Edgar Filing: NRG ENERGY, INC.

Large accelerated filer x

Accelerated filer o

Non-accelerated filer o

Smaller reporting company o

(Do not check if a smaller reporting company)

Document

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: June 30, 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.)

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

(609) 524-4500

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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 July 31, 2016, there were 315,280,157 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	58
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	100
ITEM 4 — CONTROLS AND PROCEDURES	102
PART II — OTHER INFORMATION	103
ITEM 1 — LEGAL PROCEEDINGS	103
ITEM 1A — RISK FACTORS	103
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	103
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES	103
ITEM 4 — MINE SAFETY DISCLOSURES	103
ITEM 5 — OTHER INFORMATION	103
ITEM 6 — EXHIBITS	104
SIGNATURES	105

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 for units subject to capacity performance requirements in PJM, performance incentives in ISO-NE, and scarcity pricing in ERCOT;


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


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


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


•	GenOn's ability to continue as a going concern;


•	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
2016 Revolving Credit Facility		The Company’s $2.5 billion revolving credit facility, a component of the 2016 Senior Credit Facility. The revolving credit facility consists of $289 million of Tranche A Revolving Credit Facility, due 2018, and $2.2 billion of Tranche B Revolving Credit Facility, due 2021.
2016 Senior Credit Facility		As of June 30, 2016, NRG’s new senior secured credit facility, comprised of a $1.9 billion term loan facility and a $2.5 billion revolving credit facility, which replaces the Senior Credit Facility.
2016 Term Loan Facility		The Company's $1.9 billion term loan facility due 2023, a component of the 2016 Senior Credit Facility.
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 GAAP
ASU		Accounting Standards Updates, which reflect updates to the ASC
Average realized prices		Volume-weighted average power prices, net of average fuel costs and reflecting the impact of settled hedges
BACT		Best Available Control Technology
BETM		Boston Energy Trading and Marketing LLC
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 1		NRG DGPV Holdco 1 LLC
DGPV Holdco 2		NRG DGPV Holdco 2 LLC
Discrete Customers		Customers measured by unit sales of one-time products or services, such as one-time in-home product installation/maintenance, 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 and other revenue, less cost of fuels and other 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
ESCO		Energy Service Company
ESP		Electrostatic Precipitator
ESPP		NRG Energy, Inc. Amended and Restated Employee Stock Purchase Plan
ESPS		Existing Source Performance Standards
Exchange Act		The Securities Exchange Act of 1934, as amended
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FirstEnergy		FirstEnergy Corp.
FPA		Federal Power Act
FTRs		Financial Transmission Rights
GAAP		Accounting principles generally accepted in the U.S.
GenConn		GenConn Energy LLC
GenOn		GenOn Energy, Inc.
GenOn Americas Generation		GenOn Americas Generation, LLC
GenOn Americas Generation Senior Notes		GenOn Americas Generation's $695 million outstanding unsecured senior notes consisting of $366 million of 8.5% senior notes due 2021 and $329 million of 9.125% senior notes due 2031
GenOn Mid-Atlantic		GenOn Mid-Atlantic, LLC and, except where the context indicates otherwise, its subsidiaries, which include the coal generation units at two generating facilities under operating leases
GenOn Senior Notes		GenOn's $1.8 billion outstanding unsecured senior notes consisting of $691 million of 7.875% senior notes due 2017, $649 million of 9.5% senior notes due 2018, and $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
LSE		Load Serving Entity
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)
Mass Market		Residential and small commercial customers
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		Megawatts
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 the economic interests of NRG Yield LLC with a controlling interest, and issuer of publicly held shares of Class A and Class C common stock
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
NYSERDA		New York State Energy Research and Development Authority
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		Reporting segment that includes NRG's residential and small commercial businesses which go to market as Reliant, NRG and other brands owned by NRG
Retail Mass Recurring Customers		Customers that subscribe to one or more recurring services, such as electricity, natural gas and protection products, the majority of which are retail electricity customers in Texas and the Northeast
Revolving Credit Facility		Prior to June 30, 2016, the Company's $2.5 billion revolving credit facility due 2018, a component of the Senior Credit Facility. On June 30, 2016, the Company replaced the Senior Credit Facility, including the Revolving Credit Facility, with the 2016 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		Prior to June 30, 2016, the Company's senior secured facility, comprised of the Term Loan Facility and the Revolving Credit Facility. On June 30, 2016, the Company replaced the Senior Credit Facility with the 2016 Senior Credit Facility.



Senior Notes		As of June 30, 2016, the Company’s $5.9 billion outstanding unsecured senior notes, consisting of $587 million of 7.625% senior notes due 2018, $818 million of 8.25% senior notes due 2020, $889 million of 7.875% senior notes due 2021, $992 million of 6.25% senior notes due 2022, $869 million of 6.625% senior notes due 2023, $734 million of 6.25% senior notes due 2024 and $1.0 billion of 7.25% senior notes due 2026.
Seward		The Seward Power Generating Station, a 525 MW coal-fired facility in Pennsylvania
SF6		Sulfur Hexafluoride
Shelby		The Shelby County Generating Station, a 352 MW natural gas-fired facility in Illinois
SO₂		Sulfur Dioxide
STP		South Texas Project — nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest
S&P		Standard & Poor's
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		Prior to June 30, 2016, the Company's $2.0 billion term loan facility due 2018, a component of the Senior Credit Facility. On June 30, 2016, the Company replaced its Senior Credit Facility, including the Term Loan Facility, with the 2016 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
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 June 30,						Six months ended June 30,
(In millions, except for per share amounts)	2016			2015			2016			2015
Operating Revenues
Total operating revenues	$	2,638		$	3,400		$	5,867		$	7,229
Operating Costs and Expenses
Cost of operations	1,756			2,436			3,945			5,509
Depreciation and amortization	309			396			622			791
Impairment losses	115			—			115			—
Selling, general and administrative	265			296			520			551
Acquisition-related transaction and integration costs	5			3			7			13
Development activity expenses	18			37			44			71
Total operating costs and expenses	2,468			3,168			5,253			6,935
Gain on postretirement benefits curtailment	—			—			—			14
Loss on sale of assets, net of gains	(83		)	—			(51		)	—
Operating Income	87			232			563			308
Other Income/(Expense)
Equity in earnings/(losses) of unconsolidated affiliates	4			8			(3		)	5
Gain/(impairment loss) on investment	7			—			(139		)	—
Other income, net	8			4			26			23
Loss on debt extinguishment	(80		)	(7		)	(69		)	(7		)
Interest expense	(277		)	(263		)	(561		)	(564		)
Total other expense	(338		)	(258		)	(746		)	(543		)
Loss Before Income Taxes	(251		)	(26		)	(183		)	(235		)
Income tax expense/(benefit)	25			(17		)	46			(90		)
Net Loss	(276		)	(9		)	(229		)	(145		)
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interests	(5		)	5			(40		)	(11		)
Net Loss Attributable to NRG Energy, Inc.	(271		)	(14		)	(189		)	(134		)
Gain on redemption, net of dividends for preferred shares	(78		)	5			(73		)	10
Loss Available for Common Stockholders	$	(193	)	$	(19	)	$	(116	)	$	(144	)
Loss per Share Attributable to NRG Energy, Inc. Common Stockholders
Weighted average number of common shares outstanding — basic and diluted	315			333			315			335
Loss per Weighted Average Common Share — Basic and Diluted	$	(0.61	)	$	(0.06	)	$	(0.37	)	$	(0.43	)
Dividends Per Common Share	$	0.03		$	0.14		$	0.18		$	0.29

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

(Unaudited)



	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
	(In millions)
Net Loss	$	(276	)	$	(9	)	$	(229	)	$	(145	)
Other Comprehensive (Loss)/Income, net of tax
Unrealized (loss)/gains on derivatives, net of income tax expense of $1, $12, $2 and $6	(3		)	16			(35		)	4
Foreign currency translation adjustments, net of income tax expense/(benefit) of $0 , $6, $0 and $(1)	(3		)	9			3			(2		)
Available-for-sale securities, net of income tax benefit of $0, $3, $0 and $7	(2		)	(3		)	1			(4		)
Defined benefit plans, net of tax expense of $0, $0, $0 and $4	—			(1		)	1			6
Other comprehensive (loss)/income	(8		)	21			(30		)	4
Comprehensive (Loss)/Income	(284		)	12			(259		)	(141		)
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interests	(16		)	12			(68		)	(17		)
Comprehensive Loss Attributable to NRG Energy, Inc.	(268		)	—			(191		)	(124		)
Gain on redemption, net of dividends for preferred shares	(78		)	5			(73		)	10
Comprehensive Loss Available for Common Stockholders	$	(190	)	$	(5	)	$	(118	)	$	(134	)

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS



	June 30, 2016			December 31, 2015
(In millions, except shares)	(unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	1,389		$	1,518
Funds deposited by counterparties	44			106
Restricted cash	413			414
Accounts receivable — trade, less allowance for doubtful accounts of $20 and $21	1,251			1,157
Inventory	1,124			1,252
Derivative instruments	1,470			1,915
Cash collateral paid in support of energy risk management activities	218			568
Renewable energy grant receivable, net	36			13
Current assets held-for-sale	13			6
Prepayments and other current assets	406			442
Total current assets	6,364			7,391
Property, plant and equipment, net of accumulated depreciation of $6,107 and $5,761	18,382			18,732
Other Assets
Equity investments in affiliates	882			1,045
Notes receivable, less current portion	25			53
Goodwill	999			999
Intangible assets, net of accumulated amortization of $1,650 and $1,525	2,180			2,310
Nuclear decommissioning trust fund	599			561
Derivative instruments	348			305
Deferred income taxes	175			167
Non-current assets held-for-sale	229			105
Other non-current assets	1,239			1,214
Total other assets	6,676			6,759
Total Assets	$	31,422		$	32,882
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	1,215		$	481
Accounts payable	898			869
Derivative instruments	1,373			1,721
Cash collateral received in support of energy risk management activities	44			106
Current liabilities held-for-sale	2			2
Accrued expenses and other current liabilities	982			1,196
Total current liabilities	4,514			4,375
Other Liabilities
Long-term debt and capital leases	17,893			18,983
Nuclear decommissioning reserve	334			326
Nuclear decommissioning trust liability	309			283
Deferred income taxes	42			19
Derivative instruments	539			493
Out-of-market contracts, net of accumulated amortization of $712 and $664	1,093			1,146
Non-current liabilities held-for-sale	—			4
Other non-current liabilities	1,554			1,488
Total non-current liabilities	21,764			22,742
Total Liabilities	26,278			27,117
2.822% convertible perpetual preferred stock	—			302
Redeemable noncontrolling interest in subsidiaries	23			29
Commitments and Contingencies
Stockholders’ Equity
Common stock	4			4
Additional paid-in capital	8,306			8,296
Retained deficit	(3,179		)	(3,007		)
Less treasury stock, at cost — 102,450,781 and 102,749,908 shares, respectively	(2,406		)	(2,413		)
Accumulated other comprehensive loss	(203		)	(173		)
Noncontrolling interest	2,599			2,727
Total Stockholders’ Equity	5,121			5,434
Total Liabilities and Stockholders’ Equity	$	31,422		$	32,882

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Six months ended June 30,
	2016			2015
	(In millions)
Cash Flows from Operating Activities
Net Loss	$	(229	)	$	(145	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates	32			40
Depreciation and amortization	622			791
Provision for bad debts	20			29
Amortization of nuclear fuel	26			23
Amortization of financing costs and debt discount/premiums	3			(7		)
Adjustment to loss on debt extinguishment	14			7
Amortization of intangibles and out-of-market contracts	41			32
Amortization of unearned equity compensation	16			24
Impairment losses	254			—
Changes in deferred income taxes and liability for uncertain tax benefits	1			(98		)
Changes in nuclear decommissioning trust liability	13			(4		)
Changes in derivative instruments	(25		)	186
Changes in collateral deposits supporting energy risk management activities	350			(112		)
Proceeds from sale of emission allowances	47			—
Loss/(gain) on sale of assets and postretirement benefits curtailment	43			(14		)
Cash used by changes in other working capital	(355		)	(294		)
Net Cash Provided by Operating Activities	873			458
Cash Flows from Investing Activities
Acquisitions of businesses, net of cash acquired	(17		)	(30		)
Capital expenditures	(622		)	(583		)
Decrease/(increase) in restricted cash, net	29			(3		)
(Increase)/decrease in restricted cash to support equity requirements for U.S. DOE funded projects	(28		)	27
(Increase)/decrease in notes receivable	(3		)	7
Purchases of emission allowances	(27		)	—
Proceeds from sale of emission allowances	25			—
Investments in nuclear decommissioning trust fund securities	(280		)	(354		)
Proceeds from the sale of nuclear decommissioning trust fund securities	267			358
Proceeds from renewable energy grants and state rebates	10			61
Proceeds from sale of assets, net of cash disposed of	145			1
Investments in unconsolidated affiliates	—			(353		)
Other	32			9
Net Cash Used by Investing Activities	(469		)	(860		)
Cash Flows from Financing Activities
Payment of dividends to common and preferred stockholders	(57		)	(102		)
Payment for treasury stock	—			(186		)
Payment for preferred shares	(226		)	—
Net receipts from settlement of acquired derivatives that include financing elements	103			91
Proceeds from issuance of long-term debt	3,223			629
Distributions from, net of contributions to, noncontrolling interest in subsidiaries	(21		)	670
Proceeds from issuance of common stock	—			1
Payment of debt issuance costs	(35		)	(12		)
Payments for short and long-term debt	(3,507		)	(662		)
Other - contingent consideration	(10		)	—
Net Cash (Used)/Provided by Financing Activities	(530		)	429
Effect of exchange rate changes on cash and cash equivalents	(3		)	3
Net (Decrease)/Increase in Cash and Cash Equivalents	(129		)	30
Cash and Cash Equivalents at Beginning of Period	1,518			2,116
Cash and Cash Equivalents at End of Period	$	1,389		$	2,146

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 use energy products and services. NRG has one of the nation's largest and most diverse competitive power generation portfolios balanced with a leading retail electricity platform. The Company owns and operates approximately 48,000 MW of generation; engages in the trading of wholesale energy, capacity and related products; transacts in and trades fuel and transportation services; and directly sells energy, services, and innovative, sustainable products and services to retail customers under the names “NRG,” "Reliant" and other retail brand names owned by NRG.

The accompanying unaudited interim condensed consolidated financial statements have been prepared in accordance with the SEC's regulations for interim financial information and with the instructions to Form 10-Q. Accordingly, they do not include all of the information and notes required by generally accepted accounting principles for complete financial statements. The following notes should be read in conjunction with the accounting policies and other disclosures as set forth in the notes to the consolidated financial statements in the Company's 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 June 30, 2016, and the results of operations, comprehensive income/(loss) and cash flows for the three and six months ended June 30, 2016, and 2015.

Use of Estimates

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

Reclassifications

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

The Company decreased accumulated depreciation and facilities and equipment within total property, plant and equipment by approximately $1 billion, respectively, to adjust amounts previously presented as of December 31, 2015. This adjustment had no impact on net assets at December 31, 2015. Accordingly, the Company does not consider the adjustment to be material to the consolidated balance sheet. Consolidated operating income and net loss for the three months and six months ended June 30, 2016 were not impacted by the adjustment.

Note 2 — Summary of Significant Accounting Policies

Other Cash Flow Information

NRG’s investing activities exclude capital expenditures of $96 million which were accrued and unpaid at June 30, 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	(82		)
Contributions from noncontrolling interest	13
Redemption of noncontrolling interest	(8		)
Comprehensive loss attributable to noncontrolling interest	(51		)
Balance as of June 30, 2016	$	2,599

Redeemable Noncontrolling Interest

The following table reflects the changes in the Company's redeemable noncontrolling interest balance for the six months ended June 30, 2016:



	(In millions)
Balance as of December 31, 2015	$	29
Distributions to redeemable noncontrolling interest	(1		)
Contributions from redeemable noncontrolling interest	12
Comprehensive loss attributable to redeemable noncontrolling interest	(17		)
Balance as of June 30, 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 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 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 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 No. 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 addition to ASU No. 2014-09, the FASB has issued additional guidance which provides further clarification on Topic 606. 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. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606), or ASU No. 2016-12. The amendments of ASU No. 2016-12 provide further clarification on contract revenue recognition as updated by ASU No. 2014-09, specifically related to collectibility, the presentation of tax collected from customers, and non-cash consideration, as well as offering practical expedients. The Company is working through an adoption plan which includes the evaluation of revenue contracts compared to the new standard and evaluating the impact of Topic 606 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

Disposition of Majority Interest in EVgo

On June 17, 2016, the Company completed the sale of a majority interest in its EVgo business to Vision Ridge Partners for total consideration of approximately $39 million, including $17 million in cash received, which is net of $2.5 million in working capital adjustments, $15 million contributed as capital to the EVgo business and $7 million of future contributions by Vision Ridge Partners. all of which were determined based on forecasted cash requirements to operate the business in future periods. In addition, the Company has future earnout potential of up to $70 million based on future profitability targets. NRG will retain its original financial obligation of $102.5 million under its agreement with the CPUC whereby EVgo will build at least 200 public fast charging Freedom Station sites and perform the associated work to prepare 10,000 commercial and multi-family parking spaces for electric vehicle charging in California. As part of the sale, NRG has contracted with EVgo to continue to build the remaining required Freedom Stations and commercial and multi-family parking spaces for electric vehicle charging required under this obligation and will be directly reimbursed by NRG for the costs. As a result of the sale, the Company recorded a loss on sale of $83 million during the second quarter of 2016, which reflects the loss on the sale of the equity interest of $27 million and the accrual of NRG's remaining obligation under its agreement with the CPUC of $56 million. At June 30, 2016, the Company's remaining 35% interest in EVgo was accounted for as an equity-method investment at its fair value of $10 million.

Rockford Disposition

On May 12, 2016, the Company entered into an agreement with RA Generation, LLC to sell 100% of its interests in the Rockford I and Rockford II generating stations, or Rockford, for cash consideration of $55 million, subject to adjustments for working capital and the results of the PJM 2019/2020 base residual auction. Rockford is a 450 MW natural gas facility located in Rockford, Illinois. The transaction triggered an indicator of impairment as the sales price was less than the carrying amount of the assets, and, as a result the assets were considered to be impaired. The Company measured the impairment loss as the difference between the carrying amount of the assets and the agreed-upon sales price. The Company recorded an impairment loss of $17 million during the quarter ended June 30, 2016 to reduce the carrying amount of the assets held for sale to the fair market value. At June 30, 2016, the Company had $2 million of current assets and $54 million of non-current assets classified as held for sale for Rockford on its balance sheet. On July 12, 2016, the Company completed the sale of Rockford for cash proceeds of $56 million, including $1 million in adjustments for the PJM base residual auction results. For further discussion on this impairment, refer to Note 7, Impairments.

Aurora Disposition

On May 12, 2016, GenOn entered into an agreement with RA Generation, LLC to sell the Aurora generating station, or Aurora, for cash consideration of $365 million, subject to adjustments for working capital and the results of the PJM 2019/2020 base residual auction. Aurora is a 878 MW natural gas facility located in Aurora, Illinois. At June 30, 2016, GenOn had $2 million of current assets, $175 million of non-current assets and $2 million of current liabilities classified as held for sale for Aurora on its balance sheet. On July 12, 2016, GenOn completed the sale of Aurora for cash proceeds of $369 million, including $4 million in adjustments for the PJM base residual auction results and estimated working capital, which is subject to further adjustment. The sale will result in a gain of approximately $189 million to be recognized within GenOn's consolidated results of operations during the third quarter of 2016.

Seward Disposition

On November 24, 2015, GenOn entered into an agreement with an affiliate of Robindale Energy Services, Inc. to sell 100% of its interest in the Seward generating station, a 525 MW coal-fired facility in Pennsylvania, for cash consideration of $75 million. 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 an affiliate of Rockland Power Partners II, LP to sell 100% of its interest in the Shelby generating station, a 352 MW natural gas-fired facility located in Illinois for cash consideration of $46 million. 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 the 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 August 8, 2016, the Company entered into an agreement to sell the remaining 51.05% interest in the CVSR project to NRG Yield, Inc. for total expected consideration of $78.5 million plus assumed debt and working capital adjustments to be calculated at close. The sale is subject to customary closing conditions and is expected to close during the third quarter of 2016.

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 June 30, 2016				As of December 31, 2015
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Assets:
Notes receivable^(a)	$	54	$	54	$	73	$	73
Liabilities:
Long-term debt, including current portion^(b)	19,253		18,593		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 June 30, 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	$	—	$	—	$	16	$	16
Available-for-sale securities	11		—		—		11
Other ^(a)	11		—		—		11
Nuclear trust fund investments:
Cash and cash equivalents	33		—		—		33
U.S. government and federal agency obligations	55		1		—		56
Federal agency mortgage-backed securities	—		69		—		69
Commercial mortgage-backed securities	—		19		—		19
Corporate debt securities	—		81		—		81
Equity securities	289		—		51		340
Foreign government fixed income securities	—		1		—		1
Other trust fund investments:
U.S. government and federal agency obligations	1		—		—		1
Derivative assets:
Commodity contracts	595		1,007		216		1,818
Total assets	$	995	$	1,178	$	283	$	2,456
Derivative liabilities:
Commodity contracts	529		974		209		1,712
Interest rate contracts	—		200		—		200
Total liabilities	$	529	$	1,174	$	209	$	1,912

(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 and six months ended June 30, 2016, and 2015 between Levels 1 and 2. The following tables reconcile, for the three and six months ended June 30, 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 June 30, 2016												Six months ended June 30, 2016
(In millions)	Debt Securities			Trust Fund Investments			Derivatives^(a)			Total			Debt Securities			Trust Fund Investments			Derivatives^(a)			Total
Beginning balance	$	17		$	52		$	(17	)	$	52		$	17		$	54		$	(33	)	$	38
Total gains/(losses) — realized/unrealized:
Included in earnings	—			—			24			24			—			—			7			7
Included in OCI	(1		)	—			—			(1		)	(1		)	—			—			(1		)
Included in nuclear decommissioning obligation	—			(1		)	—			(1		)	—			(4		)	—			(4		)
Purchases	—			—			24			24			—			1			29			30
Transfers into Level 3 ^(b)	—			—			(20		)	(20		)	—			—			7			7
Transfers out of Level 3 ^(b)	—			—			(4		)	(4		)	—			—			(3		)	(3		)
Ending balance as of June 30, 2016	$	16		$	51		$	7		$	74		$	16		$	51		$	7		$	74
Gains/(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 June 30, 2016	$	—		$	—		$	9		$	9		$	—		$	—		$	(15	)	$	(15	)


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


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



	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Three months ended June 30, 2015													Six months ended June 30, 2015
(In millions)	Debt Securities		Other			Trust Fund Investments		Derivatives^(a)			Total			Debt Securities		Other			Trust Fund Investments		Derivatives^(a)			Total
Beginning balance	$	18	$	11		$	54	$	34		$	117		$	18	$	11		$	52	$	80		$	161
Total gains/(losses) — realized/unrealized:
Included in earnings	—		(11		)	—		(23		)	(34		)	—		(11		)	—		(78		)	(89		)
Included in nuclear decommissioning obligations	—		—			—		—			—			—		—			2		—			2
Purchases	—		—			1		39			40			—		—			1		35			36
Transfers into Level 3 ^(b)	—		—			—		(4		)	(4		)	—		—			—		11			11
Transfers out of Level 3 ^(b)	—		—			—		3			3			—		—			—		1			1
Ending balance as of June 30, 2015	$	18	$	—		$	55	$	49		$	122		$	18	$	—		$	55	$	49		$	122
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 June 30, 2015	$	—	$	—		$	—	$	(8	)	$	(8	)	$	—	$	—		$	—	$	(28	)	$	(28	)


(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 June 30, 2016, contracts valued with prices provided by models and other valuation techniques make up 12% of the total derivative assets and 11% 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 June 30, 2016 and December 31, 2015:



	Significant Unobservable Inputs
	June 30, 2016
	Fair Value						Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average
	(In millions)
Power Contracts	$	165	$	146	Discounted Cash Flow	Forward Market Price (per MWh)	$	10		$	108	$	38
Coal Contracts	—		13		Discounted Cash Flow	Forward Market Price (per ton)	28			38		33
FTRs	51		50		Discounted Cash Flow	Auction Prices (per MWh)	(97		)	29		—
	$	216	$	209



	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 June 30, 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 June 30, 2016, the credit reserve resulted in a $6 million increase in fair value, which is composed of a $4 million gain in OCI and a $2 million gain in operating revenue and cost of operations. As of June 30, 2015, the credit reserve resulted in a $3 million increase in fair value, which was composed of a $1 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 June 30, 2016, counterparty credit exposure, excluding credit risk exposure under certain long term agreements, was $678 million and NRG held collateral (cash and letters of credit) against those positions of $53 million, resulting in a net exposure of $646 million. Approximately 87% 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	53	%
Utilities, energy merchants, marketers and other	29
ISOs	18
Total as of June 30, 2016	100	%



	Net Exposure ^(a)
Category	(% of Total)
Investment grade	97	%
Non-rated ^(b)	2
Non-investment grade	1
Total as of June 30, 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 $296 million as of June 30, 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 June 30, 2016, aggregate credit risk exposure managed by NRG to these counterparties was approximately $4.1 billion, including $2.5 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 June 30, 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 June 30, 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	$	33	$	—	$	—	—	$	6	$	—	$	—	—
U.S. government and federal agency obligations	56		5		—		12	55		1		—		11
Federal agency mortgage-backed securities	69		2		—		24	59		1		—		25
Commercial mortgage-backed securities	19		—		1		27	25		—		2		28
Corporate debt securities	81		3		—		11	81		1		1		10
Equity securities	340		202		—		—	334		199		—		—
Foreign government fixed income securities	1		—		—		8	1		—		—		9
Total	$	599	$	212	$	1		$	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.



	Six months ended June 30,
	2016		2015
	(In millions)
Realized gains	$	3	$	9
Realized losses	2		5
Proceeds from sale of securities	267		358

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 June 30, 2016, NRG had energy-related derivative instruments extending through 2027. The Company marks 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 June 30, 2016, the Company had interest rate derivative instruments on recourse debt extending through 2021, which are not designated as cash flow hedges. The Company had interest rate swaps on non-recourse debt extending through 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 June 30, 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
		June 30, 2016			December 31, 2015
Category	Units	(In millions)
Emissions	Short Ton	—			1
Coal	Short Ton	27			35
Natural Gas	MMBtu	136			293
Oil	Barrel	1			1
Power	MWh	(45		)	(74		)
Capacity	MW/Day	(1		)	(1		)
Interest	Dollars	$	3,184		$	2,326
Equity	Shares	1			1

The decrease in the natural gas position was primarily the result of settlement of generation and retail hedge positions. The increase in the interest rate position was primarily the result of entering into new interest rate swaps to hedge the Term Loan Facility, as described in Note 8, Debt and Capital Leases.

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
	June 30, 2016		December 31, 2015		June 30, 2016		December 31, 2015
	(In millions)
Derivatives designated as cash flow hedges:
Interest rate contracts current	$	—	$	—	$	39	$	42
Interest rate contracts long-term	—		—		124		68
Total derivatives designated as cash flow hedges	—		—		163		110
Derivatives not designated as cash flow hedges:
Interest rate contracts current	—		—		9		5
Interest rate contracts long-term	—		—		28		13
Commodity contracts current	1,470		1,915		1,325		1,674
Commodity contracts long-term	348		305		387		412
Total derivatives not designated as cash flow hedges	1,818		2,220		1,749		2,104
Total derivatives	$	1,818	$	2,220	$	1,912	$	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 June 30, 2016	(In millions)
Commodity contracts:
Derivative assets	$	1,818		$	(1,525	)	$	(53	)	$	240
Derivative liabilities	(1,712		)	1,525			17			(170		)
Total commodity contracts	106			—			(36		)	70
Interest rate contracts:
Derivative liabilities	(200		)	—			—			(200		)
Total derivative instruments	$	(94	)	$	—		$	(36	)	$	(130	)



	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 June 30, 2016								Six months ended June 30, 2016
	Energy Commodities		Interest Rate			Total			Energy Commodities		Interest Rate			Total
	(In millions)
Accumulated OCI beginning balance	$	—	$	(150	)	$	(150	)	$	—	$	(101	)	$	(101	)
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	—		7			7			—		10			10
Mark-to-market of cash flow hedge accounting contracts	—		(22		)	(22		)	—		(74		)	(74		)
Accumulated OCI ending balance, net of $26 tax	$	—	$	(165	)	$	(165	)	$	—	$	(165	)	$	(165	)
Losses expected to be realized from OCI during the next 12 months, net of $3 tax	$	—	$	22		$	22		$	—	$	22		$	22



	Three months ended June 30, 2015									Six months ended June 30, 2015
	Energy Commodities			Interest Rate			Total			Energy Commodities			Interest Rate			Total
	(In millions)
Accumulated OCI beginning balance	$	(1	)	$	(83	)	$	(84	)	$	(1	)	$	(67	)	$	(68	)
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	—			2			2			—			4			4
Mark-to-market of cash flow hedge accounting contracts	—			19			19			—			1			1
Accumulated OCI ending balance, net of $37 tax	$	(1	)	$	(62	)	$	(63	)	$	(1	)	$	(62	)	$	(63	)

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 and six months ended June 30, 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 June 30,						Six months ended June 30,
	2016			2015			2016			2015
Unrealized mark-to-market results	(In millions)
Reversal of previously recognized unrealized gains on settled positions related to economic hedges	$	(51	)	$	(36	)	$	(137	)	$	(150	)
Reversal of acquired gain positions related to economic hedges	(15		)	(24		)	(28		)	(50		)
Net unrealized (losses)/gains on open positions related to economic hedges	(32		)	57			102			(81		)
Total unrealized mark-to-market losses for economic hedging activities	(98		)	(3		)	(63		)	(281		)
Reversal of previously recognized unrealized losses/(gains) on settled positions related to trading activity	2			(15		)	10			(36		)
Reversal of acquired gain positions related to trading activity	—			(5		)	—			(12		)
Net unrealized gains/(losses) on open positions related to trading activity	11			(4		)	22			2
Total unrealized mark-to-market gains/(losses) for trading activity	13			(24		)	32			(46		)
Total unrealized losses	$	(85	)	$	(27	)	$	(31	)	$	(327	)



	Three months ended June 30,						Six months ended June 30,
	2016			2015			2016			2015
	(In millions)
Unrealized losses included in operating revenues	$	(526	)	$	(137	)	$	(481	)	$	(246	)
Unrealized gains/(losses) included in cost of operations	441			110			450			(81		)
Total impact to statement of operations — energy commodities	$	(85	)	$	(27	)	$	(31	)	$	(327	)
Total impact to statement of operations — interest rate contracts	$	(7	)	$	35		$	(18	)	$	21

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 six months ended June 30, 2016, the $102 million unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward purchases of ERCOT electricity and natural gas due to increases in ERCOT power and natural gas prices, partially offset by a decrease in value of forward sales of PJM electricity due to decreases in PJM power prices.

For the six months ended June 30, 2015, the $81 million unrealized loss from open economic hedge positions was primarily the result of a decrease in value of forward purchases of ERCOT electricity and coal due to decreases in ERCOT power and coal prices partially offset by an increase in value of forward sales of PJM electricity due to decreases in PJM power prices.

During 2016, the Company has been undergoing the process of closing out and financially settling certain open positions with counterparties. The closure and financial settlements with these counterparties were necessary to manage the increase in collateral posting requirements following rating agency downgrades for GenOn and to reduce expected collateral costs associated with exchange cleared hedge transactions. As discussed above, GenOn realized approximately $38 million due to the closure and financial settlement of all open positions with one of GenOn's counterparties during the three months ended June 30, 2016. GenOn expects to close out and financially settle certain open positions with an additional counterparty during the third quarter of 2016. These positions had a fair market value of $80 million as of June 30, 2016. As of July 31, 2016, GenOn has realized $98 million due to the closure and financial settlement of these positions which would have otherwise been realized in 2017 through 2019.

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 June 30, 2016, was $80 million. The collateral required for contracts with credit rating contingent features as of June 30, 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 $9 million as of June 30, 2016.

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

Note 7 — Impairments

Rockford — As described in Note 3, Business Acquisitions and Dispositions, on May 12, 2016, the Company entered into an agreement with RA Generation, LLC to sell 100% of its interests in the Rockford generating stations for cash consideration of $55 million. The transaction triggered an indicator of impairment as the sale price was less than the carrying amount of the assets, and, as a result, the assets were considered to be impaired. The Company measured the impairment loss as the difference between the carrying amount of the assets and the agreed-upon sale price. The Company recorded an impairment loss of $17 million during the quarter ended June 30, 2016, to reduce the carrying amount of the assets held for sale to the fair market value.

Mandalay and Ormond Beach — On May 26, 2016, the CPUC rejected a multi-year resource adequacy contract between Mandalay and SCE. Also occurring during the second quarter of 2016, the Statewide Advisory Committee on Cooling Water Intake Structures, or SACCWIS, issued a draft April 2016 Report noting that CAISO plans to continue to assume in its transmission studies that Ormond Beach will not operate after December 31, 2020, the deadline for Ormond Beach compliance with California regulations to mitigate once-through cooling (OTC) impacts. The Company does not anticipate that contracts of sufficient value can be secured to support the significant investment required to design, permit, construct and operate measures required for OTC compliance. As a result, on May 6, 2016, the Company notified SACCWIS that it does not expect to continue to operate Ormond Beach beyond 2020. Additionally, during the second quarter of 2016, CAISO issued its Local Capacity Requirements report for 2017 indicating unfavorable changes within the local reliability areas in which both Mandalay and Ormond Beach are located. The culmination of these events were considered to be indicators of impairment and as a result, the Company performed impairment tests for the Mandalay and Ormond Beach assets under ASC 360, Property, Plant and Equipment. Based on the results of the impairment tests, the Company determined that the carrying amount of these assets was higher than the estimated future net cash flows expected to be generated by the respective assets and that the Mandalay and Ormond Beach assets were impaired. The fair value of the Mandalay and Ormond Beach operating units was determined using the income approach which utilizes estimates of discounted future cash flows, which were Level 3 fair value measurements and include key inputs such as forecasted contract prices, forecasted operating expenses and discount rates. The Company measured the impairment losses as the difference between the carrying amount of the Mandalay and Ormond Beach operating units and the present value of the estimated future net cash flows for each respective operating unit. The Company recorded an impairment loss of $16 million and $43 million for Mandalay and Ormond Beach, respectively, during the quarter ended June 30, 2016.

Other Impairments — During the second quarter of 2016, the Company recorded impairment losses for intangible assets of $8 million in connection with the Company's strategic change in its residential solar business as well as $10 million of deferred marketing expenses. In addition, the Company also recorded an impairment loss of $17 million to record certain previously purchased solar panels at fair market value.

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

Note 8 — Debt and Capital Leases

This footnote should be read in conjunction with the complete description under Note 12, Debt and Capital Leases, to the Company's 2015 Form 10-K. Long-term debt and capital leases consisted of the following:



(In millions, except rates)	June 30, 2016		December 31, 2015		June 30, 2016 interest rate % ^(a)

Recourse debt:
Senior notes, due 2018	$	587	$	1,039	7.625
Senior notes, due 2020	818		1,058		8.250
Senior notes, due 2021	889		1,128		7.875
Senior notes, due 2022	992		1,100		6.250
Senior notes, due 2023	869		936		6.625
Senior notes, due 2024	734		904		6.250
Senior notes, due 2026	1,000		—		7.250
Term loan facility, due 2018	—		1,964		L+2.00
Term loan facility, due 2023	1,890		—		L+2.75
Tax-exempt bonds	455		455		4.125 - 6.00
Subtotal NRG recourse debt	8,234		8,584
Non-recourse debt:
GenOn senior notes	1,934		1,956		7.875 - 9.875
GenOn Americas Generation senior notes	748		752		8.500 - 9.125
GenOn Other	53		56
Subtotal GenOn debt (non-recourse to NRG)	2,735		2,764
Yield Operating LLC Senior Notes, due 2024	500		500		5.375
Yield LLC and Yield Operating LLC Revolving Credit Facility, due 2019	318		306		L+2.75
Yield Inc. Convertible Senior Notes, due 2019	333		330		3.500
Yield Inc. Convertible Senior Notes, due 2020	268		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	978		1,002		5.696 - 7.015
Walnut Creek, term loans due 2023	341		351		L+1.625
Tapestry, due 2021	176		181		L+1.625
Laredo Ridge, due 2028	102		104		L+1.875
Alpine, due 2022	151		154		L+1.750
Energy Center Minneapolis, due 2017 and 2025	100		108		5.95 - 7.25
Viento, due 2023	183		189		L+2.75
NRG Yield - other	455		469		various
Subtotal NRG Yield debt (non-recourse to NRG)	4,772		4,863
Ivanpah, due 2033 and 2038	1,141		1,149		2.285 - 4.256
Agua Caliente, due 2037	874		879		2.395 - 3.633
CVSR, due 2037	780		793		2.339 - 3.775
Dandan, due 2033	101		98		L+2.25
Peaker bonds, due 2019	—		72		L+1.07
Cedro Hill, due 2025	100		103		L+3.125
Midwest Generation, due 2019	249		—		4.390
NRG Other	267		315		various
Subtotal other NRG non-recourse debt	3,512		3,409
Subtotal all non-recourse debt	11,019		11,036
Subtotal long-term debt (including current maturities)	19,253		19,620
Capital leases:
Capital leases	13		13		various
Other	2		3		various
Subtotal long-term debt and capital leases (including current maturities)	19,268		19,636
Less current maturities	1,215		481
Less debt issuance costs	160		172
Total long-term debt and capital leases	$	17,893	$	18,983

(a) As of June 30, 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, and 2016 Term Loan Facility, which are 1 month LIBOR plus x%.

NRG Recourse Debt

Senior Notes

Issuance of 2026 Senior Notes

On May 23, 2016, NRG issued $1.0 billion in aggregate principal amount at par of 7.25% senior notes due 2026, or the 2026 Senior Notes. The 2026 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest is paid semi-annually beginning on November 15, 2016, until the maturity date of May 15, 2026. The proceeds from the issuance of the 2026 Senior Notes were utilized to redeem a portion of the Senior Notes discussed below.

Issuance of 2027 Senior Notes

On August 2, 2016, NRG issued $1.25 billion in aggregate principal amount at par of 6.625% senior notes due 2027, or the 2027 Senior Notes. The 2027 Senior Notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest is paid semi-annually beginning on January 15, 2017, until the maturity date of January 15, 2027. The proceeds from the issuance of the 2027 Senior Notes will be utilized to retire the Company's 8.250% senior notes due 2020 and reduce the balance of the Company's 7.875% senior notes due 2021.

2016 Senior Notes Repurchases

During the six months ended June 30, 2016, the Company repurchased $1.3 billion in aggregate principal of its Senior Notes in the open market for $1.3 billion, which included accrued interest of $21 million. In connection with the repurchases, a $45 million loss on debt extinguishment was recorded, which included the write-off of previously deferred financing costs of $7 million.



	Principal Repurchased		Cash Paid ^(a)		Average Early Redemption Percentage
Amount in millions, except rates
7.625% senior notes due 2018	$	451	$	499	107.95	%
7.875% senior notes due 2021	240		250		104.19	%
6.625% senior notes due 2023	67		64		94.13	%
6.250% senior notes due 2022	108		105		94.73	%
6.250% senior notes due 2024	171		163		94.52	%
8.250% senior notes due 2020	239		254		104.38	%
Total	$	1,276	$	1,335

(a) Includes accrued interest.

Senior Credit Facility

On June 30, 2016, NRG replaced its Senior Credit Facility, consisting of its Term Loan Facility and Revolving Credit Facility with a new senior secured facility, or the 2016 Senior Credit Facility, which includes the following:

•

A $1.9 billion term loan facility, or the 2016 Term Loan Facility, with a maturity date of June 30, 2023, which will pay interest at a rate of LIBOR plus 2.75%, with a LIBOR floor of 0.75%. The debt was issued at 99.50% of face value; the discount will be amortized to interest expense over the life of the loan. Repayments under the 2016 Term Loan Facility will consist of 0.25% of principal per quarter, with the remainder due at maturity. The proceeds of the new term loan facility as well as cash on hand were used to repay the existing 2018 Term Loan Facility balance outstanding. A $21 million loss on extinguishment of the Term Loan Facility was recorded, which consisted of the write-off of previously deferred financing costs.


•	The 2016 Revolving Credit Facility, which includes a $289 million revolving senior credit facility, or the Tranche A Revolving Facility, with a maturity date of July 1, 2018 and a $2.2 billion revolving senior credit facility, or the Tranche B Revolving Facility, with a maturity date of June 30, 2021 will pay interest at a rate of LIBOR plus 2.25%.

The 2016 Senior Credit Facility is guaranteed by substantially all of NRG's existing and future direct and indirect subsidiaries, with certain customary or agreed-upon exceptions for unrestricted foreign subsidiaries, and certain other subsidiaries, including GenOn and NRG Yield, Inc. and their respective subsidiaries. The capital stock of these guarantor subsidiaries has been pledged for the benefit of the 2016 Senior Credit Facility's lenders.

The 2016 Senior Credit Facility is also secured by first-priority perfected security interests in substantially all of the property and assets owned or acquired by NRG and its subsidiaries, other than certain limited exceptions. These exceptions include assets of certain unrestricted subsidiaries, equity interests in certain of NRG's affiliates that have non-recourse debt financing, including GenOn and NRG Yield, Inc. and their respective subsidiaries, and voting equity interests in excess of 66% of the total outstanding voting equity interest of certain of NRG's foreign subsidiaries.

Non-recourse Debt

GenOn Senior Notes

As of June 30, 2016, $707 million of GenOn's senior unsecured notes outstanding are classified as current within the consolidated balance sheet as they mature on June 15, 2017. GenOn is not expected to generate sufficient cash, exclusive of cash subject to the restrictions under the GenOn Mid-Atlantic and REMA operating leases, during the subsequent twelve months to make this principal payment as it becomes due. There is no assurance GenOn will continue as a going concern.

GenOn is currently considering all options available to it, including negotiations with creditors, refinancing the senior unsecured notes, potential sales of certain generating assets as well as the possibility for a need to file for protection under Chapter 11 of the U.S. Bankruptcy Code. During the second quarter of 2016, GenOn appointed two independent directors as part of this process. Any resolution may have a material impact on the Company's statement of operations, cash flows and financial position.

Project Financings

Peakers

In June 2002, NRG Peaker Finance Company LLC, or Peakers, an indirect wholly-owned subsidiary of NRG, issued bonds due June 2019. These notes were also secured by, among other things, substantially all of the assets of and membership interests in Big Cajun I Peaking Power LLC, NRG Sterlington Power LLC, NRG Rockford LLC, NRG Rockford II LLC, and NRG Rockford Equipment LLC.

On June 30, 2016, in contemplation of the sale of Rockford as further discussed in Note 3, Business Acquisitions and Dispositions, NRG Peaker Finance Company LLC elected to redeem all of the outstanding bonds at a redemption price equal to the principal amount plus a redemption premium, accrued and unpaid interest, swap breakage, and other fees, totaling approximately $85 million in connection with the removal of NRG Rockford LLC, and NRG Rockford II, LLC from the peaker financing collateral package. The Company recognized a $3 million loss on extinguishment of the debt related to the write-off of unamortized discount. On July 12, 2016, NRG completed the sale of the Rockford generating stations.

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 fifth anniversary of the term conversion date and 2.50% from the fifth 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 June 30, 2016, $78 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 4.39%, over the term of the arrangement, through June 2019. As of June 30, 2016, $249 million was outstanding.

CVSR

On July 15, 2016, CVSR Holdco LLC, the indirect owner of the CVSR project, issued $200 million of senior secured notes. The $199 million of net proceeds from the notes were distributed to a subsidiary of NRG and NRG Yield Operating LLC, the owners of CVSR Holdco LLC, based on their pro-rata ownership. The notes were issued at par and bear an interest rate at 4.68%. Interest is payable semi-annually beginning on September 30, 2016, until the maturity date of March 31, 2037.

Capistrano Refinancing

In July, Cedro Hill, Broken Bow and Crofton Bluffs, subsidiaries of Capistrano Wind Partners, each amended their respective credit facilities to increase borrowings to a total of $312 million and to lower their respective interest rates. The net proceeds of $87 million, were distributed to Capistrano Wind Partners and subsequently distributed to the holders of the Class B preferred equity interests of tax Capistrano Wind Partners.

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 June 30, 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 $73 million as of June 30, 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 $38 million as of June 30, 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)	June 30, 2016		December 31, 2015
Current assets	$	78	$	84
Net property, plant and equipment	1,754		1,807
Other long-term assets	926		863
Total assets	2,758		2,754
Current liabilities	57		56
Long-term debt	350		366
Other long-term liabilities	192		179
Total liabilities	599		601
Noncontrolling interests	703		493
Net assets less noncontrolling interests	$	1,456	$	1,660

Note 10 — Changes in Capital Structure

As of June 30, 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	457,135	—		457,135
Shares issued under ESPP	—	299,127		299,127
Balance as of June 30, 2016	417,397,085	(102,450,781	)	314,946,304

Preferred Stock

On May 24, 2016, NRG entered an agreement with Credit Suisse Group to repurchase 100% of the outstanding shares of its $344.5 million 2.822% preferred stock. On June 13, 2016, the Company completed the repurchase from Credit Suisse of 100% of the outstanding shares at a price of $226 million. The transaction resulted in a gain on redemption of $78 million, measured as the difference between the fair value of the cash consideration paid upon redemption of $226 million and the carrying value of the preferred stock at the time of the redemption of $304 million. This amount is reflected in net income/(loss) available to NRG common stockholders in the calculation of earnings per share.

Employee Stock Purchase Plan

As of June 30, 2016, there were 977,786 shares of treasury stock available for issuance under the ESPP. In July 2016, 309,967 shares of NRG common stock were issued to employee accounts from treasury stock under the ESPP.

NRG Common Stock Dividends

The following table lists the dividends paid during the six months ended June 30, 2016:



	Second Quarter 2016		First Quarter 2016
Dividends per Common Share	$	0.030	$	0.145

On July 13, 2016, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable August 15, 2016, to stockholders of record as of August 1, 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 — Loss Per Share

Basic loss per common share is computed by dividing net 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 loss per share is computed in a manner consistent with that of basic 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 loss per share is shown in the following table:



	Three months ended June 30,						Six months ended June 30,
(In millions, except per share data)	2016			2015			2016			2015
Basic and diluted loss per share attributable to NRG Energy, Inc. common stockholders
Net loss attributable to NRG Energy, Inc.	$	(271	)	$	(14	)	$	(189	)	$	(134	)
Dividends for preferred shares	—			5			5			10
Gain on redemption of 2.822% redeemable perpetual preferred stock	(78		)	—			(78		)	—
Loss available for common stockholders	$	(193	)	$	(19	)	$	(116	)	$	(144	)
Weighted average number of common shares outstanding - basic and diluted	315			333			315			335
Loss per weighted average common share — basic and diluted	$	(0.61	)	$	(0.06	)	$	(0.37	)	$	(0.43	)

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



	Three months ended June 30,		Six months ended June 30,
(In millions of shares)	2016	2015	2016	2015
Equity compensation plans	3	7	3	7
Embedded derivative of 2.822% redeemable perpetual preferred stock	—	16	—	16
Total	3	23	3	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 (previously Generation/Business), which includes generation, international and business solutions; 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, 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. Effective April 1, 2016, the Company began reporting the results of its international business in its Generation segment. The financial information for the three months and six months ended June 30, 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 and six months ended June 30, 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^(a)(b)			Retail Mass^(a)		Renewables^(a)			NRG Yield^(a)		Corporate^(a)(c)			Eliminations			Total
Three months ended June 30, 2016
Operating revenues^(a)	$	1,306		$	1,201	$	125		$	258	$	29		$	(281	)	$	2,638
Depreciation and amortization	144			27		55			67		16			—			309
Impairment losses	76			—		26			—		13			—			115
Equity in (losses)/earnings of unconsolidated affiliates	—			—		(4		)	18		1			(11		)	4
Gain on investment	—			—		—			—		7			—			7
(Loss)/income before income taxes	(371		)	496		(63		)	70		(371		)	(12		)	(251		)
Net (Loss)/Income	(371		)	496		(58		)	58		(389		)	(12		)	(276		)
Net (Loss)/Income attributable to NRG Energy, Inc.	$	(371	)	$	496	$	(53	)	$	42	$	(409	)	$	24		$	(271	)
Total assets as of June 30, 2016	$	14,445		$	2,169	$	5,730		$	7,609	$	16,799		$	(15,330	)	$	31,422



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	218	$	3	$	5	$	—	$	55		$	—	$	281
(b) Includes loss on sale of assets	$	—	$	—	$	—	$	—	$	(83	)	$	—	$	(83	)
(c) Includes loss on debt extinguishment	$	—	$	—	$	—	$	—	$	(80	)	$	—	$	(80	)



(In millions)	Generation^(e)		Retail Mass^(e)		Renewables^(e)			NRG Yield^(e)		Corporate^(e)			Eliminations			Total
Three months ended June 30, 2015
Operating revenues^(a)	$	2,110	$	1,298	$	128		$	235	$	10		$	(381	)	$	3,400
Depreciation and amortization	228		33		53			70		12			—			396
Equity in earnings/(loss) of unconsolidated affiliates	6		—		(2		)	8		—			(4		)	8
Income/(Loss) before income taxes	4		217		(9		)	42		(272		)	(8		)	(26		)
Net Income/(Loss)	3		217		(6		)	38		(253		)	(8		)	(9		)
Net Income/(Loss) attributable to NRG Energy, Inc.	$	3	$	217	$	(20	)	$	21	$	(239	)	$	4		$	(14	)



(e) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	297	$	4	$	23	$	9	$	48	$	—	$	381



(In millions)	Generation^(h)(i)			Retail Mass^(h)		Renewables^(h)			NRG Yield^(h)		Corporate^(h)(i)(j)			Eliminations			Total
Six months ended June 30, 2016
Operating revenues^(a)	$	3,426		$	2,249	$	234		$	478	$	88		$	(608	)	$	5,867
Depreciation and amortization	290			55		111			133		33			—			622
Impairment losses	76			—		26			—		13			—			115
Equity in (losses)/earnings of unconsolidated affiliates	(5		)	—		(8		)	20		2			(12		)	(3		)
Impairment loss on investment	(137		)	—		—			—		(2		)	—			(139		)
(Loss)/Income before income taxes	(211		)	642		(114		)	72		(563		)	(9		)	(183		)
Net (Loss)/Income	(212		)	642		(103		)	60		(607		)	(9		)	(229		)
Net (Loss)/Income attributable to NRG Energy, Inc.	$	(212	)	$	642	$	(88	)	$	52	$	(614	)	$	31		$	(189	)



(h) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	469	$	4	$	10	$	4	$	121		$	—	$	608
(i) Includes gain/(loss) on sale of assets	$	32	$	—	$	—	$	—	$	(83	)	$	—	$	(51	)
(j) Includes loss on debt extinguishment	$	—	$	—	$	—	$	—	$	(69	)	$	—	$	(69	)



(In millions)	Generation^(l)(m)		Retail Mass^(l)		Renewables^(l)			NRG Yield^(l)		Corporate^(l)			Eliminations			Total
Six months ended June 30, 2015
Operating revenues^(a)	$	4,619	$	2,609	$	219		$	435	$	8		$	(661	)	$	7,229
Depreciation and amortization	461		63		105			137		25			—			791
Equity in earnings/(losses) of unconsolidated affiliates	2		—		(3		)	10		(1		)	(3		)	5
Income/(Loss) before income taxes	33		321		(66		)	18		(534		)	(7		)	(235		)
Net Income/(Loss)	32		321		(57		)	18		(452		)	(7		)	(145		)
Net Income/(Loss) attributable to NRG Energy, Inc.	$	32	$	321	$	(66	)	$	6	$	(426	)	$	(1	)	$	(134	)



(l) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	544	$	4	$	23	$	9	$	81	$	—	$	661
(m) Includes gain on postretirement benefits curtailment	$	14	$	—	$	—	$	—	$	—	$	—	$	14

Note 13 — Income Taxes

Effective Tax Rate

The income tax provision consisted of the following:



	Three months ended June 30,						Six months ended June 30,
(In millions except otherwise noted)	2016			2015			2016			2015
Loss before income taxes	$	(251	)	$	(26	)	$	(183	)	$	(235	)
Income tax expense/(benefit)	25			(17		)	46			(90		)
Effective tax rate	(10.0		)%	65.4		%	(25.1		)%	38.3		%

For the three and six months ended June 30, 2016, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to tax expense resulting from the change in the valuation allowance, amortization of indefinite lived assets, inclusion of consolidated partnerships and the impact of state income taxes.

For the three and six months ended June 30, 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 tax expense attributable to consolidated partnerships.

Uncertain Tax Benefits

As of June 30, 2016, NRG has recorded a non-current tax liability of $43 million for uncertain tax benefits from positions taken on various state income tax returns, including accrued interest. For the six months ended June 30, 2016, NRG accrued an insignificant amount of interest relating to the uncertain tax benefits. As of June 30, 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 June 30, 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. On March 17, 2016, the CPUC adopted a resolution approving the forbearance agreements, which are final and non-appealable and in full effect. 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. Subsequent to the close of the second quarter of 2016, each of Ivanpah's unit 1 and unit 3 satisfied their respective production requirements for the initial six-month measurement period under the forbearance agreements.

Lignite Contract with Texas Westmoreland Coal Co. — The lignite used to fuel the Gulf Coast region's Limestone facility is obtained from the Jewett mine, a surface mine adjacent to the Limestone facility, under a long-term contract with Texas Westmoreland Coal Co., or TWCC. The contract is based on a cost-plus arrangement with incentives and penalties to ensure proper management of the mine. NRG has the flexibility to increase or decrease lignite purchases from the mine within certain ranges, including the ability to suspend or terminate lignite purchases with adequate notice. The mining period extends through 2018 with an option to further extend the mining period by two five-year intervals.

TWCC is responsible for performing ongoing reclamation activities at the mine until all lignite reserves have been produced. When production is completed at the mine, NRG will be responsible for final mine reclamation obligations and maintains an appropriate ARO. The Railroad Commission of Texas has imposed a bond obligation of $107.5 million on TWCC for the reclamation of this lignite mine. Pursuant to the contract with TWCC, NRG supports this obligation as follows: $12 million is guaranteed by NRG, and $95.5 million is supported by surety bonds posted by NRG, of which $64 million were issued during the second quarter of 2016. Additionally, NRG is required to provide additional performance assurance over TWCC's current bond obligations if required by the Railroad Commission of Texas.

Contingencies

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

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

Midwest Generation Asbestos Liabilities — The Company, through its subsidiary, Midwest Generation, may be subject to potential asbestos liabilities as a result of its acquisition of EME. The Company is currently analyzing the scope of potential liability as it may relate to Midwest Generation.

Actions Pursued by MC Asset Recovery — With Mirant Corporation's emergence from bankruptcy protection in 2006, certain actions filed by GenOn Energy Holdings and some of its subsidiaries against third parties were transferred to MC Asset Recovery, a wholly owned subsidiary of GenOn Energy Holdings. MC Asset Recovery is governed by a manager who is independent of NRG and GenOn. MC Asset Recovery is a disregarded entity for income tax purposes. Under the remaining action transferred to MC Asset Recovery, MC Asset Recovery seeks to recover damages from Commerzbank AG and various other banks, or the Commerzbank Defendants, for alleged fraudulent transfers that occurred prior to Mirant's bankruptcy proceedings. In December 2010, the U.S. District Court for the Northern District of Texas dismissed MC Asset Recovery's complaint against the Commerzbank Defendants. In January 2011, MC Asset Recovery appealed the District Court's dismissal of its complaint against the Commerzbank Defendants to the U.S. Court of Appeals for the Fifth Circuit, or the Fifth Circuit. In March 2012, the Fifth Circuit reversed the District Court's dismissal and reinstated MC Asset Recovery's amended complaint against the Commerzbank Defendants. On December 10, 2015, the District Court granted summary judgment in favor of the Commerzbank Defendants. On December 29, 2015, MC Asset Recovery filed a notice to appeal this judgment. On July 29, 2016, MC Asset Recovery filed its appeal with the Fifth Circuit.

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. Defendants filed their briefs in opposition to class plaintiffs' motions for class certification on June 24, 2016. On May 20, 2016, the U.S. District Court for the District of Nevada heard argument on the defendants' motion for summary judgment in one of the Kansas cases. On May 24, 2016, the court granted the motion for summary judgment as to the GenOn entity 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.

In July 2016, the parties signed a consent decree, which will settle the matter, subject to approval by the court. The consent decree requires: (1) improving the wastewater treatment systems at the Chalk Point and Dickerson facilities; (2) completing supplemental environmental projects worth $1 million; and (3) paying a civil penalty of $1 million.

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. On July 8, 2016, NRG filed a Rule 11 Motion seeking dismissal of NRG from the California case.

California Department of Water Resources and San Diego Gas & Electric Company v. Sunrise Power Company LLC — On January 29, 2016, CDWR and SDG&E filed a lawsuit against Sunrise Power Company, along with NRG and Chevron Power Corporation. In June 2001, CDWR and Sunrise entered into a 10-year PPA under which Sunrise would construct and operate a generating facility and provide power to CDWR. At the time the PPA was entered into, Sunrise had a transportation services agreement, or TSA, to purchase natural gas from Kern River through April 30, 2018. In August 2003, CDWR entered into an agreement with Sunrise and Kern River in which CDWR accepted assignment of the TSA through the term of the PPA. After the PPA expired, Kern River demanded that any reassignment be to a party which met certain creditworthiness standards which Sunrise did not. As such, the plaintiffs have brought this lawsuit against the defendants alleging breach of contract, breach of covenant of good faith and fair dealing and improper distributions. Plaintiffs generally claim damages of $1.2 million per month for the remaining 70 months of the TSA. On April 20, 2016, the defendants filed demurrers in response to the plaintiffs' complaint. The demurrers were granted on June 14, 2016; however, the plaintiffs were allowed to file amended complaints on July 1, 2016. On July 27, 2016, defendants filed demurrers to the amended complaints.

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 California Superior Court in Kern County, CA. Plaintiffs allege various violations of the Securities Act due to the defendants’ alleged failure to disclose material facts related to low wind production prior to the NRG Yield, Inc.'s June 22, 2015 Class C common stock offering. Plaintiffs seek compensatory damages, rescission, attorney’s fees and costs. On August 3, 2016, the court approved a stipulation entered into by the parties. The stipulation provides that the plaintiffs will file an amended complaint by August 19, 2016. The Defendants need to file a responsive pleading by October 18, 2016.

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.

PJM Capacity Performance Appeals — On or about July 8, 2016, four petitions were filed at the U.S. Court of Appeals for the D.C. Circuit seeking review of the FERC orders approving PJM’s Capacity Performance revisions to its forward capacity market after motions for rehearing at FERC were denied on May 10, 2016. The Company intervened in these matters on July 29, 2016. This case governs capacity revenues already received by the Company, as well as the revenues for forward periods.

Midwest Generation, LLC Reactive Power Compensation — On June 21, 2016, FERC issued an order directing MWG to make a compliance filing setting forth refunds for payments received in violation of its 2004 reactive power settlement or to show cause why it has not violated the settlement and ordered MWG to revise its tariff to reflect the costs of units continuing to provide reactive power or show cause why it should not be required to do so. The Commission also referred this matter to the Commission's Office of Enforcement. On June 30, 2016, MWG filed a revised tariff, and on July 22, 2016, MWG made a compliance filing as ordered by FERC. The matter is pending at FERC.

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' obligations to reduce emissions so that downwind states can achieve federal air quality standards. In December 2011, the D.C. Circuit stayed the implementation of CSAPR and then vacated CSAPR in August 2012 but kept CAIR in place until the EPA could replace it. In April 2014, the U.S. Supreme Court reversed and remanded the D.C. Circuit's decision. In October 2014, the D.C. Circuit lifted the stay of CSAPR. In response, the EPA in November 2014 amended the CSAPR compliance dates. Accordingly, CSAPR replaced CAIR on January 1, 2015. On July 28, 2015, the D.C. Circuit held that the EPA had exceeded its authority by requiring certain reductions that were not necessary for downwind states to achieve federal standards. Although the D.C. Circuit kept the rule in place, the court ordered the EPA to revise the Phase 2 (or 2017) (i) 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 MATS rule to the EPA without vacatur. On April 25, 2016, the EPA released a supplemental finding that the benefits of this regulation outweigh the costs to address the U.S. Supreme Court's ruling that the EPA had not properly considered costs. This finding has been challenged in the D.C. Circuit. 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 June 30, 2016.

Environmental Capital Expenditures

NRG estimates that environmental capital expenditures from 2016 through 2020 required to comply with environmental laws will be approximately $322 million, which includes $61 million for GenOn and $247 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 June 30, 2016, the Company had outstanding $5.9 billion of Senior Notes due from 2018 - 2026, 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 June 30, 2016:



Ace Energy, Inc.	Norwalk Power LLC	NRG Operating Services, Inc.
Allied Warranty LLC	NRG Advisory Services, LLC	NRG Oswego Harbor Power Operations Inc.
Arthur Kill Power LLC	NRG Affiliate Services Inc.	NRG PacGen Inc.
Astoria Gas Turbine Power LLC	NRG Artesian Energy LLC	NRG Portable Power LLC
Bayou Cove Peaking Power, LLC	NRG Arthur Kill Operations Inc.	NRG Power Marketing LLC
BidURenergy, Inc.	NRG Astoria Gas Turbine Operations Inc.	NRG Reliability Solutions LLC
Cabrillo Power I LLC	NRG Bayou Cove LLC	NRG Renter's Protection LLC
Cabrillo Power II LLC	NRG Business Services LLC	NRG Retail LLC
Carbon Management Solutions LLC	NRG Business Solutions LLC	NRG Retail Northeast LLC
Cirro Group, Inc.	NRG Cabrillo Power Operations Inc.	NRG Rockford Acquisition LLC
Cirro Energy Services, Inc.	NRG California Peaker Operations LLC	NRG Saguaro Operations Inc.
Clean Edge Energy LLC	NRG Cedar Bayou Development Company, LLC	NRG Security LLC
Conemaugh Power LLC	NRG Connected Home LLC	NRG Services Corporation
Connecticut Jet Power LLC	NRG Connecticut Affiliate Services Inc.	NRG SimplySmart Solutions LLC
Cottonwood Development LLC	NRG Construction LLC	NRG South Central Affiliate Services Inc.
Cottonwood Energy Company LP	NRG Curtailment Solutions Holdings LLC	NRG South Central Generating LLC
Cottonwood Generating Partners I LLC	NRG Curtailment Solutions Inc	NRG South Central Operations Inc.
Cottonwood Generating Partners II LLC	NRG Development Company Inc.	NRG South Texas LP
Cottonwood Generating Partners III LLC	NRG Devon Operations Inc.	NRG SPV #1 LLC
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 Home & Business Solutions LLC	Reliant Energy Power Supply, LLC
Green Mountain Energy Company	NRG Home Services LLC	Reliant Energy Retail Holdings, LLC
Gregory Partners, LLC	NRG Home Solutions LLC	Reliant Energy Retail Services, LLC
Gregory Power Partners LLC	NRG Home Solutions Product LLC	RERH Holdings LLC
Huntley Power LLC	NRG Homer City Services LLC	Saguaro Power LLC
Independence Energy Alliance LLC	NRG Huntley Operations Inc.	Somerset Operations Inc.
Independence Energy Group LLC	NRG HQ DG LLC	Somerset Power LLC
Independence Energy Natural Gas LLC	NRG Identity Protect LLC	Texas Genco Financing Corp.
Indian River Operations Inc.	NRG Ilion Limited Partnership	Texas Genco GP, LLC
Indian River Power LLC	NRG Ilion LP LLC	Texas Genco Holdings, Inc.
Keystone Power LLC	NRG International LLC	Texas Genco LP, LLC
Langford Wind Power, LLC	NRG Maintenance Services LLC	Texas Genco Operating Services, LLC
Louisiana Generating LLC	NRG Mextrans Inc.	Texas Genco Services, LP
Meriden Gas Turbines LLC	NRG MidAtlantic Affiliate Services Inc.	US Retailers LLC
Middletown Power LLC	NRG Middletown Operations Inc.	Vienna Operations Inc.
Montville Power LLC	NRG Montville Operations Inc.	Vienna Power LLC
NEO Corporation	NRG New Roads Holdings LLC	WCP (Generation) Holdings LLC
NEO Freehold-Gen LLC	NRG North Central Operations Inc.	West Coast Power LLC
NEO Power Services Inc.	NRG Northeast Affiliate Services Inc.
New Genco GP, LLC	NRG Norwalk Harbor Operations Inc.

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

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

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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Three Months Ended June 30, 2016

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	1,699		$	986		$	—		$	(47	)	$	2,638
Operating Costs and Expenses
Cost of operations	1,110			685			8			(47		)	1,756
Depreciation and amortization	108			195			6			—			309
Impairment losses	—			115			—			—			115
Selling, general and administrative	94			92			79			—			265
Acquisition-related transaction and integration costs	—			—			5			—			5
Development activity expenses	—			13			5			—			18
Total operating costs and expenses	1,312			1,100			103			(47		)	2,468
Loss on sale of assets	—			—			(83		)	—			(83		)
Operating Income/(Loss)	387			(114		)	(186		)	—			87
Other Income/(Expense)
Equity in (losses)/earnings of consolidated subsidiaries	(44		)	(27		)	98			(27		)	—
Equity in earnings of unconsolidated affiliates	3			6			—			(5		)	4
Gain on investment	—			1			6			—			7
Other income	2			3			4			(1		)	8
Loss on debt extinguishment	—			(4		)	(76		)	—			(80		)
Interest expense	(2		)	(145		)	(130		)	—			(277		)
Total other expense	(41		)	(166		)	(98		)	(33		)	(338		)
Income/(Loss) Before Income Taxes	346			(280		)	(284		)	(33		)	(251		)
Income tax expense/(benefit)	133			(104		)	(44		)	40			25
Net Income/(Loss)	213			(176		)	(240		)	(73		)	(276		)
Less: Net income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interests	—			10			31			(46		)	(5		)
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	213		$	(186	)	$	(271	)	$	(27	)	$	(271	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Six Months Ended June 30, 2016

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	3,655		$	2,285		$	—		$	(73	)	$	5,867
Operating Costs and Expenses
Cost of operations	2,560			1,444			18			(77		)	3,945
Depreciation and amortization	225			385			12			—			622
Impairment losses	—			115			—			—			115
Selling, general and administrative	192			191			137			—			520
Acquisition-related transaction and integration costs	—			—			7			—			7
Development activity expenses	—			32			12			—			44
Total operating costs and expenses	2,977			2,167			186			(77		)	5,253
Gain/(loss) on sale of assets	—			32			(83		)	—			(51		)
Operating Income/(Loss)	678			150			(269		)	4			563
Other Income/(Expense)
Equity in (losses)/earnings of consolidated subsidiaries	(68		)	(23		)	311			(220		)	—
Equity in earnings/(losses) of unconsolidated affiliates	3			(2		)	—			(4		)	(3		)
Impairment loss on investment	—			(139		)	—			—			(139		)
Other income	2			23			2			(1		)	26
Loss on debt extinguishment	—			(4		)	(65		)	—			(69		)
Interest expense	(7		)	(295		)	(259		)	—			(561		)
Total other expense	(70		)	(440		)	(11		)	(225		)	(746		)
Income/(Loss) Before Income Taxes	608			(290		)	(280		)	(221		)	(183		)
Income tax expense/(benefit)	233			(112		)	(127		)	52			46
Net Income/(Loss)	375			(178		)	(153		)	(273		)	(229		)
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interests	—			(23		)	36			(53		)	(40		)
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	375		$	(155	)	$	(189	)	$	(220	)	$	(189	)


(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 June 30, 2016

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Net Income/(Loss)	$	213		$	(176	)	$	(240	)	$	(73	)	$	(276	)
Other Comprehensive Income/(Loss), net of tax
Unrealized (loss)/gain on derivatives, net	—			(5		)	(4		)	6			(3		)
Foreign currency translation adjustments, net	(2		)	(2		)	(4		)	5			(3		)
Available-for-sale securities, net	—			—			(2		)	—			(2		)
Defined benefit plans, net	—			—			—			—			—
Other comprehensive loss	(2		)	(7		)	(10		)	11			(8		)
Comprehensive Income/(Loss)	211			(183		)	(250		)	(62		)	(284		)
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—			(1		)	31			(46		)	(16		)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	211			(182		)	(281		)	(16		)	(268		)
Gain on redemption of preferred shares	—			—			(78		)	—			(78		)
Comprehensive Income/(Loss) Available for Common Stockholders	$	211		$	(182	)	$	(203	)	$	(16	)	$	(190	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME

For the Six Months Ended June 30, 2016

(Unaudited)



	Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Net Income/(Loss)	375		(178		)	(153		)	(273		)	(229		)
Other Comprehensive Income/(Loss), net of tax
Unrealized (loss)/gain on derivatives, net	—		(55		)	20			—			(35		)
Foreign currency translation adjustments, net	2		2			2			(3		)	3
Available-for-sale securities, net	—		—			1			—			1
Defined benefit plans, net	1		—			—			—			1
Other comprehensive income/(loss)	3		(53		)	23			(3		)	(30		)
Comprehensive Income/(Loss)	378		(231		)	(130		)	(276		)	(259		)
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—		(51		)	36			(53		)	(68		)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	378		(180		)	(166		)	(223		)	(191		)
Gain on redemption, net of dividends for preferred shares	—		—			(73		)	—			(73		)
Comprehensive Income/(Loss) Available for Common Stockholders	$	378	$	(180	)	$	(93	)	$	(223	)	$	(118	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

June 30, 2016

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
ASSETS	(In millions)
Current Assets
Cash and cash equivalents	$	—		$	1,039	$	350		$	—		$	1,389
Funds deposited by counterparties	—			44		—			—			44
Restricted cash	10			403		—			—			413
Accounts receivable - trade, net	911			338		2			—			1,251
Accounts receivable - affiliate	325			41		191			(553		)	4
Inventory	475			649		—			—			1,124
Derivative instruments	991			574		—			(95		)	1,470
Cash collateral paid in support of energy risk management activities	130			88		—			—			218
Renewable energy grant receivable, net	—			36		—			—			36
Current assets held-for-sale	—			13		—			—			13
Prepayments and other current assets	106			237		59			—			402
Total current assets	2,948			3,462		602			(648		)	6,364
Net property, plant and equipment	4,483			13,678		248			(27		)	18,382
Other Assets
Investment in subsidiaries	1,080			2,031		10,771			(13,882		)	—
Equity investments in affiliates	(17		)	984		10			(95		)	882
Notes receivable, less current portion	—			24		(2		)	3			25
Goodwill	697			302		—			—			999
Intangible assets, net	691			1,491		1			(3		)	2,180
Nuclear decommissioning trust fund	599			—		—			—			599
Derivative instruments	210			164		—			(26		)	348
Deferred income tax	30			590		(445		)	—			175
Non-current assets held-for-sale	—			229		—			—			229
Other non-current assets	53			833		353			—			1,239
Total other assets	3,343			6,648		10,688			(14,003		)	6,676
Total Assets	$	10,774		$	23,788	$	11,538		$	(14,678	)	$	31,422
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	—		$	1,375	$	(163	)	$	3		$	1,215
Accounts payable	588			270		40			—			898
Accounts payable — affiliate	242			269		42			(553		)	—
Derivative instruments	915			550		3			(95		)	1,373
Cash collateral received in support of energy risk management activities	—			44		—			—			44
Current liabilities held-for-sale	—			2		—			—			2
Accrued expenses and other current liabilities	301			338		343			—			982
Total current liabilities	2,046			2,848		265			(645		)	4,514
Other Liabilities
Long-term debt and capital leases	245			9,810		7,838			—			17,893
Nuclear decommissioning reserve	334			—		—			—			334
Nuclear decommissioning trust liability	309			—		—			—			309
Deferred income taxes	958			255		(1,171		)	—			42
Derivative instruments	298			267		—			(26		)	539
Out-of-market contracts, net	88			1,005		—			—			1,093
Other non-current liabilities	411			781		362			—			1,554
Total non-current liabilities	2,643			12,118		7,029			(26		)	21,764
Total liabilities	4,689			14,966		7,294			(671		)	26,278
Redeemable noncontrolling interest in subsidiaries	—			23		—			—			23
Stockholders’ Equity	6,085			8,799		4,244			(14,007		)	5,121
Total Liabilities and Stockholders’ Equity	$	10,774		$	23,788	$	11,538		$	(14,678	)	$	31,422


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

NRG ENERGY, INC. AND SUBSIDIARIES CONDENSED

CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Six Months Ended June 30, 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)	$	375		$	(178	)	$	(153	)	$	(273	)	$	(229	)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Distributions from unconsolidated affiliates	—			40			—			(11		)	29
Equity in (earnings)/losses of unconsolidated affiliates	(3		)	2			—			4			3
Depreciation and amortization	225			385			12			—			622
Provision for bad debts	16			4			—			—			20
Amortization of nuclear fuel	26			—			—			—			26
Amortization of financing costs and debt discount/premiums	—			(10		)	13			—			3
Adjustment for debt extinguishment	—			4			10			—			14
Amortization of intangibles and out-of-market contracts	20			21			—			—			41
Amortization of unearned equity compensation	—			—			16			—			16
Impairment losses	—			254			—			—			254
Changes in deferred income taxes and liability for uncertain tax benefits	233			(112		)	(120		)	—			1
Changes in nuclear decommissioning trust liability	13			—			—			—			13
Changes in derivative instruments	(64		)	36			3			—			(25		)
Changes in collateral deposits supporting energy risk management activities	344			6			—			—			350
Proceeds from sale of emission allowances	47			—			—			—			47
(Gain)/loss on sale of assets	—			(32		)	75			—			43
Cash (used)/provided by changes in other working capital	(935		)	24			276			280			(355		)
Net Cash Provided by Operating Activities	297			444			132			—			873
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc.	—			—			39			(39		)	—
Intercompany dividends	—						12			(12		)	—
Acquisition of businesses, net of cash acquired	—			(17		)	—			—			(17		)
Capital expenditures	(80		)	(509		)	(33		)	—			(622		)
Decrease in restricted cash, net	4			25			—			—			29
Decrease/(increase) in restricted cash — U.S. DOE funded projects	1			(29		)	—			—			(28		)
Increase in notes receivable	—			(3		)	—			—			(3		)
Purchases of emission allowances	(27		)	—			—			—			(27		)
Proceeds from sale of emission allowances	25			—			—			—			25
Investments in nuclear decommissioning trust fund securities	(280		)	—			—			—			(280		)
Proceeds from sales of nuclear decommissioning trust fund securities	267			—			—			—			267
Proceeds from renewable energy grants and state rebates	—			10			—			—			10
Proceeds from sale of assets, net of cash disposed of	—			120			25			—			145
Other	28			4			—			—			32
Net Cash (Used)/Provided by Investing Activities	(62		)	(399		)	43			(51		)	(469		)
Cash Flows from Financing Activities
Payments (for)/from intercompany loans	(179		)	45			134			—			—
Payment of dividends NRG Yield, Inc.	—			(39		)	—			39			—
Intercompany dividends	(52		)	40			—			12			—
Payment of dividends to common and preferred stockholders	—			—			(57		)	—			(57		)
Payment for preferred shares	—			—			(226		)	—			(226		)
Net receipts from settlement of acquired derivatives that include financing elements	—			103			—			—			103
Proceeds from issuance of long-term debt	—			332			2,891			—			3,223
Distributions from, net of contributions to, noncontrolling interest in subsidiaries	—			(21		)	—			—			(21		)
Payment of debt issuance costs	—			—			(35		)	—			(35		)
Payments for short and long-term debt	(1		)	(281		)	(3,225		)	—			(3,507		)
Other	(3		)	(7		)	—			—			(10		)
Net Cash (Used)/Provided by Financing Activities	(235		)	172			(518		)	51			(530		)
Effect of exchange rate changes on cash and cash equivalents	—			(3		)	—			—			(3		)
Net Increase/(Decrease) in Cash and Cash Equivalents	—			214			(343		)	—			(129		)
Cash and Cash Equivalents at Beginning of Period	—			825			693			—			1,518
Cash and Cash Equivalents at End of Period	$	—		$	1,039		$	350		$	—		$	1,389


(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 June 30, 2015

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	2,267		$	1,161		$	—		$	(28	)	$	3,400
Operating Costs and Expenses
Cost of operations	1,703			756			(16		)	(7		)	2,436
Depreciation and amortization	196			195			5			—			396
Selling, general and administrative	116			93			87			—			296
Acquisition-related transaction and integration costs	—			(1		)	4			—			3
Development activity expenses	—			11			26			—			37
Total operating costs and expenses	2,015			1,054			106			(7		)	3,168
Operating Income/(Loss)	252			107			(106		)	(21		)	232
Other Income/(Expense)
Equity in (losses)/earnings of consolidated subsidiaries	(22		)	(49		)	154			(83		)	—
Equity in earnings of unconsolidated affiliates	3			10			—			(5		)	8
Other income, net	—			3			1			—			4
Loss on debt extinguishment	—			(7		)	—			—			(7		)
Interest expense	(5		)	(121		)	(137		)	—			(263		)
Total other expense	(24		)	(164		)	18			(88		)	(258		)
Income/(Loss) Before Income Taxes	228			(57		)	(88		)	(109		)	(26		)
Income tax expense/(benefit)	83			(16		)	(84		)	—			(17		)
Net Income/(Loss)	145			(41		)	(4		)	(109		)	(9		)
Less: Net income attributable to noncontrolling interest and redeemable noncontrolling interest	—			21			10			(26		)	5
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	145		$	(62	)	$	(14	)	$	(83	)	$	(14	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Six Months Ended June 30, 2015

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	4,833		$	2,464		$	—		$	(68	)	$	7,229
Operating Costs and Expenses
Cost of operations	3,807			1,762			(4		)	(56		)	5,509
Depreciation and amortization	400			381			10			—			791
Selling, general and administrative	221			183			147			—			551
Acquisition-related transaction and integration costs	—			1			12			—			13
Development activity expenses	—			26			45			—			71
Total operating costs and expenses	4,428			2,353			210			(56		)	6,935
Gain on postretirement benefits curtailment	—			14			—			—			14
Operating Income/(Loss)	405			125			(210		)	(12		)	308
Other Income/(Expense)
Equity in (losses)/earnings of consolidated subsidiaries	(35		)	(57		)	204			(112		)	—
Equity in earnings/(losses) of unconsolidated affiliates	3			6			(1		)	(3		)	5
Other income, net	1			20			2			—			23
Loss on debt extinguishment	—			(7		)	—			—			(7		)
Interest expense	(9		)	(279		)	(276		)	—			(564		)
Total other expense	(40		)	(317		)	(71		)	(115		)	(543		)
Income/(Loss) Before Income Taxes	365			(192		)	(281		)	(127		)	(235		)
Income tax expense/(benefit)	137			(76		)	(151		)	—			(90		)
Net Income/(Loss)	228			(116		)	(130		)	(127		)	(145		)
Less: Net income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest	—			—			4			(15		)	(11		)
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	228		$	(116	)	$	(134	)	$	(112	)	$	(134	)


(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 June 30, 2015

(Unaudited)



	Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Net Income/(Loss)	$	145	$	(41	)	$	(4	)	$	(109	)	$	(9	)
Other Comprehensive Income/(Loss), net of tax
Unrealized gain on derivatives, net	2		4			25			(15		)	16
Foreign currency translation adjustments, net	—		9			—			—			9
Available-for-sale securities, net	—		—			(3		)	—			(3		)
Defined benefit plans, net	—		—			(1		)	—			(1		)
Other comprehensive income	2		13			21			(15		)	21
Comprehensive Income/(Loss)	147		(28		)	17			(124		)	12
Less: Comprehensive income attributable to noncontrolling interest and redeemable noncontrolling interest	—		28			10			(26		)	12
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	147		(56		)	7			(98		)	—
Dividends for preferred shares	—		—			5			—			5
Comprehensive Income/(Loss) Available for Common Stockholders	$	147	$	(56	)	$	2		$	(98	)	$	(5	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

For the Six Months Ended June 30, 2015

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Net Income/(Loss)	228			(116		)	(130		)	(127		)	(145		)
Other Comprehensive Income/(Loss), net of tax
Unrealized (loss)/gain on derivatives, net	(5		)	15			9			(15		)	4
Foreign currency translation adjustments, net	—			—			(2		)	—			(2		)
Available-for-sale securities, net	—			(1		)	(3		)	—			(4		)
Defined benefit plans, net	(3		)	(1		)	10			—			6
Other comprehensive (loss)/income	(8		)	13			14			(15		)	4
Comprehensive Income/(Loss)	220			(103		)	(116		)	(142		)	(141		)
Less: Comprehensive (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	—			(6		)	4			(15		)	(17		)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	220			(97		)	(120		)	(127		)	(124		)
Dividends for preferred shares	—			—			10			—			10
Comprehensive Income/(Loss) Available for Common Stockholders	$	220		$	(97	)	$	(130	)	$	(127	)	$	(134	)


(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 Six Months Ended June 30, 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)	$	228		$	(116	)	$	(130	)	$	(127	)	$	(145	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Distributions from unconsolidated affiliates	6			50			—			(11		)	45
Equity in (earnings)/losses of unconsolidated affiliates	(3		)	(6		)	1			3			(5		)
Depreciation and amortization	400			381			10			—			791
Provision for bad debts	26			—			3			—			29
Amortization of nuclear fuel	23			—			—			—			23
Amortization of financing costs and debt discount/premiums	—			(20		)	13			—			(7		)
Adjustment for debt extinguishment	—			7			—			—			7
Amortization of intangibles and out-of-market contracts	24			8			—			—			32
Amortization of unearned equity compensation	—			—			24			—			24
Changes in deferred income taxes and liability for uncertain tax benefits	137			(76		)	(159		)	—			(98		)
Changes in nuclear decommissioning trust liability	(4		)	—			—			—			(4		)
Changes in derivative instruments	63			121			2			—			186
Changes in collateral deposits supporting energy risk management activities	(82		)	(30		)	—			—			(112		)
Gain on postretirement benefits curtailment	—			(14		)	—			—			(14		)
Cash provided/(used) by changes in other working capital	710			(771		)	(368		)	135			(294		)
Net Cash Provided/(Used) by Operating Activities	1,528			(466		)	(604		)	—			458
Cash Flows from Investing Activities
Dividends from NRG Yield, Inc.	—			—			34			(34		)	—
Intercompany dividends	—			—			33			(33		)	—
Acquisition of businesses, net of cash acquired	—			(30		)	—			—			(30		)
Capital expenditures	(177		)	(388		)	(18		)	—			(583		)
Increase in restricted cash, net	—			(3		)	—			—			(3		)
Decrease in restricted cash — U.S. DOE projects	—			27			—			—			27
Decrease in notes receivable	—			7			—			—			7
Investments in nuclear decommissioning trust fund securities	(354		)	—			—			—			(354		)
Proceeds from sales of nuclear decommissioning trust fund securities	358			—			—			—			358
Proceeds from renewable energy grants and state rebates	—			61			—			—			61
Proceeds from sale of assets, net of cash disposed of	—			—			1			—			1
Investments in unconsolidated affiliates	—			(304		)	(49		)	—			(353		)
Other	5			4			—			—			9
Net Cash (Used)/Provided by Investing Activities	(168		)	(626		)	1			(67		)	(860		)
Cash Flows from Financing Activities
Payments (for)/from intercompany loans	(1,368		)	440			928			—			—
Intercompany dividends	—			(33		)	—			33			—
Payments of dividends from NRG Yield, Inc.	—			(34		)	—			34			—
Payment of dividends to common and preferred stockholders	—			—			(102		)	—			(102		)
Payment for treasury stock	—			—			(186		)	—			(186		)
Net receipts for settlement of acquired derivatives that include financing elements	—			91			—			—			91
Proceeds from issuance of long-term debt	—			601			28			—			629
Distributions from, net of contributions to, noncontrolling interest in subsidiaries	—			670			—			—			670
Proceeds from issuance of common stock	—			—			1			—			1
Payment of debt issuance costs	—			(12		)	—			—			(12		)
Payments for short and long-term debt	—			(652		)	(10		)	—			(662		)
Net Cash (Used)/Provided by Financing Activities	(1,368		)	1,071			659			67			429
Effect of exchange rate changes on cash and cash equivalents	—			3			—			—			3
Net (Decrease)/Increase in Cash and Cash Equivalents	(8		)	(18		)	56			—			30
Cash and Cash Equivalents at Beginning of Period	18			1,455			643			—			2,116
Cash and Cash Equivalents at End of Period	$	10		$	1,437		$	699		$	—		$	2,146


(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 and six months ended June 30, 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 use energy products and services. NRG has one of the nation's largest and most diverse competitive generation portfolios balanced with a leading retail electricity platform. The Company owns and operates approximately 48,000 MW of generation; engages in the trading of wholesale energy, capacity and related products; transacts in and trades fuel and transportation services; and directly sells energy, services, and innovative, sustainable products and services to retail customers under the names “NRG”, "Reliant" and other retail brand names owned by NRG. NRG was incorporated as a Delaware corporation on May 29, 1992.

The following table summarizes NRG's global generation portfolio as of June 30, 2016, by operating segment:



	Global Generation Portfolio^(a)
	(In MW)
	Generation
Generation Type	Gulf Coast	East	West	International	Renewables^(b)		NRG Yield ^(c)		Other^(d)	Total Global
Natural gas^(e)	8,651	9,175	6,085	144	—		1,878		—	25,933
Coal^(f)	5,114	7,472	—	605	—		—		—	13,191
Oil^(g)	—	5,477	—	—	—		190		—	5,667
Nuclear	1,176	—	—	—	—		—		—	1,176
Wind	—	—	—	—	961		2,005		—	2,966
Utility Scale Solar	—	—	—	—	851		482		—	1,333
Distributed Solar	—	—	—	—	78		9		114	201
Total generation capacity	14,941	22,124	6,085	749	1,890		4,564		114	50,467
Capacity attributable to noncontrolling interest	—	—	—	—	(638	)	(2,053	)		(2,691	)
Total net generation capacity	14,941	22,124	6,085	749	1,252		2,511		114	47,776

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

(b) Includes Distributed Solar capacity from assets held by DGPV Holdco 1 and DGPV Holdco 2. Excludes 100 MW related to the High Lonesome Mesa facility, which was transferred to lien holders on March 31, 2016.

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

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

(e) New Castle Units 3, 4, and 5 and Joliet Units 6, 7, and 8, totaling 1,651 MW, were moved to natural gas from coal following completion of natural gas conversion projects in the second quarter of 2016. The balance of plant work is being completed for full load operation of Joliet Unit 6.

(f) Coal generation portfolio does not include 94 MW related to Avon Lake 7, which retired in April 2016. New Castle Units 3, 4, and 5 and Joliet Units 6, 7, and 8, totaling 1,651 MW were moved from coal to natural gas following completion of natural gas conversion projects in the second quarter of 2016.

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

To effectuate the Company’s strategy, NRG is focused on: (i) excellence in operating performance of its existing assets including repowering its power generation assets at premium sites and optimal hedging of generation assets and retail load operations; (ii) serving the energy needs of end-use residential, commercial and industrial customers in competitive markets through multiple brands and channels with a variety of retail energy products and services differentiated by innovative features, premium service, sustainability, and loyalty/affinity programs; (iii) investing in, 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 (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.

STP License Amendment — STP Unit 1 is operating with a single-cycle license amendment issued on December 11, 2015 after a control rod was determined to be inoperable following a scheduled refueling and maintenance outage. The approved license amendment supports STP Unit 1 operation with the inoperable control rod and the associated control rod drive shaft removed. Subsequently, STPNOC submitted a permanent license amendment on May 25, 2016 to authorize continued operation of Unit 1 for the remainder of the operating license. The NRC formally accepted this submittal on June 6, 2016 and has committed to reaching a conclusion in time to support the next Unit 1 refueling outage in the spring of 2017.

East Region

PJM

2019/2020 PJM Auction Results — On May 24, 2016, PJM announced the results of its 2019/2020 base residual auction. NRG cleared approximately 11,155 MW of Capacity Performance product and 371 MW of Base Capacity product in the 2019/2020 base residual auction. NRG’s expected capacity revenues from the base residual auction for the 2019/2020 delivery year are approximately $569 million. For results of the 2018/2019 PJM base residual auction, refer to Item 1 - Business of the 2015 Form 10-K.

The table below provides a detailed description of NRG’s 2019/2020 base residual auction results:



	Base Capacity Product		Capacity Performance Product
Zone	Cleared Capacity (MW)⁽¹⁾⁽²⁾	Price ($/MW-day)	Cleared Capacity (MW)⁽¹⁾⁽²⁾	Price ($/MW-day)
COMED	65	$182.77	3,738	$202.77
EMAAC	103	$99.77	895	$119.77
MAAC	10	$80.00	5,972	$100.00
RTO	193	$80.00	550	$100.00
Total	371		11,155

(1) Includes imports. Does not include capacity sold by NRG Curtailment Specialists. Excludes cleared capacity related to Aurora and Rockford, the sales of which were completed on July 12, 2016.

(2) Includes GenOn.

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 would 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 to FERC, 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 protested the filing. On June 28, 2016, FERC accepted ISO-NE's compliance filing and accepted the transition period. The change in the demand curve 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 impermissibly interfered 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, and discovery is ongoing.

On May 20, 2016, the NYSPSC issued a notice soliciting comments as to whether National Grid should still be authorized to recover costs under the DNG Agreement Term Sheet given various intervening events subsequent to the Commission’s approval in 2014. The Company submitted comments on July 15, 2016 in response to the notice.

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. Multiple parties filed for rehearing. NYISO will make a compliance filing by September 19, 2016. 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.

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 both sought rehearing of the Reset Order with the NYSPSC and requested emergency judicial review. On July 25, 2016, the New York Supreme Court vacated part of the Reset Order on procedural grounds and remanded the matter back to the NYSPSC for further consideration. Additionally, the court order affirmed NYSPSC’s authority to regulate ESCO rates. A decision by the NYSPSC to re-affirm the provisions of its prior Reset Order would have a negative impact on the viability of the New York retail energy market.

New York Public Service Commission Clean Energy Standard Proceeding — On August 1, 2016, the NYPSC approved a new Clean Energy Standard, or CES, with the goal of reaching 50 percent renewables in New York by 2030. One aspect of the CES order requires LSEs operating in New York to provide out-of-market support to three struggling nuclear units in New York through the purchase of Zero Energy Credits, or ZECs. The order requires NYSERDA to contract with the operators of the specified nuclear units and then resell the ZECs, at cost, to LSEs. The CES order also specifies the types of resources that qualify to provide RECs and provides a schedule of RECs that each LSE will be required to retire by year. The CES order, both through its implementation of increased REC procurement targets and the uneconomic retention of certain nuclear facilities is expected to have a price suppressing effect on the market. The Company is currently evaluating how to respond to the CES order.

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 May 27, 2016, ERCOT made a final determination that the unit is needed for reliability must-run, or RMR, service to address potential operational contingencies. On June 14, 2016, the ERCOT Board confirmed ERCOT’s determination and approved a two-year RMR agreement, effective June 1, 2016 through June 30, 2018; provided, however, ERCOT may terminate the RMR agreement at any time upon 90 days' notice. ERCOT has a standard form contract that provides for recovery of the operating costs of the unit, together with additional performance metrics and incentives. The estimated budget for the unit is $58 million for the contract period, which amount does not include any incentives. Under the RMR agreement, the unit is only available to ERCOT during the months of June through September. On July 13, 2016, ERCOT issued a request for proposals for alternatives to the RMR agreement.

MISO

MISO Forward Capacity Market Design for Retail Choice — MISO staff has proposed revisions to its market design by implementing a three-year Forward Resource Auction for Illinois and the portion of Michigan with Retail Choice Load with a Sloped Demand Curve. The Company is actively participating in discussions at MISO. The ultimate outcome could have an effect on overall market prices in MISO.

West Region

CAISO

Puente Power Project — On May 26, 2016, the CPUC adopted the alternate proposed decision issued by Commissioner Peterman which approves the resource adequacy purchase agreement, or RAPA, between SCE and NRG for the construction of the 262 MW natural gas peaking Puente Power Project. On July 1, 2016, four different parties sought rehearing by the CPUC of the May 26, 2016 decision approving the RAPA.

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, ash disposal requirements, 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. In May 2016, the U.S. Court of Appeals for the D.C. Circuit announced that it would hold oral argument on the challenges to the CPP while sitting en banc on September 27, 2016.

Gulf Coast Region

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

Illinois Union Insurance Company Litigation — On October 2, 2015, the U.S. District Court for the Middle District of Louisiana issued an order granting LaGen’s motion for summary judgment on its claims for declaratory judgment and breach of contract against ILU for its failure to indemnify LaGen for the costs LaGen paid pursuant to the consent decree that resolved the NSR lawsuit which was brought by the U.S. EPA and LA DEQ against LaGen related to Big Cajun II. The court entered judgment in favor of LaGen for approximately $27 million. In addition, the court ruled that LaGen is entitled to approximately $7 million for future consent decree costs as they are incurred. On October 14, 2015, ILU filed a motion to stay execution of the judgment, which was granted on October 19, 2015. Also, on October 14, 2015, ILU filed a notice to appeal the judgment. On January 14, 2016, the U.S. District Court granted LaGen's motion for attorney's fees of approximately $2 million for the indemnity phase of the litigation. On January 29, 2016, ILU filed their appeal brief with the U.S. Court of Appeals for the Fifth Circuit. After hearing oral argument on July 8, 2016, the U.S. Court of Appeals for the Fifth Circuit issued an order on August 4, 2016 which vacated the summary judgment and remanded the case to the U.S. District Court.

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 resources, 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.

Sherwin Bankruptcy

The Company's Gregory cogeneration plant provides steam, processed water and a small percentage of its electrical generation to the Corpus Christi Sherwin Alumina plant. On January 11, 2016, Sherwin Alumina Company, or Sherwin, filed a voluntary petition with the United States Bankruptcy Court for the Southern District of Texas for relief under Title 11 of the United States Code. Sherwin has agreed to pay all owed pre-petition amounts and, post-petition, Sherwin is performing pursuant to bankruptcy court authorization while it decides whether to reject the agreement Sherwin has with the Company's subsidiary that owns and operates the Company's Gregory cogeneration plant. On August 1, 2016, Sherwin issued a press release indicating that it intends to cease operations and Sherwin is expected to liquidate the bankruptcy estate. The Company is currently evaluating potential options for the Gregory cogeneration plant.

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 station to be returned to service in the third quarter of 2016. The Company expects the restoration costs to be reimbursed through insurance recoveries, except for the $5 million deductible. Through June 30, 2016, NRG has expensed $5 million and collected $27.5 million of insurance proceeds from property damage and is continuing to work with insurers on further property and business interruption insurance recovery. The Company does not anticipate recognizing additional expenses related to restoration costs.

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. The Company receives compensation in exchange for allowing the coal treatment facilities to operate at the Limestone and Parish power generating plants. The current owner of the project companies suspended operations of its coal treatment facilities on May 1, 2016. Should this suspension continue through the remainder of 2016, it will have an adverse impact on future financial 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.

Significant Events

The following significant events occurred during the first six months of 2016, as further described within this Management's Discussion and Analysis and the Condensed Consolidated Financial Statements:


•	Petra Nova Parish Holdings — During the first quarter of 2016, the Company recorded an impairment loss of $140 million on its investment in Petra Nova Parish Holdings.


•	Asset Dispositions —In the first quarter of 2016, the Company completed the sale of the Seward and Shelby generating stations. On May 12, 2016, the Company entered into an agreement to sell 100% of its interests in the Rockford generating stations. Also on May 12, 2016, GenOn entered into an agreement to sell the Aurora generating station.


•	Senior Notes Issuance and Repurchases — On May 23, 2016, NRG issued $1.0 billion in aggregate principal amount at par of 7.25% senior notes due 2026, or the 2026 Senior Notes. The proceeds from the issuance of the 2026 Senior Notes were utilized to redeem a portion of the Senior Notes.


•	Preferred Stock Repurchase — On June 13, 2016, the Company completed the repurchase from Credit Suisse of 100% of the outstanding shares of its $344.5 million 2.822% preferred stock at a price of $226 million.

•

EVgo Sale — On June 17, 2016, the Company completed the sale of a majority interest in the EVgo business to Vision Ridge Partners, which resulted in a loss of $83 million, for total consideration of approximately $39 million, consisting of $17 million in cash received, which is net of $2.5 million in working to the Company, $15 million contributed as capital to the EVgo business by Vision Ridge Partners and $7 million of future contributions by Vision Ridge Partners.


•	Impairment Losses — During the second quarter of 2016, the Company recorded impairment losses on its Rockford generating stations and Mandalay and Ormond Beach operating units, as well as impairments relating to its residential solar business and previously purchased solar panels, totaling $115 million.

Consolidated Results of Operations

The following table provides selected financial information for the Company:



	Three months ended June 30,								Six months ended June 30,
(In millions except otherwise noted)	2016			2015			Change %		2016			2015			Change %
Operating Revenues
Energy revenue^(a)	$	1,031		$	1,231		(16	)%	$	2,182		$	2,907		(25	)%
Capacity revenue ^(a)	511			558			(8	)	1,032			1,046			(1	)
Retail revenue	1,514			1,644			(8	)	2,884			3,307			(13	)
Mark-to-market for economic hedging activities	(539		)	(113		)	(377	)	(513		)	(200		)	(157	)
Contract amortization	(14		)	(12		)	(17	)	(29		)	(20		)	(45	)
Other revenues ^(b)	135			92			47		311			189			65
Total operating revenues	2,638			3,400			(22	)	5,867			7,229			(19	)
Operating Costs and Expenses
Cost of sales ^(c)	1,517			1,791			(15	)	3,022			3,922			(23	)
Mark-to-market for economic hedging activities	(441		)	(110		)	(301	)	(450		)	81			N/M
Contract and emissions credit amortization ^(c)	(3		)	—			N/A		3			4			(25	)
Operations and maintenance	577			644			(10	)	1,160			1,272			(9	)
Other cost of operations	106			111			(5	)	210			230			(9	)
Total cost of operations	1,756			2,436			(28	)	3,945			5,509			(28	)
Depreciation and amortization	309			396			(22	)	622			791			(21	)
Impairment losses	115			—			N/A		115			—			N/A
Selling and marketing	86			123			(30	)	186			228			(18	)
General and administrative	179			173			3		334			323			3
Acquisition-related transaction and integration costs	5			3			67		7			13			(46	)
Development activity expenses	18			37			(51	)	44			71			(38	)
Total operating costs and expenses	2,468			3,168			(22	)	5,253			6,935			(24	)
Loss on sale of assets, net of gains and gain on postretirement benefits curtailment	(83		)	—			N/A		(51		)	14			(464	)
Operating Income	87			232			(63	)	563			308			83
Other Income/(Expense)
Equity in earnings/(losses) of unconsolidated affiliates	4			8			50		(3		)	5			160
Gain/(impairment loss) on investment	7			—			N/A		(139		)	—			N/A
Other income, net	8			4			(100	)	26			23			(13	)
Loss on debt extinguishment	(80		)	(7		)	N/A		(69		)	(7		)	N/A
Interest expense	(277		)	(263		)	5		(561		)	(564		)	(1	)
Total other expense	(338		)	(258		)	31		(746		)	(543		)	37
Loss before Income Taxes	(251		)	(26		)	N/M		(183		)	(235		)	22
Income tax expense /(benefit)	25			(17		)	(247	)	46			(90		)	(151	)
Net Loss	(276		)	(9		)	N/M		(229		)	(145		)	(58	)
Less: Net (loss)/income attributable to noncontrolling interest and redeemable noncontrolling interest	(5		)	5			(200	)	(40		)	(11		)	(264	)
Net Loss Attributable to NRG Energy, Inc.	$	(271	)	$	(14	)	N/M		$	(189	)	$	(134	)	(41	)
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	$	1.95		$	2.64		(26	)%	$	2.02		$	2.81		(28	)%

(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 June 30, 2016, and 2015

Loss before income taxes — The pre-tax loss of $251 million for the three months ended June 30, 2016, compared to pre-tax loss of $26 million for the three months ended June 30, 2015, primarily reflects:

•an increase of $115 million in impairment losses,

•an increase of $80 million in other expenses primarily relating to loss on debt extinguishment and interest expense; and

•a decrease in gross margin of $170 million comprised of a decrease in Generation gross margin of $455 million, decrease in Renewables gross margin of $2 million, partially offset by an increase in Retail Mass gross margin of $262 million, and an increase in NRG Yield gross margin of $25 million;

partially offset by:

•a decrease of $140 million in other operating costs comprised primarily of operations and maintenance expense, other costs of operations, depreciation and amortization, selling and marketing expense, general and administrative expense, acquisition-related transaction and integration costs, development activity expense, and loss on sale of assets.

Net loss — The increase in net loss of $267 million primarily reflects the drivers discussed above, including an income tax expense of $25 million for the three months ended June 30, 2016, compared to an income tax benefit of $17 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 June 30, 2016, and 2015. Average on-peak power prices decreased primarily due to the decrease in natural gas prices for the three months ended June 30, 2016 as compared to the same period in 2015.



	Average on Peak Power Price ($/MWh) ^(a)
	Three months ended June 30,
Region	2016		2015		Change %
Gulf Coast ^(b)
ERCOT - Houston	$	24.33	$	27.98	(13	)%
ERCOT - North	22.30		27.81		(20	)%
MISO - Louisiana Hub	37.10		39.15		(5	)%
East
NY J/NYC	29.31		34.68		(15	)%
NY A/West NY	35.61		38.92		(9	)%
NEPOOL	28.24		28.40		(1	)%
PEPCO (PJM)	37.52		44.42		(16	)%
PJM West Hub	32.71		39.23		(17	)%
West
CAISO - NP15	26.15		39.29		(33	)%
CAISO - SP15	27.14		27.62		(2	)%

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

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

The following table summarizes average realized power prices for each region in which NRG operates for the three months ended June 30, 2016, and 2015, which reflects the impact of settled hedges.



	Average Realized Power Price ($/MWh)
	Three months ended June 30,
Region	2016		2015		Change %
Gulf Coast	$	37.95	$	40.96	(7	)%
East	56.55		47.18		20	%
West	36.14		44.40		(19	)%

Though the average on peak power prices have decreased on average by 14%, average realized prices by region for the Company have either increased or decreased at a slower rate year-over-year due to the Company's multi-year hedging program and the success of the Company's commercial operations team that optimizes the value of the assets on a daily basis.

Gross Margin

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

Economic Gross Margin

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

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

The below tables present the composition and reconciliation of gross margin and economic gross margin for the three months ended June 30, 2016 and 2015:



	Three months ended June 30, 2016
	Generation																		Retail Mass
(In millions)	Gulf Coast			East			West			Business Solutions^(a)			Eliminations			Subtotal			Retail Mass			Renewables			NRG Yield			Eliminations/Corporate			Total
Energy revenue	$	529		$	485		$	45		$	1		$	—		$	1,060		$	—		$	116		$	147		$	(292	)	$	1,031
Capacity revenue	71			294			42			22			—			429			—			—			87			(5		)	511
Retail revenue	—			—			—			311			—			311			1,202			—			—			1			1,514
Mark-to-market for economic hedging activities	(421		)	(176		)	(11		)	(2		)	—			(610		)	—			(2		)	—			73			(539		)
Contract amortization	4			—			—			—			—			4			(1		)	—			(17		)	—			(14		)
Other revenue	82			23			6			5			(4		)	112			—			11			41			(29		)	135
Operating revenue	265			626			82			337			(4		)	1,306			1,201			125			258			(252		)	2,638
Cost of fuel	(239		)	(261		)	(28		)	—			—			(528		)	—			(1		)	(7		)	88			(448		)
Other cost of sales^(b)	(110		)	(75		)	(5		)	(301		)	—			(491		)	(821		)	—			(7		)	250			(1,069		)
Mark-to-market for economic hedging activities	32			9			(4		)	165			—			202			312			—			—			(73		)	441
Contract and emission credit amortization	(5		)	6			4			(1		)	—			4			—			—			—			(1		)	3
Gross margin	$	(57	)	$	305		$	49		$	200		$	(4	)	$	493		$	692		$	124		$	244		$	12		$	1,565
Less: Mark-to-market for economic hedging activities, net	(389		)	(167		)	(15		)	163			—			(408		)	312			(2		)	—			—			(98		)
Less: Contract and emission credit amortization, net	(1		)	6			4			(1		)	—			8			(1		)	—			(17		)	(1		)	(11		)
Economic gross margin	$	333		$	466		$	60		$	38		$	(4	)	$	893		$	381		$	126		$	261		$	13		$	1,674
Business Metrics
MWh sold (thousands)^(c)(d)	13,938			8,576			1,245															1,122			1,820
MWh generated (thousands) ^(e)	12,675			7,328			1,077															1,122			2,196
Electricity sales volume — GWh										4,671
(a) Includes International.
(b) Includes purchased energy, capacity and emissions credits
(c) MWh sold excludes generation at facilities in the East and West that generate revenue under capacity agreements.
(d) Does not include thermal MWh of 9 thousand or MWt of 448 thousand for thermal sold by NRG Yield.
(e) Does not include thermal MWh of 32 thousand or MWt of 448 thousand for thermal generated by NRG Yield.



	Three months ended June 30, 2015
	Generation
(In millions)	Gulf Coast			East			West			Business Solutions^(a)			Eliminations			Subtotal			Retail Mass			Renewables			NRG Yield			Eliminations/Corporate			Total
Energy revenue	$	634		$	582		$	46		$	—		$	—		$	1,262		$	—		$	124		$	123		$	(278	)	$	1,231
Capacity revenue	63			326			52			35			—			476			—			—			85			(3		)	558
Retail revenue	—			—			—			344			—			344			1,298			—			—			2			1,644
Mark-to-market for economic hedging activities	(75		)	39			(11		)	2			—			(45		)	—			(2		)	(4		)	(62		)	(113		)
Contract amortization	4			—			—			—			—			4			—			(1		)	(15		)	—			(12		)
Other revenue	53			12			2			5			(3		)	69			—			7			46			(30		)	92
Operating revenue	679			959			89			386			(3		)	2,110			1,298			128			235			(371		)	3,400
Cost of fuel	(309		)	(303		)	(30		)	—			—			(642		)	—			(1		)	(9		)	5			(647		)
Other cost of sales^(b)	(84		)	(91		)	(5		)	(346		)	—			(526		)	(910		)	(1		)	(7		)	300			(1,144		)
Mark-to-market for economic hedging activities	(1		)	(8		)	(3		)	18			—			6			42			—			—			62			110
Contract and emission credit amortization	(5		)	5			2			(1		)	—			1			—			—			—			(1		)	—
Gross margin	$	280		$	562		$	53		$	57		$	(3	)	$	949		$	430		$	126		$	219		$	(5	)	$	1,719
Less: Mark-to-market for economic hedging activities, net	(76		)	31			(14		)	20			—			(39		)	42			(2		)	(4		)	—			(3		)
Less: Contract and emission credit amortization, net	(1		)	5			2			(1		)	—			5			—			(1		)	(15		)	(1		)	(12		)
Economic gross margin	$	357		$	526		$	65		$	38		$	(3	)	$	983		$	388		$	129		$	238		$	(4	)	$	1,734
Business Metrics
MWh sold (thousands)^(c)(d)	15,480			12,336			1,036															1,193			1,699
MWh generated (thousands)^(e)	14,547			10,823			804															1,208			2,240
Electricity sales volume — GWh										4,896
(a) Includes International
(b) Includes purchased energy, capacity and emissions credits
(c) MWh sold excludes generation at facilities in the East and West that generate revenue under capacity agreements.
(d) Does not include thermal MWh of 83 thousand or MWt of 434 thousand for thermal sold by NRG Yield.
(e) Does not include thermal MWh of 83 thousand or MWt of 434 thousand for thermal generated by NRG Yield.



	Three months ended June 30,
Weather Metrics	Gulf Coast	East	West
2016
CDDs ^(a)	873	348	199
HDDs ^(a)	53	578	243
2015
CDDs	892	391	195
HDDs	47	465	315
10 year average
CDDs	969	347	171
HDDs	77	526	370

(a)

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

Generation gross margin and economic gross margin

The below tables present the changes in Generation gross margin and economic gross margin which include intercompany sales, during the three months ended June 30, 2016, compared to the same period in 2015:



(In millions)	Gross Margin (increase/(decrease))			Economic Gross Margin (increase/(decrease))
Gulf Coast region	$	(337	)	$	(24	)
East region	(257		)	(60		)
West region	(4		)	(5		)
Business Solutions	143			—
	$	(455	)	$	(89	)

The decreases in Generation gross margin and economic gross margin were driven by:

Gulf Coast Region



	(In millions)
Lower gross margin primarily due to lower coal generation mainly in Texas, which was driven by lower natural gas prices	$	(42	)
Lower gross margin due to lower average realized prices primarily in Texas	(6		)
Higher gross margin from a 25% increase in nuclear generation driven by reduced planned outages in Texas	16
Higher capacity gross margin, primarily in South Central due to ISO auction prices	8
Decrease in economic gross margin	$	(24	)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(313		)
Decrease in gross margin	$	(337	)

East Region



	(In millions)
Lower gross margin due to a 32% decrease in generation primarily driven by the environmental control work at Avon Lake, fuel conversion projects at the Joliet and Shawville facilities as well as the sale of the Seward and Shelby generating stations in 2016.	$	(92	)
Lower gross margin driven primarily by a 7% decrease in New York and New England hedged capacity prices as well as the roll-off of the Dunkirk RSS contract offset by a 1% increase in volumes sold	(19		)
Lower gross margin driven by a 5% decrease in PJM capacity volumes, a 3% decrease in PJM hedged capacity prices and an increase in capacity purchases as a result of operational performance	(17		)
Lower gross margin due to lower load contracted volumes and roll-off of contracts	(7		)
Higher gross margin as a result of 28% increase in average realized energy prices due to beneficial hedges	63
Changes in commercial optimization activities and other	12
Decrease in economic gross margin	$	(60	)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(198		)
Contract and emission credit amortization	1
Decrease in gross margin	$	(257	)

West Region



	(In millions)
Lower capacity gross margin due to a 20% decrease in volume, and a 2% decrease in price due to higher reserve margins driven by more competition in certain areas	$	(11	)
Other	6
Decrease in economic gross margin	$	(5	)
Decrease in mark-to-market for economic hedging activities	(1		)
Increase in contract and emission credit amortization	2
Decrease in gross margin	$	(4	)

Business Solutions



	(In millions)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	143
Increase in gross margin	$	143

Retail Mass gross margin and economic gross margin

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



	Three months ended June 30,
(In millions except otherwise noted)	2016			2015
Retail Mass revenue	$	1,169		$	1,267
Supply management revenue	33			31
Contract amortization	(1		)	—
Operating revenue^(a)	1,201			1,298
Cost of sales ^(b)	(821		)	(910		)
Mark-to-market for economic hedging activities	312			42
Gross Margin	$	692		$	430
Less: Mark-to-market for economic hedging activities, net	312			42
Less: Contract and emission credit amortization, net	(1		)	—
Economic Gross Margin	$	381		$	388

Business Metrics
Electricity sales volume — GWh - Gulf Coast	8,674			8,400
Electricity sales volume — GWh - All other regions	1,444			1,778
Average Retail Mass customer count (in thousands)^(c)	2,770			2,774
Ending Retail Mass customer count (in thousands)^(c)	2,771			2,759


(a)	Includes intercompany sales of $3 million and $4 million in 2016 and 2015, respectively, representing sales from Retail Mass to the Gulf Coast region.


(b)	Includes intercompany purchases of $223 million and $279 million in 2016 and 2015.


(c)	Includes Retail Mass Recurring Customers and excludes Discrete Customers.

Retail Mass gross margin increased $262 million and economic gross margin decreased $7 million for the three months ended June 30, 2016, compared to the same period in 2015, due to:



	(In millions)
Lower gross margin due to lower rates to customers of $90 million or approximately $9 per MWh, partially offset by lower supply costs of $85 million or approximately $8 per MWh driven by a decrease in natural gas prices	$	(5	)
Lower gross margin due to milder weather conditions in 2016 as compared to 2015	(2		)
Decrease in economic gross margin	$	(7	)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	270
Decrease in contract and emission credit amortization	(1		)
Increase in gross margin	$	262

Renewables gross margin and economic gross margin

Renewables gross margin decreased $2 million and economic gross margin decreased $3 million for the three months ended June 30, 2016, compared to the same period in 2015, primarily related to unplanned outages at Ivanpah facility during the quarter.

NRG Yield gross margin and economic gross margin

NRG Yield gross margin increased $25 million and economic gross margin increased $23 million for the three months ended June 30, 2016, compared to the same period in 2015, primarily related to higher wind generation during the 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 decreased by $95 million during the three months ended June 30, 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 June 30, 2016
			Generation
	Retail Mass		Gulf Coast			East			West			Business Solutions			Renewables			Elimination^(a)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	—	$	(129	)	$	(75	)	$	—		$	(1	)	$	—		$	32		$	(173	)
Reversal of acquired gain positions related to economic hedges	—		—			(13		)	—			—			—			—			(13		)
Net unrealized (losses)/gains on open positions related to economic hedges	—		(292		)	(88		)	(11		)	(1		)	(2		)	41			(353		)
Total mark-to-market (losses)/gains in operating revenues	$	—	$	(421	)	$	(176	)	$	(11	)	$	(2	)	$	(2	)	$	73		$	(539	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	76	$	8		$	24		$	—		$	46		$	—		$	(32	)	$	122
Reversal of acquired (gain)/loss positions related to economic hedges	—		—			—			(3		)	1			—			—			(2		)
Net unrealized gains/(losses) on open positions related to economic hedges	236		24			(15		)	(1		)	118			—			(41		)	321
Total mark-to-market gains/(losses) in operating costs and expenses	$	312	$	32		$	9		$	(4	)	$	165		$	—		$	(73	)	$	441


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



	Three months ended June 30, 2015
				Generation
	Retail Mass			Gulf Coast			East			West			Business Solutions			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	$	—		$	(125	)	$	(55	)	$	—		$	(1	)	$	(4	)	$	2		$	(25	)	$	(208	)
Reversal of acquired gain positions related to economic hedges	—			—			(24		)	—			—			—			—			—			(24		)
Net unrealized gains/(losses) on open positions related to economic hedges	—			50			118			(11		)	3			2			(6		)	(37		)	119
Total mark-to-market (losses)/gains in operating revenues	$	—		$	(75	)	$	39		$	(11	)	$	2		$	(2	)	$	(4	)	$	(62	)	$	(113	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses on settled positions related to economic hedges	$	87		$	11		$	6		$	—		$	43		$	—		$	—		$	25		$	172
Reversal of acquired loss/(gain) positions related to economic hedges	3			—			—			(3		)	—			—			—			—			—
Net unrealized losses on open positions related to economic hedges	(48		)	(12		)	(14		)	—			(25		)	—			—			37			(62		)
Total mark-to-market gains/(losses) in operating costs and expenses	$	42		$	(1	)	$	(8	)	$	(3	)	$	18		$	—		$	—		$	62		$	110


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

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

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

For the three months ended June 30, 2016, the $539 million loss in operating revenues from economic hedge positions was driven primarily by a decrease in value of open positions as a result of increases in gas and electricity prices, in addition to the reversal of previously recognized unrealized gains on contracts that settled during the period and the reversal of acquired contracts. The $441 million gain in operating costs and expenses from economic hedge positions was driven primarily by an increase in value of open positions as a result of increases in natural gas, coal, and ERCOT electricity prices, in addition to the reversal of previously recognized unrealized losses on contracts that settled during the period.

For the three months ended June 30, 2015, the $113 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 and the reversal of acquired contracts, partially offset by an increase in value of open positions as a result of decreases in ERCOT and PJM electricity prices. The $110 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, partially offset by a decrease in value of open positions as a result of decreases in ERCOT electricity and coal prices.

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the three months ended June 30, 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 June 30,
(In millions)	2016		2015
Trading gains/(losses)
Realized	$	23	$	25
Unrealized	13		(24		)
Total trading gains	$	36	$	1

In addition, trading activities reflect an increase in gross margin of $17 million, reflected in the Corporate segment, for the three months ended June 30, 2016, as compared to the three months ended June 30, 2015.

Operations and Maintenance Expense



	Generation								Retail Mass		Renewables		NRG Yield		Corporate
	Gulf Coast		East		West		Business Solutions		Retail Mass		Renewables		NRG Yield		Corporate			Total
	(In millions)
Three months ended June 30, 2016	$	143	$	257	$	34	$	6	$	60	$	49	$	47	$	(19	)	$	577
Three months ended June 30, 2015	183		291		36		6		56		27		42		3			644

Operations and maintenance expense decreased by $67 million for the three months ended June 30, 2016, compared to the same period in 2015, due to the following:



	(In millions)
Decrease in Gulf Coast operations and maintenance expense primarily related to the timing of outages at the Limestone and STP facilities located in Texas	$	(36	)
Decrease in operating costs due to the sale of Seward and Shelby generating stations in 2016	(19		)
Decrease in East operations and maintenance expense relating to timing of outages and maintenance work in the prior year for Bowline, Powerton and Canal, partially offset by an increase in maintenance expense at Joliet, New Castle, and Avon Lake in the current year	(8		)
Decrease in East variable operating costs driven by a 32% decrease in generation across the fleet	(7		)
Decrease in West operations and maintenance expense primarily related to the timing of outages	(6		)
Increase in Renew operations and maintenance expense primarily related to unplanned outages at Ivanpah	16
Other	(7		)
	$	(67	)

Other Cost of Operations

Other cost of operations, comprised of asset retirement expense, insurance expense and property and other tax expense, decreased by $5 million for the three months ended June 30, 2016, compared to the same period in 2015.

Depreciation and Amortization



	Generation								Retail Mass		Renewables		NRG Yield		Corporate
	Gulf Coast		East		West		Business Solutions		Retail Mass		Renewables		NRG Yield		Corporate		Total
	(In millions)
Three months ended June 30, 2016	$	73	$	52	$	16	$	3	$	27	$	55	$	67	$	16	$	309
Three months ended June 30, 2015	140		72		13		3		33		53		70		12		396

Depreciation and amortization expense decreased by $87 million for the three months ended June 30, 2016, compared to the same period in 2015, primarily due to decrease in depreciation expense for facilities impaired during 2015.

Impairment Losses

For the three months ended June 30, 2016, the Company recorded impairment losses of $115 million, primarily due to the impairment of the Rockford stations, Mandalay and Ormond Beach operating units, as further described in Note 7, Impairments, of this Form 10-Q.

Selling, Marketing, General and Administrative Expenses

Selling and marketing expenses are comprised of the following:



	Generation								Retail Mass		Renewables		NRG Yield		Corporate
	Gulf Coast		East		West		Business Solutions		Retail Mass		Renewables		NRG Yield		Corporate		Total
	(In millions)
Three months ended June 30, 2016	$	—	$	—	$	—	$	11	$	56	$	2	$	—	$	17	$	86
Three months ended June 30, 2015	—		—		—		15		64		3		—		41		123

Selling and marketing expense decreased by $37 million for the three months ended June 30, 2016, compared to the same period in 2015, due primarily to the continued focus on cost management.

General and administrative expenses are comprised of the following:



	Generation								Retail Mass		Renewables		NRG Yield		Corporate
	Gulf Coast		East		West		Business Solutions		Retail Mass		Renewables		NRG Yield		Corporate		Total
	(In millions)
Three months ended June 30, 2016	$	37	$	48	$	9	$	9	$	32	$	14	$	3	$	27	$	179
Three months ended June 30, 2015	45		54		12		7		42		9		3		1		173

General and administrative expenses increased by $6 million for the three months ended June 30, 2016, compared to the same period in 2015, due primarily to an increase in cost to achieve expenses in 2016, which primarily reflects severance and employee costs based on the Company's recent strategy changes, which were partially offset by a reduction in expenses due to continued focus on cost management.

Loss on Sale of Assets

During the three months ended June 30, 2016, the Company sold a majority interest in its EVgo business to Vision Ridge Partners, as described in Note 3, Business Acquisitions and Dispositions. In connection with the sale, the Company recorded a loss on sale of $83 million, which includes $56 million for the accrual of NRG's remaining obligation to the CPUC.

Loss on Debt Extinguishment

A loss on debt extinguishment of $80 million was recorded for the three months ended June 30, 2016, primarily driven by the repurchase of NRG Senior Notes at a price above par value, combined with the write-off of unamortized debt issuance costs.

Interest Expense

NRG's interest expense increased by $14 million for the three months ended June 30, 2016, compared to the same period in 2015 due to the following:



	(In millions)
Increase in derivative interest expense from changes in fair value of interest rate swaps	$	34
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	4
Decrease due to the repurchases of Senior Notes at the end of 2015 and first two quarters of 2016	(22		)
Other	(2		)
	$	14

Income Tax Expense/(Benefit)

For the three months ended June 30, 2016, NRG recorded an income tax expense of $25 million on a pre-tax loss of $251 million. For the same period in 2015, NRG recorded an income tax benefit of $17 million on a pre-tax loss of $26 million. The effective tax rate was (10.0)% and 65.4% for the three months ended June 30, 2016, and 2015, respectively.

For the three months ended June 30, 2016, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to tax expense resulting from the change in the valuation allowance, amortization of indefinite lived assets, inclusion of consolidated partnerships and the impact of state income taxes.

For the three months ended June 30, 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 tax expense attributable to consolidated partnerships.

Net (loss)/income attributable to noncontrolling interests and redeemable noncontrolling interests

For the three months ended June 30, 2016, and 2015, net (loss)/income 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.

Management’s discussion of the results of operations for the six months ended June 30, 2016, and 2015

Loss before income taxes — The pre-tax loss of $183 million for the six months ended June 30, 2016, compared to pre-tax loss of $235 million for the six months ended June 30, 2015, primarily reflects:

•a decrease of $376 million in other operating costs comprised primarily of operations and maintenance expense, other costs of operations, depreciation and amortization, selling and marketing expense, general and administrative expense, acquisition-related transaction and integration costs, development activity expense, and loss on sale of assets;

partially offset by:

•an increase of $254 million in impairment losses, including $139 million on investments;

•an increase of $64 million in other expenses primarily relating to loss on debt extinguishment; and

•a decrease in gross margin of $6 million comprised of a decrease in Generation gross margin of $363 million, partially offset by an increase in Retail Mass gross margin of $297 million, an increase in NRG Yield gross margin of $45 million, and an increase in Renewables gross margin of $15 million.

Net loss — The increase in net loss of $84 million primarily reflects the drivers discussed above, including an income tax expense of $46 million for the six months ended June 30, 2016, compared to an income tax benefit of $90 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 six months ended June 30, 2016, and 2015. Average on-peak power prices decreased primarily due to the decrease in natural gas prices for the six months ended June 30, 2016 as compared to the same period in 2015.



	Average on Peak Power Price ($/MWh) ^(a)
	Six months ended June 30,
Region	2016		2015		Change %
Gulf Coast ^(b)
ERCOT - Houston	$	22.39	$	27.22	(18	)%
ERCOT - North	20.97		27.17		(23	)%
MISO - Louisiana Hub	30.30		38.20		(21	)%
East
NY J/NYC	31.30		58.11		(46	)%
NY A/West NY	32.94		46.35		(29	)%
NEPOOL	29.53		58.62		(50	)%
PEPCO (PJM)	35.94		52.97		(32	)%
PJM West Hub	31.50		48.31		(35	)%
West
CAISO - NP15	25.01		36.92		(32	)%
CAISO - SP15	25.21		30.19		(16	)%

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

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

The following table summarizes average realized power prices for each region in which NRG operates for the six months ended June 30, 2016, and 2015, which reflects the impact of settled hedges.



	Average Realized Power Price ($/MWh)
	Six months ended June 30,
Region	2016		2015		Change %
Gulf Coast	$	38.26	$	40.93	(7	)%
East	60.58		56.28		8	%
West	34.80		42.53		(18	)%

Though the average on peak power prices have decreased on average by 33%, average realized prices by region for the Company have either increased or decreased at a slower rate year-over-year due to the Company's multi-year hedging program and the success of the Company's commercial operations team that optimizes the value of the assets on a daily basis.

Gross Margin

Economic Gross Margin

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

The below tables present the composition and reconciliation of gross margin and economic gross margin for the six months ended June 30, 2016 and 2015:



	Six months ended June 30, 2016
	Generation																		Retail Mass
(In millions)	Gulf Coast			East			West			Business Solutions^(a)			Eliminations			Subtotal			Retail Mass			Renewables			NRG Yield			Eliminations/Corporate			Total
Energy revenue	$	997		$	1,220		$	73		$	1		$	—		$	2,291		$	—		$	215		$	262		$	(586	)	$	2,182
Capacity revenue	150			618			81			29			—			878			—			—			170			(16		)	1,032
Retail revenue	—			—			—			622			—			622			2,251			—			—			11			2,884
Mark-to-market for economic hedging activities	(449		)	(145		)	(11		)	(2		)	—			(607		)	—			(1		)	—			95			(513		)
Contract amortization	7			—			—			—			—			7			(2		)	—			(34		)	—			(29		)
Other revenue	138			41			56			8			(8		)	235			—			20			80			(24		)	311
Operating revenue	843			1,734			199			658			(8		)	3,426			2,249			234			478			(520		)	5,867
Cost of fuel	(431		)	(632		)	(41		)	—			—			(1,104		)	(4		)	(2		)	(18		)	217			(911		)
Other cost of sales^(b)	(197		)	(202		)	(10		)	(593		)	—			(1,002		)	(1,551		)	(1		)	(12		)	455			(2,111		)
Mark-to-market for economic hedging activities	34			8			(7		)	169			—			204			341			—			—			(95		)	450
Contract and emission credit amortization	(10		)	11			3			(3		)	—			1			—			—			(6		)	2			(3		)
Gross margin	$	239		$	919		$	144		$	231		$	(8	)	$	1,525		$	1,035		$	231		$	442		$	59		$	3,292
Less: Mark-to-market for economic hedging activities, net	(415		)	(137		)	(18		)	167			—			(403		)	341			(1		)	—			—			(63		)
Less: Contract and emission credit amortization, net	(3		)	11			3			(3		)	—			8			(2		)	—			(40		)	2			(32		)
Economic gross margin	$	657		$	1,045		$	159		$	67		$	(8	)	$	1,920		$	696		$	232		$	482		$	57		$	3,387
Business Metrics
MWh sold (thousands)^(b)(c)	26,061			20,137			2,098															2,340			3,470
MWh generated (thousands) ^(d)	23,536			15,622			1,801															2,340			4,107
Electricity sales volume — GWh										9,211
(a) Includes International.
(b) MWh sold excludes generation at facilities in the East and West that generate revenue under capacity agreements.
(c) Does not include thermal MWh of 49 thousand or MWt of 1,001 thousand for thermal sold by NRG Yield.
(d) Does not include thermal MWh of 123 thousand or MWt of 1,001 thousand for thermal generated by NRG Yield.



	Six months ended June 30, 2015
	Generation
(In millions)	Gulf Coast			East			West			Business Solutions^(a)			Eliminations			Subtotal			Retail Mass			Renewables			NRG Yield			Eliminations/Corporate			Total
Energy revenue	$	1,250		$	1,677		$	70		$	—		$	—		$	2,997		$	—		$	206		$	204		$	(500	)	$	2,907
Capacity revenue	121			645			89			35			—			890			—			—			163			(7		)	1,046
Retail revenue	—			—			—			692			—			692			2,610			—			—			5			3,307
Mark-to-market for economic hedging activities	13			(139		)	(5		)	3			—			(128		)	—			(2		)	3			(73		)	(200		)
Contract amortization	8			—			—			—			—			8			(1		)	(1		)	(26		)	—			(20		)
Other revenue	110			42			6			9			(7		)	160			—			16			91			(78		)	189
Operating revenue	1,502			2,225			160			739			(7		)	4,619			2,609			219			435			(653		)	7,229
Cost of fuel	(609		)	(836		)	(43		)	—			—			(1,488		)	(5		)	(2		)	(26		)	(4		)	(1,525		)
Other cost of sales^(b)	(162		)	(239		)	(9		)	(665		)	—			(1,075		)	(1,876		)	(1		)	(12		)	567			(2,397		)
Mark-to-market for economic hedging activities	(24		)	(83		)	(8		)	(49		)	—			(164		)	10			—			—			73			(81		)
Contract and emission credit amortization	(11		)	8			3			(3		)	—			(3		)	—			—			—			(1		)	(4		)
Gross margin	$	696		$	1,075		$	103		$	22		$	(7	)	$	1,889		$	738		$	216		$	397		$	(18	)	$	3,222
Less: Mark-to-market for economic hedging activities, net	(11		)	(222		)	(13		)	(46		)	—			(292		)	10			(2		)	3			—			(281		)
Less: Contract and emission credit amortization, net	(3		)	8			3			(3		)	—			5			(1		)	(1		)	(26		)	(1		)	(24		)
Economic gross margin	$	710		$	1,289		$	113		$	71		$	(7	)	$	2,176		$	729		$	219		$	420		$	(17	)	$	3,527
Business Metrics
MWh sold (thousands)^(b)(c)	30,537			29,798			1,646															2,150			2,873
MWh generated (thousands)^(d)	28,931			25,642			1,230															2,204			3,734
Electricity sales volume — GWh										9,482
(a) Includes International.
(b) MWh sold excludes generation at facilities in the East and West that generate revenue under capacity agreements.
(c) Does not include thermal MWh of 127 thousand or MWt of 1,051 thousand for thermal sold by NRG Yield.
(d) Does not include thermal MWh of 127 thousand or MWt of 1,051 thousand for thermal generated by NRG Yield.



	Six months ended June 30,
Weather Metrics	Gulf Coast	East	West
2016
CDDs ^(a)	950	380	204
HDDs ^(a)	984	2,829	1,217
2015
CDDs	933	424	212
HDDs	1,331	3,425	1,128
10 year average
CDDs	1,059	376	174
HDDs	1,170	3,025	1,525

(a)

Generation gross margin and economic gross margin

The below tables present the changes in Generation gross margin and economic gross margin which include intercompany sales, during the six months ended June 30, 2016, compared to the same period in 2015:



(In millions)	Gross Margin (increase/(decrease))			Economic Gross Margin (increase/(decrease))
Gulf Coast region	$	(457	)	$	(53	)
East region	(156		)	(244		)
West region	41			46
Business Solutions	209			(4		)
	$	(363	)	$	(255	)

The decreases in Generation gross margin and economic gross margin were driven by:

Gulf Coast Region



	(In millions)
Lower gross margin primarily due to lower coal generation mainly in Texas, which was driven by lower natural gas prices	$	(77	)
Lower gross margin due to lower average realized prices	(19		)
Higher capacity margin, primarily in South Central due to ISO auction prices	29
Higher gross margin from a 11% increase in nuclear generation driven by reduced planned outages in Texas	17
Other	(3		)
Decrease in economic gross margin	$	(53	)
Decrease in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	(404		)
Decrease in gross margin	$	(457	)

East Region



	(In millions)
Lower gross margin due to a 26% decrease in generation primarily driven by the environmental control work at Avon Lake and Powerton, fuel conversion projects at the Joliet and Shawville facilities as well as the sale of the Seward and Shelby generating stations in 2016. In addition there was a 13% decrease in generation as the result of prior year winter weather conditions and current year planned outages	$	(224	)
Lower gross margin driven primarily by a 7% decrease in capacity volumes due to plant shutdowns, a 1% 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	(42		)
Lower gross margin primarily driven by an increase in purchased capacity and a 5% decrease in PJM capacity volumes as a result of unit deactivations, partially offset by a 5% increase in PJM cleared auction prices	(16		)
Changes in commercial optimization activities	23
Higher gross margin due to lower supply cost for servicing the load contracts	20
Other	(5		)
Decrease in economic gross margin	$	(244	)
Increase in mark-to-market for economic hedging primarily due to reversals of previously recognized unrealized gains/losses on settled positions and unrealized gains/losses on open positions related to economic hedges	85
Increase in contract and credit amortization	3
Decrease in gross margin	$	(156	)

West Region



	(In millions)
Gain on sale of excess emission credits	$	47
Higher energy gross margin due to a 27% increase in volume due to higher margin from lower gas prices and higher availability at the Sunrise power plant, as well as Pittsburg generating station's merchant status due to toll expiration, offset by 17% decrease in energy prices	5
Lower capacity gross margin due to a 8% decrease in volume, and a 2% decrease in price due to higher reserve margins driven by more competition in certain areas	(8		)
Other	2
Increase in economic gross margin	$	46
Decrease in mark-to-market for economic hedging activities driven by a decrease in the value of open positions	(5		)
Increase in gross margin	$	41

Business Solutions



	(In millions)
Lower gross margin in 2016 primarily driven by a 10% decrease in customers	$	(4	)
Decrease in economic gross margin	$	(4	)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	213
Increase in gross margin	$	209

Retail Mass gross margin and economic gross margin

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



	Six months ended June 30,
(In millions except otherwise noted)	2016			2015
Retail Mass revenue	$	2,199		$	2,549
Supply management revenue	52			61
Contract amortization	(2		)	(1		)
Operating revenue^(a)	2,249			2,609
Cost of sales ^(b)	(1,555		)	(1,881		)
Mark-to-market for economic hedging activities	341			10
Gross Margin	$	1,035		$	738
Less: Mark-to-market for economic hedging activities, net	341			10
Less: Contract and emission credit amortization, net	(2		)	(1		)
Economic Gross Margin	$	696		$	729

Business Metrics
Electricity sales volume — GWh - Gulf Coast	15,386			15,948
Electricity sales volume — GWh - All other regions	3,278			4,392
Average Retail Mass customer count (in thousands)^(c)	2,763			2,793
Ending Retail Mass customer count (in thousands)^(c)	2,771			2,759


(a)	Includes intercompany sales of $4 million and $5 million in 2016 and 2015, respectively, representing sales from Retail Mass to the Gulf Coast region.


(b)	Includes intercompany purchases of $415 million and $529 million in 2016 and 2015.


(c)	Includes Retail Mass Recurring Customers and excludes Discrete Customers.

Retail Mass gross margin increased $297 million and economic gross margin decreased $33 million for the six months ended June 30, 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	$	(59	)
Higher gross margin due to lower supply costs of $237 million or approximately $9 per MWh, partially offset by lower rates to customers of $211 million or $7 per MWh driven by a decrease in natural gas prices	26
Decrease in economic gross margin	$	(33	)
Increase in mark-to-market for economic hedging primarily due to net unrealized gains/losses on open positions related to economic hedges	331
Decrease in contract and emission credit amortization	(1		)
Increase in gross margin	$	297

Renewables gross margin and economic gross margin

Renewables gross margin increased $15 million and economic gross margin increased $13 million for the six months ended June 30, 2016, compared to the same period in 2015, primarily as a result of higher wind generation at the Cedro Hill and Mountain Wind projects I and II, as well as an increase due to Guam reaching commercial operations in the third quarter of 2015.

NRG Yield gross margin and economic gross margin

NRG Yield gross margin increased $45 million and economic gross margin increased $62 million for the six months ended June 30, 2016, compared the same period in 2015, primarily related to higher wind generation during the period.

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 $218 million during the six months ended June 30, 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:



	Six months ended June 30, 2016
			Generation
	Retail Mass		Gulf Coast			East			West			Business Solutions			Renewables			Elimination^(a)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	—	$	(268	)	$	(209	)	$	(1	)	$	(1	)	$	—		$	75		$	(404	)
Reversal of acquired gain positions related to economic hedges	—		—			(24		)	—			—			—			—			(24		)
Net unrealized (losses)/gains on open positions related to economic hedges	—		(181		)	88			(10		)	(1		)	(1		)	20			(85		)
Total mark-to-market (losses)/gains in operating revenues	$	—	$	(449	)	$	(145	)	$	(11	)	$	(2	)	$	(1	)	$	95		$	(513	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	168	$	19		$	60		$	(1	)	$	96		$	—		$	(75	)	$	267
Reversal of acquired (gain)/loss positions related to economic hedges	—		—			—			(5		)	1			—			—			(4		)
Net unrealized gains/(losses) on open positions related to economic hedges	173		15			(52		)	(1		)	72			—			(20		)	187
Total mark-to-market gains/(losses) in operating costs and expenses	$	341	$	34		$	8		$	(7	)	$	169		$	—		$	(95	)	$	450


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



	Six months ended June 30, 2015
				Generation
	Retail Mass			Gulf Coast			East			West			Business Solutions			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	$	—		$	(275	)	$	(201	)	$	2		$	(1	)	$	(4	)	$	—	$	(85	)	$	(564	)
Reversal of acquired gain positions related to economic hedges	—			—			(43		)	—			—			—			—		—			(43		)
Net unrealized gains/(losses) on open positions related to economic hedges	—			288			105			(7		)	4			2			3		12			407
Total mark-to-market gains/(losses) in operating revenues	$	—		$	13		$	(139	)	$	(5	)	$	3		$	(2	)	$	3	$	(73	)	$	(200	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	215		$	21		$	10		$	(1	)	$	84		$	—		$	—	$	85		$	414
Reversal of acquired gain positions related to economic hedges	—			—			—			(7		)	—			—			—		—			(7		)
Net unrealized losses on open positions related to economic hedges	(205		)	(45		)	(93		)	—			(133		)	—			—		(12		)	(488		)
Total mark-to-market gains/(losses) in operating costs and expenses	$	10		$	(24	)	$	(83	)	$	(8	)	$	(49	)	$	—		$	—	$	73		$	(81	)


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

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

For the six months ended June 30, 2016, the $513 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, as well as a decrease in value of open positions as a result of increases in natural gas and ERCOT electricity prices, partially offset by increases in PJM electricity prices. The $450 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, and an increase in value of open positions as a result of increases in natural gas and ERCOT electricity prices.

For the six months ended June 30, 2015, the $200 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 and the reversal of acquired contracts, largely offset by an increase in value of open positions as a result of decreases in ERCOT and PJM electricity and natural gas prices. The $81 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 ERCOT electricity and coal prices and the reversal of acquired contracts, largely 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 six months ended June 30, 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.



	Six months ended June 30,
(In millions)	2016		2015
Trading gains/(losses)
Realized	$	47	$	50
Unrealized	32		(46		)
Total trading gains	$	79	$	4

In addition, trading activities reflect an increase in gross margin of $67 million, reflected in the Corporate segment, for the six months ended June 30, 2016, as compared to the six months ended June 30, 2015.

Operations and Maintenance Expense



	Generation								Retail Mass		Renewables		NRG Yield		Eliminations
	Gulf Coast		East		West		Business Solutions		Retail Mass		Renewables		NRG Yield		Eliminations			Total
	(In millions)
Six months ended June 30, 2016	$	286	$	529	$	68	$	11	$	110	$	82	$	90	$	(16	)	$	1,160
Six months ended June 30, 2015	358		565		78		14		113		63		87		(6		)	1,272

Operations and maintenance expense decreased by $112 million for the six months ended June 30, 2016, compared to the same period in 2015, due to the following:



	(In millions)
Decrease in Gulf Coast operations and maintenance expense primarily related to the timing of outages at the Limestone and STP facilities located in Texas	$	(73	)
Decrease in operating costs due to the sale of Seward and Shelby generating facilities	(36		)
Decrease in East variable operating costs driven by a 39% decrease in generation across the fleet	(20		)
Decrease in West operations and maintenance expense primarily related to the timing of outages	(11		)
Decrease in East operations and maintenance expense relating to timing of outages and maintenance work in the prior year, partially offset by an increase in maintenance expense at Joliet, New Castle, Shawville and Avon Lake in the current year	(9		)
Increase in East operating costs due to plant unit deactivations and increased estimates at Maryland Ash sites	20
Increase in Renew operations and maintenance expense primarily related to unplanned outages at Ivanpah	19
Other	(2		)
	$	(112	)

Other Cost of Operations



	Generation								Retail Mass		Renewables		NRG Yield		Eliminations
	Gulf Coast		East		West		Business Solutions		Retail Mass		Renewables		NRG Yield		Eliminations		Total
	(In millions)
Six months ended June 30, 2016	$	53	$	57	$	11	$	8	$	40	$	9	$	32	$	—	$	210
Six months ended June 30, 2015	51		67		11		9		47		11		34		—		230

Other cost of operations, comprised of asset retirement expense, insurance expense and property and other tax expense, decreased by $20 million for the six months ended June 30, 2016, compared to the same period in 2015, primarily due to a reduction in property tax for Chalk Point and Dickerson.

Depreciation and Amortization



	Generation								Retail Mass		Renewables		NRG Yield		Corporate
	Gulf Coast		East		West		Business Solutions		Retail Mass		Renewables		NRG Yield		Corporate		Total
	(In millions)
Six months ended June 30, 2016	$	150	$	105	$	30	$	5	$	55	$	111	$	133	$	33	$	622
Six months ended June 30, 2015	284		145		27		5		63		105		137		25		791

Depreciation and amortization expense decreased by $169 million for the six months ended June 30, 2016, compared to the same period in 2015, primarily due to decrease in depreciation expense for facilities impaired during 2015.

Impairment Losses

For the six months ended June 30, 2016, the Company recorded impairment losses of $115 million, primarily due to the impairment of the Rockford stations, Mandalay and Ormond Beach operating units, as further described in Note 7, Impairments, of this Form 10-Q.

Selling, Marketing, General and Administrative Expenses

Selling and marketing expenses are comprised of the following:



	Generation								Retail Mass		Renewables		NRG Yield		Corporate
	Gulf Coast		East		West		Business Solutions		Retail Mass		Renewables		NRG Yield		Corporate		Total
	(In millions)
Six months ended June 30, 2016	$	—	$	—	$	—	$	21	$	123	$	3	$	—	$	39	$	186
Six months ended June 30, 2015	1		—		—		22		123		3		—		79		228

Selling and marketing expense decreased by $42 million for the six months ended June 30, 2016, compared to the same period in 2015, due primarily to the continued focus on cost management.

General and administrative expenses are comprised of the following:



	Generation								Retail Mass		Renewables		NRG Yield		Corporate
	Gulf Coast		East		West		Business Solutions		Retail Mass		Renewables		NRG Yield		Corporate		Total
	(In millions)
Six months ended June 30, 2016	$	67	$	88	$	16	$	17	$	65	$	28	$	6	$	47	$	334
Six months ended June 30, 2015	77		96		21		16		72		20		6		15		323

General and administrative expenses increased by $11 million for the six months ended June 30, 2016, compared to the same period in 2015, due primarily to an increase in cost to achieve expenses in 2016, which primarily reflects severance and employee costs based on the Company's recent strategy changes, which were partially offset by a reduction in expenses due to continued focus on cost management.

Development Activity Expenses

Development activity expenses decreased by $27 million for the six months ended June 30, 2016, compared to the same period in 2015, due to the strategic move for a more focused development program primarily related to Renewables, NRG EVgo and other corporate initiatives.

Loss on Sale of Assets, net of gains

During the six months ended June 30, 2016, the Company sold a majority interest in its EVgo business to Vision Ridge Partners, as described in Note 3, Business Acquisitions and Dispositions, which resulted in a loss on sale of $83 million which includes $56 million for the accrual of NRG's remaining obligation to the CPUC. In addition the Company also sold 100% of its interest in Shelby to Rockland Power Partners II, LP, also described in Note 3, Business Acquisitions and Dispositions, which resulted in a gain on sale of $29 million.

Impairment Losses on Investments

For the six months ended June 30, 2016, the Company recorded other-than-temporary impairment losses of $139 million, which is primarily due to its 50% interest in Petra Nova Parish Holdings, as further described in Note 7, Impairments, of this Form 10-Q.

Loss on Debt Extinguishment

A loss on debt extinguishment of $69 million was recorded for the six months ended June 30, 2016, primarily driven by the repurchase of NRG Senior Notes at a price above par value, combined with the write-off of unamortized debt issuance costs.

Interest Expense

NRG's interest expense decreased by $3 million for the six months ended June 30, 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 two quarters of 2016	$	(35	)
Decrease due to the termination of Alta X and XI term loans and the related interest rate swaps in 2015	(6		)
Increase in derivative interest expense from changes in fair value of interest rate swaps	25
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	8
Other	5
	$	(3	)

Income Tax Expense/(Benefit)

For the six months ended June 30, 2016, NRG recorded an income tax expense of $46 million on a pre-tax loss of $183 million. For the same period in 2015, NRG recorded an income tax benefit of $90 million on a pre-tax loss of $235 million. The effective tax rate was (25.1)% and 38.3% for the six months ended June 30, 2016, and 2015, respectively.

For the six months ended June 30, 2016, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to tax expense resulting from the change in the valuation allowance, amortization of indefinite lived assets, inclusion of consolidated partnerships and the impact of state income taxes.

For the six months ended June 30, 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 tax expense attributable to consolidated partnerships.

Net loss attributable to noncontrolling interests and redeemable noncontrolling interests

For the six months ended June 30, 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 June 30, 2016, and December 31, 2015, NRG's liquidity, excluding collateral received, was approximately $3.1 billion and $3.3 billion, respectively, comprised of the following:



(In millions)	June 30, 2016		December 31, 2015
Cash and cash equivalents:
NRG excluding NRG Yield and GenOn	$	659	$	742
NRG Yield and subsidiaries	89		111
GenOn and subsidiaries	641		665
Restricted cash - operating	319		127
Restricted cash - reserves^(a)	94		287
Total	1,802		1,932
Total credit facility availability	1,329		1,373
Total liquidity, excluding collateral received	$	3,131	$	3,305

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

For the six months ended June 30, 2016, total liquidity, excluding collateral funds deposited by counterparties, decreased by $174 million. Changes in cash and cash equivalents balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents at June 30, 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 stockholders, and to fund other liquidity commitments with the exception of commitments related to GenOn as further described below. Management continues to regularly monitor the Company's ability to finance the needs of its operating, financing and investing activity within the dictates of prudent balance sheet management.

Restricted Payments Tests

Of the $1.4 billion of cash and cash equivalents of the Company as of June 30, 2016, $324 million and $149 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 June 30, 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 June 30, 2016, GenOn did not meet the consolidated debt ratio component of the restricted payments test.

GenOn Liquidity

As disclosed in Note 8, Debt and Capital Leases, $707 million of GenOn's senior unsecured notes outstanding are current within the GenOn consolidated balance sheet and are due on June 15, 2017. GenOn's future profitability continues to be adversely affected by (i) a sustained decline in natural gas prices and its resulting effect on wholesale power prices and capacity prices, and (ii) the inability of GenOn Mid-Atlantic and REMA to make distributions of cash and certain other restricted payments to GenOn. Based on current projections, GenOn is not expected to have sufficient liquidity to repay the senior unsecured notes due in June 2017. As a result of these factors, there is no assurance GenOn will continue as a going concern.

Credit Ratings

On May 24, 2016, S&P lowered its corporate credit ratings on GenOn to CCC from CCC+. The ratings outlook for GenOn, GenOn Americas Generation, GenOn Mid-Atlantic and REMA is negative. S&P also lowered the issue ratings on the GenOn senior notes to CCC+ from B-, the GenOn Americas Generation senior notes to CCC from CCC+, and the pass-through certificates at REMA to B- from B. S&P upgraded the rating on the pass-through certificates at GenOn Mid-Atlantic to B- from CCC+.

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.

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

The following table summarizes the Company's credit ratings as of June 30, 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
7.25% Senior Notes, due 2026	BB-	B1
Term Loan Facility, due 2023	BB+	Baa3
GenOn 7.875% Senior Notes, due 2017	CCC+	Caa2
GenOn 9.500% Senior Notes, due 2018	CCC+	Caa2
GenOn 9.875% Senior Notes, due 2020	CCC+	Caa2
GenOn Americas Generation 8.500% Senior Notes, due 2021	CCC+	Caa2
GenOn Americas Generation 9.125% Senior Notes, due 2031	CCC+	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, including sales to NRG Yield, Inc. As described in Note 8, Debt and Capital Leases, to this Form 10-Q and Note 12, Debt and Capital Leases, to the Company's 2015 Form 10-K, the Company's financing arrangements consist mainly of the 2016 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.

Sale of CVSR to NRG Yield, Inc. and CVSR Financing Arrangement

On August 8, 2016, the Company entered an agreement to sell the remaining 51.05% interest in the CVSR project to NRG Yield, Inc. for total expected consideration of $78.5 million plus assumed debt and working capital adjustments to be calculated at close. On July 15, 2016, CVSR Holdco LLC, the indirect owner of the CVSR project, issued $200 million of senior secured notes that bear interest at 4.68% and mature on March 31, 2037. The $199 million of net proceeds from the notes were distributed to a subsidiary of NRG and NRG Yield Operating LLC, the owners of CVSR Holdco LLC, based on their pro-rata ownership. NRG Yield Operating LLC utilized its net proceeds of $97.5 million to reduce the outstanding balance of its revolving credit facility. NRG expects to utilize its net proceeds in connection with the 2016 Capital Allocation Program.

Issuance of 2027 Senior Notes

Capistrano Refinancing

In July 2016, Cedro Hill, Broken Bow and Crofton Bluffs, subsidiaries of Capistrano Wind Partners, each amended their respective credit facilities to increase borrowings to a total of $312 million and to lower their respective interest rates. The net proceeds of $87 million were distributed to Capistrano Wind Partners and subsequently distributed to the holders of the Class B preferred equity interests of Capistrano Wind Partners.

EVgo

Issuance of 2026 Senior Notes

Residential Solar

In April 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

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 is 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 4.39%, over the term of the arrangement, through June 2019.

Asset Dispositions

During the six months ended June 30, 2016, the Company received proceeds of $118 million related to the sale of its Seward and Shelby generating stations. On July 12, 2016, the Company sold its Rockford generating stations for proceeds of $56 million and GenOn sold its Aurora generating station for proceeds of $369 million.

Cash Grants

As of June 30, 2016, the Company had a net renewable energy grant receivable of $36 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 June 30, 2016, all hedges under the first liens were in-the-money on a counterparty aggregate basis.

The following table summarizes the amount of MW hedged against the Company's coal and nuclear assets and as a percentage relative to the Company's coal and nuclear capacity under the first lien structure as of June 30, 2016:



Equivalent Net Sales Secured by First Lien Structure ^(a)	2016		2017		2018		2019		2020
In MW	2,217		2,353		497		—		—
As a percentage of total net coal and nuclear capacity ^(b)	38	%	41	%	9	%	—	%	—	%


(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.

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 June 30, 2016, commercial operations had total cash collateral outstanding of $218 million, and $802 million outstanding in letters of credit to third parties primarily to support its commercial activities for both wholesale and retail transactions. As of June 30, 2016, total collateral held from counterparties was $44 million in cash and $57 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 six months ended June 30, 2016, and the currently estimated capital expenditure and growth investments forecast for the remainder of 2016.



	Maintenance			Environmental		Growth Investments			Total
	(In millions)
Generation
Gulf Coast	$	71		$	5	$	2		$	78
East	85			184		77			346
West	1			—		13			14
Business Solutions	4			—		1			5
Retail Mass	7			—		—			7
Renewables	11			—		76			87
NRG Yield	9			—		2			11
Corporate^(b)	16			—		58			74
Total cash capital expenditures for the six months ended June 30, 2016	204			189		229			622
Funding from debt financing, net of fees	—			—		(13		)	(13		)
Funding from third party equity partners and cash grants	(5		)	—		(86		)	(91		)
Other investments ^(a)	—			—		47			47
Total capital expenditures and investments, net of financings	199			189		177			565

Estimated capital expenditures for the remainder of 2016	270			115		887			1,272
Funding from debt financing, net of fees	—			—		(528		)	(528		)
Funding from third party equity partners and cash grants	(9		)	—		(128		)	(137		)
Other investments ^(a)	—			—		28			28
NRG estimated capital expenditures for the remainder of 2016, net of financings	$	261		$	115	$	259		$	635


(a)	Other investments include restricted cash activity.


(b)	Includes residential solar.


•	Environmental capital expenditures — For the six months ended June 30, 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 six months ended June 30, 2016, the Company's growth investment capital expenditures included $109 million for solar projects, $77 million for fuel conversions, $15 million for repowering projects, $2 million for thermal projects and $26 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 $322 million which includes $61 million for GenOn and $247 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 the remainder of 2016 is as follows:

•

Debt Reduction. The Company expects to allocate a majority of NRG's capital available for allocation during 2016 to additional debt 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 primarily 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.

Debt Reduction

During the six months ended June 30, 2016, the Company repurchased $1.3 billion of its senior notes in open market transactions for $1.3 billion, which included $21 million in accrued interest, as further described in Note 8, Debt and Capital Leases, to this Form 10-Q. As further described in Note 8, Debt and Capital Leases, to this Form 10-Q, the Company expects to utilize the proceeds from the issuance of the 2027 Senior Notes to retire the Company's 8.250% senior notes due 2020 and reduce the balance of the Company's 7.875% senior notes due 2021.

Preferred Stock

On May 24, 2016, the Company entered an agreement with Credit Suisse Group to repurchase 100% of the outstanding shares of its $344.5 million 2.822% preferred stock. On June 13, 2016, the Company completed the repurchase from Credit Suisse of 100% of the outstanding shares at a price of $226 million. The Company anticipates the transaction to generate approximately $10 million in annual dividend savings.

Dividends

The following table lists the dividends paid during the six months ended June 30, 2016:



	Second Quarter 2016		First Quarter 2016
Dividends per Common Share	$	0.030	$	0.145

On July 13, 2016, NRG declared a quarterly dividend on the Company's common stock of $0.03 per share, payable August 15, 2016, to stockholders of record as of August 1, 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.

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	Q3 2016
Shawville Units 1, 2, 3 and 4	597	Growth	Natural Gas	Q4 2016
Total	1,923
Repowerings
Carlsbad Peakers (formerly Encina) Units 1, 2, 3, 4, 5 and GT^(c)	527	Growth	Natural Gas	Q2 2018
Puente (formerly Mandalay) Units 1 and 2^(c)	262	Growth	Natural Gas	Q2 2020
Bacliff (formerly Cielo Lindo/PH Robinson) Peakers 1-6	360	Growth	Natural Gas	Q3 2016
Total	1,149

Total Fuel Repowerings and Conversions	3,072

(a) Does not include the natural gas conversions of (i) Dunkirk Units 2, 3 and 4, which are on hold pending the outcome of outstanding litigation; and (ii) New Castle Units 3, 4 and 5, which were completed in the second quarter of 2016.

(b) The Company has incurred and will incur environmental capital expenditures to switch to gas to satisfy MATS. Joliet Units 6, 7 & 8 are in commercial service using natural gas; the balance of plant work is being completed for full load operation of Unit 6.

Cash Flow Discussion

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



	Six months ended June 30,
	2016			2015			Change
	(In millions)
Net cash provided by operating activities	$	873		$	458		$	415
Net cash used in investing activities	(469		)	(860		)	391
Net cash (used)/provided by financing activities	(530		)	429			(959		)

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	$	462
Increase in operating income adjusted for non-cash items	26
Decrease in inventory primarily related to plant fuel conversions at Shawville, Joliet, New Castle and Unit 2 at our Big Cajun II facility and retirements of Huntley and Dunkirk	25
Decrease in accrued interest primarily driven by redemption of Senior Notes in late 2015 and 2016	(39		)
Other changes in working capital driven by various timing differences	(25		)
Decrease in accounts payable primarily related to lower operations and maintenance expense in 2016	(21		)
Increase in prepaid expense primarily related to timing of property tax and insurance payments that occur in the first half of the year	(13		)
	$	415

Net Cash Used In Investing Activities

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



	(In millions)
Decrease in investments in unconsolidated affiliates in 2016 compared to 2015, primarily related to the 25% investment in Desert Sunlight of $285 million, as well as Petra Nova and Altenex in 2015	$	354
Proceeds from the sale of assets related to the sale of the Seward and Shelby generating facilities in 2016	136
Insurance proceeds primarily related to the Cottonwood generation station outage in 2016	27
Decrease in cash paid for acquisitions in 2016 compared to 2015, primarily related to the Spring Canyon acquisition in 2015	13
Decrease in cash grants received as the final Ivanpah cash grant amount was received in 2015 after resolution of all open inquiries	(51		)
Increase in capital expenditures, primarily related to environmental projects at Powerton and Joliet	(39		)
Decrease in restricted cash primarily related to the Agua Caliente and CVSR projects	(23		)
Net decrease in nuclear decomissioning trust fund activity	(17		)
Increase in notes receivable and other	(9		)
	$	391

Net Cash (Used)/Provided By Financing Activities

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



	(In millions)
Decrease in cash contributions from noncontrolling interest in 2016, primarily related to the NRG Yield, Inc public offering in 2015 which had proceeds of $600 million	$	(691	)
Net decrease in borrowings, offset by debt payments, which includes debt repurchases in 2016	(251		)
Repurchase of preferred stock in 2016	(226		)
Increase in debt issuance costs primarily due to the refinancing of the senior credit facility and the issuance of the 2026 Senior Notes	(23		)
Repurchases of treasury stock in 2015	186
Decrease in payment of dividends which reflects the reduction to the annualized dividend rate in 2016 from $0.58/share to $0.12/share	45
Other	1
	$	(959	)

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

For the six months ended June 30, 2016, the Company had a total domestic pre-tax book loss of $195 million and foreign pre-tax book income of $12 million. As of December 31, 2015, the Company has cumulative domestic Federal NOL carryforwards of $4.0 billion which will begin expiring in 2026 and cumulative state NOL carryforwards of $4.2 billion for financial statement purposes. In addition, NRG has cumulative foreign NOL carryforwards of $202 million, which do not have an expiration date.

In addition to these amounts, the Company has $40 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 $43 million until final resolution with the related taxing authority. The $43 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.

Obligations Arising Out of a Variable Interest in an Unconsolidated Entity

Variable interest in equity investments — As of June 30, 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 $633 million as of June 30, 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 six months ended June 30, 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 June 30, 2016, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at June 30, 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	(129		)
Changes in fair value	29
Fair Value of Contracts as of June 30, 2016	$	(94	)



	Fair Value of Contracts as of June 30, 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	$	116		$	(41	)	$	(9	)	$	—		$	66
Level 2	(20		)	(71		)	(38		)	(38		)	(167		)
Level 3	1			7			—			(1		)	7
Total	$	97		$	(105	)	$	(47	)	$	(39	)	$	(94	)

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 June 30, 2016, NRG's net derivative liability was $94 million, a decrease to total fair value of $100 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 $163 million in the net value of derivatives as of June 30, 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 $119 million in the net value of derivatives as of June 30, 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 and recovery of long-lived assets. Additionally, continued decreases in natural gas prices could result in an adverse change in the manner that long-lived assets are used, or result in the Company selling an asset before the end of its previously estimated useful life, at a price that is lower than its carrying amount. Accordingly, if these decreases continue, it is possible that the Company's goodwill or long-lived assets will be impaired.

ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

NRG is exposed to several market risks in the Company's normal business activities. Market risk is the potential loss that may result from market changes associated with the Company's merchant power generation or with an existing or forecasted financial or commodity transaction. The types of market risks the Company is exposed to are commodity price risk, interest rate risk, liquidity risk, credit risk and currency exchange risk. The following disclosures about market risk provide an update to, and should be read in conjunction with, Item 7A — Quantitative and Qualitative Disclosures About Market Risk, of the Company's 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 six months ending June 30, 2016, and 2015:



(In millions)	2016		2015
VaR as of June 30,	$	63	$	36
Three months ended June 30,
Average	$	62	$	39
Maximum	68		50
Minimum	55		34
Six months ended June 30,
Average	$	58	$	43
Maximum	68		54
Minimum	44		34

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 June 30, 2016, for the entire term of these instruments entered into for both asset management and trading was $57 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 June 30, 2016, the Company would have owed the counterparties $202 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 June 30, 2016, a 1% change in variable interest rates would result in a $12 million change in interest expense on a rolling twelve month basis.

100

As of June 30, 2016, the fair value and related carrying value of the Company's debt was $18.6 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 $1.3 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 $211 million as of June 30, 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 $271 million as of June 30, 2016. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of June 30, 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.

101

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 second quarter of 2016 that materially affected, or are reasonably likely to materially affect, NRG’s internal control over financial reporting.

102

PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

For a discussion of material legal proceedings in which NRG was involved through June 30, 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. Except as presented below, there have been no material changes in the Company's risk factors since those reported in its 2015 Form 10‑K.

There is no assurance GenOn will continue as a going concern. GenOn’s inability to continue as a going concern could have a material impact on the Company.

As disclosed in Note 8, Debt and Capital Leases, to this Form 10-Q, $707 million of GenOn's senior unsecured notes outstanding are current within the GenOn consolidated balance sheet and are due on June 15, 2017. GenOn's future profitability continues to be adversely affected by (i) a sustained decline in natural gas prices and its resulting effect on wholesale power prices and capacity prices, and (ii) the inability of GenOn Mid-Atlantic and REMA to make distributions of cash and certain other restricted payments to GenOn. Based on current projections, GenOn is not expected to have sufficient liquidity to repay the senior unsecured notes due in June 2017. As a result of these factors, there is no assurance GenOn will continue as a going concern.

As of June 30, 2016, GenOn has cash and cash equivalents of $641 million, of which $324 million and $149 million is held by GenOn Mid-Atlantic and REMA, respectively. Under their respective operating leases, GenOn Mid-Atlantic and REMA are not permitted to make any distributions and other restricted payments unless: (a) they satisfy the fixed charge coverage ratio for the most recently ended period for four fiscal quarters; (b) they are projected to satisfy the fixed charge coverage ratio for each of the two following periods of four fiscal quarters, commencing with the fiscal quarter in which such payment is proposed to be made; and (c) no significant lease default or event of default has occurred and is continuing. Additionally, 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 lease. As a result, GenOn Mid-Atlantic has not been able to make distributions of cash and certain other restricted payments since the quarter ended March 31, 2014 which was the last quarterly period for which GenOn Mid-Atlantic satisfied the conditions under its operating agreement. REMA has not satisfied the conditions under its operating agreement to make distributions of cash and certain other restricted payments since GenOn was acquired by NRG in December 2012.

The Company, GenOn's parent company, has no obligation to provide any financial support other than as described under the secured intercompany revolving credit agreement between the Company and GenOn and NRG Americas.

The Company cannot assure you that GenOn’s inability to continue as a going concern will not have a material impact on the Company's statement of operations, cash flows and financial position including, among other things, if GenOn were to file for bankruptcy protection.

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.

103

ITEM 6 — EXHIBITS



Number	Description	Method of Filing
4.1	Indenture, dated May 23, 2016, between NRG Energy, Inc. and Law Debenture Trust Company of New York.	Incorporated herein by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K, filed on May 23, 2016.
4.2	Supplemental Indenture, dated May 23, 2016, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York.	Incorporated herein by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K, filed on May 23, 2016.
4.3	Form of 7.250% Senior Note due 2026.	Incorporated herein by reference to Exhibit 4.3 to the Registrant's Current Report on Form 8-K, filed on May 23, 2016.
4.4	Registration Rights Agreement, dated May 23, 2016, among NRG Energy, Inc., the guarantors named therein and Deutsche Bank Securities Inc., as representative to the initial purchasers listed in Schedule I thereto.	Incorporated herein by reference to Exhibit 4.4 to the Registrant's Current Report on Form 8-K, filed on May 23, 2016.
4.5	One Hundred-Nineteenth Supplemental Indenture, dated as of July 19, 2016, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York.	Incorporated herein by reference to Exhibit 4.1 to the Registrant's Current Report on Form 8-K, filed on July 25, 2016.
4.6	Ninth Supplemental Indenture, dated as of July 19, 2016, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York.	Incorporated herein by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K, filed on July 25, 2016.
4.7	Second Supplemental Indenture, dated as of July 19, 2016, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York.	Incorporated herein by reference to Exhibit 4.3 to the Registrant's Current Report on Form 8-K, filed on July 25, 2016.
4.8	Third Supplemental Indenture, dated August 2, 2016, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York.	Incorporated herein by reference to Exhibit 4.2 to the Registrant's Current Report on Form 8-K, filed on August 3, 2016.
4.9	Form of 6.625% Senior Note due 2027.	Incorporated herein by reference to Exhibit 4.3 to the Registrant's Current Report on Form 8-K, filed on August 3, 2016.
4.10	Registration Rights Agreement, dated August 2, 2016, among NRG Energy, Inc., the guarantors named therein and Morgan Stanley & Co. LLC, as representative to the initial purchasers listed in Schedule I thereto.	Incorporated herein by reference to Exhibit 4.4 to the Registrant's Current Report on Form 8-K, filed on August 3, 2016.
10.1	Amendment and Restatement Agreement, dated as of June 30, 2016, to the Amended and Restated Credit Agreement, the Second Amended and Restated Collateral Trust Agreement and the Amended and Restated Guarantee and Collateral Agreement.	Filed herewith.
10.2	Second Amended and Restated Credit Agreement, dated as of June 30, 2016, by and among NRG Energy, Inc., the lenders party thereto, the joint lead arrangers and joint lead bookrunners party thereto, Citicorp North America, Inc., Commerzbank AG, New York Branch, Keybank Capital Markets Inc. and CIT Bank, N.A.	Filed herewith.
10.3	Amended and Restated 2009 Executive Change-in-Control and General Severance Plan.	Filed herewith.
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.

104

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: August 9, 2016	Chief Accounting Officer (Principal Accounting Officer)

105