NRG ENERGY, INC. - Quarter Report: 2017 March (Form 10-Q)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



x		Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

		For the Quarterly Period Ended: March 31, 2017

o		Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

Commission File Number: 001-15891

NRG Energy, Inc.

(Exact name of registrant as specified in its charter)



Delaware (State or other jurisdiction of incorporation or organization)		41-1724239 (I.R.S. Employer Identification No.)

804 Carnegie Center, Princeton, New Jersey (Address of principal executive offices)		08540 (Zip Code)

(609) 524-4500

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has 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 registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its 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 x No o

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



Large accelerated filer x	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o	Emerging growth company o
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No x

As of April 30, 2017, there were 316,082,221 shares of common stock outstanding, par value $0.01 per share.

TABLE OF CONTENTS

Index



CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION	3
GLOSSARY OF TERMS	5
PART I — FINANCIAL INFORMATION	9
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES	9
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	52
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	80
ITEM 4 — CONTROLS AND PROCEDURES	82
PART II — OTHER INFORMATION	83
ITEM 1 — LEGAL PROCEEDINGS	83
ITEM 1A — RISK FACTORS	83
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	83
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES	83
ITEM 4 — MINE SAFETY DISCLOSURES	83
ITEM 5 — OTHER INFORMATION	83
ITEM 6 — EXHIBITS	84
SIGNATURES	85

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q of NRG Energy, Inc., or NRG or the Company, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or Exchange Act. The words "believes," "projects," "anticipates," "plans," "expects," "intends," "estimates" and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors that may cause NRG's actual results, performance and achievements, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. These factors, risks and uncertainties include the factors described under Item 1A — Risk Factors Related to NRG Energy, Inc., in Part I, Item 1A of the Company's Annual Report on Form 10-K for the year ended December 31, 2016, and the following:


•	GenOn's and certain of its subsidiaries' ability to continue as a going concern;


•	General economic conditions, changes in the wholesale power markets and fluctuations in the cost of fuel;


•	Volatile power supply costs and demand for power;

•

Hazards customary to the power production industry and power generation operations such as fuel and electricity price volatility, unusual weather conditions (including wind and solar conditions), catastrophic weather-related or other damage to facilities, unscheduled generation outages, maintenance or repairs, unanticipated changes to fuel supply costs or availability due to higher demand, shortages, transportation problems or other developments, environmental incidents, or electric transmission or gas pipeline system constraints and the possibility that NRG may not have adequate insurance to cover losses as a result of such hazards;


•	The effectiveness of NRG's risk management policies and procedures, and the ability of NRG's counterparties to satisfy their financial commitments;


•	Counterparties' collateral demands and other factors affecting NRG's liquidity position and financial condition;


•	NRG's ability to operate its businesses efficiently and generate earnings and cash flows from its asset-based businesses in relation to its debt and other obligations;


•	NRG's ability to enter into contracts to sell power and procure fuel on acceptable terms and prices;


•	The liquidity and competitiveness of wholesale markets for energy commodities;


•	Government regulation, including compliance with regulatory requirements and changes in market rules, rates, tariffs and environmental laws;


•	Changes in law, including judicial decisions;


•	Price mitigation strategies and other market structures employed by ISOs or RTOs that result in a failure to adequately and fairly compensate NRG's generation units;


•	NRG's ability to mitigate forced outage risk for units subject to capacity performance requirements in PJM, performance incentives in ISO-NE, and scarcity pricing in ERCOT;


•	NRG's ability to borrow funds and access capital markets, as well as NRG's substantial indebtedness and the possibility that NRG may incur additional indebtedness going forward;


•	NRG's ability to receive loan guarantees or cash grants to support development projects;


•	Operating and financial restrictions placed on NRG and its subsidiaries that are contained in the indentures governing NRG's outstanding notes, in NRG's Senior Credit Facility, and in debt and other agreements of certain of NRG subsidiaries and project affiliates generally;


•	Cyber terrorism and inadequate cybersecurity, or the occurrence of a catastrophic loss and the possibility that NRG may not have adequate insurance to cover losses resulting from such hazards or the inability of NRG's insurers to provide coverage;


•	NRG's ability to develop and build new power generation facilities, including new renewable projects;


•	NRG's ability to develop and innovate new products as retail and wholesale markets continue to change and evolve;


•	NRG's ability to implement its strategy of finding ways to meet the challenges of climate change, clean air and protecting natural resources while taking advantage of business opportunities;


•	NRG's ability to increase cash from operations through operational and commercial initiatives, corporate efficiencies, asset strategy, and a range of other programs throughout NRG to reduce costs or generate revenues;


•	NRG's ability to sell assets to NRG Yield, Inc. and to close drop-down transactions;


•	NRG's ability to achieve its strategy of regularly returning capital to stockholders;


•	NRG's ability to obtain and maintain retail market share;


•	NRG's ability to successfully evaluate investments and achieve intended financial results in new business and growth initiatives;


•	NRG's ability to engage in successful mergers and acquisitions activity;


•	NRG's ability to successfully integrate, realize cost savings and manage any acquired businesses; and


•	NRG's ability to develop and maintain successful partnering relationships.

Forward-looking statements speak only as of the date they were made, and NRG undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors that could cause NRG's actual results to differ materially from those contemplated in any forward-looking statements included in this Quarterly Report on Form 10-Q should not be construed as exhaustive.

GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:



2016 Form 10-K		NRG’s Annual Report on Form 10-K for the year ended December 31, 2016
Revolving Credit Facility		The Company’s $2.5 billion revolving credit facility, a component of the Senior Credit Facility. The revolving credit facility consists of $289 million of Tranche A Revolving Credit Facility, due 2018, and $2.2 billion of Tranche B Revolving Credit Facility, due 2021.
2023 Term Loan Facility		The Company's $1.9 billion term loan facility due 2023, a component of the Senior Credit Facility.
ARO		Asset Retirement Obligation
ASC		The FASB Accounting Standards Codification, which the FASB established as the source of authoritative GAAP
ASU		Accounting Standards Updates, which reflect updates to the ASC
Average realized prices		Volume-weighted average power prices, net of average fuel costs and reflecting the impact of settled hedges
BACT		Best Available Control Technology
BETM		Boston Energy Trading and Marketing LLC
BRA		Base Residual Auction
BTU		British Thermal Unit
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
CAISO		California Independent System Operator
CDD		Cooling Degree Day
CDWR		California Department of Water Resources
CEC		California Energy Commission
CenterPoint		CenterPoint Energy, Inc. and its subsidiaries, on and after August 31, 2002, and Reliant Energy, Incorporated and its subsidiaries prior to August 31, 2002
CFTC		U.S. Commodity Futures Trading Commission
COD		Commercial Operation Date
ComEd		Commonwealth Edison
Company		NRG Energy, Inc.
CPP		Clean Power Plan
CPUC		California Public Utilities Commission
CSAPR		Cross-State Air Pollution Rule
CVSR		California Valley Solar Ranch
D.C. Circuit		U.S. Court of Appeals for the District of Columbia Circuit
DGPV Holdco 1		NRG DGPV Holdco 1 LLC
DGPV Holdco 2		NRG DGPV Holdco 2 LLC
Distributed Solar		Solar power projects that primarily sell power to customers for usage on site, or are interconnected to sell power into a local distribution grid
DSI		Dry Sorbent Injection
Economic gross margin		Sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuels and other cost of sales
ELG		Effluent Limitations Guidelines
El Segundo Energy Center		NRG West Holdings LLC, the subsidiary of Natural Gas Repowering LLC, which owns the El Segundo Energy Center project
EME		Edison Mission Energy
Energy Plus Holdings		Energy Plus Holdings LLC
EPA		U.S. Environmental Protection Agency



EPC		Engineering, Procurement and Construction
ERCOT		Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
ESCO		Energy Service Company
ESP		Electrostatic Precipitator
ESPP		NRG Energy, Inc. Amended and Restated Employee Stock Purchase Plan
ESPS		Existing Source Performance Standards
Exchange Act		The Securities Exchange Act of 1934, as amended
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FTRs		Financial Transmission Rights
GAAP		Accounting principles generally accepted in the U.S.
GenConn		GenConn Energy LLC
GenOn		GenOn Energy, Inc.
GenOn Americas Generation		GenOn Americas Generation, LLC
GenOn Americas Generation Senior Notes		GenOn Americas Generation's $695 million outstanding unsecured senior notes consisting of $366 million of 8.5% senior notes due 2021 and $329 million of 9.125% senior notes due 2031
GenOn Mid-Atlantic		GenOn Mid-Atlantic, LLC and, except where the context indicates otherwise, its subsidiaries, which include the coal generation units at two generating facilities under operating leases
GenOn Senior Notes		GenOn's $1.8 billion outstanding unsecured senior notes consisting of $691 million of 7.875% senior notes due 2017, $649 million of 9.5% senior notes due 2018, and $490 million of 9.875% senior notes due 2020
GHG		Greenhouse Gas
GWh		Gigawatt Hour
HAP		Hazardous Air Pollutant
HDD		Heating Degree Day
Heat Rate		A measure of thermal efficiency computed by dividing the total BTU content of the fuel burned by the resulting kWhs generated. Heat rates can be expressed as either gross or net heat rates, depending whether the electricity output measured is gross or net generation and is generally expressed as BTU per net kWh
HLBV		Hypothetical Liquidation at Book Value
IASB		Independent Accounting Standards Board
IFRS		International Financial Reporting Standards
ILU		Illinois Union Insurance Company
ISO		Independent System Operator
ISO-NE		ISO New England Inc.
ITC		Investment Tax Credit
LIBOR		London Inter-Bank Offered Rate
LTIPs		Collectively, the NRG Long-Term Incentive Plan, as amended, and the NRG GenOn Long-Term Incentive Plan
Marsh Landing		NRG Marsh Landing, LLC (formerly known as GenOn Marsh Landing, LLC)
Mass Market		Residential and small commercial customers
MATS		Mercury and Air Toxics Standards promulgated by the EPA
MDth		Thousand Dekatherms
Midwest Generation		Midwest Generation, LLC
MISO		Midcontinent Independent System Operator, Inc.
MMBtu		Million British Thermal Units
MW		Megawatts
MWh		Saleable megawatt hour net of internal/parasitic load megawatt-hour



MWt		Megawatts Thermal Equivalent
NAAQS		National Ambient Air Quality Standards
NEPOOL		New England Power Pool
NERC		North American Electric Reliability Corporation
Net Exposure		Counterparty credit exposure to NRG, net of collateral
Net Generation		The net amount of electricity produced, expressed in kWhs or MWhs, that is the total amount of electricity generated (gross) minus the amount of electricity used during generation
NOL		Net Operating Loss
NO_x		Nitrogen Oxides
NPDES		National Pollutant Discharge Elimination System
NPNS		Normal Purchase Normal Sale
NRC		U.S. Nuclear Regulatory Commission
NRG		NRG Energy, Inc.
NRG Yield		Reporting segment including the projects owned by NRG Yield, Inc.
NRG Yield 2019 Convertible Notes		$345 million aggregate principal amount of 3.50% Convertible Senior Notes due 2019 issued by NRG Yield, Inc.
NRG Yield 2020 Convertible Notes		$287.5 million aggregate principal amount of 3.25% Convertible Notes due 2020 issued by NRG Yield, Inc.
NRG Yield, Inc.		NRG Yield, Inc., the owner of 53.4% of the economic interests of NRG Yield LLC with a controlling interest, and issuer of publicly held shares of Class A and Class C common stock
NSR		New Source Review
Nuclear Decommissioning Trust Fund		NRG's nuclear decommissioning trust fund assets, which are for the Company's portion of the decommissioning of the STP, units 1 & 2
NYAG		State of New York Office of Attorney General
NYISO		New York Independent System Operator
NYSPSC		New York State Public Service Commission
OCI/OCL		Other Comprehensive Income/(Loss)
Peaking		Units expected to satisfy demand requirements during the periods of greatest or peak load on the system
PER		Peak Energy Rent
PG&E		Pacific Gas and Electric Company
PJM		PJM Interconnection, LLC
PM		Particulate Matter
PPA		Power Purchase Agreement
PSD		Prevention of Significant Deterioration
PTC		Production Tax Credit
PUCT		Public Utility Commission of Texas
RAPA		Resource Adequacy Purchase Agreement
RCRA		Resource Conservation and Recovery Act of 1976
REMA		NRG REMA LLC, which leases a 100% interest in the Shawville generating facility and 16.7% and 16.5% interests in the Keystone and Conemaugh generating facilities, respectively
Repowering		Technologies utilized to replace, rebuild, or redevelop major portions of an existing electrical generating facility to achieve a substantial emissions reduction, increase facility capacity and improve system efficiency
Retail		Reporting segment that includes NRG's residential and small commercial businesses which go to market as Reliant, NRG and other brands owned by NRG, as well as Business Solutions
Revolving Credit Facility		Prior to June 30, 2016, the Company's $2.5 billion revolving credit facility due 2018, a component of the Senior Credit Facility. On June 30, 2016, the Company replaced the Senior Credit Facility, including the Revolving Credit Facility.
RGGI		Regional Greenhouse Gas Initiative
RMR		Reliability Must-Run



RPV Holdco		NRG RPV Holdco 1 LLC
RTO		Regional Transmission Organization
SCE		Southern California Edison
SDG&E		San Diego Gas & Electric Company
SEC		U.S. Securities and Exchange Commission
Securities Act		The Securities Act of 1933, as amended
Senior Credit Facility		Prior to June 30, 2016, the Company's senior secured facility, comprised of the Term Loan Facility and the Revolving Credit Facility. On June 30, 2016, the Company replaced the Senior Credit Facility.
Senior Notes		As of March 31, 2017, the Company’s $5.4 billion outstanding unsecured senior notes, consisting of $398 million of 7.625% senior notes due 2018, $207 million of 7.875% senior notes due 2021, $992 million of 6.25% senior notes due 2022, $869 million of 6.625% senior notes due 2023, $733 million of 6.25% senior notes due 2024, $1.0 billion of 7.25% senior notes due 2026 and $1.25 billion of 6.625% senior notes due 2027.
Seward		The Seward Power Generating Station, a 525 MW coal-fired facility in Pennsylvania
Shelby		The Shelby County Generating Station, a 352 MW natural gas-fired facility in Illinois
SO₂		Sulfur Dioxide
STP		South Texas Project — nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest
S&P		Standard & Poor's
TCPA		Telephone Consumer Protection Act
Term Loan Facility		Prior to June 30, 2016, the Company's $2.0 billion term loan facility due 2018, a component of the Senior Credit Facility.
TSA		Transportation Services Agreement
TWCC		Texas Westmoreland Coal Co.
U.S.		United States of America
U.S. DOE		U.S. Department of Energy
Utility Scale Solar		Solar power projects, typically 20 MW or greater in size (on an alternating current basis), that are interconnected into the transmission or distribution grid to sell power at a wholesale level
VaR		Value at Risk
VIE		Variable Interest Entity
Walnut Creek		NRG Walnut Creek, LLC, the operating subsidiary of WCEP Holdings, LLC, which owns the Walnut Creek project

PART I — FINANCIAL INFORMATION

ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three months ended March 31,
(In millions, except for per share amounts)	2017			2016
Operating Revenues
Total operating revenues	$	2,759		$	3,229
Operating Costs and Expenses
Cost of operations	2,125			2,194
Depreciation and amortization	300			313
Selling, general and administrative	272			252
Development activity expenses	17			26
Total operating costs and expenses	2,714			2,785
Gain on sale of assets	2			32
Operating Income	47			476
Other Income/(Expense)
Equity in earnings/(losses) of unconsolidated affiliates	5			(7		)
Impairment loss on investment	—			(146		)
Other income, net	12			18
(Loss)/gain on debt extinguishment, net	(2		)	11
Interest expense	(269		)	(284		)
Total other expense	(254		)	(408		)
(Loss)/Income Before Income Taxes	(207		)	68
Income tax (benefit)/expense	(4		)	21
Net (Loss)/Income	(203		)	47
Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interests	(40		)	(35		)
Net (Loss)/Income Attributable to NRG Energy, Inc.	(163		)	82
Dividends for preferred shares	—			5
(Loss)/Income Available for Common Stockholders	$	(163	)	$	77
(Loss)/Earnings per Share Attributable to NRG Energy, Inc. Common Stockholders
Weighted average number of common shares outstanding — basic	316			315
(Loss)/Earnings per Weighted Average Common Share — Basic	$	(0.52	)	$	0.24
Weighted average number of common shares outstanding — diluted	316			315
(Loss)/Earnings per Weighted Average Common Share — Diluted	$	(0.52	)	$	0.24
Dividends Per Common Share	$	0.03		$	0.15

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

(Unaudited)



	Three months ended March 31,
	2017			2016
	(In millions)
Net (loss)/income	$	(203	)	$	47
Other comprehensive income/(loss), net of tax
Unrealized income/(loss) on derivatives, net of income tax expense of $1, and $1	4			(32		)
Foreign currency translation adjustments, net of income tax expense of $0, and $0	7			6
Available-for-sale securities, net of income tax expense of $0, and $0	—			3
Defined benefit plans, net of income tax expense of $0, and $0	—			1
Other comprehensive income/(loss)	11			(22		)
Comprehensive (loss)/income	(192		)	25
Less: Comprehensive loss attributable to noncontrolling interest and redeemable noncontrolling interests	(39		)	(52		)
Comprehensive (loss)/income attributable to NRG Energy, Inc.	(153		)	77
Dividends for preferred shares	—			5
Comprehensive (loss)/income available for common stockholders	$	(153	)	$	72

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS



	March 31, 2017			December 31, 2016
(In millions, except shares)	(unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	1,513		$	1,973
Funds deposited by counterparties	3			2
Restricted cash	397			446
Accounts receivable, net	974			1,166
Inventory	1,140			1,111
Derivative instruments	682			1,062
Cash collateral paid in support of energy risk management activities	277			203
Current assets held-for-sale	—			9
Prepayments and other current assets	454			423
Total current assets	5,440			6,395
Property, plant and equipment, net	17,942			17,912
Other Assets
Equity investments in affiliates	1,148			1,120
Notes receivable, less current portion	13			17
Goodwill	662			662
Intangible assets, net	1,957			2,036
Nuclear decommissioning trust fund	627			610
Derivative instruments	226			189
Deferred income taxes	223			225
Non-current assets held-for-sale	10			10
Other non-current assets	1,172			1,179
Total other assets	6,038			6,048
Total Assets	$	29,420		$	30,355
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	1,688		$	1,220
Accounts payable	872			895
Derivative instruments	747			1,084
Cash collateral received in support of energy risk management activities	3			2
Accrued expenses and other current liabilities	887			1,181
Total current liabilities	4,197			4,382
Other Liabilities
Long-term debt and capital leases	17,672			18,006
Nuclear decommissioning reserve	291			287
Nuclear decommissioning trust liability	352			339
Deferred income taxes	20			20
Derivative instruments	315			294
Out-of-market contracts, net	1,017			1,040
Non-current liabilities held-for-sale	12			12
Other non-current liabilities	1,487			1,483
Total non-current liabilities	21,166			21,481
Total Liabilities	25,363			25,863
Redeemable noncontrolling interest in subsidiaries	44			46
Commitments and Contingencies
Stockholders’ Equity
Common stock	4			4
Additional paid-in capital	8,375			8,358
Retained deficit	(4,238		)	(3,787		)
Less treasury stock, at cost — 101,858,284 and 102,140,814 shares, respectively	(2,392		)	(2,399		)
Accumulated other comprehensive loss	(124		)	(135		)
Noncontrolling interest	2,388			2,405
Total Stockholders’ Equity	4,013			4,446
Total Liabilities and Stockholders’ Equity	$	29,420		$	30,355

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Three months ended March 31,
	2017			2016
	(In millions)
Cash Flows from Operating Activities
Net (loss)/income	$	(203	)	$	47
Adjustments to reconcile net (loss)/income to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates	8			17
Depreciation and amortization	300			313
Provision for bad debts	9			10
Amortization of nuclear fuel	12			13
Amortization of financing costs and debt discount/premiums	1			1
Adjustment for debt extinguishment	—			(11		)
Amortization of intangibles and out-of-market contracts	10			26
Amortization of unearned equity compensation	8			8
Impairment losses	—			146
Changes in deferred income taxes and liability for uncertain tax benefits	1			(25		)
Changes in nuclear decommissioning trust liability	36			9
Changes in derivative instruments	25			(50		)
Changes in collateral posted in support of risk management activities	(74		)	156
Proceeds from sale of emission allowances	—			47
Gain on sale of assets	(2		)	(32		)
Cash used by changes in other working capital	(199		)	(121		)
Net Cash (Used)/Provided by Operating Activities	(68		)	554
Cash Flows from Investing Activities
Acquisitions of businesses, net of cash acquired	(3		)	(6		)
Capital expenditures	(268		)	(279		)
Decrease/(increase)in restricted cash, net	13			(12		)
Decrease in restricted cash to support equity requirements for U.S. DOE funded projects	36			39
Decrease in notes receivable	4			1
Purchases of emission allowances	(9		)	(12		)
Proceeds from sale of emission allowances	11			7
Investments in nuclear decommissioning trust fund securities	(153		)	(200		)
Proceeds from the sale of nuclear decommissioning trust fund securities	117			191
Proceeds from renewable energy grants and state rebates	—			8
Proceeds from sale of assets, net of cash disposed of	14			120
Investments in unconsolidated affiliates	(12		)	(4		)
Other	18			4
Net Cash Used by Investing Activities	(232		)	(143		)
Cash Flows from Financing Activities
Payment of dividends to common and preferred stockholders	(9		)	(48		)
Net receipts from settlement of acquired derivatives that include financing elements	1			39
Proceeds from issuance of long-term debt	192			61
Payments for short and long-term debt	(177		)	(316		)
Payment for credit support in long-term deposits	(130		)	—
Proceeds from draw on revolving credit facility for long-term deposits	125			—
Increase in long-term deposits	(125		)	—
Contributions to, net of distributions from, noncontrolling interest in subsidiaries	(5		)	10
Payment of debt issuance costs	(15		)	—
Other - contingent consideration	(10		)	(10		)
Net Cash Used by Financing Activities	(153		)	(264		)
Effect of exchange rate changes on cash and cash equivalents	(7		)	(6		)
Net (Decrease)/ Increase in Cash and Cash Equivalents	(460		)	141
Cash and Cash Equivalents at Beginning of Period	1,973			1,518
Cash and Cash Equivalents at End of Period	$	1,513		$	1,659

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 — Basis of Presentation

NRG Energy, Inc., or NRG or the Company, is a leading integrated power company built on the strength of the nation's largest and most diverse competitive electric generation portfolio and leading retail electricity platform. NRG aims to create a sustainable energy future by producing, selling and delivering electricity and related products and services in major competitive power markets in the U.S. in a manner that delivers value to all of NRG's stakeholders. The Company owns and operates approximately 46,000 MW of generation; engages in the trading of wholesale energy, capacity and related products; transacts in and trades fuel and transportation services; and directly sells energy, services, and innovative, sustainable products and services to retail customers under the names “NRG”, "Reliant" and other retail brand names owned by NRG.

The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with the SEC's regulations for interim financial information and with the instructions to Form 10-Q. Accordingly, they do not include all of the information and notes required by generally accepted accounting principles for complete financial statements. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to the consolidated financial statements in the Company's 2016 Form 10-K. Interim results are not necessarily indicative of results for a full year.

In the opinion of management, the accompanying unaudited interim condensed consolidated financial statements contain all material adjustments consisting of normal and recurring accruals necessary to present fairly the Company's consolidated financial position as of March 31, 2017, and the results of operations, comprehensive income/(loss) and cash flows for the three months ended March 31, 2017 and 2016.

GenOn Liquidity and Ability to Continue as a Going Concern

As of March 31, 2017, GenOn had cash and cash equivalents of $885 million, of which $305 million and $82 million were held by GenOn Mid-Atlantic and REMA, respectively. Under their respective operating leases, GenOn Mid-Atlantic and REMA are not permitted to make any distributions and other restricted payments unless: (a) they satisfy the fixed charge coverage ratio for the most recently ended period for four fiscal quarters; (b) they are projected to satisfy the fixed charge coverage ratio for each of the two following periods of four fiscal quarters, commencing with the fiscal quarter in which such payment is proposed to be made; and (c) no significant lease default or event of default has occurred and is continuing. Additionally, GenOn Mid-Atlantic and REMA must be in compliance with the requirement to provide credit support to the owner lessors securing their obligations to pay scheduled rent under their respective leases. As a result, GenOn Mid-Atlantic has not been able to make distributions of cash and certain other restricted payments since the quarter ended March 31, 2014 which was the last quarterly period for which GenOn Mid-Atlantic satisfied the conditions under its operating agreement. REMA has not satisfied the conditions under its operating agreement to make distributions of cash and certain other restricted payments since 2009.

As disclosed in Note 8, Debt and Capital Leases, $691 million of GenOn's Senior Notes, excluding $4 million of associated premiums, are current within the GenOn consolidated balance sheet as of March 31, 2017 and are due on June 15, 2017. GenOn's future profitability continues to be adversely affected by (i) a sustained decline in natural gas prices and its resulting effect on wholesale power prices and capacity prices, and (ii) the inability of GenOn Mid-Atlantic and REMA to make distributions of cash and certain other restricted payments to GenOn. GenOn is currently considering all options available to it, including negotiations with creditors and lessors, refinancing the GenOn Senior Notes, potential sales of certain generating assets as well as the possibility for a need to file for protection under Chapter 11 of the U.S. Bankruptcy Code. If GenOn is unable to enter into a settlement with its creditors, refinance the senior notes or otherwise raise or generate sufficient capital, GenOn is not expected to have sufficient liquidity to repay the GenOn Senior Notes due in June 2017. Pending resolution, there is substantial doubt about GenOn's ability to continue as a going concern. As a result of the substantial doubt about GenOn’s ability to continue as a going concern, along with additional factors, there is substantial doubt about certain of GenOn’s subsidiaries’ ability to continue as a going concern.

During 2016, GenOn appointed two independent directors, retained advisors and established a separate audit committee as part of this process. On April 7, 2017, GenOn also appointed a new dedicated chief executive officer, effective immediately. Any resolution may have a material impact on the NRG's statement of operations, cash flows and financial position.

NRG, GenOn's parent company, has no obligation to provide any financial support to GenOn other than under the secured intercompany revolving credit agreement between NRG and GenOn and NRG Americas. As of March 31, 2017, $214 million was available to be used by GenOn under the $500 million revolving credit agreement. As controlled group members, ERISA requires that NRG and GenOn are jointly and severally liable for the NRG Pension Plan for Bargained Employees and the NRG Pension Plan, including the pension liabilities associated with GenOn employees.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates.

Reclassifications

Certain prior year amounts have been reclassified for comparative purposes. The reclassifications did not affect results from operations, net assets or cash flows.

Note 2 — Summary of Significant Accounting Policies

Other Balance Sheet Information

The following table presents the allowance for doubtful accounts included in accounts receivable, net; accumulated depreciation included in property, plant and equipment, net; accumulated amortization included in intangible assets, net and accumulated amortization included in out-of-market contracts, net:



	March 31, 2017		December 31, 2016
	(In millions)
Accounts receivable allowance for doubtful accounts	$	33	$	30
Property, plant and equipment accumulated depreciation	6,602		6,314
Intangible assets accumulated amortization	1,724		1,775
Out-of-market contracts accumulated amortization	666		765

Noncontrolling Interest

The following table reflects the changes in NRG's noncontrolling interest balance:



	(In millions)
Balance as of December 31, 2016	$	2,405
Dividends paid to NRG Yield, Inc. public shareholders	(25		)
Comprehensive loss attributable to noncontrolling interest	(22		)
Distributions to noncontrolling interest	(21		)
Contributions from noncontrolling interest	48
Sale of assets to NRG Yield, Inc.	3
Balance as of March 31, 2017	$	2,388

Redeemable Noncontrolling Interest

The following table reflects the changes in the Company's redeemable noncontrolling interest balance:



	(In millions)
Balance as of December 31, 2016	$	46
Contributions from redeemable noncontrolling interest	15
Comprehensive loss attributable to redeemable noncontrolling interest	(17		)
Balance as of March 31, 2017	$	44

Recent Accounting Developments - Guidance Adopted in 2017

ASU 2016-16 — In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740), Intra-Entity Transfers of Assets Other Than Inventory, or ASU No. 2016-16. Current GAAP prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party which has resulted in diversity in practice and increased complexity within financial reporting. The amendments of ASU No. 2016-16 would require an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The Company adopted the guidance in ASU No. 2016-16 effective January 1, 2017. In connection with the adoption of the standard, the Company recorded a reduction to non-current assets of $267 million with a corresponding reduction to cumulative retained deficit.

ASU 2016-15 — In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230), Classification of Certain Cash Receipts and Cash Payments, or ASU No. 2016-15. The amendments of ASU No. 2016-15 were issued to address eight specific cash flow issues for which stakeholders have indicated to the FASB that a diversity in practice existed in how entities were presenting and classifying these items in the statement of cash flows. The issues addressed by ASU No. 2016-15 include but are not limited to the classification of debt prepayment and debt extinguishment costs, payments made for contingent consideration for a business combination, proceeds from the settlement of insurance proceeds, distributions received from equity method investees and separately identifiable cash flows and the application of the predominance principle. The Company adopted the guidance in ASU No. 2016-15 effective January 1, 2017. While the Company has applied this guidance retrospectively, the adoption of the standard did not have an impact on the statement of cash flow for the three months ended March 31, 2016.

ASU 2016-09 — In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718), or ASU No. 2016-09. The amendments focused on simplification specifically with regard to share-based payment transactions, including income tax consequences, classification of awards as equity or liabilities and classification on the statement of cash flows. The Company adopted the guidance in ASU No. 2016-09 effective January 1, 2017 with no material adjustments recorded to the consolidated balance sheet.

Recent Accounting Developments - Guidance Not Yet Adopted

ASU 2017-07 — In March 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (Topic 715), Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, or ASU No. 2017-07. Current GAAP does not indicate where the amount of net benefit cost should be presented in an entity’s income statement and does not require entities to disclose the amount of net benefit cost that is included in the income statement. The amendments of ASU No. 2017-07 require an entity to report the service cost component of net benefit costs in the same line item as other compensation costs arising from services rendered by the related employees during the applicable service period. The other components of net benefit cost are required to be presented separately from the service cost component and outside the subtotal of income from operations. Further, ASU No. 2017-07 prescribes that only the service cost component of net benefit costs is eligible for capitalization. The amendments of ASU No. 2017-07 are effective for fiscal years beginning after December 15, 2017, including interim periods therein. Early adoption is permitted and must be applied on a retrospective basis, except for the amendments regarding the capitalization of the service cost component, which must be applied prospectively. The Company is currently assessing the impact that the adoption of ASU No. 2017-07 will have on its results of operations, cash flows, and statement of financial position.

ASU 2016-18 — In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topic 230), Restricted Cash, or ASU No. 2016-18. The amendments of ASU No. 2016-18 require an entity to include amounts generally described as restricted cash and restricted cash equivalents, including funds deposited by counterparties with cash and cash equivalents when reconciling the beginning of period and end of period total amounts on the statement of cash flows. The amendments of ASU No. 2016-18 are effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. Early adoption is permitted and the adoption of ASU No. 2016-18 will be applied retrospectively. The Company calculated the impact of ASU No. 2016-18 on the statement of cash flows to be a decrease of cash flows used by operating activities of $1 million and an increase of cash flows used by investing activities of $49 million for the three months ended March 31, 2017, and a decrease of cash flows provided by operating activities of $5 million and a decrease of cash flows used by investing activities of $27 million for the three months ended March 31, 2016.

ASU 2016-02 — In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), or Topic 842, with the objective to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and to improve financial reporting by expanding the related disclosures. The guidance in Topic 842 provides that a lessee that may have previously accounted for a lease as an operating lease under current GAAP should recognize the assets and liabilities that arise from a lease on the balance sheet. In addition, Topic 842 expands the required quantitative and qualitative disclosures with regards to lease arrangements. The Company expects to adopt the standard effective January 1, 2019 utilizing the required modified retrospective approach for the earliest period presented. The Company expects to elect certain of the practical expedients permitted, including the expedient that permits the Company to retain its existing lease assessment and classification. The Company is currently working through an adoption plan which includes the evaluation of lease contracts compared to the new standard. While the Company is currently evaluating the impact the new guidance will have on its financial position and results of operations, the Company expects to recognize lease liabilities and right of use assets. The extent of the increase to assets and liabilities associated with these amounts remains to be determined pending the Company’s review of its existing lease contracts and service contracts which may contain embedded leases. As this review is still in process, it is currently not practicable to quantify the impact of adopting the ASU at this time.

ASU 2014-09 — In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), or Topic 606, which was further amended through various updates issued by the FASB thereafter. The amendments of Topic 606 completed the joint effort between the FASB and the IASB, to develop a common revenue standard for GAAP and IFRS, and to improve financial reporting. The guidance under Topic 606 provides that an entity should recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled to in exchange for the goods or services provided and establishes a five step model to be applied by an entity in evaluating its contracts with customers. The Company expects to adopt the standard effective January 1, 2018 and apply the guidance retrospectively to contracts at the date of adoption. The Company will recognize the cumulative effect of applying Topic 606 at the date of initial application, as prescribed under the modified retrospective transition method. The Company also expects to elect the practical expedient available under Topic 606 for measuring progress toward complete satisfaction of a performance obligation and for disclosure requirements of remaining performance obligations. The practical expedient allows an entity to recognize revenue in the amount to which the entity has the right to invoice such that the entity has a right to the consideration in an amount that

corresponds directly with the value to the customer for performance completed to date by the entity. The Company continues to assess the new standard with a focus on identifying the performance obligations included within its revenue arrangements with customers and evaluating the Company’s methods of estimating the amount and timing of variable consideration. Based on the assessment to date, the Company is currently evaluating the impact of the new standard on the Company’s results of operations, financial position or cash flows.

Note 3 — Dispositions

The Company completed the following transfer of assets under common control.

On March 27, 2017, the Company sold to NRG Yield, Inc.: (i) a 16% interest in the Agua Caliente solar project, representing ownership of approximately 46 net MW of capacity and (ii) NRG's interests in seven utility-scale solar projects located in Utah representing 265 net MW of capacity, which have reached commercial operations. NRG Yield Inc. paid cash consideration of $130 million, plus $1 million in working capital adjustments, and assumed non-recourse debt of approximately $328 million.

Note 4 — Fair Value of Financial Instruments

This footnote should be read in conjunction with the complete description under Note 4, Fair Value of Financial Instruments, to the Company's 2016 Form 10-K.

For cash and cash equivalents, funds deposited by counterparties, accounts and other receivables, accounts payable, restricted cash, and cash collateral paid and received in support of energy risk management activities, the carrying amount approximates fair value because of the short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy.

The estimated carrying amounts and fair values of NRG's recorded financial instruments not carried at fair market value are as follows:



	As of March 31, 2017				As of December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Assets:
Notes receivable^(a)	$	30	$	30	$	34	$	34
Liabilities:
Long-term debt, including current portion^(b)	19,539		18,726		19,406		18,566

(a) Includes the current portion of notes receivable which is recorded in prepayments and other current assets on the Company's consolidated balance sheets.

(b) Excludes deferred financing costs, which are recorded as a reduction to long-term debt on the Company's consolidated balance sheets.

The fair value of the Company's publicly-traded long-term debt is based on quoted market prices and is classified as Level 2 within the fair value hierarchy. The fair value of debt securities, non-publicly traded long-term debt and certain notes receivable of the Company are based on expected future cash flows discounted at market interest rates, or current interest rates for similar instruments with equivalent credit quality and are classified as Level 3 within the fair value hierarchy. The following table presents the level within the fair value hierarchy for long-term debt, including current portion as of March 31, 2017 and December 31, 2016:



	As of March 31, 2017				As of December 31, 2016
	Level 2		Level 3		Level 2		Level 3
	(In millions)
Long-term debt, including current portion	$	11,190	$	7,536	$	11,055	$	7,511

Recurring Fair Value Measurements

Debt securities, equity securities, and trust fund investments, which are comprised of various U.S. debt and equity securities, and derivative assets and liabilities, are carried at fair market value.

The following tables present assets and liabilities measured and recorded at fair value on the Company's condensed consolidated balance sheets on a recurring basis and their level within the fair value hierarchy:



	As of March 31, 2017
	Fair Value
(In millions)	Level 1		Level 2		Level 3		Total
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities	$	—	$	—	$	18	$	18
Available-for-sale securities	4		—		—		4
Other ^(a)	8		—		—		8
Nuclear trust fund investments:
Cash and cash equivalents	16		—		—		16
U.S. government and federal agency obligations	55		1		—		56
Federal agency mortgage-backed securities	—		67		—		67
Commercial mortgage-backed securities	—		17		—		17
Corporate debt securities	—		100		—		100
Equity securities	309		—		58		367
Foreign government fixed income securities	—		4		—		4
Other trust fund investments:
U.S. government and federal agency obligations	1		—		—		1
Derivative assets:
Commodity contracts	245		534		79		858
Interest rate contracts	—		50		—		50
Total assets	$	638	$	773	$	155	$	1,566
Derivative liabilities:
Commodity contracts	307		541		137		985
Interest rate contracts	—		77		—		77
Total liabilities	$	307	$	618	$	137	$	1,062

(a) Consists primarily of mutual funds held in a Rabbi Trust for non-qualified deferred compensation plans for certain former employees.



	As of December 31, 2016
	Fair Value
(In millions)	Level 1		Level 2		Level 3		Total
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities	$	—	$	—	$	17	$	17
Available-for-sale securities	10		—		—		10
Other ^(a)	10		—		—		10
Nuclear trust fund investments:
Cash and cash equivalents	25		—		—		25
U.S. government and federal agency obligations	72		1		—		73
Federal agency mortgage-backed securities	—		62		—		62
Commercial mortgage-backed securities	—		17		—		17
Corporate debt securities	—		84		—		84
Equity securities	292		—		54		346
Foreign government fixed income securities	—		3		—		3
Other trust fund investments:
U.S. government and federal agency obligations	1		—		—		1
Derivative assets:
Commodity contracts	559		551		92		1,202
Interest rate contracts	—		49		—		49
Total assets	$	969	$	767	$	163	$	1,899
Derivative liabilities:
Commodity contracts	494		635		161		1,290
Interest rate contracts	—		88		—		88
Total liabilities	$	494	$	723	$	161	$	1,378

(a) Primarily consists of mutual funds held in rabbi trusts for non-qualified deferred compensation plans for certain former employees and a total return swap that does not meet the definition of a derivative.

There were no transfers during the three months ended March 31, 2017 and 2016 between Levels 1 and 2. The following tables reconcile, for the three months ended March 31, 2017 and 2016, the beginning and ending balances for financial instruments that are recognized at fair value in the condensed consolidated financial statements, at least annually, using significant unobservable inputs:



	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Three months ended March 31, 2017
(In millions)	Debt Securities		Trust Fund Investments		Derivatives^(a)			Total
Beginning balance	$	17	$	54	$	(69	)	$	2
Total gains — realized/unrealized:
Included in earnings	1		—		6			7
Included in nuclear decommissioning obligation	—		4		—			4
Purchases	—		—		3			3
Transfers into Level 3 ^(b)	—		—		(8		)	(8		)
Transfers out of Level 3 ^(b)	—		—		10			10
Ending balance as of March 31, 2017	$	18	$	58	$	(58	)	$	18
Losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of March 31, 2017	$	—	$	—	$	(15	)	$	(15	)


(a)	Consists of derivative assets and liabilities, net.


(b)	Transfers into/out of Level 3 are related to the availability of external broker quotes and are valued as of the end of the reporting period. All transfers in/out are with Level 2.



	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Three months ended March 31, 2016
(In millions)	Debt Securities		Trust Fund Investments			Derivatives^(a)			Total
Beginning balance	$	17	$	54		$	(33	)	$	38
Total losses — realized/unrealized:
Included in earnings	—		—			(17		)	(17		)
Included in nuclear decommissioning obligations	—		(2		)	—			(2		)
Purchases	—		—			5			5
Transfers into Level 3 ^(b)	—		—			27			27
Transfers out of Level 3 ^(b)	—		—			1			1
Ending balance as of March 31, 2016	$	17	$	52		$	(17	)	$	52
Losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of March 31, 2016	$	—	$	—		$	(24	)	$	(24	)


(a)	Consists of derivative assets and liabilities, net.


(b)	Transfers into/out of Level 3 are related to the availability of external broker quotes and are valued as of the end of the reporting period. All transfers in/out are with Level 2.

Derivative Fair Value Measurements

A portion of NRG's contracts are exchange-traded contracts with readily available quoted market prices. A majority of NRG's contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. The remainder of the assets and liabilities represent contracts for which external sources or observable market quotes are not available for the whole term or for certain delivery months or the contracts are retail and load following power contracts. These contracts are valued using various valuation techniques including but not limited to internal models that apply fundamental analysis of the market and corroboration with similar markets. As of March 31, 2017, contracts valued with prices provided by models and other valuation techniques make up 9% of the total derivative assets and 13% of the total derivative liabilities.

NRG's significant positions classified as Level 3 include physical and financial power and physical coal executed in illiquid markets as well as financial transmission rights, or FTRs. The significant unobservable inputs used in developing fair value include illiquid power and coal location pricing which is derived as a basis to liquid locations. The basis spread is based on observable market data when available or derived from historic prices and forward market prices from similar observable markets when not available. For FTRs, NRG uses the most recent auction prices to derive the fair value.

The following tables quantify the significant unobservable inputs used in developing the fair value of the Company's Level 3 positions as of March 31, 2017 and December 31, 2016:



	Significant Unobservable Inputs
	March 31, 2017
	Fair Value						Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average
	(In millions)
Power Contracts	$	43	$	97	Discounted Cash Flow	Forward Market Price (per MWh)	$	12		$	88	$	26
Coal Contracts	—		1		Discounted Cash Flow	Forward Market Price (per ton)	42			48		44
FTRs	36		39		Discounted Cash Flow	Auction Prices (per MWh)	(17		)	19		—
	$	79	$	137



	Significant Unobservable Inputs
	December 31, 2016
	Fair Value						Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average
	(In millions)
Power Contracts	$	40	$	107	Discounted Cash Flow	Forward Market Price (per MWh)	$	11		$	104	$	31
Coal Contracts	—		1		Discounted Cash Flow	Forward Market Price (per ton)	42			51		45
FTRs	52		53		Discounted Cash Flow	Auction Prices (per MWh)	(22		)	17		—
	$	92	$	161

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of March 31, 2017 and December 31, 2016:



Significant Unobservable Input	Position	Change In Input	Impact on Fair Value Measurement
Forward Market Price Power/Coal	Buy	Increase/(Decrease)	Higher/(Lower)
Forward Market Price Power/Coal	Sell	Increase/(Decrease)	Lower/(Higher)
FTR Prices	Buy	Increase/(Decrease)	Higher/(Lower)
FTR Prices	Sell	Increase/(Decrease)	Lower/(Higher)

The fair value of each contract is discounted using a risk-free interest rate. In addition, the Company applies a credit reserve to reflect credit risk, which is calculated based on published default probabilities. As of March 31, 2017, the credit reserve resulted in a $2 million decrease in fair value in operating revenue and cost of operations. As of December 31, 2016, the credit reserve resulted in an $11 million decrease in fair value in operating revenue and cost of operations.

Concentration of Credit Risk

In addition to the credit risk discussion as disclosed in Note 2, Summary of Significant Accounting Policies, to the Company's 2016 Form 10-K, the following is a discussion of the concentration of credit risk for the Company's contractual obligations. Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. NRG is exposed to counterparty credit risk through various activities including wholesale sales, fuel purchases and retail supply arrangements, and retail customer credit risk through its retail load activities.

Counterparty Credit Risk

The Company's counterparty credit risk policies are disclosed in its 2016 Form 10-K. As of March 31, 2017, the Company's counterparty credit exposure, excluding credit risk exposure under certain long term agreements, was $191 million with net exposure of $188 million. NRG held collateral (cash and letters of credit) against those positions of $3 million. Approximately 76% of the Company's exposure before collateral is expected to roll off by the end of 2018. Counterparty credit exposure is valued through observable market quotes and discounted at a risk free interest rate. The following tables highlight net counterparty credit exposure by industry sector and by counterparty credit quality. Net counterparty credit exposure is defined as the aggregate net asset position for NRG with counterparties where netting is permitted under the enabling agreement and includes all cash flow, mark-to-market and NPNS, and non-derivative transactions. The exposure is shown net of collateral held, and includes amounts net of receivables or payables.



	Net Exposure ^{(a) (b)}
Category by Industry Sector	(% of Total)
Utilities, energy merchants, marketers and other	91	%
Financial institutions	9
Total as of March 31, 2017	100	%



	Net Exposure ^{(a) (b)}
Category by Counterparty Credit Quality	(% of Total)
Investment grade	87	%
Non-Investment grade/Non-Rated	13
Total as of March 31, 2017	100	%


(a)	Counterparty credit exposure excludes uranium and coal transportation contracts because of the unavailability of market prices.


(b)	The figures in the tables above exclude potential counterparty credit exposure related to RTOs, ISOs, registered commodity exchanges and certain long term contracts.

NRG has counterparty credit risk exposure to certain counterparties, each of which represent more than 10% of total net exposure discussed above. The aggregate of such counterparties' exposure was $72 million as of March 31, 2017. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality, diversification and term of the exposure in the portfolio, NRG does not anticipate a material impact on the Company's financial position or results of operations from nonperformance by any of NRG's counterparties.

RTOs and ISOs

The Company participates in the organized markets of CAISO, ERCOT, ISO-NE, MISO, NYISO and PJM, known as RTOs or ISOs. Trading in these markets is approved by FERC, or in the case of ERCOT, approved by the PUCT and includes credit policies that, under certain circumstances, require that losses arising from the default of one member on spot market transactions be shared by the remaining participants. As a result, the counterparty credit risk to these markets is limited to NRG’s share of overall market and are excluded from the above exposures.

Exchange Traded Transactions

The Company enters into commodity transactions on registered exchanges, notably ICE and NYMEX. These clearinghouses act as the counterparty and transactions are subject to extensive collateral and margining requirements. As a result, these commodity transactions have limited counterparty credit risk.

Long Term Contracts

Counterparty credit exposure described above excludes credit risk exposure under certain long term agreements, including California tolling agreements, Gulf Coast load obligations, and wind and solar PPAs. As external sources or observable market quotes are not available to estimate such exposure, the Company estimates its credit exposure for these contracts based on various techniques including, but not limited to, internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Based on these valuation techniques, as of March 31, 2017, aggregate credit risk exposure managed by NRG to these counterparties was approximately $4.4 billion, including $2.9 billion related to assets of NRG Yield, Inc., for the next five years. This amount excludes potential credit exposures for projects with long-term PPAs that have not reached commercial operations. The majority of these power contracts are with utilities or public power entities with strong credit quality and public utility commission or other regulatory support. However, such regulated utility counterparties can be impacted by changes in government regulations, which NRG is unable to predict.

Retail Customer Credit Risk

NRG is exposed to retail credit risk through the Company's retail electricity providers, which serve commercial, industrial and governmental/institutional customers and the Mass market. Retail credit risk results when a customer fails to pay for products or services rendered. The losses may result from both nonpayment of customer accounts receivable and the loss of in-the-money forward value. NRG manages retail credit risk through the use of established credit policies that include monitoring of the portfolio, and the use of credit mitigation measures such as deposits or prepayment arrangements.

As of March 31, 2017, the Company believes its retail customer credit exposure was diversified across many customers and various industries, as well as government entities.

Note 5 — Nuclear Decommissioning Trust Fund

This footnote should be read in conjunction with the complete description under Note 6, Nuclear Decommissioning Trust Fund, to the Company's 2016 Form 10-K.

NRG's Nuclear Decommissioning Trust Fund assets are comprised of securities classified as available-for-sale and recorded at fair value based on actively quoted market prices. NRG accounts for the Nuclear Decommissioning Trust Fund in accordance with ASC 980, Regulated Operations, because the Company's nuclear decommissioning activities are subject to approval by the PUCT with regulated rates that are designed to recover all decommissioning costs and that can be charged to and collected from the ratepayers per PUCT mandate. Since the Company is in compliance with PUCT rules and regulations regarding decommissioning trusts and the cost of decommissioning is the responsibility of the Texas ratepayers, not NRG, all realized and unrealized gains or losses (including other-than-temporary impairments) related to the Nuclear Decommissioning Trust Fund are recorded to nuclear decommissioning trust liability and are not included in net income or accumulated OCI, consistent with regulatory treatment.

The following table summarizes the aggregate fair values and unrealized gains and losses (including other-than-temporary impairments) for the securities held in the trust funds, as well as information about the contractual maturities of those securities.



	As of March 31, 2017							As of December 31, 2016
(In millions, except otherwise noted)	Fair Value		Unrealized Gains		Unrealized Losses		Weighted-average Maturities (In years)	Fair Value		Unrealized Gains		Unrealized Losses		Weighted-average Maturities (In years)
Cash and cash equivalents	$	16	$	—	$	—	—	$	25	$	—	$	—	—
U.S. government and federal agency obligations	56		2		—		9	73		1		—		11
Federal agency mortgage-backed securities	67		1		1		24	62		1		1		25
Commercial mortgage-backed securities	17		—		1		26	17		—		1		26
Corporate debt securities	100		1		1		10	84		1		2		11
Equity securities	367		233		—		—	346		214		—		—
Foreign government fixed income securities	4		—		—		7	3		—		—		9
Total	$	627	$	237	$	3		$	610	$	217	$	4

The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from these sales. The cost of securities sold is determined on the specific identification method.



	Three months ended March 31,
	2017		2016
	(In millions)
Realized gains	$	2	$	4
Realized losses	2		3
Proceeds from sale of securities	117		191

Note 6 — Accounting for Derivative Instruments and Hedging Activities

This footnote should be read in conjunction with the complete description under Note 5, Accounting for Derivative Instruments and Hedging Activities, to the Company's 2016 Form 10-K.

Energy-Related Commodities

As of March 31, 2017, NRG had energy-related derivative instruments extending through 2031. The Company marks these derivatives to market through the statement of operations.

Interest Rate Swaps

NRG is exposed to changes in interest rates through the Company's issuance of variable rate debt. In order to manage the Company's interest rate risk, NRG enters into interest rate swap agreements. As of March 31, 2017, the Company had interest rate derivative instruments on recourse debt extending through 2021, which are not designated as cash flow hedges. The Company had interest rate swaps on non-recourse debt extending through 2036, most of which are designated as cash flow hedges.

Volumetric Underlying Derivative Transactions

The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by category, excluding those derivatives that qualified for the NPNS exception, as of March 31, 2017 and December 31, 2016. Option contracts are reflected using delta volume. Delta volume equals the notional volume of an option adjusted for the probability that the option will be in-the-money at its expiration date.



		Total Volume
		March 31, 2017			December 31, 2016
Category	Units	(In millions)
Emissions	Short Ton	(4		)	—
Coal	Short Ton	32			41
Natural Gas	MMBtu	162			85
Oil	Barrel	—			1
Power	MWh	(12		)	(28		)
Capacity	MW/Day	(1		)	(1		)
Interest	Dollars	$	3,369		$	3,429
Equity	Shares	1			1

The increase in the natural gas position was primarily the result of additional generation and retail hedge positions.

Fair Value of Derivative Instruments

The following table summarizes the fair value within the derivative instrument valuation on the balance sheets:



	Fair Value
	Derivative Assets				Derivative Liabilities
	March 31, 2017		December 31, 2016		March 31, 2017		December 31, 2016
	(In millions)
Derivatives designated as cash flow hedges:
Interest rate contracts current	$	—	$	—	$	22	$	28
Interest rate contracts long-term	12		12		31		41
Total derivatives designated as cash flow hedges	12		12		53		69
Derivatives not designated as cash flow hedges:
Interest rate contracts current	3		—		8		7
Interest rate contracts long-term	35		37		16		12
Commodity contracts current	679		1,062		717		1,049
Commodity contracts long-term	179		140		268		241
Total derivatives not designated as cash flow hedges	896		1,239		1,009		1,309
Total derivatives	$	908	$	1,251	$	1,062	$	1,378

The Company has elected to present derivative assets and liabilities on the balance sheet on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. In addition, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. The following table summarizes the offsetting of derivatives by counterparty master agreement level and collateral received or paid:



	Gross Amounts Not Offset in the Statement of Financial Position
	Gross Amounts of Recognized Assets / Liabilities			Derivative Instruments			Cash Collateral (Held) / Posted			Net Amount
As of March 31, 2017	(In millions)
Commodity contracts:
Derivative assets	$	858		$	(732	)	$	(2	)	$	124
Derivative liabilities	(985		)	732			64			(189		)
Total commodity contracts	(127		)	—			62			(65		)
Interest rate contracts:
Derivative assets	50			(4		)	—			46
Derivative liabilities	(77		)	4			—			(73		)
Total interest rate contracts	(27		)	—			—			(27		)
Total derivative instruments	$	(154	)	$	—		$	62		$	(92	)



	Gross Amounts Not Offset in the Statement of Financial Position
	Gross Amounts of Recognized Assets / Liabilities			Derivative Instruments			Cash Collateral (Held) / Posted			Net Amount
As of December 31, 2016	(In millions)
Commodity contracts:
Derivative assets	$	1,202		$	(1,005	)	$	(1	)	$	196
Derivative liabilities	(1,290		)	1,005			14			(271		)
Total commodity contracts	(88		)	—			13			(75		)
Interest rate contracts:
Derivative assets	49			(4		)	—			45
Derivative liabilities	(88		)	4			—			(84		)
Total interest rate contracts	(39		)	—			—			(39		)
Total derivative instruments	$	(127	)	$	—		$	13		$	(114	)

Accumulated Other Comprehensive Loss

The following table summarizes the effects of ASC 815 on the Company's accumulated OCI balance attributable to cash flow hedge derivatives, net of tax:



	Three months ended March 31, 2017
	Interest Rate			Total
	(In millions)
Accumulated OCI beginning balance	$	(66	)	$	(66	)
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	3			3
Mark-to-market of cash flow hedge accounting contracts	2			2
Accumulated OCI ending balance, net of $14 tax	$	(61	)	$	(61	)
Losses expected to be realized from OCI during the next 12 months, net of $4 tax	$	(15	)	$	(15	)



	Three months ended March 31, 2016
	Interest Rate			Total
	(In millions)
Accumulated OCI beginning balance	$	(101	)	$	(101	)
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	3			3
Mark-to-market of cash flow hedge accounting contracts	(52		)	(52		)
Accumulated OCI ending balance, net of $24 tax	$	(150	)	$	(150	)

Amounts reclassified from accumulated OCI into income and amounts recognized in income from the ineffective portion of cash flow hedges are recorded to interest expense for interest rate contracts. There was no ineffectiveness for the three months ended March 31, 2017 and 2016.

Accounting guidelines require a high degree of correlation between the derivative and the hedged item throughout the period in order to qualify as a cash flow hedge. As of December 31, 2016, the Company's regression analysis for Viento Funding II interest rate swaps, while positively correlated, did not meet the required threshold for cash flow hedge accounting. As a result, the Company de-designated the Viento Funding II cash flow hedges as of December 31, 2016, and will prospectively mark these derivatives to market through the income statement.

Impact of Derivative Instruments on the Statements of Operations

Unrealized gains and losses associated with changes in the fair value of derivative instruments not accounted for as cash flow hedges and ineffectiveness of hedge derivatives are reflected in current period consolidated results of operations.

The following table summarizes the pre-tax effects of economic hedges that have not been designated as cash flow hedges, ineffectiveness on cash flow hedges and trading activity on the Company's statement of operations. The effect of energy commodity contracts is included within operating revenues and cost of operations and the effect of interest rate contracts is included in interest expense.



	Three months ended March 31,
	2017			2016
Unrealized mark-to-market results	(In millions)
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	16		$	(86	)
Reversal of acquired loss/(gain) positions related to economic hedges	2			(13		)
Net unrealized (losses)/gains on open positions related to economic hedges	(24		)	134
Total unrealized mark-to-market (losses)/gains for economic hedging activities	(6		)	35
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity	(15		)	8
Net unrealized gains on open positions related to trading activity	1			11
Total unrealized mark-to-market (losses)/gains for trading activity	(14		)	19
Total unrealized (losses)/gains	$	(20	)	$	54



	Three months ended March 31,
	2017			2016
	(In millions)
Unrealized gains included in operating revenues	$	114		$	45
Unrealized (losses)/gains included in cost of operations	(134		)	9
Total impact to statement of operations — energy commodities	$	(20	)	$	54
Total impact to statement of operations — interest rate contracts	$	5		$	(11	)

The reversals of acquired gain or loss positions were valued based upon the forward prices on the acquisition date. The roll-off amounts were offset by realized gains or losses at the settled prices and are reflected in operating revenue or cost of operations during the same period.

For the three months ended March 31, 2017, the $24 million unrealized loss from open economic hedge positions was primarily the result of a decrease in value of forward purchases of natural gas, coal, and ERCOT electricity due to decreases in natural gas, coal and ERCOT electricity prices.

For the three months ended March 31, 2016, the $134 million unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward sales of power due to decreases in electricity prices partially offset by a decrease in value of forward purchases of coal due to decreases in coal prices.

Credit Risk Related Contingent Features

Certain of the Company's hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed “adequate assurance” under the agreements, or requires the Company to post additional collateral if there were a one notch downgrade in the Company's credit rating. The collateral required for contracts with adequate assurance clauses that are in a net liability position as of March 31, 2017, was $38 million. The collateral required for contracts with credit rating contingent features as of March 31, 2017, was $33 million. The Company is also a party to certain marginable agreements where NRG has a net liability position, but the counterparty has not called for the collateral due, which was approximately $4 million as of March 31, 2017.

See Note 4, Fair Value of Financial Instruments, to this Form 10-Q for discussion regarding concentration of credit risk.

Note 7 — Impairments

2016 Impairment Loss

Petra Nova Parish Holdings — During the first quarter of 2016, management changed its plans with respect to its future capital commitments driven in part by the continued decline in oil prices. As a result, the Company reviewed its 50% interest in Petra Nova Parish Holdings for impairment utilizing the other-than-temporary impairment model. In determining fair value, the Company utilized an income approach and considered project specific assumptions for the future project cash flows. The carrying amount of the Company's equity method investment exceeded the fair value of the investment and the Company concluded that the decline is considered to be other than temporary. As a result, the Company measured the impairment loss as the difference between the carrying amount and the fair value of the investment and recorded an impairment loss of $140 million.

Note 8 — Debt and Capital Leases

This footnote should be read in conjunction with the complete description under Note 12, Debt and Capital Leases, to the Company's 2016 Form 10-K. Long-term debt and capital leases consisted of the following:



(In millions, except rates)	March 31, 2017			December 31, 2016			March 31, 2017 interest rate % ^(a)

Recourse debt:
Senior notes, due 2018	$	398		$	398		7.625
Senior notes, due 2021	207			207			7.875
Senior notes, due 2022	992			992			6.250
Senior notes, due 2023	869			869			6.625
Senior notes, due 2024	733			733			6.250
Senior notes, due 2026	1,000			1,000			7.250
Senior notes, due 2027	1,250			1,250			6.625
Term loan facility, due 2023	1,886			1,891			L+2.25
Revolving credit facility, due 2018 and 2021	125			—			L+2.25
Tax-exempt bonds	455			455			4.125 - 6.00
Subtotal NRG recourse debt	7,915			7,795
Non-recourse debt:
GenOn senior notes	1,830			1,830			7.875 - 9.875
GenOn Americas Generation senior notes	695			695			8.500 - 9.125
GenOn other	95			96
Subtotal GenOn debt (non-recourse to NRG)	2,620			2,621
NRG Yield Operating LLC Senior Notes, due 2024	500			500			5.375
NRG Yield Operating LLC Senior Notes, due 2026	350			350			5.000
NRG Yield Inc. Convertible Senior Notes, due 2019	345			345			3.500
NRG Yield Inc. Convertible Senior Notes, due 2020	288			288			3.250
El Segundo Energy Center, due 2023	414			443			L+1.625 - L+2.25
Marsh Landing, due 2017 and 2023	361			370			L+1.750 - L+1.875
Alta Wind I - V lease financing arrangements, due 2034 and 2035	965			965			5.696 - 7.015
Walnut Creek, term loans due 2023	303			310			L+1.625
Utah Portfolio, due 2022	287			287			L+2.65
Tapestry, due 2021	168			172			L+1.625
CVSR, due 2037	757			771			2.339 - 3.775
CVSR HoldCo, due 2037	194			199			4.680
Alpine, due 2022	144			145			L+1.750
Energy Center Minneapolis, due 2017 and 2025	94			96			5.95 - 7.25
Energy Center Minneapolis, due 2031	125			125			3.55
Viento, due 2023	178			178			L+2.75
NRG Yield - other	578			540			various
Subtotal NRG Yield debt (non-recourse to NRG)	6,051			6,084
Ivanpah, due 2033 and 2038	1,108			1,113			2.285 - 4.256
Agua Caliente, due 2037	846			849			2.395 - 3.633
Agua Caliente Borrower 1, due 2038	89			—			5.430
Cedro Hill, due 2025	161			163			L+1.75
Midwest Generation, due 2019	213			231			4.390
NRG Other	462			468			various
Subtotal other NRG non-recourse debt	2,879			2,824
Subtotal all non-recourse debt	11,550			11,529
Subtotal long-term debt (including current maturities)	19,465			19,324
Capital leases	12			8			various
Subtotal long-term debt and capital leases (including current maturities)	19,477			19,332
Less current maturities	(1,688		)	(1,220		)
Less debt issuance costs	(191		)	(188		)
Premiums, net of discounts	74			82
Total long-term debt and capital leases	$	17,672		$	18,006

(a) As of March 31, 2017, L+ equals 3 month LIBOR plus x%, with the exception of the Viento Funding II term loan, the Utah Portfolio term loans, the Alpine Term Loan, the NRG Marsh Landing term loan, the Walnut Creek term loan, the 2023 Term Loan Facility, and the Revolving credit facility which are 1 month LIBOR plus x%.

Recourse Debt

Revolving Credit Facility

On January 27, 2017, GenOn Mid-Atlantic entered into an agreement with Natixis Funding Corp., or Natixis, under which Natixis will procure payment and credit support for the payment of certain lease payments owed pursuant to the GenOn Mid-Atlantic operating leases for Morgantown and Dickerson. GenOn Mid-Atlantic made a payment of $130 million plus fees of $1 million as consideration for Natixis applying for the issuance of, and obtaining, letters of credit from Natixis, New York Branch, the LC Provider, to support the lease payments. Natixis is solely responsible for (i) obtaining letters of credit from the LC Provider, (ii) causing the letters of credit to be issued to the lessors to support the lease payments on behalf of GenOn Mid-Atlantic, (iii) making lease payments and (iv) satisfying any reimbursement obligations payable to the LC Provider. The payment is reflected as a long-term deposit on the Company's consolidated balance sheet as of March 31, 2017.

On February 24, 2017, GenOn Mid-Atlantic received a series of notices from certain of the owner lessors under its operating leases of the Morgantown coal generation unit alleging default, or Notices. The Notices allege the existence of lease events of default as a result of, among other items, the purported failure by GenOn Mid-Atlantic to comply with a covenant requiring the maintenance of qualifying credit support. The Notices instructed the relevant trustees to draw on letters of credit under the secured intercompany revolving credit agreement between NRG and GenOn, supporting the GenOn Mid-Atlantic operating leases that were set to expire on February 28, 2017. The offset was recorded to other non-current assets under the related operating leases pending resolution of the matter which is further described below. On February 28, 2017, the trustees drew on the letters of credit under NRG's revolving credit facility, which resulted in borrowings of $125 million. Upon notification, GenOn became obligated under the secured intercompany revolving credit agreement between NRG and GenOn. GenOn requested Genon Mid-Atlantic repay the related amount borrowed under the secured intercompany revolving credit agreement. GenOn Mid-Atlantic is unaware of whether any further action will be taken by the owner lessors or any other person in connection with the Notices. GenOn Mid-Atlantic disagrees with the owner lessors as to the existence of any lease events of default and/or any breaches by GenOn Mid-Atlantic of any terms and conditions of the operating leases and believes that the declaration of a lease event of default, the instruction to draw on the letters of credit under the secured intercompany revolving credit agreement between NRG and GenOn and the draws thereon constituted a violation by the owner lessors and the relevant trustees of the terms and conditions of the GenOn Mid-Atlantic operating leases. GenOn Mid-Atlantic intends to vigorously pursue its rights and remedies in connection with these actions. On March 7, 2017, GenOn Mid-Atlantic filed a complaint in the Supreme Court for the State of New York against the owner lessors of the Morgantown and Dickerson facilities and U.S. Bank National Association in its capacity as the indenture trustee. The complaint seeks, inter alia, a declaratory judgment that no lease events of default exist and asserts counts for breach of contract, conversion, tortious interference, breach of the implied covenant of good faith and fair dealing, unjust enrichment, constructive trust, and injunctive relief. The defendants in this action have not yet responded to the complaint and have until June 5, 2017 to do so. The court has set an initial conference hearing for June 12, 2017.

2023 Term Loan Facility

On January 24, 2017, NRG repriced the 2023 Term Loan Facility, reducing the interest rate margin by 50 basis points to LIBOR plus 2.25%. The LIBOR floor remains 0.75%.

Non-recourse Debt

GenOn Senior Notes

As disclosed in Note 1, Basis of Presentation, as of March 31, 2017, $691 million of GenOn's Senior Notes, excluding $4 million of associated premiums, of GenOn's Senior Notes outstanding are classified as current within the consolidated balance sheet as they mature on June 15, 2017. GenOn is currently considering all options available to it, including negotiations with creditors and lessors, refinancing the Senior Notes, potential sales of certain generating assets as well as the possibility of a need to file for protection under Chapter 11 of the U.S. Bankruptcy Code. If GenOn is unable to enter into a settlement with its creditors, refinance the senior notes or otherwise raise or generate sufficient capital, GenOn is not expected to have sufficient liquidity to repay the GenOn Senior Notes due in June 2017. Pending resolution, there is substantial doubt about GenOn's ability to continue as a going concern.

During 2016, GenOn appointed two independent directors, retained advisors and established a separate audit committee as part of this process. On April 7, 2017, GenOn also appointed a new dedicated chief executive officer, effective immediately. Any resolution may have a material impact on the Company's statement of operations, cash flows and financial position.

NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility

NRG Yield LLC and its direct wholly owned subsidiary, NRG Yield Operating LLC, entered into a senior secured revolving credit facility, which can be used for cash and for the issuance of letters of credit. At March 31, 2017, there was $64 million of letters of credit issued under the revolving credit facility and no borrowing outstanding on the revolver.

Project Financings

Agua Caliente Project Financing

On February 17, 2017, Agua Caliente Borrower 1 LLC and Agua Caliente Borrower 2 LLC, or Agua Caliente Holdco, the indirect owners of 51% of the Agua Caliente solar facility, issued $130 million of senior secured notes under the Agua Caliente Holdco Financing Agreement, or 2038 Agua Caliente Holdco Notes, that bear interest at 5.43% and mature on December 31, 2038. As described in Note 3, Dispositions, on March 27, 2017, NRG Yield, Inc. acquired Agua Caliente Borrower 2 LLC from NRG. The debt is joint and several with respect to Agua Caliente Borrower 1 LLC and Agua Caliente Borrower 2 LLC and is secured by the equity interests of each borrower in the Agua Caliente solar facility.

Note 9 — Variable Interest Entities, or VIEs

Entities that are not Consolidated

NRG has interests in entities that are considered VIEs under ASC 810, Consolidation, but NRG is not considered the primary beneficiary. NRG accounts for its interests in these entities under the equity method of accounting.

GenConn Energy LLC — Through its consolidated subsidiary, NRG Yield Operating LLC, the Company owns a 50% interest in GCE Holding LLC, the owner of GenConn, which owns and operates two 190 MW peaking generation facilities in Connecticut at NRG's Devon and Middletown sites. NRG's maximum exposure to loss is limited to its equity investment, which was $104 million as of March 31, 2017.

Entities that are Consolidated

The Company has a controlling financial interest in certain entities which have been identified as VIEs under ASC 810. These arrangements are primarily related to tax equity arrangements entered into with third-parties in order to finance the cost of solar energy systems under operating leases and wind facilities eligible for certain tax credits as further described in Note 2, Summary of Significant Accounting Policies to the Company's 2016 Form 10-K. For one of the tax equity arrangements, the Company has a deficit restoration obligation equal to $88 million as of March 31, 2017, which would be required to be funded if the arrangement were to be dissolved.

The summarized financial information for the Company's consolidated VIEs consisted of the following:



(In millions)	March 31, 2017		December 31, 2016
Current assets	$	90	$	87
Net property, plant and equipment	1,513		1,534
Other long-term assets	948		954
Total assets	2,551		2,575
Current liabilities	59		59
Long-term debt	439		442
Other long-term liabilities	185		183
Total liabilities	683		684
Noncontrolling interests	535		529
Net assets less noncontrolling interests	$	1,333	$	1,362

Note 10 — Changes in Capital Structure

As of March 31, 2017 and December 31, 2016, the Company had 500,000,000 shares of common stock authorized. The following table reflects the changes in NRG's common stock issued and outstanding:



	Issued	Treasury		Outstanding
Balance as of December 31, 2016	417,583,825	(102,140,814	)	315,443,011
Shares issued under LTIPs	355,047	—		355,047
Shares issued under ESPP	—	282,530		282,530
Balance as of March 31, 2017	417,938,872	(101,858,284	)	316,080,588

Amended and Restated Employee Stock Purchase Plan

As of March 31, 2017, there were 385,289 shares of treasury stock available for issuance under the ESPP. On April 27, 2017, NRG stockholders approved an increase of 3,000,000 shares available for issuance under the ESPP.

Amended and Restated Long-term Incentive Plan

On April 27, 2017, NRG stockholders approved an increase of 3,000,000 shares available for issuance under the NRG Energy, Inc. Amended and Restated Long-term Incentive Plan.

NRG Common Stock Dividends

The following table lists the dividends paid during the three months ended March 31, 2017:



	First Quarter 2017
Dividends per Common Share	$	0.030

On April 7, 2017, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable May 15, 2017, to stockholders of record as of May 1, 2017, representing $0.12 per share on an annualized basis.

The Company's common stock dividends are subject to available capital, market conditions, and compliance with associated laws, regulations and other contractual obligations.

Note 11 — Earnings/(Loss) Per Share

Basic earnings/(loss) per common share is computed by dividing net income/(loss) less accumulated preferred stock dividends by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year are weighted for the portion of the year that they were outstanding. Diluted earnings/(loss) per share is computed in a manner consistent with that of basic income/(loss) per share while giving effect to all potentially dilutive common shares that were outstanding during the period. During the second quarter of 2016, the Company repurchased 100% of the outstanding shares of its 2.822% preferred stock. The reconciliation of NRG's basic and diluted earnings/(loss) per share is shown in the following table:



	Three months ended March 31,
(In millions, except per share data)	2017			2016
Basic (loss)/earnings per share attributable to NRG Energy, Inc. common stockholders
Net (loss)/income attributable to NRG Energy, Inc.	$	(163	)	$	82
Dividends for preferred shares	—			5
(Loss)/income available for common stockholders	$	(163	)	$	77
Weighted average number of common shares outstanding - basic	316			315
(Loss)/Earnings per weighted average common share — basic	$	(0.52	)	$	0.24
Diluted (loss)/earnings per share attributable to NRG Energy, Inc. common stockholders
Weighted average number of common shares outstanding - diluted	316			315
Incremental shares attributable to the issuance of equity compensation (treasury stock method)	—			—
Total dilutive shares	316			315
(Loss)/earnings per weighted average common share — diluted	$	(0.52	)	$	0.24

The following table summarizes NRG’s outstanding equity instruments that are anti-dilutive and were not included in the computation of the Company’s diluted loss per share:



	Three months ended March 31,
(In millions of shares)	2017	2016
Equity compensation plans	6	4
Embedded derivative of 2.822% redeemable perpetual preferred stock	—	16
Total	6	20

Note 12 — Segment Reporting

The Company's segment structure reflects how management currently makes financial decisions and allocates resources. The Company's businesses are segregated as follows: Generation, which includes generation, international and BETM; Retail, which includes Mass customers and Business Solutions, which includes C&I customers and other distributed and reliability products; Renewables, which includes solar and wind assets, excluding those in NRG Yield; NRG Yield; and corporate activities. Intersegment sales are accounted for at market prices. The financial information for the three months ended March 31, 2016 has been recast to reflect the current segment structure.

On September 1, 2016, NRG Yield acquired the remaining 51.05% interest in CVSR Holdco LLC, which indirectly owns the CVSR solar facility, from the Company. On March 27, 2017, NRG Yield acquired from NRG a 16% interest in the Agua Caliente solar project, and NRG's interests in seven utility-scale solar projects located in Utah. Both acquisitions were treated as a transfer of entities under common control and accordingly, all historical periods have been recast to reflect the acquisition as if they had occurred at the beginning of the financial statement period.

NRG’s chief operating decision maker, its chief executive officer, evaluates the performance of its segments based on operational measures including adjusted earnings before interest, taxes, depreciation and amortization, or Adjusted EBITDA, free cash flow and capital for allocation, as well as net income/(loss).



	Generation^(a)			Retail ^(a)			Renewables^(a)(b)			NRG Yield			Corporate^(a)			Eliminations			Total
Three months ended March 31, 2017	(In millions)
Operating revenues^(a)	$	1,343		$	1,335		$	98		$	218		$	8		$	(243	)	$	2,759
Depreciation and amortization	138			28			49			75			10			—			300
Equity in (losses)/earnings of unconsolidated affiliates	(13		)	—			(1		)	19			3			(3		)	5
Gain on sale of assets	2			—			—			—			—			—			2
Income/(loss) before income taxes	67			(30		)	(37		)	(2		)	(203		)	(2		)	(207		)
Net Income/(Loss)	67			(33		)	(31		)	(1		)	(203		)	(2		)	(203		)
Net Income/(Loss) attributable to NRG Energy, Inc.	$	67		$	(32	)	$	(3	)	$	13		$	(203	)	$	(5	)	$	(163	)
Total assets as of March 31, 2017	$	12,962		$	2,150		$	5,123		$	8,580		$	14,621		$	(14,016	)	$	29,420



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	205	$	1	$	8		$	—	$	29	$	—	$	243
(b) Includes loss on debt extinguishment	$	—	$	—	$	(2	)	$	—	$	—	$	—	$	(2	)



	Generation^(a)			Retail^(a)		Renewables^(a)			NRG Yield^(a)		Corporate^(a)(b)			Eliminations			Total
Three months ended March 31, 2016	(In millions)
Operating revenues^(a)	$	1,708		$	1,370	$	96		$	234	$	18		$	(197	)	$	3,229
Depreciation and amortization	144			30		48			74		17			—			313
Impairment losses	(137		)	—		—			—		(9		)	—			(146		)
Equity in earnings/(loss) of unconsolidated affiliates	(8		)	—		(4		)	4		3			(2		)	(7		)
Gain on sale of assets	32			—		—			—		—			—			32
Income/(Loss) before income taxes	191			150		(46		)	2		(231		)	2			68
Net Income/(Loss)	191			150		(40		)	2		(258		)	2			47
Net Income/(Loss) attributable to NRG Energy, Inc.	$	191		$	150	$	(30	)	$	10	$	(245	)	$	6		$	82



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	118	$	3	$	6	$	4	$	66	$	—	$	197
(b) Includes gain on debt extinguishment	$	—	$	—	$	—	$	—	$	11	$	—	$	11

Note 13 — Income Taxes

Effective Tax Rate

The income tax provision consisted of the following:



	Three months ended March 31,
(In millions except otherwise noted)	2017			2016
Income/(loss) before income taxes	$	(207	)	$	68
Income tax (benefit)/expense	(4		)	21
Effective tax rate	1.9		%	30.9		%

For the three months ended March 31, 2017, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the change in valuation allowance partially offset by the generation of PTCs and ITCs from various wind and solar facilities, respectively and current state tax expense.

For the three months ended March 31, 2016, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the change in the valuation allowance, partially offset by the recording of a deferred tax liability associated with the amortization of indefinite lived assets.

Uncertain Tax Benefits

As of March 31, 2017, NRG has recorded a non-current tax liability of $38 million for uncertain tax benefits from positions taken on various state income tax returns, including accrued interest. For the three months ended March 31, 2017, NRG accrued $0.2 million of interest relating to the uncertain tax benefits. As of March 31, 2017, NRG had cumulative interest and penalties related to these uncertain tax benefits of $3 million. The Company recognizes interest and penalties related to uncertain tax benefits in income tax expense.

NRG is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including operations located in Australia. The Company is not subject to U.S. federal income tax examinations for years prior to 2015. With few exceptions, state and local income tax examinations are no longer open for years before 2010. The Company's primary foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2010.

Note 14 — Commitments and Contingencies

This footnote should be read in conjunction with the complete description under Note 22, Commitments and Contingencies, to the Company's 2016 Form 10-K.

Commitments

First Lien Structure — NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, excluding assets acquired in the GenOn and EME (including Midwest Generation) acquisitions, assets held by NRG Yield, Inc. and NRG's assets that have project-level financing, to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. The Company's lien counterparties may have a claim on NRG's assets to the extent market prices exceed the hedged price. As of March 31, 2017, hedges under the first liens were out-of-the-money for NRG on a counterparty aggregate basis.

Ivanpah Energy Production Guarantee — The Company's PPAs with PG&E with respect to the Ivanpah plant contain provisions for contract quantity and guaranteed energy production, which require that Ivanpah units 1 and 3 deliver to PG&E no less than the guaranteed energy production amount specified in the PPAs in any period of twenty-four consecutive months, or performance measurement period, during the term of the PPAs. In January 2017, the Company and PG&E executed amendments to the PPAs that provide, among other things, the ability to cure any failure to meet the guaranteed energy production amounts through performance and liquidated damage provisions. On February 2, 2017, PG&E filed a request with the CPUC to approve the amendments. On April 5, 2017, the CPUC issued a draft resolution proposing approval of the amendments without modification. Pending final and nonappealable CPUC approval, PG&E agreed to refrain from declaring any event of default with respect to any failure to deliver the guaranteed energy production amounts.

Lignite Contract with Texas Westmoreland Coal Co. — The Company has a contract with TWCC for reclamation activities associated with closure of the Jewett mine. NRG is responsible for reclamation costs and has recorded an adequate ARO liability. The Railroad Commission of Texas has imposed a bond obligation of $95.5 million on TWCC for the reclamation of the mine. Pursuant to the contract with TWCC, NRG supports this obligation through surety bonds. Additionally, NRG is obligated to provide additional performance assurance if required by the Railroad Commission of Texas.

Contingencies

The Company's material legal proceedings are described below. The Company believes that it has valid defenses to these legal proceedings and intends to defend them vigorously. NRG records reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. As applicable, the Company has established an adequate reserve for the matters discussed below. In addition, legal costs are expensed as incurred. Management has assessed each of the following matters based on current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought, and the probability of success. Unless specified below, the Company is unable to predict the outcome of these legal proceedings or reasonably estimate the scope or amount of any associated costs and potential liabilities. As additional information becomes available, management adjusts its assessment and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments, it is possible that the ultimate resolution of the Company's liabilities and contingencies could be at amounts that are different from its currently recorded reserves and that such difference could be material.

In addition to the legal proceedings noted below, NRG and its subsidiaries are party to other litigation or legal proceedings arising in the ordinary course of business. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.

Midwest Generation Asbestos Liabilities — The Company, through its subsidiary, Midwest Generation, may be subject to potential asbestos liabilities as a result of its acquisition of EME. The Company is currently analyzing the scope of potential liability as it may relate to Midwest Generation. The Company believes that it has established an adequate reserve for these cases.

Actions Pursued by MC Asset Recovery — With Mirant Corporation's emergence from bankruptcy protection in 2006, certain actions filed by GenOn Energy Holdings and some of its subsidiaries against third parties were transferred to MC Asset Recovery, a wholly owned subsidiary of GenOn Energy Holdings. MC Asset Recovery is governed by a manager who is independent of NRG and GenOn. MC Asset Recovery is a disregarded entity for income tax purposes. Under the remaining action transferred to MC Asset Recovery, MC Asset Recovery seeks to recover damages from Commerzbank AG and various other banks, or the Commerzbank Defendants, for alleged fraudulent transfers that occurred prior to Mirant's bankruptcy proceedings. In December 2010, the U.S. District Court for the Northern District of Texas dismissed MC Asset Recovery's complaint against the Commerzbank Defendants. In January 2011, MC Asset Recovery appealed the District Court's dismissal of its complaint against the Commerzbank Defendants to the U.S. Court of Appeals for the Fifth Circuit, or the Fifth Circuit. In March 2012, the Fifth Circuit reversed the District Court's dismissal and reinstated MC Asset Recovery's amended complaint against the Commerzbank Defendants. On December 10, 2015, the District Court granted summary judgment in favor of the Commerzbank Defendants. On December 29, 2015, MC Asset Recovery filed a notice to appeal this judgment with the Fifth Circuit. The appeal has been fully briefed by the parties and was argued before the Fifth Circuit on February 8, 2017.

Natural Gas Litigation — GenOn is party to several lawsuits, certain of which are class action lawsuits, in state and federal courts in Kansas, Missouri, Nevada and Wisconsin. These lawsuits were filed in the aftermath of the California energy crisis in 2000 and 2001 and the resulting FERC investigations and relate to alleged conduct to increase natural gas prices in violation of state antitrust law and similar laws. The lawsuits seek treble or punitive damages, restitution and/or expenses. The lawsuits also name as parties a number of energy companies unaffiliated with NRG. In July 2011, the U.S. District Court for the District of Nevada, which was handling four of the five cases, granted the defendants' motion for summary judgment and dismissed all claims against GenOn in those cases. The plaintiffs appealed to the U.S. Court of Appeals for the Ninth Circuit, or the Ninth Circuit, which reversed the decision of the District Court. GenOn along with the other defendants in the lawsuit filed a petition for a writ of certiorari to the U.S. Supreme Court challenging the Ninth Circuit's decision and the U.S. Supreme Court granted the petition. On April 21, 2015, the U.S. Supreme Court affirmed the Ninth Circuit’s holding that plaintiffs’ state antitrust law claims are not field-preempted by the federal Natural Gas Act and the Supremacy Clause of the U.S. Constitution. The U.S. Supreme Court left open whether the claims were preempted on the basis of conflict preemption. The U.S. Supreme Court directed that the case be remanded to the U.S. District Court for the District of Nevada for further proceedings. On March 7, 2016, class plaintiffs filed their motions for class certification. Defendants filed their briefs in opposition to class plaintiffs' motions for class certification on June 24, 2016. On March 30, 2017, the court denied the plaintiffs' motions for class certification. On April 13, 2017, the plaintiffs petitioned the Ninth Circuit for interlocutory review of the court’s order denying class certification.

In May 2016 in one of the Kansas cases, the U.S. District Court for the District of Nevada granted the defendants' motion for summary judgment. Subsequently in December 2016, the plaintiffs filed a notice of appeal with the Ninth Circuit. On March 28, 2017, plaintiffs filed their appellate brief. GenOn has agreed to indemnify CenterPoint against certain losses relating to these lawsuits.

In September 2012, the State of Nevada Supreme Court, which was handling the remaining case, affirmed dismissal by the Eighth Judicial District Court for Clark County, Nevada of all plaintiffs' claims against GenOn. In February 2013, the plaintiffs in the Nevada case filed a petition for a writ of certiorari to the U.S. Supreme Court. In June 2013, the U.S. Supreme Court denied the petition for a writ of certiorari, thereby ending one of the five lawsuits.

Energy Plus Holdings — On August 7, 2012, Energy Plus Holdings received a subpoena from the NYAG which generally sought information and business records related to Energy Plus Holdings' sales, marketing and business practices. Energy Plus Holdings provided documents and information to the NYAG. On June 22, 2015, the NYAG issued another subpoena seeking additional information. Energy Plus Holdings provided responsive documents to this second subpoena. The Company does not expect the resolution of this matter to have a material impact on the Company's consolidated financial position, results of operation, or cash flows.

Midwest Generation New Source Review Litigation — In August 2009, the EPA and the Illinois Attorney General, or the Government Plaintiffs, filed a complaint, or the Governments’ Complaint, in the U.S. District Court for the Northern District of Illinois alleging violations of CAA PSD requirements by Midwest Generation arising from maintenance, repair or replacement projects at six Illinois coal-fired electric generating stations performed by Midwest Generation or ComEd, a prior owner of the stations, including alleged failures to obtain PSD construction permits and to comply with BACT requirements. The Government Plaintiffs also alleged violations of opacity and PM standards at the Midwest Generation plants. Finally, the Government Plaintiffs alleged that Midwest Generation violated certain operating permit requirements under Title V of the CAA allegedly arising from such claimed PSD, opacity and PM emission violations. In addition to seeking penalties of up to $37,500 per violation, per day, the complaint seeks an injunction ordering Midwest Generation to install controls sufficient to meet BACT emission rates at the units subject to the complaint and other remedies, which could go well beyond the requirements of the CPS. Several environmental groups intervened as plaintiffs in this litigation and filed a complaint, or the Intervenors’ Complaint, which alleged opacity, PM and related Title V violations. Midwest Generation filed a motion to dismiss nine of the ten PSD counts in the Governments’ Complaint, and to dismiss the tenth PSD count to the extent the Governments’ Complaint sought civil penalties for that count. The trial court granted the motion in March 2010.

In June 2010, the Government Plaintiffs and Intervenors each filed an amended complaint. The Governments’ Amended Complaint again alleged that Midwest Generation violated PSD (based upon the same projects as alleged in their original complaint, but adding allegations that the Company was liable as the “successor” to ComEd), Title V and opacity and PM standards. It named EME and ComEd as additional defendants and alleged PSD violations (again, premised on the same projects) against them. The Intervenors’ Amended Complaint named only Midwest Generation as a defendant and alleged Title V and opacity/PM violations, as well as one of the ten PSD violations alleged in the Governments’ Amended Complaint. Midwest Generation again moved to dismiss all but one of the Government Plaintiffs’ PSD claims and the related Title V claims. Midwest Generation also filed a motion to dismiss the PSD claim in the Intervenors’ Amended Complaint and the related Title V claims. In March 2011, the trial court granted Midwest Generation’s partial motion to dismiss the Government Plaintiffs’ PSD claims. The trial court denied Midwest Generation’s motion to dismiss the PSD claim asserted in the Intervenors’ Amended Complaint, but noted that the plaintiffs would be required to convince the court that the statute of limitations should be equitably tolled. The trial court did not address other counts in the amended complaints that allege violations of opacity and PM emission limitations under the Illinois State Implementation Plan and related Title V claims. The trial court also granted the motions to dismiss the PSD claims asserted against EME and ComEd.

Following the trial court ruling, the Government Plaintiffs appealed the trial court’s dismissals of their PSD claims, including the dismissal of nine of the ten PSD claims against Midwest Generation and of the PSD claims against the other defendants. Those PSD claim dismissals were affirmed by the U.S. Court of Appeals for the Seventh Circuit in July 2013. In addition, in 2012, all but one of the environmental groups that had intervened in the case dismissed their claims without prejudice. As a result, only one environmental group remains a plaintiff intervenor in the case. The Company does not expect the resolution of this matter to have a material impact on the Company’s consolidated financial position, results of operations or cash flows.

Potomac River Environmental Investigation — In March 2013, NRG Potomac River LLC, a subsidiary of GenOn, received notice that the District of Columbia Department of Environment (now renamed the Department of Energy and Environment, or DOEE) was investigating potential discharges to the Potomac River originating from the Potomac River Generating facility site, a site where the generation facility is no longer in operation. In connection with that investigation, DOEE served a civil subpoena on NRG Potomac River LLC requesting information related to the site and potential discharges occurring from the site. NRG Potomac River LLC provided various responsive materials. In January 2016, DOEE advised NRG Potomac River LLC that DOEE believed various environmental violations had occurred as a result of discharges DOEE believes occurred to the Potomac River from the Potomac River Generating facility site and as a result of associated failures to accurately or sufficiently report such discharges. DOEE has indicated it believes that penalties are appropriate in light of the violations. NRG is currently reviewing the information provided by DOEE.

Telephone Consumer Protection Act Purported Class Actions — Three purported class action lawsuits have been filed against NRG Residential Solar Solutions, LLC — one in California and two in New Jersey. The plaintiffs generally allege misrepresentation by the call agents and violations of the TCPA, claiming that the defendants engaged in a telemarketing campaign placing unsolicited calls to individuals on the “Do Not Call List.” The plaintiffs seek statutory damages of up to $1,500 per plaintiff, actual damages and equitable relief. On July 8, 2016, NRG filed a Rule 11 Motion seeking dismissal of NRG from the California case. The Rule 11 Motion was denied on August 16, 2016. Class certification hearings are scheduled on August 21, 2017 and June 19, 2017 in the New Jersey and California cases respectively.

California Department of Water Resources and San Diego Gas & Electric Company v. Sunrise Power Company LLC — On January 29, 2016, CDWR and SDG&E filed a lawsuit against Sunrise Power Company, along with NRG and Chevron Power Corporation. In June 2001, CDWR and Sunrise entered into a 10-year PPA under which Sunrise would construct and operate a generating facility and provide power to CDWR. At the time the PPA was entered into, Sunrise had a transportation services agreement, or TSA, to purchase natural gas from Kern River through April 30, 2018. In August 2003, CDWR entered into an agreement with Sunrise and Kern River in which CDWR accepted assignment of the TSA through the term of the PPA. After the PPA expired, Kern River demanded that any reassignment be to a party which met certain creditworthiness standards which Sunrise did not. As such, the plaintiffs have brought this lawsuit against the defendants alleging breach of contract, breach of covenant of good faith and fair dealing and improper distributions. Plaintiffs generally claim damages of $1.2 million per month for the remaining 70 months of the TSA. On April 20, 2016, the defendants filed demurrers in response to the plaintiffs' complaint. The demurrers were granted on June 14, 2016; however, the plaintiffs were allowed to file amended complaints on July 1, 2016. On July 27, 2016, defendants filed demurrers to the amended complaints. On November 18, 2016, the court sustained the demurrers and allowed plaintiffs another opportunity to file a second amended lawsuit which they did on January 13, 2017. On April 21, 2017, the court issued an order sustaining the demurrers without leave to amend.

Braun v. NRG Yield, Inc. — On April 19, 2016, plaintiffs filed a putative class action lawsuit against NRG Yield, Inc., the current and former members of its board of directors individually, and other parties in California Superior Court in Kern County, CA. Plaintiffs allege various violations of the Securities Act due to the defendants’ alleged failure to disclose material facts related to low wind production prior to the NRG Yield, Inc.'s June 22, 2015 Class C common stock offering. Plaintiffs seek compensatory damages, rescission, attorney’s fees and costs. On August 3, 2016, the court approved a stipulation entered into by the parties. The stipulation provided that the plaintiffs would file an amended complaint by August 19, 2016, which they did on August 18, 2016. The Defendants filed demurrers and a motion challenging jurisdiction on October 18, 2016. On February 24, 2017, the court approved the parties' stipulation which provides the plaintiffs' opposition is due on June 15, 2017 and defendants' reply is due on August 14, 2017.

Ahmed v. NRG Energy, Inc. and the NRG Yield Board of Directors — On September 15, 2016, plaintiffs filed a putative class action lawsuit against NRG Energy, Inc., the directors of NRG Yield, Inc., and other parties in the Delaware Chancery Court. The complaint alleges that the defendants breached their respective fiduciary duties with regard to the recapitalization of NRG Yield, Inc. common stock in 2015. The plaintiffs generally seek economic damages, attorney’s fees and injunctive relief. The defendants filed a motion to dismiss the lawsuit on December 21, 2016. Plaintiffs filed their objection to the motion to dismiss on February 15, 2017. The Defendants' reply was filed on March 24, 2017. Oral argument is scheduled for June 20, 2017.

GenOn Noteholders' Lawsuit — On December 13, 2016, certain indenture trustees for an ad hoc group of holders, or the Noteholders, of the GenOn Energy, Inc. 7.875% Senior Notes due 2017, 9.500% Notes due 2018, and 9.875% Notes due 2020, and the GenOn Americas Generation, LLC 8.50% Senior Notes due 2021 and 9.125% Senior Notes due 2031, along with certain of the Noteholders, filed a complaint in the Superior Court of the State of Delaware against NRG and GenOn alleging certain claims related to a services agreement between NRG and GenOn. Plaintiffs generally seek recovery of all monies paid under the services agreement and any other damages that the court deems appropriate. On February 3, 2017, the court entered an order approving a Standstill Agreement whereby the parties agreed to suspend all deadlines in the case until March 1, 2017. The Standstill Agreement terminated on March 1, 2017. On April 30, 2017, the Noteholders filed an amended complaint that asserts (i) additional fraudulent transfer claims in relation to GenOn’s sale of the Marsh Landing project to NRG Yield LLC, (ii) alleged breaches of fiduciary duty by certain current and former officers and directors of GenOn in relation to the management services agreement and the alleged usurpation of corporate opportunities concerning the Mandalay and Canal projects and (iii) claims against NRG for allegedly aiding and abetting such claimed breaches of fiduciary duties. In addition to NRG and GenOn, the amended complaint names NRG Yield LLC and certain current and former officers and directors of GenOn as defendants. The plaintiffs generally seek recovery of all monies paid under the services agreement and any other damages that the court deems appropriate. On March 31, 2017, NRG and GenOn filed separate motions to dismiss the complaint, but such motions are superseded by the amended complaint.

Griffoul v. NRG Residential Solar Solutions — On February 28, 2017, plaintiffs, consisting of New Jersey residential solar customers, filed a purported class action lawsuit in New Jersey state court. Plaintiffs allege violations of the New Jersey Consumer Fraud Action and Truth-in-Consumer Contracts, Warranty and Notice Act with regard to certain provisions of their residential solar contracts. The plaintiffs seek damages and injunctive relief as to the proper allocation of the solar renewable energy credits.

Rice v. NRG — On April 14, 2017, plaintiffs filed a purported class action lawsuit in the U.S. District Court for the Western District of Pennsylvania against NRG, First Energy Corporation and Matt Canastrale Contracting, Inc. Plaintiffs generally claim personal injury, trespass, nuisance and property damage related to the disposal of coal ash from the Elrama Power Plant and First Energy’s Mitchell and Hatfield Power Plants. Plaintiffs generally seek monetary damages, medical monitoring and remediation of their property.

Note 15 — Regulatory Matters

This footnote should be read in conjunction with the complete description under Note 23, Regulatory Matters, to the Company's 2016 Form 10-K.

NRG operates in a highly regulated industry and is subject to regulation by various federal and state agencies. As such, NRG is affected by regulatory developments at both the federal and state levels and in the regions in which NRG operates. In addition, NRG is subject to the market rules, procedures, and protocols of the various ISO and RTO markets in which NRG participates. These power markets are subject to ongoing legislative and regulatory changes that may impact NRG's wholesale and retail businesses.

In addition to the regulatory proceedings noted below, NRG and its subsidiaries are parties to other regulatory proceedings arising in the ordinary course of business or have other regulatory exposure. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.

National

Zero-Emission Credits for Nuclear Plants in Illinois — In 2016, the Illinois legislature approved a Zero Emission Credit, or ZEC, program for selected nuclear units in Illinois. In total, the program directs over $2.5 billion over ten years to nuclear plants in Illinois that would otherwise retire. Pursuant to the legislation, the Illinois Power Agency, or IPA, conducts a competitive solicitation to procure ZECs, although both the Governor of Illinois and Exelon have already announced that the ZECs will be awarded to two Exelon-owned nuclear power plants in Illinois. These ZECs are out-of-market subsidies that threaten to artificially suppress market prices and interfere with the wholesale power market. On February 14, 2017, NRG, along with other companies, filed a complaint in the U.S. District Court for the Northern District of Illinois alleging that the state program is preempted by federal law and in violation of the dormant commerce clause. Another plaintiff group filed a similar complaint on the same day. Subsequently, on March 31, 2017, NRG, along with other companies, filed a motion for preliminary injunction. On April 10, 2017, Exelon, as an intervenor defendant, and State defendants filed motions to dismiss. The motions are pending before the U.S. District Court.

Zero-Emission Credits for Nuclear Plants in New York — On August 1, 2016, the NYSPSC issued its Clean Energy Standard, or CES, which provided for ZECs which would provide more than $7.6 billion over 12 years in out-of-market subsidy payments to certain selected nuclear generating units in the state. These ZECs are out-of-market subsidies that threaten to artificially suppress market prices and interfere with the wholesale power market. On October 19, 2016, NRG, along with other companies, filed a complaint in the U.S. District Court for the Southern District of New York, challenging the validity of the NYSPSC action and the ZEC program. On March 29, 2017, the U.S. District Court heard oral arguments on a motion to dismiss filed by defendants.

Current Administration and Changeover at FERC — FERC is currently without a quorum and cannot issue orders in contested proceedings until a new Commissioner is appointed. FERC continues to issue orders through authority that was delegated by the full Commission to FERC Staff. The legal validity of these actions has been questioned in connection with several of those orders. With a new administration and three vacant positions at FERC, NRG’s business may be affected because its generation fleet is subject to changes in FERC regulatory policy.

Note 16 — Environmental Matters

This footnote should be read in conjunction with the complete description under Note 24, Environmental Matters, to the Company's 2016 Form 10-K.

NRG is subject to a wide range of environmental laws in the development, construction, ownership and operation of projects. These laws generally require that governmental permits and approvals be obtained before construction and during operation of power plants. NRG is also subject to laws regarding the protection of wildlife, including migratory birds, eagles and threatened and endangered species. The electric generation industry has been facing requirements regarding GHGs, combustion byproducts, water discharge and use, and threatened and endangered species that have been put in place in recent years. However, under the new U.S. presidential administration, some of these rules are being reconsidered and reviewed. In general, future laws are expected to require the addition of emissions controls or other environmental controls or to impose certain restrictions on the operations of the Company's facilities, which could have a material effect on the Company's consolidated financial position, results of operations, or cash flows. Federal and state environmental laws generally have become more stringent over time, although this trend could slow or pause in the near term with respect to federal laws under the new U.S. presidential administration.

The EPA finalized CSAPR in 2011, which was intended to replace CAIR in January 2012, to address certain states' obligations to reduce emissions so that downwind states can achieve federal air quality standards. In December 2011, the D.C. Circuit stayed the implementation of CSAPR and then vacated CSAPR in August 2012 but kept CAIR in place until the EPA could replace it. In April 2014, the U.S. Supreme Court reversed and remanded the D.C. Circuit's decision. In October 2014, the D.C. Circuit lifted the stay of CSAPR. In response, the EPA in November 2014 amended the CSAPR compliance dates. Accordingly, CSAPR replaced CAIR on January 1, 2015. On July 28, 2015, the D.C. Circuit held that the EPA had exceeded its authority by requiring certain reductions that were not necessary for downwind states to achieve federal standards. Although the D.C. Circuit kept the rule in place, the court ordered the EPA to revise the Phase 2 (or 2017) (i) SO₂ budgets for four states including Texas and (ii) ozone-season NOx budgets for 11 states including Maryland, New Jersey, New York, Ohio, Pennsylvania and Texas. On October 26, 2016, the EPA finalized the CSAPR Update Rule, which reduces future NOx allocations and discounts the current banked allowances to account for the more stringent 2008 Ozone NAAQS and to address the D.C. Circuit's July 2015 decision. This rule has been challenged in the D.C. Circuit. The Company believes its investment in pollution controls and cleaner technologies leave the fleet well-positioned for compliance.

In February 2012, the EPA promulgated standards (the MATS rule) to control emissions of HAPs from coal and oil-fired electric generating units. The rule established limits for mercury, non-mercury metals, certain organics and acid gases, which had to be met beginning in April 2015 (with some units getting a 1-year extension). In June 2015, the U.S. Supreme Court issued a decision in the case of Michigan v. EPA, and held that the EPA unreasonably refused to consider costs when it determined that it was "appropriate and necessary" to regulate HAPs emitted by electric generating units. The U.S. Supreme Court did not vacate the MATS rule but rather remanded it to the D.C. Circuit for further proceedings. In December 2015, the D.C. Circuit remanded the MATS rule to the EPA without vacatur. On April 25, 2016, the EPA released a supplemental finding that the benefits of this regulation outweigh the costs to address the U.S. Supreme Court's ruling that the EPA had not properly considered costs. This finding has been challenged in the D.C. Circuit. On April 18, 2017, the EPA asked the D.C. Circuit to postpone oral argument that had been scheduled for May 18, 2017 because the EPA is closely reviewing the supplemental finding to determine whether it should reconsider all or part of the rule. On April 27, 2017, the D.C. Circuit granted EPA's request to postpone the oral argument and hold the case in abeyance. While NRG cannot predict the final outcome of this rulemaking, NRG believes that because it has already invested in pollution controls and cleaner technologies, the fleet is well-positioned to comply with the MATS rule.

Water

In August 2014, the EPA finalized the regulation regarding the use of water for once through cooling at existing facilities to address impingement and entrainment concerns. NRG anticipates that more stringent requirements will be incorporated into some of its water discharge permits over the next several years as NPDES permits are renewed.

Effluent Limitations Guidelines — In November 2015, the EPA revised the Effluent Limitations Guidelines for Steam Electric Generating Facilities, which would have imposed more stringent requirements (as individual permits were renewed) for wastewater streams from flue gas desulfurization, fly ash, bottom ash, and flue gas mercury control. The Company estimated that it would have cost approximately $200 million over the next eight years (the majority of the cost would be incurred after 2019) to comply with this rule at 11 coal-fired plants. In April 2017, the EPA granted two petitions to reconsider the rule and also administratively stayed the deadlines. This regulation also has been challenged. The Company expects the legal challenges to be suspended while the EPA reconsiders and likely modifies the rule. Accordingly, the Company expects to reduce its estimate of the environmental capital expenditures that would be required to comply with permits issued that incorporate the revised guidelines. The Company decides to invest capital for environmental controls based on: the certainty of regulations; evaluation of different technologies; options to convert to gas; and the expected economic returns on the capital. Over the next several years, the Company will decide whether to proceed with these investments at each of the plants as permits are renewed based on, among other things, the legal certainty of the regulation and market conditions at that time.

Byproducts, Wastes, Hazardous Materials and Contamination

In April 2015, the EPA finalized the rule regulating byproducts of coal combustion (e.g., ash and gypsum) as solid wastes under the RCRA. The Company has evaluated the impact of the new rule on the Company's consolidated financial position, results of operations, or cash flows and has accrued its environmental and asset retirement obligations under the rule based on current estimates as of March 31, 2017.

East Region

Burton Island Old Ash Landfill — In January 2006, NRG's Indian River Power LLC was notified that it may be a potentially responsible party with respect to Burton Island Old Ash Landfill, a historic captive landfill located at the Indian River facility. On October 1, 2007, NRG signed an agreement with DNREC to investigate the site through the Voluntary Clean-up Program, or the VCP. On February 4, 2008, DNREC issued findings that no further action was required in relation to surface water and that a previously planned shoreline stabilization project would satisfactorily address shoreline erosion. The landfill itself required a Remedial Investigation and Feasibility Study to determine the type and scope of any additional required work. DNREC approved the Feasibility Study in December 2012. In January 2013, DNREC proposed a remediation plan based on the Feasibility Study. The remediation plan was approved in October 2013. In December 2015, DNREC approved the Company's remediation design and the Company's Long Term Stewardship Plan. The cost of completing the work required by the approved remediation plan is consistent with amounts budgeted in early 2016 and on track for completion in the second quarter of 2017. The estimated cost to comply with the Long-Term Stewardship Plan was added to the liability in December 2016.

In addition to the VCP, on May 29, 2008, DNREC requested that NRG's Indian River Power LLC participate in the development and performance of a Natural Resource Damage Assessment at the Burton Island Old Ash Landfill. NRG is working with DNREC and other trustees to close out the assessment process.

Note 17 — Condensed Consolidating Financial Information

As of March 31, 2017, the Company had outstanding $5.4 billion of Senior Notes due from 2018 to 2027, as shown in Note 8, Debt and Capital Leases. These Senior Notes are guaranteed by certain of NRG's current and future 100% owned domestic subsidiaries, or guarantor subsidiaries. These guarantees are both joint and several. The non-guarantor subsidiaries include all of NRG's foreign subsidiaries and certain domestic subsidiaries, including GenOn and its subsidiaries and NRG Yield, Inc. and its subsidiaries.

Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of March 31, 2017:



Ace Energy, Inc.	Norwalk Power LLC	NRG Operating Services, Inc.
Allied Home Warranty GP LLC	NRG Advisory Services LLC	NRG Oswego Harbor Power Operations Inc.
Allied Warranty LLC	NRG Affiliate Services Inc.	NRG PacGen Inc.
Arthur Kill Power LLC	NRG Artesian Energy LLC	NRG Portable Power LLC
Astoria Gas Turbine Power LLC	NRG Arthur Kill Operations Inc.	NRG Power Marketing LLC
Bayou Cove Peaking Power, LLC	NRG Astoria Gas Turbine Operations Inc.	NRG Reliability Solutions LLC
BidURenergy, Inc.	NRG Bayou Cove LLC	NRG Renter's Protection LLC
Cabrillo Power I LLC	NRG Business Services LLC	NRG Retail LLC
Cabrillo Power II LLC	NRG Business Solutions LLC	NRG Retail Northeast LLC
Carbon Management Solutions LLC	NRG Cabrillo Power Operations Inc.	NRG Rockford Acquisition LLC
Cirro Group, Inc.	NRG California Peaker Operations LLC	NRG Saguaro Operations Inc.
Cirro Energy Services, Inc.	NRG Cedar Bayou Development Company, LLC	NRG Security LLC
Clean Edge Energy LLC	NRG Connected Home LLC	NRG Services Corporation
Conemaugh Power LLC	NRG Connecticut Affiliate Services Inc.	NRG SimplySmart Solutions LLC
Connecticut Jet Power LLC	NRG Construction LLC	NRG South Central Affiliate Services Inc.
Cottonwood Development LLC	NRG Curtailment Solutions Holdings LLC	NRG South Central Generating LLC
Cottonwood Energy Company LP	NRG Curtailment Solutions, Inc	NRG South Central Operations Inc.
Cottonwood Generating Partners I LLC	NRG Development Company Inc.	NRG South Texas LP
Cottonwood Generating Partners II LLC	NRG Devon Operations Inc.	NRG SPV #1 LLC
Cottonwood Generating Partners III LLC	NRG Dispatch Services LLC	NRG Texas C&I Supply LLC
Cottonwood Technology Partners LP	NRG Distributed Generation PR LLC	NRG Texas Gregory LLC
Devon Power LLC	NRG Dunkirk Operations Inc.	NRG Texas Holding Inc.
Dunkirk Power LLC	NRG El Segundo Operations Inc.	NRG Texas LLC
Eastern Sierra Energy Company LLC	NRG Energy Efficiency-L LLC	NRG Texas Power LLC
El Segundo Power, LLC	NRG Energy Labor Services LLC	NRG Warranty Services LLC
El Segundo Power II LLC	NRG ECOKAP Holdings LLC	NRG West Coast LLC
Energy Alternatives Wholesale, LLC	NRG Energy Services Group LLC	NRG Western Affiliate Services Inc.
Energy Choice Solutions LLC	NRG Energy Services International Inc.	O'Brien Cogeneration, Inc. II
Energy Plus Holdings LLC	NRG Energy Services LLC	ONSITE Energy, Inc.
Energy Plus Natural Gas LLC	NRG Generation Holdings, Inc.	Oswego Harbor Power LLC
Energy Protection Insurance Company	NRG Greenco	RE Retail Receivables, LLC
Everything Energy LLC	NRG Home & Business Solutions LLC	Reliant Energy Northeast LLC
Forward Home Security, LLC	NRG Home Services LLC	Reliant Energy Power Supply, LLC
GCP Funding Company, LLC	NRG Home Solutions LLC	Reliant Energy Retail Holdings, LLC
Green Mountain Energy Company	NRG Home Solutions Product LLC	Reliant Energy Retail Services, LLC
Gregory Partners, LLC	NRG Homer City Services LLC	RERH Holdings, LLC
Gregory Power Partners LLC	NRG Huntley Operations Inc.	Saguaro Power LLC
Huntley Power LLC	NRG HQ DG LLC	Somerset Operations Inc.
Independence Energy Alliance LLC	NRG Identity Protect LLC	Somerset Power LLC
Independence Energy Group LLC	NRG Ilion Limited Partnership	Texas Genco Financing Corp.
Independence Energy Natural Gas LLC	NRG Ilion LP LLC	Texas Genco GP, LLC
Indian River Operations Inc.	NRG International LLC	Texas Genco Holdings, Inc.
Indian River Power LLC	NRG Maintenance Services LLC	Texas Genco LP, LLC
Keystone Power LLC	NRG Mextrans Inc.	Texas Genco Operating Services, LLC
Langford Wind Power, LLC	NRG MidAtlantic Affiliate Services Inc.	Texas Genco Services, LP
Louisiana Generating LLC	NRG Middletown Operations Inc.	US Retailers LLC
Meriden Gas Turbines LLC	NRG Montville Operations Inc.	Vienna Operations Inc.
Middletown Power LLC	NRG New Roads Holdings LLC	Vienna Power LLC
Montville Power LLC	NRG North Central Operations Inc.	WCP (Generation) Holdings LLC
NEO Corporation	NRG Northeast Affiliate Services Inc.	West Coast Power LLC
New Genco GP, LLC	NRG Norwalk Harbor Operations Inc.

NRG conducts much of its business through and derives much of its income from its subsidiaries. Therefore, the Company's ability to make required payments with respect to its indebtedness and other obligations depends on the financial results and condition of its subsidiaries and NRG's ability to receive funds from its subsidiaries. There are no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to NRG. However, there may be restrictions for certain non-guarantor subsidiaries.

The following condensed consolidating financial information presents the financial information of NRG Energy, Inc., the guarantor subsidiaries and the non-guarantor subsidiaries in accordance with Rule 3-10 under the SEC Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiaries or non-guarantor subsidiaries operated as independent entities.

In this presentation, NRG Energy, Inc. consists of parent company operations. Guarantor subsidiaries and non-guarantor subsidiaries of NRG are reported on an equity basis. For companies acquired, the fair values of the assets and liabilities acquired have been presented on a push-down accounting basis.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the three months ended March 31, 2017

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	1,599		$	1,243		$	—		$	(83	)	$	2,759
Operating Costs and Expenses
Cost of operations	1,261			933			14			(83		)	2,125
Depreciation and amortization	102			190			8			—			300
Selling, general and administrative	96			106			70			—			272
Development activity expenses	—			12			5			—			17
Total operating costs and expenses	1,459			1,241			97			(83		)	2,714
Gain on sale of assets	2			—			—			—			2
Operating Income/(Loss)	142			2			(97		)	—			47
Other Income/(Expense)
Equity in (losses)/earnings of consolidated subsidiaries	(77		)	(34		)	67			44			—
Equity in (losses)/earnings of unconsolidated affiliates	(1		)	7			(1		)	—			5
Other income	1			8			4			(1		)	12
Loss on debt extinguishment	—			(2		)	—			—			(2		)
Interest expense	(4		)	(151		)	(114		)	—			(269		)
Total other expense	(81		)	(172		)	(44		)	43			(254		)
Income/(Loss) Before Income Taxes	61			(170		)	(141		)	43			(207		)
Income tax expense/(benefit)	19			(46		)	25			(2		)	(4		)
Net Income/(Loss)	42			(124		)	(166		)	45			(203		)
Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interests	—			(38		)	(3		)	1			(40		)
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	42		$	(86	)	$	(163	)	$	44		$	(163	)


(a)	All significant intercompany transactions have been eliminated in consolidation.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

For the three months ended March 31, 2017

(Unaudited)



	Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Net Income/(Loss)	$	42	$	(124	)	$	(166	)	$	45		$	(203	)
Other Comprehensive Income/(Loss), net of tax
Unrealized gain on derivatives, net	—		5			4			(5		)	4
Foreign currency translation adjustments, net	5		4			7			(9		)	7
Defined benefit plans, net	—		1			(1		)	—			—
Other comprehensive income	5		10			10			(14		)	11
Comprehensive Income/(Loss)	47		(114		)	(156		)	31			(192		)
Less: Comprehensive loss attributable to noncontrolling interest and redeemable noncontrolling interest	—		(37		)	(3		)	1			(39		)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	47		(77		)	(153		)	30			(153		)
Comprehensive Income/(Loss) Available for Common Stockholders	$	47	$	(77	)	$	(153	)	$	30		$	(153	)


(a)	All significant intercompany transactions have been eliminated in consolidation.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

March 31, 2017

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
ASSETS	(In millions)
Current Assets
Cash and cash equivalents	$	—		$	1,257		$	256		$	—		$	1,513
Funds deposited by counterparties	3			—			—			—			3
Restricted cash	5			392			—			—			397
Accounts receivable - trade, net	592			378			4			—			974
Accounts receivable - affiliate	251			23			(36		)	(231		)	7
Inventory	483			657			—			—			1,140
Derivative instruments	594			207			3			(122		)	682
Cash collateral paid in support of energy risk management activities	173			104			—			—			277
Prepayments and other current assets	94			295			58			—			447
Total current assets	2,195			3,313			285			(353		)	5,440
Net property, plant and equipment	4,168			13,555			246			(27		)	17,942
Other Assets
Investment in subsidiaries	1,067			1,062			10,040			(12,169		)	—
Equity investments in affiliates	—			1,144			4			—			1,148
Notes receivable, less current portion	—			13			125			(125		)	13
Goodwill	359			303			—			—			662
Intangible assets, net	566			1,394			—			(3		)	1,957
Nuclear decommissioning trust fund	627			—			—			—			627
Derivative instruments	178			66			34			(52		)	226
Deferred income tax	(2		)	911			(686		)	—			223
Non-current assets held-for-sale	—			10			—			—			10
Other non-current assets	71			1,037			64			—			1,172
Total other assets	2,866			5,940			9,581			(12,349		)	6,038
Total Assets	$	9,229		$	22,808		$	10,112		$	(12,729	)	$	29,420
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—		$	1,268		$	420		$	—		$	1,688
Accounts payable	436			403			33			—			872
Accounts payable — affiliate	738			1,686			(2,193		)	(231		)	—
Derivative instruments	584			285			—			(122		)	747
Cash collateral received in support of energy risk management activities	3			—			—			—			3
Accrued expenses and other current liabilities	251			368			268			—			887
Total current liabilities	2,012			4,010			(1,472		)	(353		)	4,197
Other Liabilities
Long-term debt and capital leases	244			10,443			7,110			(125		)	17,672
Nuclear decommissioning reserve	291			—			—			—			291
Nuclear decommissioning trust liability	352			—			—			—			352
Deferred income taxes	200			(1,095		)	915			—			20
Derivative instruments	183			184			—			(52		)	315
Out-of-market contracts, net	77			940			—			—			1,017
Non-current liabilities held-for-sale	—			12			—			—			12
Other non-current liabilities	402			763			322			—			1,487
Total non-current liabilities	1,749			11,247			8,347			(177		)	21,166
Total liabilities	3,761			15,257			6,875			(530		)	25,363
Redeemable noncontrolling interest in subsidiaries	—			44			—			—			44
Stockholders’ Equity	5,468			7,507			3,237			(12,199		)	4,013
Total Liabilities and Stockholders’ Equity	$	9,229		$	22,808		$	10,112		$	(12,729	)	$	29,420


(a)	All significant intercompany transactions have been eliminated in consolidation.

NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED

CONSOLIDATING STATEMENTS OF CASH FLOWS

For the three months ended March 31, 2017 (Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Cash Flows from Operating Activities
Net income/(loss)	$	42		$	(124	)	$	(166	)	$	45		$	(203	)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Distributions from unconsolidated affiliates	—			18			—			(5		)	13
Equity in losses/(earnings) of unconsolidated affiliates	1			(7		)	1			—			(5		)
Depreciation and amortization	102			190			8			—			300
Provision for bad debts	8			1			—			—			9
Amortization of nuclear fuel	12			—			—			—			12
Amortization of financing costs and debt discount/premiums	—			(3		)	4			—			1
Amortization of intangibles and out-of-market contracts	6			4			—			—			10
Amortization of unearned equity compensation	—			—			8			—			8
Changes in deferred income taxes and liability for uncertain tax benefits	19			(46		)	28			—			1
Changes in nuclear decommissioning trust liability	36			—			—			—			36
Changes in derivative instruments	(4		)	30			(1		)	—			25
Changes in collateral deposits supporting energy risk management activities	(136		)	62			—			—			(74		)
Gain on sale of assets	(2		)	—			—			—			(2		)
Cash (used)/provided by changes in other working capital	(86		)	499			(604		)	(8		)	(199		)
Net Cash (Used)/Provided by Operating Activities	(2		)	624			(722		)	32			(68		)
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc.	—			—			22			(22		)	—
Acquisition of Drop Down Assets, net of cash acquired	—			(131		)	—			131			—
Intercompany dividends	—			—			129			(129		)	—
Acquisition of business, net of cash acquired	—			(3		)	—			—			(3		)
Capital expenditures	(64		)	(200		)	(4		)	—			(268		)
Decrease in restricted cash, net	2			11			—			—			13
Decrease in restricted cash - U.S. DOE projects	4			32			—			—			36
Decrease in notes receivable	—			4			—			—			4
Purchases of emission allowances	(9		)	—			—			—			(9		)
Proceeds from sale of emission allowances	11			—			—			—			11
Investments in nuclear decommissioning trust fund securities	(153		)	—			—			—			(153		)
Proceeds from sales of nuclear decommissioning trust fund securities	117			—			—			—			117
Proceeds from sale of assets, net of cash disposed of	11			3			—			—			14
Investments in unconsolidated affiliates	—			(12		)	—			—			(12		)
Other	18			—			—			—			18
Net Cash (Used)/Provided by Investing Activities	(63		)	(296		)	147			(20		)	(232		)
Cash Flows from Financing Activities
Dividends from NRG Yield, Inc.	—			(22		)	—			22			—
Payments from/(for) intercompany loans	65			(428		)	395			(32		)	—
Acquisition of Drop Down Assets, net of cash acquired	—			—			131			(131		)	—
Intercompany dividends	—			(129		)	—			129			—
Payment of dividends to common and preferred stockholders	—			—			(9		)	—			(9		)
Net receipts from settlement of acquired derivatives that include financing elements	—			1			—			—			1
Proceeds from issuance of long-term debt	—			166			26			—			192
Payments for short and long-term debt	—			(146		)	(31		)	—			(177		)
Payment for credit support in long-term deposits	—			(130		)	—			—			(130		)
Proceeds from draw on revolving credit facility for long-term deposits	—			125			—			—			125
Increase in long-term deposits	—			(125		)	—			—			(125		)
Contributions to, net of distributions from, noncontrolling interest in subsidiaries	—			(5		)	—			—			(5		)
Payment of debt issuance costs	—			(11		)	(4		)	—			(15		)
Other - contingent consideration	—			(10		)	—			—			(10		)
Net Cash Provided/(Used) by Financing Activities	65			(714		)	508			(12		)	(153		)
Effect of exchange rate changes on cash and cash equivalents	—			(7		)	—			—			(7		)
Net Decrease in Cash and Cash Equivalents	—			(393		)	(67		)	—			(460		)
Cash and Cash Equivalents at Beginning of Period	—			1,650			323			—			1,973
Cash and Cash Equivalents at End of Period	$	—		$	1,257		$	256		$	—		$	1,513


(a)	All significant intercompany transactions have been eliminated in consolidation.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the three months ended March 31, 2016

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	1,956		$	1,299		$	—		$	(26	)	$	3,229
Operating Costs and Expenses
Cost of operations	1,455			759			10			(30		)	2,194
Depreciation and amortization	117			190			6			—			313
Selling, general and administrative	93			99			60			—			252
Development activity expenses	—			19			7			—			26
Total operating costs and expenses	1,665			1,067			83			(30		)	2,785
Gain on sale of assets	—			32			—			—			32
Operating Income/(Loss)	291			264			(83		)	4			476
Other Income/(Expense)
Equity in (losses)/earnings of consolidated subsidiaries	(24		)	4			213			(193		)	—
Equity in losses of unconsolidated affiliates	—			(8		)	—			1			(7		)
Impairment loss on investment	—			(140		)	(6		)	—			(146		)
Other income/(expense), net	—			20			(2		)	—			18
Gain on debt extinguishment	—			—			11			—			11
Interest expense	(5		)	(150		)	(129		)	—			(284		)
Total other (expense)/income	(29		)	(274		)	87			(192		)	(408		)
Income/(Loss) Before Income Taxes	262			(10		)	4			(188		)	68
Income tax expense/(benefit)	100			(8		)	(83		)	12			21
Net Income/(Loss)	162			(2		)	87			(200		)	47
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—			(33		)	5			(7		)	(35		)
Net Income Attributable to NRG Energy, Inc.	$	162		$	31		$	82		$	(193	)	$	82


(a)	All significant intercompany transactions have been eliminated in consolidation.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME

For the three months ended March 31, 2016

(Unaudited)



	Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)		Eliminations^(a)			Consolidated
	(In millions)
Net Income/(Loss)	$	162	$	(2	)	$	87	$	(200	)	$	47
Other Comprehensive Income/(Loss), net of tax
Unrealized (loss)/gain on derivatives, net	—		(50		)	24		(6		)	(32		)
Foreign currency translation adjustments, net	4		4			6		(8		)	6
Available-for-sale securities, net	—		—			3		—			3
Defined benefit plans, net	1		—			—		—			1
Other comprehensive income/(loss)	5		(46		)	33		(14		)	(22		)
Comprehensive Income/Loss	167		(48		)	120		(214		)	25
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—		(50		)	5		(7		)	(52		)
Comprehensive Income Attributable to NRG Energy, Inc.	167		2			115		(207		)	77
Dividends for preferred shares	—		—			5		—			5
Comprehensive Income Available for Common Stockholders	$	167	$	2		$	110	$	(207	)	$	72


(a)	All significant intercompany transactions have been eliminated in consolidation.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

December 31, 2016



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations ^(a)			Consolidated
ASSETS	(In millions)
Current Assets
Cash and cash equivalents	$	—		$	1,650		$	323		$	—		$	1,973
Funds deposited by counterparties	2			—			—			—			2
Restricted cash	11			435			—			—			446
Accounts receivable - trade, net	734			429			3			—			1,166
Accounts receivable - affiliate	309			(241		)	200			(262		)	6
Inventory	482			629			—			—			1,111
Derivative instruments	962			305			—			(205		)	1,062
Cash collateral paid in support of energy risk management activities	37			166			—			—			203
Current assets held-for-sale	—			9			—			—			9
Prepayments and other current assets	76			279			62			—			417
Total current assets	2,613			3,661			588			(467		)	6,395
Net Property, Plant and Equipment	4,216			13,472			251			(27		)	17,912
Other Assets
Investment in subsidiaries	837			1,973			10,128			(12,938		)	—
Equity investments in affiliates	(14		)	1,129			5			—			1,120
Notes receivable, less current portion	—			17			(76		)	76			17
Goodwill	359			303			—			—			662
Intangible assets, net	592			1,447			—			(3		)	2,036
Nuclear decommissioning trust fund	610			—			—			—			610
Derivative instruments	143			60			36			(50		)	189
Deferred income taxes	3			868			(646		)	—			225
Non-current assets held for sale	—			10			—			—			10
Other non-current assets	67			784			328			—			1,179
Total other assets	2,597			6,591			9,775			(12,915		)	6,048
Total Assets	$	9,426		$	23,724		$	10,614		$	(13,409	)	$	30,355
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—		$	1,202		$	(58	)	$	76		$	1,220
Accounts payable	499			362			34			—			895
Accounts payable — affiliate	655			1,834			(2,227		)	(262		)	—
Derivative instruments	947			342			—			(205		)	1,084
Cash collateral received in support of energy risk management activities	2			—			—			—			2
Current liabilities held-for-sale	—			—			—			—			—
Accrued expenses and other current liabilities	317			400			464			—			1,181
Total current liabilities	2,420			4,140			(1,787		)	(391		)	4,382
Other Liabilities
Long-term debt and capital leases	244			10,302			7,460			—			18,006
Nuclear decommissioning reserve	287			—			—			—			287
Nuclear decommissioning trust liability	339			—			—			—			339
Deferred income taxes	186			(1,094		)	928			—			20
Derivative instruments	157			187			—			(50		)	294
Out-of-market contracts, net	80			960			—			—			1,040
Non-current liabilities held-for-sale	—			12			—			—			12
Other non-current liabilities	397			762			324			—			1,483
Total non-current liabilities	1,690			11,129			8,712			(50		)	21,481
Total Liabilities	4,110			15,269			6,925			(441		)	25,863
Redeemable noncontrolling interest in subsidiaries	—			46			—			—			46
Stockholders’ Equity	5,316			8,409			3,689			(12,968		)	4,446
Total Liabilities and Stockholders’ Equity	$	9,426		$	23,724		$	10,614		$	(13,409	)	$	30,355


(a)	All significant intercompany transactions have been eliminated in consolidation.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the three months ended March 31, 2016

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Cash Flows from Operating Activities
Net income/(loss)	$	162		$	(2	)	$	87		$	(200	)	$	47
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Distributions from unconsolidated affiliates	—			22			—			(12		)	10
Equity in losses of unconsolidated affiliates	—			8			—			(1		)	7
Depreciation and amortization	117			190			6			—			313
Provision for bad debts	8			2			—			—			10
Amortization of nuclear fuel	13			—			—			—			13
Amortization of financing costs and debt discount/premiums	—			7			(6		)	—			1
Adjustment for debt extinguishment	—			—			(11		)	—			(11		)
Amortization of intangibles and out-of-market contracts	11			15			—			—			26
Amortization of unearned equity compensation	—			—			8			—			8
Impairment losses	—			140			6			—			146
Changes in deferred income taxes and liability for uncertain tax benefits	(613		)	(1,696		)	2,284			—			(25		)
Changes in nuclear decommissioning trust liability	9			—			—			—			9
Changes in derivative instruments	(28		)	(22		)	—			—			(50		)
Changes in collateral deposits supporting energy risk management activities	150			6			—			—			156
Proceeds from sale of emission allowances	47			—			—			—			47
Gain on sale of assets	—			(32		)	—			—			(32		)
Cash provided/(used) by changes in other working capital	338			1,728			(2,400		)	213			(121		)
Net Cash Provided/(Used) by Operating Activities	214			366			(26		)	—			554
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc.	—			(19		)	—			19			—
Acquisition of businesses, net of cash acquired	—			(6		)	—			—			(6		)
Capital expenditures	(44		)	(219		)	(16		)	—			(279		)
Increase in restricted cash, net	(2		)	(10		)	—			—			(12		)
Decrease in restricted cash - U.S. DOE funded projects	—			39			—			—			39
Decrease in notes receivable	—			1			—			—			1
Purchases of emission allowances	(12		)	—			—			—			(12		)
Proceeds from sale of emission allowances	7			—			—			—			7
Investments in nuclear decommissioning trust fund securities	(200		)	—			—			—			(200		)
Proceeds from sales of nuclear decommissioning trust fund securities	191			—			—			—			191
Proceeds from renewable energy grants and state rebates	—			8			—			—			8
Proceeds from sale of assets, net of cash disposed of	—			120			—			—			120
Investments in unconsolidated affiliates	—			(4		)	—			—			(4		)
Other	—			4			—			—			4
Net Cash Used by Investing Activities	(60		)	(86		)	(16		)	19			(143		)
Cash Flows from Financing Activities
Dividends from NRG Yield, Inc.	—			—			19			(19		)	—
Payments (for)/from intercompany loans	(151		)	(11		)	162						—
Payment of dividends to common and preferred stockholders	—			—			(48		)	—			(48		)
Net receipts for settlement of acquired derivatives that include financing elements	—			39			—			—			39
Proceeds from issuance of long-term debt	—			61			—			—			61
Payments for short and long-term debt	—			(121		)	(195		)	—			(316		)
Distributions from, net of contributions to, noncontrolling interest in subsidiaries	—			10			—			—			10
Other	(3		)	(7		)	—			—			(10		)
Net Cash Used by Financing Activities	(154		)	(29		)	(62		)	(19		)	(264		)
Effect of exchange rate changes on cash and cash equivalents	—			(6		)	—			—			(6		)
Net Increase/(Decrease) in Cash and Cash Equivalents	—			245			(104		)	—			141
Cash and Cash Equivalents at Beginning of Period	—			825			693			—			1,518
Cash and Cash Equivalents at End of Period	$	—		$	1,070		$	589		$	—		$	1,659


(a)	All significant intercompany transactions have been eliminated in consolidation.

ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

As you read this discussion and analysis, refer to NRG's Condensed Consolidated Statements of Operations to this Form 10-Q, which present the results of operations for the three months ended March 31, 2017 and 2016. Also refer to NRG's 2016 Form 10-K, which includes detailed discussions of various items impacting the Company's business, results of operations and financial condition, including: Introduction and Overview section; NRG's Business Strategy section; Business section, including how regulation, weather, and other factors affect NRG's business; and Critical Accounting Policies and Estimates section.

The discussion and analysis below has been organized as follows:


•	Executive summary, including introduction and overview, business strategy, and changes to the business environment during the period, including environmental and regulatory matters;


•	Results of operations;


•	Financial condition, addressing liquidity position, sources and uses of liquidity, capital resources and requirements, commitments, and off-balance sheet arrangements; and


•	Known trends that may affect NRG's results of operations and financial condition in the future.

Executive Summary

Introduction and Overview

The following table summarizes NRG's global generation portfolio as of March 31, 2017, by operating segment:



	Global Generation Portfolio^(a)
	(In MW)
	Generation
Generation Type	Gulf Coast	East	West	Other	Renewables ^(b)		NRG Yield ^(c)		Other ^(d)	Total Global
Natural gas^(e)	8,613	8,444	4,899	144	—		1,878		22	24,000
Coal	5,114	7,465	—	605	—		—		—	13,184
Oil	—	5,477	—	—	—		190		—	5,667
Nuclear	1,136	—	—	—	—		—		—	1,136
Wind	—	—	—	—	961		2,005		—	2,966
Utility Scale Solar	—	—	—	—	722		921		—	1,643
Distributed Solar	—	—	—	—	121		14		114	249
Total generation capacity^(f)	14,863	21,386	4,899	749	1,804		5,008		136	48,845
Capacity attributable to noncontrolling interest^(f)	—	—	—	—	(684	)	(2,252	)	—	(2,936	)
Total net generation capacity	14,863	21,386	4,899	749	1,120		2,756		136	45,909

(a) All Utility Scale Solar and Distributed Solar facilities are described in MW on an alternating current basis. MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units.

(b) Includes Distributed Solar capacity from assets held by DGPV Holdco 1 and DGPV Holdco 2.

(c) Does not include NRG Yield, Inc.'s thermal converted (MWt) capacity, which is part of the NRG Yield operating segment.

(d) The Distributed Solar figure within "Other" includes the aggregate production capacity of installed and activated residential solar energy systems. Also includes capacity from operating portfolios of residential solar assets held by RPV Holdco.

(e) Natural gas generation does not include 1,029 MW related to Pittsburg which GenOn Americas Generation deactivated on January 1, 2017, 51 MW related to the Miramar and El Cajon sites which were part of the San Diego Combustion Turbines and retired on January 1, 2017, and 106 MW related to Encina Unit 1 which was deactivated on March 31, 2017.

(f) NRG Yield's total generation capacity includes 6 MWs for noncontrolling interest for Spring Canyon II and III. NRG Yield's total generation capacity net of this noncontrolling interest was 5,002 MWs.

Strategy

NRG's strategy is to maximize stockholder value through the safe production and sale of reliable and affordable power to its customers in the markets served by the Company, while positioning the Company to meet the market's increasing demand for sustainable, low carbon and customized energy solutions for the benefit of the end-use energy consumer. This strategy is intended to enable the Company to achieve sustainable growth at reasonable margins while de-risking the Company in terms of reduced and mitigated exposure both to environmental risk and cyclical commodity price risk. At the same time, the Company's relentless commitment to safety for its employees, customers and partners continues unabated.

To effectuate the Company’s strategy, NRG is focused on: (i) excellence in operating performance of its existing assets including repowering its power generation assets at premium sites and optimal hedging of generation assets and retail load operations; (ii) serving the energy needs of end-use residential, commercial and industrial customers in competitive markets through multiple brands and channels with a variety of retail energy products and services differentiated by innovative features, premium service, sustainability, and loyalty/affinity programs; (iii) investing in alternative power generation technologies in its wholesale business, like wind and solar, and deploying innovative energy solutions for consumers within its retail businesses; and (iv) engaging in a proactive capital allocation plan focused on achieving the regular return of and on stockholder capital within the dictates of prudent balance sheet management, including pursuing selective acquisitions, joint ventures, divestitures and investments.

Regulatory Matters

The Company’s regulatory matters are described in the Company’s 2016 Form 10-K in Item 1, Business — Regulatory Matters. These matters have been updated below and in Note 15, Regulatory Matters, to the Condensed Consolidated Financial Statements of this Form 10-Q as found in Item 1.

As owners of power plants and participants in wholesale and retail energy markets, certain NRG entities are subject to regulation by various federal and state government agencies. These include the CFTC, FERC, NRC, and the PUCT, as well as other public utility commissions in certain states where NRG's generating, thermal, or distributed generation assets are located. In addition, NRG is subject to the market rules, procedures and protocols of the various ISO and RTO markets in which it participates. Likewise, certain NRG entities participating in the retail markets are subject to rules and regulations established by the states in which NRG entities are licensed to sell at retail. NRG must also comply with the mandatory reliability requirements imposed by NERC and the regional reliability entities in the regions where NRG operates.

NRG's operations within the ERCOT footprint are not subject to rate regulation by FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce. These operations are subject to regulation by the PUCT, as well as to regulation by the NRC with respect to NRG's ownership interest in STP.

East Region

PJM

PJM Seasonal Capacity Proceeding — On November 17, 2016, PJM proposed to allow winter- and summer-peaking capacity resources to “aggregate” their seasonal capacity into an annual capacity product eligible to participate as Capacity Performance resources. NRG filed comments specifically supporting PJM’s proposal to modify the aggregation rules to allow seasonal capacity resources to aggregate across LDAs and to allow aggregations through RPM auctions. On January 23, 2017, PJM amended its proposal to address questions from FERC. On March 21, 2017, FERC issued a decision accepting PJM's seasonal capacity aggregation filing. The outcome of this proceeding could have a material impact on future PJM capacity prices.

Complaints Regarding Pseudo-Ties for Capacity — On April 6, 2017, Potomac Economics, the market monitor for MISO and NYISO, filed a complaint against PJM regarding the participation of external capacity resources in PJM’s auction. Currently, external resources must enter into a pseudo-tie agreement in order to sell capacity into PJM. The complaint alleges that the pseudo-tie requirements is causing market inefficiencies in PJM, New York and MISO and suggests a new protocol for incorporating external resources into PJM’s markets. In addition, other market participants have filed separate complaints at FERC against MISO or PJM, respectively, for issues resulting from pseudo-tied generators. The complainants argue that the generation owners with pseudo-ties from MISO to PJM are receiving double-charges for congestion. The outcome could impact the PJM, NYISO and MISO capacity markets.

New England

2020/2021 ISO-NE Auction Results — On February 6, 2017, ISO-NE announced the results of its 2020/2021 forward capacity auction. NRG cleared 2,641 MW at $5.297 KW per month providing expected annual capacity revenues of $167.9 million. The 333 MWs at Canal Unit 3, which previously cleared the tenth forward capacity auction with a seven year price lock at a price of $7.17 KW per month for the 2020/2021 deliverability year, are excluded from these results.

Peak Energy Rent Adjustment Complaint — On September 30, 2016, the New England Power Generators Association, or NEPGA, filed a complaint against ISO-NE asking FERC to find the Peak Energy Rent, or PER, unjust and unreasonable. The PER adjustment reduces capacity payments on days where energy prices exceed a pre-defined level, known as the "PER strike price." On January 9, 2017, FERC granted NEPGA’s complaint requiring a change to the methodology used to calculate the PER strike price. FERC also directed the parties to determine any refunds for PER paid between September 30, 2016 and May 31, 2018. The parties are currently in settlement negotiations at FERC. The outcome of this matter will determine the amount of refunds that the NRG fleet may receive as a result of negotiating the PER strike price methodology.

New York

New York Public Service Commission Retail Energy Market Proceedings — On February 23, 2016, the NYSPSC issued what it refers to as its “Retail Reset” order, or Reset Order, in docket 12-M-0476 et al. Among other things, the Reset Order instituted a price cap on energy supply offers and required many retail providers to seek affirmative consent from certain retail customers over a very short period of time to retain those customers. Retail suppliers who cannot meet these conditions will be required to return their customers to energy supply service provided by the local utility. On July 25, 2016, the New York Supreme Court vacated part of the Reset Order on procedural grounds and remanded the matter to the NYSPSC for further consideration. Additionally, the Court affirmed the NYSPSC’s authority to regulate Energy Service Companies prices. The matter is now on appeal before the Supreme Court of New York, Appellate Division. On December 2, 2016 in the same docket, the NYSPSC issued notice of an evidentiary proceeding and collaborative process to determine the future structure of the retail energy market in New York. On January 26, 2017, the Administrative Law Judge assigned to the proceeding commenced the evidentiary proceeding, including discovery, and set a schedule for pre-filed testimony, with the evidentiary hearing set to commence in the summer of 2017. The collaborative process has not yet been commenced or scheduled. The outcome of this evidentiary and collaborative process, combined with the outcome of the appeal of the Reset Order, could affect the viability of the New York retail energy market.

Gulf Coast Region

ERCOT

Greens Bayou Unit 5 RMR Status — On March 29, 2016, NRG filed notice with ERCOT of its intent to mothball Greens Bayou Unit 5. On May 27, 2016, ERCOT made a final determination that the unit is needed for reliability must-run, or RMR, service to address potential operational contingencies. On June 14, 2016, the ERCOT Board confirmed ERCOT’s determination and approved a two-year RMR agreement, effective June 1, 2016 through June 30, 2018. ERCOT provided formal notice to NRG on February 27, 2017 that the RMR agreement will terminate on May 29, 2017. On March 31, 2017, NRG notified ERCOT that Greens Bayou Unit 5 will be returned to mothball status after the RMR agreement terminates.

West Region

CAISO

Puente Power Project — On May 26, 2016, the CPUC approved the resource adequacy purchase agreement, or RAPA, between SCE and NRG for the construction of the 262 MW natural gas peaking Puente Power Project. On July 1, 2016, four different parties sought rehearing of the CPUC's approval of the RAPA. On December 1, 2016, the CPUC affirmed approval of the RAPA in a rehearing decision. On January 4, 2017, a petition for request for review was filed in the California Court of Appeal seeking to reverse the CPUC's approval of the RAPA. Briefing in connection with the petition for request for review was completed on March 20, 2017 and the parties are now awaiting the court’s decision on whether to review the case. In addition, on March 10, 2017, the California Energy Commission, or CEC, the agency responsible for permitting Puente, issued an order requesting additional information after hearings had already concluded in February 2017. The CEC’s request will result in a several month delay in the processing of Puente’s permit; however, this permitting delay has not changed the project's estimated commercial operation date of the second quarter of 2020.

Environmental Matters

NRG is subject to a wide range of environmental laws in the development, construction, ownership and operation of projects. These laws generally require that governmental permits and approvals be obtained before construction and maintained during operation of power plants. NRG is also subject to laws regarding the protection of wildlife, including migratory birds, eagles and threatened and endangered species. Requirements regarding GHGs, combustion byproducts, water discharge and use, and threatened and endangered species have been put in place in recent years. However, under the new U.S. presidential administration, some of these rules are being reconsidered and reviewed. Future laws may require the addition of emissions controls or other environmental controls or impose restrictions on the operations of the Company's facilities, which could have a material effect on the Company's operations. Complying with environmental laws involves significant capital and operating expenses. NRG decides to invest capital for environmental controls based on the relative certainty of the requirements, an evaluation of compliance options, and the expected economic returns on capital.

A number of regulations with the potential to affect the Company and its facilities have been recently promulgated by the EPA but are being reconsidered, including ESPS/NSPS for GHGs, NAAQS revisions and implementation and effluent guidelines. NRG is evaluating the potential outcomes and any resulting impacts of recently promulgated regulations that the EPA is now reconsidering and cannot fully predict such impacts until administrative reconsiderations and legal challenges are resolved. Federal and state environmental laws generally have become more stringent over time, although this trend could slow or pause in the near term with respect to federal laws under the new U.S. presidential administration. The Company’s environmental matters are described in the Company’s 2016 Form 10-K in Item 1, Business - Environmental Matters and Item 1A, Risk Factors. These matters have been updated in Item 1 — Note 16, Environmental Matters, to the Condensed Consolidated Financial Statements of this Form 10-Q and as follows.

National

Air

The CAA and the resulting regulations (as well as similar state and local requirements) have the potential to affect air emissions, operating practices and pollution control equipment required at power plants. Under the CAA, the EPA sets NAAQS for certain pollutants including SO₂, ozone, and PM_2.5. Many of the Company's facilities are located in or near areas that are classified by the EPA as not achieving certain NAAQS (non-attainment areas). The relevant NAAQS have historically become more stringent. The Company maintains a comprehensive compliance strategy to address continuing and new requirements. Complying with increasingly stringent NAAQS could require the installation of additional emissions control equipment at some NRG facilities or retiring of units if installing such controls is not economical. Significant changes to air regulatory programs affecting the Company are described below.

Ozone NAAQS — On October 26, 2015, the EPA promulgated a rule that reduces the ozone NAAQS to 0.070 ppm. Challenges to this rule have been stayed at the request of the EPA so that it can evaluate the rule. If the rule is not altered by the EPA and survives legal challenges, this more stringent NAAQS will obligate the states to develop plans to reduce NO_x (an ozone precursor), which could affect some of the Company's units.

Clean Power Plan — The attention in recent years on GHG emissions has resulted in federal regulations and state legislative and regulatory action. In October 2015, the EPA finalized the Clean Power Plan, or CPP, addressing GHG emissions from existing EGUs. On February 9, 2016, the U.S. Supreme Court stayed the CPP. The D.C. Circuit, sitting all of the active judges, heard oral argument on the legal challenges to the CPP in September 2016. At the EPA's request, the D.C. Circuit agreed on April 28, 2017 to hold the case in abeyance for 60 days. Due to a recent Executive Order and various steps taken by the new U.S. presidential administration, the Company believes the CPP is not likely to survive.

Byproducts, Wastes, Hazardous Materials and Contamination

Nuclear Waste — The federal government's program to construct a nuclear waste repository at Yucca Mountain, Nevada was discontinued in 2010. Since 1998, the U.S. DOE has been in default of the federal government's obligations to begin accepting spent nuclear fuel, or SNF, and high-level radioactive waste, or HLW, under the U.S. Nuclear Waste Policy Act of 1982, or the Nuclear Waste Policy Act. Owners of nuclear plants, including the owners of STP, had been required to enter into contracts setting out the obligations of the owners and the U.S. DOE, including the fees to be paid by the owners for the U.S. DOE's services to license a spent fuel repository. Effective May 16, 2014, the U.S. DOE stopped collecting the fees.

On February 5, 2013, STPNOC entered into a settlement agreement with the U.S. DOE for payment of damages relating to the U.S. DOE's failure to accept SNF and HLW under the Nuclear Waste Policy Act through December 31, 2013, which was extended through an addendum dated January 24, 2014, to December 31, 2016. On December 12, 2016, STPNOC received the federal government's offer of another three-year extension of payment for continued failure to accept SNF and HLW. The proposal has been reviewed for adequacy and, with advice of counsel, was accepted. There are no facilities for the reprocessing or permanent disposal of SNF currently in operation in the U.S., nor has the NRC licensed any such facilities. STPNOC currently stores all SNF generated by its nuclear generating facilities in on-site storage pools. Since STPNOC's SNF storage pools do not have sufficient storage capacity for the life of the units, STPNOC is proceeding to construct dry cask storage capability on-site. STPNOC plans to continue to assert claims against the U.S. DOE for damages relating to the U.S. DOE's failure to accept SNF and HLW.

Under the federal Low-Level Radioactive Waste Policy Act of 1980, as amended, the state of Texas is required to provide, either on its own or jointly with other states in a compact, for the disposal of all low-level radioactive waste generated within the state. STP's warehouse capacity is adequate for on-site storage until a site in Andrews County, Texas becomes fully operational.

Regional Environmental Developments

East Region

Gulf Coast Region

Texas Regional Haze — In January 2016, the EPA promulgated a final rule that requires 15 coal-fired units (at eight plants in Texas) to reduce their SO₂ rates at various times over the next five years if the rule survives legal challenges. This Regional Haze rule was promulgated under the portion of the CAA that seeks to improve visibility at national parks. Eight of these 15 units already have scrubbers and seven do not. NRG owns two of the affected units, Limestone units 1 and 2, which already have scrubbers. The rule requires that the Limestone units reduce their SO₂ emission rates by 2019. In July 2016, the U.S. Court of Appeals for the Fifth Circuit stayed the rule pending resolution of the legal challenges. On December 2, 2016, the EPA filed a motion in the Fifth Circuit for partial voluntary remand and partial lifting of the stay, but did not request vacatur of the final rule. On March 22, 2017, the Fifth Circuit remanded the rule to the EPA so that it could reconsider the rule.

Illinois Union Insurance Company Litigation — On October 2, 2015, the U.S. District Court for the Middle District of Louisiana issued an order granting LaGen’s motion for summary judgment on its claims for declaratory judgment and breach of contract against ILU for its failure to indemnify LaGen for the costs LaGen paid pursuant to the consent decree that resolved the NSR lawsuit which was brought by the U.S. EPA and LA DEQ against LaGen related to Big Cajun II. The court entered judgment in favor of LaGen for approximately $27 million. In addition, the court ruled that LaGen is entitled to approximately $7 million for future consent decree costs as they are incurred. On October 14, 2015, ILU filed a motion to stay execution of the judgment, which was granted on October 19, 2015. Also, on October 14, 2015, ILU filed a notice to appeal the judgment. On January 14, 2016, the U.S. District Court granted LaGen's motion for attorney's fees of approximately $2 million for the indemnity phase of the litigation. On January 29, 2016, ILU filed an appeal brief with the U.S. Court of Appeals for the Fifth Circuit. The Court of Appeals issued a decision on August 4, 2016 which vacated the summary judgment ruling and remanded the case to the U.S. District Court. On March 21, 2017, the U.S. District Court issued an order extending the time for the parties to finalize a settlement until May 26, 2017.

Significant Events

The following significant events have occurred during 2017, as further described within this Management's Discussion and Analysis and the Condensed Consolidated Financial Statements:

Transfers of Assets Under Common Control

•

On March 27, 2017, the Company completed the sale of the following projects to NRG Yield, Inc.: (i) a 16% interest in the Agua Caliente solar project, and (ii) NRG's interests in seven utility-scale solar projects located in Utah, which have reached commercial operations, for $130 million cash consideration, as discussed in more detail in Note 3, Dispositions, to the Condensed Consolidated Financial Statements of this Form 10-Q.

Financing Activities


•	On February 28, 2017, letters of credit under NRG's revolving credit facility were drawn upon, which resulted in additional borrowings of $125 million, as discussed in more detail in Note 8, Debt and Capital Leases, to the Condensed Consolidated Financial Statements of this Form 10-Q.

Operational Matters

Carlsbad Energy Center Power Purchase Tolling Agreement

As of May 1, 2017, NRG’s subsidiary, Carlsbad Energy Center LLC, achieved the Conditions Precedent, or CP ,Satisfaction Date under the power purchase tolling agreement with San Diego Gas & Electric Company for the Carlsbad Energy Center. The CP Satisfaction Date is the date on which specified conditions precedent under the power purchase tolling agreement have either been satisfied or waived.

Sherwin Bankruptcy

The Company's Gregory cogeneration plant provided steam, processed water and a small percentage of its electrical generation to the Corpus Christi Sherwin Alumina plant pursuant to an Energy Service Agreement, or ESA. On January 11, 2016, Sherwin Alumina Company, or Sherwin, filed a voluntary petition with the United States Bankruptcy Court for the Southern District of Texas for relief under Title 11 of the United States Code. Sherwin agreed to pay all owed pre-petition amounts and, post-petition, Sherwin performed its obligations under the ESA through September 2016 when it shut down its operations. On September 28, 2016, Sherwin filed a motion with the Bankruptcy Court to reject the ESA, which includes Gregory's lease, effective September 29, 2016. Gregory objected to the rejection and is asserting its right to remain on its leasehold. A trial regarding the dispute was concluded on April 13, 2017. The parties await a decision by the court. The Company is currently evaluating potential options for the Gregory cogeneration plant.

Trends Affecting Results of Operations and Future Business Performance

The Company’s trends are described in the Company’s 2016 Form 10-K in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations - Trends Affecting Results of Operations and Future Business Performance.

Changes in Accounting Standards

See Note 2, Summary of Significant Accounting Policies, to the Condensed Consolidated Financial Statements of this Form 10-Q, for a discussion of recent accounting developments.

Consolidated Results of Operations

The following table provides selected financial information for the Company:



	Three months ended March 31,
(In millions except otherwise noted)	2017			2016			Change
Operating Revenues
Energy revenue^(a)	$	826		$	1,151		$	(325	)
Capacity revenue ^(a)	384			513			(129		)
Retail revenue	1,341			1,376			(35		)
Mark-to-market for economic hedging activities	128			26			102
Contract amortization	(15		)	(15		)	—
Other revenues ^(b)	95			178			(83		)
Total operating revenues	2,759			3,229			(470		)
Operating Costs and Expenses
Cost of sales ^(c)	1,404			1,505			101
Mark-to-market for economic hedging activities	134			(9		)	(143		)
Contract and emissions credit amortization ^(c)	(2		)	6			8
Operations and maintenance	485			588			103
Other cost of operations	104			104			—
Total cost of operations	2,125			2,194			69
Depreciation and amortization	300			313			13
Selling, general and administrative	272			252			(20		)
Development costs	17			26			9
Total operating costs and expenses	2,714			2,785			71
Gain on sale of assets	2			32			(30		)
Operating Income	47			476			(429		)
Other Income/(Expense)
Equity in earnings/(losses) of unconsolidated affiliates	5			(7		)	12
Impairment loss on investment	—			(146		)	146
Other income, net	12			18			(6		)
(Loss)/gain on debt extinguishment, net	(2		)	11			(13		)
Interest expense	(269		)	(284		)	15
Total other expense	(254		)	(408		)	154
(Loss)/Income before Income Taxes	(207		)	68			(275		)
Income tax (benefit)/expense	(4		)	21			(25		)
Net (Loss)/Income	(203		)	47			(250		)
Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interest	(40		)	(35		)	(5		)
Net (Loss)/Income Attributable to NRG Energy, Inc.	$	(163	)	$	82		$	(245	)
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	$	3.32		$	2.09		59		%

(a) Includes realized gains and losses from financially settled transactions.

(b) Includes unrealized trading gains and losses.

Management’s discussion of the results of operations for the three months ended March 31, 2017 and 2016

Electricity Prices

The following table summarizes average on peak power prices for each of the major markets in which NRG operates for the three months ended March 31, 2017 and 2016. The average on-peak power prices have generally increased primarily due to the increase in natural gas prices for the three months ended March 31, 2017 as compared to the same period in 2016.



	Average on Peak Power Price ($/MWh) ^(a)
	Three months ended March 31,
Region	2017		2016		Change %
Gulf Coast ^(b)
ERCOT - Houston	$	27.70	$	20.45	35	%
ERCOT - North	22.76		19.64		16	%
MISO - Louisiana Hub	44.77		23.50		91	%
East
NY J/NYC	35.59		33.30		7	%
NY A/West NY	27.61		30.27		(9	)%
NEPOOL	33.92		30.82		10	%
PEPCO (PJM)	33.72		34.36		(2	)%
PJM West Hub	31.96		30.30		5	%
West
CAISO - NP15	26.54		23.92		11	%
CAISO - SP15	23.08		23.32		(1	)%

(a) Average on peak power prices based on real time settlement prices as published by the respective ISOs.

(b) Gulf Coast region also transacts in PJM - West Hub.

The following table summarizes average realized power prices for each region in which NRG operates for the three months ended March 31, 2017 and 2016, which reflects the impact of settled hedges.



	Average Realized Power Price ($/MWh)
	Three months ended March 31,
Region	2017		2016		Change %
Gulf Coast	$	33.05	$	38.60	(14	)%
East	50.85		52.33		(3	)%
West	44.49		32.83		36	%

Though the average on peak power prices have increased on average by 14%, average realized prices by region for the Company have generally fluctuated at a slower rate year-over-year due to the Company's multi-year hedging program.

Gross Margin

The Company calculates gross margin in order to evaluate operating performance as operating revenues less cost of sales, which includes cost of fuel, other costs of sales, contract and emission credit amortization and mark-to-market for economic hedging activities.

Economic Gross Margin

In addition to gross margin, the Company evaluates its operating performance using the measure of economic gross margin, which is not a GAAP measure and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Economic gross margin should be viewed as a supplement to and not a substitute for the Company's presentation of gross margin, which is the most directly comparable GAAP measure. Economic gross margin is not intended to represent gross margin. The Company believes that economic gross margin is useful to investors as it is a key operational measure reviewed by the Company's chief operating decision maker. Economic gross margin is defined as the sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of fuels and other cost of sales.

Economic gross margin does not include mark-to-market gains or losses on economic hedging activities, contract amortization, emission credit amortization, or other operating costs.

The below tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended March 31, 2017 and 2016:



	Three months ended March 31, 2017
	Generation
(In millions)	Gulf Coast			East			West			Other		Eliminations			Subtotal			Retail			Renewables			NRG Yield			Corporate/Eliminations			Total
Energy revenue	$	412		$	411		$	23		$	1	$	—		$	847		$	—		$	72		$	114		$	(207	)	$	826
Capacity revenue	66			217			27			—		—			310			—			—			79			(5		)	384
Retail revenue	—			—			—			—		—			—			1,334			—			—			7			1,341
Mark-to-market for economic hedging activities	130			(2		)	4			—		—			132			2			6			—			(12		)	128
Contract amortization	3			—			—			—		—			3			(1		)	—			(17		)	—			(15		)
Other revenue ^(a)	50			(2		)	1			5		(3		)	51			—			20			42			(18		)	95
Operating revenue	661			624			55			6		(3		)	1,343			1,335			98			218			(235		)	2,759
Cost of fuel	(237		)	(187		)	(14		)	—		—			(438		)	(5		)	(1		)	(12		)	26			(430		)
Other cost of sales^(b)	(81		)	(77		)	(4		)	—		—			(162		)	(992		)	(3		)	(4		)	187			(974		)
Mark-to-market for economic hedging activities	(9		)	(1		)	3			—		—			(7		)	(139		)	—			—			12			(134		)
Contract and emission credit amortization	(5		)	5			2			—		—			2			—			—			—			—			2
Gross margin	$	329		$	364		$	42		$	6	$	(3	)	$	738		$	199		$	94		$	202		$	(10	)	$	1,223
Less: Mark-to-market for economic hedging activities, net	121			(3		)	7			—		—			125			(137		)	6			—			—			(6		)
Less: Contract and emission credit amortization, net	(2		)	5			2			—		—			5			(1		)	—			(17		)	—			(13		)
Economic gross margin	$	210		$	362		$	33		$	6	$	(3	)	$	608		$	337		$	88		$	219		$	(10	)	$	1,242
Business Metrics
MWh sold (thousands)^(c)(d)	12,467			8,082			517														930			1,662
MWh generated (thousands)^(e)	11,783			5,921			517														930			1,804
(a) Renewables other revenue includes $7 million of intercompany revenue to NRG Yield.
(b) Includes purchased energy, capacity and emissions credits
(c) MWh sold excludes generation at facilities in the East, West and NRG Yield that generate revenue under capacity agreements.
(d) Does not include thermal MWh of 9 thousand or MWt of 569 thousand for thermal sold by NRG Yield.
(e) Does not include thermal MWh of 16 thousand or MWt of 569 thousand for thermal generated by NRG Yield.



	Three months ended March 31, 2016
	Generation
(In millions)	Gulf Coast			East			West			Other		Eliminations			Subtotal			Retail			Renewables			NRG Yield			Corporate/Eliminations			Total
Energy revenue	$	468		$	605		$	28		$	28	$	—		$	1,129		$	—		$	85		$	129		$	(192	)	$	1,151
Capacity revenue	78			324			39			—		—			441			—			—			83			(11		)	513
Retail revenue	—			—			—			—		—			—			1,371			—			—			5			1,376
Mark-to-market for economic hedging activities	(28		)	31			—			—		—			3			—			1			—			22			26
Contract amortization	3			—			—			—		—			3			(1		)	—			(17		)	—			(15		)
Other revenue ^(a)	56			17			50			13		(4		)	132			—			10			39			(3		)	178
Operating revenue	577			977			117			41		(4		)	1,708			1,370			96			234			(179		)	3,229
Cost of fuel	(192		)	(242		)	(13		)	—		—			(447		)	(4		)	(1		)	(11		)	58			(405		)
Other cost of sales^(b)	(88		)	(126		)	(5		)	—		—			(219		)	(1,021		)	(1		)	(5		)	146			(1,100		)
Mark-to-market for economic hedging activities	2			(1		)	(3		)	—		—			(2		)	33			—			—			(22		)	9
Contract and emission credit amortization	(5		)	5			(1		)	—		—			(1		)	(2		)	—			(6		)	3			(6		)
Gross margin	$	294		$	613		$	95		$	41	$	(4	)	$	1,039		$	376		$	94		$	212		$	6		$	1,727
Less: Mark-to-market for economic hedging activities, net	(26		)	30			(3		)	—		—			1			33			1			—			—			35
Less: Contract and emission credit amortization, net	(2		)	5			(1		)	—		—			2			(3		)	—			(23		)	3			(21		)
Economic gross margin	$	322		$	578		$	99		$	41	$	(4	)	$	1,036		$	346		$	93		$	235		$	3		$	1,713
Business Metrics
MWh sold (thousands)^(c)(d)	12,123			11,561			853														1,089			1,778
MWh generated (thousands)^(e)	10,861			8,295			724														1,089			2,039
(a) Renewables other revenue includes $4 million of intercompany revenue to NRG Yield.
(b) Includes purchased energy, capacity and emissions credits
(c) MWh sold excludes generation at facilities in the East, West and NRG Yield that generate revenue under capacity agreements.
(d) Does not include thermal MWh of 40 thousand or MWt of 553 thousand for thermal sold by NRG Yield.
(e) Does not include thermal MWh of 91 thousand or MWt of 553 thousand for thermal generated by NRG Yield.

The table below represents the weather metrics for the three months ended March 31, 2017 and 2016:



	Three months ended March 31,
Weather Metrics	Gulf Coast	East	West
2017
CDDs ^(a)	204	37	3
HDDs ^(a)	631	2,137	1,119
2016
CDDs	76	33	5
HDDs	931	2,251	974
10 year average
CDDs	81	32	3
HDDs	1,086	2,487	1,111

(a)

National Oceanic and Atmospheric Administration-Climate Prediction Center - A Cooling Degree Day, or CDD, represents the number of degrees that the mean temperature for a particular day is above 65 degrees Fahrenheit in each region. A Heating Degree Day, or HDD, represents the number of degrees that the mean temperature for a particular day is below 65 degrees Fahrenheit in each region. The CDDs/HDDs for a period of time are calculated by adding the CDDs/HDDs for each day during the period.

Generation gross margin and economic gross margin

The below tables present the changes in Generation gross margin and economic gross margin which include intercompany sales, during the three months ended March 31, 2017, compared to the same period in 2016:



(In millions)	Gross Margin increase/(decrease)			Economic Gross Margin increase/(decrease)
Gulf Coast region	$	35		$	(112	)
East region	(249		)	(216		)
West region	(53		)	(66		)
Other	(35		)	(35		)
	$	(302	)	$	(429	)

The tables below describe the decrease in Generation gross margin and economic gross margin by region:

Gulf Coast Region



	(In millions)
Lower gross margin due to lower average realized prices primarily in Texas due to lower hedged power prices	$	(101	)
Lower gross margin primarily due to contract expirations and lower demand	(15		)
Lower gross margin due to a 66% decrease in ISO capacity prices and a 14% decrease in capacity volume	(14		)
Lower gross margin due to increased supply costs on load contracts	(8		)
Lower gross margin resulting from an 8% decrease in nuclear generation driven by the timing of planned outages	(7		)
Higher gross margin primarily due to higher coal generation mainly in Texas which was driven by the timing of planned outages	31
Other	2
Decrease in economic gross margin	$	(112	)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	147
Increase in gross margin	$	35

East Region



	(In millions)
Lower gross margin due to a 43% decrease in New York and New England hedged capacity prices and a 32% decrease in PJM cleared auction capacity prices	$	(77	)
Lower gross margin due to a 30% decrease in generation as a result of deactivating the Huntley and Dunkirk facilities in 2016, the sale of the Seward, Aurora and Shelby generating stations in 2016, as well as milder winter weather conditions in 2017	(55		)
Lower gross margin due to a 32% increase in the price of natural gas and transportation costs due to less favorable short-term natural gas contract terms, as well as a 2% decrease in average realized energy prices	(35		)
Lower gross margin due to higher supply costs for servicing certain load contracts	(22		)
Lower gross margin due to lower contracted volumes and prices in New York	(17		)
Changes in commercial optimization activities	(17		)
Higher gross margin due to fewer outage hours primarily in PJM, due to unit conversions and deactivations	12
Other	(5		)
Decrease in economic gross margin	$	(216	)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(33		)
Decrease in gross margin	$	(249	)

West Region



	(In millions)
Lower gross margin due to the gain on sale of excess emission credits in 2016	$	(47	)
Lower gross margin due to a 45% decrease in capacity volume primarily due to the retirement of the Pittsburg generating station, partially offset by a 14% increase in capacity prices	(16		)
Other	(3		)
Decrease in economic gross margin	$	(66	)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	10
Increase in contract and emission credit amortization	3
Decrease in gross margin	$	(53	)

Other

Other gross margin and economic gross margin both decreased $35 million for the three months ended March 31, 2017, compared to the same period in 2016, due to BETM losses on both over the counter and congestion strategies.

Retail gross margin and economic gross margin

The following is a discussion of gross margin and economic gross margin for Retail.



	Three months ended March 31,
(In millions except otherwise noted)	2017			2016
Retail revenue	$	1,295		$	1,340
Supply management revenue	33			24
Capacity revenue	6			7
Customer mark-to-market	2			—
Contract amortization	(1		)	(1		)
Operating revenue^(a)	1,335			1,370
Cost of sales ^(b)	(997		)	(1,025		)
Mark-to-market for economic hedging activities	(139		)	33
Contract amortization	—			(2		)
Gross Margin	$	199		$	376
Less: Mark-to-market for economic hedging activities, net	(137		)	33
Less: Contract and emission credit amortization, net	(1		)	(3		)
Economic Gross Margin	$	337		$	346

Business Metrics
Mass electricity sales volume - GWh - Gulf Coast	6,984			6,713
Mass electricity sales volume - GWh - All other regions	1,641			1,834
C&I electricity sales volume — GWh - All regions	4,833			4,540
Natural gas sales volumes (MDth)	1,262			923
Average Retail Mass customer count (in thousands)	2,826			2,760
Ending Retail Mass customer count (in thousands)	2,832			2,759


(a)	Includes intercompany sales of $1 million and $3 million in 2017 and 2016, respectively, representing sales from Retail to the Gulf Coast region.


(b)	Includes intercompany purchases of $209 million and $192 million in 2017 and 2016, respectively.

Retail gross margin decreased $177 million and economic gross margin decreased $9 million for the three months ended March 31, 2017, compared to the same period in 2016, due to:



	(In millions)
Weather driven gross margin is lower by $12 million due to a reduction in load of 308,000 MWhs and $7 million in lower margin due to the unfavorable impacts of selling back excess supply in 2017 as compared to 2016	$	(19	)
Lower gross margin due to lower rates to customers of $54 million, or approximately $6 per MWh, partially offset by lower supply costs of $45 million, or approximately $5 per MWh driven primarily by a decrease in power prices at the time of procurement	(9		)
Higher gross margin due to higher volumes driven by higher average customer usage and mix and an increase in customer count	19
Decrease in economic gross margin	$	(9	)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(170		)
Increase in contract and emission credit amortization	2
Decrease in gross margin	$	(177	)

NRG Yield gross margin and economic gross margin

NRG Yield gross margin decreased $10 million and economic gross margin decreased $16 million for the three months ended March 31, 2017, compared to the same period in 2016, due to a 17% decrease in volume generated at the Alta Wind projects due to low wind resources as well as a 14% decrease in solar generation at solar projects caused by weather.

Mark-to-market for Economic Hedging Activities

Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges and ineffectiveness on cash flow hedges. Total net mark-to-market results decreased by $41 million during the three months ended March 31, 2017, compared to the same period in 2016.

The breakdown of gains and losses included in operating revenues and operating costs and expenses by region was as follows:



	Three months ended March 31, 2017
	Generation
	Gulf Coast			East			West			Retail			Renewables		Elimination^(a)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	—		$	(20	)	$	(1	)	$	—		$	—	$	40		$	19
Reversal of acquired loss positions related to economic hedges	—			2			—			—			—		—			2
Net unrealized gains/(losses) on open positions related to economic hedges	130			16			5			2			6		(52		)	107
Total mark-to-market gains/(losses) in operating revenues	$	130		$	(2	)	$	4		$	2		$	6	$	(12	)	$	128
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(3	)	$	6		$	3		$	31		$	—	$	(40	)	$	(3	)
Net unrealized (losses)/gains on open positions related to economic hedges	(6		)	(7		)	—			(170		)	—		52			(131		)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(9	)	$	(1	)	$	3		$	(139	)	$	—	$	12		$	(134	)


(a)	Represents the elimination of the intercompany activity between Retail and Generation.



	Three months ended March 31, 2016
	Generation
	Gulf Coast			East			West			Retail			Renewables		Elimination^(a)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(139	)	$	(134	)	$	(1	)	$	—		$	—	$	43		$	(231	)
Reversal of acquired gain positions related to economic hedges	—			(11		)	—			—			—		—			(11		)
Net unrealized gains/(losses) on open positions related to economic hedges	111			176			1			—			1		(21		)	268
Total mark-to-market (losses)/gains in operating revenues	$	(28	)	$	31		$	—		$	—		$	1	$	22		$	26
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	11		$	36		$	(1	)	$	142		$	—	$	(43	)	$	145
Reversal of acquired gain positions related to economic hedges	—			—			(2		)	—			—		—			(2		)
Net unrealized (losses)/gains on open positions related to economic hedges	(9		)	(37		)	—			(109		)	—		21			(134		)
Total mark-to-market gains/(losses) in operating costs and expenses	$	2		$	(1	)	$	(3	)	$	33		$	—	$	(22	)	$	9


(a)	Represents the elimination of the intercompany activity between Retail and Generation.

Mark-to-market results consist of unrealized gains and losses on contracts that are not yet settled. The settlement of these transactions is reflected in the same revenue or cost caption as the items being hedged.

The reversals of acquired gain or loss positions were valued based upon the forward prices on the acquisition date.

For the three months ended March 31, 2017, the $128 million gain in operating revenues from economic hedge positions was driven primarily by an increase in value of open positions as a result of decreases in natural gas and ERCOT electricity prices, as well as the reversal of previously recognized unrealized losses on contracts that settled during the period and the reversal of acquired contracts. The $134 million loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in value of open positions as a result of decreases in natural gas, coal, and ERCOT electricity prices.

For the three months ended March 31, 2016, the $26 million gain in operating revenues from economic hedge positions was driven primarily by an increase in value of open positions as a result of decreases in electricity prices, largely offset by the reversal of previously recognized unrealized gains on contracts that settled during the period and the reversal of acquired contracts. The $9 million gain in operating costs and expenses from economic hedge positions was driven primarily by the reversal of previously recognized unrealized losses on contracts that settled during the period, largely offset by a decrease in value of open positions as a result of decreases in natural gas, coal, and ERCOT electricity prices.

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the three months ended March 31, 2017 and 2016. The realized and unrealized financial and physical trading results are included in operating revenue within the Generation segment. The Company's trading activities are subject to limits within the Company's Risk Management Policy and are primarily transacted through BETM.



	Three months ended March 31,
(In millions)	2017			2016
Trading gains/(losses)
Realized	$	14		$	24
Unrealized	(14		)	19
Total trading gains	$	—		$	43

Operations and Maintenance Expense



	Generation											Retail		Renewables		NRG Yield		Corporate			Eliminations			Total
	Gulf Coast		East		West		Other		Eliminations			Retail		Renewables		NRG Yield		Corporate			Eliminations			Total
	(In millions)
Three months ended March 31, 2017	$	146	$	187	$	27	$	—	$	(3	)	$	59	$	29	$	51	$	(1	)	$	(10	)	$	485
Three months ended March 31, 2016	$	144	$	272	$	36	$	—	$	(4	)	$	60	$	33	$	44	$	9		$	(6	)	$	588

Operations and maintenance expense decreased by $103 million for the three months ended March 31, 2017, compared to the same period in 2016, primarily due to an $85 million decrease in expenses in the East region as a result of fewer planned outages, less deactivation activity, sales of facilities in 2016, and a decrease in expenses due to environmental control and fuel conversion expenses incurred in 2016. In addition, expenses for the West region decreased by $9 million primarily due to the timing of planned outages.

Depreciation and Amortization

Depreciation and amortization expense decreased by $13 million for the three months ended March 31, 2017, compared to the same period in 2016, primarily due to a decrease in depreciation expense for facilities that were impaired in 2016.

Selling, General and Administrative Expenses



	Generation		Retail		Renewables		NRG Yield		Corporate		Total
	Generation		Retail		Renewables		NRG Yield		Corporate		Total
	(In millions)
Three months ended March 31, 2017	$	82	$	119	$	15	$	5	$	51	$	272
Three months ended March 31, 2016	$	86	$	111	$	14	$	3	$	38	$	252

Selling, general and administrative expenses increased by $20 million for the three months ended March 31, 2017, compared to the same period in 2016. The increase was due primarily to $14 million of costs incurred related to advisors engaged to assist the Company in its strategic review and $11 million of costs incurred in connection with advisors and other consultants engaged to assist the Company with GenOn's ability to continue as a going concern. After giving consideration to the increase for these costs, remaining selling, general and administrative expenses decreased quarter over quarter.

Impairment Losses on Investments

During the first quarter of 2016, the Company recorded other-than-temporary impairment losses of $146 million, primarily due to its 50% interest in Petra Nova Parish Holdings, as further described in Note 7, Impairments, of this Form 10-Q.

Interest Expense

NRG's interest expense decreased by $15 million for the three months ended March 31, 2017, compared to the same period in 2016 due to the following:



	(In millions)
Decrease due to the repurchases of Senior Notes in 2016 of $55 million, offset by $39 million in Senior Notes issued in 2016	$	(16	)
Decrease in derivative interest expense from changes in fair value of interest rate swaps	(11		)
Increase due to the issuance of Utah Portfolio debt, due 2022 and CVSR Holdco Notes, due 2037 during 2016	6
Increase due to interest expense related to Midwest Generation financing	4
Other	2
	$	(15	)

Income Tax (Benefit)/Expense

For the three months ended March 31, 2017, NRG recorded an income tax benefit of $4 million on a pre-tax loss of $207 million. For the same period in 2016, NRG recorded an income tax expense of $21 million on pre-tax income of $68 million. The effective tax rate was 1.9% and 30.9% for the three months ended March 31, 2017 and 2016, respectively.

For the three months ended March 31, 2016, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the change in the valuation allowance, partially offset by the recording of a deferred liability associated with the amortization of indefinite lived assets.

Net loss attributable to noncontrolling interests and redeemable noncontrolling interests

For the three months ended March 31, 2017 and 2016, net loss attributable to noncontrolling interests and redeemable noncontrolling interests primarily reflects net losses allocated to tax equity investors in tax equity arrangements using the hypothetical liquidation at book value, or HLBV, method, as well as NRG Yield, Inc.'s share of net loss.

Liquidity and Capital Resources

Liquidity Position

As of March 31, 2017 and December 31, 2016, NRG's liquidity, excluding collateral received, was approximately $3.3 billion and $3.6 billion, respectively, comprised of the following:



(In millions)	March 31, 2017		December 31, 2016
Cash and cash equivalents:
NRG excluding NRG Yield and GenOn	$	415	$	622
NRG Yield and subsidiaries	213		317
GenOn and subsidiaries	885		1,034
Restricted cash - operating	68		56
Restricted cash - reserves^(a)	329		390
Total	1,910		2,419
Total credit facility availability	1,364		1,217
Total liquidity, excluding collateral received	$	3,274	$	3,636

^(a) Includes reserves primarily for debt service, performance obligations, and capital expenditures

For the three months ended March 31, 2017, total liquidity, excluding collateral funds deposited by counterparties, decreased by $362 million. Changes in cash and cash equivalents balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents at March 31, 2017 were predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt.

Management believes that the Company's liquidity position and cash flows from operations will be adequate to finance operating and maintenance capital expenditures, to fund dividends to NRG's common stockholders, and to fund other liquidity commitments with the exception of commitments related to GenOn as further described below. Management continues to regularly monitor the Company's ability to finance the needs of its operating, financing and investing activity within the dictates of prudent balance sheet management.

Restricted Payments Tests

Of the $1.5 billion of cash and cash equivalents of the Company as of March 31, 2017, $305 million and $82 million were held by GenOn Mid-Atlantic and REMA, respectively. The ability of certain of GenOn’s and GenOn Americas Generation’s subsidiaries to pay dividends and make distributions is restricted under the terms of certain agreements, including the GenOn Mid-Atlantic and REMA operating leases. Under their respective operating leases, GenOn Mid-Atlantic and REMA are not permitted to make any distributions and other restricted payments unless: (a) they satisfy the fixed charge coverage ratio for the most recently ended period of four fiscal quarters; (b) they are projected to satisfy the fixed charge coverage ratio for each of the two following periods of four fiscal quarters, commencing with the fiscal quarter in which such payment is proposed to be made; and (c) no significant lease default or event of default has occurred and is continuing. In addition, prior to making a dividend or other restricted payment, GenOn Mid-Atlantic and REMA must be in compliance with the requirement to provide credit support to the owner lessors securing their obligations to pay scheduled rent under their respective leases. Based on GenOn Mid-Atlantic’s and REMA’s most recent calculations of these tests, GenOn Mid-Atlantic and REMA did not satisfy the restricted payments tests. As a result, as of March 31, 2017, GenOn Mid-Atlantic and REMA could not make distributions of cash and certain other restricted payments. Each of GenOn Mid-Atlantic and REMA may recalculate its fixed charge coverage ratios from time to time and, subject to compliance with the restricted payments test described above, make dividends or other restricted payments.

To the extent GenOn Mid-Atlantic or REMA are able to pay dividends to GenOn, the GenOn Senior Notes due 2018 and 2020 and the related indentures restrict the ability of GenOn to incur additional liens and make certain restricted payments, including dividends. In the event of a default or if restricted payment tests are not satisfied, GenOn would not be able to distribute cash to its parent, NRG. At March 31, 2017, GenOn did not meet the consolidated debt ratio component of the restricted payments test.

GenOn Liquidity

As disclosed in Note 8, Debt and Capital Leases, to this Form 10-Q, $691 million of GenOn's Senior Notes, excluding $4 million of associated premiums, are current within the GenOn consolidated balance sheet as of March 31, 2017 and are due on June 15, 2017. GenOn's future profitability continues to be adversely affected by (i) a sustained decline in natural gas prices and its resulting effect on wholesale power prices and capacity prices, and (ii) the inability of GenOn Mid-Atlantic and REMA to make distributions of cash and certain other restricted payments to GenOn. GenOn is currently considering all options available to it, including negotiations with creditors and lessors, refinancing the GenOn Senior Notes, potential sales of certain generating assets as well as the possibility for a need to file for protection under Chapter 11 of the U.S. Bankruptcy Code. If GenOn is unable to enter into a settlement with its creditors, refinance the senior notes or otherwise raise or generate sufficient capital, GenOn is not expected to have sufficient liquidity (exclusive of cash subject to the restrictions under the GenOn Mid-Atlantic and REMA operating leases) to repay the Senior Notes due in June 2017. Pending resolution, there is substantial doubt about GenOn's ability to continue as a going concern. As a result of the substantial doubt about GenOn’s ability to continue as a going concern, along with additional factors, there is substantial doubt about certain of GenOn’s subsidiaries’ ability to continue as a going concern.

During 2016, GenOn appointed two independent directors, retained advisors and established a separate audit committee as part of this process. On April 7, 2017, GenOn also appointed a new dedicated chief executive officer, effective immediately. Any resolution may have a material impact on the Company's statement of operations, cash flows and financial position.

The Company, GenOn's parent company, has no obligation to provide any financial support to GenOn other than under the secured intercompany revolving credit agreement between the Company and GenOn and NRG Americas. As of March 31, 2017, $214 million was available to be used by GenOn under the $500 million revolving credit agreement. As controlled group members, ERISA requires that NRG and GenOn are jointly and severally liable for the NRG Pension Plan for Bargained Employees and the NRG Pension Plan, including the pension liabilities associated with GenOn employees.

Credit Ratings

On January 10, 2017, GenOn's corporate credit rating was lowered by S&P to CCC- from CCC. The ratings outlook for GenOn, GenOn Americas Generation, GenOn Mid-Atlantic and REMA is negative. In addition, S&P also lowered the issue-level ratings on the GenOn Senior Notes to CCC from CCC+, the GenOn Americas Generation Senior Notes to CCC- from CCC, and the pass-through certificates at REMA and GenOn Mid-Atlantic to CCC+ from B-.

The following table summarizes the Company's credit ratings as of March 31, 2017:



	S&P	Moody's
NRG Energy, Inc.	BB- Stable	Ba3 Stable
7.625% Senior Notes, due 2018	BB-	B1
7.875% Senior Notes, due 2021	BB-	B1
6.25% Senior Notes, due 2022	BB-	B1
6.625% Senior Notes, due 2023	BB-	B1
6.25% Senior Notes, due 2024	BB-	B1
7.25% Senior Notes, due 2026	BB-	B1
6.625% Senior Notes, due 2027	BB-	B1
Term Loan Facility, due 2023	BB+	Baa3
GenOn 7.875% Senior Notes, due 2017	CCC	Caa3
GenOn 9.500% Senior Notes, due 2018	CCC	Caa3
GenOn 9.875% Senior Notes, due 2020	CCC	Caa3
GenOn Americas Generation 8.500% Senior Notes, due 2021	CCC-	Caa3
GenOn Americas Generation 9.125% Senior Notes, due 2031	CCC-	Caa3
NRG Yield, Inc.	BB	Ba2
5.375% NRG Yield Operating LLC Senior Notes, due 2024	BB	Ba2
5.00% NRG Yield Operating LLC Senior Notes, due 2026	BB	Ba2

Sources of Liquidity

The principal sources of liquidity for NRG's future operating and capital expenditures are expected to be derived from new and existing financing arrangements, existing cash on hand, cash flows from operations and cash proceeds from future sales of assets, including sales to NRG Yield, Inc. As described in Note 8, Debt and Capital Leases, to this Form 10-Q and Note 12, Debt and Capital Leases, to the Company's 2016 Form 10-K, the Company's financing arrangements consist mainly of the Senior Credit Facility, the Senior Notes, the GenOn Senior Notes, the GenOn Americas Generation Senior Notes, the NRG Yield 2019 Convertible Notes, the NRG Yield 2020 Convertible Notes, the NRG Yield Operating LLC senior unsecured notes, the NRG Yield, Inc. revolving credit facility, and project-related financings.

ROFO Agreement Expansion

On February 24, 2017, the Company amended and restated the ROFO Agreement to expand the ROFO assets pipeline with the addition of 234 net MW of utility-scale solar projects. These assets include Buckthorn Solar, a 154 net MW facility located in Texas, and the Hawaii Solar projects, which have a combined capacity of 80 net MW.

Sale of Assets to NRG Yield, Inc.

On March 27, 2017, the Company sold (i) a 16% interest in the Agua Caliente solar project, representing ownership of approximately 46 net MW of capacity and (ii) NRG's interests in seven utility-scale solar projects located in Utah representing 265 net MW of capacity which have reached commercial operations to NRG Yield, Inc. NRG Yield Inc. paid cash consideration of $130 million, plus $1 million in working capital adjustments, and assumed non-recourse project debt of approximately $328 million.

2023 Term Loan Facility

On January 24, 2017, NRG repriced the 2023 Term Loan Facility, reducing the interest rate margin by 50 basis points to LIBOR plus 2.25%, the LIBOR floor remains 0.75%. As a result of the repricing, the Company expects interest savings of approximately $9 million in 2017 and approximately $60 million in interest savings over the life of the loan.

First Lien Structure

NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, excluding assets acquired through GenOn and EME (including Midwest Generation), assets held by NRG Yield, Inc., and NRG's assets that have project-level financing. NRG uses the first lien structure to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or gas used as a proxy for power. To the extent that the underlying hedge positions for a counterparty are out-of-the-money to NRG, the counterparty would have claim under the first lien program. The first lien program limits the volume that can be hedged, not the value of underlying out-of-the-money positions. The first lien program does not require NRG to post collateral above any threshold amount of exposure. Within the first lien structure, the Company can hedge up to 80% of its coal and nuclear capacity, excluding GenOn and Midwest Generation's coal capacity, and 10% of its other assets, excluding GenOn's other assets with these counterparties for the first 60 months and then declining thereafter. Net exposure to a counterparty on all trades must be positively correlated to the price of the relevant commodity for the first lien to be available to that counterparty. The first lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty and has no stated maturity date.

The Company's first lien counterparties may have a claim on its assets to the extent market prices exceed the hedged prices. As of March 31, 2017, all hedges under the first liens were out-of-the-money on a counterparty aggregate basis.

The following table summarizes the amount of MW hedged against the Company's coal and nuclear assets and as a percentage relative to the Company's coal and nuclear capacity under the first lien structure as of March 31, 2017:



Equivalent Net Sales Secured by First Lien Structure ^(a)	2017		2018		2019		2020		2021
In MW	2,150		1,158		—		—		—
As a percentage of total net coal and nuclear capacity ^(b)	40	%	21	%	—	%	—	%	—	%


(a)	Equivalent net sales include natural gas swaps converted using a weighted average heat rate by region.


(b)	Net coal and nuclear capacity represents 80% of the Company’s total coal and nuclear assets eligible under the first lien which excludes coal assets acquired in the GenOn and EME (Midwest Generation) acquisitions, assets in NRG Yield, Inc. and NRG's assets that have project level financing.

Uses of Liquidity

The Company's requirements for liquidity and capital resources, other than for operating its facilities, can generally be categorized by the following: (i) commercial operations activities; (ii) debt service obligations; (iii) capital expenditures, including repowering and renewable development, and environmental; and (iv) allocations in connection with acquisition opportunities, debt repayments, return of capital and dividend payments to stockholders.

Commercial Operations

NRG's commercial operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) margin and collateral required to participate in physical markets and commodity exchanges; (iii) timing of disbursements and receipts (i.e. buying fuel before receiving energy revenues); (iv) initial collateral for large structured transactions; and (v) collateral for project development. As of March 31, 2017, commercial operations had total cash collateral outstanding of $277 million, and $861 million outstanding in letters of credit to third parties primarily to support its commercial activities for both wholesale and retail transactions. As of March 31, 2017, total collateral held from counterparties was $3 million in cash and $16 million in letters of credit.

Future liquidity requirements may change based on the Company's hedging activities and structures, fuel purchases, and future market conditions, including forward prices for energy and fuel and market volatility. In addition, liquidity requirements are dependent on NRG's credit ratings and general perception of its creditworthiness.

Capital Expenditures

The following tables and descriptions summarize the Company's capital expenditures for maintenance, environmental, and growth investments for the three months ended March 31, 2017, and the currently estimated capital expenditure and growth investments forecast for the remainder of 2017.



	Maintenance		Environmental		Growth Investments			Total
	(In millions)
Generation
Gulf Coast	$	40	$	1	$	1		$	42
East	19		24		15			58
West	—		—		81			81
Other	1		—		—			1
Retail	6		—		4			10
Renewables	1		—		67			68
NRG Yield	4		—		—			4
Corporate^(b)	1		—		3			4
Total cash capital expenditures for the three months ended March 31, 2017	72		25		171			268
Funding from third party equity partners, cash grants and debt financing, net of fees	—		—		(51		)	(51		)
Other investments ^(a)	—		—		33			33
Total capital expenditures and investments, net of financings	72		25		153			250

Estimated capital expenditures for the remainder of 2017	221		25		625			871
Funding from third party equity partners, cash grants and debt financing, net of fees	—		—		(611		)	(611		)
Other investments ^(a)	—		—		26			26
NRG estimated capital expenditures for the remainder of 2017, net of financings	$	221	$	25	$	40		$	286


(a)	Other investments include restricted cash activity.


•	Environmental capital expenditures — For the three months ended March 31, 2017, the Company's environmental capital expenditures included DSI/ESP upgrades at the Powerton facility and the Joliet gas conversion to satisfy CPS as well as controls to satisfy MATS at the Avon Lake Facility.


•	Growth Investments capital expenditures — For the three months ended March 31, 2017, the Company's growth investment capital expenditures included $88 million for repowering projects, $55 million for solar projects, $12 million for wind projects, $9 million for fuel conversions and $7 million for the Company's other growth projects.

Environmental Capital Expenditures

NRG estimates that environmental capital expenditures from 2017 through 2021 required to comply with environmental laws will be approximately $132 million which includes $61 million for GenOn and $38 million for Midwest Generation. These costs are primarily associated with the cost of complying with the ELG requirements as they exist today. As discussed in Item 1 - Note 16, Environmental Matters, the ELG rule has been challenged. The Company expects to reduce its estimate of the environmental capital expenditures that would be required to comply with permits issued that incorporate the revised ELG guidelines.

Dividends

The following table lists the dividends paid during the three months ended March 31, 2017:



	First Quarter 2017
Dividends per Common Share	$	0.030

On April 7, 2017, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable May 15, 2017, to stockholders of record as of May 1, 2017 representing $0.12 on an annualized basis.

The Company's common stock dividends are subject to available capital, market conditions, and compliance with associated laws, regulations and other contractual obligations. The Company expects that, based on current circumstances, comparable cash dividends will continue to be paid in the foreseeable future.

GenOn Mid-Atlantic Long-Term Deposits

On January 27, 2017, GenOn Mid-Atlantic entered into an agreement with Natixis under which Natixis will procure payment and credit support for the payment of certain lease payments owed pursuant to the GenOn Mid-Atlantic operating leases for Morgantown and Dickerson. GenOn Mid-Atlantic made a payment of $130 million plus fees of $1 million as consideration for Natixis applying for the issuance of, and obtaining, letters of credit from Natixis, New York Branch, the LC Provider, to support the lease payments. Natixis is solely responsible for (i) obtaining letters of credit from the LC Provider, (ii) causing the letters of credit to be issued to the lessors to support the lease payments on behalf of GenOn Mid-Atlantic, (iii) making lease payments and (iv) satisfying any reimbursement obligations payable to the LC Provider.

On February 24, 2017, GenOn Mid-Atlantic received a series of notices from certain of the owner lessors under its operating leases of the Morgantown coal generation unit alleging default, or Notices. The Notices allege the existence of lease events of default as a result of, among other items, the purported failure by GenOn Mid-Atlantic to comply with a covenant requiring the maintenance of qualifying credit support. The Notices instructed the relevant trustees to draw on letters of credit under the secured intercompany revolving credit agreement between NRG and GenOn, supporting the GenOn Mid-Atlantic operating leases that were set to expire on February 28, 2017. The offset was recorded to other non-current assets under the related operating leases pending resolution of the matter which is further described below. On February 28, 2017, the trustees drew on the letters of credit under NRG's revolving credit facility, which resulted in borrowings of $125 million. Upon notification, GenOn became obligated under the secured intercompany revolving credit agreement between NRG and GenOn. GenOn requested GenOn Mid-Atlantic repay the related amount borrowed under the secured intercompany revolving credit agreement. GenOn Mid-Atlantic is unaware of whether any further action will be taken by the owner lessors or any other person in connection with the Notices. GenOn Mid-Atlantic disagrees with the owner lessors as to the existence of any lease events of default and/or any breaches by GenOn Mid-Atlantic of any terms and conditions of the operating leases and believes that the declaration of a lease event of default, the instruction to draw on the letters of credit under the secured intercompany revolving credit agreement between NRG and GenOn and the draws thereon constituted a violation by the owner lessors and the relevant trustees of the terms and conditions of the GenOn Mid-Atlantic operating leases. GenOn Mid-Atlantic intends to vigorously pursue its rights and remedies in connection with these actions. On March 7, 2017, GenOn Mid-Atlantic filed a complaint in the Supreme Court for the State of New York against the owner lessors of the Morgantown and Dickerson facilities and U.S. Bank National Association in its capacity as the indenture trustee. The complaint seeks, inter alia, a declaratory judgment that no lease events of default exist and asserts counts for breach of contract, conversion, tortious interference, breach of the implied covenant of good faith and fair dealing, unjust enrichment, constructive trust, and injunctive relief. The defendants in this action have not yet responded to the complaint and have until June 5, 2017 to do so. The court has set an initial conference hearing for June 12, 2017.

Fuel Repowerings

The table below lists the Company's currently projected repowering and conversion projects. With respect to facilities that are currently operating, the timing of the projects listed below could adversely impact the Company's operating revenues, gross margin and other operating costs during the period prior to the targeted COD.



Facility	Net Generation Capacity (MW)	Project Type	Fuel Type	Targeted COD
Repowerings
Carlsbad Peakers (formerly Encina) Units 1, 2, 3, 4, 5 and GT	527	Growth	Natural Gas	Q4 2018
Puente (formerly Mandalay) Units 1 and 2^(a)	262	Growth	Natural Gas	Q2 2020
Bacliff (formerly Cielo Lindo/PH Robinson) Peakers 1-6	360	Growth	Natural Gas	Q2 2017
Total Fuel Repowerings	1,149

(a) Projects are subject to applicable regulatory approvals and permits.

Cash Flow Discussion

The following table reflects the changes in cash flows for the comparative three month periods:



	Three months ended March 31,
	2017			2016			Change
	(In millions)
Net cash used by operating activities	$	(68	)	$	554		$	(622	)
Net cash used by investing activities	(232		)	(143		)	(89		)
Net cash used by financing activities	(153		)	(264		)	111

Net Cash Used By Operating Activities

Changes to net cash used by operating activities were driven by:



	(In millions)
Changes in cash collateral in support of risk management activities due to changes in commodity prices	$	(230	)
Decrease in operating income adjusted for non-cash items	(215		)
Increase due to lower generation in the first quarter of 2017, combined with earlier inventory purchases in the fourth quarter of 2015 for anticipated 2016 generation requirements	(119		)
Increase in accounts receivable due to lower overall revenue rates and receipt of Cottonwood insurance proceeds	(59		)
Other	1
	$	(622	)

Net Cash Used By Investing Activities

Changes to net cash used by investing activities were driven by:



	(In millions)
Decrease in proceeds from the sale of assets primarily related to the sale of the Seward and Shelby generating stations in 2016	$	(106	)
Net decrease in nuclear decommissioning trust fund activity	(27		)
Increase in investments in unconsolidated affiliates, primarily related to the 2016 utility-scale solar and wind asset acquisitions	(8		)
Decrease in restricted cash primarily due to decreases in the Alta Wind, CVSR, Agua Caliente and SPP Fund accounts of $49 million, offset by an increase in Solar Partners LLC of $32 million	22
Increase in insurance proceeds received in 2017, related to the Cottonwood generation station outage in 2016	18
Decrease in capital expenditures for environmental and maintenance projects of $76 million primarily for Powerton and Joliet capitalized in 2016, offset by an increase in growth projects of $96 million primarily for repowering and solar projects	11
Other	1
	$	(89	)

Net Cash Used By Financing Activities

Changes to net cash used by financing activities were driven by:



	(In millions)
Increase in borrowings, primarily related to Agua Caliente Borrower 1 & 2, 2038 Senior Notes as well as reduced payments due to repurchases of Senior Notes in 2016	$	270
Decrease in payment of dividends, primarily related to reduction of NRG dividend rate in the first quarter of 2016	39
Payment for credit support in long-term deposits	(130		)
Decrease in financing element related to acquired derivatives	(38		)
Increase in debt issuance cost primarily due to repricing of the 2023 Senior Notes and the issuance of the Agua Caliente 1 & 2, 2038 Senior Notes	(15		)
Decrease in cash contributions from non-controlling interest in 2017	(15		)
	$	111

NOLs, Deferred Tax Assets and Uncertain Tax Position Implications, under ASC 740

For the three months ended March 31, 2017, the Company had a total domestic pre-tax book loss of $208 million and foreign pre-tax book income of $1 million. As of December 31, 2016, the Company has cumulative domestic Federal NOL carryforwards of $3.4 billion which will begin expiring in 2026 and cumulative state NOL carryforwards of $4.9 billion for financial statement purposes. In addition, NRG has cumulative foreign NOL carryforwards of $196 million, which do not have an expiration date.

In addition to these amounts, the Company has $35 million of tax effected uncertain tax benefits. As a result of the Company's tax position, and based on current forecasts, NRG anticipates income tax payments, primarily to state and local jurisdictions, of up to $35 million in 2017.

The Company has recorded a non-current tax liability of $38 million until final resolution with the related taxing authority. The $38 million non-current tax liability for uncertain tax benefits is from positions taken on various state income tax returns, including accrued interest.

NRG is subject to examination by taxing authorities for income tax returns filed in the U.S. federal jurisdiction and various state and foreign jurisdictions including operations located in Australia. The Company is not subject to U.S. federal income tax examinations for years prior to 2015. With few exceptions, state and local income tax examinations are no longer open for years prior to 2010. The Company's primary foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2010.

Off-Balance Sheet Arrangements

Obligations under Certain Guarantee Contracts

NRG and certain of its subsidiaries enter into guarantee arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include financial and performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications.

Retained or Contingent Interests

NRG does not have any material retained or contingent interests in assets transferred to an unconsolidated entity.

Obligations Arising Out of a Variable Interest in an Unconsolidated Entity

Variable interest in equity investments — As of March 31, 2017, NRG has several investments with an ownership interest percentage of 50% or less in energy and energy-related entities that are accounted for under the equity method of accounting. Several of these investments are variable interest entities for which NRG is not the primary beneficiary. See also Note 9, Variable Interest Entities, or VIEs, to this Form 10-Q.

NRG's pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $628 million as of March 31, 2017. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG. See also Note 16, Investments Accounted for by the Equity Method and Variable Interest Entities, to the Company's 2016 Form 10-K.

Contractual Obligations and Commercial Commitments

NRG has a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to the Company's capital expenditure programs, as disclosed in the Company's 2016 Form 10-K. See also Note 8, Debt and Capital Leases, and Note 14, Commitments and Contingencies, to this Form 10-Q for a discussion of new commitments and contingencies that also include contractual obligations and commercial commitments that occurred during the three months ended March 31, 2017.

Fair Value of Derivative Instruments

NRG may enter into power purchase and sales contracts, fuel purchase contracts and other energy-related financial instruments to mitigate variability in earnings due to fluctuations in spot market prices and to hedge fuel requirements at generation facilities or retail load obligations. In addition, in order to mitigate interest rate risk associated with the issuance of the Company's variable rate and fixed rate debt, NRG enters into interest rate swap agreements. The following disclosures about fair value of derivative instruments provide an update to, and should be read in conjunction with, Fair Value of Derivative Instruments in Item 7 — Management's Discussion and Analysis of Financial Condition and Results of Operations, of the Company's 2016 Form 10‑K.

The tables below disclose the activities that include both exchange and non-exchange traded contracts accounted for at fair value in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820. Specifically, these tables disaggregate realized and unrealized changes in fair value; disaggregate estimated fair values at March 31, 2017, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at March 31, 2017.



Derivative Activity Losses	(In millions)
Fair Value of Contracts as of December 31, 2016	$	(127	)
Contracts realized or otherwise settled during the period	(16		)
Changes in fair value	(11		)
Fair Value of Contracts as of March 31, 2017	$	(154	)



	Fair Value of Contracts as of March 31, 2017
	Maturity
Fair value hierarchy Gains/(Losses)	1 Year or Less			Greater than 1 Year to 3 Years			Greater than 3 Years to 5 Years			Greater than 5 Years			Total Fair Value
	(In millions)
Level 1	$	9		$	(58	)	$	(13	)	$	—		$	(62	)
Level 2	(39		)	6			(2		)	1			(34		)
Level 3	(35		)	(11		)	(5		)	(7		)	(58		)
Total	$	(65	)	$	(63	)	$	(20	)	$	(6	)	$	(154	)

The Company has elected to present derivative assets and liabilities on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. Also, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. Consequently, the magnitude of the changes in individual current and non-current derivative assets or liabilities is higher than the underlying credit and market risk of the Company's portfolio. As discussed in Item 3 — Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, to this Form 10-Q, NRG measures the sensitivity of the Company's portfolio to potential changes in market prices using VaR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG's risk management policy places a limit on one-day holding period VaR, which limits the Company's net open position. As the Company's trade-by-trade derivative accounting results in a gross-up of the Company's derivative assets and liabilities, the net derivative asset and liability position is a better indicator of NRG's hedging activity. As of March 31, 2017, NRG's net derivative liability was $154 million, a decrease to total fair value of $27 million as compared to December 31, 2016. This decrease was driven by the roll-off of trades that settled during the period and losses in fair value.

Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase in natural gas prices across the term of the derivative contracts would result in an increase of approximately $66 million in the net value of derivatives as of March 31, 2017. The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of derivative contracts would result in a decrease of approximately $82 million in the net value of derivatives as of March 31, 2017.

Critical Accounting Policies and Estimates

NRG's discussion and analysis of the financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance as well as the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingent assets and liabilities. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges, and the fair value of certain assets and liabilities. These judgments, in and of themselves, could materially affect the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment may also have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies has not changed.

On an ongoing basis, NRG evaluates these estimates, utilizing historic experience, consultation with experts and other methods the Company considers reasonable. In any event, actual results may differ substantially from the Company's estimates. Any effects on the Company's business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the information that gives rise to the revision becomes known.

The Company identifies its most critical accounting policies as those that are the most pervasive and important to the portrayal of the Company's financial position and results of operations, and that require the most difficult, subjective and/or complex judgments by management regarding estimates about matters that are inherently uncertain. NRG's critical accounting policies include derivative instruments, income taxes and valuation allowance for deferred tax assets, impairment of long lived assets and investments, goodwill and other intangible assets, and contingencies.

The Company performs its annual test of goodwill impairment during the fourth quarter. The Company tests its long-lived assets for impairment whenever indicators of impairment exist. The Company notes that if natural gas prices continue to decrease, this could have a negative impact on the fair value of the reporting units that have goodwill balances and recovery of long-lived assets. Additionally, continued decreases in natural gas prices could result in an adverse change in the manner that long-lived assets are used, or result in the Company selling an asset before the end of its previously estimated useful life, at a price that is lower than its carrying amount. Accordingly, if these decreases continue, it is possible that the Company's goodwill or long-lived assets will be impaired.

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

NRG is exposed to several market risks in the Company's normal business activities. Market risk is the potential loss that may result from market changes associated with the Company's merchant power generation or with an existing or forecasted financial or commodity transaction. The types of market risks the Company is exposed to are commodity price risk, interest rate risk, liquidity risk, credit risk and currency exchange risk. The following disclosures about market risk provide an update to, and should be read in conjunction with, Item 7A — Quantitative and Qualitative Disclosures About Market Risk, of the Company's 2016 Form 10-K.

Commodity Price Risk

Commodity price risks result from exposures to changes in spot prices, forward prices, volatilities and correlations between various commodities, such as natural gas, electricity, coal, oil and emissions credits. NRG manages the commodity price risk of the Company's merchant generation operations and load serving obligations by entering into various derivative or non-derivative instruments to hedge the variability in future cash flows from forecasted sales and purchases of electricity and fuel. NRG measures the risk of the Company's portfolio using several analytical methods, including sensitivity tests, scenario tests, stress tests, position reports and VaR. NRG uses a Monte Carlo simulation based VaR model to estimate the potential loss in the fair value of its energy assets and liabilities, which includes generation assets, load obligations and bilateral physical and financial transactions.

The following table summarizes average, maximum and minimum VaR for NRG's commodity portfolio, including generation assets, load obligations and bilateral physical and financial transactions, calculated using the VaR model for the three months ending March 31, 2017 and 2016:



(In millions)	2017		2016
VaR as of March 31,	$	60	$	59
Three months ended March 31,
Average	$	52	$	54
Maximum	60		60
Minimum	41		44

In order to provide additional information for comparative purposes to NRG's peers, the Company also uses VaR to estimate the potential loss of derivative financial instruments that are subject to mark-to-market accounting. These derivative instruments include transactions that were entered into for both asset management and trading purposes. The VaR for the derivative financial instruments calculated using the diversified VaR model as of March 31, 2017, for the entire term of these instruments entered into for both asset management and trading was $19 million, primarily driven by asset-backed transactions.

Interest Rate Risk

NRG is exposed to fluctuations in interest rates through its issuance of variable rate debt. Exposures to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument. NRG's risk management policies allow the Company to reduce interest rate exposure from variable rate debt obligations.

The Company's project subsidiaries enter into interest rate swaps, intended to hedge the risks associated with interest rates on non-recourse project level debt. See Note 12, Debt and Capital Leases, of the Company's 2016 Form 10-K for more information on the Company's interest rate swaps.

If all of the above swaps had been discontinued on March 31, 2017, the Company would have owed the counterparties $30 million. Based on the credit ratings of the counterparties, NRG believes its exposure to credit risk due to nonperformance by counterparties to its hedge contracts to be insignificant.

NRG has both long and short-term debt instruments that subject the Company to the risk of loss associated with movements in market interest rates. As of March 31, 2017, a 1% change in variable interest rates would result in a $12.8 million change in interest expense on a rolling twelve month basis.

As of March 31, 2017, the fair value and related carrying value of the Company's debt was $18.7 billion and $19.5 billion, respectively. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company's long-term debt by $1.5 billion.

Liquidity Risk

Liquidity risk arises from the general funding needs of NRG's activities and in the management of the Company's assets and liabilities. The Company is currently exposed to additional collateral posting if natural gas prices decline primarily due to the long natural gas equivalent position at various exchanges used to hedge NRG's retail supply load obligations.

Based on a sensitivity analysis for power and gas positions under marginable contracts, a $0.50 per MMBtu change in natural gas prices across the term of the marginable contracts would cause a change in margin collateral posted of approximately $220 million as of March 31, 2017, and a 1 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral posted of approximately $176 million as of March 31, 2017. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of March 31, 2017.

Credit Risk

Credit risk relates to the risk of loss resulting from non-performance or non-payment by counterparties pursuant to the terms of their contractual obligations. NRG is exposed to counterparty credit risk through various activities including wholesale sales, fuel purchases and retail supply arrangements, and retail customer credit risk through its retail load activities. See Note 4, Fair Value of Financial Instruments, to this Form 10-Q for discussions regarding counterparty credit risk and retail customer credit risk, and Note 6, Accounting for Derivative Instruments and Hedging Activities, to this Form 10-Q for discussion regarding credit risk contingent features.

Currency Exchange Risk

NRG's foreign earnings and investments may be subject to foreign currency exchange risk, which NRG generally does not hedge. As these earnings and investments are not material to NRG's consolidated results, the Company's foreign currency exposure is limited.

ITEM 4 — CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Under the supervision and with the participation of NRG's management, including its principal executive officer, principal financial officer and principal accounting officer, NRG conducted an evaluation of the effectiveness of the design and operation of its disclosure controls and procedures, as such term is defined in Rules 13a-15(e) or 15d-15(e) of the Exchange Act. Based on this evaluation, the Company's principal executive officer, principal financial officer and principal accounting officer concluded that the disclosure controls and procedures were effective as of the end of the period covered by this Quarterly Report on Form 10-Q.

Changes in Internal Control over Financial Reporting

There were no changes in NRG’s internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the first quarter of 2017 that materially affected, or are reasonably likely to materially affect, NRG’s internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

For a discussion of material legal proceedings in which NRG was involved through March 31, 2017, see Note 14, Commitments and Contingencies, to this Form 10-Q.

ITEM 1A — RISK FACTORS

Information regarding risk factors appears in Part I, Item 1A, Risk Factors Related to NRG Energy, Inc., in the Company's 2016 Form 10-K. There have been no material changes in the Company's risk factors since those reported in its 2016 Form 10‑K.

ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3 — DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4 — MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5 — OTHER INFORMATION

None.

ITEM 6 — EXHIBITS



Number	Description	Method of Filing
10.1*	NRG Energy, Inc. Amended and Restated Long-Term Incentive Plan.	Incorporated herein by reference to Exhibit 10.1 to the Registrant's Current Report on Form 8-K filed on April 28, 2017.
10.2*	NRG Energy, Inc. Amended and Restated Employee Stock Purchase Plan.	Incorporated herein by reference to Exhibit 10.2 to the Registrant's Current Report on Form 8-K filed on April 28, 2017.
31.1	Rule 13a-14(a)/15d-14(a) certification of Mauricio Gutierrez.	Filed herewith.
31.2	Rule 13a-14(a)/15d-14(a) certification of Kirkland B. Andrews.	Filed herewith.
31.3	Rule 13a-14(a)/15d-14(a) certification of David Callen.	Filed herewith.
32	Section 1350 Certification.	Furnished herewith.
101 INS	XBRL Instance Document.	Filed herewith.
101 SCH	XBRL Taxonomy Extension Schema.	Filed herewith.
101 CAL	XBRL Taxonomy Extension Calculation Linkbase.	Filed herewith.
101 DEF	XBRL Taxonomy Extension Definition Linkbase.	Filed herewith.
101 LAB	XBRL Taxonomy Extension Label Linkbase.	Filed herewith.
101 PRE	XBRL Taxonomy Extension Presentation Linkbase.	Filed herewith.

* Exhibit relates to compensation arrangements.

SIGNATURES

Pursuant to the requirements 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.



	NRG ENERGY, INC. (Registrant)

	/s/ MAURICIO GUTIERREZ
	Mauricio Gutierrez
	Chief Executive Officer (Principal Executive Officer)


	/s/ KIRKLAND B. ANDREWS
	Kirkland B. Andrews
	Chief Financial Officer (Principal Financial Officer)


	/s/ DAVID CALLEN
	David Callen
Date: May 2, 2017	Chief Accounting Officer (Principal Accounting Officer)