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)

NRG 2015 06.30 10Q

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, 2015

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

Commission File Number: 001-15891

NRG Energy, Inc.

(Exact name of registrant as specified in its charter)



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

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

(609) 524-4500

(Registrant’s telephone number, including area code)

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

Yes x No o

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

Yes x No o

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

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

Yes o No x

As of July 31, 2015, there were 330,655,311 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	4
PART I — FINANCIAL INFORMATION	8
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES	8
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	58
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	92
ITEM 4 — CONTROLS AND PROCEDURES	94
PART II — OTHER INFORMATION	95
ITEM 1 — LEGAL PROCEEDINGS	95
ITEM 1A — RISK FACTORS	95
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	95
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES	95
ITEM 4 — MINE SAFETY DISCLOSURES	95
ITEM 5 — OTHER INFORMATION	95
ITEM 6 — EXHIBITS	96
SIGNATURES	97

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, 2014, 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 commodities markets;


•	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 compensate NRG's generation units for all of their costs;


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


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


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


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


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


•	NRG's ability to implement its strategy;


•	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 successfully integrate, realize cost savings and manage any acquired businesses; and


•	NRG's ability to develop and maintain successful partnership 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:



2014 Form 10-K		NRG’s Annual Report on Form 10-K for the year ended December 31, 2014
Alta Wind Assets		Seven wind facilities that total 947 MWs located in Tehachapi, California and a portfolio of land leases
ASC		The FASB Accounting Standards Codification, which the FASB established as the source of authoritative U.S. GAAP
ASU		Accounting Standards Updates, which reflect updates to the ASC
B2B		Business-to-business, which includes demand response, commodity sales, energy efficiency and energy management services
BACT		Best Available Control Technology
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
Capital Allocation Program		NRG's plan of allocating capital between debt reduction, reinvestment in the business, investment in acquisition opportunities, share repurchases and shareholder dividends
CCF		Carbon Capture Facility
CCPI		Clean Coal Power Initiative
CEC		California Energy Commission
CenterPoint		CenterPoint Energy, Inc. and its subsidiaries, on and after August 31, 2002, and Reliant Energy, Incorporated and its subsidiaries prior to August 31, 2002
CFTC		U.S. Commodity Futures Trading Commission
C&I		Commercial, Industrial and Governmental/Institutional
CO₂		Carbon Dioxide
COD		Commercial Operations Date
ComEd		Commonwealth Edison
CPS		Combined Pollutant Standard
CPUC		California Public Utilities Commission
CSAPR		Cross-State Air Pollution Rule
CWA		Clean Water Act
D.C. Circuit		U.S. Court of Appeals for the District of Columbia Circuit
DGPV Holding		NRG Yield DGPV Holding LLC
Discrete Customers		Customers measured by unit sales of one-time products or services, such as connected home thermostats, portable solar products and portable battery solutions
Distributed Solar		Solar power projects that primarily sell power produced to customers for usage on site, or are interconnected to sell power into the local distribution grid
Dominion		Dominion Resources, Inc.
DSI		Dry Sorbent Injection with Trona
EME		Edison Mission Energy
Energy Plus Holdings		Energy Plus Holdings LLC and Energy Plus Natural Gas LLC
EPA		U.S. Environmental Protection Agency
EPSA		Electric Power Supply Association
ERCOT		Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
ESP		Electrostatic Precipitator



ESPP		NRG Energy, Inc. Amended and Restated Employee Stock Purchase Plan
Exchange Act		The Securities Exchange Act of 1934, as amended
FASB		Financial Accounting Standards Board
FCM		Forward Capacity Market
FERC		Federal Energy Regulatory Commission
FPA		Federal Power Act
GEM		GenOn Energy Management, LLC
GenConn		GenConn Energy LLC
GenOn		GenOn Energy, Inc.
GenOn Americas Generation		GenOn Americas Generation, LLC
GenOn Americas Generation Senior Notes		GenOn Americas Generation's $850 million outstanding unsecured senior notes consisting of $450 million of 8.50% senior notes due 2021 and $400 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 the Dickerson and Morgantown generating facilities under operating leases
GenOn Senior Notes		GenOn's $2.0 billion outstanding unsecured senior notes consisting of $725 million of 7.875% senior notes due 2017, $675 million of 9.5% senior notes due 2018, and $550 million of 9.875% senior notes due 2020
GHG		Greenhouse Gases
GWh		Gigawatt Hour
HAPs		Hazardous Air Pollutants
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
IL CPS		Illinois Combined Pollutant Standard
IPPNY		Independent Power Producers of New York
ISO		Independent System Operator
JX Nippon		JX Nippon Oil Exploration (EOR) Limited
Kansas South		NRG Solar Kansas South LLC
kV		Kilovolts
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
LSEs		Load Serving Entities
LTIPs		Collectively, the NRG Long-Term Incentive Plan and the NRG GenOn Long-Term Incentive Plan
Mass		Residential and Small Business
MATS		Mercury and Air Toxics Standards promulgated by the EPA
MDE		Maryland Department of the Environment
Midwest Generation		Midwest Generation, LLC
MISO		Midcontinent Independent System Operator, Inc.
MMBtu		Million British Thermal Units
MW		Megawatt
MWh		Saleable megawatt hours, net of internal/parasitic load megawatt-hours
MWt		Megawatts Thermal Equivalent
NAAQS		National Ambient Air Quality Standards



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 kWh or MWhs, that is the total amount of electricity generated (gross) minus the amount of electricity used during generation
NOL		Net Operating Loss
NO_x		Nitrogen Oxide
NPNS		Normal Purchase Normal Sale
NRC		U.S. Nuclear Regulatory Commission
NRG Marsh Landing		NRG Marsh Landing, LLC (formerly known as GenOn Marsh Landing, LLC)
NRG Yield		Reporting segment that includes the projects held by NRG Yield, Inc.
NRG Yield, Inc.		NRG Yield, Inc., the owner of 53.3% of NRG Yield LLC with a controlling interest, and issuer of publicly held shares of Class A common stock
NSPS		New Source Performance Standards
NSR		New Source Review
Nuclear Decommissioning Trust Fund		NRG's nuclear decommissioning trust fund assets, which are for the Company's portion of the decommissioning of the STP, units 1 & 2
NYAG		State of New York Office of Attorney General
NYISO		New York Independent System Operator
NYPA		New York Power 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
Plan		The plan of reorganization that was approved in conjunction with Mirant Corporation's emergence from bankruptcy protection on January 3, 2006
PM		Particulate Matter
POJO		Powerton and Joliet, of which the Company leases 100% interests in Unit 7 and Unit 8 of the Joliet generating facility and the Powerton generating facility, through Midwest Generation
PPA		Power Purchase Agreement
PPTA		Power Purchase Tolling Agreement
PSD		Prevention of Significant Deterioration
PUCT		Public Utility Commission of Texas
RCRA		Resource Conservation and Recovery Act of 1976
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
REMA		NRG REMA LLC, which leases a 100% interest in the Shawville generating facility and 16.7% and 16.5% interests in the Keystone and Conemaugh generating facilities, respectively
Repowering		Technologies utilized to replace, rebuild, or redevelop major portions of an existing electrical generating facility, generally to achieve a substantial emissions reduction, increase facility capacity, and improve system efficiency
Revolving Credit Facility		The Company's $2.5 billion revolving credit facility due 2018, a component of the Senior Credit Facility
RFP		Request For Proposal
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
RPM		Reliability Pricing Model
RPV Holding		NRG Yield RPV Holding LLC
RSSA		Reliability Support Services Agreement
RTO		Regional Transmission Organization
Sabine		Sabine Cogen, L.P.
SCE		Southern California Edison
SCR		Selective Catalytic Reduction Control System
SDG&E		San Diego Gas & Electric
SEC		U.S. Securities and Exchange Commission
Senior Credit Facility		NRG's senior secured facility, comprised of the Term Loan Facility and the Revolving Credit Facility
Senior Notes		The Company’s $6.4 billion outstanding unsecured senior notes, consisting of $1.1 billion of 7.625% senior notes due 2018, $1.1 billion of 8.25% senior notes due 2020, $1.1 billion of 7.875% senior notes due 2021, $1.1 billion of 6.25% senior notes due 2022, $990 million of 6.625% senior notes due 2023, and $1.0 billion of 6.25% senior notes due 2024
SF6		Sulfur Hexafluoride
SO₂		Sulfur Dioxide
STP		South Texas Project — nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest
SunPower		SunPower Corporation, Systems
Taloga		Taloga Wind, LLC, the operating subsidiary of Tapestry Wind LLC, which owns the Taloga project
TCPA		Telephone Consumer Protection Act
Term Loan Facility		The Company's $2.0 billion term loan facility due 2018, a component of the Senior Credit Facility
U.S.		United States of America
U.S. DOE		U.S. Department of Energy
U.S. GAAP		Accounting principles generally accepted in the U.S.
Utility Scale Solar		Solar power projects, typically 20 MW or greater in size (on an alternating current basis), that are interconnected into the transmission or distribution grid to sell power at a wholesale level
VaR		Value at Risk
VIE		Variable Interest Entity
Walnut Creek		NRG Walnut Creek, LLC, the operating subsidiary of WCEP Holdings, LLC, which owns the Walnut Creek project
Yield Operating		NRG Yield Operating LLC

PART I — FINANCIAL INFORMATION

ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three months ended June 30,						Six months ended June 30,
(In millions, except for per share amounts)	2015			2014			2015			2014
Operating Revenues
Total operating revenues	$	3,397		$	3,621		$	7,223		$	7,107
Operating Costs and Expenses
Cost of operations	2,434			2,828			5,496			5,565
Depreciation and amortization	396			386			791			721
Selling, general and administrative	291			257			554			479
Acquisition-related transaction and integration costs	3			40			13			52
Development activity expenses	41			21			75			40
Total operating costs and expenses	3,165			3,532			6,929			6,857
Gain on postretirement benefits curtailment and sale of assets	—			—			14			19
Operating Income	232			89			308			269
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	8			14			5			21
Other income, net	4			5			23			16
Loss on debt extinguishment	(7		)	(40		)	(7		)	(81		)
Interest expense	(263		)	(274		)	(564		)	(529		)
Total other expense	(258		)	(295		)	(543		)	(573		)
Loss Before Income Taxes	(26		)	(206		)	(235		)	(304		)
Income tax benefit	(17		)	(126		)	(90		)	(157		)
Net Loss	(9		)	(80		)	(145		)	(147		)
Less: Net income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interests	5			17			(11		)	6
Net Loss Attributable to NRG Energy, Inc.	(14		)	(97		)	(134		)	(153		)
Dividends for preferred shares	5			3			10			5
Loss Available for Common Stockholders	$	(19	)	$	(100	)	$	(144	)	$	(158	)
Loss per Share Attributable to NRG Energy, Inc. Common Stockholders
Weighted average number of common shares outstanding — basic and diluted	333			337			335			331
Loss per Weighted Average Common Share — Basic and Diluted	$	(0.06	)	$	(0.30	)	$	(0.43	)	$	(0.48	)
Dividends Per Common Share	$	0.14		$	0.14		$	0.29		$	0.26

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,
	2015			2014			2015			2014
	(In millions)
Net Loss	$	(9	)	$	(80	)	$	(145	)	$	(147	)
Other Comprehensive Income/(Loss), net of tax
Unrealized gain/(loss) on derivatives, net of income tax expense/(benefit) of $12, $(3), $6 and $(6)	16			(19		)	4			(28		)
Foreign currency translation adjustments, net of income tax expense/(benefit) of $6, $2, $(1) and $4	9			(3		)	(2		)	3
Available-for-sale securities, net of income tax benefit of $(3), $(6), $(7) and $(4)	(3		)	7			(4		)	13
Defined benefit plans, net of tax expense/(benefit) of $0, $(7), $4 and $(7)	(1		)	10			6			12
Other comprehensive income/(loss)	21			(5		)	4			—
Comprehensive Income/(loss)	12			(85		)	(141		)	(147		)
Less: Comprehensive income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interests	12			12			(17		)	(3		)
Comprehensive Loss Attributable to NRG Energy, Inc.	—			(97		)	(124		)	(144		)
Dividends for preferred shares	5			3			10			5
Comprehensive Loss Available for Common Stockholders	$	(5	)	$	(100	)	$	(134	)	$	(149	)

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS



	June 30, 2015			December 31, 2014
(In millions, except shares)	(unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	2,146		$	2,116
Funds deposited by counterparties	33			72
Restricted cash	433			457
Accounts receivable — trade, less allowance for doubtful accounts of $19 and $23	1,413			1,322
Inventory	1,153			1,247
Derivative instruments	1,805			2,425
Cash collateral paid in support of energy risk management activities	299			187
Deferred income taxes	193			174
Renewable energy grant receivable, net	19			135
Prepayments and other current assets	516			447
Total current assets	8,010			8,582
Property, plant and equipment, net of accumulated depreciation of $8,611 and $7,890	22,304			22,367
Other Assets
Equity investments in affiliates	1,077			771
Notes receivable, less current portion	65			72
Goodwill	2,555			2,574
Intangible assets, net of accumulated amortization of $1,506 and $1,402	2,428			2,567
Nuclear decommissioning trust fund	576			585
Derivative instruments	491			480
Deferred income taxes	1,454			1,406
Other non-current assets	1,405			1,261
Total other assets	10,051			9,716
Total Assets	$	40,365		$	40,665
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	636		$	474
Accounts payable	1,080			1,060
Derivative instruments	1,638			2,054
Cash collateral received in support of energy risk management activities	33			72
Accrued expenses and other current liabilities	1,082			1,199
Total current liabilities	4,469			4,859
Other Liabilities
Long-term debt and capital leases	19,661			19,900
Nuclear decommissioning reserve	318			310
Nuclear decommissioning trust liability	311			333
Deferred income taxes	18			21
Derivative instruments	522			438
Out-of-market contracts, net of accumulated amortization of $613 and $562	1,193			1,244
Other non-current liabilities	1,527			1,574
Total non-current liabilities	23,550			23,820
Total Liabilities	28,019			28,679
2.822% convertible perpetual preferred stock	296			291
Redeemable noncontrolling interest in subsidiaries	33			19
Commitments and Contingencies
Stockholders’ Equity
Common stock	4			4
Additional paid-in capital	8,365			8,327
Retained earnings	3,346			3,588
Less treasury stock, at cost — 86,245,318 and 78,843,552 shares, respectively	(2,166		)	(1,983		)
Accumulated other comprehensive loss	(170		)	(174		)
Noncontrolling interest	2,638			1,914
Total Stockholders’ Equity	12,017			11,676
Total Liabilities and Stockholders’ Equity	$	40,365		$	40,665

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,
	2015			2014
	(In millions)
Cash Flows from Operating Activities
Net loss	$	(145	)	$	(147	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates	40			39
Depreciation and amortization	791			721
Provision for bad debts	29			30
Amortization of nuclear fuel	23			20
Amortization of financing costs and debt discount/premiums	(7		)	(9		)
Adjustment for debt extinguishment	7			21
Amortization of intangibles and out-of-market contracts	32			22
Amortization of unearned equity compensation	24			24
Changes in deferred income taxes and liability for uncertain tax benefits	(98		)	(514		)
Changes in nuclear decommissioning trust liability	(4		)	6
Changes in derivative instruments	186			535
Changes in collateral deposits supporting energy risk management activities	(112		)	(297		)
Loss on sale of emission allowances	(6		)	2
Gain on postretirement benefits curtailment and sale of assets	(14		)	(19		)
Cash used by changes in other working capital	(288		)	(64		)
Net Cash Provided by Operating Activities	458			370
Cash Flows from Investing Activities
Acquisitions of businesses, net of cash acquired	(30		)	(1,817		)
Capital expenditures	(583		)	(507		)
Increase in restricted cash, net	(3		)	(6		)
Decrease in restricted cash to support equity requirements for U.S. DOE funded projects	27			21
Decrease in notes receivable	7			2
Investments in nuclear decommissioning trust fund securities	(354		)	(340		)
Proceeds from the sale of nuclear decommissioning trust fund securities	358			334
Proceeds from renewable energy grants and state rebates	61			429
Proceeds from sale of assets, net of cash disposed of	1			77
Cash proceeds to fund cash grant bridge loan payment	—			57
Investments in unconsolidated affiliates	(353		)	(22		)
Other	9			19
Net Cash Used by Investing Activities	(860		)	(1,753		)
Cash Flows from Financing Activities
Payment of dividends to common and preferred stockholders	(102		)	(91		)
Payment for treasury stock	(186		)	—
Net receipts from/(payments for) settlement of acquired derivatives that include financing elements	91			(167		)
Proceeds from issuance of long-term debt	629			3,886
Distributions from, net of contributions to, noncontrolling interest in subsidiaries	670			10
Proceeds from issuance of common stock	1			8
Payment of debt issuance costs	(12		)	(43		)
Payments for short and long-term debt	(662		)	(2,969		)
Net Cash Provided by Financing Activities	429			634
Effect of exchange rate changes on cash and cash equivalents	3			(24		)
Net Increase/ (Decrease) in Cash and Cash Equivalents	30			(773		)
Cash and Cash Equivalents at Beginning of Period	2,116			2,254
Cash and Cash Equivalents at End of Period	$	2,146		$	1,481

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 — Basis of Presentation

NRG Energy, Inc., or NRG or the Company, is a competitive power company, which produces, sells and delivers energy and energy products and services in major competitive power markets primarily in the U.S. while positioning itself as a leader in the way residential, industrial and commercial consumers think about and use energy products and services. NRG is responding to a consumer-driven change to the U.S. energy industry by offering cleaner, smarter and ultimately more portable energy while enabling personal energy choice, building on the strength of one of the nation’s largest and most diverse competitive power generation portfolios. The Company owns and operates approximately 50,000 MWs of generation; engages in the trading of wholesale energy, capacity and related products; transacts in and trades fuel and transportation services; and directly sells energy, services, and innovative, sustainable products and services to retail customers under the name “NRG” and various other retail brand names owned by NRG.

On June 29, 2015, NRG Yield, Inc. closed on its offering of 28,198,000 shares of Class C common stock at a price of $22 per share, which included 3,678,000 shares of Class C common stock purchased by the underwriters through an over-allotment option. Net proceeds to NRG Yield, Inc. from the sale of the Class C common stock were $600 million, net of underwriting discounts and commissions of $20 million. The additional equity offering reduced the Company's economic interest in NRG Yield, Inc. to 46.7% and its voting interest to 55.1%. The Company continues to consolidate NRG Yield, Inc. through its controlling interest.

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 2014 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, 2015, and the results of operations, comprehensive income/(loss) and cash flows for the three and six months ended June 30, 2015, and 2014.

Use of Estimates

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

Reclassifications

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

Note 2 — Summary of Significant Accounting Policies

Other Cash Flow Information

NRG’s investing activities exclude capital expenditures of $33 million which were accrued and unpaid at June 30, 2015.

Noncontrolling Interest

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



	(In millions)
Balance as of December 31, 2014	$	1,914
Sale of assets to NRG Yield, Inc.	(27		)
Distributions to noncontrolling interest	(83		)
Contributions from noncontrolling interest	140
Increase to noncontrolling interest due to NRG Yield, Inc. acquisitions	74
Proceeds received from NRG Yield, Inc. public offering	600
Non-cash adjustments for equity component of NRG Yield, Inc. convertible notes	23
Non-cash increase to noncontrolling interest	14
Comprehensive loss attributable to noncontrolling interest	(17		)
Balance as of June 30, 2015	$	2,638

NRG RPV Holdco 1 LLC

On April 9, 2015, NRG and NRG Yield, Inc. entered into a partnership, through their ownership of NRG RPV Holdco 1 LLC, or RPV Holdco, that will invest in and hold operating portfolios of residential solar assets developed by NRG Home Solar, including: (i) an existing, unlevered portfolio of over 2,200 leases across nine states representing approximately 17 MW with a weighted average remaining lease term of approximately 17 years, in which NRG Yield, Inc. invested $26 million in April 2015; and (ii) in-development, tax equity financed portfolios of approximately 13,000 leases representing approximately 90 MW with an average lease term for the existing and new leases of approximately 17 to 20 years. NRG Yield, Inc. has committed to invest up to an additional $150 million of cash contributions into the partnership over time, excluding the $26 million noted above. As of June 30, 2015, NRG Yield, Inc. has contributed $14 million of the $150 million committed contributions. The following illustrates the structure of RPV Holdco:

Alta Wind X-XI TE Holdco, LLC

On June 30, 2015, NRG Yield Operating LLC, a subsidiary of NRG Yield, Inc., sold an economic interest in Alta Wind X-XI TE Holdco LLC, or Alta TE Holdco, holder of the Alta Wind X and Alta Wind XI projects, to a financial institution in order to monetize cash and tax attributes, primarily production tax credits. The net proceeds of $119 million are reflected as noncontrolling interest in the Company's balance sheet.

NRG Yield, Inc. Issuance of Class C Common Stock and Convertible Notes

On June 29, 2015, NRG Yield, Inc. issued 28,198,000 shares of Class C common stock for net proceeds of $600 million, as described in Note 1, Basis of Presentation, and issued $287.5 million in aggregate principal amount of 3.25% Convertible Senior Notes, due 2020, as described in Note 7, Debt and Capital Leases. The value of the conversion option of $23 million is reflected in the NRG Yield, Inc. noncontrolling interest balance.

Redeemable Noncontrolling Interest in Subsidiaries

Redeemable noncontrolling interest in subsidiaries represents third-party interests in the net assets under certain arrangements that the Company has entered into to finance the cost of certain projects, including solar energy systems under operating leases and wind facilities eligible for certain tax credits. To the extent that the third party has the right to redeem their interests for cash or other assets, the Company has included the noncontrolling interest attributable to the third party as a component of temporary equity in the mezzanine section of the consolidated balance sheet. The following table reflects the changes in the Company's redeemable noncontrolling interest balance for the six months ended June 30, 2015:



	(In millions)
Balance as of December 31, 2014	$	19
Non-cash contributions from noncontrolling interest	9
Cash contributions from noncontrolling interest	6
Comprehensive loss attributable to noncontrolling interest	(1		)
Balance as of June 30, 2015	$	33

Gain on Postretirement Benefits Curtailment

During the first quarter of 2015, the Company recognized a gain of $14 million related to the curtailment of certain of the Company's postretirement plans.

Recent Accounting Developments

ASU 2015-03 — In April 2015, the FASB issued ASU No. 2015-03, Interest - Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs, or ASU No. 2015-03. The amendments of ASU No. 2015-03 were issued to reduce complexity in the balance sheet presentation of debt issuance costs. ASU No. 2015-03 requires that debt issuance costs be presented in the balance sheet as a direct deduction from the carrying amount of debt liability, consistent with debt discounts or premiums. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this standard. The guidance in ASU No. 2015-03 is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for financial statements that have not been previously issued. The adoption of this standard is not expected to have a material impact on the Company's balance sheets on a gross basis and will have no impact on net assets.

ASU 2015-02 — In February 2015, the FASB issued ASU No. 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis, or ASU No. 2015-02. The amendments of ASU No. 2015-02 were issued in an effort to minimize situations under previously existing guidance in which a reporting entity was required to consolidate another legal entity in which that reporting entity did not have: (1) the ability through contractual rights to act primarily on its own behalf; (2) ownership of the majority of the legal entity's voting rights; or (3) the exposure to a majority of the legal entity's economic benefits. ASU No. 2015-02 affects reporting entities that are required to evaluate whether they should consolidate certain legal entities. All legal entities are subject to reevaluation under the revised consolidation model. The guidance in ASU No. 2015-02 is effective for periods beginning after December 15, 2015. Early adoption is permitted. The Company adopted the standard effective January 1, 2015 and the adoption of this standard did not impact the Company's results of operations, cash flows or financial position.

ASU 2014-16 — In November 2014, the FASB issued ASU No. 2014-16, Derivatives and Hedging (Topic 815): Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity, or ASU No. 2014-16. The amendments of ASU No. 2014-16 clarify how U.S. GAAP should be applied in determining whether the nature of a host contract is more akin to debt or equity and in evaluating whether the economic characteristics and risks of an embedded feature are "clearly and closely related" to its host contract. The guidance in ASU No. 2014-16 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. The Company adopted the standard effective January 1, 2015 and the adoption of this standard did not impact the Company's results of operations, cash flows or 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 International Accounting Standards Board, or IASB, to develop a common revenue standard for U.S. GAAP and International Financial Reporting Standards, or 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. On July 9, 2015, the FASB voted to defer 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. The Company is currently evaluating the impact of the standard on the Company's results of operations, cash flows and financial position.

Note 3 — Business Acquisitions and Dispositions

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

2015 Acquisitions and Dispositions

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 MWs 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.

Sale of Assets to NRG Yield, Inc.

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. The sale was recorded as a transfer of entities under common control and the related assets were transferred at carrying value of $405 million.

2014 Acquisitions and Dispositions

Sale of Sabine

On December 2, 2014, the Company, through its subsidiaries GenOn Sabine (Delaware), Inc. and GenOn Sabine (Texas), Inc., completed the sale of its 50% interest in Sabine to Bayou Power, LLC, an affiliate of Rockland Capital, LLC. Sabine owns a 105 MW natural gas-fired cogeneration facility located in Texas. The Company received cash consideration of $35 million at closing. A gain of $18 million was recognized as a result of the transaction and recorded as a gain on sale of equity-method investments within the Company's consolidated statements of operations.

Acquisition of Alta Wind

On August 12, 2014, NRG Yield, Inc., through its subsidiary Yield Operating, completed the acquisition of 100% of the membership interests of Alta Wind Asset Management Holdings, LLC, Alta Wind Company, LLC, Alta Wind X Holding Company, LLC, and Alta Wind XI Holding Company, LLC, which collectively own seven wind facilities that total 947 MWs located in Tehachapi, California and a portfolio of land leases, or the Alta Wind Assets. Power generated by the Alta Wind facilities is sold to Southern California Edison under long-term power purchase agreements, with 21 years of remaining contract life for Alta I-V. The Alta X and XI power purchase agreements begin in 2016 with a term of 22 years and currently sell energy and renewable energy credits on a merchant basis.

The purchase price of the Alta Wind Assets was $923 million, which was comprised of a purchase price of $870 million and $53 million paid for working capital balances. In order to fund the purchase price of the acquisition, NRG Yield, Inc. issued 12,075,000 shares of its Class A common stock on July 29, 2014, for net proceeds of $630 million. In addition, on August 5, 2014, Yield Operating issued $500 million in aggregate principal amount at par of 5.375% senior notes due August 2024. Interest on the notes is payable semi-annually on February 15 and August 15 of each year, and commenced on February 15, 2015. The notes are senior unsecured obligations of Yield Operating and are guaranteed by NRG Yield LLC, Yield Operating’s parent company, and by certain of Yield Operating’s wholly owned subsidiaries.

The acquisition was recorded as a business combination under ASC 805, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date. The initial accounting for the business combination is not complete because the evaluation necessary to assess the fair values of certain net assets acquired is still in process. The provisional amounts are subject to revision until the evaluations are completed to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. The allocation of the purchase price may be modified up to one year from the date of the acquisition as more information is obtained about the fair value of assets acquired and liabilities assumed. The following table summarizes the provisional amounts recognized for assets acquired and liabilities assumed as of December 31, 2014, as well as adjustments made through June 30, 2015. The purchase price of $923 million was provisionally allocated as follows:



	Acquisition Date Fair Value at December 31, 2014		Measurement period adjustments			Revised Acquisition Date
	(In millions)
Assets
Cash	$	22	$	—		$	22
Current and non-current assets	49		(2		)	47
Property, plant and equipment	1,304		6			1,310
Intangible assets	1,177		(6		)	1,171
Total assets acquired	2,552		(2		)	2,550

Liabilities
Debt	1,591		—			1,591
Current and non-current liabilities	38		(2		)	36
Total liabilities assumed	1,629		(2		)	1,627
Net assets acquired	$	923	$	—		$	923

Disposition of 50% Interest in Petra Nova Parish Holdings LLC

On July 3, 2014, the Company, through its wholly owned subsidiary Petra Nova Holdings LLC, sold 50% of its interest in Petra Nova Parish Holdings LLC to JX Nippon, a wholly owned subsidiary of JX Nippon Oil & Gas Exploration Corporation. As a result of the sale, the Company no longer has a controlling interest in and has deconsolidated Petra Nova Parish Holdings LLC as of the date of the sale. On July 7, 2014, the Company made its initial capital contribution into the partnership of $35 million, which was funded with a portion of the sale proceeds of $76 million. On March 3, 2014, Petra Nova CCS I LLC, a wholly owned subsidiary of Petra Nova Parish Holdings LLC, entered into a fixed-price agreement to build and operate a CCF at the W.A. Parish facility with a consortium of Mitsubishi Heavy Industries America, Inc. and TIC - The Industrial Company. Notice to proceed for the construction on the CCF was issued on July 15, 2014, and commercial operation is expected in late 2016.

Petra Nova Parish Holdings LLC also owns a 75 MW peaking unit at W.A. Parish, which achieved commercial operations on June 26, 2013. The peaking unit will be converted into a cogeneration facility to provide power and steam to the CCF. The project is being financed by: (i) up to $167 million from a U.S. DOE CCPI grant, (ii) $250 million in loans provided by the Japan Bank for International Cooperation and Mizuho Bank, Ltd., and (iii) approximately $300 million in equity contributions from each of the Company and JX Nippon. NRG’s contribution will include investments already made during the development of the project.

Sale of Assets to NRG Yield, Inc.

On June 30, 2014, the Company sold the following facilities to NRG Yield, Inc.: High Desert, Kansas South, and El Segundo Energy Center. NRG Yield, Inc. paid total cash consideration of $357 million, which represents a base purchase price of $349 million and $8 million of working capital adjustments, plus assumed project level debt of approximately $612 million. The sale was recorded as a transfer of entities under common control and the related assets were transferred at their carrying value of $236 million.

Acquisition of Dominion's Competitive Electric Retail Business

On March 31, 2014, the Company acquired the competitive retail electricity business of Dominion. The acquisition of Dominion's competitive retail electricity business increased NRG’s retail portfolio by approximately 540,000 customers in the aggregate by the end of 2014. The acquisition supports NRG's ongoing efforts to expand the Company's retail footprint in the Northeast and to grow its retail position in Texas. The Company paid approximately $192 million as cash consideration for the acquisition, including $165 million of purchase price and $27 million paid for working capital balances, which was funded by cash on hand. The purchase price was allocated to the following: $40 million to accounts receivable-trade, $64 million to customer relationships, $9 million to trade names, $14 million to current assets, $21 million to derivative assets, $47 million to current and non-current liabilities, and goodwill of $91 million of which $8 million is deductible for U.S. income tax purposes in future periods. The factors that resulted in goodwill arising from the acquisition include the revenues associated with new customers in new regions and through the synergies associated with combining a new retail business with the Company's existing retail and generation assets. The assets acquired and liabilities assumed are included within the NRG Home Retail segment. The accounting for the Dominion acquisition was completed as of March 30, 2015, at which point the provisional fair values became final with no material changes.

EME Acquisition

On April 1, 2014, the Company acquired substantially all of the assets of EME. EME, through its subsidiaries and affiliates, owned or leased and operated a portfolio of approximately 8,000 MW consisting of wind energy facilities and coal- and gas-fired generating facilities. The Company paid an aggregate purchase price of $3.5 billion, which was funded through the issuance of 12,671,977 shares of NRG common stock on April 1, 2014, the issuance of $700 million in newly-issued corporate debt and cash on hand. The Company also assumed non-recourse debt of approximately $1.2 billion.

In connection with the transaction, NRG agreed to certain conditions with the parties to the POJO sale-leaseback transaction subject to which an NRG subsidiary assumed the POJO leveraged leases and NRG guaranteed the remaining payments under each lease, which total $405 million through 2034. In connection with this agreement, NRG has committed to fund up to $350 million in capital expenditures for plant modifications at Powerton and Joliet to comply with environmental regulations, as discussed further in Note 15, Environmental Matters.

The acquisition was recorded as a business combination under ASC 805, with identifiable assets acquired and liabilities assumed provisionally recorded at their estimated fair values on the acquisition date. The accounting for the EME acquisition was completed as of March 31, 2015, at which point the fair values became final. The following table summarizes the provisional amounts recognized for assets acquired and liabilities assumed as of December 31, 2014, as well as adjustments made through March 31, 2015, when the allocation became final. Measurement period adjustments primarily reflect the tax impact of the acquisition date fair values and final estimates for asset retirement obligations.

The purchase price of $3.5 billion was allocated as follows:



	Acquisition Date Fair Value at December 31, 2014		Measurement period adjustments			Revised Acquisition Date
	(In millions)
Assets
Cash	$	1,422	$	—		$	1,422
Current assets	724		72			796
Property, plant and equipment	2,438		(3		)	2,435
Intangible assets	172		—			172
Goodwill	334		(56		)	278
Non-current assets	773		—			773
Total assets acquired	5,863		13			5,876

Liabilities
Current and non-current liabilities	629		13			642
Out-of-market contracts and leases	159		—			159
Long-term debt	1,249		—			1,249
Total liabilities assumed	2,037		13			2,050
Less: noncontrolling interest	352		—			352
Net assets acquired	$	3,474	$	—		$	3,474

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 2014 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, 2015				As of December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Assets:
Notes receivable^(a)	$	85	$	85	$	91	$	91
Liabilities:
Long-term debt, including current portion	$	20,292	$	20,380	$	20,366	$	20,361

(a) Includes the current portion of notes receivable which is recorded in prepayments and other current assets 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, 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	$	—	$	—	$	18	$	18
Available-for-sale securities	19		—		—		19
Other ^(a)	21		—		—		21
Nuclear trust fund investments:
Cash and cash equivalents	4		—		—		4
U.S. government and federal agency obligations	47		3		—		50
Federal agency mortgage-backed securities	—		62		—		62
Commercial mortgage-backed securities	—		29		—		29
Corporate debt securities	—		85		—		85
Equity securities	289		—		55		344
Foreign government fixed income securities	—		2		—		2
Other trust fund investments:
U.S. government and federal agency obligations	1		—		—		1
Derivative assets:
Commodity contracts	650		1,336		306		2,292
Interest rate contracts	—		4		—		4
Total assets	$	1,031	$	1,521	$	379	$	2,931
Derivative liabilities:
Commodity contracts	$	595	$	1,181	$	257	$	2,033
Interest rate contracts	—		127		—		127
Total liabilities	$	595	$	1,308	$	257	$	2,160

(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, 2014
	Fair Value
(In millions)	Level 1		Level 2		Level 3		Total
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities	$	—	$	—	$	18	$	18
Available-for-sale securities	30		—		—		30
Other ^(a)	21		—		11		32
Nuclear trust fund investments:
Cash and cash equivalents	14		—		—		14
U.S. government and federal agency obligations	44		3		—		47
Federal agency mortgage-backed securities	—		74		—		74
Commercial mortgage-backed securities	—		25		—		25
Corporate debt securities	—		78		—		78
Equity securities	292		—		52		344
Foreign government fixed income securities	—		3		—		3
Other trust fund investments:
U.S. government and federal agency obligations	1		—		—		1
Derivative assets:
Commodity contracts	1,078		1,515		309		2,902
Interest rate contracts	—		2		—		2
Equity contracts	—		—		1		1
Total assets	$	1,480	$	1,700	$	391	$	3,571
Derivative liabilities:
Commodity contracts	$	1,004	$	1,093	$	230	$	2,327
Interest rate contracts	—		165		—		165
Total liabilities	$	1,004	$	1,258	$	230	$	2,492

(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, 2015, and 2014 between Levels 1 and 2. The following tables reconcile, for the three and six months ended June 30, 2015, and 2014, 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, 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 OCI	—		—			—		—			—			—		—			—		—			—
Included in nuclear decommissioning obligation	—		—			—		—			—			—		—			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 in/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, 2014												Six months ended June 30, 2014
(In millions)	Debt Securities		Other		Trust Fund Investments		Derivatives^(a)			Total			Debt Securities		Other		Trust Fund Investments		Derivatives^(a)			Total
Beginning balance	$	18	$	11	$	56	$	23		$	108		$	16	$	10	$	56	$	13		$	95
Total gains/(losses) — realized/unrealized:
Included in earnings	—		—		—		(12		)	(12		)	—		1		—		4			5
Included in OCI	—		—		—		—			—			2		—		—		—			2
Included in nuclear decommissioning obligations	—		—		1		—			1			—		—		1		—			1
Purchases	—		—		1		(63		)	(62		)	—		—		1		(84		)	(83		)
Contracts acquired in Dominion and EME acquisition	—		—		—		36			36			—		—		—		39			39
Transfers into Level 3 ^(b)	—		—		—		—			—			—		—		—		18			18
Transfers out of Level 3 ^(b)	—		—		—		4			4			—		—		—		(2		)	(2		)
Ending balance as of June 30, 2014	$	18	$	11	$	58	$	(12	)	$	75		$	18	$	11	$	58	$	(12	)	$	75
Gains 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, 2014	$	—	$	—	$	—	$	2		$	2		$	—	$	—	$	—	$	21		$	21


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


(b)	Transfers in/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, 2015, contracts valued with prices provided by models and other valuation techniques make up 13% of the total derivative assets and 12% 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, 2015 and December 31, 2014:



	Significant Unobservable Inputs
	June 30, 2015
	Fair Value						Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average
	(In millions)
Power Contracts	$	207	$	182	Discounted Cash Flow	Forward Market Price (per MWh)	$	7		$	86	$	37
Coal Contracts	2		11		Discounted Cash Flow	Forward Market Price (per ton)	46			60		47
FTRs	97		64		Discounted Cash Flow	Auction Prices (per MWh)	(45		)	34		—
	$	306	$	257



	Significant Unobservable Inputs
	December 31, 2014
	Fair Value						Input/Range
	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low			High		Weighted Average
	(In millions)
Power Contracts	$	195	$	154	Discounted Cash Flow	Forward Market Price (per MWh)	$	15		$	92	$	47
Coal Contracts	3		1		Discounted Cash Flow	Forward Market Price (per ton)	53			56		54
FTRs	111		75		Discounted Cash Flow	Auction Prices (per MWh)	(29		)	30		—
	$	309	$	230

The following table provides sensitivity of fair value measurements to increases/(decreases) in significant unobservable inputs as of June 30, 2015 and December 31, 2014:



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, 2015, the credit reserve resulted in a $3 million increase in fair value, which is composed of a $1 million gain in OCI and a $2 million gain in operating revenue and cost of operations. As of June 30, 2014, the credit reserve resulted in a $1 million increase in fair value, which is a gain in OCI.

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 2014 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 2014 Form 10-K. As of June 30, 2015, counterparty credit exposure, excluding credit risk exposure under certain long term agreements, was $948 million and NRG held collateral (cash and letters of credit) against those positions of $50 million, resulting in a net exposure of $866 million. Approximately 95% of the Company's exposure before collateral is expected to roll off by the end of 2016. 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	44	%
Utilities, energy merchants, marketers and other	31
ISOs	25
Total as of June 30, 2015	100	%



	Net Exposure ^(a)
Category	(% of Total)
Investment grade	98	%
Non-rated ^(b)	1
Non-investment grade	1
Total as of June 30, 2015	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 $270 million as of June 30, 2015. 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, 2015, aggregate credit risk exposure managed by NRG to these counterparties was approximately $3.8 billion, including $2.4 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, 2015, 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 2014 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, 2015							As of December 31, 2014
(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	$	4	$	—	$	—	—	$	14	$	—	$	—	—
U.S. government and federal agency obligations	50		2		—		9	47		2		—		11
Federal agency mortgage-backed securities	62		1		—		24	74		2		—		25
Commercial mortgage-backed securities	29		—		1		29	25		—		1		30
Corporate debt securities	85		1		1		9	78		2		1		11
Equity securities	344		209		—		—	344		211		—		—
Foreign government fixed income securities	2		—		—		14	3		1		—		16
Total	$	576	$	213	$	2		$	585	$	218	$	2

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,
	2015		2014
	(In millions)
Realized gains	$	9	$	7
Realized losses	5		3
Proceeds from sale of securities	358		334

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 2014 Form 10-K.

Energy-Related Commodities

As of June 30, 2015, NRG had energy-related derivative instruments extending through 2024. The Company voluntarily de-designated all remaining commodity cash flow hedges as of January 1, 2014, and prospectively marked these derivatives to market through the income statement.

Interest Rate Swaps

NRG is exposed to changes in interest rates through the Company's issuance of variable and fixed rate debt. In order to manage the Company's interest rate risk, NRG enters into interest rate swap agreements. As of June 30, 2015, the Company had interest rate derivative instruments on non-recourse debt extending through 2032, most of which are designated as cash flow hedges.

Volumetric Underlying Derivative Transactions

The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by category, excluding those derivatives that qualified for the NPNS exception, as of June 30, 2015, and December 31, 2014. 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, 2015			December 31, 2014
Category	Units	(In millions)
Emissions	Short Ton	4			2
Coal	Short Ton	40			57
Natural Gas	MMBtu	(13		)	(58		)
Oil	Barrel	—			1
Power	MWh	(65		)	(56		)
Capacity	MW/Day	(1		)	—
Interest	Dollars	$	2,452		$	3,440
Equity	Shares	2			2

The decrease in the interest rate position was primarily the result of settling the Alta X and Alta XI interest rate swaps in connection with the repayment of the project-level debt, as described in Note 7, 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, 2015		December 31, 2014		June 30, 2015		December 31, 2014
	(In millions)
Derivatives designated as cash flow hedges:
Interest rate contracts current	$	—	$	—	$	48	$	55
Interest rate contracts long-term	4		2		63		74
Total derivatives designated as cash flow hedges	4		2		111		129
Derivatives not designated as cash flow hedges:
Interest rate contracts current	—		—		7		8
Interest rate contracts long-term	—		—		9		28
Commodity contracts current	1,805		2,425		1,583		1,991
Commodity contracts long-term	487		477		450		336
Equity contracts long-term	—		1		—		—
Total derivatives not designated as cash flow hedges	2,292		2,903		2,049		2,363
Total derivatives	$	2,296	$	2,905	$	2,160	$	2,492

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, 2015	(In millions)
Commodity contracts:
Derivative assets	$	2,292		$	(1,778	)	$	(33	)	$	481
Derivative liabilities	(2,033		)	1,778			53			(202		)
Total commodity contracts	259			—			20			279
Interest rate contracts:
Derivative assets	4			(3		)	—			1
Derivative liabilities	(127		)	3			—			(124		)
Total interest rate contracts	(123		)	—			—			(123		)
Total derivative instruments	$	136		$	—		$	20		$	156



	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, 2014	(In millions)
Commodity contracts:
Derivative assets	$	2,902		$	(2,155	)	$	(72	)	$	675
Derivative liabilities	(2,327		)	2,155			27			(145		)
Total commodity contracts	575			—			(45		)	530
Interest rate contracts:
Derivative assets	2			(2		)	—			—
Derivative liabilities	(165		)	2			—			(163		)
Total interest rate contracts	(163		)	—			—			(163		)
Equity contracts:
Derivative assets	1			—			—			1
Total derivative instruments	$	413		$	—		$	(45	)	$	368

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, 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	)
Losses expected to be realized from OCI during the next 12 months, net of $8 tax	$	(1	)	$	(13	)	$	(14	)	$	(1	)	$	(13	)	$	(14	)



	Three months ended June 30, 2014									Six months ended June 30, 2014
	Energy Commodities			Interest Rate			Total			Energy Commodities			Interest Rate			Total
	(In millions)
Accumulated OCI beginning balance	$	(1	)	$	(31	)	$	(32	)	$	(1	)	$	(22	)	$	(23	)
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	—			(7		)	(7		)	—			(8		)	(8		)
Mark-to-market of cash flow hedge accounting contracts	—			(12		)	(12		)	—			(20		)	(20		)
Accumulated OCI ending balance, net of $29 tax	$	(1	)	$	(50	)	$	(51	)	$	(1	)	$	(50	)	$	(51	)

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, 2015, and 2014.

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,
	2015			2014			2015			2014
Unrealized mark-to-market results	(In millions)
Reversal of previously recognized unrealized gains on settled positions related to economic hedges	$	(36	)	$	(5	)	$	(150	)	$	(2	)
Reversal of acquired gain positions related to economic hedges	(24		)	(84		)	(50		)	(162		)
Net unrealized gains/(losses) on open positions related to economic hedges	57			(30		)	(81		)	(223		)
Total unrealized mark-to-market losses for economic hedging activities	(3		)	(119		)	(281		)	(387		)
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity	(15		)	5			(36		)	5
Reversal of acquired gain positions related to trading activity	(5		)	(19		)	(12		)	(20		)
Net unrealized (losses)/gains on open positions related to trading activity	(4		)	14			2			30
Total unrealized mark-to-market (losses)/gains for trading activity	(24		)	—			(46		)	15
Total unrealized losses	$	(27	)	$	(119	)	$	(327	)	$	(372	)



	Three months ended June 30,						Six months ended June 30,
	2015			2014			2015			2014
	(In millions)
Unrealized losses included in operating revenues	$	(137	)	$	(48	)	$	(246	)	$	(364	)
Unrealized gains/(losses) included in cost of operations	110			(71		)	(81		)	(8		)
Total impact to statement of operations — energy commodities	$	(27	)	$	(119	)	$	(327	)	$	(372	)
Total impact to statement of operations — interest rate contracts	$	35		$	(3	)	$	21		$	(7	)

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, 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.

For the six months ended June 30, 2014, the $223 million unrealized loss from open economic hedge positions was primarily the result of a decrease in value of forward purchases due to decreases in ERCOT heat rates combined with a decrease in value of forward sales of natural gas and electricity due to increases in East power and natural gas prices.

Credit Risk Related Contingent Features

Certain of the Company's hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed “adequate assurance” under the agreements, or requires the Company to post additional collateral if there were a one notch downgrade in the Company's credit rating. The collateral required for contracts with adequate assurance clauses that are in a net liability position as of June 30, 2015, was $153 million. The collateral required for contracts with credit rating contingent features as of June 30, 2015, was $41 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 $20 million as of June 30, 2015.

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

Note 7 — 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 2014 Form 10-K. Long-term debt and capital leases consisted of the following:



(In millions, except rates)	June 30, 2015		December 31, 2014		June 30, 2015 interest rate % ^(a)

Recourse debt:
Senior notes, due 2018	$	1,130	$	1,130	7.625
Senior notes, due 2020	1,063		1,063		8.250
Senior notes, due 2021	1,128		1,128		7.875
Senior notes, due 2022	1,100		1,100		6.250
Senior notes, due 2023	990		990		6.625
Senior notes, due 2024	1,000		1,000		6.250
Term loan facility, due 2018	1,973		1,983		L+2.00
Tax-exempt bonds	434		406		4.125 - 6.00
Subtotal NRG recourse debt	8,818		8,800
Non-recourse debt:
GenOn senior notes	2,109		2,133		7.875 - 9.875
GenOn Americas Generation senior notes	924		929		8.500 - 9.125
GenOn Other	58		60		various
Subtotal GenOn debt (non-recourse to NRG)	3,091		3,122
NRG Yield Operating LLC Senior Notes, due 2024	500		500		5.375
NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility, due 2019	267		—		L+2.50
NRG Yield, Inc. Convertible Senior Notes, due 2019	328		326		3.500
NRG Yield, Inc. Convertible Senior Notes, due 2020	264		—		3.250
NRG West Holdings LLC, due 2023 (El Segundo Energy Center)	489		506		L+1.625 - L+2.25
NRG Marsh Landing, due 2017 and 2023	454		464		L+1.75 - L+1.875
Alta Wind I - V lease financing arrangements, due 2034 and 2035	1,016		1,036		5.696-7.015
Alta Wind X, due 2021	—		300		L+2.00
Alta Wind XI, due 2021	—		191		L+2.00
Walnut Creek, term loans due 2023	381		391		L+1.625
Tapestry Wind LLC, due 2021	185		192		L+1.625
Laredo Ridge Wind LLC, due 2026	106		108		L+1.875
NRG Solar Alpine LLC, due 2022	161		163		L+1.750
NRG Energy Center Minneapolis LLC, due 2017 and 2025	112		121		5.95 - 7.25
NRG Yield - other	480		489		various
Subtotal NRG Yield debt (non-recourse to NRG)	4,743		4,787
Ivanpah Financing, due 2033 and 2038	1,176		1,187		2.285 - 4.256
Agua Caliente Solar LLC, due 2037	904		898		2.395 - 3.633
CVSR High Plains Ranch II LLC, due 2037	802		815		2.339 - 3.775
Viento Funding II, Inc., due 2023	193		196		L+2.75
NRG Peaker Finance Co. LLC, bonds due 2019	102		100		L+1.07
Cedro Hill Wind LLC, due 2025	106		111		L+3.125
NRG - other	357		350		various
Subtotal other NRG non-recourse debt	3,640		3,657
Subtotal all non-recourse debt	11,474		11,566
Subtotal long-term debt (including current maturities)	20,292		20,366
Capital leases:
Chalk Point capital lease, due 2015	2		5		8.190
Other	3		3		various
Subtotal long-term debt and capital leases (including current maturities)	20,297		20,374
Less current maturities	636		474
Total long-term debt and capital leases	$	19,661	$	19,900

(a) As of June 30, 2015, L+ equals 3 month LIBOR plus x%, with the exception of the Viento Funding II term loan and Kansas South which is 6 month LIBOR plus x% and the NRG Marsh Landing term loan, Walnut Creek term loan, and NRG Yield Operating LLC Revolving Credit facility which are 1 month LIBOR plus x%.

NRG Recourse Debt

Senior Notes

Issuance of 2022 Senior Notes

On January 27, 2014, NRG issued $1.1 billion in aggregate principal amount at par of 6.25% senior notes due 2022. The notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest is payable semi-annually beginning on July 15, 2014, until the maturity date of July 15, 2022. The proceeds were utilized to redeem the 8.5% and 7.625% 2019 Senior Notes, as discussed below, and to fund the acquisition of EME.

Issuance of 2024 Senior Notes

On April 21, 2014, NRG issued $1.0 billion in aggregate principal amount at par of 6.25% senior notes due 2024. The notes are senior unsecured obligations of NRG and are guaranteed by certain of its subsidiaries. Interest is payable semi-annually beginning on November 1, 2014, until the maturity date of November 1, 2024. A portion of the cash proceeds were used to redeem all remaining of its 7.625% 2019 Senior Notes, as discussed below, and the rest of the proceeds were used to redeem all remaining $225 million of its 8.5% 2019 Senior Notes in September 2014.

Redemptions of 8.5% and 7.625% 2019 Senior Notes

On February 10, 2014, the Company redeemed $308 million of its 8.5% 2019 Senior Notes and $91 million of its 7.625% 2019 Senior Notes through a tender offer, at an average early redemption percentage of 106.992% and 105.500%, respectively. A $33 million loss on debt extinguishment of the 8.5% and 7.625% 2019 Senior Notes was recorded during the three months ended March 31, 2014, primarily consisting of the premiums paid on the redemption and the write-off of previously deferred financing costs.

On April 21, 2014, the Company redeemed $74 million of its 8.5% 2019 Senior Notes and $337 million of its 7.625% 2019 Senior Notes through a tender offer and call, at an average early redemption percentage of 105.250% and 104.200%, respectively. A $22 million loss on debt extinguishment of the 8.5% and 7.625% 2019 Senior Notes was recorded during the three months ended June 30, 2014, primarily consisting of the premiums paid on the redemption and the write-off of previously deferred financing costs.

On May 21, 2014, the Company redeemed for cash all of its remaining 7.625% 2019 Senior Notes at an average early redemption percentage of 103.813%. An $18 million loss on debt extinguishment of the 7.625% 2019 Senior Notes was recorded during the three months ended June 30, 2014, primarily consisting of the premiums paid on the redemption and the write-off of previously deferred financing costs.

NRG Non-Recourse Debt

The Company has non-recourse debt that is secured by acquired or developed projects that are held in several of its subsidiaries. In the event of a bankruptcy, receivership, liquidation or similar event involving a subsidiary, the assets of such subsidiary would be used to satisfy claims of creditors of the subsidiary, including liabilities under the non-recourse debt associated with such subsidiaries, rather than the creditors of NRG. As described in Note 3, Business Acquisitions and Dispositions, through the Company's acquisitions of EME on April 1, 2014 and Alta Wind on August 12, 2014, the Company acquired approximately $1.2 billion and $1.6 billion, respectively, of non-recourse debt.

Alta Wind X and Alta Wind XI due 2021

On June 30, 2015, the Company entered into a tax equity financing arrangement through which Yield Operating, a subsidiary of NRG Yield, Inc., received $119 million in net proceeds, as described in Note 2, Summary of Significant Accounting Policies. These proceeds, as well as proceeds obtained from the June 29, 2015, NRG Yield, Inc. common stock issuance and the 2020 Convertible Notes issuance, were utilized to repay all of the outstanding project indebtedness associated with Alta Wind X and Alta Wind XI facilities. The Company also settled interest rate swaps associated with the project level debt for Alta Wind X and Alta Wind XI and incurred a fee of $17 million.

NRG Yield, Inc. Convertible Notes

On June 29, 2015, NRG Yield, Inc. closed on its offering of $287.5 million aggregate principal amount of 3.25% Convertible Senior Notes due 2020, or the 2020 Convertible Notes. The 2020 Convertible Notes are convertible, under certain circumstances, into NRG Yield, Inc. Class C common stock, cash or a combination thereof at an initial conversion price of $27.50 per Class C common share, which is equivalent to an initial conversion rate of approximately 36.3636 shares of Class C common stock per $1,000 principal amount of notes. Interest on the 2020 Convertible Notes is payable semi-annually in arrears on June 1 and December 1 of each year, commencing on December 1, 2015. The 2020 Convertible Notes mature on June 1, 2020, unless earlier repurchased or converted in accordance with their terms. Prior to the close of business on the business day immediately preceding December 1, 2019, the 2020 Convertible Notes will be convertible only upon the occurrence of certain events and during certain periods, and thereafter, at any time until the close of business on the second scheduled trading day immediately preceding the maturity date. The 2020 Convertible Notes are accounted for in accordance with ASC 470-20. Under ASC 470-20, issuers of convertible debt instruments that may be settled in cash upon conversion, including partial cash settlement, are required to separately account for the liability (debt) and equity (conversion option) components. The equity component, the $23 million conversion option value, was recorded to NRG's noncontrolling interest for NRG Yield, Inc. with the offset to debt discount. The debt discount will be amortized to interest expense over the term of the notes.

During the first quarter of 2014, NRG Yield, Inc. closed on its offering of $345 million aggregate principal amount of 3.50% Convertible Senior Notes due 2019, or the 2019 Convertible Notes. The 2019 Convertible Notes were convertible, under certain circumstances, into NRG Yield, Inc. Class A common stock, cash or a combination thereof at an initial conversion rate of approximately 21.4822 shares of Class A common stock per $1,000 principal amount of 2019 Convertible Notes. Effective May 15, 2015, the conversion rate was adjusted to 42.9644 shares of Class A common stock per $1,000 principal amount of 2019 Convertible Notes in accordance with the terms of the related indenture. Interest on the 2019 Convertible Notes is payable semi-annually in arrears on February 1 and August 1 of each year, commencing on August 1, 2014. The 2019 Convertible Notes mature on February 1, 2019, unless earlier repurchased or converted in accordance with their terms. Prior to the close of business on the business day immediately preceding August 1, 2018, the 2019 Convertible Notes will be convertible only upon the occurrence of certain events and during certain periods, and thereafter, at any time until the close of business on the second scheduled trading day immediately preceding the maturity date. The notes are accounted for in accordance with ASC 470-20. The equity component, the $23 million conversion option value, was recorded to NRG's noncontrolling interest for NRG Yield, Inc. with the offset to debt discount. The debt discount will be amortized to interest expense over the term of the notes.

NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility

On June 26, 2015, the Company amended the revolving credit facility to, among other things, increase the availability from $450 million to $495 million. As of June 30, 2015, $267 million of borrowing and $32 million of letters of credit were outstanding. In July 2015, the Company repaid $190 million utilizing proceeds from the issuance of the 2020 Convertible Notes and Class C common stock.

NRG West Holdings LLC

On May 29, 2015, NRG West Holdings LLC amended its financing agreement to increase borrowings under the Tranche A facility by $5 million and to reduce the related interest rate to LIBOR plus an applicable margin of 1.625% from May 29, 2015 to August 31, 2017, LIBOR plus an applicable margin of 1.75% from September 1, 2017, to August 31, 2020, and LIBOR plus 1.875% from September 1, 2020 through the maturity date; to reduce Tranche B loan interest rate to LIBOR plus an applicable margin of 2.25% from May 29, 2015, to August 31, 2017, LIBOR plus 2.375% from September 1, 2017, to August 31, 2020, and LIBOR plus an applicable margin of 2.50% from September 1, 2020 through the maturity date and to reduce the working capital facility by $9 million. The proceeds of the increased borrowing were used to pay costs associated with the refinancing. Further, the amendment resulted in a $7 million loss on debt extinguishment.

Peakers

On February 21, 2014, NRG Peaker Finance Company LLC elected to redeem approximately $30 million 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 $35 million in connection with the removal of Bayou Cove Peaking Power LLC from the Peaker financing collateral package, which also involved limited commitments for certain repairs on other assets that were funded concurrently with the December 10, 2013, debt service payment. On March 3, 2014, Bayou Cove Peaking Power LLC sold Bayou Cove Unit 1, which the Company continues to manage and operate.

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. As a result, the balance under the project financing arrangement is classified as current and the lender can request repayment at any time. The facility is secured by the assets of High Lonesome Mesa and is non-recourse to NRG.

Note 8 — 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 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 $113 million as of June 30, 2015.

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 $80 million as of June 30, 2015.

Entities that are Consolidated

Capistrano Wind Partners — Through the acquisition of EME, the Company has a controlling financial interest in Capistrano Wind Partners, whose Class B preferred equity interests are held by outside investors. Capistrano Wind Partners holds 100% ownership in five projects generating 411 MW of wind capacity. The five wind projects include Cedro Hill located in Texas, Mountain Wind Power I located in Wyoming, Mountain Wind Power II located in Wyoming, Crofton Bluffs located in Nebraska, and Broken Bow I located in Nebraska.

Under the terms of the Capistrano Wind Partners formation documents, the holders of the Class B preferred equity interests receive 100% of the cash available for distribution, up to a scheduled amount to target a certain return and thereafter cash distributions are shared. The Company retains indirect beneficial ownership of the wind projects and retains responsibilities for managing the operations of Capistrano Wind Partners. Accordingly, the Company consolidates these projects. The Company does not consolidate Capistrano Wind Partners for tax purposes.

The summarized financial information for Capistrano Wind Holdings, the parent company of Capistrano Wind Partners, consisted of the following:



(In millions)	June 30, 2015
Current assets	$	25
Net property, plant and equipment	570
Other long-term assets	127
Total assets	722
Current liabilities	35
Long-term debt	177
Other long-term liabilities	150
Total liabilities	362
Noncontrolling interests	339
Net assets less noncontrolling interests	$	21

Note 9 — Changes in Capital Structure

As of June 30, 2015, and December 31, 2014, 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, 2014	415,506,176	(78,843,552	)	336,662,624
Shares issued under LTIPs	1,235,939	—		1,235,939
Shares issued under ESPP	—	124,625		124,625
Shares repurchased under Capital Allocation Program	—	(7,526,391	)	(7,526,391	)
Balance as of June 30, 2015	416,742,115	(86,245,318	)	330,496,797

Employee Stock Purchase Plan

As of June 30, 2015, there were 1,435,427 shares of treasury stock available for issuance under the ESPP. In July 2015, 158,514 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, 2015:



	Second Quarter 2015		First Quarter 2015
Dividends per Common Share	$	0.145	$	0.145

On July 15, 2015, NRG declared a quarterly dividend on the Company's common stock of $0.145 per share, payable August 17, 2015, to stockholders of record as of August 3, 2015, representing $0.58 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.

2015 Capital Allocation Program

In December 2014, the Company was authorized to repurchase $100 million of its common stock under the 2015 Capital Allocation Program. In March 2015, the Company was authorized to repurchase an additional $100 million of its common stock under the 2015 Capital Allocation Program. In addition, in the second quarter of 2015, the Company's board of directors authorized the repurchase of an additional $81 million of the Company's common stock, for a total authorized share repurchase of $281 million.

The following table reflects the repurchases made under the 2015 Capital Allocation Program:



	Total number of shares purchased	Average price paid per share ^(a)		Amounts paid for shares purchased (in millions) ^(a)
2015 Capital Allocation Program
December 2014	1,624,360	$	26.95	$	44

January 2015	1,755,976	25.19		44
February 2015	468,854	25.46		12
March 2015	921,654	24.92		23
Total Repurchases - First Quarter 2015	3,146,484			79

April 2015	1,328,329	24.47		32
May 2015	307,754	25.34		8
June 2015	2,743,824	24.48		$	67
Total Repurchases - Second Quarter 2015	4,379,907			$	107
Total Repurchases under 2015 Capital Allocation Program	9,150,751			$	230

(a) The average price paid per share and amounts paid for shares purchased excludes the commissions of $0.015 per share paid in connection with the share repurchase.

Note 10 — 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)	2015			2014			2015			2014
Basic and diluted loss per share attributable to NRG Energy, Inc. common stockholders
Net loss attributable to NRG Energy, Inc.	$	(14	)	$	(97	)	$	(134	)	$	(153	)
Dividends for preferred shares	5			3			10			5
Loss available for common stockholders	$	(19	)	$	(100	)	$	(144	)	$	(158	)
Weighted average number of common shares outstanding - basic and diluted	333			337			335			331
Loss per weighted average common share — basic and diluted	$	(0.06	)	$	(0.30	)	$	(0.43	)	$	(0.48	)

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)	2015	2014	2015	2014
Equity compensation plans	7	8	7	8
Embedded derivative of 2.822% redeemable perpetual preferred stock^(a)	16	16	16	16
Total	23	24	23	24

(a) As of June 30, 2014, the redeemable perpetual preferred stock had an interest rate of 3.625%.

Note 11 — Segment Reporting

Effective in December 2014, the Company's segment structure and its allocation of corporate expenses were updated to reflect how management currently makes financial decisions and allocates resources. The Company has recast data from prior periods to reflect this change in reportable segments to conform to the current year presentation. The Company's businesses are segregated as follows: NRG Business, which includes conventional power generation and the carbon capture business; NRG Home, which includes NRG Home Retail, consisting of Mass market retail products and services, and NRG Home Solar, which includes the installation and leasing of residential solar systems and the sale of solar energy services; NRG Renew, which includes solar and wind assets, excluding those in the NRG Yield segment; NRG Yield; and corporate activities. NRG Yield includes certain of the Company's contracted generation assets. On January 2, 2015, NRG Yield, Inc. acquired three projects from the Company: Walnut Creek formerly in the NRG Business segment, the Tapestry projects (Buffalo Bear, Pinnacle and Taloga) and Laredo Ridge, both formerly in the NRG Renew segment. As the transaction was accounted for as a transfer of entities under common control, all historical periods have been recast to reflect this change. The Company's corporate segment includes international business and electric vehicle services. Intersegment sales are accounted for at market.

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) and net income/(loss) attributable to NRG Energy, Inc.



				NRG Home
(In millions)	NRG Business^(a)			Retail^(a)		Solar^(a)			NRG Renew^(a)			NRG Yield^(a)(b)		Corporate^(a)			Eliminations			Total
Three months ended June 30, 2015	(in millions)
Operating revenues^(a)	$	2,105		$	1,298	$	10		$	145		$	217	$	1		$	(379	)	$	3,397
Depreciation and amortization	229			33		4			63			59		8			—			396
Equity in earnings/(loss) of unconsolidated affiliates	4			—		—			(2		)	9		1			(4		)	8
(Loss)/Income before income taxes	(1		)	212		(54		)	(21		)	45		(201		)	(6		)	(26		)
Net (Loss)/Income	(1		)	212		(54		)	(18		)	41		(183		)	(6		)	(9		)
Net (Loss)/Income attributable to NRG Energy, Inc.	$	(1	)	$	212	$	(53	)	$	(32	)	$	24	$	(171	)	$	7		$	(14	)
Total assets as of June 30, 2015	$	29,067		$	6,675	$	219		$	7,053		$	7,208	$	32,631		$	(42,488	)	$	40,365



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	295	$	4	$	—	$	23	$	9	$	48	$	—	$	379



(b) Includes loss on debt extinguishment of:	$	—	$	—	$	—	$	—	$	7	$	—	$	—	$	7



			NRG Home
(In millions)	NRG Business^(c)		Retail^(c)			Solar^(c)			NRG Renew^(c)			NRG Yield^(c)		Corporate^(c)(d)			Eliminations			Total
Three months ended June 30, 2014	(in millions)
Operating revenues^(c)	$	2,533	$	1,405		$	23		$	153		$	173	$	20		$	(686	)	$	3,621
Depreciation and amortization	239		31			1			51			54		10			—			386
Equity in earnings/(loss) of unconsolidated affiliates	11		—			—			(3		)	14		1			(9		)	14
Income/(loss) before income taxes	100		(50		)	(7		)	2			44		(285		)	(10		)	(206		)
Net Income/(Loss)	99		(50		)	(7		)	2			42		(156		)	(10		)	(80		)
Net income/(loss) attributable to NRG Energy, Inc.	$	99	$	(50	)	$	(7	)	$	(18	)	$	36	$	(161	)	$	4		$	(97	)



(c) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	712	$	2	$	—	$	15	$	—	$	(43	)	$	—	$	686



(d) Includes loss on debt extinguishment of:	$	—	$	—	$	—	$	—	$	—	$	40	$	—	$	40



			NRG Home
(In millions)	NRG Business^(e)		Retail^(e)		Solar^(e)			NRG Renew^(e)			NRG Yield^(e)(f)		Corporate^(e)			Eliminations			Total
Six months ended June 30, 2015	(in millions)
Operating revenues^(e)	$	4,611	$	2,609	$	15		$	255		$	397	$	(6	)	$	(658	)	$	7,223
Depreciation and amortization	462		63		10			128			113		15			—			791
Equity in (loss)/earnings of unconsolidated affiliates	—		—		—			(2		)	10		—			(3		)	5
Income/(loss) before income taxes	28		316		(99		)	(82		)	25		(418		)	(5		)	(235		)
Net Income/(Loss)	28		316		(99		)	(73		)	25		(337		)	(5		)	(145		)
Net income/(loss) attributable to NRG Energy, Inc.	$	28	$	316	$	(98	)	$	(82	)	$	13	$	(313	)	$	2		$	(134	)



(e) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	541	$	4	$	—	$	23	$	9	$	81	$	—	$	658



(f) Includes loss on debt extinguishment of:	$	—	$	—	$	—	$	—	$	7	$	—	$	—	$	7



			NRG Home
(In millions)	NRG Business^(g)		Retail^(g)		Solar^(g)			NRG Renew^(g)(h)			NRG Yield^(g)		Corporate^(g)(h)			Eliminations			Total
Six months ended June 30, 2014	(in millions)
Operating revenues^(g)	$	4,881	$	2,485	$	25		$	206		$	313	$	24		$	(827	)	$	7,107
Depreciation and amortization	464		61		2			100			78		16			—			721
Equity in earnings/(loss) of unconsolidated affiliates	16		—		—			(6		)	15		3			(7		)	21
Income/(loss) before income taxes	94		135		(9		)	(63		)	73		(524		)	(10		)	(304		)
Net Income/(Loss)	$	93	$	135	$	(9	)	$	(63	)	$	68	$	(361	)	$	(10	)	(147		)
Net income/(loss) attributable to NRG Energy, Inc.	$	93	$	135	$	(9	)	$	(66	)	$	58	$	(370	)	$	6		$	(153	)



(g) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	825	$	4	$	—	$	15	$	—	$	(17	)	$	—	$	827



(h) Includes loss on debt extinguishment of:	$	—	$	—	$	—	$	1	$	—	$	80	$	—	$	81

Note 12 — 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)	2015			2014			2015			2014
Loss before income taxes	$	(26	)	$	(206	)	$	(235	)	$	(304	)
Income tax benefit	(17		)	(126		)	(90		)	(157		)
Effective tax rate	65.4		%	61.2		%	38.3		%	51.6		%

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.

For the three and six months ended June 30, 2014, 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 and the recognition of uncertain tax benefits.

Uncertain Tax Benefits

As of June 30, 2015, NRG has recorded a non-current tax liability of $56 million for uncertain tax benefits from positions taken on various state income tax returns, including accrued interest. For the six months ended June 30, 2015, NRG accrued $1 million of interest relating to the uncertain tax benefits. As of June 30, 2015, NRG had cumulative interest and penalties related to these uncertain tax benefits of $6 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 13 — Commitments and Contingencies

This footnote should be read in conjunction with the complete description under Note 22, Commitments and Contingencies, to the Company's 2014 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, 2015, hedges under the first liens were in-the-money for NRG on a counterparty aggregate basis.

Nuclear Insurance — STP maintains required insurance coverage for liability claims arising from nuclear incidents pursuant to the Price-Anderson Amendment to the Energy Policy Act of 2005, referred to as the Price-Anderson Act. As a result of two reactors shutting down in the U.S., the current per reactor liability limits under the Price-Anderson Act have changed. Effective June 30, 2015, the current liability limit per incident is $13.4 billion, subject to change to account for the effects of inflation and the number of licensed reactors. An inflation adjustment must be made at least once every five years with the most recent adjustment effective September 2013. Under the Price-Anderson Act, owners of nuclear power plants in the U.S. are required to purchase primary insurance limits of $375 million for each operating site. In addition, the Price-Anderson Act requires an additional layer of protection through mandatory participation in a retrospective rating plan for power reactors resulting in an additional $13.4 billion in funds available for public liability claims. The current maximum assessment per incident, per reactor, is approximately $127 million, taking into account a 5% adjustment for administrative fees, payable at approximately $19 million per year, per reactor. NRG would be responsible for 44% of the maximum assessment, or $8 million per year, per reactor, and a maximum of $112 million per incident. In addition, the U.S. Congress retains the ability to impose additional financial requirements on the nuclear industry to pay liability claims that exceed $13.4 billion for a single incident. The liabilities of the co-owners of STP with respect to the retrospective premium assessments for nuclear liability insurance are joint and several.

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. Based on the energy production amount since January 2014, the Company expects that either or both units may not meet their guaranteed energy production amount for the initial performance measurement period. The Company is exploring options to mitigate this risk or its consequences.

Contingencies

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

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

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

Actions Pursued by MC Asset Recovery — With Mirant Corporation's emergence from bankruptcy protection in 2006, certain actions filed by GenOn Energy Holdings and some of its subsidiaries against third parties were transferred to MC Asset Recovery, a wholly owned subsidiary of GenOn Energy Holdings. MC Asset Recovery is governed by a manager who is independent of NRG and GenOn. MC Asset Recovery is a disregarded entity for income tax purposes. Under the remaining action transferred to MC Asset Recovery, MC Asset Recovery seeks to recover damages from Commerzbank AG and various other banks, or the Commerzbank Defendants, for alleged fraudulent transfers that occurred prior to Mirant's bankruptcy proceedings. In December 2010, the U.S. District Court for the Northern District of Texas dismissed MC Asset Recovery's complaint against the Commerzbank Defendants. In January 2011, MC Asset Recovery appealed the District Court's dismissal of its complaint against the Commerzbank Defendants to the U.S. Court of Appeals for the Fifth Circuit. In March 2012, the Court of Appeals reversed the District Court's dismissal and reinstated MC Asset Recovery's amended complaint against the Commerzbank Defendants. If MC Asset Recovery succeeds in obtaining any recoveries from the Commerzbank Defendants, the Commerzbank Defendants have asserted that they will seek to file claims in Mirant's bankruptcy proceedings for the amount of those recoveries. GenOn Energy Holdings would vigorously contest the allowance of any such claims. If the Commerzbank Defendants were to receive an allowed claim as a result of a recovery by MC Asset Recovery on its claims against them, GenOn Energy Holdings would retain from the net amount recovered by MC Asset Recovery an amount equal to the dollar amount of the resulting allowed claim.

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 U.S. Supreme Court granted the petition. On April 21, 2015, the U.S. Supreme Court affirmed the Ninth Circuit’s holding that plaintiffs’ state antitrust law claims are not field-preempted by the federal Natural Gas Act and the Supremacy Clause of the U.S. Constitution. The U.S. Supreme Court left open whether the claims were preempted on the basis of conflict preemption. The U.S. Supreme Court directed that the case be remanded to the U.S. District Court for the District of Nevada for further proceedings. GenOn has agreed to indemnify CenterPoint against certain losses relating to these lawsuits.

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

Cheswick Class Action Complaint — In April 2012, a putative class action lawsuit was filed against GenOn in the Court of Common Pleas of Allegheny County, Pennsylvania alleging that emissions from the Cheswick generating facility have damaged the property of neighboring residents. Plaintiffs alleged nuisance, negligence, trespass and strict liability claims seeking both damages and injunctive relief. Plaintiffs sought to certify a class that consists of people who owned property or lived within one mile of the Company's plant. In July 2012, the Company removed the lawsuit to the U.S. District Court for the Western District of Pennsylvania. On May 11, 2015, the District Court entered an agreed upon voluntary dismissal with prejudice. The order entered by the District Court provides that the plaintiffs failed to establish any of the claims in their complaint, that each party will bear its own costs, and that no money or other consideration will be paid to the plaintiffs or putative class members.

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. Energy Plus Holdings continues to cooperate and discuss a resolution of these issues with the NYAG. The Company does not expect the resolution of this matter to have a material impact on the Company's consolidated financial position, results of operations, or cash flows.

Maryland Department of the Environment v. GenOn Chalk Point and GenOn Mid-Atlantic — On January 25, 2013, Food & Water Watch, the Patuxent Riverkeeper and the Potomac Riverkeeper (together, the Citizens Group) sent GenOn Mid-Atlantic a letter alleging that the Chalk Point, Dickerson and Morgantown generating facilities were violating the terms of the three National Pollution Discharge Elimination System permits by discharging nitrogen and phosphorous in excess of the limits in each permit. On March 21, 2013, the MDE sent GenOn Mid-Atlantic a similar letter with respect to the Chalk Point and Dickerson generating facilities, threatening to sue within 60 days if the generating facilities were not brought into compliance. On June 11, 2013, the Maryland Attorney General on behalf of the MDE filed a complaint in the U.S. District Court for the District of Maryland alleging violations of the CWA and Maryland environmental laws related to water. The lawsuit is ongoing and seeks injunctive relief and civil penalties in excess of $100,000. The Company does not expect the resolution of this matter to have a material impact on the Company's consolidated financial position, results of operations, or cash flows.

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

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

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

Telephone Consumer Protection Act Purported Class Actions — Two purported class action lawsuits have been filed against NRG and NRG Residential Solar Solutions, LLC in California and 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 generally seek statutory damages of up to $1,500, actual damages and equitable relief. The Company intends to vigorously defend against these lawsuits.

El Segundo Environmental Liability — During the maintenance of breakers in 2012, the Company’s El Segundo plant exceeded California’s limit regarding SF6 losses. SF6 is an electrical insulator and GHG. In 2015, the Company began discussions with the California Air Resources Board regarding a potential penalty. Later this year, the Company expects to pay a penalty in excess of $100,000 to settle this matter. 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.

Note 14 — Regulatory Matters

This footnote should be read in conjunction with the complete description under Note 23, Regulatory Matters, to the Company's 2014 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 a party to other regulatory proceedings arising in the ordinary course of business or have other regulatory exposure. In management's opinion, the disposition of these ordinary course matters will not materially adversely affect NRG's consolidated financial position, results of operations, or cash flows.

National

Court Rejects FERC's Jurisdiction Over Demand Response — On May 23, 2014, the D.C. Circuit vacated FERC’s rules (known as Order No. 745) that allowed demand response resources to participate in FERC-jurisdictional energy markets. The Court of Appeals held that the FPA does not authorize FERC to exercise jurisdiction over demand response and that instead demand response is part of the retail market over which the states have jurisdiction. The specific order being challenged related to energy market compensation, but this ruling also calls into question whether demand response will be permitted to participate in the capacity markets in the future. Parties including the U.S. Solicitor General filed petitions for a writ of certiorari with the U.S. Supreme Court. On May 4, 2015, the U.S. Supreme Court granted certiorari on two questions: first, on whether the FPA gives FERC jurisdiction over demand response, and second, whether FERC was arbitrary and capricious when it established in Order No. 745 the level of compensation to be paid to demand response resources participating in the wholesale energy markets. On July 16, 2015, the Company filed an amicus brief with the U.S. Supreme Court. The eventual outcome of this proceeding could result in refunds of payments made for non-jurisdictional services and resettlement of wholesale markets, but it is not possible to predict the outcome or estimate the impact on the Company at this time.

East Region

Montgomery County Station Power Tax — On December 20, 2013, the Company received a letter from Montgomery County, Maryland requesting payment of an energy tax for the consumption of station power at the Dickerson Facility over the previous three years. Montgomery County seeks payment in the amount of $22 million, which includes tax, interest and penalties. The Company is disputing the applicability of the tax. On December 17, 2014, the Maryland Tax Court heard oral arguments from the parties. Subsequently, post hearing briefs were filed. The decision is pending.

Note 15 — Environmental Matters

This footnote should be read in conjunction with the complete description under Note 24, Environmental Matters, to the Company's 2014 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 and regulations surrounding 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 likely to face new requirements to address various emissions, including GHG, as well as 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 each state's obligation to reduce emissions so that downwind states can achieve federal air quality standards. In December 2011, the D.C. Circuit stayed the implementation of CSAPR and then vacated CSAPR in August 2012 but kept CAIR in place until the EPA could replace it. In April 2014, the U.S. Supreme Court reversed and remanded the D.C. Circuit's decision. In October 2014, the D.C. Circuit lifted the stay of CSAPR. In response, the EPA in November 2014 amended the CSAPR compliance dates. Accordingly, CSAPR replaced CAIR on January 1, 2015. On July 28, 2015, the D.C. Circuit held that the EPA had exceeded its authority by requiring certain reductions that were not necessary for downwind states to achieve federal standards. Although the D.C. Circuit kept the rule in place, the D.C. Circuit 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. While NRG cannot predict the final outcome of this rulemaking, the Company believes its investment in pollution controls and cleaner technologies coupled with planned plant retirements leave the fleet well positioned for compliance.

In December 2014, the EPA proposed making the NAAQS for ozone more stringent. The EPA anticipates promulgating a more stringent ozone NAAQS by October 2015. A more stringent NAAQS would obligate the states to develop plans to reduce NO_x (an ozone precursor), which could affect some of the Company's units.

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 must 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, which will hold further proceedings over the next several months.

On August 3, 2015, the EPA administrator signed final GHG emissions rules for new and existing fossil-fuel-fired electric generating units. As the documents signed by the administrator note, they are a pre-publication version of the final rules; the official version of the rules will be the version published in the Federal Register, which the Company expects to occur in the coming weeks. The Company is evaluating the potential impacts of these rules regarding existing units. The Company expects that it will take several years for the impacts of these rules to be fully known and to take effect because of the likely legal challenges and because it may take several years for states to develop and put in place plans that will be required to implement these rules and to achieve state-specific goals.

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.

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. In 2010, the EPA had proposed two alternatives. Under the first proposal, which was reflected in the final rule, these byproducts will be regulated as solid wastes. Under the second proposal, these byproducts would have been regulated as “special wastes” in a manner similar to the regulation of hazardous waste with an exception for certain types of beneficial use of these byproducts. The second alternative would have imposed significantly more stringent requirements and materially increased the cost of disposal of coal combustion byproducts. The Company is evaluating 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, 2015.

East Region

Maryland Environmental Regulations — In December 2014, MDE proposed a regulation regarding NO_x emissions from coal-fired electric generating units, which if finalized would have required by 2020 the Company (at each of the three Dickerson coal-fired units and the Chalk Point coal-fired unit that does not have an SCR) to either (1) install and operate an SCR; (2) retire the unit; or (3) convert the fuel source from coal to natural gas. In early 2015, a new gubernatorial administration in Maryland decided not to finalize the regulation as proposed. Later this year, the Company expects MDE to propose revised regulations to address future NO_xreductions, which when finalized may negatively affect certain of the Company’s coal-fired units in Maryland.

Environmental Capital Expenditures

Based on current (and in some cases proposed) rules, technology and preliminary plans based on some proposed rules, NRG estimates that environmental capital expenditures from 2015 through 2019 required to comply with environmental laws will be approximately $605 million which includes $52 million for GenOn and $443 million for Midwest Generation. These costs are primarily associated with (i) DSI/ESP upgrades at Waukegan and Powerton to satisfy the IL CPS and the Joliet gas conversion; (ii) controls to satisfy MATS and the recent NSR settlement at Big Cajun II; (iii) controls to satisfy MATS at W.A. Parish; and (iv) NO_x controls for Sayreville and Gilbert.

Note 16 — Condensed Consolidating Financial Information

As of June 30, 2015, the Company had outstanding $6.4 billion of Senior Notes due from 2018 - 2024, as shown in Note 7, 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, 2015:



Ace Energy, Inc.	NEO Power Services Inc.	NRG Operating Services, Inc.
Allied Warranty LLC	New Genco GP, LLC	NRG Oswego Harbor Power Operations Inc.
Arthur Kill Power LLC	Norwalk Power LLC	NRG PacGen Inc.
Astoria Gas Turbine Power LLC	NRG Advisory Services LLC	NRG Portable Power LLC
Bayou Cove Peaking Power, LLC	NRG Affiliate Services Inc.	NRG Power Marketing LLC
BidURenergy, Inc.	NRG Artesian Energy LLC	NRG Reliability Solutions LLC
Cabrillo Power I LLC	NRG Arthur Kill Operations Inc.	NRG Renter's Protection LLC
Cabrillo Power II LLC	NRG Astoria Gas Turbine Operations Inc.	NRG Retail LLC
Carbon Management Solutions LLC	NRG Bayou Cove LLC	NRG Retail Northeast LLC
Cirro Group, Inc.	NRG Business Services LLC	NRG Rockford Acquisition LLC
Cirro Energy Services, Inc.	NRG Business Solutions LLC	NRG Saguaro Operations Inc.
Clean Edge Energy LLC	NRG Cabrillo Power Operations Inc.	NRG Security LLC
Conemaugh Power LLC	NRG California Peaker Operations LLC	NRG Services Corporation
Connecticut Jet Power LLC	NRG Cedar Bayou Development Company, LLC	NRG SimplySmart Solutions LLC
Cottonwood Development LLC	NRG Connected Home LLC	NRG SPV #1 LLC
Cottonwood Energy Company LP	NRG Connecticut Affiliate Services Inc.	NRG South Central Affiliate Services Inc.
Cottonwood Generating Partners I LLC	NRG Construction LLC	NRG South Central Generating LLC
Cottonwood Generating Partners II LLC	NRG Curtailment Solutions LLC	NRG South Central Operations Inc.
Cottonwood Generating Partners III LLC	NRG Development Company Inc.	NRG South Texas LP
Cottonwood Technology Partners LP	NRG Devon Operations Inc.	NRG Texas C&I Supply LLC
Devon Power LLC	NRG Dispatch Services LLC	NRG Texas Gregory LLC
Dunkirk Power LLC	NRG Distributed Generation PR LLC	NRG Texas Holding Inc.
Eastern Sierra Energy Company LLC	NRG Dunkirk Operations Inc.	NRG Texas LLC
El Segundo Power, LLC	NRG El Segundo Operations Inc.	NRG Texas Power LLC
El Segundo Power II LLC	NRG Energy Efficiency-L LLC	NRG Warranty Services LLC
Energy Alternatives Wholesale, LLC	NRG Energy Efficiency-P LLC	NRG West Coast LLC
Energy Curtailment Specialists, Inc.	NRG Energy Labor Services 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 Home & Business Solutions LLC	Reliant Energy Northeast LLC
GCP Funding Company, LLC	NRG Home Services LLC	Reliant Energy Power Supply, LLC
Green Mountain Energy	NRG Home Solutions LLC	Reliant Energy Retail Holdings, LLC
Green Mountain Energy Company	NRG Home Solutions Product LLC	Reliant Energy Retail Services, LLC
Gregory Partners, LLC	NRG Homer City Services LLC	RERH Holdings LLC
Gregory Power Partners LLC	NRG Huntley Operations Inc.	Saguaro Power LLC
Huntley Power LLC	NRG HQ DC LLC	Somerset Operations Inc.
Independence Energy Alliance LLC	NRG Identity Protect LLC	Somerset Power LLC
Independence Energy Group LLC	NRG Ilion Limited Partnership	Texas Genco Financing Corp.
Independence Energy Natural Gas LLC	NRG Ilion LP LLC	Texas Genco GP, LLC
Indian River Operations Inc.	NRG International LLC	Texas Genco Holdings, Inc.
Indian River Power LLC	NRG Maintenance Services LLC	Texas Genco LP, LLC
Keystone Power LLC	NRG Mextrans Inc.	Texas Genco Operating Services, LLC
Langford Wind Power, LLC	NRG MidAtlantic Affiliate Services Inc.	Texas Genco Services, LP
Louisiana Generating LLC	NRG Middletown Operations Inc.	US Retailers LLC
Meriden Gas Turbines LLC	NRG Montville Operations Inc.	Vienna Operations Inc.
Middletown Power LLC	NRG New Roads Holdings LLC	Vienna Power LLC
Montville Power LLC	NRG North Central Operations Inc.	WCP (Generation) Holdings LLC
NEO Corporation	NRG Northeast Affiliate Services Inc.	West Coast Power LLC
NEO Freehold-Gen 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, 2015

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	2,264		$	1,161		$	—		$	(28	)	$	3,397
Operating Costs and Expenses
Cost of operations	1,703			754			(16		)	(7		)	2,434
Depreciation and amortization	196			195			5			—			396
Selling, general and administrative	113			91			87			—			291
Acquisition-related transaction and integration costs	—			(1		)	4			—			3
Development activity expenses	—			15			26			—			41
Total operating costs and expenses	2,012			1,054			106			(7		)	3,165
Operating Income/(Loss)	252			107			(106		)	(21		)	232
Other Income/(Expense)
Equity in (loss)/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)/income	(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/(loss) attributable to noncontrolling interest and redeemable noncontrolling interests	—			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	$	4,827		$	2,464		$	—		$	(68	)	$	7,223
Operating Costs and Expenses
Cost of operations	3,807			1,749			(4		)	(56		)	5,496
Depreciation and amortization	400			381			10			—			791
Selling, general and administrative	215			192			147			—			554
Acquisition-related transaction and integration costs	—			1			12			—			13
Development activity expenses	—			30			45			—			75
Total operating costs and expenses	4,422			2,353			210			(56		)	6,929
Gain on postretirement benefits curtailment	—			14			—			—			14
Operating Income/(Loss)	405			125			(210		)	(12		)	308
Other Income/(Expense)
Equity in (loss)/earnings of consolidated subsidiaries	(35		)	(57		)	204			(112		)	—
Equity in earnings 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 loss attributable to noncontrolling interest and redeemable noncontrolling interests	—			—			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

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 plan, net	—		—			(1		)	—			(1		)
Other comprehensive income	2		13			21			(15		)	21
Comprehensive Income/(Loss)	147		(28		)	17			(124		)	12
Less: Comprehensive income/(loss) 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

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 plan, 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 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

June 30, 2015

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
ASSETS	(In millions)
Current Assets
Cash and cash equivalents	$	10		$	1,437		$	699		$	—		$	2,146
Funds deposited by counterparties	10			23			—			—			33
Restricted cash	12			420			1			—			433
Accounts receivable - trade, net	1,088			324			1			—			1,413
Accounts receivable - affiliate	9,404			2,185			(6,024		)	(5,559		)	6
Inventory	517			636			—			—			1,153
Derivative instruments	1,306			844			—			(345		)	1,805
Cash collateral paid in support of energy risk management activities	196			103			—			—			299
Deferred income taxes	—			88			105			—			193
Renewable energy grant receivable, net	—			18			1			—			19
Prepayments and other current assets	197			313			—			—			510
Total current assets	12,740			6,391			(5,217		)	(5,904		)	8,010
Net property, plant and equipment	8,165			13,985			180			(26		)	22,304
Other Assets
Investment in subsidiaries	436			2,465			23,341			(26,242		)	—
Equity investments in affiliates	(17		)	1,153			45			(104		)	1,077
Notes receivable, less current portion	—			52			200			(187		)	65
Goodwill	2,072			461			22			—			2,555
Intangible assets, net	816			1,616			2			(6		)	2,428
Nuclear decommissioning trust fund	576			—			—			—			576
Derivative instruments	243			299			—			(51		)	491
Deferred income tax	(149		)	679			924			—			1,454
Other non-current assets	73			829			503			—			1,405
Total other assets	4,050			7,554			25,037			(26,590		)	10,051
Total Assets	$	24,955		$	27,930		$	20,000		$	(32,520	)	$	40,365
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	1		$	616		$	206		$	(187	)	$	636
Accounts payable	690			349			41			—			1,080
Accounts payable — affiliate	2,585			3,211			(181		)	(5,615		)	—
Derivative instruments	1,261			721			—			(344		)	1,638
Cash collateral received in support of energy risk management activities	10			23			—			—			33
Accrued expenses and other current liabilities	281			436			365			—			1,082
Total current liabilities	4,828			5,356			431			(6,146		)	4,469
Other Liabilities
Long-term debt and capital leases	307			11,047			8,307			—			19,661
Nuclear decommissioning reserve	318			—			—			—			318
Nuclear decommissioning trust liability	311			—			—			—			311
Deferred income taxes	1,278			(1,039		)	(221		)	—			18
Derivative instruments	323			250			—			(51		)	522
Out-of-market contracts, net	103			1,090			—						1,193
Other non-current liabilities	492			740			295			—			1,527
Total non-current liabilities	3,132			12,088			8,381			(51		)	23,550
Total liabilities	7,960			17,444			8,812			(6,197		)	28,019
2.822% convertible perpetual preferred stock	—			—			296			—			296
Redeemable noncontrolling interest in subsidiaries	—			33			—			—			33
Stockholders’ Equity	16,995			10,453			10,892			(26,323		)	12,017
Total Liabilities and Stockholders’ Equity	$	24,955		$	27,930		$	20,000		$	(32,520	)	$	40,365


(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 Cash Provided/(Used) by Operating Activities	$	1,528		$	(533	)	$	(1,465	)	$	928		$	458
Cash Flows from Investing Activities
(Payments for)/proceeds from intercompany loans to subsidiaries	(1,368		)	440			928			—			—
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	—			—			1			—			1
Investments in unconsolidated affiliates	—			(304		)	(49		)	—			(353		)
Other	5			4			—			—			9
Net Cash (Used)/Provided by Investing Activities	(1,536		)	(186		)	862			—			(860		)
Cash Flows from Financing Activities
Proceeds from intercompany loans	—			—			928			(928		)	—
Payment of dividends to common and preferred stockholders	—			—			(102		)	—			(102		)
Payment for treasury stock	—			—			(186		)	—			(186		)
Net receipts from 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 Provided/(Used) by Financing Activities	—			698			659			(928		)	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.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Three Months Ended June 30, 2014

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	2,514		$	1,129		$	—		$	(22	)	$	3,621
Operating Costs and Expenses
Cost of operations	2,048			773			11			(4		)	2,828
Depreciation and amortization	211			170			5			—			386
Selling, general and administrative	106			71			80			—			257
Acquisition-related transaction and integration costs	—			7			33			—			40
Development activity expenses	—			7			14			—			21
Total operating costs and expenses	2,365			1,028			143			(4		)	3,532
Operating Income/(Loss)	149			101			(143		)	(18		)	89
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	52			—			65			(117		)	—
Equity in earnings of unconsolidated affiliates	6			17			—			(9		)	14
Other income/(expense), net	3			4			(2		)	—			5
Loss on debt extinguishment	—			—			(40		)	—			(40		)
Interest expense	(5		)	(120		)	(149		)	—			(274		)
Total other income/(expense)	56			(99		)	(126		)	(126		)	(295		)
Income/(Loss) Before Income Taxes	205			2			(269		)	(144		)	(206		)
Income tax expense/(benefit)	47			4			(177		)	—			(126		)
Net Income/(Loss)	158			(2		)	(92		)	(144		)	(80		)
Less: Net income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest	—			39			5			(27		)	17
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	158		$	(41	)	$	(97	)	$	(117	)	$	(97	)


(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, 2014

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	4,793		$	2,380		$	—		$	(66	)	$	7,107
Operating Costs and Expenses
Cost of operations	3,845			1,747			7			(34		)	5,565
Depreciation and amortization	409			304			8			—			721
Selling, general and administrative	207			128			144			—			479
Acquisition-related transaction and integration costs	—			8			44			—			52
Development activity expenses	—			17			23			—			40
Total operating costs and expenses	4,461			2,204			226			(34		)	6,857
Gain on sale of assets	—			19			—			—			19
Operating Income/(Loss)	332			195			(226		)	(32		)	269
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries	101			(6		)	180			(275		)	—
Equity in earnings of unconsolidated affiliates	10			18			—			(7		)	21
Other income, net	4			8			5			(1		)	16
Loss on debt extinguishment	—			(9		)	(72		)	—			(81		)
Interest expense	(11		)	(227		)	(292		)	1			(529		)
Total other income/(expense)	104			(216		)	(179		)	(282		)	(573		)
Income/(Loss) Before Income Taxes	436			(21		)	(405		)	(314		)	(304		)
Income tax expense/(benefit)	110			(6		)	(261		)	—			(157		)
Net Income/ (Loss)	326			(15		)	(144		)	(314		)	(147		)
Less: Net income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest	—			36			9			(39		)	6
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	326		$	(51	)	$	(153	)	$	(275	)	$	(153	)


(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, 2014

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Net Income/(Loss)	$	158		$	(2	)	$	(92	)	$	(144	)	$	(80	)
Other Comprehensive Income/(Loss), net of tax
Unrealized gain/(loss) on derivatives, net	2			(20		)	(8		)	7			(19		)
Foreign currency translation adjustments, net	—			(1		)	(2		)	—			(3		)
Available-for-sale securities, net	—			5			4			(2		)	7
Defined benefit plan, net	(2		)	(13		)	25			—			10
Other comprehensive (loss)/income	—			(29		)	19			5			(5		)
Comprehensive Income/(Loss)	158			(31		)	(73		)	(139		)	(85		)
Less: Comprehensive income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest	—			32			5			(25		)	12
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	158			(63		)	(78		)	(114		)	(97		)
Dividends for preferred shares	—			—			3			—			3
Comprehensive Income/(Loss) Available for Common Stockholders	$	158		$	(63	)	$	(81	)	$	(114	)	$	(100	)


(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, 2014

(Unaudited)



	Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Net Income/(Loss)	326		(15		)	(144		)	(314		)	(147		)
Other Comprehensive Income/(Loss), net of tax
Unrealized gain/(loss) on derivatives, net	8		(26		)	(3		)	(7		)	(28		)
Foreign currency translation adjustments, net	—		5			(2		)	—			3
Available-for-sale securities, net	—		5			8			—			13
Defined benefit plan, net	—		(13		)	25			—			12
Other comprehensive income/(loss)	8		(29		)	28			(7		)	—
Comprehensive Income/(Loss)	334		(44		)	(116		)	(321		)	(147		)
Less: Comprehensive income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest	—		27			9			(39		)	(3		)
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	334		(71		)	(125		)	(282		)	(144		)
Dividends for preferred shares	—		—			5			—			5
Comprehensive Income/(Loss) Available for Common Stockholders	$	334	$	(71	)	$	(130	)	$	(282	)	$	(149	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

December 31, 2014



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
ASSETS	(In millions)
Current Assets
Cash and cash equivalents	$	18		$	1,455		$	643		$	—		$	2,116
Funds deposited by counterparties	9			63			—			—			72
Restricted cash	5			451			1			—			457
Accounts receivable - trade, net	924			392			6			—			1,322
Accounts receivable - affiliate	7,449			1,988			(5,991		)	(3,437		)	9
Inventory	537			710			—			—			1,247
Derivative instruments	1,657			1,209			—			(441		)	2,425
Cash collateral paid in support of energy risk management activities	114			73			—			—			187
Deferred income taxes	41			96			37			—			174
Renewable energy grant receivable, net	—			134			1			—			135
Prepayments and other current assets	53			79			306			—			438
Total current assets	10,807			6,650			(4,997		)	(3,878		)	8,582
Net Property, Plant and Equipment	8,344			13,877			171			(25		)	22,367
Other Assets
Investment in subsidiaries	140			2,293			23,410			(25,843		)	—
Equity investments in affiliates	(18		)	891			—			(102		)	771
Notes receivable, less current portion	1			60			109			(98		)	72
Goodwill	1,921			653			—			—			2,574
Intangible assets, net	765			1,806			2			(6		)	2,567
Nuclear decommissioning trust fund	585			—			—			—			585
Derivative instruments	242			288			1			(51		)	480
Deferred income taxes	(247		)	816			837			—			1,406
Other non-current assets	113			640			508			—			1,261
Total other assets	3,502			7,447			24,867			(26,100		)	9,716
Total Assets	$	22,653		$	27,974		$	20,041		$	(30,003	)	$	40,665
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	1		$	444		$	127		$	(98	)	$	474
Accounts payable	598			416			46			—			1,060
Accounts payable — affiliate	1,588			2,447			(598		)	(3,437		)	—
Deferred Income Taxes	7			—			(7		)	—			—
Derivative instruments	1,532			963			—			(441		)	2,054
Cash collateral received in support of energy risk management activities	9			63			—			—			72
Accrued expenses and other current liabilities	283			498			418			—			1,199
Total current liabilities	4,018			4,831			(14		)	(3,976		)	4,859
Other Liabilities
Long-term debt and capital leases	307			11,226			8,367			—			19,900
Nuclear decommissioning reserve	310			—			—			—			310
Nuclear decommissioning trust liability	333			—			—			—			333
Deferred income taxes	1,036			(1,012		)	(3		)	—			21
Derivative instruments	248			241			—			(51		)	438
Out-of-market contracts, net	111			1,133			—			—			1,244
Other non-current liabilities	465			795			314			—			1,574
Total non-current liabilities	2,810			12,383			8,678			(51		)	23,820
Total Liabilities	6,828			17,214			8,664			(4,027		)	28,679
2.822% Preferred Stock	—			—			291			—			291
Redeemable noncontrolling interest in subsidiaries	—			19			—			—			19
Stockholders’ Equity	15,825			10,741			11,086			(25,976		)	11,676
Total Liabilities and Stockholders’ Equity	$	22,653		$	27,974		$	20,041		$	(30,003	)	$	40,665


(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, 2014

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Cash Flows from Operating Activities
Net Cash Provided/(Used) by Operating Activities	$	798		$	641		$	(2,429	)	$	1,360		$	370
Cash Flows from Investing Activities
Intercompany loans (to)/from subsidiaries	(808		)	(552		)	1,360			—			—
Acquisition of businesses, net of cash acquired	—			(25		)	(1,792		)	—			(1,817		)
Capital expenditures	(9		)	(134		)	(364		)	—			(507		)
(Increase)/decrease in restricted cash, net	(2		)	(5		)	1			—			(6		)
Decrease/(increase) in restricted cash — U.S. DOE projects	—			24			(3		)	—			21
Decrease in notes receivable	—			2			—			—			2
Investments in nuclear decommissioning trust fund securities	(340		)	—			—			—			(340		)
Proceeds from sales of nuclear decommissioning trust fund securities	334			—			—			—			334
Proceeds from renewable energy grants	—			429			—			—			429
Proceeds from sale of assets, net of cash disposed of	—			—			77			—			77
Cash proceeds to fund cash grant bridge loan payment	—			57			—			—			57
Investments in unconsolidated affiliates				(22		)							(22		)
Other	(4		)	23			—			—			19
Net Cash Used by Investing Activities	(829		)	(203		)	(721		)	—			(1,753		)
Cash Flows from Financing Activities
Proceeds from intercompany loans	—			—			1,360			(1,360		)	—
Payment of dividends to common and preferred stockholders	—			—			(91		)	—			(91		)
Net payment for settlement of acquired derivatives that include financing elements	—			(167		)	—			—			(167		)
Contributions from noncontrolling interest in subsidiaries	—			10			—			—			10
Proceeds from issuance of long-term debt	—			551			3,335			—			3,886
Proceeds from issuance of common stock	—			—			8			—			8
Payment of debt issuance costs	—			(15		)	(28		)	—			(43		)
Payments for short and long-term debt	—			(542		)	(2,427		)	—			(2,969		)
Net Cash (Used)/Provided by Financing Activities	—			(163		)	2,157			(1,360		)	634
Effect of exchange rate changes on cash and cash equivalents	—			(24		)	—			—			(24		)
Net (Decrease)/Increase in Cash and Cash Equivalents	(31		)	251			(993		)	—			(773		)
Cash and Cash Equivalents at Beginning of Period	56			870			1,328			—			2,254
Cash and Cash Equivalents at End of Period	$	25		$	1,121		$	335		$	—		$	1,481


(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, 2015 and 2014. Also refer to NRG's 2014 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 which provides a description of NRG's business segments; NRG's Business Strategy section; Business section, including how regulation, weather, and other factors affect NRG's business; and Critical Accounting Policies and Estimates section.

The discussion and analysis below has been organized as follows:


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


•	Results of operations;


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


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

Executive Summary

Introduction and Overview

The following table summarizes NRG's global generation portfolio as of June 30, 2015, by operating segment:



	Global Generation Portfolio by Operating Segment^(a)
	(In MW)
	NRG Business
	Gulf Coast	East	West	NRG Home Solar^(b)	NRG Renew		NRG Yield^(c)		Total Domestic		Other(Inter-national)	Total Global
Primary Fuel-type
Natural gas^(d)	8,659	7,875	6,496	—	—		1,879		24,909		144	25,053
Coal^(e)	5,114	10,197	—	—	—		—		15,311		605	15,916
Oil^(f)	—	5,606	—	—	—		190		5,796		—	5,796
Nuclear	1,176	—	—	—	—		—		1,176		—	1,176
Wind	—	—	—	—	1,680		1,395		3,075		—	3,075
Utility Scale Solar	—	—	—	—	807		481		1,288		—	1,288
Distributed Solar	—	—	—	68	42		10		120		—	120
Total generation capacity	14,949	23,678	6,496	68	2,529		3,955		51,675		749	52,424
Capacity attributable to noncontrolling interest	—	—	—	—	(630	)	(1,779	)	(2,409	)	—	(2,409	)
Total net generation capacity	14,949	23,678	6,496	68	1,899		2,176		49,266		749	50,015

(a) Includes 92 active fossil fuel and nuclear plants, 15 Utility Scale Solar facilities, 36 wind farms and multiple Distributed Solar facilities. All Utility Scale Solar and Distributed Solar facilities are described in MWs on an alternating current basis. MW figures provided represent nominal summer net MW capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units.

(b) Includes the aggregate production capacity of installed and activated residential solar energy systems.

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

(d) Natural gas generation portfolio does not include 463 MW related to Osceola, which was mothballed on January 1, 2015; 636 MW related to Coolwater, which was retired on January 1, 2015; 160 MW related to Glen Gardner, which was retired on May 1, 2015; and 98 MW related to Gilbert, which was retired on May 1, 2015. Natural gas generation portfolio increased 389 MW as Bowline Unit 2 was restored to full capacity on June 23, 2015, following a boiler restoration.

(e) Coal generation portfolio does not include 251 MW related to Will County, which was retired April 15, 2015; and 597 MW related to Shawville, which was mothballed on May 31, 2015.

(f) Oil generation portfolio does not include 212 MW related to Werner, which was retired on May 1, 2015.

NRG's Business Strategy

NRG's business strategy, summarized in “Enhance Generation, Expand Retail and Go Green while engaging in Smart Capital Allocation” is to maximize stockholder value through the production and sale of safe, reliable and affordable power to its customers in the markets served by the Company, while aggressively positioning the Company to meet the market's increasing demand for sustainable, low carbon and portable energy solutions individualized for the benefit of the end use energy consumer. This strategy is intended to enable the Company to achieve substantial 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.

The Company believes that the U.S. energy industry is going to be increasingly impacted by the long-term societal trend towards sustainability, which is both generational and irreversible. Moreover, it further believes the information technology driven revolution, increasingly wireless and thus portable, has enabled greater and easier personal choice in other sectors of the consumer economy, will do the same in the U.S. energy sector over the years to come. Finally, NRG believes that the aging and static transmission and distribution infrastructure of the national grid is becoming increasingly inadequate in the face of the more extreme weather demands of the 21st century. As a result, the Company expects energy consumers to secure increased personal control over their energy choices in the future. Nevertheless, as the Company shifts to respond to these trends that are playing out over time, the Company's immediate imperative every day remains to serve its customers and the markets in which it operates with safe, affordable, reliable and increasingly sustainable power.

To address these trends and effectuate the Company’s strategy, NRG is focused on: (i) excellence in operating performance of its existing assets including repowering its power generation assets at premium sites and optimal hedging of generation assets and retail load operations; (ii) serving the energy needs of end-use residential, commercial and industrial customers in competitive markets through multiple brands and channels with a variety of retail energy products and services differentiated by innovative features, premium service, sustainability, and loyalty/affinity programs; (iii) investing in, and deploying, alternative energy technologies both in its wholesale portfolio through its wind and solar portfolio and, particularly, in and around its retail businesses and its customers as it transforms this part of its business into a technology-driven provider of retail energy services; and (iv) engaging in a proactive capital allocation plan focused on achieving the regular return of and on stockholder capital within the dictates of prudent balance sheet management; including pursuing selective acquisitions, joint ventures, divestitures and investments. The Company's progress in each of these areas is more fully described in Item 1, Business of the Company's 2014 Form 10-K, and this Form 10-Q.

To further enhance the Company’s strategy, the Company's businesses and personnel are organized based upon the basis of their key target customer segments. The businesses include NRG Business, NRG Home and NRG Renew. In addition, NRG Carbon 360 and NRG eVgo are two distinct businesses that have dedicated management and are organized separately within NRG because of their distinct capital structure, success metrics and competitive environment but are supportive of and closely coordinated with NRG's core businesses. These five companies, plus NRG Yield, Inc., collectively represent the "NRG Group of Companies".

In support of the Company's strategy, the following events have occurred to date during 2015:


•	The Company established a capital allocation program that will apportion cash in an amount equal to the drop down proceeds received from NRG Yield, Inc. equally among share repurchases, corporate debt reduction and future NRG Yield, Inc. eligible projects.

•

Through June 30, 2015, the Company has completed $230 million of share repurchases as part of its 2015 Capital Allocation Program. The Company's board of directors has authorized the repurchase of an additional $51 million of the Company's common stock, which is expected to be completed during the remainder of 2015. In addition, as noted above, the Company plans to utilize a portion of future drop down proceeds to repurchase additional shares.


•	The Company offered NRG Yield, Inc. the opportunity to purchase 75% of NRG Wind TE Holdco LLC, which owns a portfolio of twelve wind facilities totaling 814 net MW.


•	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 for working capital adjustments, plus assumed project level debt of $737 million.

•

NRG Yield, Inc. amended its certificate of incorporation to create two new classes of capital stock, Class C common stock and Class D common stock and distributed shares of the Class C common stock and Class D common stock to holders of NRG Yield Inc.'s outstanding Class A common stock and Class B common stock, respectively, through a stock split. The recapitalization enhances NRG Yield, Inc.’s ability to focus on growth opportunities without the constraints of NRG’s capital allocation to NRG Yield, Inc., while maintaining NRG Yield, Inc.'s relationship with NRG. The recapitalization preserves NRG’s management and operational expertise, asset development and acquisition track record, financing experience and provides flexibility for NRG Yield, Inc. to raise capital to fund its growth.

The Class C common stock and Class D common stock have the same rights and privileges and rank equally, share ratably and are identical in all respects to the shares of Class A common stock and Class B common stock, respectively, as to all matters, except that each share of Class C common stock and Class D common stock is entitled to 1/100th of a vote on all stockholder matters. In addition, on July 29, 2015, NRG Yield, Inc. completed the issuance of 28,198,000 shares of Class C common stock for net proceeds of $600 million.

In connection with the amendments described above, the Right of First Offer Agreement was amended to make additional assets available to NRG Yield, Inc. should NRG choose to sell them, including (i) two natural gas facilities totaling 795 MW of net capacity that are expected to reach COD in 2017 and 2020; (ii) an equity interest in a wind portfolio that includes wind facilities totaling approximately 934 MW of net capacity; and (iii) up to $250 million of equity interests in one or more residential or distributed solar generation portfolios developed by affiliates of NRG.

•

In addition, NRG Yield, Inc. issued $287.5 million of 2020 Convertible Notes on June 29, 2015. The proceeds from the Class C common stock issuance were utilized to acquire a 25% interest in Desert Sunlight, with the remaining proceeds along with the proceeds from the 2020 Convertible Notes and the proceeds from the Alta X and Alta XI wind tax equity financing arrangement utilized to repay the outstanding project indebtedness associated with the Alta X and Alta XI wind facilities in June 2015 and to repay $190 million outstanding under the NRG Yield revolving credit facility in July 2015.

•

In April 2015, NRG and RPV Holding, a subsidiary of NRG Yield, Inc., formed a partnership that will invest in and hold operating portfolios of residential solar assets developed by NRG Home Solar, including: (i) an existing, unlevered portfolio of over 2,200 leases across nine states representing approximately 17 MW with a weighted average remaining lease term of approximately 17 years in which NRG Yield, Inc. invested approximately $26 million in April 2015; and (ii) in-development, tax equity financed portfolios of approximately 13,000 leases representing approximately 90 MW, with an average lease term for the existing and new leases of approximately 17 to 20 years.

•

NRG and DGPV Holding, a subsidiary of NRG Yield, Inc., formed a partnership that will invest in and hold operating portfolios of distributed solar assets developed by NRG Renew. The partnership will allow NRG to periodically monetize its distributed solar investments and NRG Yield, Inc. to invest in a growing segment of the solar market. Under the terms of the partnership agreement, NRG Yield, Inc. will receive 95% of the economics until achieving a targeted return, expected to be achieved commensurate with the end of the customer contract period, after which NRG will receive 95% of the economics. NRG Yield, Inc. has initially committed to invest up to $100 million of cash contributions into the partnership over time. The partnership is expected to be fully invested over the next 18 months.


•	On May 21, 2015, the CPUC approved the 20-year PPTA with SDG&E for NRG's 500 MW Carlsbad Energy Center. This new natural gas peaking plant will help ensure reliability in southern California.


•	NRG Renew plans to build a 20 MW solar energy facility in Blythe, California and will sell electricity generated by the solar facility to Cisco Systems under a 20-year PPA.


•	NRG Renew entered into an agreement with Kaiser Permanente, one of the nation's largest not-for-profit healthcare providers, to utilize as much as 70 MWs of on-site solar energy to help Kaiser Permanente achieve its greenhouse gas emission reduction goals.

Wind Resource Availability

In the first and second quarters of 2015, the Company's results were impacted by lower than normal wind resource availability. While the Company's wind facilities were available, adverse weather had a negative impact on wind resources. The Company cannot predict the impact of wind resource availability on future performance or results.

Regulatory Matters

The Company’s regulatory matters are described in the Company’s 2014 Form 10-K in Item 1, Business — Regulatory Matters. These matters have been updated below and in Note 14, 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.

East Region

PJM

New Jersey and Maryland's Generator Contracting Programs — The New Jersey Board of Public Utilities and the Maryland Public Service Commission awarded long-term power purchase contracts to generation developers to encourage the construction of new generation capacity in the respective states. The constitutionality of the long-term contracts was challenged and the U.S. District Court for the District of New Jersey (in an October 25, 2013, decision) and the U.S. District Court for the District of Maryland (in an October 24, 2013, decision) found that the respective contracts violated the Supremacy Clause of the U.S. Constitution and were preempted. On June 30, 2014, the U.S. Court of Appeals for the Fourth Circuit affirmed the Maryland District Court's decision. On September 11, 2014, the U.S. Court of Appeals for the Third Circuit affirmed the New Jersey District Court's decision. Various parties filed petitions for a writ of certiorari seeking U.S. Supreme Court review of both cases. On March 23, 2015, the U.S. Supreme Court requested the views of the U.S. Solicitor General. The outcome of this litigation and the validity of the contracts may affect future capacity prices in PJM.

Capacity Performance Proposal — On December 14, 2014, PJM requested FERC approval to substantially revamp its capacity market. Under that proposal, future annual capacity auctions would procure two categories of capacity resources: Capacity Performance resources and Base Capacity resources. PJM also would institute substantial new performance penalties on Capacity Performance resources that do not perform in real time during specified periods of high demand and substantially modify capacity bidding rules, and also included a transitional auction mechanism for the 2016/2017 and 2017/2018 delivery years. On June 9, 2015, FERC issued an order accepting the vast majority of PJM's filing.

Additionally, on April 24, 2015, FERC permitted PJM to delay its next Base Residual Auction until August 10-14, 2015, with results posted on August 21, 2015, in order to accommodate the auction changes approved in FERC’s June 9, 2015 order.

On June 30, 2015, a group of consumer representatives filed a request for expedited clarification or expedited rehearing of the PJM Capacity Performance order to ensure that Annual Demand Response resources are able to participate in the upcoming Transition Auctions for the 2016/17 and 2017/18 delivery years. On July 22, 2015, FERC ordered PJM to revise the Transition Auction Schedule to permit Demand Response Resources and Energy Efficiency participation. On June 30, 2015, the Company also requested rehearing, and that request remains pending at FERC.

Consumers Complaint Against PJM on RPM Load Forecasts — On June 30, 2015, a group of consumer representatives filed a complaint against PJM alleging that PJM has violated Section 206 of the FPA by failing to update its methodology for defining load forecast for purposes of the upcoming annual Base Residual Auction and the Transition Auctions. Briefing is underway. Any change to the load forecast of the underlying models could affect capacity prices going forward.

PJM “Stop Gap” Demand Response Filing — On January 14, 2015, PJM filed to implement “stop gap” rules governing the participation of demand response in the upcoming capacity auction (for the 2018/2019 delivery year), which would take effect only if the U.S. Supreme Court denied certiorari in the EPSA v. FERC case from the U.S. Court of Appeals for the D.C. Circuit. Under the proposed new rules, PJM would prohibit demand response from participating in PJM’s capacity auction as a supply-side resource. Instead, PJM proposed to create a new product, termed Wholesale Load Reduction, that would allow LSEs to bid reductions in demand, backed by physical demand response resources, into the auction. Demand response resources participating as Wholesale Load Reduction would have a comparable impact on capacity clearing prices as demand response participating as supply, on a MW for MW basis. The Company opposed PJM’s proposal. On March 31, 2015, FERC issued an order rejecting PJM's filing as premature.

New England

FCM Rules for 2014 Forward Capacity Auction — On February 28, 2014, ISO-NE filed with FERC the results of Forward Capacity Auction 8. On September 16, 2014, FERC issued a notice stating that the Forward Capacity Auction 8 results would go into effect by operation of law. Several parties requested rehearing of FERC’s notice. FERC rejected those requests on legal and procedural grounds. The matter was appealed to the U.S. Court of Appeals for the D.C. Circuit. On April 10, 2015, the D.C. Circuit referred the matter to a full merits panel. On July 1, 2015, the D.C. Circuit issued a briefing schedule.

Complaint Against ISO-NE — On April 6, 2015, GEM filed a complaint against ISO-NE regarding ISO-NE’s conduct of the third Annual Reconfiguration Auction. The Canal 2 unit suffered a transformer failure which significantly restricted the output of the facility. The transformer was repaired in July 2014 and the unit was brought back to its full output. ISO-NE, however, failed to recognize that the unit had been repaired and mistakenly submitted a capacity buy-bid for the 2015-2016 capacity year in the amount of the derate. ISO-NE has denied the allegations. On July 16, 2015, FERC denied GEM's complaint.

New York

Dunkirk Power Reliability Service — On March 14, 2012, Dunkirk Power filed a notice with the NYSPSC of its intent to mothball the Dunkirk Station no later than September 10, 2012. The effects of the mothball on electric system reliability were reviewed by Niagara Mohawk Power Corporation, or National Grid. As a result of those studies, National Grid determined that the mothball of the Dunkirk Station would have a negative impact on the reliability of the New York transmission system and that portions of the Dunkirk Station may be retained for reliability purposes via a non-market compensation arrangement. On July 20, 2012, National Grid and Dunkirk Power agreed on the material terms for a bilateral RSSA and submitted those terms to the NYSPSC for rate recovery in National Grid's rates. On August 16, 2012, the NYSPSC approved terms and on August 27, 2012, Dunkirk Power and National Grid entered into the RSSA that began on September 1, 2012, and expired on May 31, 2013. In late 2012, National Grid issued a request for proposals with respect to its reliability need in the Dunkirk area for the two years beginning June 1, 2014. Dunkirk Power submitted a proposal and signed a second, two-year, contract on March 4, 2013, pursuant to which one unit (Unit 2) at Dunkirk would continue operating through May 31, 2015. The contract was submitted to the NYSPSC in March 2013 and approved in May 2013. On March 2, 2015, National Grid filed a request for NYSPSC approval of a seven-month extension of the RSSA with Dunkirk (to December 31, 2015) of the March 4, 2013, RSSA which extension was approved by the NYSPSC on May 18, 2015.

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 within 120 days of the date of the FERC’s order. However, FERC clarified that NYISO’s RMR proposal will not require Dunkirk to enter into new pro forma agreements for the 2012 and 2013 RSSAs. On March 23, 2015, the NYSPSC filed a request for rehearing and a group of New York transmission owners filed a request for clarification, which is still pending. NYISO received an extension until October 19, 2015, to file tariff revisions.

Dunkirk Natural Gas Addition — On February 13, 2014, Dunkirk Power LLC and National Grid agreed to a term sheet for a 10-year agreement to govern the addition of natural gas-burning capabilities to the Dunkirk facility. This term sheet, known as the DNG Agreement Term Sheet, was approved by the NYSPSC on June 13, 2014. On February 27, 2015, Entergy filed a complaint in the U.S. District Court for the Northern District of New York alleging that the NYSPSC’s approval of the DNG Agreement Term Sheet represents an impermissible interference with FERC’s exclusive jurisdiction over the wholesale markets. On April 20, 2015, Dunkirk Power LLC filed an unopposed motion to become a party to the proceeding. Discovery is ongoing.

Independent Power Producers of New York (IPPNY) Complaint — On May 10, 2013, as amended on March 25, 2014, a generator trade association in New York filed a complaint at FERC against the NYISO. The generators asked FERC to direct the NYISO to require that capacity from existing generation resources that would have exited the market but for out-of-market payments under RMR-type agreements be excluded from the capacity market altogether or be offered at levels no lower than the resources' going-forward costs. The complaints point to the recent reliability services agreements entered into between the NYSPSC and generators, including Dunkirk Power, as evidence that capacity market prices are being influenced by non-market considerations.

On March 19, 2015, FERC denied IPPNY’s complaint and directed NYISO to establish a stakeholder process to consider whether there are circumstances that warrant the adoption of buyer-side mitigation rules in the rest-of-state, and whether mitigation measures would need to be in place to address any price suppressing effects of repowering agreements. On June 17, 2015, NYISO filed its compliance report describing the outcome of the stakeholder process on concluding that buyer-side mitigation measures in the rest-of-state are not warranted. Failure to implement buyer-side mitigation measures could result in uneconomic entry, which artificially decreases capacity prices below competitive market levels.

Competitive Entry Exemption to Buyer-Side Mitigation Rules — On December 4, 2014, pursuant to Section 206 of the FPA, a group of New York transmission owners filed a complaint seeking a competitive entry exemption to the current NYISO Buyer-Side Mitigation rules. On December 16, 2014, TDI USA Holdings Corporation filed a complaint under Section 206 of the FPA against the NYISO claiming that the NYISO’s application of the Mitigation Exemption Test under the Buyer-Side Mitigation Rules to TDI’s Champlain Hudson 1,000 MW transmission line project is unjust and unreasonable and seeks an exemption from the Mitigation Exemption Test. On February 26, 2015, FERC granted the complaint filed by the New York transmission owners and directed the NYISO to adopt a competitive entry exemption into its tariff within 30 days. In a companion order issued on the same day, FERC rejected the TDI complaint on the grounds that TDI’s concerns were adequately addressed by FERC’s first order. On March 30, 2015, NRG filed a request for rehearing. Allowing a competitive entry exemption significantly degrades protections against uneconomic entry into the New York markets.

Revisions to the Buyer-Side Mitigation Rules — On May 8, 2015, several New York entities, including the NYSPSC, filed a complaint against the NYISO under Section 206 of the FPA seeking revisions to the buyer-side market power mitigation measures of the NYISO tariff. The parties request FERC to find that the current buyer-side mitigation rules are unjust and unreasonable because they prevent the ICAP market from functioning properly and that the rules should apply only to a limited subset of generation facilities. NRG protested the complaint arguing that if the New York entities’ changes are implemented, vast amounts of uneconomic resources could enter the market and harm current and future investments.

New York In-City Mitigation — On April 16, 2015, FERC issued an order on clarification and rehearing that established a mitigation bid floor for the Astoria Energy II generating unit, built in New York City in response to a NYPA-sponsored RFP. FERC initially held that Astoria Energy II’s bid floor would incorporate a proxy cost of capital. In this order, FERC directs NYISO to recalculate the NYPA bid floor to reflect its lower actual cost of capital. However, Astoria Energy II’s mitigation has rolled off and FERC’s order did not specify whether it intended its action was intended to be moot or to be applied retroactively. FERC's order could have implications for the price of capacity in New York City.

Gulf Coast Region

ERCOT

Houston Import Project — At its April 8, 2014, meeting, the ERCOT Board endorsed a new 345 kV transmission line project designed to address purported reliability challenges related to congestion between north Texas into the Houston region. On November 14, 2014, the PUCT denied a challenge by the Company and Calpine Corp. regarding ERCOT's endorsement of the project. On April 24, 2015, the transmission owners filed for approval to amend their certificates of convenience and necessity with the PUCT to obtain the authorization to move forward with the project. The Company is continuing to contest ERCOT’s recommendation that the proposed line is needed for reliability purposes.

MISO

MATS Waiver — Indianapolis Power and Light Company, DTE Electric Company, MidAmerican Energy Company, Duke Energy Indiana, Inc., Consumers Energy Company, and Wisconsin Power & Light Company each separately requested a limited, one-time waiver from their obligations to meet the Resource Adequacy Requirement in the MISO tariff, addressing an approximate six-week gap between the EPA’s MATS compliance deadline and the end of MISO’s 2015-2016 capacity planning year. The EPA’s MATS rules establish limits for HAPs emitted from, among other sources, existing and planned coal-fired generators and went into effect on April 16, 2015, with a one-year compliance extension available. Because the MISO capacity planning year runs from June 1 to May 31, there was a gap between the MATS-driven retirements in April and the MISO planning year in June.

FERC granted several of the utilities' requests for the limited, one-time waivers, some of which continue to be contested on rehearing. These waivers distort the efficient operation of MISO's capacity market.

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

Consumer Group Complaint Seeking Reforms — On June 30, 2015, the Illinois Energy Consumers filed at FERC a complaint under Section 206 of the FPA regarding MISO’s Planning Resource Auction tariff provisions, stating that the current MISO tariff does not produce just and reasonable results. The complaint suggests specific tariff modifications to address these alleged deficiencies, particularly as to the initial reference level price and the failure of the MISO tariff to count capacity sold in neighboring capacity markets toward meeting Local Clearing Requirements in effect for the zones where capacity is physically located. The matter remains pending at FERC.

West Region

CAISO

Carlsbad Energy Center — On May 21, 2015, the CPUC approved the Carlsbad Energy Center PPTA for a 500 MW five unit natural gas peaking plant. Several parties filed administrative appeals of the CPUC's decision, which remain pending. Additionally, on July 30, 2015, the CEC approved an amendment to the design of the Carlsbad Energy Center.

California Station Power — On December 18, 2012, the D.C. Circuit upheld a decision by FERC disclaiming jurisdiction over how the states impose retail station power charges. This decision allowed the CPUC to establish retail charges for future station power consumption. Due to reservation-of-rights language in the California utilities' state-jurisdictional station power tariffs, the District Court's ruling arguably requires California generators to pay state-imposed retail charges back to the date of enrollment by the facilities in the CAISO's station period program. The CPUC approved revised station power tariffs in the SCE and PG&E service territories effective August 30, 2010. On April 10, 2015, the CPUC denied the final rehearing of the matter.

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 governmental authorizations to build and operate power plants. NRG is also subject to laws and regulations surrounding 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 Company’s environmental matters are described in the Company’s 2014 Form 10-K in Item 1, Business — Environmental Matters and Item 1A, Risk Factors. These matters have been updated in Note 15, Environmental Matters, to the Condensed Consolidated Financial Statements of this Form 10-Q as found in Item 1.

Changes in Accounting Standards

See Note 2, Summary of Significant Accounting Policies, to this Form 10-Q as found in Item 1 for a discussion of recent accounting developments.

Consolidated Results of Operations

The following table provides selected financial information for the Company:



	Three months ended June 30,								Six months ended June 30,
(In millions except otherwise noted)	2015			2014			Change %		2015			2014			Change %
Operating Revenues
Energy revenue^(a)	$	1,231		$	1,094		13	%	$	2,907		$	2,732		6	%
Capacity revenue ^(a)	524			563			(7	)	1,012			1,064			(5	)
Retail revenue	1,684			1,879			(10	)	3,347			3,404			(2	)
Mark-to-market for economic hedging activities	(113		)	(48		)	(135	)	(200		)	(379		)	47
Contract amortization	(12		)	2			N/M		(20		)	6			(433	)
Other revenues ^(b)	83			131			(37	)	177			280			(37	)
Total operating revenues	3,397			3,621			(6	)	7,223			7,107			2
Operating Costs and Expenses
Cost of sales ^(c)	1,793			2,024			(11	)	3,927			4,246			(8	)
Mark-to-market for economic hedging activities	(110		)	71			(255	)	81			8			N/M
Contract and emissions credit amortization ^(c)	—			6			(100	)	4			21			(81	)
Other cost of operations	751			727			3		1,484			1,290			15
Total cost of operations	2,434			2,828			(14	)	5,496			5,565			(1	)
Depreciation and amortization	396			386			3		791			721			10
Selling, general and administrative	291			257			13		554			479			16
Acquisition-related transaction and integration costs	3			40			(93	)	13			52			(75	)
Development activity expenses	41			21			95		75			40			88
Total operating costs and expenses	3,165			3,532			(10	)	6,929			6,857			1
Gain on postretirement benefits curtailment and sale of assets	—			—			—		14			19			(26	)
Operating Income	232			89			161		308			269			14
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	8			14			43		5			21			(76	)
Other income, net	4			5			(20	)	23			16			44
Loss on debt extinguishment	(7		)	(40		)	(83	)	(7		)	(81		)	(91	)
Interest expense	(263		)	(274		)	(4	)	(564		)	(529		)	7
Total other expense	(258		)	(295		)	(13	)	(543		)	(573		)	(5	)
Loss before Income Taxes	(26		)	(206		)	87		(235		)	(304		)	23
Income tax benefit	(17		)	(126		)	(87	)	(90		)	(157		)	43
Net Loss	(9		)	(80		)	89		(145		)	(147		)	1
Less: Net income/(loss) attributable to noncontrolling interest and redeemable noncontrolling interest	5			17			(71	)	(11		)	6			(283	)
Net Loss Attributable to NRG Energy, Inc.	$	(14	)	$	(97	)	86		$	(134	)	$	(153	)	12
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	$	2.64		$	4.67		(43	)%	$	2.81		$	4.80		(41	)%

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

(b) Includes unrealized trading gains and losses.

Management’s discussion of the results of operations for the three months ended June 30, 2015, and 2014

Loss before income taxes — The pre-tax loss of $26 million for the three months ended June 30, 2015, compared to pre-tax loss of $206 million for the three months ended June 30, 2014, primarily reflects:


•	an increase in gross margin of $104 million comprised of an increase in NRG Home Retail gross margin of $70 million and an increase in NRG Yield gross margin of $62 million, offset in part by decreases in NRG Business gross margin of $17 million, NRG Home Solar gross margin of $4 million and NRG Renew gross margin of $7 million;


•	a current year increase from net mark to market results for economic hedges activity of $116 million;


•	a net decrease in other expense of $37 million primarily related to a decrease in interest expense and loss on debt extinguishment; offset by


•	a net increase in operating costs of $51 million including operations and maintenance expense, depreciation and amortization, selling, general and administrative costs, acquisition related costs, and development expense.

Net loss — The decrease in net loss of $71 million primarily reflects the drivers discussed above, including an income tax benefit for the three months ended June 30, 2015, of $17 million, compared to an income tax benefit of $126 million in the comparable period in 2014.

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, 2015, and 2014:



	Average on Peak Power Price ($/MWh) ^(a)
	Three months ended June 30,
Region	2015		2014
Gulf Coast ^(b)
ERCOT - Houston	$	27.98	$	44.70
ERCOT - North	27.81		40.54
MISO - Louisiana Hub	39.15		50.96
East
NY J/NYC	34.68		46.99
NY A/West NY	38.92		44.87
NEPOOL	28.40		44.31
PEPCO (PJM)	44.42		54.02
PJM West Hub	39.23		50.58
West
CAISO - NP15	39.29		52.50
CAISO - SP15	27.62		47.41

(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.

NRG Business gross margin

The following is a discussion of gross margin for NRG Business, adjusted to eliminate intersegment activity, primarily with NRG Home.



	Three months ended June 30, 2015
(In millions except otherwise noted)	Gulf Coast			East			West			B2B			Subtotal			Eliminations			Total
Energy revenue	$	634		$	582		$	46		$	—		$	1,262		$	—		$	1,262
Capacity revenue	63			326			52			1			442			—			442
Retail revenue	—			—			—			378			378			—			378
Other revenue	17			9			3			52			81			(16		)	65
Operating revenue	714			917			101			431			2,163			(16		)	2,147
Cost of sales	(365		)	(394		)	(35		)	(374		)	(1,168		)	—			(1,168		)
Gross Margin	$	349		$	523		$	66		$	57		$	995		$	(16	)	$	979
Business Metrics
MWh sold (in thousands) ^(a)	15,331			10,443			1,036
MWh generated (in thousands)	14,546			10,821			804
Electricity sales volume — GWh										4,896
Average customer count (in thousands, metered locations)										77
(a) MWh sold excludes generation at facilities that generate revenue under capacity agreements.



	Three months ended June 30, 2014
(In millions except otherwise noted)	Gulf Coast			East			West			B2B			Subtotal			Eliminations			Total
Energy revenue	$	710		$	681		$	65		$	—		$	1,456		$	—		$	1,456
Capacity revenue	48			324			71			1			444			—			444
Retail revenue	—			—			—			466			466			—			466
Other revenue	25			13			3			56			97			(13		)	84
Operating revenue	783			1,018			139			523			2,463			(13		)	2,450
Cost of sales	(465		)	(468		)	(57		)	(461		)	(1,451		)	—			(1,451		)
Gross Margin	$	318		$	550		$	82		$	62		$	1,012		$	(13	)	$	999
Business Metrics
MWh sold (in thousands) ^(a)	15,791			12,346			698
MWh generated (in thousands)	14,563			12,361			942
Electricity sales volume — GWh										5,633
Average customer count (in thousands, metered locations)										75
(a) MWh sold excludes generation at facilities that generate revenue under capacity agreements.

	Three months ended June 30,
Weather Metrics	Gulf Coast			East			West
2015
CDDs ^(a)	1,783			1,149			195
HDDs ^(a)	94			1,524			315
2014
CDDs	1,777			932			250
HDDs	191			1,673			226
10 year average
CDDs	1,935			1,000			160
HDDs	161			1,705			383

(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.

NRG Business gross margin — decreased by $17 million, including intercompany sales, during the three months ended June 30, 2015, compared to the same period in 2014, due to:



	(In millions)
Increase in Gulf Coast region	$	31
Decrease in East region	(27		)
Decrease in West region	(16		)
Decrease in B2B	(5		)
	$	(17	)

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



	(In millions)
Higher gross margin due to higher average realized prices in Texas, reflecting realized gains on settled hedges	$	22
Higher capacity revenue due to change in market conditions for certain South Central facilities	15
Higher gross margin from a 19% increase in nuclear generation driven by reduced unplanned outages	12
Lower gross margin due to lower coal generation resulting from planned outages for the gas conversion at Big Cajun Unit 2 and installation of back-end controls at Units 1 and 3	(24		)
Other	6
	$	31

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



	(In millions)
Lower gross margin due to a 12% decrease in generation resulting from the timing of outages and the impact of milder weather on volume	$	(49	)
Lower gross margin due to the deactivation of certain units at Gilbert, Glen Gardner, Werner and Shawville	(33		)
Higher gross margin due to increased capacity prices, primarily at the Midwest Generation facilities	23
Higher gross margin due to the impact of decreased natural gas prices on fuel costs, offset in part by lower power prices	20
Higher gross margins as a result of new load contracts starting in second quarter 2014	12
	$	(27	)

The decrease in gross margin in the West region was driven by:



	(In millions)
Lower capacity gross margin due to a decrease in contracted capacity volume and a decrease in price due to higher reserve margins driven by more competition	$	(11	)
Lower capacity gross margin due to the retirement of Coolwater	(7		)
Other	2
	$	(16	)

The decrease in B2B gross margin was driven by:



	(In millions)
Lower gross margin due to a decrease in customer usage and lower unit margins due to the competitive nature of the C&I business	$	(5	)
	$	(5	)

NRG Home Retail gross margin

The following is a discussion of gross margin for NRG Home Retail.



	Three months ended June 30,
(In millions except otherwise noted)	2015			2014
Home Retail revenue	$	1,267		$	1,316
Supply management revenue	31			88
Operating revenue^(a)	$	1,298		$	1,404
Cost of sales ^(b)	(910		)	(1,086		)
Gross Margin	$	388		$	318

Business Metrics
Electricity sales volume — GWh - Gulf Coast	8,400			8,408
Electricity sales volume — GWh - All other regions	1,778			2,241
Average NRG Home Retail customer count (in thousands)^(c)	2,780			2,887
Ending NRG Home Retail customer count (in thousands)^(c)	2,766			2,877


(a)	Includes intercompany sales of $1 million and $1 million in 2015 and 2014, respectively, representing sales from Retail to the Gulf Coast region.


(b)	Includes intercompany purchases of $279 million and $530 million in 2015 and 2014.


(c)	Excludes Discrete Customers.

NRG Home Retail gross margin increased $70 million for the three months ended June 30, 2015, compared to the same period in 2014, due to:



	(In millions)
Increase in margins due to lower supply costs driven by a decrease in natural gas prices	$	84
Unfavorable impact due to lower volumes from the expected attrition of customers from the acquisition of Dominion’s competitive retail electric business in March 2014 combined with a decrease in customer usage	(14		)
	$	70

NRG Renew gross margin

The following is a discussion of gross margin for NRG Renew.



	Three months ended June 30,
	2015			2014
(In millions except otherwise noted)
Operating revenue	$	148		$	152
Cost of sales	(5		)	(2		)
Gross margin	$	143		$	150
Business Metrics
MWh sold (in thousands)	1,711			1,928
MWh generated (in thousands)	1,726			1,967

NRG Renew gross margin decreased $7 million for the three months ended June 30, 2015, compared to the same period in 2014, primarily as a result of decreased wind availability, offset in part by improved performance at the Ivanpah project, as it continues to ramp up to full production capabilities.

NRG Yield gross margin

The following is a discussion of gross margin for NRG Yield.



	Three months ended June 30,
	2015			2014
(In millions except otherwise noted)
Operating revenue	$	235		$	174
Cost of sales	(17		)	(18		)
Gross margin	$	218		$	156
Business Metrics
MWh sold (in thousands)	1,264			615
MWht sold (in thousands)	434			442

NRG Yield gross margin increased $62 million for the three months ended June 30, 2015, compared the same period in 2014, primarily related to the acquisition of the Alta Wind Assets in August 2014.

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 $116 million during the three months ended June 30, 2015, compared to the same period in 2014.

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, 2015
				NRG Business
	NRG Home			Gulf Coast			East			West			B2B			NRG Renew			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 NRG Home, NRG Business and NRG Yield.



	Three months ended June 30, 2014
				NRG Business
	NRG Home			Gulf Coast			East			West			B2B			NRG Renew			NRG Yield		Elimination^(a)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized gains on settled positions related to economic hedges	$	—		$	(38	)	$	(5	)	$	(1	)	$	—		$	(1	)	$	—	$	(39	)	$	(84	)
Reversal of acquired gain positions related to economic hedges	—			—			(89		)	—			—			—			—		—			(89		)
Net unrealized gains/(losses) on open positions related to economic hedges	—			255			(43		)	2			—			2			—		(91		)	125
Total mark-to-market gains/(losses) in operating revenues	$	—		$	217		$	(137	)	$	1		$	—		$	1		$	—	$	(130	)	$	(48	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses on settled positions related to economic hedges	$	22		$	1		$	4		$	—		$	13		$	—		$	—	$	39		$	79
Reversal of acquired loss positions related to economic hedges	—			—			5			—			—			—			—		—			5
Net unrealized (losses)/gains on open positions related to economic hedges	(197		)	(8		)	45			—			(86		)	—			—		91			(155		)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(175	)	$	(7	)	$	54		$	—		$	(73	)	$	—		$	—	$	130		$	(71	)


(a)	Represents the elimination of the intercompany activity between NRG Home, NRG Business, and NRG Renew.

Mark-to-market results consist of unrealized gains and losses. The settlement of these transactions is reflected in the same caption as the items being hedged.

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

For the three months ended 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.

For the three months ended June 30, 2014, the $48 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 heat rates, which more than offset increases in East power and natural gas prices. The $71 million loss in operating costs and expenses from economic hedge positions was driven primarily by a decrease in the value of open positions as a result of decreases in ERCOT power prices, partially offset by increases in coal prices, the reversal of previously recognized unrealized losses on contracts that settled during the period and the reversal of acquired contracts.

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, 2015, and 2014. 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.



	Three months ended June 30,
(In millions)	2015			2014
Trading gains/(losses)
Realized	$	25		$	19
Unrealized	(24		)	—
Total trading gains	$	1		$	19

In addition, trading activities reflect a decrease in gross margin of $19 million, reflected in the Corporate segment, for the three months ended June 30, 2015, as compared to the three months ended June 30, 2014.

Other Operating Costs



	NRG Business								NRG Home Retail		NRG Home Solar		NRG Renew		NRG Yield		Eliminations
	Gulf Coast		East		West		B2B		NRG Home Retail		NRG Home Solar		NRG Renew		NRG Yield		Eliminations			Total
	(In millions)
Three months ended June 30, 2015	$	201	$	323	$	42	$	26	$	73	$	16	$	44	$	51	$	(25	)	$	751
Three months ended June 30, 2014	189		333		41		30		66		9		46		35		(22		)	727

Other operating costs increased by $24 million for the three months ended June 30, 2015, compared to the same period in 2014, due to:



	(In millions)
Increase in operations and maintenance expense related to planned outages at Cottonwood and Big Cajun	$	29
Increase due to the acquisition of the Alta Wind Assets in August 2014	13
Increase for Home Solar due to personnel costs for installation and maintenance of systems	7
Decrease in operations and maintenance expense related to timing of planned outages at Texas gas and coal plants	(18		)
Decrease in operations and maintenance expense at Midwest Generation due to lower variable costs from decreased run time	(12		)
Other	5
	$	24

Depreciation and Amortization

Depreciation and amortization increased by $10 million for the three months ended June 30, 2015, compared to the same period in 2014, primarily due to additional depreciation expense of $19 million from the acquisition of the Alta Wind Assets, offset by a decrease in depreciation for facilities that were deactivated in 2015.

Selling, General and Administrative Expenses

Selling, general and administrative expenses is comprised of the following:



	Three months ended June 30,
(In millions)	2015		2014
General and administrative expenses	$	162	$	175
Selling and marketing expenses	129		82
	$	291	$	257

General and administrative expenses decreased by $13 million for the three months ended June 30, 2015, compared to the same period in 2014, due primarily to continued integration and cost management efforts. Selling and marketing expenses increased by $47 million compared to the prior year primarily due to the acquisitions of RDS and Pure Energies, which provided NRG Home Solar with an installation team, internet and telephonic sales team and certain sales channels.

Development Activity Expenses

Development activity expenses increased by $20 million for the three months ended June 30, 2015, compared to the same period in 2014, due to an increase in development activities, primarily for Utility Scale Solar and Distributed Solar and NRG eVgo.

Equity in Earnings of Unconsolidated Affiliates

NRG's equity in earnings of unconsolidated affiliates decreased by $6 million for the three months ended June 30, 2015, as compared to the same period in 2014, due primarily to a change in the value of gas swaps at certain equity method investments and the sale on April 30, 2014 of certain cogeneration facilities acquired in the EME acquisition.

Interest Expense

NRG's interest expense decreased by $11 million for the three months ended June 30, 2015, compared to the same period in 2014 due to the following:



	(In millions)
Decrease in derivative interest expense from changes in fair value of interest rate swaps	$	(21	)
Decrease due to the redemption of 7.625% and 8.5% Senior Notes due 2019	(11		)
Increase due to the acquisition of the Alta Wind Assets in August 2014	21
Increase due to issuance of NRG Yield Operating LLC 2024 Senior Notes issued in 2014	6
Other	(6		)
	$	(11	)

Income Tax Benefit

For the three months ended June 30, 2015, NRG recorded an income tax benefit of $17 million on a pre-tax loss of $26 million. For the same period in 2014, NRG recorded an income tax benefit of $126 million on a pre-tax loss of $206 million. The effective tax rate was 65.4% and 61.2% for the three months ended June 30, 2015, and 2014, respectively.

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.

For the three months ended June 30, 2014, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the impact of production tax credits from our wind assets and the recognition of uncertain tax benefits during the quarter.

Net income attributable to noncontrolling interests and redeemable noncontrolling interests

For the three months ended June 30, 2015, and 2014, net income attributable to noncontrolling interests primarily reflects NRG Yield, Inc.'s share of net income offset by net losses allocated to tax equity investors in tax equity arrangements using the hypothetical liquidation at book value, or HLBV, method.

Management’s discussion of the results of operations for the six months ended June 30, 2015, and 2014

Loss before income taxes — The pre-tax loss of $235 million for the six months ended June 30, 2015, compared to pre-tax loss of $304 million for the six months ended June 30, 2014, primarily reflects:


•	an increase in gross margin of $334 million comprised of an increase in NRG Business gross margin of $4 million, an increase in NRG Home Retail gross margin of $143 million, an increase in NRG Home Solar gross margin of $20 million, an increase in NRG Yield gross margin of $121 million and an increase in NRG Renew gross margin of $46 million;


•	a current year increase from net mark to market results for economic hedges activity of $106 million;


•	a net increase in operating costs of $335 million including operations and maintenance expense, depreciation and amortization, selling, general and administrative costs, acquisition related costs, and development expense; offset by


•	a net decrease in other expenses of $30 million primarily related to a decrease of $74 million in loss on debt extinguishment offset by an increase in interest expense of $35 million.

Net loss — The decrease in net loss of $2 million primarily reflects the drivers discussed above, including an income tax benefit for the six months ended June 30, 2015, of $90 million, compared to an income tax benefit of $157 million in the comparable period in 2014.

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, 2015, and 2014:



	Average on Peak Power Price ($/MWh) ^(a)
	Six months ended June 30,
Region	2015		2014
Gulf Coast ^(b)
ERCOT - Houston	$	27.22	$	51.22
ERCOT - North	27.17		50.37
MISO - Louisiana Hub	38.20		58.96
East
NY J/NYC	58.11		101.55
NY A/West NY	46.35		75.13
NEPOOL	58.62		105.75
PEPCO (PJM)	52.97		93.59
PJM West Hub	48.31		81.44
West
CAISO - NP15	36.92		52.87
CAISO - SP15	30.19		50.59

(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.

NRG Business gross margin

The following is a discussion of gross margin for NRG Business, adjusted to eliminate intersegment activity, primarily with NRG Home.



	Six months ended June 30, 2015
(In millions except otherwise noted)	Gulf Coast			East			West			B2B			Subtotal			Eliminations			Total
Energy revenue	$	1,250		$	1,677		$	70		$	—		$	2,997		$	—		$	2,997
Capacity revenue	121			645			89			1			856			—			856
Retail revenue	—			—			—			726			726			—			726
Other revenue	39			36			6			104			185			(32		)	153
Operating revenue	1,410			2,358			165			831			4,764			(32		)	4,732
Cost of sales	(716		)	(1,075		)	(52		)	(720		)	(2,563		)	—			(2,563		)
Gross Margin	$	694		$	1,283		$	113		$	111		$	2,201		$	(32	)	$	2,169
Business Metrics
MWh sold (in thousands) ^(a)	30,537			25,484			1,646
MWh generated (in thousands)	28,931			25,639			1,230
Electricity sales volume — GWh										9,482
Average customer count (in thousands, metered locations)										77
(a) MWh sold excludes generation at facilities that generate revenue under capacity agreements.



	Six months ended June 30, 2014
(In millions except otherwise noted)	Gulf Coast			East			West			B2B			Subtotal			Eliminations			Total
Energy revenue	$	1,327		$	1,847		$	115		$	—		$	3,289		$	—		$	3,289
Capacity revenue	128			629			132			1			890			—			890
Retail revenue	—			—			—			909			909			—			909
Other revenue	46			67			4			99			216			(26		)	190
Operating revenue	1,501			2,543			251			1,009			5,304			(26		)	5,278
Cost of sales	(878		)	(1,217		)	(103		)	(909		)	(3,107		)	—			(3,107		)
Gross Margin	$	623		$	1,326		$	148		$	100		$	2,197		$	(26	)	$	2,171
Business Metrics
MWh sold (in thousands) ^(a)	30,936			24,934			987
MWh generated (in thousands)	28,812			24,876			1,286
Electricity sales volume — GWh										11,045
Average customer count (in thousands, metered locations)										75
(a) MWh sold excludes generation at facilities that generate revenue under capacity agreements.

	Six months ended June 30,
Weather Metrics	Gulf Coast			East			West
2015
CDDs ^(a)	1,886			1,267			212
HDDs ^(a)	2,663			10,379			1,128
2014
CDDs	1,864			1,024			252
HDDs	2,814			10,162			1,099
10 year average
CDDs	2,114			1,096			162
HDDs	2,268			9,040			1,551

(a)

NRG Business gross margin — increased by $4 million, including intercompany sales, during the six months ended June 30, 2015, compared to the same period in 2014, due to:



	(In millions)
Increase in Gulf Coast region	$	71
Decrease in East region	(43		)
Decrease in West region	(35		)
Increase in B2B	11
	$	4

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



	(In millions)
Higher gross margin due to higher average realized prices in Texas, reflecting realized gains on settled hedges	$	87
Higher gross margin from a 12% increase in nuclear generation driven by reduced planned and unplanned outages	18
Lower gross margin due to lower coal generation primarily driven by planned outages at Big Cajun Units 2 and 3 and lower economic dispatch at Texas coal facilities	(35		)
Other	1
	$	71

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



	(In millions)
Lower gross margin due to a 20% decrease in generation resulting from the impact of milder weather on volume and the timing of outages	$	(129	)
Lower gross margin due to plant layups at Shawville and deactivations at Gilbert, Glen Gardner and Werner	(33		)
Lower gross margin due to a decrease in realized PJM prices, partially offset by an increase in New York and New England hedged capacity prices	(20		)
Higher gross margin due to the EME acquisition in April 2014	121
Higher gross margins as a result of new load contracts starting in the second quarter of 2014, partially offset by a decrease in pricing for power purchases for existing load-serving contracts	48
Changes in commercial optimization activities and other	(30		)
	$	(43	)

The decrease in gross margin in the West region was driven by:



	(In millions)
Lower capacity gross margin due to a decrease in contracted capacity volume and price due to higher reserve margins driven by more competition in certain areas	$	(34	)
Lower capacity gross margin due to the retirement of Coolwater	(11		)
Higher gross margin due to the EME acquisition	9
Other	1
	$	(35	)

The increase in B2B gross margin was driven by:



	(In millions)
Higher gross margin in 2015, due to the higher supply costs incurred in 2014 due to extreme weather	$	14
Lower gross margin due to a decrease in customer usage	(4		)
Other	1
	$	11

NRG Home Retail gross margin

The following is a discussion of gross margin for NRG Home Retail.



	Six months ended June 30,
(In millions except otherwise noted)	2015			2014
Home Retail revenue	$	2,549		$	2,352
Supply management revenue	61			134
Operating revenue ^(a)	$	2,610		$	2,486
Cost of sales ^(b)	(1,881		)	(1,900		)
Gross Margin	$	729		$	586

Business Metrics
Electricity sales volume — GWh - Gulf Coast	15,948			15,024
Electricity sales volume — GWh - All other regions	4,392			3,458
Average NRG Home Retail customer count (in thousands)^(c)	2,799			2,559
Ending NRG Home Retail customer count (in thousands)^(c)	2,766			2,877


(a)	Includes intercompany sales of $2 million and $3 million in 2015 and 2014, respectively, representing sales from Retail to the Gulf Coast region.


(b)	Includes intercompany purchases of $529 million and $896 million in 2015 and 2014.


(c)	Excludes Discrete Customers.

NRG Home Retail gross margin increased $143 million for the six months ended June 30, 2015, compared to the same period in 2014, due to:



	(In millions)
Increase in margins due to lower supply costs partially offset by lower rates to customers driven by a decrease in natural gas prices; Increased sales to discrete and recurring customers also contributed to the favorable impact	$	64
Favorable impact of lower supply costs on the higher sales volumes resulting from weather conditions in 2015	49
Favorable impact from higher customer counts from the acquisition of Dominion's competitive retail electric business in March 2014	30
	$	143

NRG Renew gross margin

The following is a discussion of gross margin for NRG Renew.



	Six months ended June 30,
	2015			2014
(In millions except otherwise noted)
Operating revenue	$	257		$	206
Cost of sales	(9		)	(4		)
Gross margin	$	248		$	202
Business Metrics
MWh sold (in thousands)	3,119			2,420
MWh generated (in thousands)	3,173			2,408

NRG Renew gross margin increased $46 million for the six months ended June 30, 2015, compared to the same period in 2014. The increase in gross margin was the result of the EME acquisition in April 2014 and improved performance at the Ivanpah project, as it continues to ramp up to full production capabilities.

NRG Yield gross margin

The following is a discussion of gross margin for NRG Yield.



	Six months ended June 30,
	2015			2014
(In millions except otherwise noted)
Operating revenue	$	420		$	314
Cost of sales	(38		)	(53		)
Gross margin	$	382		$	261
Business Metrics
MWh sold (in thousands)	2,031			898
MWht sold (in thousands)	1,051			1,109

NRG Yield gross margin increased $121 million for the six months ended June 30, 2015, compared the same period in 2014. The increase in gross margin was primarily related to the acquisition of the Alta Wind Assets in August 2014 as well as the acquisition of the Walnut Creek, Tapestry Wind and Laredo Ridge projects from NRG, which were acquired in the EME acquisition in April 2014.

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 $106 million during the six months ended June 30, 2015, compared to the same period in 2014.

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, 2015
				NRG Business
	NRG Home			Gulf Coast			East			West			B2B			NRG Renew			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 NRG Home, NRG Business and NRG Yield.



	Six months ended June 30, 2014
				NRG Business
	NRG Home			Gulf Coast			East			West			B2B			NRG Renew		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	$	—		$	(90	)	$	16		$	(1	)	$	—		$	—	$	—	$	(75	)	$	(150	)
Reversal of acquired gain positions related to economic hedges	—			—			(168		)	(1		)	—			—		—		—			(169		)
Net unrealized gains/(losses) on open positions related to economic hedges	—			63			(224		)	1			(1		)	—		—		101			(60		)
Total mark-to-market (losses)/gains in operating revenues	$	—		$	(27	)	$	(376	)	$	(1	)	$	(1	)	$	—	$	—	$	26		$	(379	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses on settled positions related to economic hedges	$	36		$	1		$	8		$	—		$	28		$	—	$	—	$	75		$	148
Reversal of acquired loss positions related to economic hedges	—			—			7			—			—			—		—		—			7
Net unrealized (losses)/gains on open positions related to economic hedges	(107		)	(3		)	31			—			17			—		—		(101		)	(163		)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(71	)	$	(2	)	$	46		$	—		$	45		$	—	$	—	$	(26	)	$	(8	)


(a)	Represents the elimination of the intercompany activity between NRG Home, NRG Business, and NRG Renew.

Mark-to-market results consist of unrealized gains and losses. The settlement of these transactions is reflected in the same caption as the items being hedged.

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

For the 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.

For the six months ended June 30, 2014, the $379 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, in addition to a decrease in value of open positions as a result of increases in forward natural gas and East power prices, partially offset by decreases in ERCOT heat rates. The $8 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 heat rates, 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, 2015, and 2014. 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.



	Six months ended June 30,
(In millions)	2015			2014
Trading gains/(losses)
Realized	$	50		$	62
Unrealized	(46		)	15
Total trading gains	$	4		$	77

In addition, trading activities reflect a decrease in gross margin of $28 million, reflected in the Corporate segment, for the six months ended June 30, 2015 as compared to the six months ended June 30, 2014.

Other Operating Costs



	NRG Business								NRG Home Retail		NRG Home Solar		NRG Renew		NRG Yield		Eliminations
	Gulf Coast		East		West		B2B		NRG Home Retail		NRG Home Solar		NRG Renew		NRG Yield		Eliminations			Total
	(In millions)
Six months ended June 30, 2015	$	401	$	633	$	89	$	55	$	147	$	17	$	87	$	104	$	(49	)	$	1,484
Six months ended June 30, 2014	390		549		83		57		125		9		68		60		(51		)	1,290

Other operating costs increased by $194 million for the six months ended June 30, 2015, compared to the same period in 2014, due to:



	(In millions)
Increase due to the acquisition of EME in April 2014 and the Alta Wind Assets in August 2014	$	133
Increase in operations and maintenance expense related to planned outages at Cottonwood and Big Cajun	22
Increase in property taxes in part due to a tax settlement in the prior year for Bowline	11
Increase in operating costs for NRG Home Retail related to the acquisition of Dominion in 2014	9
Increase for Home Solar due to personnel costs for installation and maintenance of systems	8
Increase in operations and maintenance expense related to El Segundo Energy Center's forced outage in 2015	6
Increase in operations and maintenance expense related to Ivanpah reaching commercial operations in early 2014	5
	$	194

Depreciation and Amortization

Depreciation and amortization increased by $70 million for the six months ended June 30, 2015, compared to the same period in 2014, primarily due to an increase of $19 million due to the acquisition of EME and an increase of $35 million due to the acquisition of the Alta Wind Assets.

Selling, General and Administrative Expenses

Selling, general and administrative expenses is comprised of the following:



	Six months ended June 30,
(In millions)	2015		2014
General and administrative expenses	$	317	$	327
Selling and marketing expenses	237		152
	$	554	$	479

General and administrative expenses decreased by $10 million for the six months ended June 30, 2015, compared to the same period in 2014, due primarily to continued integration and cost management efforts. Selling and marketing expenses increased by $85 million compared to the prior year primarily due to the acquisitions of RDS and Pure Energies, which provided NRG Home Solar with an installation team, internet and telephonic sales team and certain sales channels.

Development Activity Expenses

Development activity expenses increased by $35 million for the six months ended June 30, 2015, compared to the same period in 2014, due to increased development activities, primarily for Utility Scale Solar and Distributed Solar and NRG eVgo.

Equity in Earnings of Unconsolidated Affiliates

NRG's equity in earnings of unconsolidated affiliates decreased by $16 million for the six months ended June 30, 2015, as compared to the same period in 2014, due primarily to a change in the value of gas swaps at certain equity method investments and the sale on April 30, 2014, of certain cogeneration facilities acquired in the EME acquisition.

Interest Expense

NRG's interest expense increased by $35 million for the six months ended June 30, 2015, compared to the same period in 2014 due to the following:



	(In millions)
Increase due to the acquisition of EME in April 2014 and Alta Wind Assets in August 2014	$	55
Increase for the 2022 Senior Notes issued in January 2014 and 2024 Senior Notes issued in April 2014	24
Increase due to issuance of NRG Yield Operating LLC 2024 Senior Notes issued in 2014	14
Decrease due to the redemption of 7.625% and 8.5% Senior Notes due 2019	(34		)
Decrease in derivative interest expense due to changes in the fair value of interest rate swaps	(18		)
Other	(6		)
	$	35

Income Tax Benefit

For the six months ended June 30, 2015, NRG recorded an income tax benefit of $90 million on a pre-tax loss of $235 million. For the same period in 2014, NRG recorded an income tax benefit of $157 million on a pre-tax loss of $304 million. The effective tax rate was 38.3% and 51.6% for the six months ended June 30, 2015, and 2014, respectively.

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.

For the six months ended June 30, 2014, 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 and the recognition of uncertain tax benefits.

Net income attributable to noncontrolling interests and redeemable noncontrolling interests

For the six months ended June 30, 2015, and 2014, net income attributable to noncontrolling interests primarily reflects NRG Yield, Inc.'s share of net income for the period offset by net losses allocated to tax equity investors in tax equity arrangements using the HLBV method.

Liquidity and Capital Resources

Liquidity Position

As of June 30, 2015, and December 31, 2014, NRG's liquidity, excluding collateral received, was approximately $4.0 billion and $3.9 billion, respectively, comprised of the following:



(In millions)	June 30, 2015		December 31, 2014
Cash and cash equivalents	$	2,146	$	2,116
Restricted cash	433		457
Total	2,579		2,573
Total credit facility availability	1,409		1,367
Total liquidity, excluding collateral received	$	3,988	$	3,940

For the six months ended June 30, 2015, total liquidity, excluding collateral received, increased by $48 million. Changes in cash and cash equivalent balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents at June 30, 2015, were predominantly held in money market mutual funds and bank deposits.

Management believes that the Company's liquidity position and cash flows from operations will be adequate to finance operating and maintenance capital expenditures, to fund dividends to NRG's common and preferred stockholders, and to fund other liquidity commitments, both in the near and longer term. 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 $2.1 billion of cash and cash equivalents of the Company as of June 30, 2015, $217 million and $283 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, 2015, 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.

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, 2015, GenOn did not meet the consolidated debt ratio component of the restricted payments test.

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 and cash flows from operations. As described in Note 7, Debt and Capital Leases, to this Form 10-Q and Note 12, Debt and Capital Leases, to the Company's 2014 Form 10-K, the Company's financing arrangements consist mainly of the Senior Credit Facility, the Senior Notes, the GenOn Senior Notes, the GenOn Americas Generation Senior Notes, and project-related financings.

Cash Proceeds from Sale of Assets to NRG Yield, Inc.

On January 2, 2015, the Company sold the following facilities to NRG Yield, Inc.: (i) Walnut Creek, a 485 MW natural gas facility located in City of Industry, California; (ii) the Tapestry projects, which include Buffalo Bear, a 19 MW wind facility in Buffalo, Oklahoma; Pinnacle, a 55 MW wind facility in Keyser, West Virginia; and Taloga, a 130 MW wind facility in Putnam, Oklahoma; and (iii) Laredo Ridge, an 80 MW wind facility located in Petersburg, Nebraska. 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. The sale was recorded as a transfer of entities under common control and the related assets were transferred at carrying value. NRG Yield, Inc. utilized cash on hand and borrowings under its revolving credit facility of $210 million to fund the acquisition.

Offer of Assets to NRG Yield, Inc.

The Company offered NRG Yield, Inc. the opportunity to purchase 75% of NRG Wind TE Holdco LLC, which owns a portfolio of twelve wind facilities totaling 814 net MW.

Cash Grants

As of June 30, 2015, the Company had a net renewable energy grant receivable of $19 million, net of sequestration. The receivable balance reflects a reduction as compared to December 31, 2014 due to a cash grant of approximately $51 million, net of sequestration, awarded by the U.S. Treasury Department to the Company for the Ivanpah project in June 2015. NRG believes it has complied with all material obligations under the 1603 Cash Grant Program and is working with the U.S. Treasury Department to obtain payment on the outstanding 1603 applications the Company or its subsidiaries have submitted.

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 lien program. The 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 and Midwest Generation's other assets and NRG Yield, Inc.'s 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 lien counterparties may have a claim on its assets to the extent market prices exceed the hedged prices. As of June 30, 2015, all hedges under the first liens were in-the-money on a counterparty aggregate basis.

The following table summarizes the amount of MWs hedged against the Company's coal and nuclear assets and as a percentage relative to the Company's coal and nuclear capacity under the first lien structure as of June 30, 2015:



Equivalent Net Sales Secured by First Lien Structure ^(a)	2015		2016		2017		2018		2019
In MW	700		3,395		1,299		177		—
As a percentage of total net coal and nuclear capacity ^(b)	12	%	59	%	23	%	3	%	—	%


(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.

The Company may offer certain assets to NRG Yield, Inc. pursuant to the Right of First Offer Agreement. Should NRG Yield, Inc. purchase the assets offered, the Company intends to allocate cash in an amount approximately equal to the proceeds received from the sale of assets to NRG Yield, Inc. equally among common share repurchases, corporate debt reduction and investment in contracted assets that could be considered for future sale to NRG Yield, Inc.

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, 2015, commercial operations had total cash collateral outstanding of $299 million, and $747 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, 2015, total collateral held from counterparties was $10 million in cash and $62 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.

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.

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, 2015, and the currently estimated capital expenditure and growth investments forecast for the remainder of 2015.



	Maintenance			Environmental			Growth Investments			Total
	(In millions)
NRG Business
Gulf Coast	$	102		$	52		$	7		$	161
East	66			100			19			185
West	2			—			11			13
B2B	3			—			1			4
NRG Home Retail	13			—			—			13
NRG Home Solar	—			—			68			68
NRG Renew	6			—			94			100
NRG Yield	6			—			2			8
Corporate	16			—			15			31
Total cash capital expenditures for the six months ended June 30, 2015	214			152			217			583
Other investments ^(a)	—			—			419			419
Funding from debt financing and NRG Yield equity issuance, net of fees	—			(25		)	(309		)	(334		)
Funding from third party equity partners	(16		)	—			(91		)	(107		)
Total capital expenditures and investments, net of financings	198			127			236			561

Estimated capital expenditures for the remainder of 2015	307			205			973			1,485
Other investments ^(a)	—			—			40			40
Funding from debt financing, net of fees	—			(12		)	(118		)	(130		)
Funding from third party equity partners and cash grants	(9		)	—			(282		)	(291		)
NRG estimated capital expenditures for the remainder of 2015, net of financings	$	298		$	193		$	613		$	1,104


(a)	Other investments includes restricted cash activity and $285 million for the acquisition of a 25% interest in the Desert Sunlight Solar Farm.

•

Environmental capital expenditures — For the six months ended June 30, 2015, the Company's environmental capital expenditures included SO₂ and particulate controls at the Powerton and Waukegan facilities, controls to satisfy MATS and NSR settlement at the Big Cajun II facility, Activated Carbon Injection mercury controls at the W.A. Parish facility, conversion of the Joliet facility to natural gas and NO_x controls for the Sayreville and Gilbert facilities.


•	Growth Investments capital expenditures — For the six months ended June 30, 2015, the Company's growth investment expenditures included $162 million for solar projects, $19 million for fuel conversions, $18 million for repowering projects and $18 million for the Company's other growth projects.

Environmental Capital Expenditures

In connection with the acquisition of EME, as further described in Note 3, Business Acquisitions and Dispositions, of this Form 10-Q, NRG has committed to fund up to $350 million in capital expenditures for plant modifications at Powerton and Joliet to comply with environmental regulations.

2015 Capital Allocation Program

During the second quarter of 2015, the Company established a capital allocation program that will apportion cash in an amount equal to the drop down proceeds received from NRG Yield, Inc. equally among share repurchases, corporate debt reduction and future NRG Yield, Inc. eligible projects.

Dividends

The following table lists the dividends paid during the six months ended June 30, 2015:



	Second Quarter 2015		First Quarter 2015
Dividends per Common Share	$	0.145	$	0.145

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.

Share Repurchases

The following table shows the Company's activity under the 2015 Capital Allocation Program:



Board Authorized Share Repurchases	Amount		Repurchases						Total Repurchases through		Remaining Authorized as of
(in millions, except share and per share data)	Authorized		Q4 2014		Q1 2015		Q2 2015		June 30, 2015		June 30, 2015
Initial Phase (Q4 2014)	$	100	$	44	$	56	$	—	$	100	$	—
Second Phase (Q1 2015)	100		—		23		77		100		—
Supplemental (Q2 2015)	81		—		—		30		30		51
Total	$	281	$	44	$	79	$	107	$	230	$	51
Average price per share			$	26.95	$	25.15	$	24.53	$	25.17
Shares repurchased			1,624,360		3,146,484		4,379,907		9,150,751

The purchases of common stock were made using cash on hand. In addition, as noted above, the Company plans to utilize a portion of future drop down proceeds to repurchase additional shares. The Company's purchases of common stock are subject to available capital, market conditions, and compliance with associated laws, regulations and other contractual obligations.

Fuel Repowerings and Conversions

The table below lists the currently projected repowering and conversion projects at certain NRG Business facilities:



Facility	Net Generation Capacity (MW)	Project Type	Fuel Type	Targeted COD
Fuel Conversions - Regulatory Compliance^(a)
Joliet Units 6, 7 and 8	1,326	Natural Gas Conversion	Natural Gas	Summer 2016
Total	1,326
Repowering and Fuel Conversions - Growth Investments^(b)
Avon Lake Units 7 and 9	732	Natural Gas Conversion	Natural Gas	Summer 2016
Dunkirk Units 2, 3 and 4	445	Natural Gas Conversion	Natural Gas	Spring 2016
Carlsbad Peakers (formerly Encina) Units 1, 2, 3, 4, 5 and GT^(c)	500	Repowering	Natural Gas	Fall 2017
Puente (formerly Mandalay) Units 1 and 2^(c)	262	Repowering	Natural Gas	Spring 2020
New Castle Units 3, 4 and 5	325	Natural Gas Conversion	Natural Gas	Summer 2016
Portland Units 1 and 2	401	Ultra-Low Sulfur Diesel Conversion	Ultra-Low Sulfur Diesel	Summer 2017
P.H. Robinson Peakers 1-6	330	Repowering	Natural Gas	Spring 2016
Shawville Units 1, 2, 3 and 4	597	Natural Gas Conversion	Natural Gas	Summer 2016
Total	3,592

Total Fuel Repowerings and Conversions	4,918

(a) The Company plans to incur environmental capital expenditures associated with controls to satisfy MATS. These expenditures are included in the Company's environmental capital expenditures estimate noted above.

(b) Expenditures incurred for these projects are included in the Company's growth investments capital expenditures.

Cash Flow Discussion

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



	Six months ended June 30,
	2015		2014			Change
	(In millions)
Net cash provided by operating activities	458		$	370		$	88
Net cash used in investing activities	(860	)	(1,753		)	893
Net cash provided by financing activities	429		634			(205		)

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	$	185
Increase in operating income adjusted for non-cash items	37
Other changes in working capital	(134		)
	$	88

Net Cash Used In Investing Activities

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



	(In millions)
Decrease in cash paid for acquisitions, due primarily to the acquisitions of EME and Dominion in 2014	$	1,787
Increase in equity investments, primarily related to 25% investment in Desert Sunlight in 2015	(388		)
Decrease in cash receipts, primarily reflecting the 2014 receipt of the CVSR grant	(368		)
Increase in capital expenditures related to maintenance and environmental projects	(76		)
Decrease in proceeds from sale of assets, due primarily to the sales of Kendall and Bayou Cove in 2014	(76		)
Decrease in restricted cash	9
Other	5
	$	893

Net Cash Provided By Financing Activities

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



	(In millions)
Net decrease in borrowing, offset by debt payments, which primarily reflects the issuance of the 2022 and 2024 Senior Notes in 2014	(950		)
Increase in repurchase of treasury stock	(186		)
Increase in payment of dividends	(11		)
Decrease in proceeds from issuance of stock	(7		)
Increase in cash contributions from noncontrolling interest due primarily to proceeds received from the NRG Yield, Inc. public offering	660
Increase in financing element of acquired derivatives	258
Decrease in cash paid for deferred financing costs	31
	$	(205	)

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

For the six months ended June 30, 2015, the Company had a total domestic pre-tax book loss of $245 million and foreign pre-tax book income of $10 million. As of June 30, 2015, the Company has cumulative domestic NOL carryforwards of $4.3 billion and cumulative state NOL carryforwards of $3.3 billion for financial statement purposes. In addition, NRG has cumulative foreign NOL carryforwards of $207 million, of which $1 million will expire in 2015 and of which $206 million do not have an expiration date.

In addition to these amounts, the Company has $72 million of tax effected uncertain tax benefits. As a result of the Company's tax position, and based on current forecasts, NRG anticipates income tax payments, primarily to state and local jurisdictions, of up to $35 million in 2015.

However, as the position remains uncertain for the $72 million of tax effected uncertain tax benefits, the Company has recorded a non-current tax liability of $56 million and may accrue the remaining balance as an increase to non-current liabilities until final resolution with the related taxing authority. The $56 million non-current tax liability for uncertain tax benefits is from positions taken on various state income tax returns, including accrued interest.

As of June 30, 2015, NRG has net deferred tax assets of $1.6 billion, which the Company believes is realizable primarily through the generation of future income before income taxes. In order to be able to consider future earnings in the assessment of the realizability of deferred tax assets, general accepted accounting principles indicate the Company should not have cumulative losses in the recent past. Should NRG determine it cannot utilize estimates of future earnings in its assessment, NRG could be required to establish a valuation allowance for up to the full amount of its deferred tax asset.

Off-Balance Sheet Arrangements

Obligations under Certain Guarantee Contracts

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

Retained or Contingent Interests

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

Derivative Instrument Obligations

The Company's 2.822% Preferred Stock includes a feature which is considered an embedded derivative in accordance with ASC 815. Although it is considered an embedded derivative, it is exempt from derivative accounting as it is excluded from the scope pursuant to ASC 815. As of June 30, 2015, based on the Company's stock price, the embedded derivative was out-of-the-money and had no redemption value.

Obligations Arising Out of a Variable Interest in an Unconsolidated Entity

Variable interest in equity investments — As of June 30, 2015, 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 8, 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 $626 million as of June 30, 2015. 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 2014 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 2014 Form 10-K. See also Note 7, Debt and Capital Leases, and Note 13, 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, 2015.

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 2014 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, 2015, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at June 30, 2015.



Derivative Activity Gains/(Losses)	(In millions)
Fair value of contracts as of December 31, 2014	$	413
Contracts realized or otherwise settled during the period	(34		)
Changes in fair value	(243		)
Fair Value of Contracts as of June 30, 2015	$	136



	Fair Value of Contracts as of June 30, 2015
	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	$	44	$	25		$	(14	)	$	—		$	55
Level 2	75		(32		)	(14		)	3			32
Level 3	48		4			(1		)	(2		)	49
Total	$	167	$	(3	)	$	(29	)	$	1		$	136

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, 2015, NRG's net derivative asset was $136 million, a decrease to total fair value of $277 million as compared to December 31, 2014. This decrease was driven by the roll-off of trades that settled during the period and losses in fair value.

Based on a sensitivity analysis using simplified assumptions, the impact of a $0.50 per MMBtu increase in natural gas prices across the term of the derivative contracts would result in a decrease of approximately $462 million in the net value of derivatives as of June 30, 2015. 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 $410 million in the net value of derivatives as of June 30, 2015.

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.

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 2014 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, 2015, and 2014:



(In millions)	2015		2014
VaR as of June 30,	$	36	$	105
Three months ended June 30,
Average	$	39	$	112
Maximum	50		126
Minimum	34		97
Six months ended June 30,
Average	$	43	$	100
Maximum	54		142
Minimum	34		73

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, 2015, 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 fixed rate and 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 2014 Form 10-K, as well as Note 7, Debt and Capital Leases of this Form 10-Q, for more information on the Company's interest rate swaps.

If all of the above swaps had been discontinued on June 30, 2015, the Company would have owed the counterparties $128 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, 2015, a 1% change in variable interest rates would result in a $23 million change in interest expense on a rolling twelve month basis.

As of June 30, 2015, the fair value and related carrying value of the Company's debt was $20.4 billion and $20.3 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 $1.5 billion.

Liquidity Risk

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

Based on a sensitivity analysis for power and gas positions under marginable contracts, a $0.50 per MMBtu change in natural gas prices across the term of the marginable contracts would cause a change in margin collateral posted of approximately $236 million as of June 30, 2015, and a 1 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral posted of approximately $260 million as of June 30, 2015. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of June 30, 2015.

Credit Risk

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

Currency Exchange Risk

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

ITEM 4 — CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

There were no changes in NRG’s internal control over financial reporting (as such term is defined in Rule 13a-15(f) under the Exchange Act) that occurred in the second quarter of 2015 that materially affected, or are reasonably likely to materially affect, NRG’s internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

For a discussion of material legal proceedings in which NRG was involved through June 30, 2015, see Note 13, 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 2014 Form 10-K. There have been no material changes in the Company's risk factors since those reported in its 2014 Form 10‑K.

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

In December 2014, the Company's board of directors authorized the Company to repurchase $100 million of its common stock under the 2015 Capital Allocation Program. The Company completed the repurchase of the $100 million of its common stock in February 2015. In March 2015, the Company's board of directors authorized the Company to repurchase an additional $100 million of its common stock under the 2015 Capital Allocation Program. In the second quarter of 2015, the Company's Board of Directors authorized the Company to repurchase an additional $81 million of its common stock.

The table below sets forth the information with respect to purchases made by or on behalf of NRG or any "affiliated purchaser" (as defined in Rule 10b-18(a)(3) under the Exchange Act), of NRG's common stock during the quarter ended June 30, 2015.



For the Quarter Ended June 30, 2015	Total Number of Shares Purchased	Average Price Paid per Share^(a)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs^(b)
Month #1
(April 1, 2015 to April 30, 2015)	1,328,329	$	24.47	1,328,329	$	44,500,014
Month #2
(May 1, 2015 to May 31, 2015)	307,754	$	25.34	307,754	$	36,696,366
Month #3
(June 1, 2015 to June 30, 2015)	2,743,824	$	24.48	2,743,824	$	50,500,020
Total	4,379,907	$	24.53	4,379,907

(a) The average price paid per share excludes commissions of $0.015 per share paid in connection with the share repurchases.

(b) Includes commissions of $0.015 per share paid in connection with the share repurchases.

ITEM 3 — DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4 — MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5 — OTHER INFORMATION

None.

ITEM 6 — EXHIBITS



Number	Description	Method of Filing
4.1	One Hundred-Seventeenth Supplemental Indenture, dated as of May 22, 2015, 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 Company's Current Report on Form 8-K filed on May 22, 2015.
4.2	Seventh Supplemental Indenture, dated as of May 22, 2015, 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 Company's Current Report on Form 8-K filed on May 22, 2015.
31.1	Rule 13a-14(a)/15d-14(a) certification of David Crane.	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.	Filed herewith.
101 INS	XBRL Instance Document.	Filed herewith.
101 SCH	XBRL Taxonomy Extension Schema.	Filed herewith.
101 CAL	XBRL Taxonomy Extension Calculation Linkbase.	Filed herewith.
101 DEF	XBRL Taxonomy Extension Definition Linkbase.	Filed herewith.
101 LAB	XBRL Taxonomy Extension Label Linkbase.	Filed herewith.
101 PRE	XBRL Taxonomy Extension Presentation Linkbase.	Filed herewith.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



	NRG ENERGY, INC. (Registrant)

	/s/ DAVID CRANE
	David Crane
	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 4, 2015	Chief Accounting Officer (Principal Accounting Officer)