entergy Mississippi has $9.8 million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Mississippi includes amounts associated with specific investments such as transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including initial investment to support advanced metering; resource planning, including potential generation projects; system improvements; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital. Management provides more information on long-term debt and preferred stock maturities in Notes 5 and 6 to the financial statements.

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As a wholly-owned subsidiary, Entergy Mississippi dividends its earnings to Entergy Corporation at a percentage determined monthly. Provisions in Entergy Mississippi’s articles of incorporation relating to preferred stock restrict the amount of retained earnings available for the payment of cash dividends or other distributions on its common and preferred stock.

New Nuclear Generation Development Costs

Pursuant to the Mississippi Baseload Act and the Mississippi Public Utilities Act, Entergy Mississippi had been developing and preserving a project option for new nuclear generation at Grand Gulf Nuclear Station. In October 2010, Entergy Mississippi filed an application with the MPSC requesting that the MPSC determine that it was in the public interest to preserve the option to construct new nuclear generation at Grand Gulf and that the MPSC approve the deferral of Entergy Mississippi’s costs incurred to date and in the future related to this project, including the accrual of AFUDC or similar carrying charges. In October 2011, Entergy Mississippi and the Mississippi Public Utilities Staff filed with the MPSC a joint stipulation that the MPSC approved in November 2011. The stipulation stated that there should be a deferral of the $57 million of costs incurred through September 2011 in connection with planning, evaluating, monitoring, and other related generation resource development activities for new nuclear generation at Grand Gulf.

In October 2014, Entergy Mississippi and the Mississippi Public Utilities Staff entered into and filed joint stipulations in Entergy Mississippi’s general rate case proceeding, which are discussed below. In consideration of the comprehensive terms for settlement in that rate case proceeding, the Mississippi Public Utilities Staff and Entergy Mississippi agreed that Entergy Mississippi would request consolidation of the new nuclear generation development costs proceeding with the rate case proceeding for hearing purposes and will not further pursue, except as noted below, recovery of the costs deferred by MPSC order in the new nuclear generation development docket. The stipulations state, however, that, if Entergy Mississippi decides to move forward with nuclear development in Mississippi, it can at that time re-present for consideration by the MPSC only those costs directly associated with the existing early site permit (ESP), to the extent that the costs are verifiable and prudent and the ESP is still valid and relevant to any such option pursued. After considering the progress of the new nuclear generation costs proceeding in light of the joint stipulation, Entergy Mississippi recorded in 2014 a $56.2 million pre-tax charge to recognize that the regulatory asset associated with new nuclear generation development is no longer probable of recovery. In December 2014 the MPSC issued an order accepting in their entirety the October 2014 stipulations, including the findings and terms of the stipulations regarding new nuclear generation development costs.

Sources of Capital

Entergy Mississippi’s sources to meet its capital requirements include:


•	internally generated funds;


•	cash on hand;


•	debt or preferred stock issuances; and


•	bank financing under new or existing facilities.

Entergy Mississippi may refinance, redeem, or otherwise retire debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.

All debt and common and preferred stock issuances by Entergy Mississippi require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in its corporate charter, bond indenture, and other agreements. Entergy Mississippi has sufficient capacity under these tests to meet its foreseeable capital needs.

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Entergy Mississippi’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.

See Note 4 to the financial statements for a description of the money pool.

Entergy Mississippi has four separate credit facilities in the aggregate amount of $102.5 million scheduled to expire May 2017. No borrowings were outstanding under the credit facilities as of December 31, 2016. In addition, Entergy Mississippi is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations under MISO. As of December 31, 2016, a $7.1 million letter of credit was outstanding under Entergy Mississippi’s uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.

Entergy Mississippi obtained authorizations from the FERC through October 2017 for short-term borrowings not to exceed an aggregate amount of $175 million at any time outstanding and long-term borrowings and security issuances. See Note 4 to the financial statements for further discussion of Entergy Mississippi’s short-term borrowing limits.

State and Local Rate Regulation and Fuel-Cost Recovery

The rates that Entergy Mississippi charges for electricity significantly influence its financial position, results of operations, and liquidity. Entergy Mississippi is regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the MPSC, is primarily responsible for approval of the rates charged to customers.

Formula Rate Plan


•	an approximate $16 million net increase in revenues, which reflected an agreed upon 10.07% return on common equity;

•

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•	recovery of non-fuel MISO-related costs through a separate rider for that purpose;

•

In December 2014 the MPSC issued an order accepting the stipulations in their entirety and approving the revenue adjustments and rate changes effective with February 2015 bills.

In August 2012 the MPSC opened inquiries to review whether the current formulaic methodology used to calculate the return on common equity in both Entergy Mississippi’s formula rate plan and Mississippi Power Company’s annual formula rate plan was still appropriate or could be improved to better serve the public interest. The intent of this inquiry and review was for informational purposes only; the evaluation of any recommendations for changes to the existing methodology would take place in a general rate case or in the existing formula rate plan docket. In March 2013 the Mississippi Public Utilities Staff filed its consultant’s report which noted the return on common equity estimation methods used by Entergy Mississippi and Mississippi Power Company are commonly used throughout the electric utility industry. The report suggested ways in which the methods used by Entergy Mississippi and Mississippi Power Company might be improved, but did not recommend specific changes in the return on common equity formulas or calculations at that time. In June 2014 the MPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate plan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi’s formula rate plan rider schedule and Mississippi Power Company’s Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has been set. In October 2014 the Mississippi Public Utilities Staff conducted a public technical conference to discuss performance benchmarking and its potential application to the electric utilities’ formula rate plans.

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Fuel and Purchased Power Cost Recovery

Mississippi Attorney General Complaint

The Mississippi attorney general filed a complaint in state court in December 2008 against Entergy Corporation, Entergy Mississippi, Entergy Services, and Entergy Power alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution. The complaint is wide ranging and relates to tariffs and procedures under which Entergy Mississippi purchases power not generated in Mississippi to meet electricity demand. Entergy believes the complaint is unfounded. In December 2008 the defendant Entergy companies removed the Attorney General’s lawsuit to U.S. District Court in Jackson, Mississippi. The Mississippi attorney general moved to remand the matter to state court. In August 2012 the District Court issued an opinion denying the Attorney General’s motion for remand, finding that the District Court has subject matter jurisdiction under the Class Action Fairness Act.

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Advanced Metering Infrastructure (AMI) Filing

Storm Damage Provision and Storm Cost Recovery

On July 1, 2013, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation, wherein both parties agreed that approximately $32 million in storm restoration costs incurred in 2011 and 2012 were

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prudently incurred and chargeable to the storm damage provision, while approximately $700,000 in prudently incurred costs were more properly recoverable through the formula rate plan. Entergy Mississippi and the Mississippi Public Utilities Staff also agreed that the storm damage provision should be increased from $750,000 per month to $1.75 million per month. In September 2013 the MPSC approved the joint stipulation with the increase in the storm damage provision effective with October 2013 bills. In February 2015, Entergy Mississippi provided notice to the Mississippi Public Utilities Staff that the storm damage provision would be set to zero effective with the March 2015 billing cycle as a result of Entergy Mississippi’s storm damage provision balance exceeding $15 million as of January 31, 2015, but would return to its current level when the storm damage provision balance becomes less than $10 million. As of April 30, 2016, Entergy Mississippi’s storm damage provision balance was less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with June 2016 bills. As of September 30, 2016, however, Entergy Mississippi’s storm damage provision balance again exceeded $15 million. Accordingly the storm damage provision was reset to zero beginning with the November 2016 billing cycle and will remain at zero until the balance again becomes less than $10 million, at which time it will return to its prior level.

Federal Regulation

Nuclear Matters

See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.

Environmental Risks

Entergy Mississippi’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Mississippi is in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

The preparation of Entergy Mississippi’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and there is the potential for future changes in the assumptions and measurements that could produce estimates that would have a material impact on the presentation of Entergy Mississippi’s financial position or results of operations.

Utility Regulatory Accounting

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Unbilled Revenue

Taxation and Uncertain Tax Positions

Qualified Pension and Other Postretirement Benefits

Entergy Mississippi’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.

Cost Sensitivity

The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).



Actuarial Assumption	Change in Assumption	Impact on 2017 Qualified Pension Cost	Impact on 2016 Projected Qualified Benefit Obligation
		Increase/(Decrease)
Discount rate	(0.25%)	$901		$12,896
Rate of return on plan assets	(0.25%)	$818	$-
Rate of increase in compensation	0.25%	$409		$2,519

The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).



Actuarial Assumption	Change in Assumption	Impact on 2017 Postretirement Benefit Cost	Impact on 2016 Accumulated Postretirement Benefit Obligation
		Increase/(Decrease)
Discount rate	(0.25%)	$195	$2,334
Health care cost trend	0.25%	$343	$1,909

Each fluctuation above assumes that the other components of the calculation are held constant.

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Costs and Funding

Total qualified pension cost for Entergy Mississippi in 2016 was $9.5 million. Entergy Mississippi anticipates 2017 qualified pension cost to be $8.5 million. In 2016, Entergy Mississippi refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $3.8 million. Entergy Mississippi contributed $20 million to its qualified pension plans in 2016 and estimates 2017 pension contributions will be approximately $19.1 million, although the 2017 required pension contributions will be known with more certainty when the January 1, 2017 valuations are completed, which is expected by April 1, 2017.

Total postretirement health care and life insurance benefit income for Entergy Mississippi in 2016 was $1.2 million. Entergy Mississippi expects 2017 postretirement health care and life insurance benefit income of approximately $1 million. In 2016, Entergy Mississippi refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $770 thousand. Entergy Mississippi contributed $685 thousand to its other postretirement plans in 2016 and estimates that 2017 contributions will be approximately $140 thousand.

The retirement and mortality rate assumptions are reviewed every three-to-five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans. The 2014 actuarial study reviewed plan experience from 2010 through 2013. As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies. These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of $33.5 million in the qualified pension benefit obligation and $4.6 million in the accumulated postretirement obligation. The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $4.8 million and other postretirement cost by approximately $0.6 million. In 2016, the mortality projection scale was updated to MP-2016, with no change in the base mortality table assumption.

Federal Healthcare Legislation

Other Contingencies

New Accounting Pronouncements

See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Entergy Mississippi, Inc.

Jackson, Mississippi

We have audited the accompanying balance sheets of Entergy Mississippi, Inc. (the “Company”) as of December 31, 2016 and 2015, and the related income statements, statements of cash flows, and statements of changes in common equity (pages 376 through 380 and applicable items in pages 59 through 232) for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy Mississippi, Inc. as of December 31, 2016 and 2015, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 24, 2017

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ENTERGY MISSISSIPPI, INC.
INCOME STATEMENTS

	For the Years Ended December 31,
	2016			2015			2014
	(In Thousands)

OPERATING REVENUES
Electric		$1,094,649			$1,396,985			$1,524,193

OPERATING EXPENSES
Operation and Maintenance:
Fuel, fuel-related expenses, and gas purchased for resale	95,090			291,666			325,643
Purchased power	297,902			389,950			493,533
Other operation and maintenance	250,443			261,255			256,339
Asset write-off	—			—			56,225
Taxes other than income taxes	94,482			94,152			87,936
Depreciation and amortization	136,214			129,029			113,903
Other regulatory charges (credits) - net	(3,721		)	19,027			3,854
TOTAL	870,410			1,185,079			1,337,433

OPERATING INCOME	224,239			211,906			186,760

OTHER INCOME
Allowance for equity funds used during construction	5,801			3,095			2,380
Interest and investment income	656			195			1,055
Miscellaneous - net	(3,531		)	(4,418		)	(3,905		)
TOTAL	2,926			(1,128		)	(470		)

INTEREST EXPENSE
Interest expense	57,114			57,842			57,002
Allowance for borrowed funds used during construction	(2,987		)	(1,644		)	(1,243		)
TOTAL	54,127			56,198			55,759

INCOME BEFORE INCOME TAXES	173,038			154,580			130,531

Income taxes	63,854			61,872			55,710

NET INCOME	109,184			92,708			74,821

Preferred dividend requirements and other	2,443			2,828			2,828

EARNINGS APPLICABLE TO COMMON STOCK		$106,741			$89,880			$71,993

See Notes to Financial Statements.

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ENTERGY MISSISSIPPI, INC.
STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
	2016			2015			2014
	(In Thousands)

OPERATING ACTIVITIES
Net income		$109,184			$92,708			$74,821
Adjustments to reconcile net income to net cash flow provided by operating activities:
Depreciation and amortization	136,214			129,029			113,903
Deferred income taxes, investment tax credits, and non-current taxes accrued	60,986			18,673			32,472
Changes in assets and liabilities:
Receivables	(28,819		)	50,199			(27,444		)
Fuel inventory	401			(8,537		)	6,163
Accounts payable	33,733			(26,682		)	(14,618		)
Taxes accrued	20,579			(10,104		)	318
Interest accrued	822			(2,341		)	2,789
Deferred fuel costs	(114,711		)	105,560			40,251
Other working capital accounts	(5,222		)	(663		)	17,567
Provisions for estimated losses	6,378			(2,080		)	14,468
Other regulatory assets	(3,626		)	39,582			(36,875		)
Pension and other postretirement liabilities	(10,648		)	(14,939		)	68,434
Other assets and liabilities	7,009			1,874			11,214
Net cash flow provided by operating activities	212,280			372,279			303,463
INVESTING ACTIVITIES
Construction expenditures	(310,356		)	(235,894		)	(179,544		)
Allowance for equity funds used during construction	5,801			3,095			2,380
Insurance proceeds	—			12,932			—
Changes in money pool receivable - net	15,335			(25,286		)	(644		)
Other	(224		)	26			43
Net cash flow used in investing activities	(289,444		)	(245,127		)	(177,765		)
FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	623,812			—			98,668
Retirement of long-term debt	(562,400		)	—			(95,000		)
Changes in money pool payable - net	—			—			(3,536		)
Redemption of preferred stock	(30,000		)	—			—
Dividends paid:
Common stock	(24,000		)	(40,000		)	(61,400		)
Preferred stock	(2,755		)	(2,828		)	(2,828		)
Other	3,736			(352		)	—
Net cash flow provided by (used in) financing activities	8,393			(43,180		)	(64,096		)
Net increase (decrease) in cash and cash equivalents	(68,771		)	83,972			61,602
Cash and cash equivalents at beginning of period	145,605			61,633			31
Cash and cash equivalents at end of period		$76,834			$145,605			$61,633
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized		$53,693			$57,576			$51,509
Income taxes		($12,487	)		$61,333			$19,650
See Notes to Financial Statements.

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ENTERGY MISSISSIPPI, INC.
BALANCE SHEETS
ASSETS

	December 31,
	2016			2015
	(In Thousands)

CURRENT ASSETS
Cash and cash equivalents:
Cash		$16			$1,426
Temporary cash investments	76,818			144,179
Total cash and cash equivalents	76,834			145,605
Accounts receivable:
Customer	51,218			56,685
Allowance for doubtful accounts	(549		)	(718		)
Associated companies	45,973			34,964
Other	12,006			8,276
Accrued unbilled revenues	51,327			47,284
Total accounts receivable	159,975			146,491
Deferred fuel costs	6,957			—
Fuel inventory - at average cost	50,872			51,273
Materials and supplies - at average cost	41,146			39,491
Prepayments and other	8,873			5,184
TOTAL	344,657			388,044

OTHER PROPERTY AND INVESTMENTS
Non-utility property - at cost (less accumulated depreciation)	4,608			4,625
Escrow accounts	31,783			41,726
TOTAL	36,391			46,351

UTILITY PLANT
Electric	4,321,214			4,083,933
Property under capital lease	1,590			2,942
Construction work in progress	118,182			114,067
TOTAL UTILITY PLANT	4,440,986			4,200,942
Less - accumulated depreciation and amortization	1,602,711			1,534,522
UTILITY PLANT - NET	2,838,275			2,666,420

DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Regulatory asset for income taxes - net	38,284			45,790
Other regulatory assets	342,213			328,681
Other	2,320			2,121
TOTAL	382,817			376,592

TOTAL ASSETS		$3,602,140			$3,477,407

See Notes to Financial Statements.

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ENTERGY MISSISSIPPI, INC.
BALANCE SHEETS
LIABILITIES AND EQUITY

	December 31,
	2016		2015
	(In Thousands)

CURRENT LIABILITIES
Currently maturing long-term debt		$—		$125,000
Accounts payable:
Associated companies	43,647		38,496
Other	80,227		51,502
Customer deposits	84,112		81,583
Taxes accrued	64,040		43,461
Interest accrued	21,653		20,831
Deferred fuel costs	—		107,754
Other	9,554		22,754
TOTAL	303,233		491,381

NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued	861,331		810,635
Accumulated deferred investment tax credits	8,667		4,645
Asset retirement cost liabilities	8,722		8,252
Accumulated provisions	54,440		48,062
Pension and other postretirement liabilities	109,551		120,217
Long-term debt	1,120,916		920,085
Other	20,108		11,699
TOTAL	2,183,735		1,923,595

Commitments and Contingencies

Preferred stock without sinking fund	20,381		50,381

COMMON EQUITY
Common stock, no par value, authorized 12,000,000 shares; issued and outstanding 8,666,357 shares in 2016 and 2015	199,326		199,326
Capital stock expense and other	167		(690		)
Retained earnings	895,298		813,414
TOTAL	1,094,791		1,012,050

TOTAL LIABILITIES AND EQUITY		$3,602,140		$3,477,407

See Notes to Financial Statements.

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ENTERGY MISSISSIPPI, INC.
STATEMENTS OF CHANGES IN COMMON EQUITY
For the Years Ended December 31, 2016, 2015, and 2014

	Common Equity
	Common Stock		Capital Stock Expense and Other			Retained Earnings			Total
	(In Thousands)

Balance at December 31, 2013		$199,326		($690	)		$752,941			$951,577
Net income	—		—			74,821			74,821
Common stock dividends	—		—			(61,400		)	(61,400		)
Preferred stock dividends	—		—			(2,828		)	(2,828		)
Balance at December 31, 2014		$199,326		($690	)		$763,534			$962,170
Net income	—		—			92,708			92,708
Common stock dividends	—		—			(40,000		)	(40,000		)
Preferred stock dividends	—		—			(2,828		)	(2,828		)
Balance at December 31, 2015		$199,326		($690	)		$813,414			$1,012,050
Net income	—		—			109,184			109,184
Common stock dividends	—		—			(24,000		)	(24,000		)
Preferred stock dividends	—		—			(2,443		)	(2,443		)
Preferred stock redemption	—		857			(857		)	—
Balance at December 31, 2016		$199,326		$167			$895,298			$1,094,791

See Notes to Financial Statements.

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ENTERGY MISSISSIPPI, INC.
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON

	2016		2015		2014		2013		2012
	(In Thousands)

Operating revenues		$1,094,649		$1,396,985		$1,524,193		$1,334,540		$1,120,366
Net income		$109,184		$92,708		$74,821		$82,159		$46,768
Total assets		$3,602,140		$3,477,407		$3,358,625		$3,234,875		$3,337,230
Long-term obligations (a)		$1,141,924		$972,058		$1,097,182		$1,092,786		$1,108,432

(a) Includes long-term debt (excluding currently maturing debt), non-current capital lease obligations, and preferred stock without sinking fund.

	2016		2015		2014		2013		2012
	(Dollars In Millions)

Electric Operating Revenues:
Residential		$459		$565		$585		$527		$454
Commercial	374		465		481		432		381
Industrial	134		164		175		156		140
Governmental	38		47		47		42		37
Total retail	1,005		1,241		1,288		1,157		1,012
Sales for resale:
Associated companies	1		75		153		92		23
Non-associated companies	30		10		14		24		24
Other	59		71		69		62		61
Total		$1,095		$1,397		$1,524		$1,335		$1,120

Billed Electric Energy Sales (GWh):
Residential	5,617		5,661		5,672		5,629		5,550
Commercial	4,894		4,913		4,821		4,815		4,915
Industrial	2,493		2,283		2,297		2,265		2,400
Governmental	439		433		414		409		408
Total retail	13,443		13,290		13,204		13,118		13,273
Sales for resale:
Associated companies	—		1,419		2,657		1,543		232
Non-associated companies	1,021		261		193		304		265
Total	14,464		14,970		16,054		14,965		13,770

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ENTERGY NEW ORLEANS, INC. AND SUBSIDIARIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Net Income

2016 Compared to 2015

Net income increased $3.9 million primarily due to higher net revenue, partially offset by higher depreciation and amortization expenses, higher interest expense, and lower other income.

2015 Compared to 2014

Net income increased $13.9 million primarily due to lower other operation and maintenance expenses and higher net revenue, partially offset by a higher effective income tax rate.

Net Revenue

2016 Compared to 2015



	Amount
	(In Millions)

2015 net revenue		$293.9
Retail electric price	39.0
Net gas revenue	(2.5		)
Volume/weather	(5.1		)
Other	(8.1		)
2016 net revenue		$317.2

The retail electric price variance is primarily due to an increase in the purchased power and capacity acquisition cost recovery rider, as approved by the City Council, effective with the first billing cycle of March 2016, primarily related to the purchase of Power Block 1 of the Union Power Station. See Note 14 to the financial statements for discussion of the Union Power Station purchase.

The net gas revenue variance is primarily due to the effect of less favorable weather on residential and commercial sales.

The volume/weather variance is primarily due to a decrease of 112 GWh, or 2%, in billed electricity usage, partially offset by the effect of favorable weather on commercial sales and a 2% increase in the average number of electric customers.

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Management’s Financial Discussion and Analysis

2015 Compared to 2014



	Amount
	(In Millions)

2014 net revenue		$284.9
Volume/weather	9.8
Net gas revenue	(3.1		)
Other	2.3
2015 net revenue		$293.9

The volume/weather variance is primarily due to an increase of 165 GWh, or 3%, in billed electricity usage, primarily in the residential and commercial sectors, including the effect of favorable weather on commercial sales in 2015 and a 2% increase in the average number of electric customers.

The net gas revenue variance is primarily due to the effect of less favorable weather, primarily on residential sales.

Other Income Statement Variances

2016 Compared to 2015

Other operation and maintenance expenses decreased primarily due to:


•	a decrease of $6.1 million due to lower transmission equalization expenses, as allocated under the System Agreement as compared to the same period in 2015 primarily due to the termination of the System Agreement. See Note 2 to the financial statements for further discussion on the System Agreement termination;


•	a decrease of $4.4 million due to the cessation of storm damage provisions in August 2015. See Note 2 to the financial statements for further discussion of storm cost recovery; and

•

a decrease of $3.1 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs.

The decrease was partially offset by:


•	an increase of $5.7 million in fossil-fueled generation expenses primarily due to an increase as a result of the purchase of Power Block 1 of the Union Power Station in March 2016, partially offset by a decrease as a result of the deactivation of Michoud Units 2 and 3 effective May 2016. See Note 14 to the financial statements for discussion of the Union Power Station purchase;


•	an increase of $3.1 million due to an increase in loss reserves; and


•	an increase of $2.8 million due to higher write-offs of uncollectible customer accounts in 2016 as compared to 2015.

Depreciation and amortization expenses increased primarily due to additions to plant in service, including the purchase of Power Block 1 of the Union Power Station in March 2016, partially offset by the deactivation of Michoud Units 2 and 3 effective May 2016.

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Management’s Financial Discussion and Analysis

Interest expense increased primarily due to the issuance of $110 million of 5.50% Series first mortgage bonds in March 2016 and the issuance of $98.7 million of storm cost recovery bonds in July 2015. See Note 5 to the financial statements for details on long-term debt.

Other income decreased primarily due to an increase in charitable contributions made in 2016 as compared to 2015.

2015 Compared to 2014

Other operation and maintenance expenses decreased primarily due to a decrease of $9.9 million in fossil-fueled generation expenses primarily resulting from a lower scope of work in 2015 and a decrease in asbestos loss reserves in 2015, and a decrease of $3 million due to the cessation of storm damage provisions in August 2015. See Note 2 to the financial statements for further discussion of storm costs recovery.

Taxes other than income taxes decreased primarily due to a decrease in local franchise taxes resulting from lower electric and gas retail revenues in 2015 as compared to 2014 and a decrease in ad valorem taxes resulting from lower assessments and higher capitalized taxes.

Income Taxes

The effective income tax rates for 2016, 2015, and 2014 were 37.0%, 35.9%, and 30.2%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2016, 2015, and 2014 were as follows:



	2016			2015			2014
	(In Thousands)
Cash and cash equivalents at beginning of period		$88,876			$42,389			$33,489

Net cash provided by (used in):
Operating activities	205,211			105,068			88,933
Investing activities	(322,681		)	(173,460		)	(72,383		)
Financing activities	131,662			114,879			(7,650		)
Net increase in cash and cash equivalents	14,192			46,487			8,900

Cash and cash equivalents at end of period		$103,068			$88,876			$42,389

Operating Activities

Net cash flow provided by operating activities increased $100.1 million in 2016 primarily due to income tax refunds of $86 million in 2016 as compared to income tax payments of $8.1 million in 2015. Entergy New Orleans had income tax refunds in 2016 and income tax payments in 2015 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The 2016 income tax refunds resulted primarily from deductible temporary differences.

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Management’s Financial Discussion and Analysis

Net cash flow provided by operating activities increased $16.1 million in 2015 primarily due to an increase in net income.

Investing Activities

Net cash flow used in investing activities increased $149.2 million in 2016 primarily due to the purchase of Power Block 1 of the Union Power Station for approximately $237 million in March 2016. See Note 14 to the financial statements for discussion of the Union Power Station purchase. The increase was partially offset by a deposit of $63.9 million into the storm reserve escrow account in July 2015 and money pool activity. See Note 5 to the financial statements for a discussion of the issuance in July 2015 of securitization bonds to recover storm costs.

Decreases in Entergy New Orleans’s receivable from the money pool are a source of cash flow, and Entergy New Orleans’s receivable from the money pool decreased $1.6 million in 2016 compared to increasing $15.4 million in 2015. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.

Net cash flow used in investing activities increased $101.1 million in 2015 primarily due to:


•	a deposit of $63.9 million into the storm reserve escrow account in July 2015. See Note 5 for a discussion of the issuance in July 2015 of securitization bonds to recover storm costs;


•	money pool activity;


•	an increase in transmission construction expenditures primarily due to a higher scope of work performed in 2015 as compared to 2014; and


•	an increase in distribution construction expenditures primarily due to a higher scope of work performed in 2015 as compared to 2014.

Increases in Entergy New Orleans’s receivable from the money pool are a use of cash flow, and Entergy New Orleans’s receivable from the money pool increased $15.4 million in 2015 compared to decreasing $4.3 million in 2014.

Financing Activities

Net cash flow provided by financing activities increased $16.8 million in 2016 primarily due to:


•	the purchase of Entergy Louisiana’s Algiers assets in September 2015. The cash portion of the purchase is reflected as a repayment of a long-term payable due to Entergy Louisiana in the cash flow statement. See Note 2 to the financial statements and “Algiers Asset Transfer” below for further discussion of the Algiers asset transfer and accounting for the transaction;


•	the issuance of $100 million of 5.50% Series first mortgage bonds in March 2016; and


•	the issuance of $85 million of 4% Series first mortgage bonds in May 2016. Entergy New Orleans used the proceeds to pay, prior to maturity, its $33.271 million of 5.6% Series first mortgage bonds due September 2024 and to pay, prior to maturity, its $37.772 million of 5.65% Series first mortgage bonds due September 2029.

The increase was offset by:


•	the issuance of $98.7 million of storm costs recovery bonds in July 2015;


•	a $47.8 million capital contribution received from Entergy Corporation in 2016 as compared to an $87.5 million capital contribution received from Entergy Corporation in 2015, both in anticipation of Entergy New Orleans’s purchase of Power Block 1 of the Union Power Station; and


•	an increase of $11.5 million in common equity distributions in 2016. Equity distributions were lower in 2015 in anticipation of the purchase of Power Block 1 of the Union Power Station.

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Management’s Financial Discussion and Analysis

Entergy New Orleans’s financing activities provided $114.9 million of cash in 2015 compared to using $7.7 million of cash in 2014 primarily due to the issuance of $98.7 million of storm cost recovery bonds in July 2015, and an $87.5 million capital contribution in 2015 in anticipation of Entergy New Orleans’s purchase of Power Block 1 of the Union Power Station, partially offset by the purchase of Entergy Louisiana’s Algiers assets in September 2015. The cash portion of the purchase is reflected as a repayment of a long-term payable due to Entergy Louisiana in the cash flow statement. See Note 2 to the financial statements and “Algiers Asset Transfer” below for further discussion of the Algiers asset transfer and accounting for the transaction.

See Note 5 to the financial statements for more details on long-term debt.

Capital Structure

Entergy New Orleans’s capitalization is balanced between equity and debt as shown in the following table. The increase in the debt to capital ratio is primarily due to the issuance of long-term debt in 2016, partially offset by the $47.8 million capital contribution received from Entergy Corporation in March 2016 and an increase in retained earnings.



	December 31, 2016		December 31, 2015
Debt to capital	50.1	%	48.1	%
Effect of excluding securitization bonds	(5.2	%)	(8.1	%)
Debt to capital, excluding securitization bonds (a)	44.9	%	40.0	%
Effect of subtracting cash	(8.0	%)	(10.0	%)
Net debt to net capital, excluding securitization bonds (a)	36.9	%	30.0	%

(a) Calculation excludes the securitization bonds, which are non-recourse to Entergy New Orleans.

Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, long-term debt, including the currently maturing portion, and the long-term payable to Entergy Louisiana. Capital consists of debt, preferred stock without sinking fund, and common equity. Net capital consists of capital less cash and cash equivalents. Entergy New Orleans uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy New Orleans’s financial condition because the securitization bonds are non-recourse to Entergy New Orleans, as more fully described in Note 5 to the financial statements. Entergy New Orleans also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy New Orleans’s financial condition because net debt indicates Entergy New Orleans’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

Entergy New Orleans seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend, or both, in appropriate amounts to maintain the targeted capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy New Orleans may issue incremental debt or reduce dividends, or both, to maintain its targeted capital structure. In addition, in certain infrequent circumstances, such as large transactions that would materially alter the capital structure if financed entirely with debt and reducing dividends, Entergy New Orleans may receive equity contributions to maintain the targeted capital structure.

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Management’s Financial Discussion and Analysis

Uses of Capital

Entergy New Orleans requires capital resources for:


•	construction and other capital investments;


•	working capital purposes, including the financing of fuel and purchased power costs;


•	debt and preferred stock maturities or retirements; and


•	dividend payments.

Following are the amounts of Entergy New Orleans’s planned construction and other capital investments.



	2017		2018		2019
	(In Millions)
Planned construction and capital investment:
Generation		$60		$115		$55
Transmission	5		5		10
Distribution	45		50		40
Other	50		45		40
Total		$160		$215		$145

Following are the amounts of Entergy New Orleans’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.



	2017		2018-2019		2020-2021		After 2021		Total
	(In Millions)
Long-term debt (a)		$31		$63		$85		$703		$882
Operating leases		$2		$4		$3		$2		$11
Purchase obligations (b)		$209		$407		$410		$3,450		$4,476


(a)	Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements.


(b)	Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy New Orleans, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which is discussed in Note 8 to the financial statements.

In addition to the contractual obligations given above, Entergy New Orleans currently expects to contribute approximately $9.9 million to its qualified pension plan and approximately $3.7 million to other postretirement health care and life insurance plans in 2017, although the 2017 required pension contributions will be known with more certainty when the January 1, 2017 valuations are completed, which is expected by April 1, 2017. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.

Also in addition to the contractual obligations, Entergy New Orleans has $138.9 million of unrecognized tax benefits and interest net of unused tax attributes and payments for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy New Orleans includes specific investments such as the New Orleans Power Station discussed below; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including initial investment to support advanced metering; system

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Management’s Financial Discussion and Analysis

improvements; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital. Management provides more information on long-term debt and preferred stock maturities in Notes 5 and 6 to the financial statements.

As a wholly-owned subsidiary of Entergy Corporation, Entergy New Orleans pays dividends from its earnings at a percentage determined monthly. Provisions in Entergy New Orleans’s articles of incorporation relating to preferred stock contains restrictions on the payment of cash dividends or other distributions on its common and preferred stock.

New Orleans Power Station

Gas Infrastructure Rebuild Plan

In September 2016, Entergy Entergy New Orleans submitted to the City Council a request for authorization for Entergy New Orleans to proceed with annual incremental capital funding of $12.5 million for its gas infrastructure rebuild plan, which would replace of all of Entergy New Orleans’s low pressure cast iron, steel, and vintage plastic pipe over a ten-year period commencing in 2017. Entergy New Orleans also proposed that recovery of the investment to fund its gas infrastructure replacement plan be determined in connection with its next base rate case, which is anticipated to be filed in 2018. The City Council has authorized Entergy New Orleans to proceed with its replacement plans at the requested pace until such time that rates resulting from the anticipated 2018 rate case are implemented (approximately 13 months after filing). As a result of the anticipated 2018 rate case, the City Council may establish new overall gas base rates to allow Entergy New Orleans to continue to recover these replacement costs. The City Council has established a schedule for proceedings in advance of the rate case intended to provide an opportunity for evaluation of the gas infrastructure replacement plan that would best serve the public interest and the effect on customers of the approval of any such plan.

Sources of Capital

Entergy New Orleans’s sources to meet its capital requirements include:


•	internally generated funds;


•	cash on hand;


•	debt and preferred stock issuances; and


•	bank financing under new or existing facilities.

Entergy New Orleans may refinance, redeem, or otherwise retire debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.

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Management’s Financial Discussion and Analysis

Entergy New Orleans’s receivables from the money pool were as follows as of December 31 for each of the following years.

See Note 4 to the financial statements for a description of the money pool.

Entergy New Orleans has a credit facility in the amount of $25 million scheduled to expire in November 2018. The credit facility allows Entergy New Orleans to issue letters of credit against $10 million of the borrowing capacity of the facility. As of December 31, 2016, there were no cash borrowings and a $0.8 million letter of credit was outstanding under the facility. In addition, Entergy New Orleans is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations under MISO. As of December 31, 2016, a $6.2 million letter of credit was outstanding under Entergy New Orleans’s letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.

Entergy New Orleans obtained authorization from the FERC through October 2017 for short-term borrowings not to exceed an aggregate amount of $100 million at any time outstanding. See Note 4 to the financial statements for further discussion of Entergy New Orleans’s short-term borrowing limits. The long-term securities issuances of Entergy New Orleans are limited to amounts authorized by the City Council, and the current authorization extends through June 2018.

State and Local Rate Regulation

The rates that Entergy New Orleans charges for electricity and natural gas significantly influence its financial position, results of operations, and liquidity. Entergy New Orleans is regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the City Council, is primarily responsible for approval of the rates charged to customers.

Retail Rates

See “Algiers Asset Transfer” below for discussion of the transfer from Entergy Louisiana to Entergy New Orleans of certain assets that serve Algiers customers.


•	a $9.3 million base rate revenue increase to be phased in on a levelized basis over four years;


•	recovery of an additional $853 thousand annually through a MISO recovery rider; and


•	the adoption of a four-year formula rate plan requiring the filing of annual evaluation reports in May of each year, commencing May 2015, with resulting rates being implemented in October of each year. The formula rate plan includes a midpoint target authorized return on common equity of 9.95% with a +/- 40 basis point bandwidth.

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costs related to the commencement of commercial operation of the Ninemile 6 generating unit and a purchased power capacity cost recovery rider. The monthly Ninemile 6 cost recovery interim rider was implemented in December 2014 to initially collect $915 thousand from Entergy Louisiana customers in the Algiers area.

As a provision of the settlement agreement approved by the City Council in May 2015 providing for the Algiers asset transfer, it was agreed that, with limited exceptions, no action may be taken with respect to Entergy New Orleans’s base rates until rates are implemented from a base rate case that must be filed for its electric and gas operations in 2018. This provision eliminated the formula rate plan applicable to Algiers operations. The limited exceptions include continued implementation of the remaining two years of the four-year phased-in rate increase for the Algiers area and certain exceptional cost increases or decreases in the base revenue requirement. An additional provision of the settlement agreement allows for continued recovery of the revenue requirement associated with the capacity and energy from Ninemile 6 received by Entergy New Orleans under a power purchase agreement with Entergy Louisiana (Algiers PPA). The settlement authorizes Entergy New Orleans to recover the remaining revenue requirement related to the Algiers PPA through base rates charged to Algiers customers. The settlement also provided for continued implementation of the Algiers MISO recovery rider.

A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs. In September 2009 the City Council approved the energy efficiency programs filed by Entergy New Orleans. The rate settlement provides an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provides a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs. In October 2013 the City Council approved the extension of the Energy Smart program through December 2014. The City Council approved the use of $3.5 million of rough production cost equalization funds for program costs. In addition, Entergy New Orleans will be allowed to recover its lost contribution to fixed costs and to earn an incentive for meeting program goals. In January 2015 the City Council approved extending the Energy Smart program through March 2015 and using $1.2 million of rough production cost equalization funds to cover program costs for the extended period. Additionally, the City Council approved funding for the Energy Smart program from April 2015 through March 2017 using the remainder of the approximately $12.8 million of 2014 rough production cost equalization funds, with any remaining costs being recovered through the fuel adjustment clause. This funding methodology was modified in November 2015 when the City Council directed Entergy New Orleans to use a combination of guaranteed customer savings related to a prior agreement with the City Council and rough production cost equalization funds to cover program costs prior to recovering any costs through the fuel adjustment clause. In February 2017, Entergy New Orleans filed a proposed implementation

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plan for the Energy Smart program from April 2017 through March 2020. As part of the proposal, Entergy New Orleans requested that the City Council identify its desired level of funding for the program during this time period and approve a cost recovery mechanism.

Fuel and Purchased Power Cost Recovery

Internal Restructuring

It is currently contemplated that Entergy New Orleans would undertake a multi-step restructuring, which would include the following:


•	Entergy New Orleans would redeem its outstanding preferred stock at a price of approximately $21 million, which includes an expected call premium of approximately $819,000, plus any accumulated and unpaid dividends.


•	Entergy New Orleans would convert from a Louisiana corporation to a Texas corporation.

•


•	Entergy New Orleans will contribute the membership interests in Entergy New Orleans Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy

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Corporation). As a result of the contribution, Entergy New Orleans Power will be a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.


•	Entergy New Orleans will change its name to Entergy Utility Group, Inc., and Entergy New Orleans Power will then change its name to Entergy New Orleans, LLC.

Advanced Metering Infrastructure (AMI) Filing

In October 2016, Entergy New Orleans filed an application seeking a finding from the City Council that Entergy New Orleans’s deployment of advanced electric and gas metering infrastructure is in the public interest. Entergy New Orleans proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy New Orleans’s modernized power grid. The filing identified a number of quantified and unquantified benefits, and Entergy New Orleans provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $101 million. Entergy New Orleans also sought to continue to include in rate base the remaining book value at December 31, 2015, approximately $21 million, of the existing electric meters and also to depreciate those assets using current depreciation rates. Entergy New Orleans proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Subject to approval by the City Council, deployment of the information technology infrastructure is expected to begin in 2017 and deployment of the communications network is expected to begin in 2018. Entergy New Orleans proposes to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022. In January 2017 the City Council approved a procedural schedule that provides for a hearing in July 2017.

Algiers Asset Transfer

Storm Cost Recovery

In August 2012, Hurricane Isaac caused extensive damage to Entergy New Orleans’s service area. The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages. In January 2015 the City Council issued a resolution approving the terms of a joint agreement in principle filed by Entergy New Orleans, Entergy Louisiana, and the City Council Advisors determining, among other things, that Entergy New Orleans’s prudently-incurred storm recovery costs were $49.3 million, of which $31.7 million, net of reimbursements from the storm reserve escrow account, remained recoverable from Entergy New Orleans’s electric customers. The resolution also directed Entergy New Orleans to file an application to securitize the unrecovered Council-approved storm recovery costs of $31.7 million pursuant to the Louisiana Electric Utility Storm Recovery Securitization Act (Louisiana Act 64). In addition, the resolution found that it was reasonable for Entergy New Orleans to include in the principal amount of its potential securitization the costs to fund and replenish Entergy New Orleans’s storm reserve in an amount that achieved the Council-approved funding level of $75 million. In January

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2015, in compliance with that directive, Entergy New Orleans filed with the City Council an application requesting that the City Council grant a financing order authorizing the financing of Entergy New Orleans’s storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 64. In May 2015 the parties entered into an agreement in principle and the City Council issued a financing order authorizing Entergy New Orleans to issue storm recovery bonds in the aggregate amount of $98.7 million, including $31.8 million for recovery of Entergy New Orleans’s Hurricane Isaac storm recovery costs, including carrying costs, $63.9 million to fund and replenish Entergy New Orleans’s storm reserve, and approximately $3 million for estimated up-front financing costs associated with the securitization. See Note 5 to the financial statements for discussion of the issuance of the securitization bonds in July 2015.

Show Cause Order

In July 2016 the City Council approved the issuance of a show cause order, which directs Entergy New Orleans to make a filing on or before September 29, 2016 to demonstrate the reasonableness of its actions or positions with regard to certain issues in four existing dockets that relate to Entergy New Orleans’s: (i) storm hardening proposal; (ii) 2015 integrated resource plan; (iii) gas infrastructure rebuild proposal; and (iv) proposed sizing of the New Orleans Power Station and its community outreach prior to the filing. In September 2016, Entergy New Orleans filed its response to the City Council’s show cause order. The City Council has not established any further procedural schedule with regard to this proceeding.

Federal Regulation

Nuclear Matters

See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.

Environmental Risks

Entergy New Orleans’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous solid wastes, and other environmental matters. Management believes that Entergy New Orleans is in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

The preparation of Entergy New Orleans’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and there is the potential for future changes in the assumptions and measurements that could produce estimates that would have a material impact on the presentation of Entergy New Orleans’s financial position or results of operations.

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Management’s Financial Discussion and Analysis

Utility Regulatory Accounting

Unbilled Revenue

Taxation and Uncertain Tax Positions

Qualified Pension and Other Postretirement Benefits

Entergy New Orleans’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.

Cost Sensitivity

The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).



Actuarial Assumption	Change in Assumption	Impact on 2017 Qualified Pension Cost	Impact on 2016 Projected Qualified Benefit Obligation
		Increase/(Decrease)
Discount rate	(0.25%)	$450		$6,312
Rate of return on plan assets	(0.25%)	$373	$-
Rate of increase in compensation	0.25%	$146		$775

The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).



Actuarial Assumption	Change in Assumption	Impact on 2017 Postretirement Benefit Cost		Impact on 2016 Accumulated Postretirement Benefit Obligation
		Increase/(Decrease)
Discount rate	(0.25%)		$85	$1,465
Health care cost trend	0.25%		$168	$1,185

Each fluctuation above assumes that the other components of the calculation are held constant.

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Management’s Financial Discussion and Analysis

Costs and Funding

Total qualified pension cost for Entergy New Orleans in 2016 was $5.6 million. Entergy New Orleans anticipates 2017 qualified pension cost to be $5.1 million. In 2016, Entergy New Orleans refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $1.7 million. Entergy New Orleans contributed $10.7 million to its pension plans in 2016 and estimates 2017 pension contributions will be approximately $9.9 million, although the 2017 required pension contributions will be known with more certainty when the January 1, 2017 valuations are completed, which is expected by April 1, 2017.

Total postretirement health care and life insurance benefit income for Entergy New Orleans in 2016 was $2.8 million. Entergy New Orleans expects 2017 postretirement health care and life insurance benefit income of approximately $2.5 million. In 2016, Entergy New Orleans refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $548 thousand. Entergy New Orleans contributed $4.3 million to its other postretirement plans in 2016 and estimates 2017 contributions will be approximately $3.7 million.

The retirement and mortality rate assumptions are reviewed every three-to-five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans. The 2014 actuarial study reviewed plan experience from 2010 through 2013. As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies. These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of $15 million in the qualified pension benefit obligation and $3.6 million in the accumulated postretirement obligation. The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $2.2 million and other postretirement cost by approximately $0.4 million. In 2016, the mortality projection scale was updated to MP-2016, with no change in the base mortality table assumption.

Federal Healthcare Legislation

Other Contingencies

New Accounting Pronouncements

See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Entergy New Orleans, Inc. and Subsidiaries

New Orleans, Louisiana

We have audited the accompanying consolidated balance sheets of Entergy New Orleans, Inc. and Subsidiaries (the “Company”) as of December 31, 2016 and 2015, and the related consolidated income statements, consolidated statements of cash flows, and consolidated statements of changes in common equity (pages 397 through 402 and applicable items in pages 59 through 232) for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy New Orleans, Inc. and Subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 24, 2017

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ENTERGY NEW ORLEANS, INC. AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENTS

	For the Years Ended December 31,
	2016			2015			2014
	(In Thousands)

OPERATING REVENUES
Electric		$586,820			$584,322			$625,088
Natural gas	78,643			87,124			110,104
TOTAL	665,463			671,446			735,192

OPERATING EXPENSES
Operation and Maintenance:
Fuel, fuel-related expenses, and gas purchased for resale	40,489			96,307			178,347
Purchased power	299,551			277,851			271,159
Other operation and maintenance	117,471			119,087			131,549
Taxes other than income taxes	48,078			46,660			49,964
Depreciation and amortization	51,737			43,205			45,426
Other regulatory charges - net	8,258			3,366			791
TOTAL	565,584			586,476			677,236

OPERATING INCOME	99,879			84,970			57,956

OTHER INCOME
Allowance for equity funds used during construction	1,178			1,404			1,750
Interest and investment income	256			73			95
Miscellaneous - net	(3,144		)	339			614
TOTAL	(1,710		)	1,816			2,459

INTEREST EXPENSE
Interest expense	21,061			17,312			16,820
Allowance for borrowed funds used during construction	(446		)	(641		)	(885		)
TOTAL	20,615			16,671			15,935

INCOME BEFORE INCOME TAXES	77,554			70,115			44,480

Income taxes	28,705			25,190			13,450

NET INCOME	48,849			44,925			31,030

Preferred dividend requirements and other	965			965			965

EARNINGS APPLICABLE TO COMMON STOCK		$47,884			$43,960			$30,065

See Notes to Financial Statements.

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ENTERGY NEW ORLEANS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
	2016			2015			2014
	(In Thousands)
OPERATING ACTIVITIES
Net income		$48,849			$44,925			$31,030
Adjustments to reconcile net income to net cash flow provided by operating activities:
Depreciation and amortization	51,737			43,205			45,426
Deferred income taxes, investment tax credits, and non-current taxes accrued	140,283			22,180			24,380
Changes in assets and liabilities:
Receivables	(3,888		)	7,878			21,098
Fuel inventory	71			1,104			(17		)
Accounts payable	15,434			2,738			(7,702		)
Interest accrued	534			1,270			(63		)
Deferred fuel costs	(33,839		)	(182		)	5,409
Other working capital accounts	2,480			(2,995		)	(18,030		)
Provisions for estimated losses	4,326			58,310			10,877
Other regulatory assets	(2,784		)	(70,471		)	(41,517		)
Pension and other postretirement liabilities	(6,859		)	(18,831		)	29,942
Other assets and liabilities	(11,133		)	15,937			(11,900		)
Net cash flow provided by operating activities	205,211			105,068			88,933
INVESTING ACTIVITIES
Construction expenditures	(90,512		)	(91,928		)	(70,903		)
Allowance for equity funds used during construction	1,178			1,404			1,750
Payment for purchase of plant	(237,335		)	—			—
Investments in affiliates	(38		)	—			—
Changes in money pool receivable - net	1,579			(15,352		)	4,295
Payments to storm reserve escrow account	(438		)	(68,886		)	(7,525		)
Receipts from storm reserve escrow account	3			5,922			—
Changes in securitization account	2,882			(4,620		)	—
Net cash flow used in investing activities	(322,681		)	(173,460		)	(72,383		)
FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	240,604			95,367			—
Retirement of long-term debt	(132,526		)	—			—
Repayment of long-term payable due to Entergy Louisiana	(4,973		)	(59,610		)	—
Capital contributions from parent	47,750			87,500			—
Dividends paid:
Common stock	(18,720		)	(7,250		)	(6,000		)
Preferred stock	(965		)	(965		)	(965		)
Other	492			(163		)	(685		)
Net cash flow provided by (used in) financing activities	131,662			114,879			(7,650		)
Net increase in cash and cash equivalents	14,192			46,487			8,900
Cash and cash equivalents at beginning of period	88,876			42,389			33,489
Cash and cash equivalents at end of period		$103,068			$88,876			$42,389
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized		$19,317			$14,951			$15,877
Income taxes		($85,962	)		$8,110			$4,871
See Notes to Financial Statements.

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ENTERGY NEW ORLEANS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS

	December 31,
	2016			2015
	(In Thousands)

CURRENT ASSETS
Cash and cash equivalents
Cash		$28			$1,068
Temporary cash investments	103,040			87,808
Total cash and cash equivalents	103,068			88,876
Securitization recovery trust account	1,738			4,620
Accounts receivable:
Customer	43,536			34,627
Allowance for doubtful accounts	(3,059		)	(268		)
Associated companies	16,811			23,248
Other	5,926			3,753
Accrued unbilled revenues	18,254			17,799
Total accounts receivable	81,468			79,159
Deferred fuel costs	4,818			—
Fuel inventory - at average cost	1,841			1,912
Materials and supplies - at average cost	8,416			13,244
Prepayments and other	10,966			10,263
TOTAL	212,315			198,074

OTHER PROPERTY AND INVESTMENTS
Non-utility property at cost (less accumulated depreciation)	1,016			1,016
Storm reserve escrow account	81,437			81,002
Other	7,160			3
TOTAL	89,613			82,021

UTILITY PLANT
Electric	1,258,934			1,051,239
Natural gas	240,408			232,780
Construction work in progress	24,975			29,027
TOTAL UTILITY PLANT	1,524,317			1,313,046
Less - accumulated depreciation and amortization	604,825			648,081
UTILITY PLANT - NET	919,492			664,965

DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Deferred fuel costs	4,080			4,080
Other regulatory assets (includes securitization property of $82,272 as of December 31, 2016 and $91,599 as of December 31, 2015)	268,106			265,322
Other	963			682
TOTAL	273,149			270,084

TOTAL ASSETS		$1,494,569			$1,215,144

See Notes to Financial Statements.

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ENTERGY NEW ORLEANS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY
	December 31,
	2016		2015
	(In Thousands)

CURRENT LIABILITIES
Payable due to Entergy Louisiana		$2,104		$4,973
Accounts payable:
Associated companies	39,260		37,467
Other	35,920		21,471
Customer deposits	28,667		28,392
Interest accrued	5,443		4,909
Deferred fuel costs	—		29,021
Other	11,415		6,216
TOTAL CURRENT LIABILITIES	122,809		132,449

NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued	334,953		214,061
Accumulated deferred investment tax credits	622		753
Regulatory liability for income taxes - net	9,074		13,199
Asset retirement cost liabilities	2,875		2,687
Accumulated provisions	88,513		84,187
Pension and other postretirement liabilities	36,750		43,609
Long-term debt (includes includes securitization bonds of $84,776 as of December 31, 2016 and $95,867 as of December 31, 2015)	428,467		317,380
Long-term payable due to Entergy Louisiana	18,423		20,527
Gas system rebuild insurance proceeds	447		12,788
Other	4,910		3,692
TOTAL NON-CURRENT LIABILITIES	925,034		712,883

Commitments and Contingencies

Preferred stock without sinking fund	19,780		19,780

COMMON EQUITY
Common stock, $4 par value, authorized 10,000,000 shares; issued and outstanding 8,435,900 shares in 2016 and 2015	33,744		33,744
Paid-in capital	171,544		123,794
Retained earnings	221,658		192,494
TOTAL	426,946		350,032

TOTAL LIABILITIES AND EQUITY		$1,494,569		$1,215,144

See Notes to Financial Statements.

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ENTERGY NEW ORLEANS, INC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY
For the Years Ended December 31, 2016, 2015, and 2014

	Common Equity
	Common Stock		Paid-in Capital		Retained Earnings			Total
	(In Thousands)

Balance at December 31, 2013		$33,744		$36,294		$136,245			$206,283
Net income	—		—		31,030			31,030
Net income attributable to Entergy Louisiana	—		—		(2,323		)	(2,323		)
Common stock dividends	—		—		(6,000		)	(6,000		)
Preferred stock dividends	—		—		(965		)	(965		)
Balance at December 31, 2014		$33,744		$36,294		$157,987			$228,025
Net income	—		—		44,925			44,925
Net income attributable to Entergy Louisiana	—		—		(2,203		)	(2,203		)
Capital contributions from parent	—		87,500		—			87,500
Common stock dividends	—		—		(7,250		)	(7,250		)
Preferred stock dividends	—		—		(965		)	(965		)
Balance at December 31, 2015		$33,744		$123,794		$192,494			$350,032
Net income	—		—		48,849			48,849
Capital contributions from parent	—		47,750		—			47,750
Common stock dividends	—		—		(18,720		)	(18,720		)
Preferred stock dividends	—		—		(965		)	(965		)
Balance at December 31, 2016		$33,744		$171,544		$221,658			$426,946

See Notes to Financial Statements.

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ENTERGY NEW ORLEANS, INC. AND SUBSIDIARIES
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON

	2016		2015		2014		2013		2012
	(In Thousands)

Operating revenues		$665,463		$671,446		$735,192		$659,746		$605,014
Net income		$48,849		$44,925		$31,030		$12,608		$19,878
Total assets		$1,494,569		$1,215,144		$1,014,916		$964,482		$953,308
Long-term obligations (a)		$466,670		$357,687		$323,280		$318,034		$215,619

(a) Includes long-term debt (including the long-term payable to Entergy Louisiana and excluding currently maturing debt) and preferred stock without sinking fund.

	2016		2015		2014		2013		2012
	(Dollars In Millions)

Electric Operating Revenues:
Residential		$231		$220		$230		$221		$195
Commercial	206		186		196		194		174
Industrial	33		30		33		35		31
Governmental	69		64		67		69		65
Total retail	539		500		526		519		465
Sales for resale:
Associated companies	30		66		78		27		45
Non-associated companies	3		—		4		—		—
Other	15		18		17		19		13
Total		$587		$584		$625		$565		$523

Billed Electric Energy Sales (GWh):
Residential	2,231		2,301		2,262		2,152		2,060
Commercial	2,268		2,257		2,181		2,130		2,105
Industrial	441		463		455		484		487
Governmental	794		825		783		778		806
Total retail	5,734		5,846		5,681		5,544		5,458
Sales for resale:
Associated companies	1,071		1,644		1,379		517		1,004
Non-associated companies	141		11		18		14		9
Total	6,946		7,501		7,078		6,075		6,471

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MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

Results of Operations

Net Income

2016 Compared to 2015

Net income increased $37.9 million primarily due to lower other operation and maintenance expenses, the asset write-off of its receivable associated with the Spindletop gas storage facility in 2015, and higher net revenue.

2015 Compared to 2014

Net income decreased $5.2 million primarily due to the asset write-off of its receivable associated with the Spindletop gas storage facility and higher other operation and maintenance expenses, partially offset by higher net revenue and a lower effective tax rate.

Net Revenue

2016 Compared to 2015



	Amount
	(In Millions)

2015 net revenue		$637.2
Reserve equalization	14.3
Purchased power capacity	12.4
Transmission revenue	7.0
Retail electric price	5.4
Net wholesale	(27.8		)
Other	(4.3		)
2016 net revenue		$644.2

The reserve equalization variance is primarily due to a reduction in reserve equalization expense primarily due to changes in the Entergy System generation mix compared to the same period in 2015 as a result of the execution of a new purchased power agreement and Entergy Mississippi’s exit from the System Agreement, each in November 2015, and Entergy Texas’s exit from the System Agreement in August 2016. See Note 2 to the financial statements for a discussion of the System Agreement.

The purchased power capacity variance is primarily due to decreased expenses due to the termination of the purchased power agreements between Entergy Louisiana and Entergy Texas in August 2016, as well as capacity cost changes for ongoing purchased power capacity contracts.

The transmission revenue variance is primarily due to an increase in Attachment O rates charged by MISO to transmission customers and a settlement of Attachment O rates previously billed to transmission customers by MISO.

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The retail electric price variance is primarily due to the implementation of the transmission cost recovery factor rider, as approved by the PUCT and implemented in September 2016, and the increase in the distribution cost recovery rider, as approved by the PUCT and implemented in January 2016. This increase was partially offset by a decrease in energy efficiency revenues. See Note 2 to the financial statements for further discussion of the transmission cost recovery factor rider and distribution cost recovery factor rider filings.

The net wholesale revenue variance is primarily due to lower capacity revenues resulting from the termination of the purchased power agreements between Entergy Louisiana and Entergy Texas in August 2016.

2015 Compared to 2014



	Amount
	(In Millions)

2014 net revenue		$611.7
Volume/weather	17.1
Retail electric price	11.4
Transmission revenue	4.0
Purchased power capacity	(5.6		)
Other	(1.4		)
2015 net revenue		$637.2

The volume/weather variance is primarily due to an increase in residential and commercial sales as a result of a 2% increase in the average number of customers, partially offset by a decrease in sales to industrial customers and the effect of less favorable weather on residential sales. The decrease in industrial sales is primarily due to extended seasonal outages for existing large refinery customers, partially offset by new customers in the transportation industry.

The retail electric price variance is primarily due to an annual base rate increase of $18.5 million, effective April 2014, as a result of the PUCT’s order in the September 2013 rate case, the implementation of the distribution cost recovery rider, as approved by the PUCT, and an increase in the energy efficiency rider, as approved by the PUCT, each effective January 2015. Energy efficiency revenues are largely offset by costs included in other operation and maintenance expenses and have a minimal effect on net income. See Note 2 to the financial statements for further discussion of the rate case.

The transmission revenue variance is primarily due to an increase in the amount of transmission revenues allocated by MISO.

The purchased power capacity variance is primarily due to increased expenses due to contract changes and price changes for ongoing purchased power capacity.

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Other Income Statement Variances

2016 Compared to 2015

Other operation and maintenance expenses decreased primarily due to:


•	a decrease of $11.2 million in fossil-fueled generation expenses primarily due to an overall lower scope of work performed in 2016 as compared to 2015;


•	a decrease of $7 million in transmission expenses primarily due to lower transmission equalization expenses, as allocated under the System Agreement, as compared to the same period in 2015 as a result of Entergy Mississippi’s exit from the System Agreement in November 2015 and Entergy Texas’s exit from the System Agreement in August 2016;

•

a decrease of $5.7 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs;


•	the write-off in the third quarter 2015 of $4.3 million of rate case expenses and acquisition costs related to the proposed Union Power Station acquisition upon Entergy Texas’s withdrawal of its 2015 rate case and dismissal of its certificate of convenience and necessity filing; and


•	a decrease of $4.2 million in energy efficiency costs.

The asset write-off variance is due to the $23.5 million ($15.3 million net-of-tax) write-off recorded in 2015 of the receivable associated with the Spindletop gas storage facility. See Note 2 to the financial statements for discussion of the write-off.

2015 Compared to 2014

Other operation and maintenance expenses increased primarily due to:


•	an increase of $7.5 million in transmission expenses primarily due to an increase in the amount of transmission costs allocated by MISO;


•	a net increase of $6.4 million in energy efficiency costs for fixed costs collected from customers; and


•	the write-off in the third quarter 2015 of $4.3 million of rate case expenses and acquisition costs related to the proposed Union Power Station acquisition upon Entergy Texas’s withdrawal of its 2015 rate case and dismissal of its certificate of convenience and necessity filing.

Income Taxes

The effective income tax rates for 2016, 2015, and 2014 were 37.0%, 34.9%, and 39.9%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.

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Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2016, 2015, and 2014 were as follows:



	2016			2015			2014
	(In Thousands)
Cash and cash equivalents at beginning of period		$2,182			$30,441			$46,488

Net cash provided by (used in):
Operating activities	306,601			284,268			315,164
Investing activities	(330,191		)	(315,293		)	(186,540		)
Financing activities	27,589			2,766			(144,671		)
Net increase (decrease) in cash and cash equivalents	3,999			(28,259		)	(16,047		)

Cash and cash equivalents at end of period		$6,181			$2,182			$30,441

Operating Activities

Net cash flow provided by operating activities increased $22.3 million in 2016 primarily due to increased net income and a decrease of $31.8 million in income tax payments in 2016. Entergy Texas had income tax payments in 2016 and 2015 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The income tax payments in 2016 resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit; whereas, the income tax payments in 2015 resulted primarily from the results of operations and the reversal of taxable temporary differences. See Note 3 to the financial statements for a discussion of the income tax audit. The increase was partially offset by an increase of $5.2 million in interest paid in 2016 due to the issuance of $125 million of 2.55% Series first mortgage bonds in March 2016 and the timing of collections from customers.

Net cash flow provided by operating activities decreased $30.9 million in 2015 primarily due to:


•	income tax payments of $60.4 million in 2015. Entergy Texas had income tax payments in 2015 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The income tax payments in 2015 resulted primarily from the results of operations and the reversal of taxable temporary differences; and

•

a net decrease of $24 million related to the System Agreement bandwidth remedy payments in 2014. In the second quarter 2014, Entergy Texas received total payments of $48.6 million as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period, of which $24.6 million was refunded to Entergy Texas customers as of December 31, 2014.

The decrease was partially offset by an increase due to the timing of recovery of fuel and purchased power costs.

Investing Activities

Net cash flow used in investing activities increased $14.9 million in 2016 primarily due to increases of $27.7 million in transmission construction expenditures and $11.7 million in distribution construction expenditures primarily due to a greater scope of projects in 2016 as compared to the same period in 2015. The increase was partially offset by a $21.4 million decrease in fossil-fueled generation construction expenditures primarily due to a decreased scope of work performed during plant outages in 2016 as compared to the same period in 2015.

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Net cash flow used in investing activities increased $128.8 million in 2015 primarily due to:


•	an increase in transmission construction expenditures primarily due to a greater scope of projects in 2015;


•	an increase in information technology capital expenditures due to various technology projects and upgrades in 2015; and


•	an increase in fossil-fueled generation construction expenditures primarily due to Lewis Creek dam repairs in 2015 and a greater scope of work done during outages in 2015.

Financing Activities

Net cash flow provided by financing activities increased $24.8 million in 2016 primarily due to the retirement of $200 million of 3.6% Series first mortgage bonds in June 2015 and the issuance of $125 million of 2.55% Series first mortgage bonds in March 2016, partially offset by the issuance of $250 million of 5.15% Series first mortgage bonds in May 2015 and money pool activity.

Decreases in Entergy Texas’s payable to the money pool are a use of cash flow, and Entergy Texas’s payable to the money pool decreased by $22.1 million in 2016 compared to increasing by $22.1 million in 2015. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.

Entergy Texas’s financing activities provided $2.8 million of cash in 2015 compared to using $144.7 million of cash in 2014 primarily due to the following activity:


•	the issuance of $250 million of 5.15% Series first mortgage bonds in May 2015;


•	the retirement, prior to maturity, of $150 million of 7.875% Series first mortgage bonds in June 2014;


•	$70 million in common stock dividends paid in 2014. Entergy Texas did not pay dividends to its parent in 2015 primarily because of lower operating cash flows and higher capital expenditures, each discussed above; and


•	money pool activity.

These activities were partially offset by the retirement of $200 million of 3.6% Series first mortgage bonds in June 2015 and the issuance of $135 million of 5.625% Series first mortgage bonds in May 2014.

Increases in Entergy Texas’s payable to the money pool are a source of cash flow, and Entergy Texas’s payable to the money pool increased by $22.1 million in 2015.

Capital Structure

Entergy Texas’s capitalization is balanced between equity and debt, as shown in the following table.



	December 31, 2016		December 31, 2015
Debt to capital	58.5	%	60.2	%
Effect of excluding the securitization bonds	(8.3	%)	(10.4	%)
Debt to capital, excluding securitization bonds (a)	50.2	%	49.8	%
Effect of subtracting cash	(0.1	%)	—	%
Net debt to net capital, excluding securitization bonds (a)	50.1	%	49.8	%



(a)	Calculation excludes the securitization bonds, which are non-recourse to Entergy Texas.

Net debt consists of debt less cash and cash equivalents. Debt consists of long-term debt, including the currently maturing portion. Capital consists of debt and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Texas uses the debt to capital ratios excluding securitization bonds in analyzing its financial

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condition and believes they provide useful information to its investors and creditors in evaluating Entergy Texas’s financial condition because the securitization bonds are non-recourse to Entergy Texas, as more fully described in Note 5 to the financial statements. Entergy Texas also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Texas’s financial condition because net debt indicates Entergy Texas’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

Entergy Texas seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend, or both, in appropriate amounts to maintain the targeted capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Texas may issue incremental debt or reduce dividends, or both, to maintain its targeted capital structure. In addition, in certain infrequent circumstances, such as large transactions that would materially alter the capital structure if financed entirely with debt and reducing dividends, Entergy Texas may receive equity contributions to maintain the targeted capital structure.

Uses of Capital

Entergy Texas requires capital resources for:


•	construction and other capital investments;


•	debt maturities or retirements;


•	working capital purposes, including the financing of fuel and purchased power costs; and


•	dividend and interest payments.

Following are the amounts of Entergy Texas’s planned construction and other capital investments.



	2017		2018		2019
	(In Millions)
Planned construction and capital investment:
Generation		$85		$180		$375
Transmission	115		180		210
Distribution	100		125		135
Other	50		30		15
Total		$350		$515		$735

Following are the amounts of Entergy Texas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.



	2017		2018-2019		2020-2021		After 2021		Total
	(In Millions)
Long-term debt (a)		$150		$775		$416		$1,068		$2,409
Operating leases (b)		$5		$9		$4		$2		$20
Purchase obligations (c)		$269		$558		$544		$811		$2,182


(a)	Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements.


(b)	Does not include power purchase agreements that are accounted for as leases that are included in purchase obligations.


(c)	Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Texas, it primarily includes unconditional fuel and purchased power obligations.

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In addition to the contractual obligations given above, Entergy Texas expects to contribute approximately $17 million to its qualified pension plans and approximately $3.2 million to other postretirement health care and life insurance plans in 2017, although the 2017 required pension contributions will be known with more certainty when the January 1, 2017 valuations are completed, which is expected by April 1, 2017. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.

Also in addition to the contractual obligations, Entergy Texas has $15.6 million of unrecognized tax benefits and interest net of unused tax attributes and payments for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Texas includes specific investments such as the Montgomery County Power Station discussed below; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including initial investment to support advanced metering; system improvements; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital. Management provides more information on long-term debt in Note 5 to the financial statements.

As discussed above in “Capital Structure,” Entergy Texas routinely evaluates its ability to pay dividends to Entergy Corporation from its earnings.

Sources of Capital

Entergy Texas’s sources to meet its capital requirements include:


•	internally generated funds;


•	cash on hand;


•	debt or preferred stock issuances; and


•	bank financing under new or existing facilities.

Entergy Texas may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest and dividend rates are favorable.

All debt and common and preferred stock issuances by Entergy Texas require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in its bond indenture and other agreements. Entergy Texas has sufficient capacity under these tests to meet its foreseeable capital needs.

Entergy Texas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.

See Note 4 to the financial statements for a description of the money pool.

Entergy Texas has a credit facility in the amount of $150 million scheduled to expire in August 2021. The credit facility allows Entergy Texas to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2016, there were no cash borrowings and $4.7 million of letters of credit outstanding under the credit facility. In addition, Entergy Texas is a party to an uncommitted letter of credit facility as a means to post collateral

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to support its obligations under MISO. As of December 31, 2016, a $14.7 million letter of credit was outstanding under Entergy Texas’s letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.

Entergy Texas obtained authorizations from the FERC through October 2017 for short-term borrowings, not to exceed an aggregate amount of $200 million at any time outstanding, and long-term borrowings and security issuances. See Note 4 to the financial statements for further discussion of Entergy Texas’s short-term borrowing limits.

Montgomery County Power Station

State and Local Rate Regulation and Fuel-Cost Recovery

The rates that Entergy Texas charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Texas is regulated and the rates charged to its customers are determined in regulatory proceedings. The PUCT, a governmental agency, is primarily responsible for approval of the rates charged to customers.

Filings with the PUCT

2011 Rate Case

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charge to recognize that assets associated with Hurricane Rita, financially-based incentive compensation, and fuel recovery are no longer probable of recovery. Entergy Texas continues to believe that it is entitled to recover these prudently incurred costs, however, and it filed a motion for rehearing regarding these and several other issues in the PUCT’s order on October 4, 2012. Several other parties also filed motions for rehearing of the PUCT’s order. The PUCT subsequently denied rehearing of substantive issues. Several parties, including Entergy Texas, appealed various aspects of the PUCT’s order to the Travis County District Court. A hearing was held in July 2014. In October 2014 the Travis County District Court issued an order upholding the PUCT’s decision except as to the line-loss factor issue referenced above, which was found in favor of Entergy Texas. In November 2014, Entergy Texas and other parties, including the PUCT, appealed the Travis County District Court decision to the Third Court of Appeals. Briefs were filed by the appealing and responding parties in the first half of 2015. Oral argument before the court panel was held in September 2015. In April 2016 the Third Court of Appeals issued its opinion affirming the District Court’s decision on all points. Entergy Texas petitioned the Texas Supreme Court to hear its appeal of the Third Court’s ruling. That petition is pending.

2013 Rate Case

Other Filings

In September 2014, Entergy Texas filed for a distribution cost recovery factor (DCRF) rider based on a law that was passed in 2011 allowing for the recovery of increases in capital costs associated with distribution plant. Entergy Texas requested collection of approximately $7 million annually from retail customers. The parties reached a unanimous settlement authorizing recovery of $3.6 million annually commencing with usage on and after January 1, 2015. A State Office of Administrative Hearings ALJ issued an order in December 2014 authorizing this recovery on an interim basis and remanded the case to the PUCT. In February 2015 the PUCT entered a final order, making the settlement final and the interim rates permanent. In September 2015, Entergy Texas filed to amend its distribution cost recovery factor rider. Entergy Texas requested an increase in recovery under the rider of $6.5 million, for a total collection of $10.1 million annually from retail customers. In October 2015 intervenors and PUCT staff filed testimony opposing, in part, Entergy Texas’s request. In November 2015 Entergy Texas and the parties filed an unopposed settlement agreement and supporting documents. The settlement established an annual revenue requirement of $8.65 million for the amended

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DCRF rider, with the resulting rates effective for usage on and after January 1, 2016. The PUCT approved the settlement agreement in February 2016.

In September 2015, Entergy Texas filed for a transmission cost recovery factor (TCRF) rider requesting a $13 million increase, incremental to base rates. Testimony was filed in November 2015, with the PUCT staff and other parties proposing various disallowances involving, among other things, MISO charges, vegetation management costs, and bad debt expenses that would reduce the requested increase by approximately $2 million. In addition to those recommended disallowances, a number of parties recommended that Entergy Texas’s request be reduced by an additional $3.4 million to account for load growth since base rates were last set. A hearing on the merits was held in December 2015. In February 2016 a State Office of Administrative Hearings ALJ issued a proposal for decision recommending that the PUCT disallow approximately $2 million from Entergy Texas’s $13 million request, but recommending that the PUCT not accept the load growth offset. In April 2016 the PUCT voted to allow Entergy Texas’s TCRF rates to become effective as of April 14, 2016 when those rates are finally approved, but did not otherwise address the proposal for decision. In May 2016 the PUCT deferred final consideration of Entergy Texas’s TCRF application and opened the record to consider additional evidence to be provided by Entergy Texas and potentially other parties regarding the rate-making treatment of spare transmission-level transformers that are transferred among the Utility operating companies. In June 2016, the PUCT indicated that it would take up in a future rulemaking project the issue of whether a load growth adjustment should apply to a TCRF. In July 2016 the PUCT issued an order generally accepting the proposal for decision but declining to adjust the TCRF baseline in two instances as recommended by the ALJ, which resulted in a total annual allowance of approximately $10.5 million. The PUCT also ordered its staff and Entergy Texas to track all spare autotransformer transfers going forward so that it could address the appropriate accounting treatment and prudence of such transfers in Entergy Texas’s next base rate case. Entergy Texas implemented the TCRF rider beginning with September 2016 bills.

In September 2016, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The proposed amended TCRF rider is designed to collect approximately $29.5 million annually from Entergy Texas’s retail customers. This amount includes the approximately $10.5 million annually that Entergy Texas is currently authorized to collect through the TCRF rider, as discussed above. In September 2016 the PUCT suspended the effective date of the tariff change to March 2017. In December 2016, Entergy Texas and the PUCT reached a settlement agreeing to the amended TCRF annual revenue requirement of $29.5 million. This settlement was developed concurrently with the 2016 fuel reconciliation stipulation and settlement agreement discussed below, and the terms and conditions in both settlements are interdependent. PUCT action on the stipulations and settlement agreements is pending.

Fuel and Purchased Power Cost Recovery

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Texas received related to calendar year 2006 production costs. In October 2015 an ALJ issued a proposal for decision recommending that the additional $10.9 million in bandwidth remedy payments be refunded to retail customers. In January 2016 the PUCT issued its order affirming the ALJ’s recommendation, and Entergy Texas filed a motion for rehearing of the PUCT’s decision, which the PUCT denied. In March 2016, Entergy Texas filed a complaint in Federal District Court for the Western District of Texas and a petition in the Travis County (State) District Court appealing the PUCT’s decision. The federal appeal was heard in December 2016, and the Federal District Court granted Entergy Texas’s requested relief. In January 2017 the PUCT and an intervenor filed petitions for appeal to the U.S. Court of Appeals for the Fifth Circuit of the Federal District Court ruling. The State District Court appeal remains pending. In April 2016, Entergy Texas filed with the PUCT an application to refund to customers approximately $56.2 million. The refund resulted from (i) $41.8 million of fuel cost recovery over-collections through February 2016, (ii) the $10.9 million in bandwidth remedy payments, discussed above, that Entergy Texas received related to calendar year 2006 production costs, and (iii) $3.5 million in bandwidth remedy payments that Entergy Texas received related to 2006-2008 production costs. In June 2016, Entergy Texas filed an unopposed settlement agreement that added additional over-recovered fuel costs for the months of March and April 2016. The settlement resulted in a $68 million refund. The ALJ approved the refund on an interim basis to be made to most customers over a four-month period beginning with the first billing cycle of July 2016. In July 2016 the PUCT issued an order approving the interim refund.

In July 2016, Entergy Texas filed an application to reconcile its fuel and purchased power costs for the period April 1, 2013 through March 31, 2016. Under a recent PUCT rule change, a fuel reconciliation is required to be filed at least once every three years and outside of a base rate case filing. During the reconciliation period, Entergy Texas incurred approximately $1.77 billion in Texas jurisdictional eligible fuel and purchased power expenses, net of certain revenues credited to such expenses and other adjustments. Entergy Texas estimated an over-recovery balance of approximately $19.3 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning Apri1 2016. Entergy Texas also noted, however, that the estimated $19.3 million over collection was being refunded to customers as a portion of the interim fuel refund beginning with the first billing cycle of July 2016, discussed above. Entergy Texas also is requesting a prudence finding for each of the fuel-related contracts and arrangements entered into or modified during the reconciliation period that have not been reviewed by the PUCT in a prior proceeding. In December 2016, Entergy Texas entered into a stipulation and settlement agreement resulting in a $6 million disallowance not associated with any particular issue raised and a refund of the over-recovery balance of $21 million as of November 30, 2016, to customers beginning April 2017 through June 2017. This settlement was developed concurrently with the stipulation and settlement agreement in the 2016 TCRF rider amendment discussed above, and the terms of the two settlements are interdependent. PUCT action on the stipulations and settlement agreements is pending.

Federal Regulation

Nuclear Matters

See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.

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Industrial and Commercial Customers

Entergy Texas’s large industrial and commercial customers continually explore ways to reduce their energy costs. In particular, cogeneration is an option available to a portion of Entergy Texas’s industrial customer base. Entergy Texas responds by working with industrial and commercial customers and negotiating electric service contracts to provide, under existing rate schedules, competitive rates that match specific customer needs and load profiles. Entergy Texas actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand, from both new and existing customers.

Environmental Risks

Entergy Texas’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Texas is in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

The preparation of Entergy Texas’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy Texas’s financial position or results of operations.

Utility Regulatory Accounting

Unbilled Revenue

Taxation and Uncertain Tax Positions

Qualified Pension and Other Postretirement Benefits

Entergy Texas’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries’ Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.

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Cost Sensitivity

The following chart reflects the sensitivity of qualified pension and qualified projected benefit obligation cost to changes in certain actuarial assumptions (dollars in thousands).



Actuarial Assumption	Change in Assumption	Impact on 2017 Qualified Pension Cost	Impact on 2016 Qualified Projected Benefit Obligation
		Increase/(Decrease)
Discount rate	(0.25%)	$768		$11,375
Rate of return on plan assets	(0.25%)	$823	$-
Rate of increase in compensation	0.25%	$312		$1,700

The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation changes in certain actuarial assumptions (dollars in thousands).



Actuarial Assumption	Change in Assumption	Impact on 2017 Postretirement Benefit Cost	Impact on 2016 Accumulated Postretirement Benefit Obligation
		Increase/(Decrease)
Discount rate	(0.25%)	$251	$3,792
Health care cost trend	0.25%	$482	$3,386

Each fluctuation above assumes that the other components of the calculation are held constant.

Costs and Funding

Total qualified pension cost for Entergy Texas in 2016 was $5 million. Entergy Texas anticipates 2017 qualified pension income to be $3.5 million. In 2016, Entergy Texas refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $3.6 million. Entergy Texas contributed $15.9 million to its qualified pension plans in 2016 and estimates 2017 pension contributions will be approximately $17 million, although the 2017 required pension contributions will be known with more certainty when the January 1, 2017 valuations are completed, which is expected by April 1, 2017.

Total postretirement health care and life insurance benefit income for Entergy Texas in 2016 was $4.4 million. Entergy Texas expects 2017 postretirement health care and life insurance benefit income to approximate $1.8 million. In 2016, Entergy Texas refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $1.1 million. Entergy Texas contributed $3.2 million to its other postretirement plans in 2016 and estimates 2017 contributions will be approximately $3.2 million.

The retirement and mortality rate assumptions are reviewed every three-to-five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans. The 2014 actuarial study reviewed plan experience from 2010 through 2013. As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies. These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of $30.8 million in the qualified pension benefit obligation and $8.2 million in the accumulated postretirement obligation. The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $4.3 million and other postretirement cost by approximately $1 million. In 2016 the mortality projection scale was updated to MP-2016, with no change in the base mortality table assumption.

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Entergy Texas, Inc. and Subsidiaries

Management’s Financial Discussion and Analysis

Federal Healthcare Legislation

Other Contingencies

New Accounting Pronouncements

See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

Entergy Texas, Inc. and Subsidiaries

The Woodlands, Texas

We have audited the accompanying consolidated balance sheets of Entergy Texas, Inc. and Subsidiaries (the “Company”) as of December 31, 2016 and 2015, and the related consolidated income statements, consolidated statements of cash flows, and consolidated statements of changes in common equity (pages 419 through 424 and applicable items in pages 59 through 232) for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Texas, Inc. and Subsidiaries as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 24, 2017

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ENTERGY TEXAS, INC. AND SUBSIDIARIES
CONSOLIDATED INCOME STATEMENTS

	For the Years Ended December 31,
	2016			2015			2014
	(In Thousands)

OPERATING REVENUES
Electric		$1,615,619			$1,707,203			$1,851,982

OPERATING EXPENSES
Operation and Maintenance:
Fuel, fuel-related expenses, and gas purchased for resale	271,968			277,810			282,809
Purchased power	616,597			709,947			881,438
Other operation and maintenance	220,566			254,731			232,955
Asset write-off	—			23,472			—
Taxes other than income taxes	70,973			72,945			70,439
Depreciation and amortization	107,026			102,410			99,609
Other regulatory charges - net	82,879			82,243			76,017
TOTAL	1,370,009			1,523,558			1,643,267

OPERATING INCOME	245,610			183,645			208,715

OTHER INCOME
Allowance for equity funds used during construction	7,617			5,678			2,959
Interest and investment income	987			684			1,106
Miscellaneous - net	(746		)	(798		)	(2,345		)
TOTAL	7,858			5,564			1,720

INTEREST EXPENSE
Interest expense	87,776			86,024			88,049
Allowance for borrowed funds used during construction	(4,943		)	(3,690		)	(2,062		)
TOTAL	82,833			82,334			85,987

INCOME BEFORE INCOME TAXES	170,635			106,875			124,448

Income taxes	63,097			37,250			49,644

NET INCOME		$107,538			$69,625			$74,804

See Notes to Financial Statements.

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ENTERGY TEXAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
	2016			2015			2014
	(In Thousands)
OPERATING ACTIVITIES
Net income		$107,538			$69,625			$74,804
Adjustments to reconcile net income to net cash flow provided by operating activities:
Depreciation and amortization	107,026			102,410			99,609
Deferred income taxes, investment tax credits, and non-current taxes accrued	20,794			(23,292		)	2,829
Changes in assets and liabilities:
Receivables	(9,300		)	21,443			24,318
Fuel inventory	9,765			2,960			5,433
Accounts payable	(22,462		)	(16,913		)	(19,854		)
Prepaid taxes and taxes accrued	10,018			3,484			57,484
Interest accrued	(3,229		)	(551		)	(1,489		)
Deferred fuel costs	29,419			36,985			(15,954		)
Other working capital accounts	(3,354		)	2,468			9,045
Provisions for estimated losses	(1,735		)	(2,899		)	3,139
Other regulatory assets	74,389			125,133			2,809
Pension and other postretirement liabilities	(10,204		)	(33,474		)	59,725
Other assets and liabilities	(2,064		)	(3,111		)	13,266
Net cash flow provided by operating activities	306,601			284,268			315,164
INVESTING ACTIVITIES
Construction expenditures	(337,963		)	(320,408		)	(195,794		)
Allowance for equity funds used during construction	7,743			5,751			2,981
Changes in money pool receivable - net	(681		)	306			5,981
Changes in securitization account	710			(942		)	292
Net cash flow used in investing activities	(330,191		)	(315,293		)	(186,540		)
FINANCING ACTIVITIES
Proceeds from the issuance of long-term debt	123,502			246,607			131,163
Retirement of long-term debt	(68,593		)	(265,734		)	(213,450		)
Change in money pool payable - net	(22,068		)	22,068			—
Dividends paid:
Common stock	—			—			(70,000		)
Other	(5,252		)	(175		)	7,616
Net cash flow provided by (used in) financing activities	27,589			2,766			(144,671		)
Net increase (decrease) in cash and cash equivalents	3,999			(28,259		)	(16,047		)
Cash and cash equivalents at beginning of period	2,182			30,441			46,488
Cash and cash equivalents at end of period		$6,181			$2,182			$30,441
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized		$88,489			$83,290			$85,695
Income taxes		$28,523			$60,359			($2,653	)
See Notes to Financial Statements.

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ENTERGY TEXAS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS

	December 31,
	2016			2015
	(In Thousands)

CURRENT ASSETS
Cash and cash equivalents:
Cash		$1,216			$2,153
Temporary cash investments	4,965			29
Total cash and cash equivalents	6,181			2,182
Securitization recovery trust account	37,451			38,161
Accounts receivable:
Customer	71,803			61,870
Allowance for doubtful accounts	(828		)	(474		)
Associated companies	39,447			42,279
Other	14,756			11,054
Accrued unbilled revenues	39,727			40,195
Total accounts receivable	164,905			154,924
Fuel inventory - at average cost	37,177			46,942
Materials and supplies - at average cost	36,631			34,994
Prepayments and other	18,599			17,975
TOTAL	300,944			295,178

OTHER PROPERTY AND INVESTMENTS
Investments in affiliates - at equity	600			620
Non-utility property - at cost (less accumulated depreciation)	376			376
Other	18,801			20,186
TOTAL	19,777			21,182

UTILITY PLANT
Electric	4,274,069			3,923,100
Construction work in progress	111,227			210,964
TOTAL UTILITY PLANT	4,385,296			4,134,064
Less - accumulated depreciation and amortization	1,526,057			1,477,529
UTILITY PLANT - NET	2,859,239			2,656,535

DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Regulatory asset for income taxes - net	105,816			107,499
Other regulatory assets (includes securitization property of $384,609 as of December 31, 2016 and $453,317 as of December 31, 2015)	740,156			812,862
Other	7,149			5,326
TOTAL	853,121			925,687

TOTAL ASSETS		$4,033,081			$3,898,582

See Notes to Financial Statements.

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ENTERGY TEXAS, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND EQUITY

	December 31,
	2016		2015
	(In Thousands)
CURRENT LIABILITIES
Accounts payable:
Associated companies		$47,867		$106,065
Other	77,342		87,421
Customer deposits	44,419		44,537
Taxes accrued	15,351		5,333
Interest accrued	25,977		29,206
Deferred fuel costs	54,543		25,124
Other	9,388		10,363
TOTAL	274,887		308,049

NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued	1,027,647		1,006,834
Accumulated deferred investment tax credits	12,934		13,835
Other regulatory liabilities	8,502		6,396
Asset retirement cost liabilities	6,470		6,124
Accumulated provisions	7,584		9,319
Pension and other postretirement liabilities	67,313		77,517
Long-term debt (includes securitization bonds of $429,043 as of December 31, 2016 and $497,030 as of December 31, 2015)	1,508,407		1,451,967
Other	50,343		57,085
TOTAL	2,689,200		2,629,077

Commitments and Contingencies

COMMON EQUITY
Common stock, no par value, authorized 200,000,000 shares; issued and outstanding 46,525,000 shares in 2016 and 2015	49,452		49,452
Paid-in capital	481,994		481,994
Retained earnings	537,548		430,010
TOTAL	1,068,994		961,456

TOTAL LIABILITIES AND EQUITY		$4,033,081		$3,898,582

See Notes to Financial Statements.

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ENTERGY TEXAS, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY
For the Years Ended December 31, 2016, 2015, and 2014

	Common Equity
	Common Stock		Paid-in Capital		Retained Earnings			Total
	(In Thousands)

Balance at December 31, 2013		$49,452		$481,994		$355,581			$887,027
Net income	—		—		74,804			74,804
Common stock dividends	—		—		(70,000		)	(70,000		)
Balance at December 31, 2014		$49,452		$481,994		$360,385			$891,831
Net income	—		—		69,625			69,625
Balance at December 31, 2015		$49,452		$481,994		$430,010			$961,456
Net income	—		—		107,538			107,538
Balance at December 31, 2016		$49,452		$481,994		$537,548			$1,068,994

See Notes to Financial Statements.

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ENTERGY TEXAS, INC. AND SUBSIDIARIES
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON

	2016		2015		2014		2013		2012
	(In Thousands)

Operating revenues		$1,615,619		$1,707,203		$1,851,982		$1,728,799		$1,581,496
Net income		$107,538		$69,625		$74,804		$57,881		$41,971
Total assets		$4,033,081		$3,898,582		$3,897,989		$3,909,470		$4,011,618
Long-term obligations (a)		$1,508,407		$1,451,967		$1,268,835		$1,544,549		$1,603,650

(a) Includes long-term debt (excluding currently maturing debt).

	2016		2015		2014		2013		2012
	(Dollars In Millions)

Electric Operating Revenues:
Residential		$613		$633		$654		$596		$553
Commercial	356		369		384		327		325
Industrial	365		372		422		325		299
Governmental	24		25		26		24		24
Total retail	1,358		1,399		1,486		1,272		1,201
Sales for resale:
Associated companies	178		259		316		369		313
Non-associated companies	40		14		23		47		36
Other	40		35		27		41		31
Total		$1,616		$1,707		$1,852		$1,729		$1,581

Billed Electric Energy Sales (GWh):
Residential	5,836		5,889		5,810		5,726		5,604
Commercial	4,570		4,548		4,471		4,402		4,396
Industrial	7,493		7,036		7,140		6,404		6,066
Governmental	283		276		277		282		278
Total retail	18,182		17,749		17,698		16,814		16,344
Sales for resale:
Associated companies	4,625		5,853		4,763		6,287		5,702
Non-associated companies	1,086		254		200		712		827
Total	23,893		23,856		22,661		23,813		22,873

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SYSTEM ENERGY RESOURCES, INC.

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS

System Energy’s principal asset currently consists of an ownership interest and a leasehold interest in Grand Gulf. The capacity and energy from its 90% interest is sold under the Unit Power Sales Agreement to its only four customers, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. System Energy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% interest in Grand Gulf pursuant to the Unit Power Sales Agreement. Payments under the Unit Power Sales Agreement are System Energy’s only source of operating revenues.

Results of Operations

Net Income

2016 Compared to 2015

Net income decreased $14.6 million primarily due to a higher effective income tax rate in 2016.

2015 Compared to 2014

Net income increased $15 million primarily due to a higher effective income tax rate in 2014, partially offset by lower operating revenue resulting from lower rate base as compared to the prior year.

Income Taxes

The effective income tax rates for 2016, 2015, and 2014 were 42.3%, 32.3%, and 46.4%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.

Liquidity and Capital Resources

Cash Flow

Cash flows for the years ended December 31, 2016, 2015, and 2014 were as follows:



	2016			2015			2014
	(In Thousands)
Cash and cash equivalents at beginning of period		$230,661			$223,179			$127,142

Net cash provided by (used in):
Operating activities	341,939			502,536			428,265
Investing activities	(232,602		)	(137,562		)	(203,930		)
Financing activities	(94,135		)	(357,492		)	(128,298		)
Net increase in cash and cash equivalents	15,202			7,482			96,037

Cash and cash equivalents at end of period		$245,863			$230,661			$223,179

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System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

Operating Activities

Net cash flow provided by operating activities decreased $160.6 million in 2016 primarily due to:

•

a decrease of $90.5 million in income tax refunds in 2016. System Energy received income tax refunds in 2016 and 2015 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The income tax refunds in 2016 and 2015 resulted primarily from the adoption of a new accounting method for income tax purposes in which System Energy will treat its nuclear decommissioning costs as production costs of electricity includable in cost of goods sold. See Note 3 to the financial statements for further discussion of the adoption of the new accounting method; and


•	an increase in spending of $35.1 million on nuclear refueling outages in 2016 as compared to 2015.

The decrease was partially offset by proceeds of $28.4 million received in August 2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed. See Note 8 to the financial statements for a discussion of the spent nuclear fuel litigation.

Net cash flow provided by operating activities increased $74.3 million in 2015 primarily due to an increase in income tax refunds of $104 million in 2015 and a decrease of $40.2 million in spending on nuclear refueling outages in 2015. The increase was partially offset by an increase in interest paid on the Grand Gulf sale-leaseback obligation as a result of the renewal in December 2013. System Energy received income tax refunds in 2015 and 2014 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The income tax refunds in 2015 resulted primarily from the adoption of a new accounting method for income tax purposes in which System Energy will treat its nuclear decommissioning costs as production costs of electricity includable in cost of goods sold. See Note 3 to the financial statements for further discussion of the adoption of the new accounting method. See Note 10 to the financial statements for details on the Grand Gulf sale-leaseback obligation.

Investing Activities

Net cash flow used in investing activities increased $95 million in 2016 primarily due to:


•	fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle; and


•	an increase in nuclear construction expenditures primarily as a result of a higher scope of work performed in 2016 on Grand Gulf outage projects, partially offset by decreased spending in 2016 on compliance with NRC post-Fukushima requirements.

The increase was partially offset by money pool activity and proceeds of $15.8 million received in August 2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously capitalized. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.

Decreases in System Energy’s receivable from the money pool are a source of cash flow and System Energy’s receivable from the money pool decreased by $6.1 million in 2016 compared to increasing by $37.6 million in 2015. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.

Net cash flow used in investing activities decreased $66.4 million in 2015 primarily due to fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle. The decrease was partially offset by money pool activity and an increase in nuclear expenditures primarily due to compliance with NRC post-Fukushima requirements.

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System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

Increases in System Energy’s receivable from the money pool are a use of cash flow and System Energy’s receivable from the money pool increased by $37.6 million in 2015 compared to decreasing by $6.9 million in 2014.

Financing Activities

Net cash flow used in financing activities decreased $263.4 million in 2016 primarily due to:


•	net borrowings of $66.9 million on the nuclear fuel company variable interest entity’s credit facility in 2016 compared to net repayments of $20.4 million on the nuclear fuel company variable interest entity’s credit facility in 2015;


•	a decrease of $61.8 million in common stock dividends and distributions as a result of lower operating cash flows and higher nuclear fuel purchases in 2016 as compared to the prior year;


•	the redemption in April 2015, at maturity, of $60 million of System Energy nuclear fuel company variable interest entity’s 5.33% Series G notes; and


•	redemption in May 2015 of $35 million and in November 2015 of $25 million of System Energy’s 5.875% Series governmental bonds due 2022.

The decrease was partially offset by the partial repayment caused by System Energy in May 2016 of $22 million of 5.875% pollution control revenue bonds due 2022 issued on behalf of System Energy.

Net cash flow used by financing activities increased $229.2 million in 2015 primarily due to:


•	an increase of $98.8 million in common stock dividends and distributions primarily due to higher operating cash flows and lower nuclear fuel purchases in 2015 as compared to the prior year;


•	redemption in April 2015, at maturity, of $60 million of System Energy nuclear fuel company variable interest entity’s 5.33% Series G notes;


•	redemption in May 2015 of $35 million and in November 2015 of $25 million of System Energy’s 5.875% Series governmental bonds due 2022; and


•	net repayments of $20.4 million on the nuclear fuel company variable interest entity’s credit facility in 2015 compared to net borrowings of $20.4 million on the nuclear fuel company variable interest entity’s credit facility in 2014.

The increase was partially offset by a decrease of $30.4 million in principal payments on the Grand Gulf sale-leaseback obligation in 2015 as compared to 2014. See Note 10 to the financial statements for details on the Grand Gulf sale-leaseback obligation.

See Note 5 to the financial statements for details of long-term debt.

Capital Structure

System Energy’s capitalization is balanced between equity and debt, as shown in the following table. The increase in the debt to capital ratio for System Energy is primarily due to net borrowings of $66.9 million on the System Energy nuclear fuel company variable interest entity’s credit facility and common stock dividends and distributions in 2016.



	December 31, 2016		December 31, 2015
Debt to capital	45.5	%	42.3	%
Effect of subtracting cash	(12.0	%)	(11.8	%)
Net debt to net capital	33.5	%	30.5	%

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System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings and long-term debt, including the currently maturing portion. Capital consists of debt and common equity. Net capital consists of capital less cash and cash equivalents. System Energy uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating System Energy’s financial condition. System Energy uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating System Energy’s financial condition because net debt indicates System Energy’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.

System Energy seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend, or both, in appropriate amounts to maintain the targeted capital structure. To the extent that operating cash flows are insufficient to support planned investments, System Energy may issue incremental debt or reduce dividends, or both, to maintain its targeted capital structure.

Uses of Capital

System Energy requires capital resources for:


•	construction and other capital investments;


•	debt maturities or retirements;


•	working capital purposes, including the financing of fuel costs; and


•	dividend, distribution, and interest payments.

Following are the amounts of System Energy’s planned construction and other capital investments.



	2017		2018		2019
	(In Millions)
Planned construction and capital investment:
Generation		$90		$165		$165
Other	10		10		10
Total		$100		$175		$175

Following are the amounts of System Energy’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.



	2017		2018-2019		2020-2021		After 2021		Total
	(In Millions)
Long-term debt (a)		$89		$158		$71		$656		$974
Purchase obligations (b)		$13		$37		$33		$33		$116


(a)	Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements.


(b)	Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For System Energy, it includes nuclear fuel purchase obligations.

In addition to the contractual obligations given above, System Energy expects to contribute approximately $18.1 million to its qualified pension plans and approximately $690 thousand to other postretirement health care and life insurance plans in 2017, although the 2017 required pension contributions will be known with more certainty when the January 1, 2017 valuations are completed, which is expected by April 1, 2017. See “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.

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System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

Also in addition to the contractual obligations, System Energy has $382.3 million of unrecognized tax benefits and interest net of unused tax attributes and payments for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.

In addition to routine spending to maintain operations, the planned capital investment estimate includes specific investments and initiatives such as the nuclear fleet operational excellence initiative, as discussed below in “Nuclear Matters,” and plant improvements.

As a wholly-owned subsidiary, System Energy dividends its earnings to Entergy Corporation at a percentage determined monthly.

Sources of Capital

System Energy’s sources to meet its capital requirements include:


•	internally generated funds;


•	cash on hand;


•	debt issuances; and


•	bank financing under new or existing facilities.

System Energy may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest and dividend rates are favorable.

All debt and common stock issuances by System Energy require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in its bond indentures and other agreements. System Energy has sufficient capacity under these tests to meet its foreseeable capital needs.

System Energy’s receivables from the money pool were as follows as of December 31 for each of the following years.

See Note 4 to the financial statements for a description of the money pool.

The System Energy nuclear fuel company variable interest entity has a credit facility in the amount of $120 million scheduled to expire in May 2019. As of December 31, 2016, $66.9 million in letters of credit were outstanding under the credit facility to support a like amount of commercial paper issued by the System Energy nuclear fuel company variable interest entity. See Note 4 to the financial statements for additional discussion of the variable interest entity credit facility.

System Energy obtained authorizations from the FERC through October 2017 for the following:


•	short-term borrowings not to exceed an aggregate amount of $200 million at any time outstanding;


•	long-term borrowings and security issuances; and


•	long-term borrowings by its nuclear fuel company variable interest entity.

See Note 4 to the financial statements for further discussion of System Energy’s short-term borrowing limits.

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System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

Federal Regulation

Complaint Against System Energy

Nuclear Matters

System Energy owns and operates Grand Gulf. System Energy is, therefore, subject to the risks related to owning and operating a nuclear plant. These include risks from the use, storage, handling and disposal of high-level and low-level radioactive materials, regulatory requirement changes, including changes resulting from events at other plants, limitations on the amounts and types of insurance commercially available for losses in connection with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts. In the event of an unanticipated early shutdown of Grand Gulf, System Energy may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. In December 2016, the NRC granted the extension of Grand Gulf’s operating license to 2044.

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System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

Grand Gulf Outage and NRC review

Environmental Risks

System Energy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that System Energy is in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.

Critical Accounting Estimates

The preparation of System Energy’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and there is the potential for future changes in the assumptions and measurements that could produce estimates that would have a material impact on the presentation of System Energy’s financial position or results of operations.

Nuclear Decommissioning Costs

Utility Regulatory Accounting

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System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

Taxation and Uncertain Tax Positions

Qualified Pension and Other Postretirement Benefits

System Energy’s qualified pension and other postretirement reported costs, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.

Cost Sensitivity

The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).



Actuarial Assumption	Change in Assumption	Impact on 2017 Qualified Pension Cost	Impact on 2016 Projected Qualified Benefit Obligation
		Increase/(Decrease)
Discount rate	(0.25%)	$884		$11,222
Rate of return on plan assets	(0.25%)	$620	$-
Rate of increase in compensation	0.25%	$327		$1,772

The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).



Actuarial Assumption	Change in Assumption	Impact on 2017 Postretirement Benefit Cost	Impact on 2016 Accumulated Postretirement Benefit Obligation
		Increase/(Decrease)
Discount rate	(0.25%)	$173	$2,082
Health care cost trend	0.25%	$277	$1,841

Each fluctuation above assumes that the other components of the calculation are held constant.

Costs and Funding

Total qualified pension cost for System Energy in 2016 was $10.8 million. System Energy anticipates 2017 qualified pension cost to be $11.7 million. In 2016, System refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $2.8 million. System Energy contributed $20.5 million to its pension plans in 2016 and estimates 2017 pension contributions will approximate $18.1 million, although the 2017 required pension contributions will be known with more certainty when the January 1, 2017 valuations are completed, which is expected by April 1, 2017.

Total postretirement health care and life insurance benefit income for System Energy in 2016 was $224 thousand. System Energy expects 2017 postretirement health care and life insurance benefit cost to approximate $692

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System Energy Resources, Inc.

Management’s Financial Discussion and Analysis

thousand. In 2016, System Energy refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $555 thousand. System Energy contributed $330 thousand to its other postretirement plans in 2016 and expects 2017 contributions to approximate $690 thousand.

The retirement and mortality rate assumptions are reviewed every three-to-five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans. The 2014 actuarial study reviewed plan experience from 2010 through 2013. As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies. These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of $17.7 million in the qualified pension benefit obligation and $3.1 million in the accumulated postretirement obligation. The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $2.7 million and other postretirement cost by approximately $0.4 million. In 2016, the mortality projection scale was updated to MP-2016, with no change in the base mortality table assumption.

Federal Healthcare Legislation

Other Contingencies

New Accounting Pronouncements

See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholder of

System Energy Resources, Inc.

Jackson, Mississippi

We have audited the accompanying balance sheets of System Energy Resources, Inc. (the “Company”) as of December 31, 2016 and 2015, and the related income statements, statements of cash flows, and statements of changes in common equity (pages 436 through 440 and applicable items in pages 59 through 232) for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of System Energy Resources, Inc. as of December 31, 2016 and 2015, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 24, 2017

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SYSTEM ENERGY RESOURCES, INC.
INCOME STATEMENTS

	For the Years Ended December 31,
	2016			2015			2014
	(In Thousands)

OPERATING REVENUES
Electric		$548,291			$632,405			$664,364

OPERATING EXPENSES
Operation and Maintenance:
Fuel, fuel-related expenses, and gas purchased for resale	27,416			89,598			84,658
Nuclear refueling outage expenses	19,512			21,654			23,309
Other operation and maintenance	153,064			156,552			156,502
Decommissioning	50,797			47,993			41,835
Taxes other than income taxes	25,195			27,281			25,160
Depreciation and amortization	136,195			143,133			142,583
Other regulatory credits - net	(45,041		)	(39,434		)	(30,799		)
TOTAL	367,138			446,777			443,248

OPERATING INCOME	181,153			185,628			221,116

OTHER INCOME
Allowance for equity funds used during construction	7,944			8,494			5,069
Interest and investment income	14,793			14,437			11,037
Miscellaneous - net	(556		)	(876		)	(529		)
TOTAL	22,181			22,055			15,577

INTEREST EXPENSE
Interest expense	37,529			45,532			58,384
Allowance for borrowed funds used during construction	(2,000		)	(2,244		)	(1,335		)
TOTAL	35,529			43,288			57,049

INCOME BEFORE INCOME TAXES	167,805			164,395			179,644

Income taxes	71,061			53,077			83,310

NET INCOME		$96,744			$111,318			$96,334

See Notes to Financial Statements.

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SYSTEM ENERGY RESOURCES, INC.
STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
	2016			2015			2014
	(In Thousands)
OPERATING ACTIVITIES
Net income		$96,744			$111,318			$96,334
Adjustments to reconcile net income to net cash flow provided by operating activities:
Depreciation, amortization, and decommissioning, including nuclear fuel amortization	224,879			270,514			254,199
Deferred income taxes, investment tax credits, and non-current taxes accrued	99,531			200,797			79,835
Changes in assets and liabilities:
Receivables	(15,846		)	5,879			37,345
Accounts payable	2,720			(352		)	(6,372		)
Prepaid taxes and taxes accrued	(6,555		)	(32,594		)	12,146
Interest accrued	(134		)	(19,013		)	21,371
Other working capital accounts	(15,470		)	13,576			(11,688		)
Other regulatory assets	(58,279		)	(4,565		)	(64,262		)
Pension and other postretirement liabilities	5,586			(16,888		)	49,741
Other assets and liabilities	8,763			(26,136		)	(40,384		)
Net cash flow provided by operating activities	341,939			502,536			428,265
INVESTING ACTIVITIES
Construction expenditures	(88,037		)	(70,358		)	(63,774		)
Allowance for equity funds used during construction	7,944			8,494			5,069
Nuclear fuel purchases	(151,068		)	(64,977		)	(181,209		)
Proceeds from the sale of nuclear fuel	11,467			57,681			61,076
Proceeds from nuclear decommissioning trust fund sales	499,252			390,371			392,872
Investment in nuclear decommissioning trust funds	(534,083		)	(421,220		)	(424,814		)
Changes in money pool receivable - net	6,117			(37,553		)	6,850
Litigation proceeds for reimbursement of spent nuclear fuel storage costs	15,806			—			—
Net cash flow used in investing activities	(232,602		)	(137,562		)	(203,930		)
FINANCING ACTIVITIES
Retirement of long-term debt	(22,002		)	(136,310		)	(46,743		)
Changes in credit borrowings - net	66,893			(20,404		)	20,404
Common stock dividends and distributions	(139,000		)	(200,750		)	(101,930		)
Other	(26		)	(28		)	(29		)
Net cash flow used in financing activities	(94,135		)	(357,492		)	(128,298		)
Net increase in cash and cash equivalents	15,202			7,482			96,037
Cash and cash equivalents at beginning of period	230,661			223,179			127,142
Cash and cash equivalents at end of period		$245,863			$230,661			$223,179
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid (received) during the period for:
Interest - net of amount capitalized		$36,152			$47,864			$27,834
Income taxes		($23,565	)		($114,092	)		($10,065	)
See Notes to Financial Statements.

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SYSTEM ENERGY RESOURCES, INC.
BALANCE SHEETS
ASSETS

	December 31,
	2016		2015
	(In Thousands)

CURRENT ASSETS
Cash and cash equivalents:
Cash		$786		$8,681
Temporary cash investments	245,077		221,980
Total cash and cash equivalents	245,863		230,661
Accounts receivable:
Associated companies	104,390		93,724
Other	3,637		4,574
Total accounts receivable	108,027		98,298
Materials and supplies - at average cost	82,469		87,366
Deferred nuclear refueling outage costs	24,729		5,605
Prepayments and other	20,111		11,282
TOTAL	481,199		433,212

OTHER PROPERTY AND INVESTMENTS
Decommissioning trust funds	780,496		701,460
TOTAL	780,496		701,460

UTILITY PLANT
Electric	4,331,668		4,253,949
Property under capital lease	585,084		575,027
Construction work in progress	43,888		92,546
Nuclear fuel	259,635		183,706
TOTAL UTILITY PLANT	5,220,275		5,105,228
Less - accumulated depreciation and amortization	3,063,249		2,961,842
UTILITY PLANT - NET	2,157,026		2,143,386

DEFERRED DEBITS AND OTHER ASSETS
Regulatory assets:
Regulatory asset for income taxes - net	93,127		98,230
Other regulatory assets	411,212		347,830
Other	4,652		4,757
TOTAL	508,991		450,817

TOTAL ASSETS		$3,927,712		$3,728,875

See Notes to Financial Statements.

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SYSTEM ENERGY RESOURCES, INC.
BALANCE SHEETS
LIABILITIES AND EQUITY

	December 31,
	2016		2015
	(In Thousands)

CURRENT LIABILITIES
Currently maturing long-term debt		$50,003		$2
Short-term borrowings	66,893		—
Accounts payable:
Associated companies	5,843		7,391
Other	50,558		34,010
Interest accrued	14,049		14,183
Other	2,957		1,926
TOTAL	190,303		57,512

NON-CURRENT LIABILITIES
Accumulated deferred income taxes and taxes accrued	1,112,865		1,019,075
Accumulated deferred investment tax credits	41,663		45,451
Other regulatory liabilities	370,862		337,424
Decommissioning	854,202		803,405
Pension and other postretirement liabilities	117,850		112,264
Long-term debt	501,129		572,665
Other	15		—
TOTAL	2,998,586		2,890,284

Commitments and Contingencies

COMMON EQUITY
Common stock, no par value, authorized 1,000,000 shares; issued and outstanding 789,350 shares in 2016 and 2015	679,350		719,350
Retained earnings	59,473		61,729
TOTAL	738,823		781,079

TOTAL LIABILITIES AND EQUITY		$3,927,712		$3,728,875

See Notes to Financial Statements.

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SYSTEM ENERGY RESOURCES, INC.
STATEMENTS OF CHANGES IN COMMON EQUITY
For the Years Ended December 31, 2016, 2015, and 2014

	Common Equity
	Common Stock			Retained Earnings			Total
	(In Thousands)

Balance at December 31, 2013		$789,350			$86,757			$876,107
Net income	—			96,334			96,334
Common stock dividends	—			(101,930		)	(101,930		)
Balance at December 31, 2014		$789,350			$81,161			$870,511
Net income	—			111,318			111,318
Common stock dividends and distributions	(70,000		)	(130,750		)	(200,750		)
Balance at December 31, 2015		$719,350			$61,729			$781,079
Net income	—			96,744			96,744
Common stock dividends and distributions	(40,000		)	(99,000		)	(139,000		)
Balance at December 31, 2016		$679,350			$59,473			$738,823

See Notes to Financial Statements.

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SYSTEM ENERGY RESOURCES, INC.
SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON

	2016		2015		2014		2013		2012
	(Dollars In Thousands)

Operating revenues		$548,291		$632,405		$664,364		$735,089		$622,118
Net income		$96,744		$111,318		$96,334		$113,664		$111,866
Total assets		$3,927,712		$3,728,875		$3,826,193		$3,537,414		$3,614,610
Long-term obligations (a)		$501,129		$572,665		$630,603		$702,273		$663,039
Electric energy sales (GWh)	5,384		10,547		9,219		9,794		6,602

(a) Includes long-term debt (excluding currently maturing debt).

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Item 2. Properties

Information regarding the registrant’s properties is included in Part I. Item 1. - Entergy’s Business under the sections titled “Utility - Property and Other Generation Resources” and “Entergy Wholesale Commodities - Property” in this report.

Item 3. Legal Proceedings

Details of the registrant’s material environmental regulation and proceedings and other regulatory proceedings and litigation that are pending or those terminated in the fourth quarter of 2016 are discussed in Part I. Item 1. - Entergy’s Business under the sections titled “Retail Rate Regulation,” “Environmental Regulation,” and “Litigation” and “Impairment of Long-lived Assets” in Note 14 to the financial statements.

Item 4. Mine Safety Disclosures

Not applicable.

EXECUTIVE OFFICERS OF ENTERGY CORPORATION

Executive Officers



Name	Age	Position	Period
Leo P. Denault (a)	57	Chairman of the Board and Chief Executive Officer of Entergy Corporation	2013-Present
		Executive Vice President and Chief Financial Officer of Entergy Corporation	2004-2013
		Director of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and System Energy	2004-2013
		Director of Entergy Texas	2007-2013
		Director of Entergy New Orleans	2011-2013

William M. Mohl (a)	57	President, Entergy Wholesale Commodities	2013-Present
		President and Chief Executive Officer of Entergy Gulf States Louisiana and Entergy Louisiana	2010-2013
		Director of Entergy Gulf States Louisiana and Entergy Louisiana	2010-2013
		Vice President, System Planning of Entergy Services, Inc.	2007-2010

Theodore H. Bunting, Jr. (a)	58	Group President Utility Operations of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas	2012-Present
		President, Chief Executive Officer, and Director of System Energy	2014-Present
		Director of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas	2012-Present
		Senior Vice President and Chief Accounting Officer of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy	2007-2012

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Name	Age	Position	Period
A. Christopher Bakken, III (a)	55	Executive Vice President and Chief Nuclear Officer of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy	2016-Present
		Project Director, Hinkley Point C of EDF Energy	2009-2016

Marcus V. Brown (a)	55	Executive Vice President and General Counsel of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy	2013-Present
		Senior Vice President and General Counsel of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy	2012-2013
		Vice President and Deputy General Counsel of Entergy Services, Inc.	2009-2012
		Associate General Counsel of Entergy Services, Inc.	2007-2009

Andrew S. Marsh (a)	45	Executive Vice President and Chief Financial Officer of Entergy Corporation	2013-Present
		Director of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy	2013-Present
		Chief Financial Officer of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy	2014-Present
		Vice President, System Planning of Entergy Services, Inc.	2010-2013
		Vice President, Planning and Financial Communications of Entergy Services, Inc.	2007-2010

Roderick K. West (a)	48	Executive Vice President of Entergy Corporation	2010-Present
		Chief Administrative Officer of Entergy Corporation	2010-2016
		President and Chief Executive Officer of Entergy New Orleans	2007-2010
		Director of Entergy New Orleans	2005-2011

Paul D. Hinnenkamp (a)	55	Senior Vice President and Chief Operating Officer of Entergy Corporation	2015-Present
		Director of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas	2015-Present
		Senior Vice President, Capital Project Management and Technology of Entergy Services, Inc.	2015
		Vice President, Capital Project Management and Technology of Entergy Services, Inc.	2013-2015
		Vice President of Fossil Generation Development and Support of Entergy Services, Inc.	2010-2013

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Name	Age	Position	Period
Alyson M. Mount (a)	46	Senior Vice President and Chief Accounting Officer of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy	2012-Present
		Vice President Corporate Controller of Entergy Services, Inc.	2010-2012
		Director, Corporate Reporting and Accounting Policy of Entergy Services, Inc.	2002-2010

Andrea Coughlin Rowley (a)	51	Senior Vice President, Human Resources of Entergy Corporation	2016-Present
		President and Chief Executive Officer of Advance/Evolve LLC	2013-2016
		Vice President, Human Resources of Dover Corporation	2012-2013

Donald W. Vinci (a)	58	Executive Vice President and Chief Administrative Officer of Entergy Corporation	2016-Present
		Senior Vice President, Human Resources and Chief Diversity Officer of Entergy Corporation	2013-2016
		Vice President, Human Capital Management of Entergy Services, Inc.	2013
		Vice President, Gas Distribution Business of Entergy Services, Inc.	2010-2013
		Vice President, Business Development of Entergy Services, Inc.	2008-2010


(a)	In addition, this officer is an executive officer and/or director of various other wholly owned subsidiaries of Entergy Corporation and its operating companies.

Each officer of Entergy Corporation is elected yearly by the Board of Directors. Each officer’s age and title is provided as of December 31, 2016.

PART II

Item 5. Market for Registrants’ Common Equity and Related Stockholder Matters

Entergy Corporation

The shares of Entergy Corporation’s common stock are listed on the New York Stock and Chicago Stock Exchanges under the ticker symbol ETR.

The high and low prices of Entergy Corporation’s common stock for each quarterly period in 2016 and 2015 were as follows:



	2016		2015
	High	Low	High	Low
	(In Dollars)
First	79.72	65.38	90.33	73.88
Second	81.36	72.67	79.84	69.06
Third	82.09	75.99	74.09	61.27
Fourth	76.56	66.71	70.67	63.90

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Consecutive quarterly cash dividends on common stock were paid to stockholders of Entergy Corporation in 2016 and 2015. Quarterly dividends of $0.83 per share were paid through third quarter 2015. In fourth quarter 2015 and through third quarter 2016, dividends of $0.85 per share were paid. In fourth quarter 2016, dividends of $0.87 per share were paid.

As of January 31, 2017, there were 27,567 stockholders of record of Entergy Corporation.

Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities (1)



Period		Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of a Publicly Announced Plan	Maximum $ Amount of Shares that May Yet be Purchased Under a Plan (2)

10/01/2016	-10/31/2016	—		$—	—		$350,052,918
11/01/2016	-11/30/2016	—		$—	—		$350,052,918
12/01/2016	-12/31/2016	—		$—	—		$350,052,918
Total		—		$—	—

In accordance with Entergy’s stock-based compensation plans, Entergy periodically grants stock options to key employees, which may be exercised to obtain shares of Entergy’s common stock. According to the plans, these shares can be newly issued shares, treasury stock, or shares purchased on the open market. Entergy’s management has been authorized by the Board to repurchase on the open market shares up to an amount sufficient to fund the exercise of grants under the plans. In addition to this authority, the Board has authorized share repurchase programs to enable opportunistic purchases in response to market conditions. In October 2010 the Board granted authority for a $500 million share repurchase program. The amount of share repurchases under these programs may vary as a result of material changes in business results or capital spending or new investment opportunities. In addition, in the first quarter 2016, Entergy withheld 19,399 shares of its common stock at $68.09 per share, 36,439 shares of its common stock at $70.58 per share, and 82,619 shares of its common stock at $71.60 per share to pay income taxes due upon vesting of restricted stock granted and payout of performance units as part of its long-term incentive program.


(1)	See Note 12 to the financial statements for additional discussion of the stock-based compensation plans.


(2)	Maximum amount of shares that may yet be repurchased relates only to the $500 million plan does not include an estimate of the amount of shares that may be purchased to fund the exercise of grants under the stock-based compensation plans.

Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy

There is no market for the common stock of Entergy Corporation’s wholly owned subsidiaries. Cash dividends on common stock paid by the Registrant Subsidiaries during 2016 and 2015, were as follows:



	2016		2015
	(In Millions)
Entergy Arkansas		$—		$—
Entergy Louisiana		$285.5		$226.0
Entergy Mississippi		$24.0		$40.0
Entergy New Orleans		$18.7		$7.3
Entergy Texas		$—		$—
System Energy		$139.0		$200.8

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Information with respect to restrictions that limit the ability of the Registrant Subsidiaries to pay dividends is presented in Note 7 to the financial statements.

Item 6. Selected Financial Data

Refer to “SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, INC. AND SUBSIDIARIES, ENTERGY LOUISIANA, LLC AND SUBSIDIARIES, ENTERGY MISSISSIPPI, INC., ENTERGY NEW ORLEANS, INC. AND SUBSIDIARIES, ENTERGY TEXAS, INC. AND SUBSIDIARIES, and SYSTEM ENERGY RESOURCES, INC.” which follow each company’s financial statements in this report, for information with respect to selected financial data and certain operating statistics.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Refer to “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, INC. AND SUBSIDIARIES, ENTERGY LOUISIANA, LLC AND SUBSIDIARIES, ENTERGY MISSISSIPPI, INC., ENTERGY NEW ORLEANS, INC. AND SUBSIDIARIES, ENTERGY TEXAS, INC. AND SUBSIDIARIES, and SYSTEM ENERGY RESOURCES, INC.”

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Refer to “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF ENTERGY CORPORATION AND SUBSIDIARIES - Market and Credit Risk Sensitive Instruments.”

Item 8. Financial Statements and Supplementary Data

Refer to “TABLE OF CONTENTS - Entergy Corporation, Entergy Arkansas, Inc., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., Entergy Texas, Inc., and System Energy Resources, Inc.”

Item 9. Changes In and Disagreements With Accountants On Accounting and Financial Disclosure

No event that would be described in response to this item has occurred with respect to Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, or System Energy.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

As of December 31, 2016, evaluations were performed under the supervision and with the participation of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy (individually “Registrant” and collectively the “Registrants”) management, including their respective Principal Executive Officers (PEO) and Principal Financial Officers (PFO). The evaluations assessed the effectiveness of the Registrants’ disclosure controls and procedures. Based on the evaluations, each PEO and PFO has concluded that, as to the Registrant or Registrants for which they serve as PEO or PFO, the Registrant’s or Registrants’ disclosure controls and procedures are effective to ensure that information required to be disclosed by each Registrant in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms; and that the Registrant’s or Registrants’ disclosure controls and procedures are also effective in reasonably assuring that such information is accumulated and communicated to the Registrant’s or Registrants’ management, including their respective PEOs and PFOs, as appropriate to allow timely decisions regarding required disclosure.

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Internal Control over Financial Reporting

(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

The managements of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy (individually “Registrant” and collectively the “Registrants”) are responsible for establishing and maintaining adequate internal control over financial reporting for the Registrants. Each Registrant’s internal control system is designed to provide reasonable assurance regarding the preparation and fair presentation of each Registrant’s financial statements presented in accordance with generally accepted accounting principles.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

Each Registrant’s management assessed the effectiveness of each Registrant’s internal control over financial reporting as of December 31, 2016. In making this assessment, each Registrant’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. The 2013 COSO Framework was utilized for management’s assessment.

Based on each management’s assessment and the criteria set forth by the 2013 COSO Framework, each Registrant’s management believes that each Registrant maintained effective internal control over financial reporting as of December 31, 2016.

The report of Deloitte & Touche LLP, Entergy Corporation’s independent registered public accounting firm, regarding Entergy Corporation’s internal control over financial reporting is included herein. The report of Deloitte & Touche LLP is not applicable to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy because these Registrants are non-accelerated filers.

Changes in Internal Controls over Financial Reporting

Under the supervision and with the participation of each Registrant’s management, including its respective PEO and PFO, each Registrant evaluated changes in internal control over financial reporting that occurred during the quarter ended December 31, 2016 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

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Attestation Report of Registered Public Accounting Firm

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Entergy Corporation and Subsidiaries

New Orleans, Louisiana

We have audited the internal control over financial reporting of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 2016, based on criteria established in Internal Control -Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Item 9A, Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Corporation’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on the criteria established in Internal Control -Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Corporation as of and for the year ended December 31, 2016 and our report dated February 24, 2017 expressed an unqualified opinion on those consolidated financial statements.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 24, 2017

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PART III

Item 10. Directors and Executive Officers of the Registrants (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)

Information required by this item concerning directors of Entergy Corporation is set forth under the heading “Item 1 – Election of Directors” contained in the Proxy Statement of Entergy Corporation, to be filed in connection with its Annual Meeting of Stockholders to be held May 5, 2017, and is incorporated herein by reference.

All officers and directors listed below held the specified positions with their respective companies as of the date of filing this report, unless otherwise noted.



Name	Age	Position	Period
ENTERGY ARKANSAS, INC.

Directors
Richard C. Riley	54	President and Chief Executive Officer of Entergy Arkansas	2016-Present
		Director of Entergy Arkansas	2016-Present
		Group Vice President, Customer Service and Operations of Entergy Arkansas	2015-2016
		Vice President, Transmission of Entergy Services, Inc.	2010-2015

Theodore H. Bunting, Jr.		See information under the Entergy Corporation Officers Section in Part I.
Andrew S. Marsh		See information under the Entergy Corporation Officers Section in Part I.
Paul D. Hinnenkamp		See information under the Entergy Corporation Officers Section in Part I.



Officers
A. Christopher Bakken, III		See information under the Entergy Corporation Officers Section in Part I.
Marcus V. Brown		See information under the Entergy Corporation Officers Section in Part I.
Theodore H. Bunting, Jr.		See information under the Entergy Corporation Officers Section in Part I.
Leo P. Denault		See information under the Entergy Corporation Officers Section in Part I.
Paul D. Hinnenkamp		See information under the Entergy Corporation Officers Section in Part I.
Andrew S. Marsh		See information under the Entergy Corporation Officers Section in Part I.
Alyson M. Mount		See information under the Entergy Corporation Officers Section in Part I.
Richard C. Riley		See information under the Entergy Arkansas Directors Section above.
Andrea Coughlin Rowley		See information under the Entergy Corporation Officers Section in Part I.
Donald W. Vinci		See information under the Entergy Corporation Officers Section in Part I.
Roderick K. West		See information under the Entergy Corporation Officers Section in Part I.

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ENTERGY LOUISIANA, LLC
Directors
Phillip R. May, Jr.	54	President and Chief Executive Officer of Entergy Louisiana	2013-Present
		Director of Entergy Louisiana	2013-Present
		Vice President, Regulatory Services of Entergy Services, Inc.	2002-2013

Theodore H. Bunting, Jr.		See information under the Entergy Corporation Officers Section in Part I.
Andrew S. Marsh		See information under the Entergy Corporation Officers Section in Part I.
Paul D. Hinnenkamp		See information under the Entergy Corporation Officers Section in Part I.



Officers
A. Christopher Bakken, III		See information under the Entergy Corporation Officers Section in Part I.
Marcus V. Brown		See information under the Entergy Corporation Officers Section in Part I.
Theodore H. Bunting, Jr.		See information under the Entergy Corporation Officers Section in Part I.
Leo P. Denault		See information under the Entergy Corporation Officers Section in Part I.
Paul D. Hinnenkamp		See information under the Entergy Corporation Officers Section in Part I.
Andrew S. Marsh		See information under the Entergy Corporation Officers Section in Part I.
Phillip R. May, Jr.		See information under the Entergy Louisiana Directors Section above.
Alyson M. Mount		See information under the Entergy Corporation Officers Section in Part I.
Andrea Coughlin Rowley		See information under the Entergy Corporation Officers Section in Part I.
Donald W. Vinci		See information under the Entergy Corporation Officers Section in Part I.
Roderick K. West		See information under the Entergy Corporation Officers Section in Part I.



ENTERGY MISSISSIPPI, INC.
Directors
Haley R. Fisackerly	51	President and Chief Executive Officer of Entergy Mississippi	2008-Present
		Director of Entergy Mississippi	2008-Present

Theodore H. Bunting, Jr.		See information under the Entergy Corporation Officers Section in Part I.
Andrew S. Marsh		See information under the Entergy Corporation Officers Section in Part I.
Paul D. Hinnenkamp		See information under the Entergy Corporation Officers Section in Part I.

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Officers
Marcus V. Brown		See information under the Entergy Corporation Officers Section in Part I.
Theodore H. Bunting, Jr.		See information under the Entergy Corporation Officers Section in Part I.
Leo P. Denault		See information under the Entergy Corporation Officers Section in Part I.
Haley R. Fisackerly		See information under the Entergy Mississippi Directors Section above.
Paul D. Hinnenkamp		See information under the Entergy Corporation Officers Section in Part I.
Andrew S. Marsh		See information under the Entergy Corporation Officers Section in Part I.
Alyson M. Mount		See information under the Entergy Corporation Officers Section in Part I.
Andrea Coughlin Rowley		See information under the Entergy Corporation Officers Section in Part I.
Donald W. Vinci		See information under the Entergy Corporation Officers Section in Part I.
Roderick K. West		See information under the Entergy Corporation Officers Section in Part I.



ENTERGY NEW ORLEANS, INC.
Directors
Charles L. Rice, Jr.	52	President and Chief Executive Officer of Entergy New Orleans	2010-Present
		Director of Entergy New Orleans	2010-Present
		Director, Utility Strategy of Entergy Services, Inc.	2009-2010
		Partner, Barrasso, Usdin, Kupperman, Freeman & Sarver, L.L.C.	2005-2009

Theodore H. Bunting, Jr.		See information under the Entergy Corporation Officers Section in Part I.
Andrew S. Marsh		See information under the Entergy Corporation Officers Section in Part I.
Paul D. Hinnenkamp		See information under the Entergy Corporation Officers Section in Part I.

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Officers
Marcus V. Brown		See information under the Entergy Corporation Officers Section in Part I.
Theodore H. Bunting, Jr.		See information under the Entergy Corporation Officers Section in Part I.
Leo P. Denault		See information under the Entergy Corporation Officers Section in Part I.
Paul D. Hinnenkamp		See information under the Entergy Corporation Officers Section in Part I.
Andrew S. Marsh		See information under the Entergy Corporation Officers Section in Part I.
Alyson M. Mount		See information under the Entergy Corporation Officers Section in Part I.
Charles L. Rice, Jr.		See information under the Entergy New Orleans Directors Section above.
Andrea Coughlin Rowley		See information under the Entergy Corporation Officers Section in Part I.
Donald W. Vinci		See information under the Entergy Corporation Officers Section in Part I.
Roderick K. West		See information under the Entergy Corporation Officers Section in Part I.



ENTERGY TEXAS, INC.
Directors
Sallie T. Rainer	55	President and Chief Executive Officer of Entergy Texas	2012-Present
		Director of Entergy Texas	2012-Present
		Vice President, Federal Policy of Entergy Services, Inc.	2011-2012
		Director, Regulatory Affairs and Energy Settlements of Entergy Services, Inc.	2006-2011

Theodore H. Bunting, Jr.		See information under the Entergy Corporation Officers Section in Part I.
Andrew S. Marsh		See information under the Entergy Corporation Officers Section in Part I.
Paul D. Hinnenkamp		See information under the Entergy Corporation Officers Section in Part I.

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Officers
Marcus V. Brown		See information under the Entergy Corporation Officers Section in Part I.
Theodore H. Bunting, Jr.		See information under the Entergy Corporation Officers Section in Part I.
Leo P. Denault		See information under the Entergy Corporation Officers Section in Part I.
Paul D. Hinnenkamp		See information under the Entergy Corporation Officers Section in Part I.
Andrew S. Marsh		See information under the Entergy Corporation Officers Section in Part I.
Alyson M. Mount		See information under the Entergy Corporation Officers Section in Part I.
Sallie T. Rainer		See information under the Entergy Texas Directors Section above.
Andrea Coughlin Rowley		See information under the Entergy Corporation Officers Section in Part I.
Donald W. Vinci		See information under the Entergy Corporation Officers Section in Part I.
Roderick K. West		See information under the Entergy Corporation Officers Section in Part I.

Each director and officer of the applicable Entergy company is elected yearly to serve by the unanimous consent of the sole common stockholder with the exception of the directors and officers of Entergy Louisiana, LLC, who are elected yearly to serve by the unanimous consent of the sole common membership owner, Entergy Utility Holding Company, LLC. Entergy Corporation’s directors are elected annually at the annual meeting of shareholders. Entergy Corporation’s officers are elected at the annual organizational meeting of the Board of Directors.

Corporate Governance Guidelines and Committee Charters

Each of the Audit, Corporate Governance, and Personnel Committees of Entergy Corporation’s Board of Directors operates under a written charter. In addition, the full Board has adopted Corporate Governance Guidelines. Each charter and the guidelines are available through Entergy’s website (www.entergy.com) or upon written request.

Audit Committee of the Entergy Corporation Board

The following directors are members of the Audit Committee of Entergy Corporation’s Board of Directors:

Patrick J. Condon (Chairman)

Maureen S. Bateman

Philip L. Frederickson

Blanche L. Lincoln

Karen A. Puckett

All Audit Committee members are independent. In addition to the general independence requirements, all Audit Committee members must meet the heightened independence standards imposed by the SEC and NYSE. All Audit Committee members possess the level of financial literacy and accounting or related financial management expertise required by the NYSE rules. The Board has determined that each of Patrick J. Condon and Philip L. Frederickson is an “audit committee financial expert” as such term is defined by the rules of the SEC.

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Code of Ethics

The Board of Directors has adopted a Code of Business Conduct and Ethics for Members of the Board of Directors. The code is available through Entergy’s website (www.entergy.com) or upon written request. The Board has also adopted a Code of Business Conduct and Ethics for Employees that includes Special Provision Relating to Principal Executive Officer and Senior Financial Officers. The Code of Business Conduct and Ethics for Employees is to be read in conjunction with Entergy’s omnibus code of integrity under which Entergy operates called the Code of Entegrity as well as system policies. All employees are expected to abide by the Codes. Non-bargaining employees are required to acknowledge annually that they understand and abide by the Code of Entegrity. The Code of Business Conduct and Ethics for Employees and the Code of Entegrity are available through Entergy’s website (www.entergy.com) or upon written request.

Source of Nominations to the Board of Directors; Nominating Procedure

The Corporate Governance Committee will consider director candidates recommended by Entergy Corporation’s shareholders. Shareholders wishing to recommend a candidate to the Corporate Governance Committee should do so by submitting the recommendation in writing to Entergy Corporation’s Secretary at 639 Loyola Avenue, P.O. Box 61000, New Orleans, LA 70161, and it will be forwarded to the Corporate Governance Committee members for their consideration. Any recommendation should include:


•	the number of shares of Entergy Corporation held by the shareholder;


•	the name and address of the candidate;


•	a brief biographical description of the candidate, including his or her occupation for at least the last five years, and a statement of the qualifications of the candidate, taking into account the qualification requirements set forth above; and


•	the candidate’s signed consent to serve as a director if elected and to be named in the Proxy Statement.

Once the Corporate Governance Committee receives the recommendation, it may request additional information from the candidate about the candidate’s independence, qualifications, and other information that would assist the Corporate Governance Committee in evaluating the candidate, as well as certain information that must be disclosed about the candidate in the Proxy Statement, if nominated. The Corporate Governance Committee will apply the same standards in considering director candidates recommended by shareholders as it applies to other candidates.

Section 16(a) Beneficial Ownership Reporting Compliance

Information called for by this item concerning the directors and officers of Entergy Corporation is set forth in the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders to be held on May 5, 2017, under the heading “Section 16(a) Beneficial Ownership Reporting Compliance,” which information is incorporated herein by reference.

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Item 11. Executive Compensation

ENTERGY CORPORATION

Information concerning the directors and officers of Entergy Corporation is set forth in the Proxy Statement under the headings “Compensation Discussion and Analysis,” “Executive Compensation Tables,” “Nominees for the Board of Directors,” and “Non-Employee Director Compensation,” all of which information is incorporated herein by reference.

ENTERGY ARKANSAS, ENTERGY LOUISIANA, ENTERGY MISSISSIPPI, ENTERGY NEW ORLEANS, AND ENTERGY TEXAS

COMPENSATION DISCUSSION AND ANALYSIS

In this section, the compensation earned by the following Named Executive Officers in 2016 is discussed. Each officer’s title is provided as of December 31, 2016.



Name⁽¹⁾	Title
A. Christopher Bakken, III⁽²⁾	Executive Vice President and Chief Nuclear Officer
Leo P. Denault	Chairman of the Board and Chief Executive Officer
Marcus V. Brown	Executive Vice President and General Counsel
Haley R. Fisackerly	President and Chief Executive Officer, Entergy Mississippi
Andrew S. Marsh	Executive Vice President and Chief Financial Officer Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas
Phillip R. May, Jr.	President and Chief Executive Officer, Entergy Louisiana
Hugh T. McDonald ⁽³⁾	Former President and Chief Executive Officer, Entergy Arkansas
Sallie T. Rainer	President and Chief Executive Officer, Entergy Texas
Charles L. Rice, Jr.	President and Chief Executive Officer, Entergy New Orleans
Richard C. Riley ⁽³⁾	President and Chief Executive Officer, Entergy Arkansas
Roderick K. West	Executive Vice President


(1)	Messrs. Bakken, Brown, Denault, Marsh, and West hold the positions referenced above as executive officers

of Entergy Corporation and are members of Entergy Corporation’s Office of the Chief Executive. No additional compensation was paid in 2016 to any of these officers for their service as Named Executive Officers of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, or Entergy Texas (the “Subsidiaries”).


(2)	Mr. Bakken joined Entergy as Chief Nuclear Officer in April 2016.


(3)	Mr. McDonald is included in the Executive Compensation section of this Form 10-K because he served as President and Chief Executive Officer, Entergy Arkansas for a portion of 2016. Mr. Riley succeeded Mr. McDonald as President and Chief Executive Officer, Entergy Arkansas in May 2016.

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CD&A Highlights

Executive Compensation Programs and Practices

Entergy Corporation regularly reviews its executive compensation programs to align them with commonly viewed best practices in the market.

Compensation Governance Best Practices:

What Entergy Corporation Does


•	Require a “double trigger” for severance payments or equity acceleration in the event of a change in control


•	Maintain a “clawback” policy that goes beyond Sarbanes-Oxley requirements


•	Cap the maximum payout at 200% of target under the Long-Term Performance Unit Program and under the Annual Incentive Plan for members of the Office of the Chief Executive


•	Require minimum vesting periods for equity based awards


•	Target long-term compensation mix to give more weight to performance units than to service-based restricted stock and stock options combined


•	Settle 100% of long-term performance units in shares of Entergy Corporation stock


•	Require 6 times base salary stock ownership for Entergy Corporation’s Chief Executive Officer and 1 to 3 times base salary for other executive officers


•	Require executives to hold substantially all equity compensation received from Entergy Corporation until stock ownership guidelines are met


•	Prohibit directors and officers from pledging or entering into hedging or other derivative transactions with respect to their Entergy Corporation shares


•	Mitigate undue risk taking in compensation programs


•	Subject executive officer equity grants to non-compete and non-solicitation covenants

What Entergy Corporation Doesn’t Do


•	No 280G tax “gross up” payments in the event of a change in control


•	No tax “gross up” payments on any executive perquisites, other than relocation benefits available to all eligible employees, and club dues for some of the Named Executive Officers


•	No option repricing or cash buy-outs for underwater options under the equity plans


•	No agreements providing for severance payments to executive officers that exceed 2.99 times annual base salary and annual incentive awards without shareholder approval


•	No unusual or excessive perquisites


•	New officers are excluded from participation in the System Executive Retirement Plan


•	No grants of supplemental service credit to newly-hired officers under any of Entergy Corporation’s non-qualified retirement plans

Entergy Corporation’s Pay for Performance Philosophy

Entergy Corporation’s executive compensation programs are based on a philosophy of pay for performance that is embodied in the design of its annual and long-term incentive plans. Entergy Corporation believes the executive pay programs described in this section and in the accompanying tables have played a significant role in its ability to drive strong financial and operational results and to attract and retain a highly experienced and successful management team. The Annual Incentive Plan incentivizes and rewards the achievement of operational financial metrics that are deemed by the Personnel Committee to be consistent with the overall goals and strategic direction that the Entergy Corporation Board has approved for Entergy Corporation. The long-term incentive programs further align the interests of Entergy Corporation executives and its shareholders by directly tying the value of the equity awards granted to executives under these programs to Entergy Corporation’s stock price performance and total shareholder return. By incentivizing officers to achieve important financial and operational objectives and create long-term shareholder value, these programs play a key role in creating sustainable value for the benefit of all of Entergy Corporation’s stakeholders, including its shareholders, customers, employees, and communities.

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2016 Incentive Pay Outcomes

The 2016 incentive pay outcomes for the Named Executive Officers demonstrated the application of Entergy Corporation’s pay for performance philosophy.

Annual Incentive Plan

Awards under the Executive Annual Incentive Plan or Annual Incentive Plan are tied to Entergy Corporation’s financial and operational performance through the Entergy Achievement Multiplier (EAM), which is the performance metric used to determine the maximum funding available for awards under the plan. The 2016 EAM was determined based in equal part on Entergy Corporation’s success in achieving its operational earnings per share and operational operating cash flow goals set at the beginning of the year. These goals were approved by the Personnel Committee based on Entergy Corporation’s financial plan and the Board’s overall goals for Entergy Corporation and were consistent with its published earnings guidance.

•

2016 Annual Incentive Program Payout. For 2016, the Personnel Committee, based on a recommendation of the Finance Committee, determined that management exceeded its operational earnings per share goal of $5.35 per share by $1.76, but fell short of its operational operating cash flow goal of $3.180 billion by approximately $176 million. Based on the targets and ranges previously established by the Committee, these results resulted in a calculated EAM of 133%. This determined the maximum funding level for the plan, and for the Named Executive Officers who are members of the Office of the Chief Executive, the maximum award, as a percentage of target that could be received by them, subject to downward adjustment based on individual performance. Individual awards under the Annual Incentive Plan for members of Entergy Corporation’s Office of the Chief Executive, are determined by the Personnel Committee. After considering individual performance, the Personnel Committee approved a payout of 133% of target for Entergy Corporation’s Chief Executive Officer and payouts ranging from 100% to 130% of target for the Named Executive Officers who are members of the Office of the Chief Executive.

After the EAM was established to determine overall funding for the Annual Incentive Plan, Entergy Corporation’s Chief Executive Officer allocated incentive award funding to individual business units based on business unit results. Individual awards were determined for the Named Executive officers who are not members of the Office of the Chief Executive by their immediate supervisor based on the individual officer’s key accountabilities, accomplishments, and performance. This resulted in payouts that ranged from 60% of target to 125% of target for the Named Executive Officers who are not members of Entergy Corporation’s Office of the Chief Executive.

Long-Term Incentives

Long term incentives consist of three components to incentivize long-term value creation - performance units, stock options, and restricted stock. Performance under the Long-Term Performance Unit Program is measured over a three year period by assessing Entergy Corporation’s total shareholder return in relation to the total shareholder return of the companies included in the Philadelphia Utility Index. Payouts, if any, are based on Entergy Corporation’s total shareholder return performance in relation to its peers and are not subject to adjustment by the Personnel Committee. Entergy Corporation also uses stock options, which reward increases in the market value of its common stock, and restricted stock which is an effective retention mechanism.

•

Long-Term Performance Unit Program Payout. For the three year performance period ending in 2016, Entergy Corporation’s total shareholder return was in the third quartile, resulting in a payout of 36% of target for its executive officers. Payouts were made in shares of Entergy Corporation stock which are required to be held by executives until they satisfy the executive stock ownership guidelines.

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What Entergy Corporation Pays and Why

How Entergy Corporation Sets Target Pay

To develop a competitive compensation program, the Personnel Committee annually reviews compensation data from two sources:

Use of Competitive Data

The Personnel Committee uses published and private compensation survey data to develop marketplace compensation levels for the executive officers. The data, which are compiled by Pay Governance LLC, the Committee’s independent compensation consultant, compare the current compensation opportunities provided to each of Entergy Corporation’s executive officers against the compensation opportunities provided to executives holding similar positions at companies with corporate revenues similar to Entergy Corporation’s. For non-industry specific positions, the Committee reviews general industry data for total cash compensation (base salary and annual incentive) since the market for talent is broader than the utility sector. For management positions that are industry-specific, such as Group President, Utility Operations, the Committee reviews data from utility companies for total cash compensation. However, for long-term incentives, all positions are reviewed relative to utility market data. The survey data reviewed by the Committee cover hundreds of companies across a broad range of industries and approximately 60 investor-owned utility companies. In evaluating compensation levels against the survey data, the Committee considers only the aggregated survey data. The identities of the companies participating in the compensation survey data are not disclosed to, or considered by, the Committee in its decision-making process and, thus, are not considered material by the Committee.

The Committee uses this survey data to develop compensation opportunities that are designed to deliver total target compensation at approximately the 50th percentile of the surveyed companies in the aggregate. The survey data are the primary data used for purposes of assessing target compensation. As a result, Mr. Denault, Entergy Corporation’s Chief Executive Officer, is compensated at a higher level than the other Named Executive Officers, reflecting market practices that compensate chief executive officers at greater potential compensation levels with more pay “at risk” than other Named Executive Officers, due to the greater responsibilities and accountability required of a Chief Executive Officer. In most cases, the Committee considers its objectives to have been met if Entergy Corporation’s Chief Executive Officer and the eight (8) other executive officers who constitute what is referred to as the Office of the Chief Executive each has a target compensation opportunity that falls within the range of 85% - 115% of the 50th percentile of the survey data. Promoted officers or officers who are new to their roles may be transitioned into the targeted market range over time. Actual compensation received by an individual officer may be above or below the targeted range based on an individual officer’s skills, performance, experience, and responsibilities, Entergy Corporation performance, and internal pay equity. For 2016, the total target compensation of most of the Named Executive Officers fell within the targeted range except there was one officer whose total targeted compensation was slightly above the targeted range, two officers whose total targeted compensation was slightly below the targeted range, based on skills, performance, experience and responsibilities, and internal pay equity, and one that was below the targeted range who is new to the role.

Proxy Analysis

Although the survey data described above are the primary data used in determining compensation, the Committee reviews data derived from the proxy statements of companies included in the Philadelphia Utility Index as an additional point of comparison. The proxy data are used to compare the compensation levels of the Named Executive Officers who are members of the Office of the Chief Executive with the compensation levels of the corresponding top 5 highest paid executive officers of the companies included in the Philadelphia Utility Index, as reported in their proxy statements. The Personnel Committee uses this analysis to evaluate the overall reasonableness of Entergy Corporation’s compensation programs. The following companies were included in the Philadelphia Utility Index at the time the proxy data from the 2016 filings were compiled:

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Ÿ	AES Corporation	Ÿ	El Paso International
Ÿ	Ameren Corporation	Ÿ	EverSource Energy
Ÿ	American Electric Power Co. Inc.	Ÿ	Exelon Corporation
Ÿ	American Water Works	Ÿ	FirstEnergy Corporation
Ÿ	CenterPoint Energy Inc.	Ÿ	NextEra Energy
Ÿ	Consolidated Edison Inc.	Ÿ	PG&E Corporation
Ÿ	Dominion Resources Inc.	Ÿ	Public Service Enterprise Group, Inc.
Ÿ	DTE Energy Company	Ÿ	Southern Company
Ÿ	Duke Energy Corporation	Ÿ	Xcel Energy
Ÿ	Edison International

Executive Compensation Elements

The following table summarizes the elements of total direct compensation (TDC) granted or paid to the executive officers under the 2016 executive compensation program. The program uses a mix of fixed and variable compensation elements and provides alignment with both short- and long-term business goals through annual and long-term incentives. The Personnel Committee establishes the performance measures and ranges of performance for the variable compensation elements. An individual’s award is based primarily on corporate performance, market-based compensation levels, and individual performance.



Element	Key Characteristics	Why This Element Is Paid	How This Amount Is Determined	2016 Decisions
Base Salary	Fixed compensation component payable in cash. Reviewed annually and adjusted when appropriate.	Provides a base level of competitive cash compensation for executive talent.	Experience, job scope, market data, individual performance, and internal pay equity.	All of the Named Executive Officers, other than Mr. Bakken and Mr. Riley, received increases in their base salaries effective April 2016 ranging from 2.5% to 4.5%. In addition to his merit increase, Mr. Brown’s salary was increased by approximately 18% to reflect the additional responsibilities he assumed in 2016. Mr. Fisackerly’s base salary was increased by 9.5% to reflect competitive market data. Mr. Riley’s base salary was increased when he became President, Entergy Arkansas. Mr. Bakken’s base salary was determined using market data.

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Element	Key Characteristics	Why This Element Is Paid	How This Amount Is Determined	2016 Decisions
Annual Incentive Awards	Variable compensation component payable in cash based on performance against goals established annually.	Motivate and reward executives for performance on key financial and operational measures during the year.	Target opportunity is determined based on job scope, market data, and internal pay equity. For 2016, awards were determined based on success in meeting operational earnings per share and operational operating cash flow targets, subject to downward adjustment at the Personnel Committee’s discretion for members of the Office of the Chief Executive.	Mr. Denault's target annual incentive award for 2016 was 135% of base salary, and target awards were in the range of 40% to 70% of base salary for the other Named Executive Officers. Strong operational and financial performance and a review of individual performance resulted in an award at 133% of target for Entergy Corporation’s Chief Executive Officer, and awards that ranged from 60% to 125% of target for the other Named Executive Officers.
Long-Term Performance Unit Program	Each performance unit equals one share of Entergy Corporation’s common stock. Performance is measured at the end of a three-year performance period. Each unit also earns the equivalent of the dividends paid during the performance period. Performance units granted under the Long-Term Performance Unit Program are settled in shares of Entergy Corporation common stock.	Focuses the executive officers on building long-term shareholder value and increases executive officers’ ownership of Entergy Corporation common stock.	Payout based on Entergy Corporation’s total shareholder return relative to the total shareholder return of the companies in the Philadelphia Utility Index.	Performance unit grants for the 2016 to 2018 performance period represented approximately 39% of target TDC for Entergy Corporation’s Chief Executive Officer and approximately 21% to 31% for the other Named Executive Officers. Unfavorable relative total shareholder return in 2015 and 2016, partially offset by strong relative total shareholder return for 2014, resulted in performance in the third quartile for the 2014 to 2016 performance period, yielding a payout of 36% of target for the Named Executive Officers who are members of the Office of the Chief Executive.
Stock Options	Non-qualified stock options are granted at fair market value, have a ten-year term, and vest over 3 years - 33 1/3% on each anniversary of the grant date.	Reward executives for absolute value creation and coupled with restricted stock provide competitive compensation, retain executive talent, and increase the executive officers’ ownership in Entergy Corporation’s common stock.	Job scope, market data, individual performance, and Entergy Corporation performance.	Stock options granted in 2016 represented approximately 13% of total TDC for Entergy Corporation’s Chief Executive Officer and approximately 7% to 10% for the other Named Executive Officers.
Restricted Stock Awards	Restricted stock awards vest over 3 years - 33 1/3% on each anniversary of the grant date, have voting rights, and accrue dividends during the vesting period.	Coupled with stock options, align interests of executives with long-term shareholder value, provide competitive compensation, retain executive talent, and increase the executive officers’ ownership of Entergy Corporation common stock.	Job scope, market data, individual performance, and Entergy Corporation performance.	Restricted stock granted in 2016 represented approximately 13% of total target compensation for Entergy Corporation’s Chief Executive Officer and approximately 7% - 10% for the other Named Executive Officers.

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Fixed Compensation

Base Salary

The Personnel Committee determines the base salaries for all of the Named Executive Officers who are members of the Office of the Chief Executive based on competitive compensation data, performance considerations, and advice provided by the Committee’s independent compensation consultant. For the other Named Executive Officers, their salaries are established by their immediate supervisors using the same criteria. The Committee also considers internal pay equity; however, the Committee has not established any predetermined formula against which the base salary of one Named Executive Officer is measured against another officer or employee.

In 2016, all of the Named Executive Officers, other than Mr. Bakken and Mr. Riley, received merit increases in their base salaries ranging from approximately 2.5% to 4.5%. The increases in base salary were made in light of current economic conditions and the projected growth in executive salaries in 2016 based on the market data previously discussed in this CD&A under “What Entergy Corporation Pays and Why - How Entergy Corporation Sets Target Pay,” as well as an internal pay equity comparison.

The following table sets forth the 2015 and 2016 base salaries for the Named Executive Officers. Except as indicated below, changes in base salaries for 2016 were effective in April.



Named Executive Officer	2015 Base Salary	2016 Base Salary
A. Christopher Bakken, III⁽¹⁾	$—	$605,000
Marcus V. Brown⁽²⁾	$491,500	$605,000
Leo P. Denault	$1,170,000	$1,200,000
Haley R. Fisackerly⁽³⁾	$310,434	$350,000
Andrew S. Marsh	$537,892	$559,408
Phillip R. May, Jr.	$346,250	$356,650
Hugh T. McDonald	$360,121	$360,121
Sallie T. Rainer	$307,275	$319,475
Charles L. Rice, Jr.	$268,470	$280,424
Richard C. Riley⁽⁴⁾	$306,168	$335,000
Roderick K. West	$643,044	$659,120


(1)	When Mr. Bakken joined Entergy in April 2016, his base salary was set at $605,000 based on competitive market data that placed him at the 50th percentile of the market data discussed above, as well as internal pay equity considerations.

(2)

In April 2016, Mr. Brown received a merit increase of 4% to his base salary. In May 2016, Mr. Brown’s base salary was further adjusted to $605,000 following an external market competitive pay analysis to reflect his additional responsibilities when he assumed leadership of Entergy Corporation’s corporate communications and regulatory and governmental affairs groups, in addition to his leadership of Entergy Corporation’s legal department.


(3)	In November 2016, Mr. Fisackerly’s base salary was increased by 9.5% after a review of his compensation in light of his experience relative to competitive market data.


(4)	In May 2016, Mr. Riley’s salary was increased from $306,168 to $335,000 when he became President and Chief Executive Officer, Entergy Arkansas and assumed the increased responsibilities of that role.

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Variable Compensation

Short-Term Compensation

Annual Incentive Plan

Performance-based incentives are included in the Named Executive Officers’ compensation packages because Entergy Corporation believes performance-based incentives encourage the Named Executive Officers to pursue objectives consistent with the overall Entergy Corporation goals and strategic direction that the Entergy Corporation Board has approved.

EAM is the performance metric used to determine the maximum percentage of target annual plan opportunities that will be paid each year to each Named Executive Officer who is a member of the Office of the Chief Executive under the Annual Incentive Plan. Once the EAM has been determined, individual awards for the Office of the Chief Executive members may be adjusted downward, but not upward, from the EAM at the Personnel Committee’s discretion, based on individual performance and other factors deemed relevant by the Personnel Committee. For 2016, the target Annual Incentive Plan opportunities for each of the Named Executive Officers, expressed as a percentage of the officer’s base salary, were:


•	135% for Mr. Denault;


•	70% for Mr. Bakken, Mr. Brown, Mr. Marsh, and Mr. West;


•	60% for Mr. May;


•	50% for Mr. McDonald; and


•	40% for Mr. Fisackerly, Ms. Rainer, Mr. Rice, and Mr. Riley.

The target opportunities established for these officers were comparable to the target opportunities historically set for these positions and levels of responsibility, except for Mr. Denault’s and Mr. Riley’s. Mr. Denault’s target opportunity was set to align it with target opportunities of other chief executive officers based on the compensation survey data compiled by Pay Governance. Mr. Riley’s target was set consistent with market and internal pay equity. Target opportunities for the Named Executive Officers who are members of the Office of the Chief Executive are established by the Personnel Committee, and these Named Executive Officers may earn a maximum payout ranging from 0% to 200% of their target opportunity, calculated as described in the table below.

Target award opportunities are set based on an executive officer’s position and executive management level within the Entergy organization. Executive management levels at Entergy range from Level 1 through Level 4. At December 31, 2016, Mr. Denault held a Level 1 position, Messrs. Bakken, Brown, Marsh, and West held positions in Level 2, Mr. May held a Level 3 position, and the remaining Named Executive Officers held positions in Level 4. Accordingly, their respective incentive award opportunities differ from one another based on their management level and the external market data developed by the Committee’s independent compensation consultant.

Each year the Personnel Committee reviews the performance measures used to determine the EAM. In December 2015, the Personnel Committee decided to retain operational earnings per share and operational operating cash flow, each measure weighted equally, as the performance measures for determining the EAM. The Committee considered a variety of other potential measures, but determined that operational earnings per share and operational operating cash flow continued to be the best metrics to use because, among other things, they are objective measures that Entergy Corporation’s investors consider to be important in evaluating its financial performance and because Entergy Corporation’s goals in that regard are broadly communicated both internally and externally. This provides both discipline and transparency that the Committee believes are important objectives of any well designed incentive compensation plan.

The Personnel Committee also engages in a rigorous process each year to establish the targets for the Annual Incentive Plan with a goal of establishing target achievement levels that are consistent with Entergy Corporation’s strategy and business objectives for the upcoming year, as reflected in its financial plan, and sufficient to drive results that represent a high level of achievement, taking into consideration the applicable business environment and specific

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challenges facing it. These targets are approved based on a comprehensive review by the full Board of Entergy Corporation’s financial plan, including changes in commodity market conditions and other key drivers of anticipated changes in performance from the preceding year. The Committee also reviews the effects on plan results of various risks and opportunities that are recognized at the time the plan is set, to assure that targets that are determined based on the plan reflect an appropriate balance of risks and opportunities. The Committee further confirms that the targets it approves are aligned with the earnings guidance that will be communicated to the financial markets, which assures that the internal targets Entergy Corporation sets for purposes of its incentive compensation plans are aligned with the external expectations set and communicated to its shareholders.

In January 2016, after full Board review of management’s 2016 financial plan for Entergy Corporation and engaging in the process discussed above, the Committee determined the Annual Incentive Plan targets to be used for purposes of determining Annual Incentive Plan awards for 2016. In keeping with its past practice, the Committee also determined that for purposes of measuring performance against such targets, the Committee would exclude the effect on reported results of any major storms that may occur during the year. This exclusion was viewed by the Committee as appropriate because although Entergy Corporation includes estimates for minor storm events in its financial plan, it does not include estimates for a major storm event, such as a hurricane. The Committee also approved the exclusion from reported results of the outcome of a pending regulatory litigation matter, to the extent such outcome was not treated as a special item and excluded from operational results. Neither of these pre-approved exclusions ultimately resulted in any adjustment to the reported results.

In determining the targets to set for 2016, the Committee reviewed anticipated drivers for operational earnings per share and operational operating cash flow for 2016 as set forth in Entergy Corporation’s financial plan. Under the plan, operational earnings per share were expected to decline from 2015 results due primarily to the significant impact on 2015 operational results of tax benefits and, to a lesser extent, favorable weather, which were not anticipated to recur in 2016. Together, they accounted for $1.89 of operational earnings per share for 2015. Under the plan, operational operating cash flow was also expected to decline slightly in 2016 from 2015 results due primarily to the timing of recovery of certain fuel and purchased power costs in the utility business.

After adjusting to eliminate the impact of weather and tax benefits, the 2016 plan targets for operational earnings per share required management to achieve strong growth in utility operational earnings and modest growth in Entergy Wholesale Commodities operational earnings, despite an expectation for further declines in wholesale energy and capacity prices. While the resulting targets represented declines from 2015 operational results, the Committee concluded, based on a careful review of the overall plan, that the targets derived from the plan challenged management appropriately to deliver strong growth in Entergy Corporation’s core business while continuing to manage the significant risks at Entergy Wholesale Commodities and represented an appropriate balancing of Entergy Corporation’s business risks and opportunities for 2016.

The following table shows the resulting Annual Incentive Plan targets established by the Personnel Committee in January 2016, and 2016 results:

Annual Incentive Plan Targets and Results



	Performance Goals⁽¹⁾
	Minimum	Target	Maximum	2016 Results
Operational Earnings Per Share ($)	$4.82	$5.35	$5.88	$7.11
Operational Operating Cash Flow ($ billion)	$2.795	$3.180	$3.565	$3.004
EAM as % of Target	25%	100%	200%	133%


(1)	Payouts for performance between minimum and target achievement levels and between target and maximum levels are calculated using straight-line interpolation. There is no payout for performance below minimum.

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In January 2017, the Finance and Personnel Committees jointly reviewed Entergy Corporation’s financial results against the performance objectives reflected in the table above. Management discussed with the Committees the operational earnings per share and operating cash flow results for 2016, including primary factors explaining how those results compared to the 2016 business plan and Annual Incentive Plan targets. Operational earnings per share exceeded the operational earnings per share goal of $5.35 per share set at the beginning of the year by $1.76, but management fell short of achieving its operational operating cash flow goal of $3.180 billion by approximately $176 million, leading to a calculated EAM of 133%. Operational results excluded the impact of certain special items that were excluded from as-reported (GAAP) earnings per share and operating cash flow to determine operational earnings per share and operational operating cash flow, including asset impairments and related write-offs at Entergy Wholesale Commodities related to Entergy Corporation’s 2016 decision to close two nuclear generating plants, and certain costs associated with nuclear plant closings. The Personnel Committee did not make any adjustments to the operational earnings per share and operating cash flow results to determine the EAM for 2016.

For members of Entergy Corporation’s Office of the Chief Executive, individual executive officer awards under the Annual Incentive Plan are determined by the Personnel Committee. In determining these individual executive officer awards under the Annual Incentive Plan, the Committee considered individual performance and, in particular, whether there were additional factors beyond those captured by the EAM measures that should be taken into account in determining whether to exercise negative discretion to reduce awards below the levels determined by the EAM. In determining the extent of negative discretion, if any, that it would exercise with respect to each Named Executive Officer who is a member of the Office of the Chief Executive, the Committee considered the executive's key accountabilities and accomplishments, time in role, and individual performance executing on Entergy Corporation’s strategies in 2016. This resulted in a payout equal to the EAM, or 133% of target, for the Chief Executive Officer and awards ranging from 100% of target to 130% of target for the other Named Executive Officers who are members of the Office of the Chief Executive.

After the EAM was established to determine overall funding for the Annual Incentive Plan, Entergy Corporation’s Chief Executive Officer allocated incentive award funding to individual business units based on business unit results. Individual awards were determined for the remaining Named Executive Officers who are not members of the Office of the Chief Executive by their immediate supervisor based on the individual officer’s key accountabilities, accomplishments, and performance. This resulted in payouts that ranged from 60% of target to 125% of target for the Named Executive Officers who are not members of the Office of the Chief Executive.

Based on the foregoing evaluation of management performance, the Personnel Committee approved the following Annual Incentive Plan payouts to each Named Executive Officer for 2016:



Named Executive Officer	Base Salary	Target as Percentage of Base Salary	Payout as Percentage of Target	2016 Annual Incentive Award
A. Christopher Bakken, III	$605,000	70%	125%	$529,375
Marcus V. Brown	$605,000	70%	130%	$550,550
Leo P. Denault	$1,200,000	135%	133%	$2,154,600
Haley R. Fisackerly	$350,000	40%	120%	$168,000
Andrew S. Marsh	$559,408	70%	130%	$509,061
Phillip R. May, Jr.	$356,650	60%	105%	$224,690
Hugh T. McDonald⁽¹⁾	$360,121	50%	44%	$79,827
Sallie T. Rainer	$319,475	40%	120%	$153,348
Charles L. Rice, Jr.	$280,424	40%	60%	$67,302
Richard C. Riley	$335,000	40%	125%	$167,500
Roderick K. West	$659,120	70%	100%	$461,384


(1)	Pursuant to the terms of the Annual Incentive Plan, Mr. McDonald received a pro-rated annual incentive award since he retired prior to the end of the performance year.

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Long-Term Incentive Compensation

Entergy Corporation’s goal for its long-term incentive compensation is to focus the executive officers on building shareholder value and to increase the executive officers’ ownership of Entergy Corporation’s common stock in order to more closely align their interest with those of its shareholders. In Entergy Corporation’s long-term incentive compensation programs, a mix of performance units, restricted stock, and stock options are used. Performance units reward the Named Executive Officers on the basis of total shareholder return, which is a measure of stock price appreciation and dividend payments, in relation to the companies in the Philadelphia Utility Index. Restricted stock ties the executive officers’ long-term financial interest to the long-term financial interests of Entergy Corporation’s shareholders. Stock options provide a direct incentive to increase the value of Entergy Corporation’s common stock. In general, Entergy Corporation seeks to allocate the total value of long-term incentive compensation 60% to performance units and 40% to a combination of stock options and restricted stock, equally divided in value, based on the value the compensation model seeks to deliver. Awards for individual Named Executive Officers may vary from this target as a result of individual performance, promotions, and internal pay equity.

The performance units for the 2014-2016 and 2015-2017 performance periods were awarded under the 2011 Equity Ownership Plan and Long-Term Cash Incentive Plan (2011 Equity Ownership Plan) and the performance units for the 2016-2018 performance period and all of the shares of restricted stock, stock options, and restricted stock units granted to the Named Executive Officers in 2016 were granted pursuant to the 2015 Equity Ownership Plan (the 2015 Equity Ownership Plan, together with the 2011 Equity Ownership Plan, the Equity Ownership Plans). The Equity Ownership Plans require both a change in control and an involuntary job loss or substantial diminution of duties (a “double trigger”) for the acceleration of these awards upon a change in control.

Performance Unit Program

Entergy Corporation issues performance unit awards to the Named Executive Officers under the Long-Term Performance Unit Program. Each performance unit represents the value of one share of Entergy Corporation’s common stock at the end of the three-year performance period, plus dividends accrued during the performance period. The Personnel Committee sets payout opportunities for the program at the outset of each performance period, and the program is structured to reward Named Executive Officers only if performance goals approved by the Personnel Committee are met. The Personnel Committee has no discretion to make awards if minimum performance goals are not achieved.

The performance units granted under the Long-Term Performance Unit Program and accrued dividends on any shares earned during the performance period are settled in shares of Entergy Corporation common stock rather than cash. All shares paid out under the Long-Term Performance Unit Program are required to be retained by the officers until applicable executive stock ownership requirements are met.

The Long-Term Performance Unit Program specifies a minimum, target, and maximum achievement level, the achievement of which will determine the number of performance units that may be earned by each participant. Entergy Corporation measures performance by assessing Entergy Corporation’s total shareholder return relative to the total shareholder return of the companies in the Philadelphia Utility Index, which Entergy Corporation refers to as its peer companies. The Personnel Committee identified the Philadelphia Utility Index as the appropriate industry peer group for this purpose because the companies included in this index, in the aggregate, approximate Entergy Corporation in terms of business and scale. The Personnel Committee chose relative total shareholder return as a measure of performance because it reflects Entergy Corporation’s creation of shareholder value relative to other electric utilities over the performance period. It also takes into account dividends paid by the companies in this index and normalizes certain events that affect the industry as a whole. Minimum, target, and maximum performance levels are determined by reference to the ranking of Entergy Corporation’s total shareholder return against the total shareholder return of the companies in the Philadelphia Utility Index.

Performance Unit Program Grants. At any given time, a participant in the Long-Term Performance Unit Program may be participating in up to three performance periods. During 2016, eligible participants were participating

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in the 2014-2016, 2015-2017, and 2016-2018 performance periods. Subject to achievement of the applicable performance levels as described below, the Personnel Committee established the following target performance unit payout opportunities for each of the 2014-2016, 2015-2017, and 2016-2018 performance periods.



Named Executive Officer	2014-2016 Target Opportunity	2015-2017 Target Opportunity	2016-2018 Target Opportunity
A. Christopher Bakken, III ⁽¹⁾	—	3,639	7,289
Marcus V. Brown	9,400	6,550	8,200
Leo P. Denault	40,000	33,100	41,700
Haley R. Fisackerly	2,200	1,450	1,800
Andrew S. Marsh	9,400	6,550	8,200
Phillip R. May, Jr.	3,100	2,050	2,700
Hugh T. McDonald⁽²⁾	1,711	644	—
Sallie T. Rainer	2,200	1,450	1,800
Charles L. Rice, Jr.	2,200	1,450	1,800
Richard C. Riley	2,200	1,450	1,800
Roderick K. West	9,400	6,550	8,200


(1)	As a new hire in 2016, Mr. Bakken did not participate in the 2014-2016 performance period, but received pro-rated target award opportunities for the 2015-2017 and 2016-2018 performance periods.


(2)	In light of his anticipated retirement in May 2016, Mr. McDonald received a pro-rated target award opportunity for 2014-2016 and 2015-2017 and did not receive award opportunities for the 2016-2018 performance period.

The range of potential payouts for the 2014-2016, 2015-2017, and 2016-2018 performance periods under the program is shown below.



Performance Level	Zero	Minimum	Target	Maximum
Total Shareholder Return	4th Quartile	Bottom of Third Quartile	Median percentile	Top Quartile
Payout	No Payout	Minimum Payout of 25% of target	100% of target	200% of Target

For the 2015-2017 and 2016-2018 performance periods, there is no payout for performance that falls within the lowest quartile of performance of the peer companies, and for top quartile performance a maximum payout of 200% of target is earned. Payouts between minimum and target and between target and maximum are calculated by interpolating between the performance of the company at the top of the fourth quartile of performance of the peer companies and the median or between the median and the performance of the company at the bottom position of the top quartile of performance of the peer companies, respectively.

Payout for the 2014-2016 Performance Period. In January 2017, the Committee reviewed Entergy Corporation’s total shareholder return for the 2014-2016 performance period in order to determine the payout to participants for the 2014-2016 performance period. The Committee compared Entergy Corporation’s total shareholder return against the total shareholder return of the companies that comprise the Philadelphia Utility Index, with the performance measures and range of potential payouts for the 2014-2016 performance period similar to that discussed above. As recommended by the Finance Committee, the Personnel Committee determined that Entergy Corporation’s relative total shareholder return fell in the third quartile, resulting in payouts to the Named Executive Officers of 36% of target. Payouts under the performance unit program are made in shares of Entergy Corporation common stock. For the 2014-2016 performance period, the following numbers of shares of Entergy Corporation common stock, including dividend equivalents were issued:

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Named Executive Officer	2014-2016 Target	Number of Shares Issued	Value of Shares Actually Issued⁽¹⁾	Grant Date Fair Value
A. Christopher Bakken⁽²⁾	—	—	$—	$—
Marcus V. Brown	9,400	3,848	$276,633	$631,304
Leo P. Denault	40,000	16,375	$1,177,199	$2,686,400
Haley R. Fisackerly	2,200	900	$64,701	$147,752
Andrew S. Marsh	9,400	3,848	$276,633	$631,304
Phillip R. May, Jr.	3,100	1,269	$91,228	$208,196
Hugh T. McDonald⁽³⁾	1,711	678	$48,741	$114,911
Sallie T. Rainer	2,200	900	$64,701	$147,752
Charles L. Rice, Jr.	2,200	900	$64,701	$147,752
Richard C. Riley	2,200	900	$64,701	$147,752
Roderick K. West	9,400	3,848	$276,633	$631,304


(1)	Value determined based on the closing price of Entergy Corporation’s common stock on January 18, 2017 ($71.89), the date the Personnel Committee certified the 2014-2016 performance period results.


(2)	As a new hire in 2016, Mr. Bakken was not eligible to participate in the 2014-2016 performance period.


(3)	Pursuant to the terms of the Long-Term Performance Unit Program, Mr. McDonald received a pro-rated award since he retired prior to the end of the performance period.

Stock Options and Restricted Stock

Stock options and restricted stock are granted as a long-term incentive to the executive officers. As previously discussed, the Personnel Committee considers several factors in determining the number of stock options and shares of restricted stock it will grant to the Named Executive Officers, including Entergy Corporation and individual performance, internal pay equity, prevailing market practice, targeted long-term value created by the use of stock options and restricted stock, and the potential dilutive effect of stock option and restricted stock grants. The Committee’s assessment of individual performance of each Named Executive Officer is the most important factor in determining the number of shares of restricted stock and stock options awarded, except with respect to the Chief Executive Officer for whom comparative market data is the most important factor. Stock option and restricted stock awards for Entergy Corporation’s Chief Executive Officer are determined solely by the Personnel Committee on the basis of the same considerations. Mr. Denault’s 2016 awards are comparable to historical awards granted to Entergy Corporation’s Chief Executive Officer and reflect the decreased stock price at the time of grant.

The following table sets forth the number of stock options and shares of restricted stock granted to each Named Executive Officer in 2016. The exercise price for each option was $70.56, which was the closing price of Entergy Corporation’s common stock on the date of grant.

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Named Executive Officer	Stock Options	Shares of Restricted Stock
A. Christopher Bakken, III⁽¹⁾	—	—
Marcus V. Brown	45,000	6,400
Leo P. Denault	167,000	15,700
Haley R. Fisackerly	6,700	1,100
Andrew S. Marsh	45,000	6,400
Phillip R. May, Jr.	9,600	1,400
Hugh T. McDonald⁽²⁾	—	—
Sallie T. Rainer	6,700	1,100
Charles L. Rice, Jr.	6,700	1,100
Richard C. Riley	4,700	1,050
Roderick K. West	41,000	6,000


(1)	Mr. Bakken was not eligible to receive stock options or restricted stock in 2016.


(2)	In light of his upcoming retirement in May 2016, Mr. McDonald did not receive any stock options or restricted stock when the awards were determined in January 2016.

Restricted Stock Units

Restricted stock units granted under the 2015 Equity Ownership Plan represent phantom shares of Entergy Corporation common stock (i.e., non-stock interests that have an economic value equivalent to a share of its common stock). Entergy Corporation occasionally grants restricted stock units for retention purposes, to offset forfeited compensation from a previous employer or for other limited purposes. If all conditions of the grant are satisfied, restrictions on the restricted units lift at the end of the restricted period, and the restricted stock units are settled in shares of Entergy Corporation common stock. Restricted stock units are generally service-based awards for which restrictions lift, subject to continued employment, generally over a two- to five-year period.

On April 6, 2016, in connection with the commencement of his employment as Chief Nuclear Officer, the Personnel Committee granted Mr. Bakken 30,000 restricted stock units. Mr. Bakken’s award was made in part to recruit him to join Entergy, to offset compensation that Mr. Bakken forfeited by joining Entergy, in recognition of his leadership role as Chief Nuclear Officer to transform the nuclear fleet, and to encourage retention of his leadership in light of his marketability as a chief nuclear officer.

Mr. Bakken’s restricted stock units will vest and be settled in shares of Entergy Corporation’s common stock in three equal installments on April 6, 2019, April 6, 2022, and April 6, 2025, provided that he remains continually employed as Chief Nuclear Officer or in a comparable position through each vesting date. Pursuant to his restricted stock unit agreement, if Mr. Bakken’s employment terminates due to total disability or death, then he will vest in and be paid the 10,000 restricted stock units that otherwise would have vested had he satisfied the vesting conditions of the restricted stock unit agreement through the next vesting date to occur following the date of his death or total disability. Additionally, if Mr. Bakken’s employment is terminated by his Entergy employer other than for cause on or before April 5, 2019, then he will vest in and be paid the 10,000 restricted stock units in which he otherwise would have vested on April 6, 2019, subject to Mr. Bakken timely executing and not revoking a release of claims against Entergy Corporation and its affiliates. In the event of a change in control, the unvested restricted stock units will fully vest upon Mr. Bakken’s termination of employment by his Entergy employer without cause or by Mr. Bakken with good reason during a change in control period (as defined in the 2015 Equity Ownership Plan). Otherwise, if Mr. Bakken voluntarily resigns or is terminated, he will forfeit all unvested stock units.

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Benefits and Perquisites

Entergy’s Named Executive Officers are eligible to participate in or receive the following benefits:



Plan Type	Description
Retirement Plans	Entergy Corporation-sponsored: Entergy Retirement Plan - a tax-qualified final average pay defined benefit pension plan that covers a broad group of employees hired before July 1, 2014. Cash Balance Plan - a tax-qualified cash balance defined benefit retirement plan that covers a broad group of employees hired on or after July 1, 2014. Pension Equalization Plan - a non-qualified pension restoration plan for a select group of management or highly compensated employees who participate in the Entergy Retirement Plan. Cash Balance Equalization Plan - a non-qualified restoration plan for a select group of management or highly compensated employees who participate in the Cash Balance Plan. System Executive Retirement Plan - a non-qualified supplemental retirement plan for individuals who became executive officers before July 1, 2014. See the 2016 Pension Benefits Table for additional information regarding the operation of the plans described above.
Savings Plan	Entergy Corporation-sponsored 401(k) Savings Plan that covers a broad group of employees.
Health & Welfare Benefits	Medical, dental, and vision coverage, life and accidental death and dismemberment insurance, business travel accident insurance, and long-term disability insurance. Eligibility, coverage levels, potential employee contributions, and other plan design features are the same for the Named Executive Officers as for the broad employee population.
2016 Perquisites	Corporate aircraft usage, annual physical exams, relocation assistance, and event tickets. The Office of the Chief Executive members do not receive tax gross ups on any benefits, except for relocation assistance. Named Executive Officers who are not members of the Office of the Chief Executive also were provided in 2016 with club dues, housing allowances, where appropriate, and tax gross up payments on some perquisites. For additional information regarding perquisites, see the “All Other Compensation” column in the 2016 Summary Compensation Table.
Deferred Compensation	The Named Executive Officers are eligible to defer up to 100% of their base salary and Annual Incentive Plan awards into the Entergy Corporation-sponsored Executive Deferred Compensation Plan.
Executive Disability Plan	Eligible individuals who become disabled under the terms of the plan are eligible for 65% of the difference between their base salary and $276,923 (i.e. the base salary that produces the maximum $15,000 monthly disability payment under the general long-term disability plan).

Entergy Corporation provides these benefits to its Named Executive Officers as part of providing a competitive executive compensation program and because it believes that these benefits are important retention and recruitment tools since many, if not all, of the companies with which Entergy Corporation competes for executive talent provide similar arrangements to their senior executive officers.

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Compensation Arrangements

Mr. Bakken’s Employment

In connection with the commencement of his employment, Mr. Bakken received a sign-on bonus of $650,000 and received a grant of 30,000 restricted stock units on April 6, 2016, the terms of which are previously described. Mr. Bakken is also eligible for certain relocation benefits pursuant to Entergy Corporation’s Relocation Assistance Policy and to certain additional relocation benefits, including the direct purchase of his home at an agreed upon price, which the Personnel Committee determined was necessary to facilitate Mr. Bakken's transition to Entergy Corporation and to mitigate the expenses associated with his relocation. Mr. Bakken’s sign-on bonus and certain of his relocation benefits are subject to forfeiture if Mr. Bakken terminates his service prior to the one year anniversary of his date of hire.

Mr. Bakken is expected to be eligible to participate in the annual and long-term incentive plans at the same level as the other Named Executive Officers who are members of the Office of the Chief Executive, except Mr. Denault. Mr. Bakken was not eligible to participate in the 2014-2016 performance period, but received pro-rated target award opportunities for the 2015-2017 and 2016-2018 performance periods, in accordance with the terms of the program. Mr. Bakken also participates in the Cash Balance Plan and the Cash Balance Equalization Plan, retirement plans that are available to all eligible executive officers hired on or after July 1, 2014. For more information about the Cash Balance Plan and the Cash Balance Equalization Plan, see “2016 Pension Benefits.” Beginning in 2017, Mr. Bakken also is eligible to participate in the annual stock option and restricted stock programs.

Mr. Bakken also participates in the Nuclear Retention Plan, a retention plan for officers and other leaders with expertise in the nuclear industry. The Personnel Committee authorized this plan to attract and retain key management and employee talent in the nuclear power field, a field that requires unique technical and other expertise that is in great demand in the utility industry. The plan provides for bonuses to be paid annually over a three-year employment period with the bonus opportunity dependent on the participant’s management level and continued employment. Each annual payment is equal to an amount ranging from 15% to 30% of the employee’s base salary as of their date of enrollment in the plan. Mr. Bakken’s participation in the plan commenced in May 2016 and in accordance with the terms and conditions of the plan, in May 2017, 2018, and 2019, subject to his continued employment, Mr. Bakken will receive a cash bonus equal to 30% of his base salary as of May 1, 2016. This plan does not allow for accelerated or pro-rated payout upon termination of any kind. The three year coverage period and percentage of base salary payable under the plan are consistent with the terms of participation of other senior nuclear officers who participate in this plan.

The terms of Mr. Bakken’s employment were reviewed by the Personnel Committee, were determined based on competitive market data, and were designed to reflect the competition for chief nuclear officer talent in the marketplace and the Committee’s assessment of the critical role this position plays in transforming the nuclear fleet and to encourage retention of his leadership in light of his marketability as a chief nuclear officer.

Post-Termination Agreements and Arrangements

The Personnel Committee believes that retention and transitional compensation arrangements are an important part of overall compensation. The Committee believes that these arrangements help to secure the continued employment and dedication of the Named Executive Officers, notwithstanding any concern that they might have at the time of a change in control regarding their own continued employment. In addition, the Committee believes that these arrangements are important as recruitment and retention devices, as all or nearly all of the companies with which Entergy Corporation competes for executive talent have similar arrangements in place for their senior employees.

To achieve these objectives, Entergy Corporation has established a System Executive Continuity Plan under which each of the Named Executive Officers is entitled to receive “change in control” payments and benefits if such officer’s employment is involuntarily terminated in connection with a change in control of Entergy Corporation. Severance payments under the System Executive Continuity Plan are based on a multiple of the sum of an executive officer’s annual base salary plus his average Annual Incentive Plan award for the two calendar years immediately preceding the calendar year in which the termination of employment occurs. Under no circumstances can this multiple

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exceed 2.99 times the sum of (a) the executive officer’s annual base salary as in effect at any time within one year prior to the commencement of a change in control period or if higher, immediately prior to a circumstance constituting good reason plus (b) his annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive Plan for the two calendar years immediately preceding the calendar year in which the officer’s termination occurs, or if higher, the annual incentive award actually received under the Annual Incentive Plan for the calendar year immediately preceding the calendar year in which the termination of employment occurs. Entergy Corporation strives to ensure that the benefits and payment levels under the System Executive Continuity Plan are consistent with market practices. The executive officers, including the Named Executive Officers, will not receive any tax gross up payments on any severance benefits received under this plan. For more information regarding the System Executive Continuity Plan, see “2016 Potential Payments Upon Termination or Change in Control-System Executive Continuity Plan.”

In certain cases, the Committee may approve the execution of a retention agreement with an individual executive officer. These decisions are made on a case by case basis to reflect specific retention needs or other factors, including market practice. If a retention agreement is entered into with an individual officer, the Committee considers the economic value associated with that agreement in making overall compensation decisions for that officer. Entergy Corporation has voluntarily adopted a policy that any employment or severance agreements providing severance benefits in excess of 2.99 times the sum of an officer’s annual base salary and annual incentive award (other than the value of the vesting or payment of an outstanding equity-based award or the pro rata vesting or payment of an outstanding long-term incentive award) must be approved by its shareholders.

Entergy Corporation currently has a retention agreement with Mr. Denault. In general, Mr. Denault’s retention agreement provides for certain payments and benefits in the event of his termination of employment by Entergy other than for cause, by Mr. Denault for good reason or on account of his death or disability. See “2016 Potential Payments Upon Termination or Change in Control - Mr. Denault’s Retention Agreement.” Because Mr. Denault has reached age 55, certain severance payment provisions in his retention agreement no longer apply. Mr. Denault will not receive tax gross up payments on any payments or benefits he may receive under his agreement. Mr. Denault’s retention agreement was entered into in 2006 when he was Entergy Corporation’s Chief Financial Officer and was designed to reflect the competition for chief financial officer talent in the marketplace at that time and the Committee’s assessment of the critical role this position played in executing Entergy Corporation’s long-term financial and other strategic objectives. Based on the market data provided by its former independent compensation consultant, the Committee believes the benefits and payment levels under Mr. Denault’s retention agreement are consistent with market practices.

For additional information regarding the System Executive Continuity Plan and Mr. Denault’s retention agreement described above, see “2016 Potential Payments Upon Termination or Change in Control.”

Compensation Policies and Practices

Entergy Corporation strives to ensure that its compensation philosophy and practices are in line with the best practices of companies in its industry as well as other companies in the S&P 500. Some of these practices include the following:

Clawback Provisions

Entergy Corporation has adopted a clawback policy that covers all individuals subject to Section 16 of the Exchange Act, including all of the members of the Office of the Chief Executive. Under the policy, the Committee will require reimbursement of incentives paid to these executive officers where:

•

(i) the payment was predicated upon the achievement of certain financial results with respect to the applicable performance period that were subsequently determined to be the subject of a material restatement other than a restatement due to changes in accounting policy; or (ii) a material miscalculation of a performance award occurs, whether or not the financial statements were restated and, in either such case, a lower payment would have been made to the executive officer based upon the restated financial results or correct calculation; or

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•	in the Board of Directors’ view, the executive officer engaged in fraud that caused or partially caused the need for a restatement or caused a material miscalculation of a performance award, in each case, whether or not the financial statements were restated.

The amount the Committee requires to be reimbursed is equal to the excess of the gross incentive payment made over the gross payment that would have been made if the original payment had been determined based on the restated financial results or correct calculation. Further, following a material restatement of Entergy Corporation’s financial statements, Entergy Corporation will seek to recover any compensation received by its Chief Executive Officer and Chief Financial Officer that is required to be reimbursed under Section 304 of the Sarbanes-Oxley Act of 2002.

Stock Ownership Guidelines and Share Retention Requirements

For many years, Entergy Corporation has had stock ownership guidelines for executives, including the Named Executive Officers. These guidelines are designed to align the executives’ long-term financial interests with those of shareholders. Annually, the Personnel Committee monitors the executive officers’ compliance with these guidelines.



Role	Value of Common Stock to be Owned
Chief Executive Officer	6 times base salary
Executive Vice Presidents	3 times base salary
Senior Vice Presidents	2 times base salary
Vice Presidents	1 time base salary

Further, to ensure compliance with the guidelines, until an executive officer satisfies the stock ownership guidelines, the officer must retain:


•	all net after-tax shares paid out under the Long-Term Performance Unit Program;


•	all net after-tax shares of the restricted stock received upon vesting; and


•	at least 75% of the after-tax net shares received upon the exercise of Entergy Corporation stock options, except for stock options granted before January 1, 2014, as to which the executive officer must retain at least 75% of the after-tax net shares until the earlier of achievement of the stock ownership guidelines or five years from the date of exercise.

Trading Controls and Anti-Pledging and Anti-Hedging Policies

Executive officers, including the Named Executive Officers, are required to receive the permission of Entergy Corporation’s General Counsel prior to entering into any transaction involving its securities, including gifts, other than the exercise of employee stock options. Trading is generally permitted only during open trading windows occurring immediately following the release of earnings. Employees, who are subject to trading restrictions, including the Named Executive Officers, may enter into trading plans under Rule 10b5-1 of the Exchange Act, but these trading plans may be entered into only during an open trading window and must be approved by Entergy Corporation. The Named Executive Officer bears full responsibility if he or she violates this policy by permitting shares to be bought or sold without pre-approval or when trading is restricted.

Entergy Corporation also prohibits its directors and executive officers, including the Named Executive Officers, from pledging any Entergy Corporation securities or entering into margin accounts involving its securities. Entergy Corporation prohibits these transactions because of the potential that sales of Entergy Corporation securities could occur outside trading periods and without the required approval of the General Counsel.

An anti-hedging policy has also been adopted that prohibits officers, directors and employees from entering into hedging or monetization transactions involving Entergy Corporation’s common stock. Prohibited transactions include, without limitation, zero-cost collars, forward sale contracts, purchase or sale of options, puts, calls, straddles or equity swaps or other derivatives that are directly linked to Entergy Corporation’s common stock or transactions

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involving “short-sales” of Entergy Corporation’s common stock. The Entergy Corporation Board adopted this policy to require officers, directors and employees to continue to own Entergy Corporation stock with the full risks and rewards of ownership, thereby ensuring continued alignment of their objectives with those of its other shareholders.

How Compensation Decisions Are Made

Role of the Personnel Committee

The Personnel Committee has overall responsibility for approving the compensation program for the Named Executive Officers and makes all final compensation decisions regarding Entergy Corporation’s Named Executive Officers. The Committee works with Entergy Corporation’s executive management to ensure that the compensation policies and practices are consistent with its values and support the successful recruitment, development and retention of executive talent so Entergy Corporation can achieve its business objectives and optimize its long-term financial returns. Each year, Entergy Corporation’s Senior Vice President, Human Resources presents the proposed compensation model for the following year, including the compensation elements, mix of elements and measures for each element, and consults with Entergy Corporation’s Chief Executive Officer on recommended compensation for senior executives. The Committee evaluates executive pay each year to ensure that the compensation policies and practices are consistent with Entergy Corporation’s philosophy. The Personnel Committee is responsible for, among its other duties, the following actions related to the Named Executive Officers:


•	developing and implementing compensation policies and programs for hiring, evaluating, and setting compensation for the executive officers, including any employment agreement with an executive officer;


•	evaluating the performance of Entergy Corporation’s Chairman and Chief Executive Officer; and


•	reporting, at least annually, to the Board on succession planning, including succession planning for the Chief Executive Officer.

Role of the Chief Executive Officer

The Personnel Committee solicits recommendations from Entergy Corporation’s Chief Executive Officer with respect to compensation decisions for the Named Executive Officers who are members of Entergy Corporation’s Office of the Chief Executive. Entergy Corporation’s Chief Executive Officer provides the Personnel Committee with an assessment of the performance of each of these Named Executive Officers and recommends compensation levels to be awarded to each of them. In addition, the Committee may request that the Chief Executive Officer provide management feedback and recommendations on changes in the design of compensation programs, such as special retention plans or changes in the structure of bonus programs. However, the Chief Executive Officer does not play any role with respect to any matter affecting his own compensation, nor does he have any role determining or recommending the amount or form of director compensation. The Personnel Committee also relies on the recommendations of Entergy Corporation’s Senior Vice President, Human Resources with respect to compensation decisions, policies, and practices.

Entergy Corporation’s Chief Executive Officer may attend meetings of the Personnel Committee only at the invitation of the chair of the Personnel Committee and cannot call a meeting of the Committee. Since he is not a member of the Committee, he has no vote on matters submitted to the Committee. During 2016, Mr. Denault attended 6 meetings of the Personnel Committee.

Role of the Compensation Consultant

Entergy Corporation’s Personnel Committee has the sole authority for the appointment, compensation, and oversight of its outside compensation consultant. The Committee conducts an annual review of the compensation consultant, and in 2016, it retained Pay Governance LLC as its independent compensation consultant to assist it in, among other things, evaluating different compensation programs and developing market data to assess the compensation programs. Also in 2016, the Corporate Governance Committee retained Pay Governance to review and perform a competitive analysis of non-employee director compensation.

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During 2016, Pay Governance assisted the Committee with its responsibilities related to Entergy Corporation’s compensation programs for its executives. The Committee directed Pay Governance to: (i) regularly attend meetings of the Committee; (ii) conduct studies of competitive compensation practices; (iii) identify Entergy Corporation’s market surveys and proxy peer group; (iv) review base salary, annual incentives, and long-term incentive compensation opportunities relative to competitive practices; and (v) develop conclusions and recommendations related to the executive compensation plan of Entergy Corporation for consideration by the Committee. A senior consultant from Pay Governance attended all Personnel Committee meetings to which he was invited in 2016.

Compensation Consultant Independence

To maintain the independence of the Personnel Committee’s compensation consultant, the Board has adopted a policy that any consultant (including its affiliates) retained by the Board of Directors or any Committee of the Board of Directors to provide advice or recommendations on the amount or form of executive or director compensation should not be retained by Entergy Corporation or any of its affiliates to provide other services in an aggregate amount that exceeds $120,000 in any year. In 2016, the Personnel Committee’s independent compensation consultant, Pay Governance, did not provide any services to Entergy Corporation other than its services to the Personnel Committee and the Corporate Governance Committee. Annually, the Committee reviews the relationship with its compensation consultant, including services provided, quality of those services, and fees associated with services in its evaluation of the executive compensation consultant’s independence. The Committee also assesses Pay Governance’s independence under NYSE rules and has concluded that no conflict of interests exists that would prevent Pay Governance from independently advising the Personnel Committee.

Tax and Accounting Considerations

Section 162(m) of the Internal Revenue Code (“the Code”) limits the tax deductibility by a publicly held corporation of compensation in excess of $1 million paid to Entergy Corporation’s Chief Executive Officer or any of its other Named Executive Officers who may be Section 162(m) covered employees, unless that compensation is “performance-based compensation” within the meaning of Section 162(m). The Personnel Committee considers deductibility under Section 162(m) as it structures the compensation packages that are provided to its Named Executive Officers. Likewise, the Personnel Committee considers financial accounting consequences as it structures the compensation packages that are provided to Entergy Corporation’s Named Executive Officers. However, the Personnel Committee and the Board believe that it is in the best interest of Entergy Corporation that the Personnel Committee retains the flexibility and discretion to make compensation awards, whether or not deductible. This flexibility is necessary to foster achievement of performance goals established by the Personnel Committee, as well as other corporate goals that the Committee deems important to Entergy Corporation’s success, such as encouraging employee retention and rewarding achievement of key goals.

PERSONNEL COMMITTEE REPORT

The Personnel Committee Report included in the Entergy Corporation Proxy Statement is incorporated by reference, but will not be deemed to be “filed” in this Annual Report on Form 10-K. None of the Subsidiaries has a compensation committee or other board committee performing equivalent functions. The board of directors of each of the Subsidiaries is comprised of individuals who are officers or employees of Entergy Corporation or one of the Subsidiaries. These boards do not make determinations regarding the compensation paid to executive officers of the Subsidiaries.

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EXECUTIVE COMPENSATION TABLES

2016 Summary Compensation Tables

The following table summarizes the total compensation paid or earned by each of the Named Executive Officers for the fiscal year ended December 31, 2016, and to the extent required by SEC executive compensation disclosure rules, the fiscal years ended December 31, 2015 and 2014. For information on the principal positions held by each of the Named Executive Officers, see Item 10, “Directors and Executive Officers of the Registrants.”

The compensation set forth in the table represents the aggregate compensation paid by all Entergy System companies. For additional information regarding the material terms of the awards reported in the following tables, including a general description of the formula or criteria to be applied in determining the amounts payable, see “Compensation Discussion and Analysis.”



(a)	(b)	(c)		(d)		(e)		(f)		(g)		(h)		(i)		(j)
Name and Principal Position (1)	Year	Salary (2)		Bonus (3)		Stock Awards (4)		Option Awards (5)		Non-Equity Incentive Plan Compen-sation (6)		Change in Pension Value and Non-qualified Deferred Compen-sation Earnings (7)		All Other Compens-ation (8)		Total
A. Christopher	2016		$426,990		$650,000		$3,292,700		$—		$529,375		$27,900		$140,601		$5,067,566
Bakken, III
Chief Nuclear
Officer of Entergy
Corp.

Marcus V. Brown	2016		$563,208		$—		$1,144,648		$333,000		$550,550		$934,600		$34,381		$3,560,387
General Counsel of
Entergy Corp.

Leo P. Denault	2016		$1,191,462		$—		$4,632,276		$1,235,800		$2,154,600		$4,166,800		$97,786		$13,478,724
Chairman of the	2015		$1,153,385		$—		$4,356,362		$1,004,080		$1,681,875		$4,802,400		$88,795		$13,086,897
Board and CEO -	2014		$1,103,173		$—		$3,564,463		$923,260		$2,597,400		$3,578,200		$57,538		$11,824,034
Entergy Corp.

Haley R. Fisackerly	2016		$320,067		$—		$229,752		$49,580		$168,000		$268,600		$34,243		$1,070,242
CEO - Entergy	2015		$320,131		$—		$219,994		$51,345		$190,000		$102,300		$43,987		$927,757
Mississippi	2014		$300,941		$—		$236,190		$50,518		$193,878		$281,100		$33,311		$1,095,938

Andrew S. Marsh	2016		$553,284		$—		$1,144,648		$333,000		$509,061		$593,700		$47,484		$3,181,177
Executive Vice	2015		$532,245		$—		$2,600,401		$273,840		$508,308		$670,200		$39,131		$4,624,125
President and CFO -	2014		$512,721		$—		$940,837		$304,850		$706,388		$750,900		$26,722		$3,242,418
Entergy Corp.,
Entergy Arkansas,
Entergy Louisiana,
Entergy Mississippi,
Entergy New
Orleans, Entergy
Texas

Phillip R. May, Jr.	2016		$353,690		$—		$326,988		$71,040		$224,690		$600,000		$26,018		$1,602,426
CEO - Entergy	2015		$344,035		$—		$279,406		$57,050		$315,000		$288,100		$25,970		$1,309,561
Louisiana	2014		$335,997		$—		$321,902		$69,680		$263,835		$546,000		$20,641		$1,558,055

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(a)	(b)	(c)		(d)		(e)		(f)		(g)		(h)		(i)		(j)
Name and Principal Position (1)	Year	Salary (2)		Bonus (3)		Stock Awards (4)		Option Awards (5)		Non-Equity Incentive Plan Compen-sation (6)		Change in Pension Value and Non-qualified Deferred Compen-sation Earnings (7)		All Other Compens-ation (8)		Total
Hugh T. McDonald	2016		$167,595		$—		$—		$—		$79,826		$476,100		$32,184		$755,705
Former CEO -	2015		$371,602		$—		$206,509		$41,076		$360,000		$127,200		$65,749		$1,172,136
Entergy Arkansas	2014		$350,104		$—		$229,873		$47,905		$228,879		$400,800		$48,766		$1,306,327

Sallie T. Rainer	2016		$316,003		$—		$229,752		$49,580		$153,348		$346,300		$53,797		$1,148,780
CEO - Entergy	2015		$304,783		$—		$211,004		$43,358		$190,000		$189,100		$41,565		$979,810
Texas	2014		$296,288		$—		$236,190		$50,518		$171,500		$504,000		$32,250		$1,290,746

Charles L. Rice, Jr.	2016		$276,998		$—		$229,752		$49,580		$67,302		$177,600		$33,807		$835,039
CEO - Entergy New	2015		$266,752		$—		$211,004		$51,345		$173,000		$104,500		$33,416		$840,017
Orleans	2014		$260,880		$—		$220,398		$45,292		$167,864		$135,700		$31,402		$861,536

Richard C. Riley	2016		$325,020		$—		$226,224		$34,780		$167,500		$277,900		$102,112		$1,133,536
CEO - Entergy
Arkansas

Roderick K. West	2016		$654,514		$—		$1,116,424		$303,400		$461,384		$601,000		$73,706		$3,210,428
Executive Vice	2015		$638,876		$—		$1,071,111		$262,430		$607,677		$543,900		$71,790		$3,195,784
President	2014		$623,854		$—		$1,010,324		$313,560		$857,280		$782,400		$43,648		$3,631,066


(1)	Effective April 6, 2016, Mr. Bakken was named Executive Vice President and Chief Nuclear Officer. Mr. Brown was not a Named Executive Officer in 2014 and 2015. Effective May 1, 2016, Mr. McDonald retired from Entergy Arkansas. Mr. Riley succeeded Mr. McDonald as Chief Executive Officer, Entergy Arkansas.

(2)

The amounts in column (c) represent the actual base salary paid to the Named Executive Officer. The 2016 changes in base salaries noted in the Compensation Discussion and Analysis were effective in April 2016, except for additional adjustments in (a) Mr. Brown’s base salary which was effective in May 2016, (b) Mr. Fisackerly’s base salary which was effective in November 2016, and (c) Mr. Riley’s base salary which was effective in May 2016.

(3)

The amount in column (d) in 2016 for Mr. Bakken represents a cash sign-on bonus paid to Mr. Bakken in connection with his commencement of employment with Entergy Corporation which is subject to forfeiture if Mr. Bakken terminates his service prior to the one-year anniversary of his date of hire. See “Compensation Arrangements - Mr. Bakken’s Employment” in Compensation Discussion and Analysis.

(4)

The amounts in column (e) represent the aggregate grant date fair value of restricted stock, performance units, and restricted stock units granted under the Equity Ownership Plans, each calculated in accordance with FASB ASC Topic 718, without taking into account estimated forfeitures. The grant date fair value of the restricted stock and the restricted stock units is based on the closing price of Entergy Corporation common stock on the date of grant. The grant date fair value of performance units is based on the probable outcome of the applicable performance conditions, measured using a Monte Carlo simulation valuation model. The simulation model applies a risk-free interest rate and an expected volatility assumption. The risk-free interest rate is assumed to equal the yield on a three-year treasury bond on the grant date. Volatility is based on historical volatility for the 36-month period preceding the grant date. If the highest achievement level is attained, the maximum amounts that will be received with respect to the performance units granted in 2016 are as follows: Mr. Bakken, $1,643,134; Mr. Brown, $1,157,184; Mr. Denault, $5,884,704; Mr. Fisackerly, $254,016; Mr. Marsh, $1,157,184; Mr. May, $381,024; Ms. Rainer, $254,016; Mr. Rice, $254,016; Mr. Riley, $254,016; and Mr. West, $1,157,184.

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(5)	The amounts in column (f) represent the aggregate grant date fair value of stock options granted under the Equity Ownership Plans calculated in accordance with FASB ASC Topic 718. For a discussion of the relevant assumptions used in valuing these awards, see Note 12 to the financial statements.


(6)	The amounts in column (g) represent cash payments made under the Annual Incentive Plan.

(7)

For all of the Named Executive Officers, the amounts in column (h) include the annual actuarial increase in the present value of the Named Executive Officers’ benefits under all pension plans established by Entergy Corporation using interest rate and mortality rate assumptions consistent with those used in Entergy Corporation’s financial statements and include amounts which the Named Executive Officers may not currently be entitled to receive because such amounts are not vested (see “2016 Pension Benefits”). None of the increase is attributable to above-market or preferential earnings on non-qualified deferred compensation (see “2016 Non-qualified Deferred Compensation”).


(8)	The amounts in column (i) for 2016 include (a) matching contributions by Entergy Corporation under the Savings Plan to each of the Named Executive Officers; (b) dividends paid on restricted stock when vested; (c) life insurance premiums; (d) tax gross up payments on club dues and relocation expenses; and (e) perquisites and other compensation. The amounts are listed in the following table:



Named Executive Officer	Company Contribution – Savings Plan		Dividends Paid on Restricted Stock		Life Insurance Premium		Tax Gross Up Payments		Perquisites and Other Compensation		Total
A. Christopher Bakken, III		$15,900		$—		$8,168		$5,950		$110,583		$140,601
Marcus V. Brown		$—		$24,907		$7,482		$—		$1,992		$34,381
Leo P. Denault		$11,130		$67,465		$7,482		$—		$11,709		$97,786
Haley R. Fisackerly		$11,130		$9,365		$2,062		$3,943		$7,743		$34,243
Andrew S. Marsh		$11,130		$31,494		$4,860		$—		$—		$47,484
Phillip R. May, Jr.		$11,130		$10,225		$2,793		$—		$1,870		$26,018
Hugh T. McDonald		$7,039		$8,867		$1,550		$4,975		$9,753		$32,184
Sallie T. Rainer		$11,130		$9,224		$6,268		$2,744		$24,431		$53,797
Charles L. Rice, Jr.		$11,130		$7,935		$4,907		$2,475		$7,360		$33,807
Richard C. Riley		$11,130		$9,862		$2,548		$26,911		$51,661		$102,112
Roderick K. West		$11,130		$37,370		$2,610		$—		$22,596		$73,706

Perquisites and Other Compensation

The amounts set forth in column (i) include perquisites and other personal benefits that Entergy Corporation provides to the Named Executive Officers as part of providing a competitive executive compensation program and for employee retention. The following perquisites and other compensation were provided by Entergy Corporation in 2016.



Named Executive Officer	Relocation	Housing Allowance	Personal Use of Corporate Aircraft	Club Dues	Executive Physical Exams	Event Tickets
A. Christopher Bakken, III	X				X
Marcus V. Brown					X	X
Leo P. Denault			X		X
Haley R. Fisackerly				X
Andrew S. Marsh					X
Phillip R. May, Jr.					X
Hugh T. McDonald				X	X
Sallie T. Rainer		X		X
Charles L. Rice, Jr.				X	X
Richard C. Riley				X
Roderick K. West			X		X

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For security and business reasons, Entergy Corporation permits its Chief Executive Officer to use its corporate aircraft for personal use at the expense of Entergy Corporation. The other Named Executive Officers may use the corporate aircraft for personal travel subject to the approval of Entergy Corporation’s Chief Executive Officer. The amounts included in column (i) for the personal use of corporate aircraft, reflect the incremental cost to Entergy Corporation for use of the corporate aircraft, determined on the basis of the variable operational costs of each flight, including fuel, maintenance, flight crew travel expense, catering, communications, and fees, including flight planning, ground handling, and landing permits. In addition, Entergy Corporation offers its executives comprehensive annual physical exams at Entergy Corporation’s expense. Tickets to cultural and sporting events are purchased for business purposes, and if not utilized for business purposes, the tickets are made available to the employees, including the Named Executive Officers, for personal use.

Entergy Corporation also provides relocation benefits to a broad base of employees which include assistance with moving expenses, purchase and sale of home, and transportation of household goods. In connection with his employment, and in accordance with its relocation policies and pursuant to certain additional relocation benefits, Entergy Corporation paid $103,849 in relocation expenses for Mr. Bakken in 2016. The relocation assistance amounts reported above represent the amount paid to Entergy’s relocation service provider or Mr. Bakken, as applicable. Certain of Mr. Bakken’s relocation benefits are subject to forfeiture if Mr. Bakken terminates his service prior to the one year anniversary of his date of hire.

In 2016 the Named Executive Officers who are not members of Entergy Corporation’s Office of the Chief Executive were provided club dues, tax gross ups on club dues, where appropriate, housing allowances. Entergy Corporation reimburses its Subsidiaries’ chief executive officers for club dues to encourage entertainment with business colleagues, and to engage with local leadership in the communities in which they serve. Mr. Riley incurred $51,661 in dues, which included a one-time membership fee. Entergy Corporation discontinued housing allowances for the Named Executive Officers in 2016. None of the other perquisites referenced above exceeded $25,000 for any of the other Named Executive Officers.

2016 Grants of Plan-Based Awards

The following table summarizes award grants during 2016 to the Named Executive Officers.

Estimated Future Payouts Under Non-Equity Incentive Plan Awards⁽¹⁾

Estimated Future Payouts under Equity Incentive Plan Awards⁽²⁾

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

Name

Grant Date

Approval Date

Thresh-old

Target

Maximum

Thresh-old

Target

Maximum

All Other Stock Awards: Number of Shares of Stock or Units

All Other Option Awards: Number of Securities Under-lying Options

Exercise or Base Price of Option Awards

Grant Date Fair Value of Stock and Option Awards

($)

(#)

(3)

(#)

(4)

($/Sh)

($)

(5)

A. Christopher

4/6/16

$423,500

$847,000

Bakken, III

5/1/16

1/28/16

1,822

7,289

14,578

$616,066

5/1/16

1/28/16

910

3,639

7,278

$360,334

30,000⁽⁶⁾

$2,316,300

Marcus V.

1/28/16

$423,500

$847,000

Brown

1/28/16

2,050

8,200

16,400

$693,064

1/28/16

6,400

$451,584

1/28/16

45,000

$70.56

$333,000

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			Estimated Future Payouts Under Non-Equity Incentive Plan Awards⁽¹⁾			Estimated Future Payouts under Equity Incentive Plan Awards⁽²⁾
(a)	(b)		(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)	(k)	(l)
Name	Grant Date	Approval Date	Thresh-old	Target	Maximum	Thresh-old	Target	Maximum	All Other Stock Awards: Number of Shares of Stock or Units	All Other Option Awards: Number of Securities Under-lying Options	Exercise or Base Price of Option Awards	Grant Date Fair Value of Stock and Option Awards
			($)	($)	($)	(#)	(#)	(#)	(#) (3)	(#) (4)	($/Sh)	($) (5)
Leo P.	1/28/16		$-	$1,620,000	$3,240,000
Denault	1/28/16					10,425	41,700	83,400				$3,524,484
	1/28/16								15,700			$1,107,792
	1/28/16									167,000	$70.56	$1,235,800

Haley R.	1/28/16		$-	$140,000	$280,000
Fisackerly	1/28/16					450	1,800	3,600				$152,136
	1/28/16								1,100			$77,616
	1/28/16									6,700	$70.56	$49,580

Andrew S.	1/28/16		$-	$391,586	$783,172
Marsh	1/28/16					2,050	8,200	16,400				$693,064
	1/28/16								6,400			$451,584
	1/28/16									45,000	$70.56	$333,000

Phillip R.	1/28/16		$-	$213,990	$427,980
May, Jr.	1/28/16					675	2,700	5,400				$228,204
	1/28/16								1,400			$98,784
	1/28/16									9,600	$70.56	$71,040

Hugh T.	1/28/16		$-	$180,061	$360,122
McDonald

Sallie T.	1/28/16		$-	$127,790	$255,580
Rainer	1/28/16					450	1,800	3,600				$152,136
	1/28/16								1,100			$77,616
	1/28/16									6,700	$70.56	$49,580

Charles L.	1/28/16		$-	$112,170	$224,340
Rice, Jr.	1/28/16					450	1,800	3,600				$152,136
	1/28/16								1,100			$77,616
	1/28/16									6,700	$70.56	$49,580

Richard C.	1/28/16		$-	$134,000	$268,000
Riley	1/28/16					450	1,800	3,600				$152,136
	1/28/16								1,050			$74,088
	1/28/16									4,700	$70.56	$34,780

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Estimated Future Payouts Under Non-Equity Incentive Plan Awards⁽¹⁾

Estimated Future Payouts under Equity Incentive Plan Awards⁽²⁾

(a)

(b)

(c)

(d)

(e)

(f)

(g)

(h)

(i)

(j)

(k)

(l)

Name

Grant Date

Approval Date

Thresh-old

Target

Maximum

Thresh-old

Target

Maximum

All Other Stock Awards: Number of Shares of Stock or Units

All Other Option Awards: Number of Securities Under- lying Options

Exercise or Base Price of Option Awards

Grant Date Fair Value of Stock and Option Awards

($)

(#)

(3)

(#)

(4)

($/Sh)

($)

(5)

Roderick K.

1/28/16

$461,384

$922,768

West

1/28/16

2,050

8,200

16,400

$693,064

1/28/16

6,000

$423,360

1/28/16

41,000

$70.56

$303,400


(1)	The amounts in columns (c), (d), and (e) represent minimum, target, and maximum payment levels under the Annual Incentive Plan. The actual amounts awarded are reported in column (g) of the Summary Compensation Table.

(2)

The amounts in columns (f), (g), and (h) represent the minimum, target, and maximum payment levels under the Long-Term Performance Unit Program. Performance under the program is measured by Entergy Corporation’s total shareholder return relative to the total shareholder returns of the companies included in the Philadelphia Utility Index. There is no payout under the program if Entergy Corporation’s total shareholder return falls within the lowest quartile of the peer companies in the Philadelphia Utility Index. Subject to achievement of performance targets, each unit will be converted into one share of Entergy Corporation’s common stock on the last day of the performance period (December 31, 2018.) Accrued dividends on the shares earned will also be paid in Entergy Corporation common stock. In connection with Mr. Bakken’s employment, the Personnel Committee, on January 28, 2016, awarded Mr. Bakken pro-rated target award opportunities for the 2015-2017 and 2016-2018 performance periods. Pursuant to the terms of the Long-Term Performance Unit Program, the grants were made on May 1, 2016, the first day of his first full month of employment.


(3)	Except as otherwise noted in footnote 6, the amounts in column (i) represent shares of restricted stock granted under the 2015 Equity Ownership Plan. Shares of restricted stock vest one-third on each of the first through third anniversaries of the grant date, have voting rights, and accrue dividends during the vesting period.


(4)	The amounts in column (j) represent options to purchase shares of Entergy Corporation’s common stock. The options vest one-third on each of the first through third anniversaries of the grant date and have a ten-year term from the date of grant. The options were granted under the 2015 Equity Ownership Plan.

(5)

The amounts in column (l) are valued based on the aggregate grant date fair value of the award calculated in accordance with FASB ASC Topic 718 and, in the case of the performance units, are based on the probable outcome of the applicable performance conditions. See Notes 4 and 5 to the Summary Compensation Table for a discussion of the relevant assumptions used in calculating the grant date fair value.


(6)	In April 2016, Mr. Bakken was awarded 30,000 restricted stock units under the 2015 Equity Ownership Plan. Shares of the restricted stock units will vest one-third on April 6, 2019, April 6, 2022, and April 6, 2025.

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2016 Outstanding Equity Awards at Fiscal Year-End

The following table summarizes, for each Named Executive Officer, unexercised options, restricted stock that has not vested, and equity incentive plan awards outstanding as of the end of 2016.



	Option Awards					Stock Awards
(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)
Name	Number of Securities Underlying Unexercised Options Exercisable	Number of Securities Underlying Unexercised Options Unexercisable	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options	Option Exercise Price	Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested	Market Value of Shares or Units of Stock That Have Not Vested	Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested
	(#)	(#)	(#)	($)		(#)	($)	(#)	($)
A. Christopher								7,289⁽⁴⁾	$535,523
Bakken, III								910⁽⁵⁾	$66,858
						30,000⁽⁹⁾	$2,204,100

Marcus V.	—	45,000⁽¹⁾		$70.56	1/28/2026
Brown	8,000	16,000⁽²⁾		$89.90	1/29/2025
	20,333	10,167⁽³⁾		$63.17	1/30/2024
	16,000	—		$64.60	1/31/2023
	4,600	—		$71.30	1/26/2022
	2,800	—		$72.79	1/27/2021
	7,500	—		$77.10	1/28/2020
	5,000	—		$77.53	1/29/2019
	4,300	—		$108.20	1/24/2018
	3,500	—		$91.82	1/25/2017
								8,200⁽⁴⁾	$602,454
								1,638⁽⁵⁾	$120,344
						6,400⁽⁶⁾	$470,208
						3,334⁽⁷⁾	$244,949
						1,634⁽⁸⁾	$120,050

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	Option Awards					Stock Awards
(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)
Name	Number of Securities Underlying Unexercised Options Exercisable	Number of Securities Underlying Unexercised Options Unexercisable	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options	Option Exercise Price	Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested	Market Value of Shares or Units of Stock That Have Not Vested	Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested
	(#)	(#)	(#)	($)		(#)	($)	(#)	($)
Leo P.	—	167,000⁽¹⁾		$70.56	1/28/2026
Denault	29,333	58,667⁽²⁾		$89.90	1/29/2025
	70,666	35,334⁽³⁾		$63.17	1/30/2024
	50,000	—		$64.60	1/31/2023
	30,000	—		$71.30	1/26/2022
	25,000	—		$72.79	1/27/2021
	50,000	—		$77.10	1/28/2020
	45,000	—		$77.53	1/29/2019
	50,000	—		$108.20	1/24/2018
	60,000	—		$91.82	1/25/2017
								41,700⁽⁴⁾	$3,063,699
								8,275⁽⁵⁾	$607,964
						15,700⁽⁶⁾	$1,153,479
						8,000⁽⁷⁾	$587,760
						4,634⁽⁸⁾	$340,460

Haley R.	—	6,700⁽¹⁾		$70.56	1/28/2026
Fisackerly	1,500	3,000⁽²⁾		$89.90	1/29/2025
	—	1,934⁽³⁾		$63.17	1/30/2024
	2,000	—		$64.60	1/31/2023
	1,534	—		$71.30	1/26/2022
	2,900	—		$72.79	1/27/2021
	9,000	—		$77.10	1/28/2020
	3,800	—		$77.53	1/29/2019
	5,000	—		$108.20	1/24/2018
	2,500	—		$91.82	1/25/2017			1,800⁽⁴⁾	$132,246
								363⁽⁵⁾	$26,670
						1,100⁽⁶⁾	$80,817
						567⁽⁷⁾	$41,657
						467⁽⁸⁾	$34,310

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	Option Awards					Stock Awards
(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)
Name	Number of Securities Underlying Unexercised Options Exercisable	Number of Securities Underlying Unexercised Options Unexercisable	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options	Option Exercise Price	Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested	Market Value of Shares or Units of Stock That Have Not Vested	Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested
	(#)	(#)	(#)	($)		(#)	($)	(#)	($)
Andrew S.	—	45,000⁽¹⁾		$70.56	1/28/2026
Marsh	8,000	16,000⁽²⁾		$89.90	1/29/2025
	23,333	11,667⁽³⁾		$63.17	1/30/2024
	32,000	—		$64.60	1/31/2023
	10,000	—		$71.30	1/26/2022
	4,000	—		$72.79	1/27/2021
	9,100	—		$77.10	1/28/2020
	8,000	—		$77.53	1/29/2019
	10,000	—		$108.20	1/24/2018
	5,000	—		$91.82	1/25/2017
								8,200⁽⁴⁾	$602,454
								1,638⁽⁵⁾	$120,344
						6,400⁽⁶⁾	$470,208
						3,334⁽⁷⁾	$244,949
						1,634⁽⁸⁾	$120,050
						21,100⁽¹⁰⁾	$1,550,217

Phillip R.	—	9,600⁽¹⁾		$70.56	1/28/2026
May, Jr.	1,666	3,334⁽²⁾		$89.90	1/29/2025
	5,333	2,667⁽³⁾		$63.17	1/30/2024
	6,000	—		$64.60	1/31/2023
	4,600	—		$71.30	1/26/2022
	2,900	—		$72.79	1/27/2021
	6,000	—		$77.10	1/28/2020
	4,700	—		$77.53	1/29/2019
	6,500	—		$108.20	1/24/2018
	5,000	—		$91.82	1/25/2017
								2,700⁽⁴⁾	$198,369
								513⁽⁵⁾	$37,690
						1,400⁽⁶⁾	$102,858
						567⁽⁷⁾	$41,657
						600⁽⁸⁾	$44,082

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	Option Awards					Stock Awards
(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)
Name	Number of Securities Underlying Unexercised Options Exercisable	Number of Securities Underlying Unexercised Options Unexercisable	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options	Option Exercise Price	Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested	Market Value of Shares or Units of Stock That Have Not Vested	Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested
	(#)	(#)	(#)	($)		(#)	($)	(#)	($)
Hugh T.	3,600	—		$89.90	1/29/2025
McDonald	1,834	—		$63.17	1/30/2024
	4,600	—		$71.30	1/26/2022
	2,900	—		$72.79	1/27/2021
	4,600	—		$77.10	1/28/2020
	4,500	—		$77.53	1/29/2019
	7,000	—		$108.20	1/24/2018
	12,000	—		$91.82	1/25/2017
								161⁽⁵⁾	$11,829

Sallie T.	—	6,700⁽¹⁾		$70.56	1/28/2026
Rainer	1,266	2,534⁽²⁾		$89.90	1/29/2025
	3,866	1,934⁽³⁾		$63.17	1/30/2024
	5,800	—		$64.60	1/31/2023
	2,500	—		$77.10	1/28/2020
	1,200	—		$77.53	1/29/2019
	2,300	—		$108.20	1/24/2018
	2,000	—		$91.82	1/25/2017
								1,800⁽⁴⁾	$132,246
								363⁽⁵⁾	$26,670
						1,100⁽⁶⁾	$80,817
						500⁽⁷⁾	$36,735
						467⁽⁸⁾	$34,310

Charles L.	—	6,700⁽¹⁾		$70.56	1/28/2026
Rice, Jr.	1,500	3,000⁽²⁾		$89.90	1/29/2025
	—	1,734⁽³⁾		$63.17	1/30/2024
	4,600	—		$71.30	1/26/2022
	2,900	—		$72.79	1/27/2021
								1,800⁽⁴⁾	$132,246
								363⁽⁵⁾	$26,670
						1,100⁽⁶⁾	$80,817
						500⁽⁷⁾	$36,735
						384⁽⁸⁾	$28,212

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	Option Awards					Stock Awards
(a)	(b)	(c)	(d)	(e)	(f)	(g)	(h)	(i)	(j)
Name	Number of Securities Underlying Unexercised Options Exercisable	Number of Securities Underlying Unexercised Options Unexercisable	Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options	Option Exercise Price	Option Expiration Date	Number of Shares or Units of Stock That Have Not Vested	Market Value of Shares or Units of Stock That Have Not Vested	Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested	Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested
	(#)	(#)	(#)	($)		(#)	($)	(#)	($)
Richard C.	—	4,700⁽¹⁾		$70.56	1/28/2026
Riley	1,500	3,000⁽²⁾		$89.90	1/29/2025
	2,667	2,667⁽³⁾		$63.17	1/30/2024
	3,334	—		$64.60	1/31/2023
	2,500	—		$71.30	1/26/2022
	4,000	—		$108.20	1/24/2018
	2,400	—		$91.82	1/25/2017
								1,800⁽⁴⁾	$132,246
								363⁽⁵⁾	$26,670
						1,050⁽⁶⁾	$77,144
						734⁽⁷⁾	$53,927
						500⁽⁸⁾	$36,735

Roderick	—	41,000⁽¹⁾		$70.56	1/28/2026
K. West	7,666	15,334⁽²⁾		$89.90	1/29/2025
	—	12,000⁽³⁾		$63.17	1/30/2024
	30,000	—		$71.30	1/26/2022
	7,000	—		$77.10	1/28/2020
	5,000	—		$77.53	1/29/2019
	8,000	—		$108.20	1/24/2018
	12,000	—		$91.82	1/25/2017
								8,200⁽⁴⁾	$602,454
								1,638⁽⁵⁾	$120,344
						6,000⁽⁶⁾	$440,820
						3,134⁽⁷⁾	$230,255
						2,000⁽⁸⁾	$146,940
						21,000⁽¹¹⁾	$1,542,870


(1)	Consists of options that vested or will vest as follows: 1/3 of the options granted vest on each of 1/28/2017, 1/28/2018, and 1/28/2019.


(2)	Consists of options that vested or will vest as follows: 1/2 of the remaining unexercisable options vest on each of 1/29/2017 and 1/29/2018.


(3)	The remaining unexercisable options vested on 1/30/2017.


(4)	Consists of performance units that will vest on December 31, 2018 based on Entergy Corporation’s total shareholder return performance over the 2016-2018 performance period, as described under “What Entergy Corporation Pays and Why- Executive Compensation Elements - Variable - Long-Term Incentive Compensation - Performance Unit Program” in Compensation Discussion and Analysis.


(5)	Consists of performance units that will vest on December 31, 2017 based on Entergy Corporation’s total shareholder return performance over the 2015-2017 performance period.

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(6)	Consists of shares of restricted stock that vested or will vest as follows: 1/3 of the shares of restricted stock granted vest on each of 1/28/2017, 1/28/2018, and 1/28/2019.


(7)	Consists of shares of restricted stock that vested or will vest as follows: 1/2 of the shares of restricted stock granted vest on each of 1/29/2017 and 1/2/2018.


(8)	Consists of shares of restricted stock that vested on 1/30/2017.


(9)	Consists of restricted stock units granted under the 2015 Equity Ownership Plan which will vest one third on April 6, 2019, April 6, 2022, and April 6, 2025.


(10)	Consists of restricted stock units granted under the 2015 Equity Ownership Plan which will vest on August 3, 2020.


(11)	Consists of restricted stock units granted under the 2011 Equity Ownership Plan which will vest on May 1, 2018.

2016 Option Exercises and Stock Vested

The following table provides information concerning each exercise of stock options and each vesting of stock during 2016 for the Named Executive Officers.



	Options Awards			Stock Awards
(a)	(b)	(c)		(d)	(e)
Name	Number of Shares Acquired on Exercise	Value Realized on Exercise		Number of Shares Acquired on Vesting	Value Realized on Vesting
	(#)	($)		(#)	($)
A. Christopher Bakken, III	—		$—	—		$—

Marcus V. Brown	—		$—	7,881⁽¹⁾		$588,641

Leo P. Denault	—		$—	27,008⁽¹⁾		$2,001,835

Haley R. Fisackerly	1,933		$27,093	2,117⁽¹⁾		$160,856

Andrew S. Marsh	—		$—	8,481⁽¹⁾		$638,206

Phillip R. May, Jr.	—		$—	2,619⁽¹⁾		$197,819

Hugh T. McDonald	9,666		$93,899	1,811⁽¹⁾		$138,530

Sallie T. Rainer	—		$—	2,084⁽¹⁾		$158,415

Charles L. Rice, Jr.	8,466		$89,545	1,933⁽¹⁾		$146,290

Richard C. Riley	—		$—	6,233⁽¹⁾⁽²⁾		$489,466

Roderick K. West	64,000		$748,718	9,081⁽¹⁾		$687,112


(1)	Represents the value of performance units for the 2014-2016 performance period (payable solely in shares based on the closing stock price of Entergy Corporation on the date of vesting) under the Performance Unit Program and the vesting of shares of restricted stock in 2016.


(2)	Includes the cash settlement on April 1, 2016 of 4,000 restricted stock units granted under the 2007 Equity Ownership Plan.

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2016 Pension Benefits

The following table shows the present value as of December 31, 2016, of accumulated benefits payable to each of the Named Executive Officers, including the number of years of service credited to each Named Executive Officer, under the retirement plans sponsored by Entergy Corporation, determined using interest rate and mortality rate assumptions set forth in Note 11 to the financial statements. Additional information regarding these retirement plans follows this table. In addition, this section includes information regarding early retirement options under the plans.



Name	Plan Name	Number of Years Credited Service	Present Value of Accumulated Benefit		Payments During 2016
A. Christopher Bakken, III	Cash Balance Equalization Plan	0.74		$11,700		$—
	Cash Balance Plan	0.74		$16,200		$—

Marcus V. Brown	System Executive Retirement Plan	21.74		$3,744,800		$—
	Entergy Retirement Plan	21.74		$739,300		$—

Leo P. Denault⁽¹⁾	System Executive Retirement Plan	32.83		$18,400,200		$—
	Entergy Retirement Plan	17.83		$654,600		$—

Haley R. Fisackerly	System Executive Retirement Plan	21.08		$1,123,300		$—
	Entergy Retirement Plan	21.08		$629,600		$—

Andrew S. Marsh	System Executive Retirement Plan	18.37		$2,822,400		$—
	Entergy Retirement Plan	18.37		$417,800		$—

Phillip R. May, Jr.	System Executive Retirement Plan	30.56		$2,114,100		$—
	Entergy Retirement Plan	30.56		$1,008,700		$—

Hugh T. McDonald ⁽²⁾	System Executive Retirement Plan	34.35		$—		$2,985,597
	Entergy Retirement Plan	32.86		$1,626,600		$57,414

Sallie T. Rainer ⁽²⁾	System Executive Retirement Plan	32.38		$1,168,300		$—
	Entergy Retirement Plan	32.00		$1,167,000		$—

Charles L. Rice, Jr.	System Executive Retirement Plan	7.47		$468,100		$—
	Entergy Retirement Plan	7.47		$227,600		$—

Richard C. Riley ⁽³⁾	System Executive Retirement Plan	27.01		$1,415,700		$—
	Entergy Retirement Plan	21.55		$700,800		$—

Roderick K. West	System Executive Retirement Plan	17.75		$3,902,600		$—
	Entergy Retirement Plan	17.75		$460,500		$—

(1)

In 2006, Mr. Denault entered into an agreement granting him an additional 15 years of service and permission to retire under the non-qualified System Executive Retirement Plan in the event his employment is terminated by his Entergy employer other than for cause (as defined in the retention agreement), by Mr. Denault for good reason (as defined in the retention agreement), or on account of his death or disability. His retention agreement also provides that if he terminates employment for any other reason, he shall be entitled to the additional 15 years of service under the non-qualified System Executive Retirement Plan only if his Entergy employer grants him permission to retire. The additional 15 years of service increases the present value of his benefit by $3,627,700.

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(2)	Service under the non-qualified System Executive Retirement Plan is granted from date of hire. Qualified plan benefit service is granted from the later of date of hire or plan participation date.


(3)	Mr. Riley separated from Entergy and was subsequently rehired in June 1995. The Entergy Retirement Plan does not include any credit service prior to his rehire date, however, the System Executive Retirement Plan reflects a net credited service date of December 28, 1989.

Qualified Retirement Benefits

Entergy Retirement Plan

The qualified retirement plan in which the Named Executive Officers, except for Mr. Bakken, participate is a funded, tax-qualified, noncontributory final average pay defined benefit pension plan that provides benefits to most of the non-bargaining unit employees of the Entergy System companies. Benefits under this plan are calculated as an annuity payable at age 65 and generally are equal to 1.5% of a participant’s Final Average Monthly Earnings (FAME) multiplied by years of service (not to exceed 40). “Earnings” for purposes of calculating FAME generally includes the employee’s base salary and eligible annual incentive award and excludes all other bonuses. FAME is calculated using the employee’s average monthly Earnings for the 60 consecutive months in which the employee’s earnings were highest during the 120 month period immediately preceding the employee’s retirement and includes up to 5 annual bonuses paid during the 60 month period. Benefits under this plan are payable monthly after attainment of at least age 55 and after separation from an Entergy System company, subject to reduction for early commencement, as described below. The amount of annual earnings that may be considered in calculating FAME and benefits under the tax-qualified pension plan is limited by the Code. Participants are 100% vested in their benefit upon completing 5 years of vesting service or upon attainment of age 65 while an active participant in the plan. Contributions to the pension plan are made entirely by the Entergy employer and are paid into a trust fund from which the benefits of participants are paid.

Normal retirement age under the plan is 65. Employees who terminate employment prior to age 55 and have a vested benefit in the plan may receive a reduced vested retirement benefit commencing as early as age 55 that is based on the normal age 65 retirement benefit (reduced by 7% per year for the first 5 years commencement precedes age 65, and reduced by 6% for each additional year commencement precedes age 65). Employees who are at least age 55 with at least 10 years of vesting service upon termination of employment are entitled to a subsidized early retirement benefit beginning as early as age 55. The subsidized early retirement benefit is equal to the normal age 65 retirement benefit reduced by 2% per year for each year that early retirement precedes age 65.

Mr. Denault, Mr. Brown, and Ms. Rainer are eligible for subsidized early retirement benefits.

Cash Balance Plan

The qualified defined benefit pension plan in which employees whose most recent hire or rehire date is on or after July 1, 2014 participate is a funded, tax-qualified, noncontributory cash balance defined benefit pension plan that provides benefits to most of the non-bargaining unit employees of the Entergy System companies hired or rehired on or after July 1, 2014. Mr. Bakken is the only Named Executive Officer who participates in this plan. Generally, the normal retirement benefit under this plan, payable as a single life annuity commencing at normal retirement age 65, is determined by converting the balance of the participant’s nominal Cash Balance Account, which is equal to the sum of his or her annual pay credits and his or her annual interest credits, into an actuarially equivalent annuity, as those terms are defined under the plan. Pay credits are made on December 31 of each plan year and range from 4% to 8% of the participant’s eligible earnings, based upon the sum of his or her age and vesting service as of January 1 of the plan year. Interest credits are made on December 31 of each calendar year, beginning with the calendar year following the calendar year in which the participant first becomes a participant, and are calculated based upon the annual rate of interest on 30-year U. S. Treasury securities, as specified by the Internal Revenue Service, for the month of August preceding the first day of the applicable calendar year. The interest crediting rate applied for any plan year will never be less than 2.6%, and will never exceed 9%. A participant becomes vested in his or her Cash Balance plan benefit if he or she has at least 3 years of vesting service or attains age 65 while actively employed by an Entergy system company. Normal retirement age is 65, and if a participant terminates employment at that time, payment of his or her normal retirement benefit begins on the first day of the month following his or her normal retirement date. However, if a participant with a vested benefit terminates employment before

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his or her normal retirement date, he or she can commence a terminated vested benefit as early as the first day of the month following his or her termination of employment. Participants may elect to receive various optional forms of actuarially equivalent benefit payments, if they satisfy the Plan’s eligibility requirements.

401(k) Savings Plan

The Savings Plan is a tax-qualified 401(k) retirement savings plan, wherein total combined before-tax and after-tax contributions may not exceed 30% of a participant’s base salary up to certain contribution limits defined by the Code. In addition, under the Savings Plan, the Entergy employer of Savings Plan participants, who participate in the Entergy Retirement Plan, matches an amount equal to seventy cents for each dollar contributed by participating employees, including the Named Executive Officers, other than Mr. Bakken, with respect to the first 6% of their eligible earnings under the plan for that pay period. The Entergy employer of Savings Plan participants who participate in the Cash Balance Plan makes a company matching contribution on behalf of the participant equal to one dollar for each dollar contributed by participating employees with respect to the first 6% of their eligible earnings each pay period. Participants who are age 50 or older as of the last day of the plan year and who have made the maximum before-tax deferral contributions for the plan year may make additional before-tax catch-up contributions to the savings plan up to $6,000 per year; however, catch-up contributions are not eligible for a company matching contribution.

Non-qualified Retirement Benefits

The Named Executive Officers are eligible to participate in certain non-qualified retirement benefit plans that provide retirement income, including the Pension Equalization Plan, the Cash Balance Equalization Plan, and the System Executive Retirement Plan. Each of these plans is an unfunded non-qualified defined benefit pension plan that provides benefits to key management employees. In these plans, as described below, an executive is typically enrolled in one or more non-qualified plans, but is only paid the amount due under the plan that provides the highest benefit. In general, upon disability, participants in the Pension Equalization Plan and the System Executive Retirement Plan remain eligible for continued service credits until the earlier of recovery, separation from service due to disability, or retirement eligibility. Generally, spouses of participants who die before commencement of benefits may be eligible for a portion of the participant’s accrued benefit.

All of the Named Executive Officers, except Mr. Bakken, participate in both the Pension Equalization Plan and the System Executive Retirement Plan. Mr. Bakken participates in the Cash Balance Equalization Plan.

The Pension Equalization Plan

The Pension Equalization Plan is a non-qualified unfunded restoration retirement plan that provides for the payment to eligible participants who also participate in the Entergy Retirement Plan from Entergy’s general assets of a single lump sum cash distribution generally upon separation from service generally equal to the actuarial present value of the difference between the amount that would have been payable as an annuity under the tax-qualified pension plan, but for Code limitations on pension benefits and earnings that may be considered in calculating tax-qualified pension benefits, and the amount actually payable as an annuity under the Entergy Retirement Plan. The Pension Equalization Plan also takes into account as eligible earnings certain incentive awards paid to certain participants under the Annual Incentive Plan not included in earnings under the Retirement Plan and includes supplemental credited service granted to a participant in calculating his or her benefit. Participants receive their Pension Equalization Plan benefit in the form of a single sum cash distribution. The benefits under this plan are offset by benefits payable from the qualified retirement plan and may be offset by prior Entergy employer benefits. The Pension Equalization Plan benefit attributable to supplemental credited service is not vested until age 65. Subject to the prior written consent of the Entergy employer (which consent is deemed given if the participant’s employment is terminated within 24 months following a change in control by the employer without “Cause” or by the participant for “Good Reason,” each as defined in the plan), an employee with supplemental credited service who terminates employment prior to age 65 may be vested in his or her benefit, with payment of the lump sum benefit generally at separation from service unless delayed 6 months under Code Section 409A. Benefits payable prior to age 65 are subject to the same terminated vested or early retirement reduction factors as benefits payable under the Entergy Retirement Plan.

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Effective July 1, 2014, participants in the Pension Equalization Plan are no longer provided with supplemental credited service unless the grant of supplemental credited service was approved and accepted in writing by the plan administrator prior to July 1, 2014. In addition, the Pension Equalization Plan was amended effective July 1, 2014 to provide that employees who participate in Entergy Corporation’s Cash Balance Plan are not eligible to participate in the Pension Equalization Plan and instead may be eligible to participate in a new Cash Balance Equalization Plan.

Cash Balance Equalization Plan

The Cash Balance Equalization Plan is a non-qualified unfunded restoration retirement plan that provides for the payment to eligible participants who participate in the Cash Balance Plan from Entergy Corporation’s general assets of a single lump sum cash distribution generally upon separation from service generally equal to the difference between the amount that would have been payable as a lump sum under the Cash Balance Plan, but for Code limitations on pension benefits and earnings that may be considered in calculating tax-qualified cash balance plan benefits, and the amount actually payable as a lump sum under the Cash Balance Plan. In the event of a change in control, participants whose employment is terminated without “Cause” or by the employee for “Good Reason,” as each is defined in the Cash Balance Plan, shall become fully vested in all benefits accrued under this plan as of the date of termination of employment and shall be entitled to a lump-sum payable under this plan generally as soon as reasonably practicable following the first day of the month after the termination of employment.

The System Executive Retirement Plan

The System Executive Retirement Plan is a non-qualified supplemental retirement plan that provides for a single sum payment at age 65. Like the Pension Equalization Plan, the System Executive Retirement Plan is designed to provide for the payment to eligible participants who participate in the Entergy Retirement Plan from Entergy Corporation's general assets of a single-sum cash distribution upon the participant’s separation from service. The single-sum benefit is generally equal to the actuarial present value of a specified percentage of the participant’s “Final Average Monthly Compensation” (which is generally 1/36th of the sum of the participant’s annual rate of base salary and Annual Incentive Plan award for the 3 highest years during the last 10 years preceding termination of employment), after first being reduced by the value of the participant’s Entergy Retirement Plan benefit.

While the System Executive Retirement Plan has a replacement ratio schedule from one year of service to the maximum of 30 years of service, the table below offers a sample ratio at 20 and 30 years of service.



Years of Service	Executives at Management Level 1 - Mr. Denault	Executives at Management Levels 2 and 3 - Messrs. Brown, Marsh, May, and West	Executives at Management Level 4 - All Other Named Executive Officers
20 Years	55.0%	50.0%	45.0%
30 years	65.0%	60.0%	55.0%

The System Executive Retirement Plan benefit is not vested until age 65. Subject to the prior written consent of the Entergy employer, an employee who terminates his or her employment prior to age 65 may be vested in the System Executive Retirement Plan benefit, with payment of the lump sum benefit generally at separation from service unless delayed 6 months under Code Section 409A. Benefits payable prior to age 65 are subject to the same terminated vested or early retirement reduction factors as benefits payable under the Entergy Retirement Plan. Further, in the event of a change in control, participants whose employment is terminated without “Cause” or by the employee for “Good Reason,” as each is defined in the plan are also eligible for a subsidized lump sum benefit payment, even if they do not currently meet the age or service requirements for early retirement under that plan or have company permission to separate from employment. Such lump sum benefit is payable generally at separation from service unless delayed 6 months under Code Section 409A. The System Executive Retirement Plan was closed to new executive officers effective July 1, 2014.

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2016 Non-qualified Deferred Compensation

As of December 31, 2016, Mr. May had a deferred account balance under a frozen Defined Contribution Restoration Plan. The amount is deemed invested, as chosen by the participant, in certain T. Rowe Price investment funds that are also available to the participant under the Savings Plan. Mr. May has elected to receive the deferred account balance after he retires. The Defined Contribution Restoration Plan, until it was frozen in 2005, credited eligible employees’ deferral accounts with employer contributions to the extent contributions under the qualified savings plan in which the employee participated were subject to limitations imposed by the Code.

Defined Contribution Restoration Plan

Name

Executive Contributions in 2016

Registrant Contributions in 2016

Aggregate Earnings in 2016⁽¹⁾

Aggregate Withdrawals/Distributions

Aggregate Balance at December 31, 2016

(a)

(b)

(c)

(d)

(e)

(f)

Phillip R. May, Jr.

$—

$177

$—

$1,751


(1)	Amounts in this column are not included in the Summary Compensation Table.

2016 Potential Payments Upon Termination or Change in Control

Entergy Corporation has plans and other arrangements that provide compensation to a Named Executive Officer if his or her employment terminates under specified conditions, including following a change in control of Entergy Corporation. In addition, in 2006 Entergy Corporation entered into a retention agreement with Mr. Denault that provides possibility of additional service credit under the System Executive Retirement Plan upon certain terminations of employment. There are no plans or agreements that would provide for payments to any of the Named Executive Officers solely upon a change in control.

The tables below reflect the amount of compensation each of the Named Executive Officers would have received if his or her employment with their Entergy employer had been terminated under various scenarios as of December 31, 2016. For purposes of these tables, a stock price of $73.47 was used, which was the closing market price on December 30, 2016, the last trading day of the year.

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Benefits and Payments Upon Termination	Voluntary Resignation	For Cause	Termination for Good Reason or Not for Cause		Retirement (1)(2)		Disability		Death		Change in Control	Termination Related to a Change in Control
A. Christopher Bakken, III⁽³⁾

Severance Payment⁽⁶⁾	—	—	—		—		—		—		—		$1,808,950
Performance Units:⁽⁸⁾
2015-2017 Performance Unit Program	—	—	—		—			$178,238		$178,238	—		$477,555
2016-2018 Performance Unit Program	—	—	—		—			$178,508		$178,508	—		$558,372
Unvested Stock Options	—	—	—		—		—		—		—	—
Unvested Restricted Stock	—	—	—		—		—		—		—	—
Welfare Benefits⁽¹³⁾	—	—	—		—		—		—		—		$21,060
Unvested Restricted Stock Units⁽¹⁴⁾	—	—		$734,700	—			$734,700		$734,700	—		$2,204,100

Marcus V. Brown⁽¹⁾⁽⁴⁾

Severance Payment⁽⁶⁾	—	—	—		—		—		—		—		$3,085,500
Performance Units:⁽⁸⁾
2015-2017 Performance Unit Program	—	—	—			$320,843		$320,843		$320,843	—		$477,555
2016-2018 Performance Unit Program	—	—	—			$200,794		$200,794		$200,794	—		$558,372
Unvested Stock Options⁽⁹⁾	—	—	—			$235,667		$235,667		$235,667	—		$235,667
Unvested Restricted Stock⁽¹¹⁾	—	—	—		—			$743,296		$743,296	—		$898,979
Welfare Benefits⁽¹²⁾	—	—	—		—		—		—		—	—

Leo P. Denault ⁽¹⁾⁽⁵⁾

Severance Payment⁽⁶⁾	—	—	—		—		—		—		—		$8,010,000
Performance Units:⁽⁷⁾⁽⁸⁾				$2,384,102
2015-2017 Performance Unit Program	—	—	—			$1,621,262		$1,621,262		$1,621,262	—		$2,384,102
2016-2018 Performance Unit Program	—	—	—			$1,021,233		$1,021,233		$1,021,233	—		$2,791,860
Unvested Stock Options⁽⁹⁾	—	—		$849,903		$849,903		$849,903		$849,903	—		$849,903
Unvested Restricted Stock⁽¹¹⁾	—	—		$2,243,774	—			$2,243,774		$2,243,774	—		$2,243,774
Welfare Benefits⁽¹²⁾	—	—	—		—		—		—		—	—

Haley Fisackerly ⁽³⁾

Severance Payment⁽⁶⁾	—	—	—		—		—		—		—		$490,000
Performance Units:⁽⁸⁾
2015-2017 Performance Unit Program	—	—	—		—			$71,045		$100,284	—		$124,899
2016-2018 Performance Unit Program	—	—	—		—			$44,082		$33,018	—		$139,593
Unvested Stock Options⁽⁹⁾	—	—	—		—			$39,410		$27,588	—		$39,410
Unvested Restricted Stock⁽¹¹⁾	—	—	—		—			$141,870		$84,493	—		$169,641
Welfare Benefits⁽¹³⁾	—	—	—		—		—		—		—		$18,846

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Benefits and Payments Upon Termination	Voluntary Resignation	For Cause	Termination for Good Reason or Not for Cause	Retirement (1)(2)		Disability		Death		Change in Control	Termination Related to a Change in Control
Andrew S. Marsh ⁽³⁾

Severance Payment⁽⁶⁾	—	—	—	—		—		—		—		$2,852,981
Performance Units:⁽⁸⁾
2015-2017 Performance Unit Program	—	—	—	—			$320,843		$320,843	—		$477,555
2016-2018 Performance Unit Program	—	—	—	—			$200,794		$200,794	—		$558,372
Unvested Stock Options⁽⁹⁾	—	—	—	—			$251,117		$251,117	—		$251,117
Unvested Restricted Stock⁽¹¹⁾	—	—	—	—			$743,296		$743,296	—		$898,979
Welfare Benefits⁽¹³⁾	—	—	—	—		—		—		—		$28,269
Unvested Stock Units⁽¹⁵⁾	—	—	—	—			$1,550,217		$1,550,217	—		$1,550,217

Phillip R. May, Jr. ⁽³⁾

Severance Payment⁽⁶⁾	—	—	—	—		—		—		—		$1,141,280
Performance Units:⁽⁸⁾
2015-2017 Performance Unit Program	—	—	—	—			$100,433		$100,433	—		$198,369
2016-2018 Performance Unit Program	—	—	—	—			$66,123		$66,123	—		$220,410
Unvested Stock Options⁽⁹⁾	—	—	—	—			$55,403		$55,403	—		$55,403
Unvested Restricted Stock⁽¹¹⁾	—	—	—	—			$175,226		$175,226	—		$203,952
Welfare Benefits⁽¹³⁾	—	—	—	—		—		—		—		$28,269

Hugh T. McDonald ⁽²⁾

Severance Payment⁽⁶⁾	—	—	—	—		—		—		—	—
Performance Units:⁽⁸⁾
2015-2017 Performance Unit Program	—	—	—		$31,543	—		—		—	—
2016-2018 Performance Unit Program	—	—	—	—		—		—		—	—
Unvested Stock Options⁽¹⁰⁾	—	—	—		$18,883	—		—		—	—
Unvested Restricted Stock⁽¹¹⁾	—	—	—	—		—		—		—	—
Welfare Benefits⁽¹²⁾	—	—	—	—		—		—		—	—

Sallie T. Rainer ⁽¹⁾⁽⁴⁾

Severance Payment⁽⁶⁾	—	—	—		$71,045		$71,045		$71,045	—		$124,899
Performance Units:⁽⁸⁾
2015-2017 Performance Unit Program	—	—	—		$44,082		$44,082		$44,082	—		$92,286
2016-2018 Performance Unit Program	—	—	—		$39,410		$39,410		$39,410	—		$92,286
Unvested Stock Options⁽⁹⁾	—	—	—	—			$139,446		$139,446	—		$27,337
Unvested Restricted Stock⁽¹¹⁾	—	—	—	—		—		—		—		$160,537
Welfare Benefits⁽¹²⁾	—	—	—	—		—		—		—		$19,234

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Benefits and Payments Upon Termination	Voluntary Resignation	For Cause	Termination for Good Reason or Not for Cause		Retirement (1)(2)	Disability		Death		Change in Control	Termination Related to a Change in Control
Charles R. Rice, Jr ⁽³⁾

Severance Payment⁽⁶⁾	—	—	—		—	—		—		—		$392,593
Performance Units:⁽⁸⁾
2015-2017 Performance Unit Program	—	—	—		—		$71,045		$71,045	—		$124,899
2016-2018 Performance Unit Program	—	—	—		—		$44,082		$44,082	—		$139,593
Unvested Stock Options⁽⁹⁾	—	—	—		—		$37,350		$37,350	—		$37,350
Unvested Restricted Stock⁽¹¹⁾	—	—	—		—		$132,980		$132,980	—		$157,226
Welfare Benefits⁽¹³⁾	—	—	—		—	—		—		—		$18,846

Richard C. Riley ⁽³⁾

Severance Payment⁽⁶⁾	—	—	—		—	—		—		—		$469,000
Performance Units:⁽⁸⁾
2015-2017 Performance Unit Program	—	—	—		—		$71,045		$71,045	—		$124,899
2016-2018 Performance Unit Program	—	—	—		—		$44,082		$44,082	—		$139,593
Unvested Stock Options⁽⁹⁾							$41,144		$41,144	—		$41,144
Unvested Restricted Stock⁽¹¹⁾	—	—	—		—		$146,866		$146,866	—		$182,058
Welfare Benefits⁽¹³⁾	—	—	—		—	—		—		—		$18,846

Roderick K. West ⁽³⁾

Severance Payment⁽⁶⁾	—	—	—		—	—		—		—		$3,361,512
Performance Units:⁽⁸⁾
2015-2017 Performance Unit Program	—	—	—		—		$320,843		$320,843	—		$477,555
2016-2018 Performance Unit Program	—	—	—		—		$200,794		$200,794	—		$558,372
Unvested Stock Options⁽⁹⁾							$242,910		$242,910	—		$242,910
Unvested Restricted Stock⁽¹¹⁾	—	—	—		—		$733,524		$733,524	—		$883,036
Welfare Benefits⁽¹³⁾	—	—	—		—	—		—		—		$28,269
Unvested Restricted Units⁽¹⁶⁾	—	—		$1,542,870	—	—		—		—		$1,542,870


(1)	As of December 31, 2016, Mr. Denault, Mr. Brown, and Ms. Rainer are retirement eligible and would retire rather than voluntarily resign.


(2)	Mr. McDonald retired effective April 30, 2016.

Pension Benefits:

(3)

In addition to the payments and benefits in the table, if a Named Executive Officer’s, other than Mr. Denault’s, Mr. Brown’s, and Ms. Rainer’s, employment were terminated under certain conditions relating to a change in control, each also would have been entitled to receive his vested pension benefits upon attainment of age 55 and would have been eligible for early retirement benefits under the System Executive Retirement Plan calculated using early retirement reduction factors. For a description of the pension benefits, see “2016 Pension Benefits.” If a Named Executive Officer’s, other than Mr. Denault’s, Mr. Brown’s, and Ms. Rainer’s, employment were

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terminated for cause or each were to resign before age 65 without the permission of their Entergy employer, each would not receive a benefit under the System Executive Retirement Plan. In addition to the payments and benefits in the table, if Mr. Bakken’s employment were terminated under certain conditions relating to a change in control, on the first day of the month following the Qualifying Event (as defined in the Cash Balance Equalization Plan), he would have become vested in and have been entitled to receive his vested pension benefits accumulated in the Cash Balance Equalization Plan as of the date of the Qualifying Event so long as a forfeiture event does not occur as described in the plan. For a description of the pension benefits under the Cash Balance Equalization Plan, see “2016 Pension Benefits.”

(4)

In addition to the payments and benefits in the table, Mr. Brown and Ms. Rainer each would have been eligible to retire and entitled to receive vested pension benefits. For a description of the pension benefits available, see “2016 Pension Benefits.” In the event of a termination by their Entergy employer without cause or by the executive for good reason in connection with a change in control, Mr. Brown and Ms. Rainer each would be eligible for subsidized early retirement benefits under the System Executive Retirement Plan even if they do not have their Entergy employer’s permission to separate from employment. If Mr. Brown’s or Ms. Rainer’s employment were terminated for cause or if either were to retire before age 65 without the permission of their Entergy employer, they would not receive a benefit under the System Executive Retirement Plan.

(5)

In addition to the payments and benefits in the table, Mr. Denault also would have been entitled to receive his vested pension benefits. If Mr. Denault’s employment was terminated by his Entergy employer other than for cause, by Mr. Denault for good reason or on account of his death or disability, he would also be eligible for certain additional retirement benefits. For a description of these benefits, see “2016 Pension Benefits.” Otherwise, if Mr. Denault’s employment was terminated for cause or he was to retire before age 65 without the permission of his Entergy employer, he would not receive a benefit under the System Executive Retirement Plan.

Severance Payments

(6)

In the event of a termination (not due to death or disability) by the executive for good reason or by the applicable Entergy employer not for cause during the period beginning upon the occurrence of a “potential change in control” (as defined in the System Executive Continuity Plan) and ending on the 2nd anniversary of a change in control, each Named Executive Officer would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to a multiple of the sum of (1) their annual base salary as in effect at any time within one year prior to the commencement of a change in control period or, if higher, immediately prior to a circumstance constituting good reason plus (2) their annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive Plan for 2014 and 2015 (the two calendar years immediately preceding the calendar year in which termination occurs), but in no event shall the severance be more than the product of 2.99 times the sum of (a) their annual base salary as in effect at any time within one year prior to the commencement of a change in control period or, if higher, immediately prior to a circumstance constituting good reason plus (b) the higher of their actual annual incentive payment under the Annual Incentive Plan for the 2015 performance year or their annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive Plan for 2014 and 2015 (the two calendar years immediately preceding the calendar year in which termination occurs). For purposes of this table, it assumed the following target opportunity and base salary was assumed:

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Named Executive Officer	Target Opportunity	Base Salary
A. Christopher Bakken III	0%	$605,000
Marcus V. Brown	70%	$605,000
Leo P. Denault	123%	$1,200,000
Andrew S. Marsh	70%	$559,408
Haley R. Fisackerly	40%	$350,000
Phillip R. May Jr,	60%	$356,650
Sallie T. Rainer	40%	$319,475
Charles L. Rice, Jr.	40%	$280,424
Richard C. Riley	40%	$335,000
Roderick K. West	70%	$659,120

Performance Units

(7)

With respect to Mr. Denault, in the event of a Termination Event, he is entitled to a Target LTIP Award, as defined in his 2006 retention agreement, calculated by using the average annual number of performance units with respect to the two most recent performance periods preceding the calendar year in which his employment termination occurs, assuming all performance goals were achieved at target. For purposes of the table, the value of Mr. Denault’s retention payment was calculated by taking an average of the target performance units from the 2012-2014 Performance Unit Program (26,900) and from the 2013-2015 Performance Unit Program (38,000). This average number of units (32,450) multiplied by the closing price of Entergy Corporation stock on December 30, 2016 ($73.47) would equal a payment of $2,384,102. In the event of death or disability, Mr. Denault receives the greater of Target LTIP Award calculated as described above or the sum of the amount that would be payable under the provisions of each open Performance Unit Program.

(8)

In the event of a qualifying termination related to a change in control, each Named Executive Officer would have forfeited their performance units for the 2015-2017 performance period and would have been entitled to receive, pursuant to the 2011 Equity Ownership Plan, a single-lump sum payment that would not be based on any outstanding performance period. For the 2015-2017 performance period, the payment would have been calculated using the average annual number of performance units they would have been entitled to receive under each Performance Unit Program with respect to the two most recent performance periods preceding (but not including) the calendar year in which their termination occurs, assuming all performance goals were achieved at target multiplied by the closing price of Entergy Corporation stock on December 30, 2016. For purposes of the table, the value of Mr. Denault’s payment was calculated by taking an average of the target performance units from the 2012-2014 Performance Unit Program (26,900) and 2013-2015 Performance Unit Program (38,000). This average number of units (32,450) multiplied by the closing price of Entergy Corporation stock on December 30, 2016 ($73.47) would equal a payment of $2,384,102 for the forfeited performance units.

The value of the payment for Messrs. Marsh, Bakken, and West was calculated by taking an average of the target performance units from the 2012-2014 Performance Unit Program (5,400) and 2013-2015 Performance Unit Program (7,600). This average number of units (6,500) multiplied by the closing price of Entergy Corporation stock on December 30, 2016 ($73.47) would equal a payment of $477,555 for the forfeited performance units.

The value of the payment for Mr. May was calculated by taking an average of the target performance units from the 2012-2014 Performance Unit Program (2,400) and 2013-2015 Performance Unit Program (3,000). This average number of units (2,700) multiplied by the closing price of Entergy Corporation stock on December 30, 2016 ($73.47) would equal a payment of $198,369 for the forfeited performance units.

The value of the payment for Messrs. Fisackerly, Rice, Riley, and Ms. Rainer was calculated by taking an average of the target performance units from the 2012-2014 Performance Unit Program (1,500) and 2013-2015 Performance Unit Program (1,900). This average number of units (1,700) multiplied by the closing price of Entergy Corporation stock on December 30, 2016 ($73.47) would equal a payment of $124,899 for the forfeited performance units.

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In the event of a qualifying termination related to a change in control, each Named Executive Officer would have forfeited his performance units for the 2016-2018 performance period and would have been entitled to receive, pursuant to the 2015 Equity Ownership Plan, a single-lump sum payment that would not be based on any outstanding performance period. The 2016-2018 performance period payment would have been calculated using the most recent performance period preceding (but not including) the calendar year in which termination occurs. For purposes of the table, the value of Mr. Denault’s payment was calculated by multiplying the target performance units for the 2013-2015 Performance Unit Program (38,000) by the closing price of Entergy Corporation stock on December 30, 2016 ($73.47), which would equal a payment of $2,791,860 for the forfeited performance units.

The value of the payment for Messrs. Marsh, Bakken, and West was calculated by multiplying the target performance units for the 2013-2015 Performance Unit Program (7,600) by the closing price of Entergy Corporation stock on December 30, 2016 ($73.47), which would equal a payment of $558,372 for the forfeited performance units.

The value of the payment for Mr. May was calculated by multiplying the target performance units for the 2013-2015 Performance Unit Program (3,000) by the closing price of Entergy Corporation stock on December 30, 2016 ($73.47), which would equal a payment of $220,410 for the forfeited performance units. The value of the payment for Messrs. Fisackerly, Rice, Riley, and Ms. Rainer was calculated by multiplying the target performance units for the 2013-2015 Performance Unit Program (1,900) by the closing price of Entergy Corporation stock on December 30, 2016 ($73.47), which would equal a payment of $139,593 for the forfeited performance units.

In the event of retirement in the case of Mr. Denault, Mr. Brown, or Ms. Rainer, or upon death or disability, other than Mr. Denault, each Named Executive Officer would not have forfeited their performance units for all open performance periods, but rather such performance unit awards would have been pro-rated based on their number of months of participation in each open Performance Unit Program performance period, in accordance with their grant agreement under the Performance Unit Program. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period. For purposes of the table, the values of the awards were calculated as follows:

Mr. Denault’s:

2015 - 2017 Plan - 22,067 (24/36*33,100) performance units at target, assuming a stock price of $73.47

2016 - 2018 Plan - 13,900 (12/36*41,700) performance units at target, assuming a stock price of $73.47

Mr. Bakken’s:

2015 - 2017 Plan - 2,426 (24/36*3,639) performance units at target, assuming a stock price of $73.47

2016 - 2018 Plan - 2,430 (12/36*7,289) performance units at target, assuming a stock price of $73.47

Messrs. Brown’s, Marsh’s, and West’s:

2015 - 2017 Plan - 4,367 (24/36*6,550) performance units at target, assuming a stock price of $73.47

2016 - 2018 Plan - 2,733 (12/36*8,200) performance units at target, assuming a stock price of $73.47

Mr. May’s:

2015 - 2017 Plan - 1,367 (24/36*2,050) performance units at target, assuming a stock price of $73.47

2016 - 2018 Plan - 900 (12/36*2,700) performance units at target, assuming a stock price of $73.47

Messrs. Fisackerly’s, Rice’s, Riley’s, and Ms. Rainer’s:

2015 - 2017 Plan - 967 (24/36*1,450) performance units at target, assuming a stock price of $73.47

2016 - 2018 Plan - 600 (12/36*1,800) performance units at target, assuming a stock price of $73.47

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Unvested Stock Options

(9)

In the event of death or disability or qualifying termination related to a change in control or retirement in the case of Mr. Denault, Mr. Brown, or Ms. Rainer, all of the unvested stock options of each Named Executive Officer would immediately vest pursuant to the 2011 Equity Ownership Plan and 2015 Equity Ownership Plan. In addition, with respect to grants under the 2011 Equity Ownership Plan, each Named Executive Officer would be entitled to exercise their stock options for the remainder of the ten-year period extending from the grant date of the options, and with respect to grants under the 2015 Equity Ownership Plan, within the lesser of five years or the remaining term of the option grant. For purposes of this table, it is assumed that the Named Executive Officers exercised their options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 30, 2016, and the applicable exercise price of each option share.

In the event of a Termination Event as defined in his 2006 retention agreement, Mr. Denault would immediately vest in all unvested stock options.

(10)

When Mr. McDonald retired all of his unvested stock options immediately vested. In addition, Mr. McDonald is entitled to exercise any outstanding options during the ten-year term extending from the grant date of the options. For purposes of this table, we assumed that Mr. McDonald exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 30, 2016, and the exercise price of each option share.

Unvested Restricted Stock

(11)

In the event of death or disability (pursuant to the 2011 Equity Ownership Plan), each Named Executive Officer would immediately vest in a pro-rated portion of their unvested restricted stock that was otherwise scheduled to become vested on the immediately following twelve (12)-month grant date anniversary date (as well as dividends declared on the pro-rated portion of such restricted stock) pursuant to the 2011 Equity Ownership Plan. The pro-rated vested portion would be determined based on the number of days between the most recent preceding twelve (12)-month grant date anniversary date and the date of their death or disability. In the event of a qualifying termination related to a change in control, the Named Executive Officer would immediately vest in all of their unvested restricted stock (as well as dividends declared on the pro-rated portion of such restricted stock). In the event of death, disability, or qualifying termination related to a change in control (pursuant to the 2015 Equity Ownership Plan), each Named Executive Officer would vest in all of their unvested restricted stock (as well as dividends declared).

In the event of a Termination Event as defined in his 2006 retention agreement, Mr. Denault would immediately vest in all unvested restricted stock.

Welfare Benefits

(12)

Upon retirement, Mr. Denault, Mr. Brown, and Ms. Rainer would be eligible for retiree medical and dental benefits, the same as all other retirees. Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. Denault, Mr. Brown, and Ms. Rainer would not be eligible to receive subsidized COBRA benefits. Upon his retirement, Mr. McDonald receives retiree medical and dental benefits, the same as all other retirees.


(13)	Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Messrs. Bakken, Marsh, May, and West would be eligible to receive subsidized COBRA benefits for 18 months and Messrs. Fisackerly, Rice, and Riley would be eligible to receive subsidized COBRA benefits for 12 months.

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Restricted Stock Units

(14)

Mr. Bakken’s 30,000 restricted stock units vest one third (1/3rd) on each of April 6, 2019, April 6, 2022 and April 6, 2025. Pursuant to his restricted stock unit agreement, if Mr. Bakken’s employment terminates due to total disability or death or, prior to April 6, 2019, Mr. Bakken’s employment is terminated by his Entergy employer other than for cause, then he will vest in and be paid the 10,000 restricted stock units that otherwise would have vested had he satisfied the vesting conditions of the restricted stock unit agreement through the next vesting date to occur following his date of total disability, death or termination other than for cause prior to April 6, 2019 subject, in the case of a termination without cause, to Mr. Bakken timely executing and not revoking a release of claims against Entergy Corporation and its affiliates. In the event of a change in control, the unvested restricted stock units will fully vest upon Mr. Bakken’s termination of employment by his employer without cause or by Mr. Bakken with good reason during a change in control period (as defined in the 2015 Equity Ownership Plan). Otherwise, if Mr. Bakken voluntarily resigns or is terminated, he would forfeit these units. Pursuant to his restricted stock unit agreement, Mr. Bakken is subject to certain restrictions on his ability to compete with Entergy Corporation and its affiliates or solicit its employees or customers during and for 12 months after his employment with his Entergy employer. In addition, the restricted stock unit agreement limits Mr. Bakken’s ability to disparage Entergy Corporation and its affiliates. In the event of a breach of these restrictions other than following certain constructive terminations of his employment, Mr. Bakken will forfeit any restricted stock units that are not yet vested and paid, and must repay to Entergy Corporation any shares of Entergy Corporation stock paid to him in respect of the restricted stock units and any amounts he received upon the sale or transfer of any such shares.

(15)

Mr. Marsh’s 21,100 restricted stock units vest 100% in 2020. Pursuant to his restricted stock unit agreement, any unvested restricted stock units will vest immediately in the event of his termination of employment due to Mr. Marsh’s total disability or death. In the event of a change in control, the units will vest upon termination of Mr. Marsh’s employment by his Entergy employer without cause or by Mr. Marsh with good reason during a change in control period (as defined in the 2015 Equity Ownership Plan). Otherwise, if Mr. Marsh voluntarily resigns or is terminated, he would forfeit these units. Pursuant to his restricted stock unit agreement, Mr. Marsh is subject to certain restrictions on his ability to compete with Entergy Corporation and its affiliates during and for 12 months after his employment, or to solicit its employees or customers during and for 24 months after his employment. In addition, the restricted stock unit agreement limits Mr. Marsh’s ability to disparage Entergy Corporation and its affiliates. In the event of a breach of these restrictions, Mr. Marsh will forfeit any restricted stock units that are not yet vested and paid, and must repay to Entergy Corporation any shares of Entergy Corporation stock paid to him in respect of the restricted stock units and any amounts he received upon the sale or transfer of any such shares.

(16)

Mr. West’s 21,000 restricted stock units vest 100% in 2018. Pursuant to his restricted stock unit agreement, any unvested restricted stock units will vest immediately in the event of a termination for a reason other than cause, total disability or death. In the event of a change in control, the units will vest upon termination of Mr. West’s employment by his Entergy employer without cause or by Mr. West with good reason during a change in control period (as defined in the 2011 Equity Ownership Plan). Otherwise, if Mr. West voluntarily resigns, is terminated for cause, dies or becomes disabled, he would forfeit these units.

Mr. Denault’s 2006 Retention Agreement

Under the terms of Mr. Denault’s 2006 retention agreement, his Entergy employer may terminate his employment for cause upon Mr. Denault’s:


•	continuing failure to substantially perform his duties (other than because of physical or mental illness or after he has given notice of termination for good reason) that remains uncured for 30 days after receiving a written notice from the Personnel Committee;


•	willfully engaging in conduct that is demonstrably and materially injurious to Entergy Corporation;


•	conviction of or entrance of a plea of guilty or nolo contendere to a felony or other crime that has or may have a material adverse effect on his ability to carry out his duties or upon Entergy Corporation’s reputation;


•	material violation of any agreement that he has entered into with Entergy Corporation; or


•	unauthorized disclosure of Entergy Corporation’s confidential information.

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Mr. Denault may terminate his employment for good reason upon:


•	the substantial reduction in the nature or status of his duties or responsibilities from those in effect immediately prior to the date of the retention agreement, other than de minimis acts that are remedied after notice from Mr. Denault;


•	a reduction of 5% or more in his base salary as in effect on the date of the retention agreement;


•	the relocation of his principal place of employment to a location other than the corporate headquarters;


•	the failure to continue to allow him to participate in programs or plans providing opportunities for equity awards, stock options, restricted stock, stock appreciation rights, incentive compensation, bonus and other plans on a basis not materially less favorable than enjoyed at the time of the retention agreement (other than changes similarly affecting all senior executives);

•

the failure to continue to allow him to participate in programs or plans with opportunities for benefits not materially less favorable than those enjoyed by him under any of Entergy Corporation’s pension, savings, life insurance, medical, health and accident, disability or vacation plans or policies at the time of the retention agreement (other than changes similarly affecting all senior executives); or


•	any purported termination of his employment not taken in accordance with his retention agreement.

System Executive Continuity Plan

Termination Related to a Change in Control

The Named Executive Officers will be entitled to the benefits described in the tables above under the System Executive Continuity Plan in the event of a termination related to a change in control if a change in control occurs and their employment is terminated by their Entergy employer other than for cause or if they terminate their employment for good reason, in each case within a period beginning on the occurrence of a potential change in control and ending 24 months following the effective date of a change in control.

A change in control includes the following events:


•	the purchase of 30% or more of either Entergy Corporation’s common stock or the combined voting power of Entergy Corporation’s voting securities;


•	the merger or consolidation of Entergy Corporation (unless its Board members constitute at least a majority of the board members of the surviving entity);


•	the liquidation, dissolution or sale of all or substantially all of Entergy Corporation’s assets; or


•	a change in the composition of Entergy Corporation’s Board such that, during any two-year period, the individuals serving at the beginning of the period no longer constitute a majority of Entergy Corporation’s Board at the end of the period.

A potential change in control includes the following events:


•	Entergy Corporation or an affiliate enters into an agreement the consummation of which would constitute a change in control;


•	the Entergy Corporation Board adopts resolutions determining that, for purposes of the System Executive Continuity Plan, a potential change in control has occurred;


•	an Entergy Corporation affiliate or other person or entity publicly announces an intention to take actions that would constitute a change in control; or


•	any person or entity becomes the beneficial owner (directly or indirectly) of outstanding shares of Entergy Corporation’s common stock constituting 20% or more of the voting power or value of Entergy Corporation’s outstanding common stock.

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A Named Executive Officer’s employment may be terminated for cause under the System Executive Continuity Plan if he or she:


•	willfully and continuously fails to substantially perform his or her duties after receiving a 30-day written demand for performance from Entergy Corporation’s Board;


•	engages in conduct that is materially injurious to Entergy Corporation or any of its subsidiaries;


•	is convicted or pleads guilty or nolo contendere to a felony or other crime that materially and adversely affects his or her ability to perform his or her duties or Entergy Corporation’s reputation;


•	materially violates any agreement with Entergy Corporation or any of its subsidiaries; or


•	discloses any of Entergy Corporation’s confidential information without authorization.

A Named Executive Officer may terminate his or her employment with his or her Entergy employer for good reason under the System Executive Continuity Plan if, without his or her consent:


•	the nature or status of his or her duties and responsibilities is substantially altered or reduced compared to the period prior to the change in control;


•	his or her salary is reduced by 5% or more;


•	he or she is required to be based outside of the continental United States at somewhere other than his or her primary work location prior to the change in control;


•	any of his or her compensation plans are discontinued without an equitable replacement;


•	his or her benefits or number of vacation days are substantially reduced; or


•	his or her Entergy employer purports to terminate his or her employment other than in accordance with the System Executive Continuity Plan.

In addition to participation in the System Executive Continuity Plan, benefits already accrued under the System Executive Retirement Plan, Pension Equalization Plan, and Cash Balance Equalization Plan, if any, will become fully vested if the executive is involuntarily terminated without cause or the executive terminates his or her employment for good reason within two years after the occurrence of a change in control. Any awards granted under the Equity Ownership Plans will become fully vested if the executive is involuntarily terminated without cause or terminates employment for good reason within two years after the occurrence of a change in control. In 2010, Entergy Corporation eliminated tax gross up payments for any severance benefits paid under the System Executive Continuity Plan.

Under certain circumstances described below, the payments and benefits received by a Named Executive Officer pursuant to the System Executive Continuity Plan may be forfeited and, in certain cases, subject to repayment. Benefits are no longer payable under the System Executive Continuity Plan, and unvested performance units under the Performance Unit Program are subject to forfeiture, if the executive:


•	accepts employment with Entergy Corporation or any of its subsidiaries;


•	elects to receive the benefits of another severance or separation program;


•	removes, copies or fails to return any property belonging to Entergy Corporation or any of its subsidiaries;


•	discloses non-public data or information concerning Entergy Corporation or any its subsidiaries; or


•	violates his or her non-compete provision, which generally runs for two years but extends to three years if permissible under applicable law.

Furthermore, if the executive discloses non-public data or information concerning Entergy Corporation or any of its subsidiaries or violates his or her non-compete provision, he or she will be required to repay any benefits previously received under the System Executive Continuity Plan.

Termination for Cause

If a Named Executive Officer’s employment is terminated for “cause” (as defined in the System Executive Continuity Plan and described above under “Termination Related to a Change in Control”), he or she is generally entitled to the same compensation and separation benefits described below under “Voluntary Resignation,” except that all options are no longer exercisable.

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Voluntary Resignation

If a Named Executive Officer voluntarily resigns, he or she is entitled to all vested accrued benefits and compensation as of the separation date, including qualified pension benefits (if any) and other post-employment benefits on terms consistent with those generally available to other salaried employees. In the case of voluntary resignation, the officer would forfeit all unvested stock options, shares of restricted stock and restricted units as well as any perquisites to which he or she is entitled as an officer. In addition, the officer would forfeit, except as described below, his or her right to receive incentive payments under any outstanding performance periods under the Long-Term Performance Unit Program or the Annual Incentive Plan. If the officer resigns after the completion of an Annual Incentive Plan or Long-Term Performance Unit Program performance period, he or she could receive a payout under the Long-Term Performance Unit Program based on the outcome of the performance period and could, at Entergy Corporation’s discretion, receive an annual incentive payment under the Annual Incentive Plan. Any vested stock options held by the officer as of the separation date will expire the earlier of ten years from date of grant or 90 days from the last day of active employment.

Retirement

Under the Entergy Retirement Plan, a Named Executive Officer’s eligibility for retirement benefits is based on a combination of age and years of service. Normal retirement is defined as age 65. Early retirement is defined under the Entergy Retirement Plan as minimum age 55 with 10 years of service and in the case of the System Executive Retirement Plan and the supplemental credited service under the Pension Equalization Plan, the consent of the Entergy employer.

Upon a Named Executive Officer’s retirement, he or she is generally entitled to all vested accrued benefits and compensation as of the separation date, including qualified pension benefits and other post-employment benefits consistent with those generally available to salaried employees. The annual incentive payment under the Annual Incentive Plan is pro-rated based on the actual number of days employed during the performance year in which the retirement date occurs. Similarly, payments under the Long-Term Performance Unit Program for those retiring with a minimum 12 months of participation are pro-rated based on the actual full months of participation, in each outstanding performance period, in which the retirement date occurs. In each case, payments are delivered at the conclusion of each annual or performance period, consistent with the timing of payments to active participants in the Annual Incentive Plan and the Long-Term Performance Unit Program, respectively. Unvested stock options issued under the 2011 Equity Ownership Plan vest on the retirement date and expire ten years from the grant date of the options. Unvested stock options issued under the 2015 Equity Ownership Plan expire the lesser of five years from the grant date of the options or original term of ten years. Any unvested restricted stock and restricted stock units (other than those issued under the Long-Term Performance Unit Program) held by the executive upon his or her retirement are forfeited, and perquisites are not available following the separation date.

Disability

If a Named Executive Officer’s employment is terminated due to disability, he or she generally is entitled to the same compensation and separation benefits described above under “Retirement,” except that unvested restricted stock and restricted stock units may be subject to specific disability benefits (as noted, where applicable, in the tables above).

Death

If a Named Executive Officer dies while actively employed by an Entergy employer, he or she generally is entitled to the same compensation and separation benefits described above under “Retirement,” except that unvested restricted stock and restricted stock units may be subject to specific death benefits (as noted, where applicable, in the tables above).

Item 12. Security Ownership of Certain Beneficial Owners and Management

Entergy Corporation owns 100% of the outstanding common stock of registrants Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and indirectly 100% of the outstanding common membership interests of registrant Entergy Louisiana. The information with respect to persons known by Entergy Corporation to

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be beneficial owners of more than 5% of Entergy Corporation’s outstanding common stock is included under the heading “Entergy Share Ownership - Beneficial Owners of More Than Five Percent” in the Proxy Statement, which information is incorporated herein by reference. The registrants know of no contractual arrangements that may, at a subsequent date, result in a change in control of any of the registrants.

The following table sets forth the beneficial ownership of common stock of Entergy Corporation and stock-based units as of January 31, 2017 for all non-employee directors and Named Executive Officers. Unless otherwise noted, each person had sole voting and investment power over the number of shares of common stock and stock-based units of Entergy Corporation set forth across from his or her name.



Name	Shares ⁽¹⁾⁽²⁾	Options Exercisable Within 60 Days	Stock Units ⁽³⁾
Entergy Corporation
A. Christopher Bakken, III**	5,200	—	—
Maureen S. Bateman*	20,924	—	—
Marcus V. Brown**	29,528	101,700	—
Patrick J. Condon*	2,668	—	—
Leo P. Denault***	111,638	470,332	—
Kirkland H. Donald*	4,662	—	609
Philip L. Frederickson*	1,159	—	609
Alexis M. Herman*	11,766	—	—
Donald C. Hintz*	13,907	—	3,973
Stuart L. Levenick*	16,255	—	—
Blanche L. Lincoln*	9,000	—	—
Andrew S. Marsh**	54,067	139,100	—
Karen A. Puckett*	2,668	—	—
W. J. Tauzin*	16,017	—	—
Roderick K. West**	36,509	90,999	—
All directors and executive
officers as a group (21 persons)	429,753	1,240,862	5,191

Entergy Arkansas
A. Christopher Bakken, III**	5,200	—	—
Marcus V. Brown**	29,528	101,700	—
Leo P. Denault**	111,638	470,332	—
Andrew S. Marsh***	54,067	139,100	—
Richard C. Riley***	10,700	19,734	—
Roderick K. West**	36,509	90,999	—
All directors and executive
officers as a group (11 persons)	320,062	1,117,630	—

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Name	Shares ⁽¹⁾⁽²⁾	Options Exercisable Within 60 Days	Stock Units ⁽³⁾
Entergy Louisiana
A. Christopher Bakken, III**	5,200	—	—
Marcus V. Brown**	29,528	101,700	—
Leo P. Denault**	111,638	470,332	—
Andrew S. Marsh***	54,067	139,100	—
Phillip R. May, Jr.***	16,599	45,233	12
All directors and executive
officers as a group (11 persons)	325,961	1,143,129	12

Entergy Mississippi
Marcus V. Brown**	29,528	101,700	—
Leo P. Denault**	111,638	470,332	—
Haley R. Fisackerly***	6,749	31,401	—
Andrew S. Marsh***	54,067	139,100	—
Roderick K. West**	36,509	90,999	—
All directors and executive
officers as a group (10 persons)	310,911	1,129,297	—

Entergy New Orleans
Marcus V. Brown**	29,528	101,700	—
Leo P. Denault**	111,638	470,332	—
Andrew S. Marsh***	54,067	139,100	—
Charles L. Rice, Jr.***	5,834	14,467	—
Roderick K. West**	36,509	90,999	—
All directors and executive
officers as a group (10 persons)	309,996	1,112,363	—

Entergy Texas
Marcus V. Brown**	29,528	101,700	—
Leo P. Denault**	111,638	470,332	—
Andrew S. Marsh***	54,067	139,100	—
Sallie T. Rainer***	8,031	22,366	—
Roderick K. West**	36,509	90,999	—
All directors and executive
officers as a group (10 persons)	312,193	1,120,262	—



*	Director of the respective Company
**	Named Executive Officer of the respective Company
***	Director and Named Executive Officer of the respective Company


(1)	The number of shares of Entergy Corporation common stock owned by each individual and by all non-employee directors and executive officers as a group does not exceed one percent of the outstanding shares of Entergy Corporation common stock.

(2)

For the non-employee directors, the balances include phantom units that are issued under the Service Recognition Program. All non-employee directors are credited with phantom units for each year of service on the Entergy Corporation Board. These phantom units do not have voting rights, accrue dividends, and will be settled in shares of Entergy Corporation common stock following the non-employee director’s separation from the Board.

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(3)

Represents the balances of phantom units each executive holds under the defined contribution restoration plan and the deferral provisions of the Equity Ownership Plan. These units will be paid out in either Entergy Corporation Common Stock or cash equivalent to the value of one share of Entergy Corporation common stock per unit on the date of payout, including accrued dividends. The deferral period is determined by the individual and is at least two years from the award of the bonus. Messrs. Donald, Hintz, and Frederickson have deferred receipt of some of their quarterly stock grants. The deferred shares will be settled in cash in an amount equal to the market value of Entergy Corporation common stock at the end of the deferral period.

Equity Compensation Plan Information

The following table summarizes the equity compensation plan information as of December 31, 2016. Information is included for equity compensation plans approved by the stockholders and equity compensation plans not approved by the stockholders.



Plan	Number of Securities to be Issued Upon Exercise of Outstanding Options (a)	Weighted Average Exercise Price (b)	Number of Securities Remaining Available for Future Issuance (excluding securities reflected in column (a))(c)
Equity compensation plans approved by security holders ⁽¹⁾	7,137,210	$84.91	5,192,463
Equity compensation plans not approved by security holders⁽²⁾	—	—	—
Total	7,137,210	$84.91	5,192,463

(1)

Includes the 2007 Equity Ownership Plan, the 2011 Equity Ownership Plan, and the 2015 Equity Ownership Plan. The 2007 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 12, 2006, and 7,000,000 shares of Entergy Corporation common stock were available for issuance, with no more than 2,000,000 shares available for non-option grants. The 2007 Plan only applies to awards granted between January 1, 2007 and May 5, 2011. The 2011 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 6, 2011, and 5,500,000 shares of Entergy Corporation common stock were available for issuance from the 2011 Equity Ownership Plan, with no more than 2,000,000 shares available for incentive stock option grants. The 2011 Plan only applied to awards granted between May 6, 2011 and May 7, 2015. The 2015 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 8, 2015, and 6,900,000 shares of Entergy Corporation common stock can be issued from the 2015 Equity Ownership Plan, with no more than 1,500,000 shares available for incentive stock option grants. The 2015 Plan applies to awards granted on or after May 8, 2015. The 2007 Equity Ownership Plan, the 2011 Equity Ownership Plan, and the 2015 Equity Ownership Plan (the “Plans”) are administered by the Personnel Committee of the Board of Directors (other than with respect to awards granted to non-employee directors, which awards are administered by the entire Board of Directors). Eligibility under the Plans is limited to the non-employee directors and to the officers and employees of an Entergy employer and any corporation 80% or more of whose stock (based on voting power) or value is owned, directly or indirectly, by Entergy Corporation. The Plans provide for the issuance of stock options, restricted stock, equity awards (units whose value is related to the value of shares of the common stock but do not represent actual shares of common stock), performance awards (performance shares or units valued by reference to shares of common stock or performance units valued by reference to financial measures or property other than common stock), restricted stock unit awards, and other stock-based awards.


(2)	Entergy has a Board-approved stock-based compensation plan. However, effective May 9, 2003, the Board has directed that no further awards be issued under that plan. As of December 31, 2016, all options outstanding under the plan were either exercised or expired.

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Item 13. Certain Relationships and Related Party Transactions and Director Independence

For information regarding certain relationship, related transactions and director independence of Entergy Corporation, see the Proxy Statement under the headings “Corporate Governance at Entergy - Our Board Structure - Director Independence” and “Corporate Governance at Entergy - Other Governance Policies and Practices - Our Transactions with Related Party Persons Policy.”

Entergy Corporation’s Board of Directors has adopted written policies and procedures for the review, approval or ratification of any transaction involving an amount in excess of $120,000 in which any director or executive officer of Entergy Corporation, any nominee for director, or any immediate family member of the foregoing has or will have a material interest as contemplated by Item 404(a) of Regulation S-K (“Related Person Transactions”). Under these policies and procedures, Entergy Corporation’s Corporate Governance Committee or a subcommittee of its Board of Directors consisting entirely of independent directors reviews the transaction and either approves or rejects the transaction after taking into account the following factors:


•	Whether the proposed transaction is on terms that are at least as favorable to Entergy Corporation as those achievable with an unaffiliated third party;


•	Size of the transaction and amount of consideration;


•	Nature of the interest;


•	Whether the transaction involves a conflict of interest;


•	Whether the transaction involves services available from unaffiliated third parties; and


•	Any other factors that the Corporate Governance Committee or subcommittee deems relevant.

The policy does not apply to (a) compensation and related person transactions involving a director or an executive officer solely resulting from that person’s service as a director or employment with Entergy Corporation so long as the compensation is approved by the Board of Directors (or an appropriate committee), (b) transactions involving the rendering of services as a public utility at rates or charges fixed in conformity with law or governmental authority, or (c) any other categories of transactions currently or in the future excluded from the reporting requirements of Item 404(a) of Regulation S-K.

Related Party Transactions

Since January 1, 2016, neither Entergy Corporation nor any of its affiliates has participated in any Related Person Transaction.

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Item 14. Principal Accountant Fees and Services (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

Aggregate fees billed to Entergy Corporation (consolidated), Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy for the years ended December 31, 2016 and 2015 by Deloitte & Touche LLP were as follows:



	2016		2015
Entergy Corporation (consolidated)
Audit Fees		$8,932,000		$9,312,255
Audit-Related Fees (a)	865,000		970,000
Total audit and audit-related fees	9,797,000		10,282,255
Tax Fees	—		—
All Other Fees	—		—
Total Fees (b)		$9,797,000		$10,282,255
Entergy Arkansas
Audit Fees		$1,056,881		$954,813
Audit-Related Fees (a)	—		—
Total audit and audit-related fees	1,056,881		954,813
Tax Fees	—		—
All Other Fees	—		—
Total Fees (b)		$1,056,881		$954,813
Entergy Louisiana
Audit Fees		$2,138,762		$1,873,042
Audit-Related Fees (a)	450,000		390,000
Total audit and audit-related fees	2,588,762		2,263,042
Tax Fees	—		—
All Other Fees	—		—
Total Fees (b)		$2,588,762		$2,263,042
Entergy Mississippi
Audit Fees		$971,881		$824,813
Audit-Related Fees (a)	—		—
Total audit and audit-related fees	971,881		824,813
Tax Fees	—		—
All Other Fees	—		—
Total Fees (b)		$971,881		$824,813

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	2016		2015
Entergy New Orleans
Audit Fees		$1,056,881		$977,652
Audit-Related Fees (a)	—		225,000
Total audit and audit-related fees	1,056,881		1,202,652
Tax Fees	—		—
All Other Fees	—		—
Total Fees (b)		$1,056,881		$1,202,652
Entergy Texas
Audit Fees		$1,076,881		$1,643,813
Audit-Related Fees (a)	—		—
Total audit and audit-related fees	1,076,881		1,643,813
Tax Fees	—		—
All Other Fees	—		—
Total Fees (b)		$1,076,881		$1,643,813
System Energy
Audit Fees		$861,881		$824,813
Audit-Related Fees (a)	—		—
Total audit and audit-related fees	861,881		824,813
Tax Fees	—		—
All Other Fees	—		—
Total Fees (b)		$861,881		$824,813


(a)	Includes fees for employee benefit plan audits, consultation on financial accounting and reporting, and other attestation services.


(b)	100% of fees paid in 2016 and 2015 were pre-approved by the Entergy Corporation Audit Committee.

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Entergy Audit Committee Guidelines for Pre-approval of Independent Auditor Services

The Audit Committee has adopted the following guidelines regarding the engagement of Entergy’s independent auditor to perform services for Entergy:


1.	The independent auditor will provide the Audit Committee, for approval, an annual engagement letter outlining the scope of services proposed to be performed during the fiscal year, including audit services and other permissible non-audit services (e.g. audit-related services, tax services, and all other services).

For other permissible services not included in the engagement letter, Entergy management will submit a description of the proposed service, including a budget estimate, to the Audit Committee for pre-approval. Management and the independent auditor must agree that the requested service is consistent with the SEC’s rules on auditor independence prior to submission to the Audit Committee. The Audit Committee, at its discretion, will pre-approve permissible services and has established the following additional guidelines for permissible non-audit services provided by the independent auditor:


•	Aggregate non-audit service fees are targeted at fifty percent or less of the approved audit service fee.


•	All other services should only be provided by the independent auditor if it is the only qualified provider of that service or if the Audit Committee specifically requests the service.


3.	The Audit Committee will be informed quarterly as to the status of pre-approved services actually provided by the independent auditor.


4.	To ensure prompt handling of unexpected matters, the Audit Committee delegates to the Audit Committee Chair or its designee the authority to approve permissible services and fees. The Audit Committee Chair or designee will report action taken to the Audit Committee at the next scheduled Audit Committee meeting.


5.	The Vice President and General Auditor will be responsible for tracking all independent auditor fees and will report quarterly to the Audit Committee.

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PART IV

Item 15. Exhibits and Financial Statement Schedules



(a)1.	Financial Statements and Independent Auditors’ Reports for Entergy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are listed in the Table of Contents.

(a)2.	Financial Statement Schedules

	Report of Independent Registered Public Accounting Firm (see page 519)

	Financial Statement Schedules are listed in the Index to Financial Statement Schedules (see page S-1)

(a)3.	Exhibits

	Exhibits for Entergy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are listed in the Exhibit Index (see page E-1). Each management contract or compensatory plan or arrangement required to be filed as an exhibit hereto is identified as such by footnote in the Exhibit Index.

Item 16. Form 10-K Summary (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)

None.

510

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ENTERGY CORPORATION

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.



	ENTERGY CORPORATION

	By /s/ Alyson M. Mount
	Alyson M. Mount
	Senior Vice President and Chief Accounting Officer

	Date: February 24, 2017

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.



Signature	Title	Date

/s/ Alyson M. Mount Alyson M. Mount	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	February 24, 2017

Leo P. Denault (Chairman of the Board, Chief Executive Officer and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President and Chief Financial Officer; Principal Financial Officer); Maureen S. Bateman, Patrick J. Condon, Kirkland H. Donald, Philip L. Frederickson, Alexis M. Herman, Donald C. Hintz, Stuart L. Levenick, Blanche L. Lincoln, Karen A. Puckett, and W. J. Tauzin (Directors).



By: /s/ Alyson M. Mount	February 24, 2017
(Alyson M. Mount, Attorney-in-fact)

511

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ENTERGY ARKANSAS, INC.

SIGNATURES



	ENTERGY ARKANSAS, INC.

	By /s/ Alyson M. Mount
	Alyson M. Mount
	Senior Vice President and Chief Accounting Officer

	Date: February 24, 2017



Signature	Title	Date

/s/ Alyson M. Mount Alyson M. Mount	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	February 24, 2017

Richard C. Riley (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Theodore H. Bunting, Jr. and Paul D. Hinnenkamp (Directors).



By: /s/ Alyson M. Mount	February 24, 2017
(Alyson M. Mount, Attorney-in-fact)

512

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ENTERGY LOUISIANA, LLC

SIGNATURES



	ENTERGY LOUISIANA, LLC

	By /s/ Alyson M. Mount
	Alyson M. Mount
	Senior Vice President and Chief Accounting Officer

	Date: February 24, 2017



Signature	Title	Date

/s/ Alyson M. Mount Alyson M. Mount	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	February 24, 2017

Phillip R. May, Jr. (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Theodore H. Bunting, Jr. and Paul D. Hinnenkamp (Directors).



By: /s/ Alyson M. Mount	February 24, 2017
(Alyson M. Mount, Attorney-in-fact)

513

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ENTERGY MISSISSIPPI, INC.

SIGNATURES



	ENTERGY MISSISSIPPI, INC.

	By /s/ Alyson M. Mount
	Alyson M. Mount
	Senior Vice President and Chief Accounting Officer

	Date: February 24, 2017



Signature	Title	Date

/s/ Alyson M. Mount Alyson M. Mount	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	February 24, 2017

Haley R. Fisackerly (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Theodore H. Bunting, Jr. and Paul D. Hinnenkamp (Directors).



By: /s/ Alyson M. Mount	February 24, 2017
(Alyson M. Mount, Attorney-in-fact)

514

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ENTERGY NEW ORLEANS, INC.

SIGNATURES



	ENTERGY NEW ORLEANS, INC.

	By /s/ Alyson M. Mount
	Alyson M. Mount
	Senior Vice President and Chief Accounting Officer

	Date: February 24, 2017



Signature	Title	Date

/s/ Alyson M. Mount Alyson M. Mount	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	February 24, 2017

Charles L. Rice, Jr. (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Theodore H. Bunting, Jr. and Paul D. Hinnenkamp (Directors).



By: /s/ Alyson M. Mount	February 24, 2017
(Alyson M. Mount, Attorney-in-fact)

515

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ENTERGY TEXAS, INC.

SIGNATURES



	ENTERGY TEXAS, INC.

	By /s/ Alyson M. Mount
	Alyson M. Mount
	Senior Vice President and Chief Accounting Officer

	Date: February 24, 2017



Signature	Title	Date

/s/ Alyson M. Mount Alyson M. Mount	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	February 24, 2017

Sallie T. Rainer (Chair of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Theodore H. Bunting, Jr. and Paul D. Hinnenkamp (Directors).



By: /s/ Alyson M. Mount	February 24, 2017
(Alyson M. Mount, Attorney-in-fact)

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SYSTEM ENERGY RESOURCES, INC.

SIGNATURES



	SYSTEM ENERGY RESOURCES, INC.

	By /s/ Alyson M. Mount
	Alyson M. Mount
	Senior Vice President and Chief Accounting Officer

	Date: February 24, 2017



Signature	Title	Date

/s/ Alyson M. Mount Alyson M. Mount	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	February 24, 2017

Theodore H. Bunting, Jr. (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); A. Christopher Bakken, III and Steven C. McNeal (Directors).



By: /s/ Alyson M. Mount	February 24, 2017
(Alyson M. Mount, Attorney-in-fact)

517

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EXHIBIT 23(a)

CONSENTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 333-213335 on Form S-3 and in Registration Statements Nos. 333-140183, 333-174148, and 333-204546 on Form S-8 of our reports dated February 24, 2017, relating to the consolidated financial statements and financial statement schedule of Entergy Corporation and Subsidiaries, and the effectiveness of Entergy Corporation and Subsidiaries’ internal control over financial reporting, appearing in this Annual Report on Form 10-K of Entergy Corporation for the year ended December 31, 2016.

We consent to the incorporation by reference in Registration Statement No. 333-213335-06 on Form S-3 of our reports dated February 24, 2017, relating to the consolidated financial statements and financial statement schedule of Entergy Arkansas, Inc. and Subsidiaries appearing in this Annual Report on Form 10-K of Entergy Arkansas, Inc. for the year ended December 31, 2016.

We consent to the incorporation by reference in Registration Statement No. 333-213335-03 on Form S-3 of our reports dated February 24, 2017, relating to the consolidated financial statements and financial statement schedule of Entergy Louisiana, LLC and Subsidiaries appearing in this Annual Report on Form 10‑K of Entergy Louisiana, LLC for the year ended December 31, 2016.

We consent to the incorporation by reference in Registration Statement No. 333-213335-02 on Form S-3 of our reports dated February 24, 2017, relating to the financial statements and financial statement schedule of Entergy Mississippi, Inc. appearing in this Annual Report on Form 10-K of Entergy Mississippi, Inc. for the year ended December 31, 2016.

We consent to the incorporation by reference in Registration Statement No. 333-213335-05 on Form S-3 of our reports dated February 24, 2017, relating to the consolidated financial statements and financial statement schedule of Entergy Texas, Inc. and Subsidiaries appearing in this Annual Report on Form 10-K of Entergy Texas, Inc. for the year ended December 31, 2016.

We consent to the incorporation by reference in Registration Statement No. 333-213335-04 on Form S-3 of our report dated February 24, 2017, relating to the financial statements of System Energy Resources, Inc. appearing in this Annual Report on Form 10-K of System Energy Resources, Inc. for the year ended December 31, 2016.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 24, 2017

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Entergy Corporation and Subsidiaries

New Orleans, Louisiana

We have audited the consolidated financial statements of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 2016 and 2015, and for each of the three years in the period ended December 31, 2016, and the Corporation’s internal control over financial reporting as of December 31, 2016, and have issued our reports thereon dated February 24, 2017; such consolidated financial statements and reports are included elsewhere in this Form 10-K. Our audits also included the consolidated financial statement schedule of the Corporation listed in Item 15. This consolidated financial statement schedule is the responsibility of the Corporation’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 24, 2017

519

Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Entergy Arkansas, Inc. and Subsidiaries

Entergy Mississippi, Inc.

Entergy New Orleans, Inc. and Subsidiaries

Entergy Texas, Inc. and Subsidiaries

To the Board of Directors and Members of

Entergy Louisiana, LLC and Subsidiaries

We have audited the consolidated financial statements of Entergy Arkansas, Inc. and Subsidiaries, Entergy Louisiana, LLC and Subsidiaries, Entergy New Orleans, Inc. and Subsidiaries, and Entergy Texas, Inc. and Subsidiaries, and we have also audited the financial statements of Entergy Mississippi, Inc. (collectively the “Companies”) as of December 31, 2016 and 2015, and for each of the three years in the period ended December 31, 2016, and have issued our reports thereon dated February 24, 2017; such financial statements and reports are included elsewhere in this Form 10-K. Our audits also included the financial statement schedules of the respective Companies listed in Item 15. These financial statement schedules are the responsibility of the respective Companies’ management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

/s/ DELOITTE & TOUCHE LLP

New Orleans, Louisiana

February 24, 2017

520

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INDEX TO FINANCIAL STATEMENT SCHEDULES



Schedule		Page

II	Valuation and Qualifying Accounts 2016, 2015, and 2014:
	Entergy Corporation and Subsidiaries	S-2
	Entergy Arkansas, Inc. and Subsidiaries	S-3
	Entergy Louisiana, LLC and Subsidiaries	S-4
	Entergy Mississippi, Inc.	S-5
	Entergy New Orleans, Inc. and Subsidiaries	S-6
	Entergy Texas, Inc. and Subsidiaries	S-7

Schedules other than those listed above are omitted because they are not required, not applicable, or the required information is shown in the financial statements or notes thereto.

Columns have been omitted from schedules filed because the information is not applicable.

S-1

Table of Contents



ENTERGY CORPORATION AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2016, 2015, and 2014
(In Thousands)
Column A	Column B		Column C		Column D		Column E
					Other
	Balance at		Additions		Changes		Balance
Description	Beginning of Period		Charged to Income		Deductions (1)		at End of Period
Allowance for doubtful accounts
2016		$39,895		$7,505		$35,476		$11,924
2015		$35,663		$6,926		$2,694		$39,895
2014		$34,311		$4,573		$3,221		$35,663
Notes:
(1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.

S-2

Table of Contents



ENTERGY ARKANSAS, INC. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2016, 2015, and 2014
(In Thousands)
Column A	Column B		Column C		Column D		Column E
					Other
	Balance at		Additions		Changes		Balance
Description	Beginning of Period		Charged to Income		Deductions (1)		at End of Period
Allowance for doubtful accounts
2016		$34,226		$902		$33,917		$1,211
2015		$32,247		$2,759		$780		$34,226
2014		$30,113		$2,881		$747		$32,247
Notes:
(1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.

S-3

Table of Contents



ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2016, 2015, and 2014
(In Thousands)
Column A	Column B		Column C		Column D		Column E
					Other
	Balance at		Additions		Changes		Balance
Description	Beginning of Period		Charged to Income		Deductions (1)		at End of Period
Allowance for doubtful accounts
2016		$4,209		$2,942		$874		$6,277
2015		$1,609		$3,464		$864		$4,209
2014		$1,874		$842		$1,107		$1,609
Notes:
(1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.

S-4

Table of Contents



ENTERGY MISSISSIPPI, INC.
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2016, 2015, and 2014
(In Thousands)
Column A	Column B		Column C		Column D		Column E
					Other
	Balance at		Additions		Changes		Balance
Description	Beginning of Period		Charged to Income		Deductions (1)		at End of Period
Allowance for doubtful accounts
2016		$718		$259		$428		$549
2015		$873		$247		$402		$718
2014		$906		$269		$302		$873
Notes:
(1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.

S-5

Table of Contents



ENTERGY NEW ORLEANS, INC. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2016, 2015, and 2014
(In Thousands)
Column A	Column B		Column C		Column D		Column E
					Other
	Balance at		Additions		Changes		Balance
Description	Beginning of Period		Charged to Income		Deductions (1)		at End of Period
Allowance for doubtful accounts
2016		$268		$2,872		$81		$3,059
2015		$262		$217		$211		$268
2014		$974		$99		$811		$262
Notes:
(1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.

S-6

Table of Contents



ENTERGY TEXAS, INC. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2016, 2015, and 2014
(In Thousands)
Column A	Column B		Column C		Column D		Column E
					Other
	Balance at		Additions		Changes		Balance
Description	Beginning of Period		Charged to Income		Deductions (1)		at End of Period
Allowance for doubtful accounts
2016		$474		$531		$177		$828
2015		$672		$239		$437		$474
2014		$443		$483		$254		$672
Notes:
(1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off.

S-7

Table of Contents

EXHIBIT INDEX

The following exhibits indicated by an asterisk preceding the exhibit number are filed herewith. The balance of the exhibits have heretofore been filed with the SEC as the exhibits and in the file numbers indicated and are incorporated herein by reference. The exhibits marked with a (+) are management contracts or compensatory plans or arrangements required to be filed herewith and required to be identified as such by Item 15 of Form 10-K.

Some of the agreements included or incorporated by reference as exhibits to this Form 10-K contain representations and warranties by each of the parties to the applicable agreement. These representations and warranties were made solely for the benefit of the other parties to the applicable agreement and (i) were not intended to be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate; (ii) may have been qualified in such agreement by disclosures that were made to the other party in connection with the negotiation of the applicable agreement; (iii) may apply contract standards of “materiality” that are different from the standard of “materiality” under the applicable securities laws; and (iv) were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement.

Entergy acknowledges that, notwithstanding the inclusion of the foregoing cautionary statements, it is responsible for considering whether additional specific disclosures of material information regarding material contractual provisions are required to make the statements in this Form 10-K not misleading.

(2) Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession

Entergy Louisiana



(a) 1 --	Plan of Merger of Entergy Gulf States Power, LLC and Entergy Gulf States Louisiana, LLC (2.1 to Form 8-K12B filed October 1, 2015 in 1-32718).

(a) 2 --	Plan of Merger of Entergy Louisiana, LLC and Entergy Louisiana Power, LLC (2.2 to Form 8-K12B filed October 1, 2015 in 1-32718).

(a) 3 --	Plan of Merger of Entergy Gulf States Power, LLC and Entergy Louisiana Power, LLC (2.3 to Form 8-K12B filed October 1, 2015 in 1-32718).

(3) Articles of Incorporation and By-laws

Entergy Corporation



(a) 1 --	Restated Certificate of Incorporation of Entergy Corporation dated October 10, 2006 (3(a) to Form 10-Q for the quarter ended September 30, 2006 in 1-11299).

(a) 2 --	Bylaws of Entergy Corporation as amended January 27, 2017, and as presently in effect (3.1 to Form 8-K filed January 30, 2017 in 1-11299).

System Energy



(b) 1 --	Amended and Restated Articles of Incorporation of System Energy and amendments thereto through April 28, 1989 (A-1(a) to Form U-1 in 70-5399).

(b) 2 --	By-Laws of System Energy effective July 6, 1998, and as presently in effect (3(f) to Form 10-Q for the quarter ended June 30, 1998 in 1-9067).

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Entergy Arkansas



(c) 1 --	Articles of Amendment and Restatement for the Second Amended and Restated Articles of Incorporation of Entergy Arkansas, effective August 19, 2009 (3 to Form 8-K filed August 24, 2009 in 1-10764).

(c) 2 --	By-Laws of Entergy Arkansas effective November 26, 1999, and as presently in effect (3(ii)(c) to Form 10-K for the year ended December 31, 1999 in 1-10764).

Entergy Louisiana



(d) 1 --	Certificate of Formation of Entergy Louisiana Power, LLC (including Certificate of Amendment to Certificate of Formation to change the company name to Entergy Louisiana, LLC) effective July 7, 2015 (3.3 to Form 8-K12B filed October 1, 2015 in 1-32718).

(d) 2 --	Company Agreement of Entergy Louisiana Power, LLC (including First Amendment to Company Agreement to change the company name to Entergy Louisiana, LLC) effective July 7, 2015 (3.4 to Form 8-K12B filed October 1, 2015 in 1-32718).

Entergy Mississippi



(e) 1 --	Second Amended and Restated Articles of Incorporation of Entergy Mississippi, effective July 21, 2009 (99.1 to Form 8-K filed July 27, 2009 in 1-31508).

(e) 2 --	By-Laws of Entergy Mississippi effective November 26, 1999, and as presently in effect (3(ii)(f) to Form 10-K for the year ended December 31, 1999 in 0-320).

Entergy New Orleans



(f) 1 --	Amended and Restated Articles of Incorporation of Entergy New Orleans, effective May 8, 2007 (3(a) to Form 10-Q for the quarter ended March 31, 2007 in 0-5807).

(f) 2 --	Amended By-Laws of Entergy New Orleans effective May 8, 2007, and as presently in effect (3(b) to Form 10-Q for the quarter ended March 31, 2007 in 0-5807).

Entergy Texas



(g) 1 --	Certificate of Formation of Entergy Texas, effective December 31, 2007 (3(i) to Form 10 filed March 14, 2008 in 000-53134).

(g) 2 --	Bylaws of Entergy Texas effective December 31, 2007 (3(ii) to Form 10 filed March 14, 2008 in 000-53134).

(4)Instruments Defining Rights of Security Holders, Including Indentures

Entergy Corporation



(a) 1 --	See (4)(b) through (4)(g) below for instruments defining the rights of security holders of System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas.

(a) 2 --	Indenture (For Unsecured Debt Securities), dated as of September 1, 2010, between Entergy Corporation and Wells Fargo Bank, National Association (4.01 to Form 8-K filed September 16, 2010 in 1-11299).

(a) 3 --	Officer’s Certificate for Entergy Corporation relating to 5.125% Senior Notes due September 15, 2020 (4.02(b) to Form 8-K filed September 16, 2010 in 1-11299).

(a) 4 --	Officer’s Certificate for Entergy Corporation relating to 4.50% Senior Note due December 16, 2028 (4(a)7 to Form 10-K for the year ended December 31, 2013 in 1-11299).

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(a) 5 --	Officer’s Certificate for Entergy Corporation relating to 2.95% Senior Notes due September 1, 2026 (4.02 to Form 8-K filed August 19, 2016 in 1-11299).

(a) 6 --	Officer’s Certificate for Entergy Corporation relating to 4.0% Senior Note due July 15, 2022 (4.02 to Form 8-K dated July 1, 2015 in 1-11299).

(a) 7 --	Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Corporation, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(g) to Form 10-Q for the quarter ended September 30, 2015 in 1-11299).

(a) 8 --	Amendment dated as of August 28, 2015, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Corporation, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(h) to Form 10-Q for the quarter ended September 30, 2015 in 1-11299).

(a) 9 --	Extension Agreement, dated as of August 8, 2016, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Corporation, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(l) to Form 10-Q for the quarter ended September 30, 2016 in 1-11299).

(a) 10 --	Amendment dated as of August 8, 2016, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Corporation, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(m) to Form 10-Q for the quarter ended September 30, 2016 in 1-11299).

System Energy



(b) 1 --	Mortgage and Deed of Trust, dated as of June 15, 1977, as amended and restated by the following Supplemental Indenture: (4.42 to Form 8-K dated September 25, 2012 in 1-9067 (Twenty-fourth)).

(b) 2 --	Loan Agreement, dated as of October 15, 1998, between System Energy and Mississippi Business Finance Corporation (B-6(b) to Rule 24 Certificate dated November 12, 1998 in 70-8511).

(b) 3 --	Fuel Lease, dated as of February 24, 1989, between River Fuel Funding Company #3, Inc. and System Energy (B-1(b) to Rule 24 Certificate dated March 3, 1989 in 70-7604).

Entergy Arkansas



(c) 1 --	Mortgage and Deed of Trust, dated as of October 1, 1944, as amended by the following Supplemental Indentures: (7(d) in 2-5463 (Mortgage); 7(b) in 2-7121 (First); 4(a)-7 in 2-10261 (Seventh); 2(b)-10 in 2-15767 (Tenth); 2(c) in 2-28869 (Sixteenth); 2(c) in 2-35107 (Eighteenth); 2(d) in 2-36646 (Nineteenth); 2(c) in 2-39253 (Twentieth); C-1 to Rule 24 Certificate in 70-6174 (Thirtieth); C-1 to Rule 24 Certificate in 70-6246 (Thirty-first); A-3(a) to Rule 24 Certificate in 70-7127 (Thirty-ninth); A-8(b) to Rule 24 Certificate dated July 6, 1989 in 70-7346 (Forty-first); 4(d)(2) in 33-54298 (Forty-sixth); C-2 to Form U5S for the year ended December 31,1995 (Fifty-third); 4.06 to Form 8-K dated October 8, 2010 in 1-10764 (Sixty-ninth); 4.06 to Form 8-K dated November 12, 2010 in 1-10764 (Seventieth); 4.06 to Form 8-K dated December 13, 2012 in 1-10764 (Seventy-first); 4(e) to Form 8-K dated January 9, 2013 in 1-10764 (Seventy-second); 4.06 to Form 8-K dated May 30, 2013 in 1-10764 (Seventy-third); 4.06 to Form 8-K dated June 4, 2013 in 1-10764 (Seventy-fourth); 4.05 to Form 8-K dated March 14, 2014 in 1-10764 (Seventy-sixth); 4.05 to Form 8-K dated December 9, 2014 in 1-10764 (Seventy-seventh); 4.05 to Form 8-K dated January 8, 2016 in 1-10764 (Seventy-eighth); and 4.05 to Form 8-K dated August 16, 2016 in 1-10764 (Seventy-ninth)).

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(c) 2 --	Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Arkansas, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(i) to Form 10-Q for the quarter ended September 30, 2015 in 1-10764).

(c) 3 --	Amendment dated as of August 28, 2015, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Arkansas, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(j) to Form 10-Q for the quarter ended September 30, 2015 in 1-10764).

(c) 4 --	Extension Agreement, dated as of August 8, 2016, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Arkansas, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(n) to Form 10-Q for the quarter ended September 30, 2016 in 1-10764).

(c) 5 --	Amendment dated as of August 8, 2016, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Arkansas, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(o) to Form 10-Q for the quarter ended September 30, 2016 in 1-10764).

(c) 6 --	Fuel Lease, dated as of December 22, 1988, between River Fuel Trust #1 and Entergy Arkansas (B-1(b) to Rule 24 Certificate in 70-7571).

(c) 7 --	Loan Agreement, dated as of January 1, 2013, between Jefferson County, Arkansas and Entergy Arkansas relating to Revenue Bonds (Entergy Arkansas, Inc. Project) Series 2013 (4(b) to Form 8-K filed January 9, 2013 in 1-10764).

(c) 8 --	Loan Agreement, dated as of January 1, 2013, between Independence County, Arkansas and Entergy Arkansas relating to Revenue Bonds (Entergy Arkansas, Inc. Project) Series 2013 (4(d) to Form 8-K filed January 9, 2013 in 1-10764).

Entergy Louisiana



(d) 1 --	Mortgage and Deed of Trust, dated as of April 1, 1944, as amended by the following Supplemental Indentures: (7(d) in 2-5317 (Mortgage); 7(b) in 2-7408 (First); D in 70-3862 (Sixth); 2(c) in 2-34659 (Twelfth); C to Rule 24 Certificate in 70-4793 (Thirteenth); 2(b)-2 in 2-38378 (Fourteenth); A-6(a) to Rule 24 Certificate in 70-5598 (Twenty-first); C-1 to Rule 24 Certificate in 70-6169 (Twenty-fifth); C-1 to Rule 24 Certificate in 70-6556 (Twenty-ninth); A-3(a) to Rule 24 Certificate in 70-7822 (Forty-second); A-2(a) to Rule 24 Certificate dated April 4, 1996 in 70-8487 (Fifty-first); B-4(i) to Rule 24 Certificate dated January 10, 2006 in 70-10324 (Sixty-third); B-4(ii) to Rule 24 Certificate dated January 10, 2006 in 70-10324 (Sixty-fourth); 4(a) to Form 10-Q for the quarter ended September 30, 2008 in 1-32718 (Sixty-fifth); 4(e)1 to Form 10-K for the year ended December 31, 2009 in 1-132718 (Sixty-sixth); 4.08 to Form 8-K dated September 24, 2010 in 1-32718 (Sixty-eighth); 4.08 to Form 8-K dated March 24, 2011 in 1-32718 (Seventy-first); 4(a) to Form 10-Q for the quarter ended June 30, 2011 in 1-32718 (Seventy-second); 4.08 to Form 8-K dated July 3, 2012 in 1-32718 (Seventy-fifth); 4.08 to Form 8-K dated December 4, 2012 in 1-32718 (Seventy-sixth); 4.08 to Form 8-K dated May 21, 2013 in 1-32718 (Seventy-seventh); 4.08 to Form 8-K dated August 23, 2013 in 1-32718 (Seventy-eighth); 4.08 to Form 8-K dated June 24, 2014 in 1-32718 (Seventy-ninth); 4.08 to Form 8-K dated July 1, 2014 in 1-32718 (Eightieth); 4.08 to Form 8-K dated November 21, 2014 (Eighty-first); 4.1 to Form 8-K12B dated October 1, 2015 (Eighty-second); 4(g) to Form 8-K dated March 18, 2016 in 1-32718 (Eighty-third); 4.33 to Form 8-K dated March 24, 2016 in 1-32718 (Eighty-fourth); 4(k) to Form 10-Q for the quarter ended March 31, 2016 in 1-32718 (Eighty-fifth); 4.33 to Form 8-K dated August 17, 2016 in 1-32718 (Eighty-sixth); and 4.33 to Form 8-K dated October 4, 2016 in 1-32718 (Eighty-seventh)).

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(d) 2 --	Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Louisiana [Old Entergy Louisiana] and Entergy Gulf States Louisiana, as the Borrowers, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4.4 to Form 8-K12B filed October 1, 2015 in 1-32718).

(d) 3 --	Amendment dated as of August 28, 2015, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Louisiana [Old Entergy Louisiana] and Entergy Gulf States Louisiana, as the Borrowers, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4.5 to Form 8-K12B filed October 1, 2015 in 1-32718).

(d) 4 --	Borrower Assumption Agreement dated as of October 1, 2015 of Entergy Louisiana [New Entergy Louisiana] under Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Louisiana [Old Entergy Louisiana] and Entergy Gulf States Louisiana, as the Borrowers, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto, as amended (4.6 to Form 8-K12B filed October 1, 2015 in 1-32718).

(d) 5 --	Extension Agreement, dated as of August 8, 2016, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Louisiana, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(p) to Form 10-Q for the quarter ended September 30, 2016 in 1-32718).

(d) 6 --	Amendment dated as of August 8, 2016, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Louisiana, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(q) to Form 10-Q for the quarter ended September 30, 2016 in 1-32718).

(d) 7 --	Fuel Lease, dated as of January 31, 1989, between River Fuel Company #2, Inc., and Entergy Louisiana (B-1(b) to Rule 24 Certificate in 70-7580).

(d) 8 --	Nuclear Fuel Lease Agreement between Entergy Gulf States, Inc. and River Bend Fuel Services, Inc. to lease the fuel for River Bend Unit 1, dated February 7, 1989 (10-64 to Form 10-K for the year ended December 31, 1988 in 1-27031).

(d) 9 --	Loan Agreement, dated as of March 1, 2016, between the Louisiana Public Facilities Authority and Entergy Louisiana relating to Refunding Revenue Bonds (Entergy Louisiana, LLC Project) Series 2016A (4(b) to Form 8-K filed March 18, 2016 in 1-32718).

(d) 10 --	Loan Agreement, dated as of March 1, 2016, between Louisiana Public Facilities Authority and Entergy Louisiana relating to Refunding Revenue Bonds (Entergy Louisiana, LLC Project) Series 2016B (4(d) to Form 8-K filed March 18, 2016 in 1-32718).

(d) 11 --	Indenture of Mortgage, dated September 1, 1926, as amended by the following Supplemental Indentures: (7-A-9 in Registration No. 2-6893 (Seventh); B to Form 8-K dated September 1, 1959 (Eighteenth); 2-A-8 in Registration No. 2-66612 (Thirty-eighth); 4(b) to Form 10-Q for the quarter ended March 31,1999 in 1-27031 (Fifty-eighth); 4(a) to Form 10-Q for the quarter ended June 30, 2008 in 333-148557 (Seventy-sixth); 4(a) to Form 10-Q for the quarter ended September 30, 2009 in 0-20371 (Seventy-seventh); 4.07 to Form 8-K dated October 1, 2010 in 0-20371 (Seventy-eighth); 4(c) to Form 8-K filed October 12, 2010 in 0-20371 (Seventy-ninth); 4.07 to Form 8-K dated July 1, 2014 in 0-20371 (Eighty-first); 4.2 to Form 8-K12B dated October 1, 2015 in 1-32718 (Eighty-second); 4.3 to Form 8-K12B dated October 1, 2015 in 1-32718 (Eighty-third); 4.42 to Form 8-K dated March 24, 2016 in 1-32718 (Eighty-fourth); 4.42 to Form 8-K dated May 19, 2016 in 1-32718 (Eighty-fifth); 4.42 to Form 8-K dated August 17, 2016 in 1-32718 (Eighty-sixth); and 4.42 to Form 8-K dated October 4, 2016 in 1-32718 (Eighty-seventh)).

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(d) 12 --	Agreement of Resignation, Appointment and Acceptance, dated as of October 3, 2007, among Entergy Gulf States, Inc., JPMorgan Chase Bank, National Association, as resigning trustee, and The Bank of New York, as successor trustee (4(a) to Form 10-Q for the quarter ended September 30, 2007 in 1-27031).

(d) 13 --	Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015, as amended by the following Supplemental Indentures: (4.38 in Registration No. 333-190911-07 (Mortgage); 4(f) to Form 8-K filed March 18, 2016 in 1-32718 (First); 4.40 to Form 8-K filed March 24, 2016 in 1-32718 (Second); 4(g) to Form 10-Q for the quarter ended March 31, 2016 in 1-32718 (Third); 4(h) to Form 10-Q for the quarter ended March 31, 2016 in 1-32718 (Fourth); 4.40 to Form 8-K filed May 19, 2016 in 1-32718 (Fifth); 4.40 to Form 8-K filed August 17, 2016 in 1-32718 (Sixth); and 4.41 to Form 8-K filed October 4, 2016 in 1-32718 (Seventh)).

(d) 14 --	Officer’s Certificate No. 1-B-1, dated March 18, 2016, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4(e) to Form 8-K filed March 19, 2016 in 1-32718).

(d) 15 --	Officer’s Certificate No. 2-B-2, dated March 17, 2016, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4.39 to Form 8-K filed March 24, 2016 in 1-32718).

(d) 16 --	Officer’s Certificate No. 3-B-3, dated March 28, 2016, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4(d) to Form 10-Q for the quarter ended March 31, 2016 in 1-32718).

(d) 17 --	Officer’s Certificate No. 4-B-4, dated May 16, 2016, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4.39 to Form 8-K filed May 19, 2016 in 1-32718).

(d) 18 --	Officer’s Certificate No. 6-B-5, dated August 1, 2016, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4.39 to Form 8-K filed August 17, 2016 in 1-32718).

(d) 19 --	Officer’s Certificate No. 7-B-6, dated September 15, 2016, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4.40 to Form 8-K filed October 4, 2016 in 1-32718).

Entergy Mississippi



(e) 1 --	Mortgage and Deed of Trust, dated as of February 1, 1988, as amended by the following Supplemental Indentures: (A-2(a)-2 to Rule 24 Certificate in 70-7461 (Mortgage); A-2(e) to Rule 24 Certificate dated January 22, 1993 in 70-7914 (Sixth); A-2(c) to Rule 24 Certificate dated May 12, 1999 in 70-8719 (Thirteenth); 4(b) to Form 10-Q for the quarter ended June 30, 2009 in 1-31508 (Twenty-sixth); 4.38 to Form 8-K dated December 11, 2012 in 1-31508 (Thirtieth); 4.05 to Form 8-K dated March 21, 2014 in 1-31508 (Thirty-first); 4.05 to Form 8-K dated May 13, 2016 in 1-31508 (Thirty-second); and 4.16 to Form 8-K dated September 15, 2016 in 1-31508 (Thirty-third)).

Entergy New Orleans



(f) 1 --	Mortgage and Deed of Trust, dated as of May 1, 1987, as amended by the following Supplemental Indentures: (A-2(c) to Rule 24 Certificate in 70-7350 (Mortgage); 4(f)4 to Form 10-K for the year ended December 31, 1992 in 0-5807 (Third); 4(b) to Form 10-Q for the quarter ended June 30, 1998 in 0-5807 (Seventh); 4.02 to Form 8-K dated November 23, 2010 in 0-5807 (Fifteenth); 4.02 to Form 8-K dated November 29, 2012 in 0-5807 (Sixteenth); 4.02 to Form 8-K dated June 21, 2013 in 0-5807 (Seventeenth); 4(m) to Form 10-Q for the quarter ended March 31, 2016 in 0-5807 (Eighteenth); 4.02 to Form 8-K dated March 22, 2016 in 0-5807 (Nineteenth); and 4.02 to Form 8-K dated May 24, 2016 in 0-5807 (Twentieth)).

(f) 2 --	Amended and Restated Credit Agreement ($25,000,000), dated as of November 20, 2015, among Entergy New Orleans, as the Borrower, the banks and other financial institutions party thereto as Lenders, and Bank of America, N.A., as Administrative Agent (4(f)2 to Form 10-K for the year ended December 31, 2015 in 0-5807).

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(f) 3 --	Amendment to Amended and Restated Credit Agreement, dated as of June 30, 2016, among Entergy New Orleans, as the Borrower, the banks and other financial institutions party thereto as Lenders, and Bank of America, N.A., as Administrative Agent (4(f) to Form 10-Q for the quarter ended June 30, 2016 in 0-5807).

Entergy Texas



(g) 1 --	Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas and The Bank of New York Mellon, as trustee (4(h)2 to Form 10-K for the year ended December 31, 2008 in 0-53134).

(g) 2 --	Officer’s Certificate No. 1-B-1 dated January 27, 2009, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas and The Bank of New York Mellon, as trustee (4(h)3 to Form 10-K for the year ended December 31, 2008 in 0-53134).

(g) 3 --	Officer’s Certificate No. 2-B-2 dated May 14, 2009, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas and The Bank of New York Mellon, as trustee (4(a) to Form 10-Q for the quarter ended June 30, 2009 in 1-34360).

(g) 4 --	Officer’s Certificate No. 5-B-4 dated September 7, 2011, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas and The Bank of New York Mellon, as trustee (4.40 to Form 8-K dated September 13, 2011 in 1-34360).

(g) 5 --	Officer’s Certificate No. 7-B-5 dated May 13, 2014, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas and The Bank of New York Mellon, as trustee (4.40 to Form 8-K dated May 16, 2014 in 1-34360).

(g) 6 --	Officer’s Certificate No. 8-B-6 dated May 18, 2015, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas and The Bank of New York Mellon, as trustee (4.40 to Form 8-K dated May 21, 2015 in 1-34360).

(g) 7 --	Officer’s Certificate No. 9-B-7 dated March 8, 2016, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas and The Bank of New York Mellon, as trustee (4.40 to Form 8-K dated March 11, 2016 in 1-34360).

(g) 8 --	Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Texas, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(k) to Form 10-Q for the quarter ended September 30, 2015 in 1-34360).

(g) 9 --	Amendment dated as of August 28, 2015, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Texas, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(l) to Form 10-Q for the quarter ended September 30, 2015 in 1-34360).

(g) 10 --	Extension Agreement, dated as of August 8, 2016, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Texas, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(r) to Form 10-Q for the quarter ended September 30, 2016 in 1-34360).

(g) 11 --	Amendment dated as of August 8, 2016, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Texas, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(s) to Form 10-Q for the quarter ended September 30, 2016 in 1-34360).

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(10) Material Contracts

Entergy Corporation



+(a) 1 --	2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries (Effective for Grants and Elections On or After January 1, 2007) (Appendix B to Entergy Corporation’s Definitive Proxy Statement filed on March 24, 2006 in 1-11299).

+(a) 2 --	First Amendment of the 2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries effective October 26, 2006 (10(a)50 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 3 --	Second Amendment of the 2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries effective January 1, 2009 (10(a)51 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 4 --	Third Amendment of the 2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries effective December 30, 2010 (10(a)52 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 5 --	2011 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries (Annex A to Entergy Corporation’s Definitive Proxy Statement filed on March 24, 2011 in 1-11299).

+(a) 6 --	2015 Equity Ownership Plan of Entergy Corporation and Subsidiaries (Annex C to 2015 Entergy Corporation’s Definitive Proxy Statement filed on March 20, 2015 in 1-11299).

+(a) 7 --	Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009 (10(a)57 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 8 --	First Amendment of the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)58 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 9 --	Second Amendment of the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)57 to Form 10-K for the year ended December 31, 2011 in 1-11299).

+(a) 10 --	Third Amendment of the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective July 25, 2013 (10(b) to Form 10-Q for the quarter ended September 30, 2014 in 1-11299).

+(a) 11 --	Fourth Amendment of the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective July 1, 2014 (10(c) to Form 10-Q for the quarter ended September 30, 2014 in 1-11299).

+(a) 12 --	Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009 (10(a)59 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 13 --	First Amendment of the Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)60 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 14 --	Second Amendment of the Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)60 to Form 10-K for the year ended December 31, 2011 in 1-11299).

+(a) 15 --	Executive Disability Plan of Entergy Corporation and Subsidiaries (10(a)74 to Form 10-K for the year ended December 31, 2001 in 1-11299).

+(a) 16 --	Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009 (10(a)62 to Form 10-K for the year ended December 31, 2010 in 1-11299).

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+(a) 17 --	First Amendment of the Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)63 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 18 --	Second Amendment of the Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)64 to Form 10-K for the year ended December 31, 2011 in 1-11299).

+(a) 19 --	System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective as of January 1, 2009 (10(a)77 to Form 10-K for the year ended December 31, 2009 in 1-11299).

+(a) 20 --	First Amendment of the System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective January 1, 2010 (10(a)78 to Form 10-K for the year ended December 31, 2009 in 1-11299).

+(a) 21 --	Second Amendment of the System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)69 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 22 --	Third Amendment of the System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)71 to Form 10-K for the year ended December 31, 2011 in 1-11299).

+(a) 23 --	Post-Retirement Plan of Entergy Corporation and Subsidiaries, as amended effective January 1, 2000 (10(a)80 to Form 10-K for the year ended December 31, 2001 in 1-11299).

+(a) 24 --	Amendment, effective December 28, 2001, to the Post-Retirement Plan of Entergy Corporation and Subsidiaries (10(a)81 to Form 10-K for the year ended December 31, 2001 in 1-11299).

+(a) 25 --	Pension Equalization Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009 (10(a)74 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 26 --	First Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)75 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 27 --	Second Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)76 to Form 10-K for the year ended December 31, 2011 in 1-11299).

+(a) 28 --	Third Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective June 19, 2013 (10(b) to Form 10-Q for the quarter ended June 30, 2013 in 1-11299).

+(a) 29 --	Fourth Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective July 25, 2013 (10(c) to Form 10-Q for the quarter ended June 30, 2013 in 1-11299).

+(a) 30 --	Fifth Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective July 1, 2014 (10(a) to Form 10-Q for the quarter ended September 30, 2014 in 1-11299).

+(a) 31 --	Executive Income Security Plan of Gulf States Utilities Company, as amended effective March 1, 1991 (10(a)86 to Form 10-K for the year ended December 31, 2001 in 1-11299).

+(a) 32 --	System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective January 1, 2009 (10(a)78 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 33 --	First Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)79 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 34 --	Second Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)81 to Form 10-K for the year ended December 31, 2011 in 1-11299).

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+(a) 35 --	Third Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective January 26, 2012 (10(a)81 to Form 10-K for the year ended December 31, 2013 in 1-11299).

+(a) 36 --	Fourth Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective July 25, 2013 (10(d) to Form 10-Q for the year ended June 30, 2013 in 1-11299).

+(a) 37 --	Fifth Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective July 1, 2014 (10(d) to Form 10-Q for the year ended September 30, 2014 in 1-11299).

+(a) 38 --	Employment Agreement effective February 9, 1999 between Leo P. Denault and Entergy Services (10(a) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299).

+(a) 39 --	Amendment to Employment Agreement effective March 5, 2004 between Leo P. Denault and Entergy Corporation (10(b) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299).

+(a) 40 --	Retention Agreement effective August 3, 2006 between Leo P. Denault and Entergy Corporation (10(b) to Form 10-Q for the quarter ended June 30, 2006 in 1-11299).

+(a) 41 --	Amendment to Retention Agreement effective January 1, 2009 between Leo P. Denault and Entergy Corporation (10(a)93 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 42 --	Amendment to Retention Agreement effective January 1, 2010 between Leo P. Denault and Entergy Corporation (10(a)101 to Form 10-K for the year ended December 31, 2009 in 1-11299).

+(a) 43 --	Amendment to Retention Agreement effective December 30, 2010 between Leo P. Denault and Entergy Corporation (10(a)95 to Form 10-K for the year ended December 31, 2010 in 1-11299).

+(a) 44 --	Shareholder Approval of Future Severance Agreements Policy, effective March 8, 2004 (10(f) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299).

+(a) 45 --	Entergy Corporation Non-Employee Director Stock Program Established under the 2015 Equity Ownership Plan of Entergy Corporation and Subsidiaries (10(c) to Form 10-Q for the quarter ended June 30, 2015 in 1-11299).

+(a) 46 --	Entergy Nuclear Retention Plan, as amended and restated January 1, 2007 (10(a)107 to Form 10-K for the year ended December 31, 2007 in 1-11299).

*+(a) 47 --	Form of Stock Option Grant Agreement.

*+(a) 48 --	Form of Long Term Incentive Program Performance Unit Agreement.

*+(a) 49 --	Form of Restricted Stock Grant Agreement.

+(a) 50 --	Restricted Units Agreement between Roderick K. West and Entergy Corporation (10(a) to Form 10-Q for the quarter ended June 30, 2013 in 1-11299).

+(a) 51 --	Restricted Stock Unit Agreement between Andrew S. Marsh and Entergy Corporation (10(a)102 to Form 10-K for the year ended December 31, 2015 in 1-11299).

+(a) 52 --	Executive Annual Incentive Plan of Entergy Corporation and Subsidiaries as amended and restated effective January 1, 2016 (Appendix B to 2015 Entergy Corporation’s Definitive Proxy Statement filed on March 20, 2015 in 1-11299).

+(a) 53 --	Service Recognition Program for Non-Employee Outside Directors of Entergy Corporation and Subsidiaries, as amended and restated effective June 1, 2015 (10(d) to Form 10-Q for the quarter ended June 30, 2015 in 1-11299).

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*+(a) 54 --	Restricted Stock Units Agreement by and between A. Christopher Bakken, III and Entergy Corporation effective April 6, 2016.

*+(a) 55 --	Offer Letter, dated January 28, 2016, by and between A. Christopher Bakken, III and Entergy Services, Inc.

System Energy



(b) 1 --	Availability Agreement, dated June 21, 1974, among System Energy and certain other System companies (B to Rule 24 Certificate dated June 24, 1974 in 70-5399).

(b) 2 --	First Amendment to Availability Agreement, dated as of June 30, 1977 (B to Rule 24 Certificate dated June 24, 1977 in 70-5399).

(b) 3 --	Second Amendment to Availability Agreement, dated as of June 15, 1981 (E to Rule 24 Certificate dated July 1, 1981 in 70-6592).

(b) 4 --	Third Amendment to Availability Agreement, dated as of June 28, 1984 (B-13(a) to Rule 24 Certificate dated July 6, 1984 in 70-6985).

(b) 5 --	Fourth Amendment to Availability Agreement, dated as of June 1, 1989 (A to Rule 24 Certificate dated June 8, 1989 in 70-5399).

(b) 6 --	Thirty-seventh Assignment of Availability Agreement, Consent and Agreement, dated as of September 1, 2012, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and The Bank of New York Mellon, as successor trustee (10(a)15 to Form 10-K for the year ended December 31, 2012 in 1-11299).

(b) 7 --	Amendment to the Thirty-seventh Assignment of Availability Agreement, Consent and Agreement, dated as of September 18, 2015, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and The Bank of New York Mellon, as successor trustee (4.25 to Form S-3 dated October 2, 2015).

(b) 8 --	Capital Funds Agreement, dated June 21, 1974, between Entergy Corporation and System Energy (C to Rule 24 Certificate dated June 24, 1974 in 70-5399).

(b) 9 --	First Amendment to Capital Funds Agreement, dated as of June 1, 1989 (B to Rule 24 Certificate dated June 8, 1989 in 70-5399).

(b) 10 --	Thirty-seventh Supplementary Capital Funds Agreement and Assignment, dated as of September 1, 2012, among Entergy Corporation, System Energy, and The Bank of New York Mellon, as successor trustee (10(a)19 to Form 10-K for the year ended December 31, 2012 in 1-11299).

(b) 11 --	Facility Lease No. 1, dated as of December 1, 1988, between Meridian Trust Company and Stephen M. Carta (Stephen J. Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (1) to Rule 24 Certificate dated April 21, 1989 in 70-7561), Lease Supplement No. 2 dated as of January 1, 1994 (B-3(d) to Rule 24 Certificate dated January 31, 1994 in 70-8215), and Lease Supplement No. 3 dated as of May 1, 2004 (B-3(d) to Rule 24 Certificate dated June 4, 2004 in 70-10182).

*(b) 12 --	Lease Supplement No. 4, dated as of January 15, 2014, to Facility Lease No. 1.

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(b) 13 --	Facility Lease No. 2, dated as of December 1, 1988 between Meridian Trust Company and Stephen M. Carta (Stephen J. Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (2) to Rule 24 Certificate dated April 21, 1989 in 70-7561), Lease Supplement No. 2 dated as of January 1, 1994 (B-4(d) Rule 24 Certificate dated January 31, 1994 in 70-8215), and Lease Supplement No. 3 dated as of May 1, 2004 (B-4(d) to Rule 24 Certificate dated June 4, 2004 in 70-10182).

*(b) 14 --	Lease Supplement No. 4, dated as of May 28, 2014, to Facility Lease No. 2.

(b) 15 --	Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624).

*(b) 16 --	Unit Power Sales Agreement among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans dated as of June 10, 1982, as amended and revised.

Entergy Louisiana



(c) 1 --	Fourth Amended and Restated Limited Liability Company Agreement of Entergy Holdings Company LLC dated as of September 19, 2015 (10(b) to Form 10-Q for the quarter ended September 30, 2015).

(12) Statement Re Computation of Ratios



*(a)	Entergy Arkansas’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined.

*(b)	Entergy Louisiana’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Distributions, as defined.

*(c)	Entergy Mississippi’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined.

*(d)	Entergy New Orleans’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined.

*(e)	Entergy Texas’s Computation of Ratios of Earnings to Fixed Charges, as defined.

*(f)	System Energy’s Computation of Ratios of Earnings to Fixed Charges, as defined.

*(21) Subsidiaries of the Registrants

(23) Consents of Experts and Counsel



*(a)	The consent of Deloitte & Touche LLP is contained herein at page 518.

*(24) Powers of Attorney

(31) Rule 13a-14(a)/15d-14(a) Certifications



*(a)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Corporation.

*(b)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Corporation.

*(c)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Arkansas.

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*(d)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Arkansas.

*(e)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Louisiana.

*(f)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Louisiana.

*(g)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Mississippi.

*(h)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Mississippi.

*(i)	Rule 13a-14(a)/15d-14(a) Certification for Entergy New Orleans.

*(j)	Rule 13a-14(a)/15d-14(a) Certification for Entergy New Orleans.

*(k)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Texas.

*(l)	Rule 13a-14(a)/15d-14(a) Certification for Entergy Texas.

*(m)	Rule 13a-14(a)/15d-14(a) Certification for System Energy.

*(n)	Rule 13a-14(a)/15d-14(a) Certification for System Energy.

(32) Section 1350 Certifications



*(a)	Section 1350 Certification for Entergy Corporation.

*(b)	Section 1350 Certification for Entergy Corporation.

*(c)	Section 1350 Certification for Entergy Arkansas.

*(d)	Section 1350 Certification for Entergy Arkansas.

*(e)	Section 1350 Certification for Entergy Louisiana.

*(f)	Section 1350 Certification for Entergy Louisiana.

*(g)	Section 1350 Certification for Entergy Mississippi.

*(h)	Section 1350 Certification for Entergy Mississippi.

*(i)	Section 1350 Certification for Entergy New Orleans.

*(j)	Section 1350 Certification for Entergy New Orleans.

*(k)	Section 1350 Certification for Entergy Texas.

*(l)	Section 1350 Certification for Entergy Texas.

*(m)	Section 1350 Certification for System Energy.

*(n)	Section 1350 Certification for System Energy.

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(101) XBRL Documents

Entergy Corporation



*INS -	XBRL Instance Document.

*SCH -	XBRL Taxonomy Extension Schema Document.

*CAL -	XBRL Taxonomy Extension Calculation Linkbase Document.

*DEF -	XBRL Taxonomy Extension Definition Linkbase Document.

*LAB -	XBRL Taxonomy Extension Label Linkbase Document.

*PRE -	XBRL Taxonomy Extension Presentation Linkbase Document.

_________________



	*	Filed herewith.
	+	Management contracts or compensatory plans or arrangements.

E-14



	Qualified Pension Costs			Other Postretirement Costs			Non-Qualified Pension Costs			Total
	(In Thousands)
Entergy
Amortization of prior service cost		($1,079	)		$30,949			($456	)		$29,414
Acceleration of prior service cost due to curtailment	(1,045		)	—			—			(1,045		)
Amortization of loss	(49,930		)	(8,248		)	(2,515		)	(60,693		)
Settlement loss	—			—			(2,007		)	(2,007		)
		($52,054	)		$22,701			($4,978	)		($34,331	)
Entergy Louisiana
Amortization of prior service cost		$—			$7,787			($1	)		$7,786
Amortization of loss	(3,345		)	(2,926		)	(10		)	(6,281		)
		($3,345	)		$4,861			($11	)		$1,505



Pension Asset Allocation	Target	Range			Actual 2016	Actual 2015
Domestic Equity Securities	45%	37%	to	53%	46%	45%
International Equity Securities	20%	16%	to	24%	20%	19%
Fixed Income Securities	35%	32%	to	38%	33%	35%
Other	0%	0%	to	10%	1%	1%



Postretirement Asset Allocation	Non-Taxable and Taxable
	Target	Range			Actual 2016	Actual 2015
Domestic Equity Securities	39%	34%	to	44%	40%	40%
International Equity Securities	26%	21%	to	31%	27%	24%
Fixed Income Securities	35%	30%	to	40%	33%	36%
Other	0%	0%	to	5%	0%	0%


•	Level 3 - Level 3 refers to securities valued based on significant unobservable inputs.