NRG ENERGY, INC. - Quarter Report: 2016 March (Form 10-Q)

Large accelerated filer x

Accelerated filer o

Non-accelerated filer o

Smaller reporting company o

(Do not check if a smaller reporting company)

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, 2016

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.)

211 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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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, 2016, there were 314,908,041 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	10
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES	10
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	49
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	75
ITEM 4 — CONTROLS AND PROCEDURES	77
PART II — OTHER INFORMATION	78
ITEM 1 — LEGAL PROCEEDINGS	78
ITEM 1A — RISK FACTORS	78
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	78
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES	78
ITEM 4 — MINE SAFETY DISCLOSURES	78
ITEM 5 — OTHER INFORMATION	78
ITEM 6 — EXHIBITS	79
SIGNATURES	80

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, 2015, and the following:


•	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, 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, manage capital expenditures and costs tightly, 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 and increased regulation of carbon dioxide and other GHG emissions;


•	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 as it becomes subject to capacity performance requirements in PJM and new performance incentives in ISO-NE;


•	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 agreed upon 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 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:



2015 Form 10-K		NRG’s Annual Report on Form 10-K for the year ended December 31, 2015
AEP		American Electric Power Company Inc.
ARO		Asset Retirement Obligation
ASC		The FASB Accounting Standards Codification, which the FASB established as the source of authoritative U.S. 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
B2B		Business-to-business, which includes demand response, commodity sales, energy efficiency and energy management services
BACT		Best Available Control Technology
BETM		Boston Energy Trading and Marketing LLC
BTU		British Thermal Unit
Buffalo Bear		Buffalo Bear, LLC, the operating subsidiary of Tapestry Wind LLC, which owns the Buffalo Bear project
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
CAISO		California Independent System Operator
CDD		Cooling Degree Day
CDFW		California Department of Fish and Wildlife
CDWR		California Department of Water and 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
CERT		Combustion Emissions Reduction Technologies, LLC
CFTC		U.S. Commodity Futures Trading Commission
COD		Commercial Operation Date
ComEd		Commonwealth Edison
Company		NRG Energy, Inc.
CPP		Clean Power Plan
CPS		Combined Pollutant Standard
CPUC		California Public Utilities Commission
CSAPR		Cross-State Air Pollution Rule
CVSR		California Valley Solar Ranch
CWA		Clean Water Act
D.C. Circuit		U.S. Court of Appeals for the District of Columbia Circuit
DGPV Holdco		NRG DGPV Holdco 1 LLC
Discrete Customers		Customers measured by unit sales of one-time products or services, such as connected home thermostats, portable solar products and portable battery solutions
Distributed Solar		Solar power projects that primarily sell power produced to customers for usage on site, or are interconnected to sell power into the local distribution grid
DNREC		Delaware Department of Natural Resources and Environmental Control
DSI		Dry Sorbent Injection with Trona
Economic gross margin		Sum of energy revenue, capacity revenue, retail revenue and other revenue, less cost of sales



EGU		Electric Generating Unit
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 and Energy Plus Natural Gas LLC
EPA		U.S. Environmental Protection Agency
ERCOT		Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
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
FirstEnergy		FirstEnergy Corp.
FPA		Federal Power Act
FTRs		Financial Transmission Rights
GenConn		GenConn Energy LLC
GenOn		GenOn Energy, Inc.
GenOn Americas Generation		GenOn Americas Generation, LLC
GenOn Americas Generation Senior Notes		GenOn Americas Generation's $694 million outstanding unsecured senior notes consisting of $365 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 $489 million of 9.875% senior notes due 2020
GHG		Greenhouse Gases
GWh		Gigawatt Hour
HAPs		Hazardous Air Pollutants
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
High Desert		TA - High Desert, LLC, which owns the High Desert project
HLBV		Hypothetical Liquidation at Book Value
HLM		High Lonesome Mesa, LLC
IASB		Independent Accounting Standards Board
ICAP		New York Installed Capacity
IFRS		International Financial Reporting Standards
IL CPS		Illinois Combined Pollutant Standard
ILU		Illinois Union Insurance Company
ISO		Independent System Operator
ISO-NE		ISO New England Inc.
January 2015 Drop Down Assets		The Laredo Ridge, Tapestry and Walnut Creek projects, which were sold to NRG Yield, Inc. on January 2, 2015
kWh		Kilowatt-hours



Laredo Ridge		Laredo Ridge Wind, LLC, the operating subsidiary of Mission Wind Laredo, LLC, which owns the Laredo Ridge project
LIBOR		London Inter-Bank Offered Rate
LTIPs		Collectively, the NRG Long-Term Incentive Plan and the NRG GenOn Long-Term Incentive Plan
Marsh Landing		NRG Marsh Landing, LLC (formerly known as GenOn Marsh Landing, LLC)
MATS		Mercury and Air Toxics Standards promulgated by the EPA
MDE		Maryland Department of the Environment
Midwest Generation		Midwest Generation, LLC
MISO		Midcontinent Independent System Operator, Inc.
MMBtu		Million British Thermal Units
MW		Megawatt
MWG		Midwest Generation, LLC
MWh		Saleable megawatt hours, net of internal/parasitic load megawatt-hours
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
NOV		Notice of Violation
NO_x		Nitrogen Oxide
NPDES		National Pollutant Discharge Elimination System
NPNS		Normal Purchase Normal Sale
NRC		U.S. Nuclear Regulatory Commission
NRG		NRG Energy, Inc.
NRG Wind TE Holdco		NRG Wind TE Holdco LLC
NRG Yield		Reporting segment that includes the projects held 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 53.3% of NRG Yield LLC with a controlling interest, and issuer of publicly held shares of Class A and Class C common stock
NRG Yield LLC		NRG Yield LLC, which owns, through its wholly owned subsidiary, NRG Yield Operating LLC, all of the assets contributed to NRG Yield LLC in connection with the initial public offering of Class A common stock of NRG Yield, Inc.
NSR		New Source Review
NSPS		New Source Performance Standards
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		Other Comprehensive Income/(Loss)
Peaking		Units expected to satisfy demand requirements during the periods of greatest or peak load on the system
PG&E		Pacific Gas and Electric Company



Pinnacle		Pinnacle Wind, LLC, the operating subsidiary of Tapestry Wind LLC, which owns the Pinnacle project
PJM		PJM Interconnection, LLC
PM		Particulate Matter
PPA		Power Purchase Agreement
PPTA		Power Purchase Tolling Agreement
PSD		Prevention of Significant Deterioration
PUCN		Public Utilities Commission of Nevada
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
Reliant Energy		Reliant Energy Retail Services, LLC
Repowering		Technologies utilized to replace, rebuild, or redevelop major portions of an existing electrical generating facility, generally to achieve a substantial emissions reduction, increase facility capacity, and improve system efficiency
RESA		Retail Electric Supply Association
Retail Mass		Residential and Small Business
Revolving Credit Facility		The Company's $2.5 billion revolving credit facility due 2018, a component of the Senior Credit Facility
RGGI		Regional Greenhouse Gas Initiative
Right of First Offer Agreement		Amended and Restated Right of First Offer Agreement by and between NRG Energy, Inc. and NRG Yield, Inc.
RMR		Reliability Must-Run
RPV Holdco		NRG RPV Holdco 1 LLC
RTO		Regional Transmission Organization
SCE		Southern California Edison
SCR		Selective Catalytic Reduction Control System
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		NRG's senior secured facility, comprised of the Term Loan Facility and the Revolving Credit Facility
Senior Notes		The Company’s $6.0 billion outstanding unsecured senior notes, consisting of $958 million of 7.625% senior notes due 2018, $1.1 billion of 8.25% senior notes due 2020, $1.1 billion of 7.875% senior notes due 2021, $1.1 billion of 6.25% senior notes due 2022, $910 million of 6.625% senior notes due 2023, and $848 million of 6.25% senior notes due 2024
Seward		The Seward Power Generation Plant
SF6		Sulfur Hexafluoride
Shelby		The Shelby County Generating Station
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
SunPower		SunPower Corporation, Systems
Taloga		Taloga Wind, LLC, the operating subsidiary of Tapestry Wind LLC, which owns the Taloga project
TCPA		Telephone Consumer Protection Act



Term Loan Facility		The Company's $2.0 billion term loan facility due 2018, a component of the Senior Credit Facility
TOU		Time-of-use
TSA		Transportation Services Agreement
TWCC		Texas Westmoreland Coal Co.
U.S.		United States of America
U.S. DOE		U.S. Department of Energy
U.S. GAAP		Accounting principles generally accepted in the U.S.
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
Yield Operating		NRG Yield Operating LLC

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)	2016			2015
Operating Revenues
Total operating revenues	$	3,229		$	3,829
Operating Costs and Expenses
Cost of operations	2,189			3,063
Depreciation and amortization	313			395
Selling, general and administrative	255			265
Acquisition-related transaction and integration costs	2			10
Development activity expenses	26			34
Total operating costs and expenses	2,785			3,767
Gain on sale of assets and postretirement benefits curtailment	32			14
Operating Income	476			76
Other Income/(Expense)
Equity in losses of unconsolidated affiliates	(7		)	(3		)
Impairment loss on investment	(146		)	—
Other income, net	18			19
Gain on debt extinguishment	11			—
Interest expense	(284		)	(301		)
Total other expense	(408		)	(285		)
Income/(Loss) Before Income Taxes	68			(209		)
Income tax expense/(benefit)	21			(73		)
Net Income/(Loss)	47			(136		)
Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interests	(35		)	(16		)
Net Income/(Loss) Attributable to NRG Energy, Inc.	82			(120		)
Dividends for preferred shares	5			5
Income/(Loss) Available for Common Stockholders	$	77		$	(125	)
Earnings/(Loss) per Share Attributable to NRG Energy, Inc. Common Stockholders
Weighted average number of common shares outstanding — basic	315			336
Earnings/(Loss) per Weighted Average Common Share — Basic	$	0.24		$	(0.37	)
Weighted average number of common shares outstanding — diluted	315			336
Earnings/(Loss) per Weighted Average Common Share — Diluted	$	0.24		$	(0.37	)
Dividends Per Common Share	$	0.15		$	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,
	2016			2015
	(In millions)
Net Income/(Loss)	$	47		$	(136	)
Other Comprehensive Income/(Loss), net of tax
Unrealized loss on derivatives, net of income tax expense/(benefit) of $1 and ($6)	(32		)	(12		)
Foreign currency translation adjustments, net of income tax benefit of $0 and $(7)	6			(11		)
Available-for-sale securities, net of income tax benefit of $0 and $(4)	3			(1		)
Defined benefit plans, net of tax expense of $0 and $4	1			7
Other comprehensive loss	(22		)	(17		)
Comprehensive Income/(Loss)	25			(153		)
Less: Comprehensive loss attributable to noncontrolling interest and redeemable noncontrolling interests	(52		)	(29		)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	77			(124		)
Dividends for preferred shares	5			5
Comprehensive Income/(Loss) Available for Common Stockholders	$	72		$	(129	)

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS



	March 31, 2016			December 31, 2015
(In millions, except shares)	(unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	1,659		$	1,518
Funds deposited by counterparties	101			106
Restricted cash	387			414
Accounts receivable — trade, less allowance for doubtful accounts of $19 and $21	1,018			1,157
Inventory	1,161			1,252
Derivative instruments	2,113			1,915
Cash collateral paid in support of energy risk management activities	411			568
Renewable energy grant receivable, net	35			13
Current assets held-for-sale	—			6
Prepayments and other current assets	461			442
Total current assets	7,346			7,391
Property, plant and equipment, net of accumulated depreciation of $7,093 and $6,804	18,763			18,732
Other Assets
Equity investments in affiliates	898			1,045
Notes receivable, less current portion	40			53
Goodwill	999			999
Intangible assets, net of accumulated amortization of $1,592 and $1,525	2,256			2,310
Nuclear decommissioning trust fund	577			561
Derivative instruments	465			305
Deferred income taxes	185			167
Non-current assets held-for-sale	—			105
Other non-current assets	1,151			1,214
Total other assets	6,571			6,759
Total Assets	$	32,680		$	32,882
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	465		$	481
Accounts payable	845			869
Derivative instruments	1,947			1,721
Cash collateral received in support of energy risk management activities	100			106
Current liabilities held-for-sale	—			2
Accrued expenses and other current liabilities	981			1,196
Total current liabilities	4,338			4,375
Other Liabilities
Long-term debt and capital leases	18,677			18,983
Nuclear decommissioning reserve	330			326
Nuclear decommissioning trust liability	294			283
Deferred income taxes	37			19
Derivative instruments	627			493
Out-of-market contracts, net of accumulated amortization of $687 and $664	1,122			1,146
Non-current liabilities held-for-sale	—			4
Other non-current liabilities	1,547			1,488
Total non-current liabilities	22,634			22,742
Total Liabilities	26,972			27,117
2.822% convertible perpetual preferred stock	304			302
Redeemable noncontrolling interest in subsidiaries	23			29
Commitments and Contingencies
Stockholders’ Equity
Common stock	4			4
Additional paid-in capital	8,299			8,296
Retained deficit	(2,977		)	(3,007		)
Less treasury stock, at cost — 102,450,781 and 102,749,908 shares, respectively	(2,406		)	(2,413		)
Accumulated other comprehensive loss	(195		)	(173		)
Noncontrolling interest	2,656			2,727
Total Stockholders’ Equity	5,381			5,434
Total Liabilities and Stockholders’ Equity	$	32,680		$	32,882

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,
	2016			2015
	(In millions)
Cash Flows from Operating Activities
Net Income/(loss)	$	47		$	(136	)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates	17			32
Depreciation and amortization	313			395
Provision for bad debts	10			15
Amortization of nuclear fuel	13			13
Amortization of financing costs and debt discount/premiums	1			(4		)
Adjustment for debt extinguishment	(11		)	—
Amortization of intangibles and out-of-market contracts	26			19
Amortization of unearned equity compensation	8			11
Impairment losses	146			—
Changes in deferred income taxes and liability for uncertain tax benefits	(25		)	(83		)
Changes in nuclear decommissioning trust liability	9			(3		)
Changes in derivative instruments	(50		)	261
Proceeds from sale of emission allowances	47			—
Changes in collateral deposits supporting energy risk management activities	156			(213		)
Gain on sale of assets and postretirement benefits curtailment	(32		)	(14		)
Cash used by changes in other working capital	(121		)	(33		)
Net Cash Provided by Operating Activities	554			260
Cash Flows from Investing Activities
Acquisitions of businesses, net of cash acquired	(6		)	(1		)
Capital expenditures	(279		)	(252		)
Increase in restricted cash, net	(12		)	(11		)
Decrease in restricted cash to support equity requirements for U.S. DOE funded projects	39			25
Decrease in notes receivable	1			5
Purchases of emission allowances	(12		)	—
Proceeds from sale of emission allowances	7			—
Investments in nuclear decommissioning trust fund securities	(200		)	(193		)
Proceeds from the sale of nuclear decommissioning trust fund securities	191			196
Proceeds from renewable energy grants and state rebates	8			2
Proceeds from sale of assets, net of cash disposed of	120			—
Investments in unconsolidated affiliates	(4		)	(44		)
Other	4			3
Net Cash Used by Investing Activities	(143		)	(270		)
Cash Flows from Financing Activities
Payment of dividends to common and preferred stockholders	(48		)	(51		)
Payment for treasury stock	—			(79		)
Net receipts from settlement of acquired derivatives that include financing elements	39			40
Proceeds from issuance of long-term debt	61			248
Distributions from, net of contributions to, noncontrolling interest in subsidiaries	10			(25		)
Proceeds from issuance of common stock	—			1
Payments for short and long-term debt	(316		)	(94		)
Other - contingent consideration	(10		)	—
Net Cash (Used)/Provided by Financing Activities	(264		)	40
Effect of exchange rate changes on cash and cash equivalents	(6		)	18
Net Increase in Cash and Cash Equivalents	141			48
Cash and Cash Equivalents at Beginning of Period	1,518			2,116
Cash and Cash Equivalents at End of Period	$	1,659		$	2,164

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 an integrated competitive power company, which produces, sells and delivers energy and energy products and services in major competitive power markets in the U.S. while positioning itself as a leader in the way residential, industrial and commercial consumers think about and use energy products and services. NRG has one of the nation's largest and most diverse competitive power generation portfolios balanced with the nation's largest competitive retail energy business. The Company owns and operates approximately 48,000 MWs 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 2015 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, 2016, and the results of operations, comprehensive income/(loss) and cash flows for the three months ended March 31, 2016, and 2015.

Use of Estimates

The preparation of financial statements in conformity with U.S. 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 Cash Flow Information

NRG’s investing activities exclude capital expenditures of $98 million which were accrued and unpaid at March 31, 2016.

Noncontrolling Interest

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



	(In millions)
Balance as of December 31, 2015	$	2,727
Distributions to noncontrolling interest	(42		)
Contributions from noncontrolling interest	12
Comprehensive loss attributable to noncontrolling interest	(41		)
Balance as of March 31, 2016	$	2,656

Redeemable Noncontrolling Interest

The following table reflects the changes in the Company's redeemable noncontrolling interest balance for the three months ended March 31, 2016:



	(In millions)
Balance as of December 31, 2015	$	29
Cash contributions from noncontrolling interest, net of distributions	5
Comprehensive loss attributable to noncontrolling interest	(11		)
Balance as of March 31, 2016	$	23

Recent Accounting Developments

ASU 2016-09 — In March 2016, the FASB issued ASU 2016-09, Compensation - Stock Compensation (Topic 718), or ASU No. 2016-09. The amendments of ASU No. 2016-09 were issued as part of the FASB's Simplification Initiative focused on improving areas of GAAP for which cost and complexity may be reduced while maintaining or improving the usefulness of information disclosed within the financial statements. 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 guidance in ASU No. 2016-09 is effective for fiscal years beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted. The Company does not expect the standard to have a material impact on its results of operations, cash flows and financial position.

ASU 2016-07 — In March 2016, the FASB issued ASU 2016-07, Investments - Equity Method and Joint Ventures (Topic 323), or ASU No. 2016-07. The amendments of ASU No. 2016-07 eliminate the requirement that when an investment qualifies for use of the equity method as a result of an increase in the level of ownership interest or degree of influence, an investor must adjust the investment, results of operations, and retained earnings retroactively on a step-by-step basis as if the equity method had been in effect during all previous periods that the investment had been held. The amendments require that the equity method investor add the cost of acquiring the additional interest in the investee to the current basis of the investor's previously held interest and adopt the equity method of accounting with no retroactive adjustment to the investment. In addition, ASU No. 2016-07 requires that an entity that has an available-for-sale equity security that becomes qualified for the equity method of accounting recognize through earnings the unrealized holding gain or loss in accumulated other comprehensive income at the date the investment becomes qualified for use of the equity method. The guidance in ASU No. 2016-07 is effective for fiscal years beginning after December 15, 2016, and interim periods within those annual periods. The adoption of ASU No. 2016-07 is required to be applied prospectively and early adoption is permitted. The Company does not expect the standard to have a material impact on its results of operations, cash flows and financial position.

ASU 2016-02 — In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), or ASU No. 2016-02. The amendments of ASU 2016-02 complete the joint effort between the FASB and the International Accounting Standards Board, or IASB, to develop a common leasing standard for U.S. GAAP and International Financial Reporting Standards, or IFRS, 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. The guidance in ASU No. 2016-02 provides that a lessee that may have previously accounted for a lease as an operating lease under current U.S. GAAP should recognize the assets and liabilities that arise from a lease on the balance sheet. In addition, ASU No. 2016-02 expands the required quantitative and qualitative disclosures with regards to lease arrangements. The guidance in ASU No. 2016-02 is effective for fiscal years beginning after December 15, 2018, and interim periods within those annual periods. The adoption of ASU 2016-02 is required to be applied using a modified retrospective approach for the earliest period presented and early adoption is permitted. The Company is currently evaluating the impact of the standard on the Company's results of operations, cash flows and financial position.

ASU 2016-01 — In January 2016, the FASB issued ASU No. 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities, or ASU No. 2016-01. The amendments of ASU No. 2016-01 eliminate available-for-sale classification of equity investments and require that equity investments (except those accounted for under the equity method of accounting, or those that result in consolidation of the investee) to be generally measured at fair value with changes in fair value recognized in net income. Further, the amendments require that financial assets and financial liabilities to be presented separately in the notes to the financial statements, grouped by measurement category and form of financial asset. The guidance in ASU No. 2016-01 is effective for financial statements issued for fiscal years beginning after December 15, 2017, and interim periods within those annual periods. The Company is currently evaluating the impact of the standard on the Company's results of operations, cash flows and financial position.

ASU 2015-16 — In September 2015, the FASB issued ASU No. 2015-16, Business Combinations (Topic 805): Simplifying the Accounting for Measurement-Period Adjustments, or ASU No. 2015-16. The amendments of ASU No. 2015-16 require that an acquirer recognize measurement period adjustments to the provisional amounts recognized in a business combination in the reporting period during which the adjustments are determined. Additionally, the amendments of ASU No. 2015-16 require the acquirer to record in the same period's financial statements the effect on earnings of changes in depreciation, amortization or other income effects, if any, as a result of the measurement period adjustment, calculated as if the accounting had been completed at the acquisition date as well as disclosing either on the face of the income statement or in the notes the portion of the amount recorded in current period earnings that would have been recorded in previous reporting periods. The guidance in ASU No. 2015-16 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The amendments should be applied prospectively. The Company adopted ASU No. 2015-16 for the year ended December 31, 2016, and the adoption did not have a material impact on the Company's results of operations, cash flows and financial position.

ASU 2014-09 — In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), or ASU No. 2014-09. The amendments of ASU No. 2014-09 complete the joint effort between the FASB and the IASB, to develop a common revenue standard for U.S. GAAP and IFRS, and to improve financial reporting. The guidance in ASU No. 2014-09 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 the following steps to be applied by an entity: (1) identify the contract with a customer; (2) identify the performance obligations in the contract; (3) determine the transaction price; (4) allocate the transaction price to the performance obligations in the contract; and (5) recognize revenue when (or as) the entity satisfies the performance obligation. In August 2015, the FASB issued ASU 2015-14, which formally deferred the effective date by one year to make the guidance of ASU No. 2014-09 effective for annual reporting periods beginning after December 15, 2017, including interim periods therein. Early adoption is permitted, but not prior to the original effective date, which was for annual reporting periods beginning after December 15, 2016. In March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606), or ASU No. 2016-08. The amendments of ASU No. 2016-08 clarify how to apply the implementation guidance on principal versus agent considerations related to the sale of goods or services to a customer as updated by ASU No. 2014-09. In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606), or ASU No. 2016-10. The amendments of ASU No. 2016-10 provide further clarification on contract revenue recognition as updated by ASU No. 2014-09, specifically related to the identification of separately identifiable performance obligations and the implementation of licensing contracts. The Company is currently evaluating the impact of the standard on the Company's results of operations, cash flows and financial position.

Note 3 — Business Acquisitions and Dispositions

The Company has completed the following business acquisitions and dispositions that are material to the Company's financial statements:

Acquisitions

2015 Acquisition of Desert Sunlight

On June 29, 2015, NRG Yield, Inc., through its subsidiary Yield Operating, acquired 25% of the membership interest in Desert Sunlight Investment Holdings, LLC, which owns two solar photovoltaic facilities that total 550 MW located in Desert Center, California from EFS Desert Sun, LLC, an affiliate of GE Energy Financial Services, for a purchase price of $285 million. The Company accounts for its 25% investment as an equity method investment.

Dispositions

Seward Disposition

On November 24, 2015, GenOn entered into an agreement with Robindale Energy Services, Inc. to sell 100% of its interest in Seward Generation, LLC, or Seward, for cash consideration of $75 million. Seward owns a 525 MW coal-fired facility in Pennsylvania. At December 31, 2015, GenOn had $5 million of current assets, $83 million of non-current assets, $1 million of current liabilities and $4 million of non-current liabilities classified as held for sale for Seward on its balance sheet. On February 2, 2016, GenOn completed the sale of Seward and received gross cash proceeds of $75 million excluding $3 million cash on hand transferred to the buyer. GenOn will also receive $5 million in deferred cash consideration in five $1 million annual installments and up to $2.5 million in payments contingent upon future environmental testing. In addition, Robindale committed to future inventory purchases from GenOn of $13 million through 2019.

Shelby Disposition

On November 9, 2015, GenOn entered into an agreement with Rockland Power Partners II, LP to sell 100% of its interest in the Shelby County Energy Center, LLC, or Shelby for cash consideration of $46 million. Shelby owns a 352 MW natural gas-fired facility located in Illinois. At December 31, 2015, GenOn had $1 million of current assets, $22 million of non-current assets, and $1 million of current liabilities classified as held for sale for Shelby on its balance sheet. On March 1, 2016, GenOn completed the sale of Shelby for cash proceeds of $46 million, which resulted in a gain of $29 million recognized within GenOn's consolidated results of operations during the first quarter of 2016. In addition, GenOn retained $10 million related to future revenue rights retained as part of the agreement.

Transfer of Assets under Common Control

On November 3, 2015, the Company sold 75% of the Class B interests of NRG Wind TE Holdco, which owns a portfolio of 12 wind facilities totaling 814 net MW, to NRG Yield, Inc. NRG Yield, Inc. paid total cash consideration of $209 million, subject to working capital adjustments. NRG Yield, Inc. is responsible for its pro-rata share of non-recourse project debt of $193 million and noncontrolling interest associated with a tax equity structure of $159 million (as of the acquisition date). In February 2016, the company made a final working capital payment of $2 million to NRG Yield, Inc. reducing total cash consideration to $207 million.

On January 2, 2015, the Company sold the following facilities to NRG Yield, Inc.: Walnut Creek, the Tapestry projects (Buffalo Bear, Pinnacle and Taloga) and Laredo Ridge. NRG Yield, Inc. paid total cash consideration of $489 million, including $9 million of working capital adjustments, plus assumed project level debt of $737 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 2015 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, 2016				As of December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Assets:
Notes receivable^(a)	$	57	$	57	$	73	$	73
Liabilities:
Long-term debt, including current portion^(b)	19,288		18,116		19,620		18,263

(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.

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, 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	12		—		—		12
Other ^(a)	11		—		—		11
Nuclear trust fund investments:
Cash and cash equivalents	17		—		—		17
U.S. government and federal agency obligations	64		1		—		65
Federal agency mortgage-backed securities	—		69		—		69
Commercial mortgage-backed securities	—		20		—		20
Corporate debt securities	—		72		—		72
Equity securities	281		—		52		333
Foreign government fixed income securities	—		1		—		1
Other trust fund investments:
U.S. government and federal agency obligations	1		—		—		1
Derivative assets:
Commodity contracts	624		1,790		164		2,578
Total assets	$	1,010	$	1,953	$	233	$	3,196
Derivative liabilities:
Commodity contracts	902		1,306		181		2,389
Interest rate contracts	—		185		—		185
Total liabilities	$	902	$	1,491	$	181	$	2,574

(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, 2015
	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	9		—		—		9
Other ^(a)	14		—		—		14
Nuclear trust fund investments:
Cash and cash equivalents	6		—		—		6
U.S. government and federal agency obligations	54		1		—		55
Federal agency mortgage-backed securities	—		59		—		59
Commercial mortgage-backed securities	—		25		—		25
Corporate debt securities	—		81		—		81
Equity securities	280		—		54		334
Foreign government fixed income securities	—		1		—		1
Other trust fund investments:
U.S. government and federal agency obligations	1		—		—		1
Derivative assets:
Commodity contracts	622		1,449		149		2,220
Total assets	$	986	$	1,616	$	220	$	2,822
Derivative liabilities:
Commodity contracts	868		1,036		182		2,086
Interest rate contracts	—		128		—		128
Total liabilities	$	868	$	1,164	$	182	$	2,214

(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, 2016, and 2015 between Levels 1 and 2. The following tables reconcile, for the three months ended March 31, 2016, and 2015, the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements, at least annually, using significant unobservable inputs:



	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 gains/(losses) — realized/unrealized:
Included in earnings	—		—			(17		)	(17		)
Included in nuclear decommissioning obligation	—		(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.



	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Three months ended March 31, 2015
(In millions)	Debt Securities		Other		Trust Fund Investments		Derivatives^(a)			Total
Beginning balance	$	18	$	11	$	52	$	80		$	161
Total gains/(losses) — realized/unrealized:
Included in earnings	—		—		—		(55		)	(55		)
Included in nuclear decommissioning obligations	—		—		2		—			2
Purchases	—		—		—		(4		)	(4		)
Transfers into Level 3 ^(b)	—		—		—		15			15
Transfers out of Level 3 ^(b)	—		—		—		(2		)	(2		)
Ending balance as of March 31, 2015	$	18	$	11	$	54	$	34		$	117
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, 2015	$	—	$	—	$	—	$	(20	)	$	(20	)


(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, 2016, contracts valued with prices provided by models and other valuation techniques make up 6% of the total derivative assets and 7% 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, 2016 and December 31, 2015:



	Significant Unobservable Inputs
	March 31, 2016
	Fair Value						Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average
	(In millions)
Power Contracts	$	120	$	115	Discounted Cash Flow	Forward Market Price (per MWh)	$	9		$	95	$	25
Coal Contracts	—		15		Discounted Cash Flow	Forward Market Price (per ton)	28			41		33
FTRs	44		51		Discounted Cash Flow	Auction Prices (per MWh)	(62		)	51		—
	$	164	$	181



	Significant Unobservable Inputs
	December 31, 2015
	Fair Value						Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average
	(In millions)
Power Contracts	$	86	$	100	Discounted Cash Flow	Forward Market Price (per MWh)	$	10		$	92	$	27
Coal Contracts	—		12		Discounted Cash Flow	Forward Market Price (per ton)	28			45		35
FTRs	63		70		Discounted Cash Flow	Auction Prices (per MWh)	(98		)	87		—
	$	149	$	182

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of March 31, 2016 and December 31, 2015:



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, 2016, the credit reserve resulted in a $5 million increase in fair value, which is composed of a $3 million gain in OCI and a $2 million gain in operating revenue and cost of operations. As of March 31, 2015, the credit reserve resulted in a $5 million increase in fair value, which was composed of a $3 million gain in OCI and a $2 million gain in operating revenues 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 2015 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 2015 Form 10-K. As of March 31, 2016, counterparty credit exposure, excluding credit risk exposure under certain long term agreements, was $887 million and NRG held collateral (cash and letters of credit) against those positions of $204 million, resulting in a net exposure of $686 million. Approximately 92% of the Company's exposure before collateral is expected to roll off by the end of 2017. 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)
Category	(% of Total)
Financial institutions	51	%
Utilities, energy merchants, marketers and other	35
ISOs	14
Total as of March 31, 2016	100	%



	Net Exposure ^(a)
Category	(% of Total)
Investment grade	97	%
Non-rated ^(b)	2
Non-investment grade	1
Total as of March 31, 2016	100	%


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


(b)	For non-rated counterparties, a significant portion are related to ISO and municipal public power entities, which are considered investment grade equivalent ratings based on NRG's internal credit ratings.

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 $223 million as of March 31, 2016. 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.

Counterparty credit exposure described above excludes credit risk exposure under certain long term agreements, including California tolling agreements, Gulf Coast load obligations, wind and solar PPAs, and a coal supply agreement. 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, 2016, aggregate credit risk exposure managed by NRG to these counterparties was approximately $4.5 billion, including $2.7 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 and other technology and market factors, which NRG is unable to predict. In the case of the coal supply agreement, NRG holds a lien against the underlying asset, which significantly reduces the risk of loss.

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, 2016, 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 2015 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, 2016							As of December 31, 2015
(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	$	17	$	—	$	—	—	$	6	$	—	$	—	—
U.S. government and federal agency obligations	65		4		—		11	55		1		—		11
Federal agency mortgage-backed securities	69		2		—		23	59		1		—		25
Commercial mortgage-backed securities	20		—		1		28	25		—		2		28
Corporate debt securities	72		2		1		11	81		1		1		10
Equity securities	333		198		—		—	334		199		—		—
Foreign government fixed income securities	1		—		—		8	1		—		—		9
Total	$	577	$	206	$	2		$	561	$	202	$	3

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,
	2016		2015
	(In millions)
Realized gains	$	4	$	6
Realized losses	3		2
Proceeds from sale of securities	191		196

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 2015 Form 10-K.

Energy-Related Commodities

As of March 31, 2016, NRG had energy-related derivative instruments extending through 2024. The Company voluntarily de-designated all remaining commodity cash flow hedges as of January 1, 2014, and prospectively marked these derivatives to market through the income statement.

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, 2016, the Company had interest rate derivative instruments on non-recourse debt extending through 2032, 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, 2016, and December 31, 2015. 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, 2016			December 31, 2015
Category	Units	(In millions)
Emissions	Short Ton	1			1
Coal	Short Ton	29			35
Natural Gas	MMBtu	223			293
Oil	Barrel	1			1
Power	MWh	(49		)	(74		)
Capacity	MW/Day	(1		)	(1		)
Interest	Dollars	$	2,284		$	2,326
Equity	Shares	1			1

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, 2016		December 31, 2015		March 31, 2016		December 31, 2015
	(In millions)
Derivatives designated as cash flow hedges:
Interest rate contracts current	$	—	$	—	$	41	$	42
Interest rate contracts long-term	—		—		115		68
Total derivatives designated as cash flow hedges	—		—		156		110
Derivatives not designated as cash flow hedges:
Interest rate contracts current	—		—		5		5
Interest rate contracts long-term	—		—		24		13
Commodity contracts current	2,113		1,915		1,901		1,674
Commodity contracts long-term	465		305		488		412
Total derivatives not designated as cash flow hedges	2,578		2,220		2,418		2,104
Total derivatives	$	2,578	$	2,220	$	2,574	$	2,214

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, 2016	(In millions)
Commodity contracts:
Derivative assets	$	2,578		$	(2,000	)	$	(99	)	$	479
Derivative liabilities	(2,389		)	2,000			186			(203		)
Total commodity contracts	189			—			87			276
Interest rate contracts:
Derivative liabilities	(185		)	—			—			(185		)
Total derivative instruments	$	4		$	—		$	87		$	91



	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, 2015	(In millions)
Commodity contracts:
Derivative assets	$	2,220		$	(1,616	)	$	(113	)	$	491
Derivative liabilities	(2,086		)	1,616			271			(199		)
Total commodity contracts	134			—			158			292
Interest rate contracts:
Derivative liabilities	(128		)	—			—			(128		)
Total derivative instruments	$	6		$	—		$	158		$	164

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, 2016
	Energy Commodities		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	)
Losses expected to be realized from OCI during the next 12 months, net of $3 tax	$	—	$	(20	)	$	(20	)



	Three months ended March 31, 2015
	Energy Commodities			Interest Rate			Total
	(In millions)
Accumulated OCI beginning balance	$	(1	)	$	(67	)	$	(68	)
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	—			2			2
Mark-to-market of cash flow hedge accounting contracts	—			(18		)	(18		)
Accumulated OCI ending balance, net of $50 tax	$	(1	)	$	(83	)	$	(84	)

Amounts reclassified from accumulated OCI into income and amounts recognized in income from the ineffective portion of cash flow hedges are recorded to operating revenue for commodity contracts and interest expense for interest rate contracts. There was no ineffectiveness for the three months ended March 31, 2016, and 2015.

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 earnings.

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,
	2016			2015
Unrealized mark-to-market results	(In millions)
Reversal of previously recognized unrealized gains on settled positions related to economic hedges	$	(86	)	$	(114	)
Reversal of acquired gain positions related to economic hedges	(13		)	(26		)
Net unrealized gains/(losses) on open positions related to economic hedges	134			(138		)
Total unrealized mark-to-market gains/(losses) for economic hedging activities	35			(278		)
Reversal of previously recognized unrealized losses/(gains) on settled positions related to trading activity	8			(21		)
Reversal of acquired gain positions related to trading activity	—			(7		)
Net unrealized gains on open positions related to trading activity	11			6
Total unrealized mark-to-market gains/(losses) for trading activity	19			(22		)
Total unrealized gains/(losses)	$	54		$	(300	)



	Three months ended March 31,
	2016			2015
	(In millions)
Unrealized gains/(losses) included in operating revenues	$	45		$	(109	)
Unrealized gains/(losses) included in cost of operations	9			(191		)
Total impact to statement of operations — energy commodities	$	54		$	(300	)
Total impact to statement of operations — interest rate contracts	$	(11	)	$	(14	)

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 revenue or cost of operations during the same period.

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.

For the three months ended March 31, 2015, the $138 million unrealized loss from open economic hedge positions was primarily the result of 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, 2016, was $126 million. The collateral required for contracts with credit rating contingent features as of March 31, 2016, was $15 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 $6 million as of March 31, 2016.

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

Note 7 — Impairments

Petra Nova Parish Holdings — During the first quarter of 2016, management changed its decisions 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 2015 Form 10-K. Long-term debt and capital leases consisted of the following:



(In millions, except rates)	March 31, 2016		December 31, 2015		March 31, 2016 interest rate % ^(a)

Recourse debt:
Senior notes, due 2018	$	958	$	1,039	7.625
Senior notes, due 2020	1,058		1,058		8.250
Senior notes, due 2021	1,128		1,128		7.875
Senior notes, due 2022	1,060		1,100		6.250
Senior notes, due 2023	910		936		6.625
Senior notes, due 2024	848		904		6.250
Term loan facility, due 2018	1,959		1,964		L+2.00
Tax-exempt bonds	455		455		4.125 - 6.00
Subtotal NRG recourse debt	8,376		8,584
Non-recourse debt:
GenOn senior notes	1,945		1,956		7.875 - 9.875
GenOn Americas Generation senior notes	750		752		8.500 - 9.125
GenOn Other	55		56
Subtotal GenOn debt (non-recourse to NRG)	2,750		2,764
Yield Operating LLC Senior Notes, due 2024	500		500		5.375
Yield LLC and Yield Operating LLC Revolving Credit Facility, due 2019	316		306		L+2.75
Yield Inc. Convertible Senior Notes, due 2019	332		330		3.500
Yield Inc. Convertible Senior Notes, due 2020	267		266		3.250
El Segundo Energy Center, due 2023	457		485		L+1.625 - L+2.25
Marsh Landing, due 2017 and 2023	410		418		L+1.175 - L+1.875
Alta Wind I - V lease financing arrangements, due 2034 and 2035	1,002		1,002		5.696 - 7.015
Walnut Creek, term loans due 2023	344		351		L+1.625
Tapestry, due 2021	178		181		L+1.625
Laredo Ridge, due 2028	103		104		L+1.875
Alpine, due 2022	153		154		L+1.750
Energy Center Minneapolis, due 2017 and 2025	107		108		5.95 - 7.25
Viento, due 2023	189		189		L+2.75
NRG Yield - other	463		469		various
Subtotal NRG Yield debt (non-recourse to NRG)	4,821		4,863
Ivanpah, due 2033 and 2038	1,145		1,149		2.285 - 4.256
Agua Caliente, due 2037	877		879		2.395 - 3.633
CVSR, due 2037	780		793		2.339 - 3.775
Dandan, due 2033	102		98		L+2.25
Peaker bonds, due 2019	72		72		L+1.07
Cedro Hill, due 2025	102		103		L+3.125
NRG Other	263		315		various
Subtotal other NRG non-recourse debt	3,341		3,409
Subtotal all non-recourse debt	10,912		11,036
Subtotal long-term debt (including current maturities)	19,288		19,620
Capital leases:
Capital leases	15		13		various
Other	3		3		various
Subtotal long-term debt and capital leases (including current maturities)	19,306		19,636
Less current maturities	465		481
Less debt issuance costs	164		172
Total long-term debt and capital leases	$	18,677	$	18,983

(a) As of March 31, 2016, L+ equals 3 month LIBOR plus x%, with the exception of the Viento Funding II term loan, which is 6 month LIBOR plus x%, and the NRG Marsh Landing term loan, Walnut Creek term loan, and NRG Yield Operating LLC revolving credit facility, which are 1 month LIBOR plus x%.

NRG Recourse Debt

Senior Notes

2016 Senior Notes Repurchases

During the first quarter of 2016, the Company repurchased $203 million in aggregate principal of its Senior Notes in the open market for $192 million, which included accrued interest of $3 million. In connection with the repurchases, an $11 million gain on debt extinguishment was recorded.



	Principal Repurchased		Cash Paid ^(a)		Average Early Redemption Percentage
Amount in millions, except rates
7.625% senior notes due 2018	$	81	$	84	103.222	%
6.625% senior notes due 2023	26		23		88.505	%
6.250% senior notes due 2022	40		36		87.000	%
6.250% senior notes due 2024	56		49		87.060	%
Total	$	203	$	192

^(a) Includes accrued interest.

Yield LLC and 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 or for the issuance of letters of credit. At March 31, 2016, there was $316 million outstanding and $60 million of letters of credit issued under the revolving credit facility.

Project Financings

High Lonesome Mesa Facility

Prior to the Company's acquisition of EME, an intercompany tax credit agreement related to the High Lonesome Mesa facility was terminated. The termination resulted in an event of default under the project financing arrangement. The Company received additional default notices for various items. The facility is secured by the assets of High Lonesome Mesa and is non-recourse to NRG.

On November 3, 2015, the lender sent a notice of acceleration and indicated that it would accept the Company's interest in the assets in lieu of repayment. On January 27, 2016, High Lonesome Mesa, LLC, or HLM, filed at FERC for approval to transfer 100% of the ownership interests in HLM to subsidiaries of the lien holders (Macquarie Bank Limited and Hannon Armstrong Capital, LLC). On March 2, 2016 HLM received FERC approval and on March 31, 2016 the Company transferred 100% of its interest in HLM to the lien holders and deconsolidated HLM.

Dandan Financing

In December 2013, NRG, through its wholly-owned subsidiary, NRG Solar Dandan LLC, or Dandan, entered into a credit agreement with a bank, or the Dandan Financing Agreement, for an $81 million construction loan and a $23 million cash grant loan. The construction loans have interest rates of LIBOR plus an applicable margin of 2.25% or base rate plus 1.25% and the cash grant loans have an interest rate of LIBOR plus an applicable margin of 1.75%. The term loan has an interest rate of LIBOR plus an applicable margin of 2.25%, which escalates 0.25% on the fifth, tenth, and fifteenth anniversary of the term conversion. The term loan, which is secured by all the assets of Dandan, matures January 2033, and amortizes based upon a predetermined schedule. The Dandan Financing Agreement also includes a letter of credit facility on behalf of Dandan of up to $5 million. Dandan pays an availability fee of 2.25% from the closing date until the 5th anniversary of the term conversion date and 2.50% from the 5th anniversary of the term conversion date on issued letters of credit. On January 29, 2016, the construction loan converted to a $79 million term loan with $23 million outstanding under the cash grant loan. In addition, a $4 million debt service letter of credit was issued replacing the $5 million construction letter of credit that was outstanding at year end. As of March 31, 2016, $81 million was outstanding under the term loan, $23 million was outstanding under the cash grant loan and $4 million in letters of credit in support of the project were issued.

Midwest Generation

On April 7, 2016, Midwest Generation, LLC, or MWG, entered into an agreement to sell certain quantities of unforced capacity that has cleared various PJM Reliability Pricing Model auctions to a trading counterparty for net proceeds of $253 million. MWG will continue to operate the applicable generation facilities and remains responsible for performance penalties and eligible for performance bonus payments, if any. Accordingly, MWG will continue to account for all revenues and costs as before; however, the proceeds will be recorded as a financing obligation while capacity payments by PJM to the counterparty will be reflected as debt amortization and interest expense through the end of the 2018/19 delivery year. MWG will amortize the upfront discount to interest expense, at an effective interest rate of 4.4%, over the term of the arrangement, through June 2019.

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, Yield Operating, 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 $108 million as of March 31, 2016.

Sherbino I Wind Farm LLC — NRG owns a 50% interest in Sherbino, a joint venture with BP Wind Energy North America Inc. NRG's maximum exposure to loss is limited to its equity investment, which was $77 million as of March 31, 2016.

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 2015 Form 10-K. For one of the tax equity arrangements, the Company has a deficit restoration obligation equal to $30 million as of March 31, 2016, 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, 2016
Current assets	$	86
Net property, plant and equipment	1,782
Other long-term assets	923
Total assets	2,791
Current liabilities	59
Long-term debt	360
Other long-term liabilities	190
Total liabilities	609
Noncontrolling interests	745
Net assets less noncontrolling interests	$	1,437

Note 10 — Changes in Capital Structure

As of March 31, 2016, and December 31, 2015, 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, 2015	416,939,950	(102,749,908	)	314,190,042
Shares issued under LTIPs	417,051	—		417,051
Shares issued under ESPP	—	299,127		299,127
Balance as of March 31, 2016	417,357,001	(102,450,781	)	314,906,220

Employee Stock Purchase Plan

As of March 31, 2016, there were 977,786 shares of treasury stock available for issuance under the ESPP.

NRG Common Stock Dividends

The following table lists the dividends paid during the three months ended March 31, 2016:



	First Quarter 2016
Dividends per Common Share	$	0.145

On April 18, 2016, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable May 16, 2016, to stockholders of record as of May 2, 2016, 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 earnings/(loss) per share while giving effect to all potentially dilutive common shares that were outstanding during the period. 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)	2016		2015
Basic earnings/(loss) per share attributable to NRG Energy, Inc. common stockholders
Net income/(loss) attributable to NRG Energy, Inc.	$	82	$	(120	)
Dividends for preferred shares	5		5
Income/(loss) available for common stockholders	$	77	$	(125	)
Weighted average number of common shares outstanding - basic	315		336
Earnings/(loss) per weighted average common share — basic	$	0.24	$	(0.37	)
Diluted earnings/(loss) per share attributable to NRG Energy, Inc. common stockholders
Weighted average number of common shares outstanding	315		336
Total dilutive shares	315		336
Earnings/(loss) per weighted average common share — diluted	$	0.24	$	(0.37	)

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 earnings/(loss) per share:



	Three months ended March 31,
(In millions of shares)	2016	2015
Equity compensation plans	4	7
Embedded derivative of 2.822% redeemable perpetual preferred stock	16	16
Total	20	23

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/Business (previously NRG Business); Retail Mass (previously NRG Home Retail); Renewables (previously NRG Renew), which includes solar and wind assets, excluding those in the NRG Yield segment; NRG Yield; and corporate activities. The Company's corporate segment includes BETM, international businesses, residential solar and electric vehicle services. Effective January 1, 2016, the Company began reporting the results of its residential solar business in its corporate segment. The financial information for the three months ended March 31, 2015 has been recast to reflect the change. Intersegment sales are accounted for at market. On November 3, 2015, NRG Yield acquired 75% of the class B interests in NRG Wind TE Holdco, which owns a portfolio of 12 wind facilities, from the Company. The acquisition was treated as a transfer of entities under common control and accordingly the financial information for the three months ended March 31, 2015 has been recast to reflect this change.

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).



(In millions)	Generation/Business^(a)(b)			Retail Mass^(a)		Renewables^(a)			NRG Yield^(a)		Corporate^(a)(c)(d)			Eliminations			Total
Three months ended March 31, 2016
Operating revenues^(a)	$	2,120		$	1,048	$	109		$	220	$	59		$	(327	)	$	3,229
Depreciation and amortization	146			28		56			66		17			—			313
Impairment loss on investment	(137		)	—		—			—		(9		)	—			(146		)
Equity in (losses)/earnings of unconsolidated affiliates	(5		)	—		(4		)	2		1			(1		)	(7		)
Income/(Loss) before income taxes	160			146		(51		)	2		(192		)	3			68
Net Income/(Loss)	159			146		(45		)	2		(218		)	3			47
Net Income/(Loss) attributable to NRG Energy, Inc.	$	159		$	146	$	(35	)	$	10	$	(205	)	$	7		$	82
Total assets as of March 31, 2016	$	17,124		$	1,919	$	5,736		$	7,659	$	19,184		$	(18,942	)	$	32,680



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	251	$	1	$	5	$	4	$	66	$	—	$	327
(b) Includes gain on sale of assets	$	32	$	—	$	—	$	—	$	—	$	—	$	32
(c) Includes gain on debt extinguishment	$	—	$	—	$	—	$	—	$	11	$	—	$	11
(d) Includes net loss of $43 million related to residential solar



(In millions)	Generation/Business^(a)(b)			Retail Mass		Renewables			NRG Yield			Corporate^(a)(c)			Eliminations			Total
Three months ended March 31, 2015
Operating revenues^(a)	$	2,509		$	1,311	$	91		$	200		$	(2	)	$	(280	)	$	3,829
Depreciation and amortization	233			30		52			67			13			—			395
Equity in (losses)/earnings of unconsolidated affiliates	(4		)	—		(1		)	2			(1		)	1			(3		)
Income/(Loss) before income taxes	29			104		(57		)	(24		)	(262		)	1			(209		)
Net Income/(Loss)	29			104		(51		)	(20		)	(199		)	1			(136		)
Net Income/(Loss) attributable to NRG Energy, Inc.	$	29		$	104	$	(46	)	$	(15	)	$	(187	)	$	(5	)	$	(120	)



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	246	$	—	$	—	$	—	$	34	$	—	$	280
(b) Includes gain on postretirement benefits curtailment	$	14	$	—	$	—	$	—	$	—	$	—	$	14
(c) Includes net loss of $45 million related to residential solar

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)	2016			2015
Income/(loss) before income taxes	$	68		$	(209	)
Income tax expense/(benefit)	21			(73		)
Effective tax rate	30.9		%	34.9		%

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.

For the three months ended March 31, 2015, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the impact of production tax credits generated from the Company's wind assets partially offset by non-taxable equity earnings and tax expense attributable to consolidated partnerships.

Uncertain Tax Benefits

As of March 31, 2016, NRG has recorded a non-current tax liability of $42 million for uncertain tax benefits from positions taken on various state income tax returns, including accrued interest. For the three months ended March 31, 2016, NRG accrued an insignificant amount of interest relating to the uncertain tax benefits. As of March 31, 2016, 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 2011. With few exceptions, state and local income tax examinations are no longer open for years before 2009. 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 2015 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, 2016, hedges under the first liens were in-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 project 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. If either of Ivanpah units 1 and 3 deliver less than the guaranteed energy production amount in any performance measurement period, PG&E may, at its option, declare an event of default. The two units did not meet their guaranteed energy production amount for the initial performance measurement period. On December 18, 2015, PG&E filed a request with the CPUC that it approve forbearance agreements relating to Ivanpah units 1 and 3. Under the forbearance agreements, PG&E agrees to refrain from taking certain actions (including declaring an event of default and invoking associated remedies) for an initial six-month period of time. If the units meet certain production requirements during such period, then the forbearance agreements provide for a six-month extension of such period. On March 17, 2016, the CPUC adopted a resolution approving the forbearance agreements. The CPUC’s approval became final and non-appealable on April 18, 2016, when no parties filed applications for rehearing of the CPUC’s decision. NRG has received confirmation from PG&E that the forbearance agreements are now considered final and non-appealable, and are now in full effect.

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. 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. In March 2012, the Court of Appeals 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.

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 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 Court of Appeals' decision and the Supreme Court granted the petition. On April 21, 2015, the 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 Supreme Court left open whether the claims were preempted on the basis of conflict preemption. The 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. On May 20, 2016, the U.S. District Court for the District of Nevada will hear argument on the defendants' motion for summary judgment in one of the Kansas cases. 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 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 is responding 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 operations, or cash flows.

Maryland Department of the Environment v. GenOn Chalk Point and GenOn Mid-Atlantic — On January 25, 2013, Food & Water Watch, the Patuxent Riverkeeper and the Potomac Riverkeeper (together, the Citizens Group) sent GenOn Mid-Atlantic a letter alleging that the Chalk Point, Dickerson and Morgantown generating facilities were violating the terms of the three National Pollution Discharge Elimination System permits by discharging nitrogen and phosphorous in excess of the limits in each permit. On March 21, 2013, the MDE sent GenOn Mid-Atlantic a similar letter with respect to the Chalk Point and Dickerson generating facilities, threatening to sue within 60 days if the generating facilities were not brought into compliance. On June 11, 2013, the Maryland Attorney General on behalf of the MDE filed a complaint in the U.S. District Court for the District of Maryland alleging violations of the CWA and Maryland environmental laws related to water. The Company is in discussions to resolve the matter and expects to pay a penalty in excess of $100,000. 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.

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 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. The Company is vigorously defending against these lawsuits. NRG requested and was granted a stay in the California case and one of the New Jersey cases pending a decision of an unrelated case by the U.S. Supreme Court, the results of which could materially affect these lawsuits. The Company believes that it has established an adequate reserve for these cases.

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 hearing on the demurrers is scheduled for June 9, 2016.

Braun v. NRG Yield, Inc. — On April 19, 2016, plaintiffs filed a purported class action lawsuit against NRG Yield, Inc. and against each current and former member of its board of directors individually 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 June 22, 2015 Class C common stock offering. Plaintiffs seek compensatory damages, rescission, attorney’s fees and costs.

Note 15 — Regulatory Matters

This footnote should be read in conjunction with the complete description under Note 23, Regulatory Matters, to the Company's 2015 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

U.S. Supreme Court’s Decision Regarding Maryland's Generator Contracting Programs — On April 19, 2016, the U.S. Supreme Court issued its decision in Hughes v. Talen Energy Marketing, the case concerning Maryland’s program to provide subsidies, through state-mandate contracts, to new generation in the state. The Court held that Maryland’s program is invalid and is preempted by the Supremacy Clause of the U.S. Constitution because it sets an interstate wholesale rate for power, thereby intruding on FERC’s exclusive authority under the FPA. The Court focused on the Maryland program’s requirement that generation participating in the program clear the market in the FERC-jurisdictional auction, and also that the contracts entered into under the Maryland program did not transfer ownership of capacity from one party to another outside the auction. The Court emphasized that its holding was limited, and that it was not addressing the permissibility of many types of measures states might use to encourage new or clean generation, such as tax incentives, land grants, direct subsidies, or other types of measures.

Due to the narrow holding and how the Court addressed the factors and interests at issue in this case, state programs that encourage new or clean generation and that do not condition payment of funds on capacity clearing a FERC-jurisdictional auction should not be affected by the Court’s ruling. In addition, projects already built pursuant to comparable state programs should not be affected by the Hughes decision. The Company anticipates that there will be considerable litigation in the coming years over the meaning and application of the decision.

East Region

Montgomery County Station Power Tax — On December 20, 2013, the Company received a letter from Montgomery County, Maryland requesting payment of an energy tax for the consumption of station power at the Dickerson Facility over the previous three years. Montgomery County seeks payment in the amount of $22 million, which includes tax, interest and penalties. The Company disputed the applicability of the tax. On December 11, 2015, the Maryland Tax Court reversed Montgomery County's assessment. Montgomery County has filed an appeal and briefing is underway.

Note 16 — Environmental Matters

This footnote should be read in conjunction with the complete description under Note 24, Environmental Matters, to the Company's 2015 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. Environmental laws have become increasingly stringent and NRG expects this trend to continue. The electric generation industry is facing new requirements regarding GHGs, combustion byproducts, water discharge and use, and threatened and endangered species. 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 operations.

The EPA finalized CSAPR in 2011, which was intended to replace CAIR in January 2012, to address certain states' obligation 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) SO₂budgets for four states including Texas and (ii) ozone-season NO_xbudgets for 11 states including Maryland, New Jersey, New York, Ohio, Pennsylvania and Texas. The EPA is currently reviewing the decision. In December 2015, the EPA proposed the CSAPR Update Rule using the 2008 Ozone NAAQS, which would reduce the total amount of ozone season NO_x as compared with the previously utilized 1997 Ozone NAAQS. If finalized, this proposal would reduce future NO_xallocations and/or current banked allowances. While NRG cannot predict the final outcome of this rulemaking, 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 limits 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 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. 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.

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 its results of operations, financial condition and cash flows and has accrued its environmental and asset retirement obligations under the rule based on current estimates as of March 31, 2016.

East Region

Maryland Environmental Regulations — In December 2014, MDE proposed a regulation regarding NO_x emissions from coal-fired electric generating units, which had it been finalized would have required by 2020 the Company (at each of the three Dickerson coal-fired units and the Chalk Point coal-fired unit that does not have an SCR) to either (1) install and operate an SCR; (2) retire the unit; or (3) convert the fuel source from coal to natural gas. In early 2015, the State of Maryland decided not to finalize the regulation as proposed. In November 2015, MDE finalized revised regulations to address future NO_xreductions, which although more stringent than previous regulations, will not cause the Company to spend capital to comply. As a result of the new regulations, on February 29, 2016, NRG notified PJM that it was withdrawing the standing deactivation notices for Dickerson Units 1, 2 and 3 and Chalk Point Units 1 and 2.

Environmental Capital Expenditures

NRG estimates that environmental capital expenditures from 2016 through 2020 required to comply with environmental laws will be approximately $339 million, which includes $66 million for GenOn and $254 million for Midwest Generation. These costs, the majority of which will be expended by the end of 2016, are primarily associated with (i) DSI/ESP upgrades at the Powerton facility and the Joliet gas conversion to satisfy the IL CPS and (ii) MATS compliance at the Avon Lake facility.

Note 17 — Condensed Consolidating Financial Information

As of March 31, 2016, the Company had outstanding $6.0 billion of Senior Notes due from 2018 - 2024, 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, 2016:



Ace Energy, Inc.	Norwalk Power LLC	NRG Norwalk Harbor Operations Inc.
Allied Warranty LLC	NRG Advisory Services, LLC	NRG Operating Services, Inc.
Arthur Kill Power LLC	NRG Affiliate Services Inc.	NRG Oswego Harbor Power Operations Inc.
Astoria Gas Turbine Power LLC	NRG Artesian Energy LLC	NRG PacGen Inc.
Bayou Cove Peaking Power, LLC	NRG Arthur Kill Operations Inc.	NRG Portable Power LLC
BidURenergy, Inc.	NRG Astoria Gas Turbine Operations Inc.	NRG Power Marketing LLC
Cabrillo Power I LLC	NRG Bayou Cove LLC	NRG Reliability Solutions LLC
Cabrillo Power II LLC	NRG Business Services LLC	NRG Renter's Protection LLC
Carbon Management Solutions LLC	NRG Business Solutions LLC	NRG Retail LLC
Cirro Group, Inc.	NRG Cabrillo Power Operations Inc.	NRG Retail Northeast LLC
Cirro Energy Services, Inc.	NRG California Peaker Operations LLC	NRG Rockford Acquisition LLC
Clean Edge Energy LLC	NRG Cedar Bayou Development Company, LLC	NRG Saguaro Operations Inc.
Conemaugh Power LLC	NRG Connected Home LLC	NRG Security LLC
Connecticut Jet Power LLC	NRG Connecticut Affiliate Services Inc.	NRG Services Corporation
Cottonwood Development LLC	NRG Construction LLC	NRG SimplySmart Solutions LLC
Cottonwood Energy Company LP	NRG Curtailment Solutions Holdings LLC	NRG South Central Affiliate Services Inc.
Cottonwood Generating Partners I LLC	NRG Curtailment Solutions Inc	NRG South Central Generating LLC
Cottonwood Generating Partners II LLC	NRG Development Company Inc.	NRG South Central Operations Inc.
Cottonwood Generating Partners III LLC	NRG Devon Operations Inc.	NRG South Texas LP
Cottonwood Technology Partners LP	NRG Dispatch Services LLC	NRG Texas C&I Supply LLC
Devon Power LLC	NRG Distributed Generation PR LLC	NRG Texas Gregory LLC
Dunkirk Power LLC	NRG Dunkirk Operations Inc.	NRG Texas Holding Inc.
Eastern Sierra Energy Company LLC	NRG El Segundo Operations Inc.	NRG Texas LLC
El Segundo Power, LLC	NRG Energy Efficiency-L LLC	NRG Texas Power LLC
El Segundo Power II LLC	NRG Energy Efficiency-P LLC	NRG Warranty Services LLC
Energy Alternatives Wholesale, LLC	NRG Energy Labor Services LLC	NRG West Coast LLC
Energy Choice Solutions, LLC	NRG ECOKAP Holdings LLC	NRG Western Affiliate Services Inc.
Energy Plus Holdings LLC	NRG Energy Services Group LLC	O'Brien Cogeneration, Inc. II
Energy Plus Natural Gas LLC	NRG Energy Services International Inc.	ONSITE Energy, Inc.
Energy Protection Insurance Company	NRG Energy Services LLC	Oswego Harbor Power LLC
Everything Energy LLC	NRG Generation Holdings, Inc.	RE Retail Receivables, LLC
Forward Home Security LLC	NRG GreenCo LLC	Reliant Energy Northeast LLC
GCP Funding Company, LLC	NRG GreenCo Holdings LLC	Reliant Energy Power Supply, LLC
Green Mountain Energy Company	NRG Home & Business Solutions LLC	Reliant Energy Retail Holdings, LLC
Gregory Partners, LLC	NRG Home Services LLC	Reliant Energy Retail Services, LLC
Gregory Power Partners LLC	NRG Home Solutions LLC	RERH Holdings LLC
Huntley Power LLC	NRG Home Solutions Product LLC	Saguaro Power LLC
Independence Energy Alliance LLC	NRG Homer City Services LLC	Somerset Operations Inc.
Independence Energy Group LLC	NRG Huntley Operations Inc.	Somerset Power LLC
Independence Energy Natural Gas LLC	NRG HQ DG LLC	Texas Genco Financing Corp.
Indian River Operations Inc.	NRG Identity Protect LLC	Texas Genco GP, LLC
Indian River Power LLC	NRG Ilion Limited Partnership	Texas Genco Holdings, Inc.
Keystone Power LLC	NRG Ilion LP LLC	Texas Genco LP, LLC
Langford Wind Power, LLC	NRG International LLC	Texas Genco Operating Services, LLC
Louisiana Generating LLC	NRG Maintenance Services LLC	Texas Genco Services, LP
Meriden Gas Turbines LLC	NRG Mextrans Inc.	US Retailers LLC
Middletown Power LLC	NRG MidAtlantic Affiliate Services Inc.	Vienna Operations Inc.
Montville Power LLC	NRG Middletown Operations Inc.	Vienna Power LLC
NEO Corporation	NRG Montville Operations Inc.	WCP (Generation) Holdings LLC
NEO Freehold-Gen LLC	NRG New Roads Holdings LLC	West Coast Power LLC
NEO Power Services Inc.	NRG North Central Operations Inc.
New Genco GP, LLC	NRG Northeast Affiliate Services 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, 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	1,450			759			10			(30		)	2,189
Depreciation and amortization	117			190			6			—			313
Selling, general and administrative	98			99			58			—			255
Acquisition-related transaction and integration costs	—			—			2			—			2
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 interests	—			(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

March 31, 2016

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
ASSETS	(In millions)
Current Assets
Cash and cash equivalents	$	—		$	1,070	$	589		$	—		$	1,659
Funds deposited by counterparties	34			66		1			—			101
Restricted cash	8			379		—			—			387
Accounts receivable - trade, net	723			290		5			—			1,018
Accounts receivable - affiliate	290			318		25			(628		)	5
Inventory	550			611		—			—			1,161
Derivative instruments	1,405			946		—			(238		)	2,113
Cash collateral paid in support of energy risk management activities	324			87		—			—			411
Renewable energy grant receivable, net	—			35		—			—			35
Prepayments and other current assets	121			248		87			—			456
Total current assets	3,455			4,050		707			(866		)	7,346
Net property, plant and equipment	4,732			13,825		233			(27		)	18,763
Other Assets
Investment in subsidiaries	894			2,218		11,197			(14,309		)	—
Equity investments in affiliates	(14		)	1,002		—			(90		)	898
Notes receivable, less current portion	—			31		8			1			40
Goodwill	697			302		—			—			999
Intangible assets, net	737			1,521		1			(3		)	2,256
Nuclear decommissioning trust fund	577			—		—			—			577
Derivative instruments	234			281		—			(50		)	465
Deferred income tax	11			497		(323		)	—			185
Other non-current assets	53			722		376			—			1,151
Total other assets	3,189			6,574		11,259			(14,451		)	6,571
Total Assets	$	11,376		$	24,449	$	12,199		$	(15,344	)	$	32,680
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—		$	529	$	(65	)	$	1		$	465
Accounts payable	498			316		31			—			845
Accounts payable — affiliate	259			300		57			(616		)	—
Derivative instruments	1,335			850		—			(238		)	1,947
Cash collateral received in support of energy risk management activities	34			66		—			—			100
Accrued expenses and other current liabilities	275			427		279			—			981
Total current liabilities	2,401			2,488		302			(853		)	4,338
Other Liabilities
Long-term debt and capital leases	301			10,391		7,985			—			18,677
Nuclear decommissioning reserve	330			—		—			—			330
Nuclear decommissioning trust liability	294			—		—			—			294
Deferred income taxes	809			265		(1,037		)	—			37
Derivative instruments	352			325		—			(50		)	627
Out-of-market contracts, net	92			1,030		—			—			1,122
Other non-current liabilities	554			788		205			—			1,547
Total non-current liabilities	2,732			12,799		7,153			(50		)	22,634
Total liabilities	5,133			15,287		7,455			(903		)	26,972
2.822% convertible perpetual preferred stock	—			—		304			—			304
Redeemable noncontrolling interest in subsidiaries	—			23		—			—			23
Stockholders’ Equity	6,243			9,139		4,440			(14,441		)	5,381
Total Liabilities and Stockholders’ Equity	$	11,376		$	24,449	$	12,199		$	(15,344	)	$	32,680


(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 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
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		)
Impairment losses	—			140			6			—			146
Cash 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
Payments for from intercompany loans to subsidiaries	(151		)	(11		)	—			162			—
Proceeds from 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
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
Purchases of emission allowances	(12		)	—			—			—			(12		)
Proceeds from sale of emission allowances	7			—			—			—			7
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	(211		)	(97		)	(16		)	181			(143		)
Cash Flows from Financing Activities
Proceeds from intercompany loans	—			—			162			(162		)	—
Proceeds from dividends from NRG Yield, Inc.	—			—			19			(19		)	—
Payment of dividends to common and preferred stockholders	—			—			(48		)	—			(48		)
Net receipts from settlement of acquired derivatives that include financing elements	—			39			—			—			39
Proceeds from issuance of long-term debt	—			61			—			—			61
Distributions from, net of contributions to, noncontrolling interest in subsidiaries	—			10			—			—			10
Proceeds from issuance of common stock	—			—			—			—			—
Payments for short and long-term debt	—			(121		)	(195		)	—			(316		)
Other	(3		)	(7		)	—			—			(10		)
Net Cash Used by Financing Activities	(3		)	(18		)	(62		)	(181		)	(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.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Three Months Ended March 31, 2015

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	2,566		$	1,303		$	—		$	(40	)	$	3,829
Operating Costs and Expenses
Cost of operations	2,104			996			12			(49		)	3,063
Depreciation and amortization	204			186			5			—			395
Selling, general and administrative	105			100			60			—			265
Acquisition-related transaction and integration costs	—			2			8			—			10
Development activity expenses	—			15			19			—			34
Total operating costs and expenses	2,413			1,299			104			(49		)	3,767
Gain on postretirement benefits curtailment	—			14			—			—			14
Operating Income/(Loss)	153			18			(104		)	9			76
Other Income/(Expense)
Equity in (losses)/earnings of consolidated subsidiaries	(13		)	(8		)	50			(29		)	—
Equity in losses of unconsolidated affiliates	—			(4		)	(1		)	2			(3		)
Other income, net	1			17			1			—			19
Interest expense	(4		)	(158		)	(139		)	—			(301		)
Total other expense	(16		)	(153		)	(89		)	(27		)	(285		)
Income/(Loss) Before Income Taxes	137			(135		)	(193		)	(18		)	(209		)
Income tax expense/(benefit)	54			(60		)	(67		)	—			(73		)
Net Income/(Loss)	83			(75		)	(126		)	(18		)	(136		)
Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interest	—			(21		)	(6		)	11			(16		)
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	83		$	(54	)	$	(120	)	$	(29	)	$	(120	)


(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, 2015

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Net Income/(Loss)	$	83		$	(75	)	$	(126	)	$	(18	)	$	(136	)
Other Comprehensive Income/(Loss), net of tax
Unrealized (loss)/gain on derivatives, net	(7		)	11			(16		)	—			(12		)
Foreign currency translation adjustments, net	—			(9		)	(2		)	—			(11		)
Available-for-sale securities, net	—			(1		)	—			—			(1		)
Defined benefit plans, net	(3		)	(1		)	11			—			7
Other comprehensive loss	(10		)	—			(7		)	—			(17		)
Comprehensive Income/(Loss)	73			(75		)	(133		)	(18		)	(153		)
Less: Comprehensive loss attributable to noncontrolling interest and redeemable noncontrolling interest	—			(34		)	(6		)	11			(29		)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	73			(41		)	(127		)	(29		)	(124		)
Dividends for preferred shares	—			—			5			—			5
Comprehensive Income/(Loss) Available for Common Stockholders	$	73		$	(41	)	$	(132	)	$	(29	)	$	(129	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

December 31, 2015



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations ^(a)			Consolidated
ASSETS	(In millions)
Current Assets
Cash and cash equivalents	$	—		$	825		$	693		$	—		$	1,518
Funds deposited by counterparties	55			51			—			—			106
Restricted cash	5			409			—			—			414
Accounts receivable - trade, net	851			304			2			—			1,157
Accounts receivable - affiliate	395			260			571			(1,222		)	4
Inventory	570			682			—			—			1,252
Derivative instruments	1,202			871			—			(158		)	1,915
Cash collateral paid in support of energy risk management activities	474			94			—			—			568
Renewable energy grant receivable, net	—			13			—			—			13
Current assets held-for-sale	—			6			—			—			6
Prepayments and other current assets	93			274			71			—			438
Total current assets	3,645			3,789			1,337			(1,380		)	7,391
Net Property, Plant and Equipment	4,767			13,773			219			(27		)	18,732
Other Assets
Investment in subsidiaries	842			2,244			11,039			(14,125		)	—
Equity investments in affiliates	(14		)	1,160			1			(102		)	1,045
Notes receivable, less current portion	—			46			7			—			53
Goodwill	697			302			—			—			999
Intangible assets, net	763			1,551			2			(6		)	2,310
Nuclear decommissioning trust fund	561			—			—			—			561
Derivative instruments	153			184			—			(32		)	305
Deferred income taxes	(6		)	815			(642		)	—			167
Non-current assets held for sale	—			105			—			—			105
Other non-current assets	80			749			385			—			1,214
Total other assets	3,076			7,156			10,792			(14,265		)	6,759
Total Assets	$	11,488		$	24,718		$	12,348		$	(15,672	)	$	32,882
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	2		$	460		$	19		$	—		$	481
Accounts payable	553			277			39			—			869
Accounts payable — affiliate	151			2,000			(929		)	(1,222		)	—
Derivative instruments	1,130			749			—			(158		)	1,721
Cash collateral received in support of energy risk management activities	55			51			—			—			106
Current liabilities held-for-sale	—			2			—			—			2
Accrued expenses and other current liabilities	319			429			449			(1		)	1,196
Total current liabilities	2,210			3,968			(422		)	(1,381		)	4,375
Other Liabilities
Long-term debt and capital leases	302			10,496			8,185			—			18,983
Nuclear decommissioning reserve	326			—			—			—			326
Nuclear decommissioning trust liability	283			—			—			—			283
Deferred income taxes	179			(1,088		)	928			—			19
Derivative instruments	301			224			—			(32		)	493
Out-of-market contracts, net	95			1,051			—			—			1,146
Non-current liabilities held-for-sale	—			4			—			—			4
Other non-current liabilities	554			735			199			—			1,488
Total non-current liabilities	2,040			11,422			9,312			(32		)	22,742
Total Liabilities	4,250			15,390			8,890			(1,413		)	27,117
2.822% Preferred Stock	—			—			302			—			302
Redeemable noncontrolling interest in subsidiaries	—			29			—			—			29
Stockholders’ Equity	7,238			9,299			3,156			(14,259		)	5,434
Total Liabilities and Stockholders’ Equity	$	11,488		$	24,718		$	12,348		$	(15,672	)	$	32,882


(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, 2015

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Cash Flows from Operating Activities
Net Income/(Loss)	83			(75		)	(126		)	(18		)	(136		)
Adjustments to reconcile net loss to net cash provided by operating activities:
Distributions from unconsolidated affiliates	—			40			—			(11		)	29
Equity in losses of unconsolidated affiliates	—			4			1			(2		)	3
Depreciation and amortization	204			186			5			—			395
Provision for bad debts	13			—			2			—			15
Amortization of nuclear fuel	13			—			—			—			13
Amortization of financing costs and debt discount/premiums	—			(11		)	7			—			(4		)
Amortization of intangibles and out-of-market contracts	12			7			—			—			19
Amortization of unearned equity compensation	—			—			11			—			11
Changes in deferred income taxes and liability for uncertain tax benefits	55			(36		)	(102		)	—			(83		)
Changes in nuclear decommissioning trust liability	(3		)	—			—			—			(3		)
Changes in derivative instruments	131			130			—			—			261
Changes in collateral deposits supporting energy risk management activities	(132		)	(81		)	—			—			(213		)
Gain on postretirement benefits curtailment and sale of assets	—			(14		)	—			—			(14		)
Cash provided/(used) by changes in other working capital	444			(580		)	(337		)	440			(33		)
Net Cash Provided/(Used) by Operating Activities	820			(430		)	(539		)	409			260
Cash Flows from Investing Activities
Intercompany loans (to)/from subsidiaries	(737		)	328			409			—			—
Acquisition of businesses, net of cash acquired	—			(1		)	—			—			(1		)
Capital expenditures	(89		)	(157		)	(6		)	—			(252		)
Increase in restricted cash, net	—			(11		)	—			—			(11		)
Decrease in restricted cash — U.S. DOE projects	—			24			1			—			25
Decrease in notes receivable	—			5			—			—			5
Investments in nuclear decommissioning trust fund securities	(193		)	—			—			—			(193		)
Proceeds from sales of nuclear decommissioning trust fund securities	196			—			—			—			196
Proceeds from renewable energy grants	—			2			—			—			2
Investments in unconsolidated affiliates	(2		)	(5		)	(37		)	—			(44		)
Other	—			3			—			—			3
Net Cash (Used)/Provided by Investing Activities	(825		)	188			367			—			(270		)
Cash Flows from Financing Activities
Proceeds from intercompany loans	—			—			409			(409		)	—
Payment of dividends to common and preferred stockholders	—			—			(51		)	—			(51		)
Payment for treasury stock	—			—			(79		)	—			(79		)
Net payment for settlement of acquired derivatives that include financing elements	—			40			—			—			40
Proceeds from issuance of long-term debt	—			221			27			—			248
Contributions to, net of distributions from, noncontrolling interest in subsidiaries	—			(25		)	—			—			(25		)
Proceeds from issuance of common stock	—			—			1			—			1
Payments for short and long-term debt	—			(89		)	(5		)	—			(94		)
Net Cash Provided by Financing Activities	—			147			302			(409		)	40
Effect of exchange rate changes on cash and cash equivalents	—			18			—			—			18
Net (Decrease)/Increase in Cash and Cash Equivalents	(5		)	(77		)	130			—			48
Cash and Cash Equivalents at Beginning of Period	18			1,455			643			—			2,116
Cash and Cash Equivalents at End of Period	$	13		$	1,378		$	773		$	—		$	2,164


(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, 2016, and 2015. Also refer to NRG's 2015 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

NRG Energy, Inc., or NRG or the Company, is an integrated competitive power company, which produces, sells and delivers energy and energy products and services in major competitive power markets in the U.S. while positioning itself as a leader in the way residential, industrial and commercial consumers think about and use energy products and services. NRG has one of the nation's largest and most diverse competitive generation portfolios balanced with the nation's largest competitive retail energy business. The Company owns and operates approximately 48,000 MWs 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. NRG was incorporated as a Delaware corporation on May 29, 1992.

The following table summarizes NRG's global generation portfolio as of March 31, 2016, by operating segment:



	Global Generation Portfolio^(a)
	(In MW)
	Generation/Business
Generation Type	Gulf Coast	East	West	Renewables^(d)		NRG Yield ^(e)		Total Domestic		Other^{(b) (c)}	Total Global
Natural gas^(f)	8,651	7,524	6,085	—		1,879		24,139		144	24,283
Coal^(g)	5,114	9,217	—	—		—		14,331		605	14,936
Oil^(h)	—	5,477	—	—		190		5,667		—	5,667
Nuclear	1,176	—	—	—		—		1,176		—	1,176
Wind	—	—	—	961		2,005		2,966		—	2,966
Utility Scale Solar	—	—	—	865		482		1,347		—	1,347
Distributed Solar	—	—	—	60		9		69		106	175
Total generation capacity	14,941	22,218	6,085	1,886		4,565		49,695		855	50,550
Capacity attributable to noncontrolling interest	—	—	—	(638	)	(2,053	)	(2,691	)	—	(2,691	)
Total net generation capacity	14,941	22,218	6,085	1,248		2,512		47,004		855	47,859

(a) Includes 85 active fossil fuel and nuclear plants, 16 Utility Scale Solar facilities, 35 wind farms and multiple Distributed Solar facilities. All Utility Scale Solar and Distributed Solar facilities are described in MWs 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 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.

(d) Includes Distributed Solar capacity from assets held by DGPV Holdco. Excludes 100 MW related to the High Lonesome facility, which was transferred to lien holders on March 31, 2016.

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

(f) Natural gas generation portfolio does not include 352 MW related to the Shelby generating facility which was sold in March 2016.

(g) Coal generation portfolio does not include 525 MW related to the Seward generating facility, which was sold in February 2016 and 380 MW related to the Huntley generating facility, which was deactivated in March 2016.

(h) Oil generation portfolio does not include 104 MW related to the Astoria Oil Turbines which were deactivated in the first quarter of 2016.

Strategy

NRG's strategy is to maximize stockholder value through the production and sale of safe, 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, and deploying, alternative energy technologies both in its wholesale portfolio through its wind and solar portfolio and, particularly, in and around its retail businesses and its customers as it transforms this part of its business into a technology-driven provider of retail energy services; 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. The Company is currently executing several key initiatives in connection with its capital allocation plan as further described within this Management's Discussion and Analysis.

Regulatory Matters

The Company’s regulatory matters are described in the Company’s 2015 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 the Company 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 the Company's ownership interest in STP.

Federal Regulation

East Region

PJM

AEP and FirstEnergy Ohio Contracts — On March 31, 2016, the Public Utility Commission of Ohio approved two settlements allowing AEP and FirstEnergy to recover costs associated with contracts between their regulated and un-regulated affiliates via a non-bypassable “retail rate rider” that will apply to all retail customers in Ohio. In anticipation of the approval of the contracts, NRG, along with other companies, participated in three separate complaints at FERC, two questioning whether AEP and FirstEnergy have the regulatory approvals necessary to enter into above-market contracts with their generation affiliates without further FERC review, and one alleging that PJM’s tariff is unjust and unreasonable because it does not include provisions to prevent the artificial suppression of prices caused by state approved out-of-market payments. On April 27, 2016, FERC granted the complaints against AEP and FirstEnergy, and required AEP and FirstEnergy to file the Ohio PPAs with FERC for further review. The second complaint against PJM regarding bidding rules remains pending. Additionally, on May 2, 2016, FirstEnergy filed an administrative appeal before the Public Utility Commission of Ohio proposing an alternative contract structure, which the Company also opposes.

New England

Sloped Demand Curve Filing — On May 30, 2014, FERC accepted the proposed tariff revisions discussed in the April 1, 2014 ISO-NE filing at FERC regarding the establishment of a sloped demand curve for use in the ISO-NE Forward Capacity Market. The Company, along with other generators, filed a petition for review of FERC's decision with the D.C. Circuit. In December 2015, FERC voluntarily requested a remand from the D.C. Circuit. FERC also instituted a FPA Section 206 proceeding, directing ISO-NE to submit tariff revisions by March 31, 2016, providing for zonal sloped demand curves to be implemented beginning in Forward Capacity Auction 11.

On April 15, 2016, ISO-NE submitted its compliance filing, which includes revisions to its system-wide demand curve by proposing a convex curve with a transition curve for up to three forward capacity auctions. The Company intends to protest the price suppression caused by ISO-NE’s compliance filing. The ultimate outcome of this proceeding will affect the market design governing future capacity auctions in New England.

New York

Dunkirk Power Reliability Service and Natural Gas Addition — On February 13, 2014, Dunkirk Power LLC and National Grid agreed to a term sheet for a 10-year agreement to govern the addition of natural gas-burning capabilities to the Dunkirk facility. This term sheet, known as the DNG Agreement Term Sheet, was approved by the NYSPSC on June 13, 2014. On February 27, 2015, Entergy filed a complaint in the U.S. District Court for the Northern District of New York alleging that the NYSPSC’s approval of the DNG Agreement Term Sheet represents an impermissible interference with FERC’s exclusive jurisdiction over the wholesale markets. On March 7, 2016, the U.S. District Court denied a motion to dismiss filed by the NYSPSC. The Company is weighing its legal options in light of the recent decision by the U.S. Supreme Court in Hughes v. Talen Energy Marketing.

FERC Investigation of NYISO RMR Practices — On February 19, 2015, pursuant to Section 206 of the FPA, FERC found NYISO’s tariff to be unjust and unreasonable because it did not contain provisions governing the retention of and compensation to generating units for reliability. FERC ordered NYISO to adopt tariff provisions containing a proposed RMR rate schedule and pro forma RMR agreement. On October 19, 2015, NYISO filed its tariff revisions at FERC. NRG protested the filing. On April 21, 2016, FERC rejected in part and accepted in part NYISO’s proposed tariff provisions. FERC also ordered NYISO to submit a compliance filing within 60 days. Resolution of this matter will affect how long uneconomic resources must stay in the market before they are allowed to retire, as well as the impact units retained for reliability will have on market prices.

Revisions to the Buyer-Side Mitigation Rules — On May 8, 2015, several New York entities, including the NYSPSC, filed a complaint against the NYISO under Section 206 of the FPA seeking revisions to the buyer-side market power mitigation measures of the NYISO tariff. The parties requested FERC to find that the current buyer-side mitigation rules are unjust and unreasonable because they prevent the ICAP market from functioning properly and that the rules should apply only to a limited subset of generation facilities. NRG protested the complaint. On October 9, 2015, FERC held that certain renewables and self-supply resources should be exempt from buyer-side mitigation rules and ordered the NYISO to submit a compliance filing. On February 5, 2016, FERC denied rehearing. The NYISO has yet to issue its compliance filing addressing FERC's order to develop exemptions for certain renewables and self-supply resources. The eventual disposition of this case could impact the ability of uneconomic resources to enter the New York market. On April 5, 2016, Entergy Nuclear Power Marketing, LLC filed a petition for review of FERC's decision with the D.C. Circuit and the Company has filed to intervene in that proceeding.

New York Public Service Commission Retail Energy Market Reset Order — On February 23, 2016, the NYSPSC issued what it refers to as its “Retail Reset” order, or Reset Order. Among other things, the Reset Order instituted a price cap on many residential and small commercial electricity and natural gas offerings. It also required many retail providers to seek affirmative consent from select classes of 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. A number of interested parties sought rehearing of the Reset Order with the NYSPSC. In addition, RESA, among other parties, filed suit in the Supreme Court of the State of New York, Albany County, and obtained a temporary restraining order preventing aspects of the Reset Order from taking effect. On May 4, 2016, the NYSPSC formally announced a number of additional reforms to the retail market, including its intent to consider price caps and new qualifications for retail suppliers operating in New York. The Reset Order, along with the other reforms announced on May 4, 2016, could have a negative impact on the viability of the New York retail energy market.

Gulf Coast Region

ERCOT

Greens Bayou Unit 5 RMR Status — On March 29, 2016, the Company filed notice with ERCOT of its intent to mothball Greens Bayou Unit 5. On April 22, 2016, ERCOT issued its initial determination that the unit is needed for reliability must-run service. ERCOT has a standard form contract that provides for recovery of the operating costs of a unit, together with additional performance metrics and incentives. The Company has not yet commenced negotiations with ERCOT.

MISO

Complaints regarding the 2015/2016 Planning Resource Auction — In May 2015, the Illinois Attorney General, Public Citizen, Inc., and Southwestern Electric Cooperative, Inc. filed complaints against MISO on the grounds that the results of the MISO 2015/2016 Planning Resource Auction resulted in unjust and unreasonable prices, specifically the auction clearing price in Zone 4. NRG, on behalf of itself and GenOn, filed comments providing its view on the rationale for the market outcome.

On June 30, 2015, the Illinois Energy Consumers filed a complaint with FERC under Section 206 of the FPA regarding MISO’s Planning Resource Auction tariff provisions, stating that the current MISO tariff does not produce just and reasonable results. The complaint suggests specific tariff modifications to address these alleged deficiencies, particularly as to the initial reference level price and the failure of the MISO tariff to count capacity sold in neighboring capacity markets toward meeting local clearing requirements in effect for the zones where capacity is physically located. On October 20, 2015, FERC held a technical conference on MISO's Planning Resource Auction, which in part addressed changes to MISO's auction design.

On December 31, 2015, FERC issued an order directing MISO to change key portions of its capacity market tariff, including restricting the ability of suppliers to place offers up to a MISO-developed opportunity cost. FERC mandated several changes to the auction, to be in place before the next planning resource auction in 2016. On March 18, 2016, FERC accepted MISO's compliance filing regarding market mitigation and subject to a further compliance filing, granted clarification with respect to going -forward costs, and denied all other requests for rehearing and clarification. MISO is pursuing its own stakeholder reforms process to create different rules and implement price formation reforms as to its restructured retail market zones, including Zone 4. FERC expressly declined to rule on the portion of the complaint addressing the outcome of the 2015 Zone 4 auction, and instead stated that its investigation into the conduct of the auction remained pending. Rehearing is pending.

West Region

CAISO

Puente Power Project — On January 11, 2016, the CPUC issued a proposed decision by the assigned administrative law judge and an alternate proposed decision by Commissioner Florio addressing, in part, the resource adequacy purchase agreement, or RAPA, between SCE and NRG for the construction of the 262 MW natural gas peaking Puente Power Project. Both the proposed decision and the Florio alternate proposed decision would delay approval of the RAPA until after the CEC has acted on the permit filing for the Puente Power Project. On February 12, 2016, Commissioner Peterman issued an alternate proposed decision which would approve the RAPA without delay. The three proposed decisions are scheduled to be taken up by the CPUC at its May 12, 2016 business meeting.

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 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. Environmental laws have become increasingly stringent and NRG expects this trend to continue. The electric generation industry is facing new requirements regarding GHGs, combustion byproducts, water discharge and use, and threatened and endangered species. 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 are in development, under review or have been recently promulgated by the EPA, including ESPS/NSPS for GHGs, NAAQS revisions and implementation and effluent guidelines. NRG is currently reviewing the outcome and any resulting impact of recently promulgated regulations and cannot fully predict such impact until legal challenges are resolved. The Company’s environmental matters are described in the Company’s 2015 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

Clean Power Plan — The national and international attention (including the Paris Agreement) in recent years on GHG emissions has resulted in federal and state legislative and regulatory action. In October 2015, the EPA finalized the Clean Power Plan, or CPP, addressing GHG emissions from existing EGUs. The CPP rule faces numerous legal challenges that likely will take several years to resolve. On February 9, 2016, the U.S. Supreme Court stayed the CPP.

Trends Affecting Results of Operations and Future Business Performance

Wind and Solar Resource Availability

The availability of the wind and solar resources affects the financial performance of the wind and solar facilities, which may impact the Company’s overall financial performance. Due to the variable nature of the wind and solar resource, the Company cannot predict the availability of the wind and solar resources and the potential variances from expected performance levels from quarter to quarter. To the extent the wind and solar resources are not available at expected levels, it could have a negative impact on the Company’s financial performance for such periods. For the first quarter of 2016, the wind performance was above prior year as well as the Company's expectations; however, the wind resources for the month of April were below expectations. If the April wind performance continues for a prolonged period of time, without a return to a performance level that meets or exceeds Company expectations, it may have a negative impact on the Company's financial performance.

Cottonwood Flooding

During March 2016, NRG's Cottonwood generating station was damaged by record flooding of the nearby Sabine River. At this time, the Company expects the unit to be returned to service in the third quarter of 2016, and expects significant recovery of the property damages from insurance. The Company will continue to work to expedite both.

CERT Suspension

The Company’s Limestone and Parish power generating plants are hosts to coal treatment facilities operated by an affiliate of Combustion Emissions Reduction Technologies, LLC, or CERT. Each coal treatment facility is owned by a special purpose project company controlled by a tax equity participant in order to provide for the efficient utilization of tax benefits. CERT has provided notice that the current owner of the project companies intends to suspend operations of its coal treatment facility on May 1, 2016. Because the CERT process provides for higher efficiency at the generation stations, should this suspension continue through the remainder of 2016, it will have an impact on future operating results.

Changes in Accounting Standards

See Note 2, Summary of Significant Accounting Policies, to this Form 10-Q as found in Item 1 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)	2016			2015			Change %
Operating Revenues
Energy revenue^(a)	$	1,151		$	1,676		(31	)%
Capacity revenue ^(a)	521			488			7
Retail revenue	1,370			1,663			(18	)
Mark-to-market for economic hedging activities	26			(87		)	130
Contract amortization	(15		)	(8		)	(88	)
Other revenues ^(b)	176			97			81
Total operating revenues	3,229			3,829			(16	)
Operating Costs and Expenses
Cost of sales ^(c)	1,505			2,134			(29	)
Mark-to-market for economic hedging activities	(9		)	191			(105	)
Contract and emissions credit amortization ^(c)	6			4			50
Operations and maintenance	583			615			(5	)
Other cost of operations	104			119			(13	)
Total cost of operations	2,189			3,063			(29	)
Depreciation and amortization	313			395			(21	)
Selling and marketing	100			108			(7	)
General and administrative	155			157			(1	)
Acquisition-related transaction and integration costs	2			10			(80	)
Development activity expenses	26			34			(24	)
Total operating costs and expenses	2,785			3,767			(26	)
Gain on sale of assets and postretirement benefits curtailment	32			14			129
Operating Income	476			76			N/M
Other Income/(Expense)
Equity in losses of unconsolidated affiliates	(7		)	(3		)	(133	)
Impairment loss on investment	(146		)	—			N/A
Other income, net	18			19			5
Gain on debt extinguishment	11			—			N/A
Interest expense	(284		)	(301		)	(6	)
Total other expense	(408		)	(285		)	43
Income/(Loss) before Income Taxes	68			(209		)	133
Income tax expense/(benefit)	21			(73		)	(129	)
Net Income/(Loss)	47			(136		)	135
Less: Net loss attributable to noncontrolling interest and redeemable noncontrolling interest	(35		)	(16		)	(119	)
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	82		$	(120	)	168
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	$	2.09		$	2.98		(30	)%

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

(b) Includes unrealized trading gains and losses.

N/M - Not meaningful.

N/A - Not applicable.

Management’s discussion of the results of operations for the three months ended March 31, 2016, and 2015

Income/(loss) before income taxes — The pre-tax income of $68 million for the three months ended March 31, 2016, compared to pre-tax loss of $209 million for the three months ended March 31, 2015, primarily reflects:


•	a current year increase from net mark-to-market results for economic hedges activity of $313 million;


•	a decrease of $223 million in other operating costs comprised primarily of depreciation and amortization, selling and marketing expense, general and administrative expense, acquisition-related transaction and integration costs and development costs; and


•	a decrease of $23 million in other expenses primarily relating to interest expense, and loss on debt extinguishment.

partially offset by:


•	an increase of $146 million in impairment losses on investments; and


•	a decrease in economic gross margin of $136 million comprised of a decrease in Generation/Business economic gross margin of $168 million, a decrease in Retail Mass economic gross margin of $26 million, partially offset by an increase in NRG Yield economic gross margin of $39 million, an increase in Renewables economic gross margin of $19 million.

Net income(loss) — The increase in net income of $183 million primarily reflects the drivers discussed above, including an income tax expense of $21 million for the three months ended March 31, 2016, compared to an income tax benefit of $73 million in the comparable period in 2015.

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, 2016, and 2015. Average on-peak power prices decreased primarily due to the decrease in natural gas prices for the three months ended March 31, 2016 as compared to the same period in 2015.



	Average on Peak Power Price ($/MWh) ^(a)
	Three months ended March 31,
Region	2016		2015
Gulf Coast ^(b)
ERCOT - Houston	$	20.45	$	26.46
ERCOT - North	19.64		26.54
MISO - Louisiana Hub	23.50		37.25
East
NY J/NYC	33.30		81.54
NY A/West NY	30.27		53.77
NEPOOL	30.82		88.85
PEPCO (PJM)	34.36		61.53
PJM West Hub	30.30		57.40
West
CAISO - NP15	23.92		34.56
CAISO - SP15	23.32		32.76

(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.

Economic 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. 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 sales.

Economic gross margin excludes the following elements from gross margin: mark-to-market gains or losses on economic hedging activities, contract amortization and emission credit amortization.

The following tables present the composition of economic gross margin for the three months ended March 31, 2016 and 2015:



	Three months ended March 31, 2016
	Generation/Business																		Retail Mass
(In millions)	Gulf Coast			East			West			B2B			Eliminations			Subtotal			Retail Mass			Renewables			NRG Yield			Eliminations/Corporate			Total
Energy revenue	$	468		$	735		$	28		$	—		$	—		$	1,231		$	—		$	99		$	115		$	(294	)	$	1,151
Capacity revenue	79			324			39			7			—			449			—			—			83			(11		)	521
Retail revenue	—			—			—			311			—			311			1,049			—			—			10			1,370
Other revenue	16			18			50			54			(15		)	123			—			9			39			5			176
Operating revenue	563			1,077			117			372			(15		)	2,114			1,049			108			237			(290		)	3,218
Cost of fuel	(192		)	(371		)	(13		)	—			—			(576		)	(4		)	(1		)	(11		)	129			(463		)
Other cost of sales	(57		)	(127		)	(5		)	(322		)	—			(511		)	(730		)	(1		)	(5		)	205			(1,042		)
Economic gross margin	$	314		$	579		$	99		$	50		$	(15	)	$	1,027		$	315		$	106		$	221		$	44		$	1,713
Business Metrics
MWh sold (thousands)^(a)(b)	12,123			8,447			853															1,218			1,650
MWh generated (thousands) ^(c)	10,861			8,297			724															1,218			1,911
Electricity sales volume — GWh										4,540
Average customer count (thousands, metered locations)										75
(a) MWh sold excludes generation at facilities that generate revenue under capacity agreements.
(b) Does not include thermal MWh of 40 thousand or MWt of 553 thousand for thermal sold by NRG Yield.
(c) Does not include thermal MWh of 91 thousand or MWt of 553 thousand for thermal generated by NRG Yield.



	Three months ended March 31, 2015
	Generation/Business																		Retail Mass
(In millions)	Gulf Coast			East			West			B2B			Eliminations			Subtotal			Retail Mass			Renewables			NRG Yield			Eliminations/Corporate			Total
Energy revenue	$	616		$	1,095		$	24		$	—		$	—		$	1,735		$	—		$	82		$	81		$	(222	)	$	1,676
Capacity revenue	58			319			37			—			—			414			—			—			78			(4		)	488
Retail revenue	—			—			—			348			—			348			1,312			—			—			3			1,663
Other revenue	22			30			4			52			(17		)	91			—			9			45			(48		)	97
Operating revenue	696			1,444			65			400			(17		)	2,588			1,312			91			204			(271		)	3,924
Cost of fuel	(300		)	(533		)	(13		)	—			—			(846		)	(5		)	(1		)	(17		)	(9		)	(878		)
Other cost of sales	(51		)	(148		)	(4		)	(346		)	—			(549		)	(966		)	(3		)	(5		)	267			(1,256		)
Economic gross margin	$	345		$	763		$	48		$	54		$	(17	)	$	1,193		$	341		$	87		$	182		$	(13	)	$	1,790
Business Metrics
MWh sold (thousands)^(a)(b)	15,057			15,041			610															957			1,174
MWh generated (thousands)^(c)	14,384			14,818			426															996			1,494
Electricity sales volume — GWh										4,586
Average customer count (thousands, metered locations)										82
(a) MWh sold excludes generation at facilities that generate revenue under capacity agreements.
(b) Does not include thermal MWh of 44 thousand or MWt of 617 thousand for thermal sold by NRG Yield.
(c) Does not include thermal MWh of 44 thousand or MWt of 617 thousand for thermal generated by NRG Yield.



	Three months ended March 31,
Weather Metrics	Gulf Coast	East	West
2016
CDDs ^(a)	76	33	5
HDDs ^(a)	931	2,251	974
2015
CDDs	41	33	17
HDDs	1,285	2,960	813
10 year average
CDDs	90	229	3
HDDs	1,092	2,499	1,154

(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/Business economic gross margin

Generation/Business economic gross margin decreased by $168 million, including intercompany sales, during the three months ended March 31, 2016, compared to the same period in 2015, due to:



	(In millions)
Decrease in Gulf Coast region	$	(31	)
Decrease in East region	(184		)
Increase in West region	51
Decrease in B2B	(4		)
	$	(168	)

The decrease in economic gross margin in the Gulf Coast region was driven by:



	(In millions)
Lower gross margin due to lower coal generation in Texas, which was driven by lower natural gas prices	$	(42	)
Lower gross margin due to lower average realized prices, primarily in South Central	(13		)
Higher capacity revenue, primarily from higher pricing for certain South Central facilities	22
Higher gross margin driven by higher gas generation, partially offset by lower coal generation for South Central, both driven by lower natural gas prices	5
Other	(3		)
	$	(31	)

The decrease in economic gross margin in the East region was driven by:



	(In millions)
Lower gross margin due to a 41% decrease in generation as a result of milder winter weather conditions and current year planned outages	$	(193	)
Lower gross margin driven primarily by a 5% decrease in New York and New England hedged capacity prices as well as increased purchased capacity and the roll-off of the Dunkirk RSS contract	(18		)
Higher gross margin due to lower supply costs for servicing certain load contracts	28
Higher gross margin primarily driven by a 22% increase in PJM cleared auction prices offset by an 11% decrease in PJM capacity volumes as a result of unit deactivations and increased purchased capacity	2
Other	(3		)
	$	(184	)

The increase in economic gross margin in the West region was driven by:



	(In millions)
Gain on sale of excess emissions credits	$	47
Higher energy gross margin due to a 57% increase in volume due to timing of outages in the prior year, offset by 24% decrease in energy prices	4
	$	51

The decrease in B2B economic gross margin of $4 million was primarily driven by lower margins during the current quarter.

Retail Mass economic gross margin

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



	Three months ended March 31,
(In millions except otherwise noted)	2016			2015
Retail Mass revenue	$	1,030		$	1,282
Supply management revenue	19			30
Operating revenue^(a)	$	1,049		$	1,312
Cost of sales ^(b)	(734		)	(971		)
Economic Gross Margin	$	315		$	341

Business Metrics
Electricity sales volume — GWh - Gulf Coast	6,713			7,549
Electricity sales volume — GWh - All other regions	1,834			2,614
Average Retail Mass customer count (in thousands)^(c)	2,771			2,815
Ending Retail Mass customer count (in thousands)^(c)	2,770			2,784


(a)	Includes intercompany sales of $1 million in 2016 and 2015, respectively, representing sales from Retail Mass to the Gulf Coast region.


(b)	Includes intercompany purchases of $192 million and $250 million in 2016 and 2015.


(c)	Excludes Discrete Customers.

Retail Mass economic gross margin decreased $26 million for the three months ended March 31, 2016, compared to the same period in 2015, due to:



	(In millions)
Lower gross margin due to milder weather conditions in 2016 as compared to 2015	$	(57	)
Higher gross margin due to lower supply costs partially offset by lower rates to customers driven by a decrease in natural gas prices	31
	$	(26	)

Renewables economic gross margin

Renewables economic gross margin increased $19 million for the three months ended March 31, 2016, compared to the same period in 2015, primarily as a result of higher wind generation and improved performance at the Ivanpah project, as it continues towards full production capabilities.

NRG Yield economic gross margin

NRG Yield economic gross margin increased $39 million for the three months ended March 31, 2016, compared the same period in 2015, primarily related to higher wind generation during the current quarter.

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 increased by $313 million during the three months ended March 31, 2016, compared to the same period in 2015.

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, 2016
				Generation/Business
	Retail Mass			Gulf Coast			East			West			B2B			Renewables		Elimination^(a)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized gains 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 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	$	92		$	11		$	36		$	(1	)	$	50		$	—	$	(43	)	$	145
Reversal of acquired gain positions related to economic hedges	—			—			—			(2		)	—			—		—			(2		)
Net unrealized losses on open positions related to economic hedges	(63		)	(9		)	(37		)	—			(46		)	—		21			(134		)
Total mark-to-market gains/(losses) in operating costs and expenses	$	29		$	2		$	(1	)	$	(3	)	$	4		$	—	$	(22	)	$	9


(a)	Represents the elimination of the intercompany activity between Retail Mass, and Generation/Business.



	Three months ended March 31, 2015
				Generation/Business
	Retail Mass			Gulf Coast			East			West			B2B			Renewables		NRG Yield			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	$	—		$	(150	)	$	(146	)	$	2		$	—		$	—	$	(2	)	$	(60	)	$	(356	)
Reversal of acquired gain positions related to economic hedges	—			—			(19		)	—			—			—		—			—			(19		)
Net unrealized gains/(losses) on open positions related to economic hedges	—			238			(13		)	4			1			—		9			49			288
Total mark-to-market gains/(losses) in operating revenues	$	—		$	88		$	(178	)	$	6		$	1		$	—	$	7		$	(11	)	$	(87	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	128		$	10		$	4		$	(1	)	$	41		$	—	$	—		$	60		$	242
Reversal of acquired gain positions related to economic hedges	(3		)	—			—			(4		)	—			—		—			—			(7		)
Net unrealized losses on open positions related to economic hedges	(157		)	(33		)	(79		)	—			(108		)	—		—			(49		)	(426		)
Total mark-to-market losses in operating costs and expenses	$	(32	)	$	(23	)	$	(75	)	$	(5	)	$	(67	)	$	—	$	—		$	11		$	(191	)


(a)	Represents the elimination of the intercompany activity between Retail Mass, Generation/Buisness, and NRG Yield.

Mark-to-market results consist of unrealized gains and losses. The settlement of these transactions is reflected in the same 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, 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.

For the three months ended March 31, 2015, the $87 million loss in operating revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on contracts that settled during the period largely offset by an increase in value of open positions as a result of decreases in natural gas and ERCOT electricity prices. The $191 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, partially offset by the reversal of previously recognized unrealized losses on contracts that settled during the period.

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, 2016, and 2015. The realized and unrealized financial and physical trading results are included in operating revenue. 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)	2016		2015
Trading gains/(losses)
Realized	$	24	$	25
Unrealized	19		(22		)
Total trading gains	$	43	$	3

In addition, trading activities reflect an increase in gross margin of $50 million, reflected in the Corporate segment, for the three months ended March 31, 2016, as compared to the three months ended March 31, 2015.

Operations and Maintenance Expense



	Generation/Business								Retail Mass		Renewables		NRG Yield		Eliminations
	Gulf Coast		East		West		B2B		Retail Mass		Renewables		NRG Yield		Eliminations			Total
	(In millions)
Three months ended March 31, 2016	$	137	$	272	$	34	$	22	$	50	$	33	$	43	$	(8	)	$	583
Three months ended March 31, 2015	173		274		42		24		51		30		45		(24		)	$	615

Operations and maintenance expense decreased by $32 million for the three months ended March 31, 2016, compared to the same period in 2015, due to the following:



	(In millions)
Decrease in operations and maintenance expense related to the timing of outages at Limestone, STP, and Cottonwood	$	(32	)
Decrease in West operations and maintenance expense primarily related to the timing of outages	(4		)
Other	4
	$	(32	)

Other Cost of Operations

Other cost of operations, comprised of asset retirement expense, insurance expense and property tax expense, decreased by $15 million for the three months ended March 31, 2016, compared to the same period in 2015, primarily due to a reduction in property tax for Chalk Point and Dickerson.

Depreciation and Amortization

Depreciation and amortization expense decreased by $82 million for the three months ended March 31, 2016, compared to the same period in 2015, primarily due to decrease in depreciation expense for facilities impaired during 2015.

Selling, Marketing, General and Administrative Expenses

Selling, marketing, general and administrative expenses are comprised of the following:



	Three months ended March 31,
(In millions)	2016		2015
Selling and marketing expenses	$	100	$	108
General and administrative expenses	155		157
	$	255	$	265

Selling and marketing expense decreased by $8 million for the three months ended March 31, 2016, compared to the same period in 2015, due primarily to the continued focus on cost management.

General and administrative expenses decreased by $2 million for the three months ended March 31, 2016, compared to the same period in 2015, due primarily to the continued focus on cost management.

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.

Gain on Debt Extinguishment

A gain on debt extinguishment of $11 million was recorded for the three months ended March 31, 2016, primarily driven by the repurchase of NRG Senior Notes at a price below par value, combined with the write-off of unamortized premium.

Interest Expense

NRG's interest expense decreased by $17 million for the three months ended March 31, 2016, compared to the same period in 2015 due to the following:



	(In millions)
Decrease due to the repurchases of Senior Notes at the end of 2015 and first quarter of 2016	$	(12	)
Decrease due to the termination of Alta X and XI term loans and the related interest rate swaps in 2015	(12		)
Increase due to the issuance of NRG Yield Inc. 3.25% Convertible Senior Notes due 2020 and NRG Yield Operating LLC Revolving Credit Facility issued in 2015	5
Other	2
	$	(17	)

Income Tax Expense/(Benefit)

For the three months ended March 31, 2016, NRG recorded an income tax expense of $21 million on pre-tax income of $68 million. For the same period in 2015, NRG recorded an income tax benefit of $73 million on a pre-tax loss of $209 million. The effective tax rate was 30.9% and 34.9% for the three months ended March 31, 2016, and 2015, respectively.

For the three months ended March 31, 2015, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the impact of production tax credits generated from our wind assets, partially offset by non-taxable equity earnings and tax expense attributable to consolidated partnerships.

Net loss attributable to noncontrolling interests and redeemable noncontrolling interests

For the three months ended March 31, 2016, and 2015, 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, partially offset by NRG Yield, Inc.'s share of net income.

Liquidity and Capital Resources

Liquidity Position

As of March 31, 2016, and December 31, 2015, NRG's liquidity, excluding collateral received, was approximately $3.4 billion and $3.3 billion, respectively, comprised of the following:



(In millions)	March 31, 2016		December 31, 2015
Cash and cash equivalents:
NRG excluding NRG Yield and GenOn	$	665	$	742
NRG Yield and subsidiaries	76		111
GenOn and subsidiaries	918		665
Restricted cash - operating	65		127
Restricted cash - reserves^(a)	322		287
Total	2,046		1,932
Total credit facility availability	1,337		1,373
Total liquidity, excluding collateral received	$	3,383	$	3,305

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

For the three months ended March 31, 2016, total liquidity, excluding collateral funds deposited by counterparties, increased by $78 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, 2016, were predominantly held in money market mutual 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 and preferred stockholders, and to fund other liquidity commitments. 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 $1.7 billion of cash and cash equivalents of the Company as of March 31, 2016, $428 million and $171 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, REMA must be in compliance with the requirement to provide credit support to the owner lessors securing its obligation to pay scheduled rent under its 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, 2016, 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 also 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, 2016, GenOn did not meet the consolidated debt ratio component of the restricted payments test.

Certain of GenOn's senior unsecured notes mature in 2017 and 2018. If GenOn is not able to refinance these notes prior to their maturities, it may have an adverse impact on GenOn's financial position. GenOn is currently considering all options available to it, including refinancing the notes, potential sales of certain generating assets or issuances of new debt securities. Given current economic and market conditions, including the depressed commodity markets, GenOn may be unable to complete these actions on a timely basis or on satisfactory terms or at all. These actions also may not be sufficient to enable GenOn to continue to satisfy its related cash commitments as they become due.

GenOn’s financial position continues to be adversely affected by a sustained decline in natural gas prices and its resulting effect on wholesale power prices. In addition, GenOn Mid-Atlantic and REMA are currently unable to make distributions of cash and certain other restricted payments to GenOn. If gas and power prices remain depressed, GenOn may be unable to generate sufficient cash flow from operations to meets its long-term liquidity requirements, including operating, maintenance and capital expenditures and debt service payments.

Credit Ratings

On March 3, 2016 and March 21, 2016, respectively, S&P and Moody's reaffirmed the corporate credit ratings on NRG Energy, Inc.

On March 21, 2016, Moody's lowered its corporate credit ratings on GenOn to Caa2 from B3. The ratings outlook for GenOn, GenOn Mid-Atlantic, REMA and GenOn Americas Generation is negative. Moody's also lowered the issue ratings on the GenOn senior notes to Caa2 from B3, the pass-through certificates at GenOn Mid-Atlantic to B2 from Ba3 and the GenOn Americas Generation senior notes to Caa2 from Caa1. The issue rating on the pass-through certificates of REMA was reaffirmed by Moody's at B2.

The following table summarizes the Company's credit ratings as of March 31, 2016:



	S&P	Moody's
NRG Energy, Inc.	BB- Stable	Ba3 Stable
7.625% Senior Notes, due 2018	BB-	B1
8.25% Senior Notes, due 2020	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
Term Loan Facility, due 2018	BB+	Baa3
GenOn 7.875% Senior Notes, due 2017	B-	Caa2
GenOn 9.500% Senior Notes, due 2018	B-	Caa2
GenOn 9.875% Senior Notes, due 2020	B-	Caa2
GenOn Americas Generation 8.500% Senior Notes, due 2021	B-	Caa2
GenOn Americas Generation 9.125% Senior Notes, due 2031	B-	Caa2
NRG Yield, Inc.	BB+ Stable	Ba2 Stable
5.375% NRG Yield Operating LLC Senior Notes, due 2024	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 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 2015 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 Yield Operating senior unsecured notes, the NRG Yield, Inc. revolving credit facility, and project-related financings.

EVgo

In May 2016, the Company entered an agreement to sell a majority interest in the EVgo business to Vision Ridge Partners for approximately $19.5 million (subject to working capital adjustments) payable to the Company and the remainder contributed as capital to the EVgo business by Vision Ridge Partners. In addition, the Company has future earnout potential of up to $70 million based on future profitability targets. NRG will retain its obligation under its agreement with the California Public Utilities Commission to build at least 200 public fast charging Freedom Station sites and associated work to prepare 10,000 commercial and multi-family parking spaces for electric vehicle charging in California by the end of 2016.

Residential Solar

In May 2016, the Company entered into agreements with both Sunrun Inc. and Spruce Finance Inc., whereby both parties will be able to purchase NRG originated residential solar contracts and provide support over the life of the customer contract.

Midwest Generation

Cash Grants

As of March 31, 2016, the Company had a net renewable energy grant receivable of $35 million, net of sequestration.

Indemnity Receivable

The Company has a receivable of $75 million pursuant to an indemnity agreement the Company has with SunPower relating to the CVSR project. Pursuant to the purchase and sale agreement for the CVSR project between NRG and SunPower, SunPower agreed to indemnify NRG up to $75 million if the U.S. Treasury Department made certain determinations and awarded a reduced 1603 cash grant for the project. SunPower has refused to honor its contractual indemnification obligation. As a result, on March 19, 2014, NRG filed a lawsuit against SunPower in California state court, alleging breach of contract and also seeking a declaratory judgment that SunPower has breached its indemnification obligation. NRG is seeking $75 million in damages from SunPower. On April 2, 2015, SunPower filed its answer to the lawsuit and also a cross-complaint alleging that NRG owes SunPower $7.5 million as a result of SunPower having paid more than its required share to cover the repayment of the DOE cash grant bridge loans. In July 2015, NRG filed its answer to the cross-complaint. The court has set this case for trial on January 17, 2017.

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, 2016, all hedges under the first liens were in-the-money on a counterparty aggregate basis.

The following table summarizes the amount of MWs 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, 2016:



Equivalent Net Sales Secured by First Lien Structure ^(a)	2016		2017		2018		2019		2020
In MW	2,155		1,677		280		—		—
As a percentage of total net coal and nuclear capacity ^(b)	37	%	29	%	5	%	—	%	—	%


(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 the Capital Allocation Program including acquisition opportunities, debt repayments, return of capital and dividend payments to stockholders.

GreenCo Intercompany Revolver

During the three months ended March 31, 2016, certain of the Company's subsidiaries borrowed approximately $80 million under the intercompany revolving facility, associated with the GreenCo strategic process. At March 31, 2016, $10 million of cash was held by the by GreenCo entities.

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, 2016, commercial operations had total cash collateral outstanding of $411 million, and $786 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, 2016, total collateral held from counterparties was $100 million in cash and $154 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, 2016, and the currently estimated capital expenditure and growth investments forecast for the remainder of 2016.



	Maintenance			Environmental		Growth Investments			Total
	(In millions)
Generation/Business
Gulf Coast	$	33		$	3	$	1		$	37
East	37			74		38			149
West	1			—		8			9
B2B	3			—		—			3
Retail Mass	4			—		—			4
Renewables	6			—		22			28
NRG Yield	6			—		1			7
Corporate^(b)	10			—		32			42
Total cash capital expenditures for the three months ended March 31, 2016	100			77		102			279
Funding from debt financing, net of fees	—			—		(8		)	(8		)
Funding from third party equity partners and cash grants	(9		)	—		(58		)	(67		)
Other investments ^(a)	—			—		20			20
Total capital expenditures and investments, net of financings	91			77		56			224

Estimated capital expenditures for the remainder of 2016	375			227		1,013			1,615
Funding from debt financing, net of fees	—			—		(533		)	(533		)
Funding from third party equity partners and cash grants	(6		)	—		(155		)	(161		)
Other investments ^(a)	—			—		55			55
NRG estimated capital expenditures for the remainder of 2016, net of financings	$	369		$	227	$	380		$	976


(a)	Other investments include restricted cash activity.


(b)	Includes residential solar.


•	Environmental capital expenditures — For the three months ended March 31, 2016, the Company's environmental capital expenditures included DSI/ESP upgrades at the Powerton facility and the Joliet gas conversion to satisfy the IL CPS as well as controls to satisfy MATS at the Avon Lake facility.


•	Growth Investments capital expenditures — For the three months ended March 31, 2016, the Company's growth investment capital expenditures included $46 million for solar projects, $38 million for fuel conversions, $9 million for repowering projects, $1 million for thermal projects and $8 million for the Company's other growth projects.

Environmental Capital Expenditures

NRG estimates that environmental capital expenditures from 2016 through 2020 required to comply with environmental laws will be approximately $339 million which includes $66 million for GenOn and $254 million for Midwest Generation. These costs, the majority of which will be expended by the end of 2016, are primarily associated with (i) DSI/ESP upgrades at the Powerton facility and the Joliet gas conversion to satisfy the IL CPS and (ii) MATS compliance at the Avon Lake facility.

In connection with the acquisition of EME, on April 1, 2014, NRG committed to fund up to $350 million in capital expenditures for plant modifications at Powerton and Joliet to comply with environmental regulations. The expected costs of these projects are included in the environmental capital expenditures detailed above.

2016 Capital Allocation Program

The Company's plan to allocate capital during 2016 is as follows:

•

Debt and Preferred Stock Reduction. The Company expects to allocate approximately seventy-eight percent (78%) of NRG's capital available for allocation during 2016 to additional debt and preferred stock repurchases through the remainder of 2016 and 2017 in order to meet the Company's goal of prudent balance sheet management in a low commodity price environment. The Company may complete this action through cash purchases, exchange offers, privately negotiated transactions or otherwise, depending on prevailing market conditions, the Company’s liquidity requirements and other factors.


•	Growth Investments. The Company intends to use a portion of capital available for allocation during 2016 to complete its fuel repowerings, conversions and renewable investments.


•	Common Stock Dividends. On February 29, 2016, the Company announced a reduction in its common stock dividend to $0.12 per share on an annualized basis. The decision to reduce the common stock dividend is a proactive measure taken by the Company in order to reallocate capital in accordance with the priorities set forth in this section.

The Company will continue to monitor market conditions in light of the Company’s 2016 Capital Allocation Program to determine if adjustments are necessary in the future.

Dividends

The following table lists the dividends paid during the three months ended March 31, 2016:



	First Quarter 2016
Dividends per Common Share	$	0.145

On April 18, 2016, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable May 16, 2016, to stockholders of record as of May 2, 2016 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.

Debt Reduction

During the first quarter of 2016, the Company repurchased $203 million of its senior notes in open market transactions for $192 million, which included $3 million in accrued interest, as further described in Note 8, Debt and Capital Leases, to this Form 10-Q. Subsequent to quarter-end and through May 4, 2016, the Company repurchased an additional $26 million in aggregate principal of NRG Energy, Inc. senior notes.

Fuel Repowerings and Conversions

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
Fuel Conversions^(a)
Joliet Units 6, 7 and 8^(b)	1,326	Environmental	Natural Gas	Summer 2016
New Castle Units 3, 4 and 5	325	Growth	Natural Gas	Summer 2016
Shawville Units 1, 2, 3 and 4	597	Growth	Natural Gas	Fall 2016
Total	2,248
Repowerings
Carlsbad Peakers (formerly Encina) Units 1, 2, 3, 4, 5 and GT^(c)	527	Growth	Natural Gas	Winter 2018
Puente (formerly Mandalay) Units 1 and 2^(c)	262	Growth	Natural Gas	Summer 2020
Cielo Lindo (formerly P.H. Robinson) Peakers 1-6	360	Growth	Natural Gas	Summer 2016
Total	1,149

Total Fuel Repowerings and Conversions	3,397

(a) Does not include the natural gas conversions of Dunkirk Units 2, 3 and 4, which are on hold pending the outcome of outstanding litigation.

(b) The Company has incurred and will incur environmental capital expenditures to switch to gas to satisfy MATS.

Cash Flow Discussion

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



	Three months ended March 31,
	2016			2015			Change
	(In millions)
Net cash provided by operating activities	$	554		$	260		$	294
Net cash used in investing activities	(143		)	(270		)	127
Net cash (used)/provided by financing activities	(264		)	40			(304		)

Net Cash Provided By Operating Activities

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



	(In millions)
Change in cash collateral in support of risk management activities	$	369
Other Changes in working capital	(72		)
Decrease in operating income adjusted for non-cash items	(3		)
	$	294

Net Cash Used In Investing Activities

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



	(In millions)
Proceeds from sale of assets - Seward & Shelby	$	119
Decrease in investments in unconsolidated affiliates	40
Increase in restricted cash	13
Increase in cash grants	6
Increase in capital expenditures primarily related to growth projects	(27		)
Net decrease in nuclear decommissioning trust fund activity	(12		)
Net proceeds from the sale of emissions allowances	(5		)
Increase in acquisitions	(5		)
Other	(2		)
	$	127

Net Cash (Used)/Provided By Financing Activities

Changes to net cash (used)/provided by financing activities were driven by:



	(In millions)
Net decrease in borrowings, offset by debt payments which includes debt repurchases in 2016	$	(409	)
Contingent consideration payments in 2016	(10		)
Decrease in repurchases of treasury stock	79
Increase in cash contributions from noncontrolling interest	35
Other	1
	$	(304	)

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

For the three months ended March 31, 2016, the Company had total domestic pre-tax book income of $57 million and foreign pre-tax book income of $11 million. As of March 31, 2016, the Company has cumulative domestic NOL carryforwards of $4.0 billion and cumulative state NOL carryforwards of $4.2 billion for financial statement purposes. In addition, NRG has cumulative foreign NOL carryforwards of $213 million with no expiration date.

In addition to these amounts, the Company has $39 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 $40 million in 2016.

The Company has recorded a non-current tax liability of $42 million until final resolution with the related taxing authority. The $42 million non-current tax liability for uncertain tax benefits is from positions taken on various state income tax returns, including accrued interest.

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.

Derivative Instrument Obligations

The Company's 2.822% Preferred Stock includes a feature which is considered an embedded derivative in accordance with ASC 815. Although it is considered an embedded derivative, it is exempt from derivative accounting as it is excluded from the scope pursuant to ASC 815. As of March 31, 2016, based on the Company's stock price, the embedded derivative was out-of-the-money and had no redemption value.

Obligations Arising Out of a Variable Interest in an Unconsolidated Entity

Variable interest in equity investments — As of March 31, 2016, 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 $615 million as of March 31, 2016. 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 2015 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 2015 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, 2016.

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 2015 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, 2016, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at March 31, 2016.



Derivative Activity Gains/(Losses)	(In millions)
Fair value of contracts as of December 31, 2015	$	6
Contracts realized or otherwise settled during the period	(81		)
Changes in fair value	79
Fair Value of Contracts as of March 31, 2016	$	4



	Fair Value of Contracts as of March 31, 2016
	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	$	(143	)	$	(117	)	$	(18	)	$	—		$	(278	)
Level 2	326			36			(32		)	(31		)	299
Level 3	(17		)	3			(1		)	(2		)	(17		)
Total	$	166		$	(78	)	$	(51	)	$	(33	)	$	4

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, 2016, NRG's net derivative asset was $4 million, a decrease to total fair value of $2 million as compared to December 31, 2015. This decrease was driven by the roll-off of trades that settled during the period and gains 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 a decrease of approximately $219 million in the net value of derivatives as of March 31, 2016. The impact of a $0.50 per MMBtu decrease in natural gas prices across the term of derivative contracts would result in an increase of approximately $179 million in the net value of derivatives as of March 31, 2016.

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 U.S. GAAP. The preparation of these financial statements and related disclosures in compliance with U.S. 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, 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. 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 2015 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, 2016, and 2015:



(In millions)	2016		2015
VaR as of March 31,	$	59	$	47
Three months ended March 31,
Average	$	54	$	47
Maximum	60		54
Minimum	44		38

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, 2016, for the entire term of these instruments entered into for both asset management and trading was $35 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 2015 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, 2016, the Company would have owed the counterparties $189 million. Based on the investment grade rating 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, 2016, a 1% change in variable interest rates would result in a $23 million change in interest expense on a rolling twelve month basis.

As of March 31, 2016, the fair value and related carrying value of the Company's debt was $18.1 billion and $19.3 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 $1.4 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 $288 million as of March 31, 2016, and a 1 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral posted of approximately $240 million as of March 31, 2016. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of March 31, 2016.

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 2016 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, 2016, 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 2015 Form 10-K. There have been no material changes in the Company's risk factors since those reported in its 2015 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
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.

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 5, 2016	Chief Accounting Officer (Principal Accounting Officer)