UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

		For the Quarterly Period Ended: ~~March 31,~~June 30, 2014

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

Commission File Number: 001-15891

NRG Energy, Inc.

(Exact name of registrant as specified in its charter)



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

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

(609) 524-4500

(Registrant’s telephone number, including area code)

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

Yes x No o

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

Yes x No o

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

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

Yes o No x

As of ~~April 30,~~July 31, 2014, there were ~~337,240,638~~337,710,439 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	6
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES	7
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	4555
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	7088
ITEM 4 — CONTROLS AND PROCEDURES	7290
PART II — OTHER INFORMATION	7391
ITEM 1 — LEGAL PROCEEDINGS	7391
ITEM 1A — RISK FACTORS	7391
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	7391
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES	7391
ITEM 4 — MINE SAFETY DISCLOSURES	7391
ITEM 5 — OTHER INFORMATION	7391
ITEM 6 — EXHIBITS	7492
SIGNATURES	7593

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, 2013, including, but not limited to, 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;

The collateral demands of counterparties and other factors affecting NRG's liquidity position and financial condition;

NRG's ability to operate its businesses efficiently, manage capital expenditures and costs tightly, and generate earnings and cash flows from its asset-based businesses in relation to its debt and other obligations;

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

The liquidity and competitiveness of wholesale markets for energy commodities;

Government regulation, including compliance with regulatory requirements and changes in market rules, rates, tariffs and environmental laws and increased regulation of carbon dioxide and other greenhouse gas 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 its 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 Federal 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;

NRG's ability to implement its strategy of developing and building new power generation facilities, including new renewable projects;

NRG's ability to implement its econrg strategy of finding ways to address environmental challenges while taking advantage of business opportunities;

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

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

NRG's ability to maintain retail market share;

NRG's ability to successfully evaluate investments 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 partnering relationships.

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

GLOSSARY OF TERMS

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



2013 Form 10-K		NRG’s Annual Report on Form 10-K for the year ended December 31, 2013
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
~~Baseload~~		~~Units expected to satisfy minimum baseload requirements for the system and produce electricity at an essentially constant rate and run continuously~~
BTU		British Thermal Unit
~~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
CCPI		Clean Coal Power Initiative
CCS-EOR		Carbon Capture and Sequestration with Enhanced Oil Recovery project
Cirro Energy		Cirro Energy, Inc.
CO₂		Carbon dioxide
CPUC		California Public Utilities Commission
CSAPR		Cross-State Air Pollution Rule
CWA		Clean Water Act
Distributed Solar		Solar power projects ~~typically less than 20 MW in size,~~ that primarily sell power produced to customers for usage on site, or are interconnected to sell power into the local distribution grid
~~DNREC~~		~~Delaware Department of Natural Resources and Environmental Control~~
EME		Edison Mission Energy
Energy Plus Holdings		Energy Plus Holdings LLC
EPA		U.S. Environmental Protection Agency
ERCOT		Electric Reliability Council of Texas, the Independent System Operator and the regional reliability coordinator of the various electricity systems within Texas
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
FERC		Federal Energy Regulatory Commission
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 ~~8.55%~~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 two generating facilities under operating leases
GenOn Senior Notes		GenOn's ~~$1.9~~$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
Green Mountain Energy		Green Mountain Energy Company
GWh		Gigawatt hour
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
ISO		Independent System Operator
ITC		Investment Tax Credit



~~ISO~~		~~Independent System Operator~~
~~ITC~~		~~Investment Tax Credit~~
Kansas South		NRG Solar Kansas South LLC
kV		Kilovolt
kWh		Kilowatt-hours
LIBOR		London Inter-Bank Offered Rate
LTIPs		Collectively, the NRG Long-Term Incentive Plan and the NRG GenOn Long-Term Incentive Plan
Marsh Landing		NRG Marsh Landing, LLC (formerly known as GenOn Marsh Landing, LLC)
Mass		Residential and small business
MATS		Mercury and Air Toxics Standards promulgated by the EPA
MDE		Maryland Department of the Environment
MISO		Midcontinent Independent System Operator, Inc.
MMBtu		Million British Thermal Units
~~MOPR~~MVA		~~Minimum Offer Price Rule~~Megavolt ampere
MW		Megawatt
MWh		Saleable megawatt hours, net of internal/parasitic load megawatt-hours
MWt		Megawatts Thermal Equivalent
NAAQS		National Ambient Air Quality Standards
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
~~NJDEP~~		~~New Jersey Department of Environmental Protection~~
NOL		Net Operating Loss
NOV		Notice of Violation
NO_x		Nitrogen oxide
NPDES		National Pollutant Discharge Elimination System
NPNS		Normal Purchase Normal Sale
NRC		U.S. Nuclear Regulatory Commission
NRG Yield		Reporting segment including the following projects: Alpine, Avenal, Avra Valley, AZ DG Solar, Blythe, Borrego, CVSR, El Segundo, GenConn, High Desert, Kansas South, Marsh Landing, PFMG DG Solar, Roadrunner, South Trent and ~~Thermal.~~the Thermal Business.
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
NYISO		New York Independent System Operator
NYSPSC		New York State Public Service Commission
OCI		Other comprehensive income
PADEP		Pennsylvania Department of Environmental Protection
Peaking		Units expected to satisfy demand requirements during the periods of greatest or peak load on the system
PG&E		Pacific Gas & Electric Company
PJM		PJM Interconnection, LLC
PPA		Power Purchase Agreement
PUCT		Public Utility Commission of Texas
Reliant Energy		Reliant Energy Retail Services, LLC
Repowering		Technologies utilized to replace, rebuild, or redevelop major portions of an existing electrical generating facility, generally to achieve a substantial emissions reduction, increase facility capacity, and improve system efficiency
Retail Business		NRG's retail energy business, including the following retail energy brands: Cirro Energy, Reliant Energy, Green Mountain Energy, Energy Plus and NRG Residential Solutions



~~Retail Business~~		~~NRG's retail energy brands, including Cirro Energy, Reliant Energy, Green Mountain Energy, Energy Plus and NRG Residential Solutions~~
Revolving Credit Facility		The Company's $2.5 billion revolving credit facility due 2018, a component of the Senior Credit Facility
RGGI		Regional Greenhouse Gas Initiative
~~RMR~~		~~Reliability Must Run~~
~~RSS~~		~~Reliability Support Service~~
RTO		Regional Transmission Organization
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~~$6.6 billion outstanding unsecured senior notes, consisting of $1.1 billion of 7.625% senior notes due 2018, ~~$299~~$225 million of 8.5% ~~senior notes due 2019, $709 million of 7.625%~~ senior notes due 2019, $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 ~~$1.1~~$1.0 billion of 6.25% senior notes due ~~2022~~2024.
SO₂		Sulfur dioxide
STP		South Texas Project — nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest
Term Loan Facility		The Company's $2.0 billion term loan facility due 2018, a component of the Senior Credit Facility
Thermal Business		NRG Yield’s thermal business, which consists of thermal infrastructure assets that provide steam, hot water and/or chilled water, and in some instances electricity, tocommercial businesses, universities, hospitals and governmental units.
U.S.		United States of America
U.S. DOE		U.S. Department of Energy
~~U.S. DOJ~~		~~U.S. Department of Justice~~
U.S. GAAP		Accounting principles generally accepted in the United States
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
Yield Operating		NRG Yield Operating LLC

PART I — FINANCIAL INFORMATION

ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three months ended March 31,						Three months ended June 30,						Six months ended June 30,
(In millions, except for per share amounts)	2014			2013			2014			2013			2014			2013
Operating Revenues
Total operating revenues	$	3,486		$	2,081		$	3,621		$	2,929		$	7,107		$	5,010
Operating Costs and Expenses
Cost of operations	2,733			1,753			2,817			2,051			5,550			3,804
Depreciation and amortization	335			307			386			313			721			620
Selling, general and administrative	226			227			268			230			494			457
Acquisition-related transaction and integration costs	12			42			40			27			52			69
Development activity expenses	19			18			21			21			40			39
Total operating costs and expenses	3,325			2,347			3,532			2,642			6,857			4,989
Gain on sale of assets	19			—			—			—			19			—
Operating Income/(Loss)	180			(266		)
Operating Income							89			287			269			21
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	7			3			14			8			21			11
Other income, net	11			4			5			—			16			4
Loss on debt extinguishment	(41		)	(28		)	(40		)	(21		)	(81		)	(49		)
Interest expense	(255		)	(196		)	(274		)	(206		)	(529		)	(402		)
Total other expense	(278		)	(217		)	(295		)	(219		)	(573		)	(436		)
Loss Before Income Taxes	(98		)	(483		)
(Loss)/Income Before Income Taxes							(206		)	68			(304		)	(415		)
Income tax benefit	(31		)	(152		)	(126		)	(63		)	(157		)	(215		)
Net Loss	(67		)	(331		)
Less: Net (loss)/income attributable to noncontrolling interest	(11		)	1
Net Loss Attributable to NRG Energy, Inc.	(56		)	(332		)
Net (Loss)/Income							(80		)	131			(147		)	(200		)
Less: Net income attributable to noncontrolling interest							17			7			6			8
Net (Loss)/Income Attributable to NRG Energy, Inc.							(97		)	124			(153		)	(208		)
Dividends for preferred shares	2			2			3			3			5			5
Loss Available for Common Stockholders	$	(58	)	$	(334	)
Loss Per Share Attributable to NRG Energy, Inc. Common Stockholders
Weighted average number of common shares outstanding — basic and diluted	324			323
Net loss per weighted average common share — basic and diluted	$	(0.18	)	$	(1.03	)
(Loss)/Income Available for Common Stockholders							$	(100	)	$	121		$	(158	)	$	(213	)
(Loss)/Earnings Per Share Attributable to NRG Energy, Inc. Common Stockholders
Weighted average number of common shares outstanding — basic							337			323			331			323
(Loss)/Earnings per Weighted Average Common Share — Basic							$	(0.30	)	$	0.37		$	(0.48	)	$	(0.66	)
Weighted average number of common shares outstanding — diluted							337			327			331			323
(Loss)/Earnings per Weighted Average Common Share — Diluted							$	(0.30	)	$	0.37		$	(0.48	)	$	(0.66	)
Dividends Per Common Share	$	0.12		$	0.09		$	0.14		$	0.12		$	0.26		$	0.21

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE ~~LOSS~~(LOSS)/INCOME

(Unaudited)

Three months ended March 31,
2014 2013
(In millions)
Net Loss $ (67 ) $ (331 )
Other Comprehensive Income, net of tax
Unrealized (loss)/gain on derivatives, net of income tax (benefit)/expense of $(3) and $9 (9 ) 7
Foreign currency translation adjustments, net of income tax expense of $2 and $0 6
—
Available-for-sale securities, net of income tax expense of $2 and $1 6
2
Defined benefit plans, net of tax expense of $0 and $5 2
5
Other comprehensive income 5
14
Comprehensive Loss (62 ) (317 )
Less: Comprehensive (loss)/income attributable to noncontrolling interest (15 ) 1
Comprehensive Loss Attributable to NRG Energy, Inc. (47 ) (318 )
Dividends for preferred shares 2
2
Comprehensive Loss Available for Common Stockholders $ (49 ) $ (320 )



	Three months ended June 30,						Six months ended June 30,
	2014			2013			2014			2013
	(In millions)
Net (Loss)/Income	$	(80	)	$	131		$	(147	)	$	(200	)
Other Comprehensive (Loss)/Income, net of tax
Unrealized (loss)/gain on derivatives, net of income tax (benefit)/expense of $(3), $12, $(6), and $3	(19		)	17			(28		)	24
Foreign currency translation adjustments, net of income tax expense/(benefit) of $2, $(12), $4, and $(12)	(3		)	(19		)	3			(19		)
Available-for-sale securities, net of income tax (benefit)/expense of $(6), $2, $(4), and $1	7			—			13			2
Defined benefit plans, net of tax (benefit)/expense of $(7), $9, $(7), and $4	10			20			12			25
Other comprehensive (loss)/income	(5		)	18			—			32
Comprehensive (Loss)/Income	(85		)	149			(147		)	(168		)
Less: Comprehensive income/(loss) attributable to noncontrolling interest	12			7			(3		)	8
Comprehensive (Loss)/Income Attributable to NRG Energy, Inc.	(97		)	142			(144		)	(176		)
Dividends for preferred shares	3			3			5			5
Comprehensive (Loss)/Income Available for Common Stockholders	$	(100	)	$	139		$	(149	)	$	(181	)

See accompanying notes to condensed consolidated financial statements.

��

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	March 31, 2014			December 31, 2013			June 30, 2014			December 31, 2013
(In millions, except shares)	(unaudited)						(unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	3,187		$	2,254		$	1,481		$	2,254
Funds deposited by counterparties	4			63			9			63
Restricted cash	209			268			286			268
Accounts receivable — trade, less allowance for doubtful accounts of $32 and $40	1,149			1,214
Accounts receivable — trade, less allowance for doubtful accounts of $26 and $40							1,482			1,214
Inventory	781			898			996			898
Derivative instruments	1,573			1,328			1,701			1,328
Cash collateral paid in support of energy risk management activities	687			276			572			276
Deferred income taxes	78			258			79			258
Renewable energy grant receivable	116			539
Renewable energy grant receivable, net							614			539
Prepayments and other current assets	599			498			537			498
Total current assets	8,383			7,596			7,757			7,596
Property, plant and equipment, net of accumulated depreciation of $6,885 and $6,573	19,644			19,851
Property, plant and equipment, net of accumulated depreciation of $7,230 and $6,573							21,576			19,851
Other Assets
Equity investments in affiliates	462			453			865			453
Notes receivable, less current portion	69			73			85			73
Goodwill	2,038			1,985			2,116			1,985
Intangible assets, net of accumulated amortization of $1,248 and $1,977	1,300			1,140
Intangible assets, net of accumulated amortization of $1,268 and $1,977							1,434			1,140
Nuclear decommissioning trust fund	557			551			576			551
Derivative instruments	333			311			413			311
Deferred income taxes	1,416			1,202			1,500			1,202
Other non-current assets	759			740			1,307			740
Total other assets	6,934			6,455			8,296			6,455
Total Assets	$	34,961		$	33,902		$	37,629		$	33,902
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	685		$	1,050		$	833		$	1,050
Accounts payable	1,082			1,038			1,103			1,038
Derivative instruments	1,504			1,055			1,736			1,055
Cash collateral received in support of energy risk management activities	4			63			9			63
Accrued expenses and other current liabilities	950			998			1,065			998
Total current liabilities	4,225			4,204			4,746			4,204
Other Liabilities
Long-term debt and capital leases	16,803			15,767			18,165			15,767
Nuclear decommissioning reserve	298			294			302			294
Nuclear decommissioning trust liability	324			324			336			324
Deferred income taxes	24			22			71			22
Derivative instruments	257			195			354			195
Out-of-market contracts	1,157			1,177			1,175			1,177
Other non-current liabilities	1,230			1,201			1,254			1,201
Total non-current liabilities	20,093			18,980			21,657			18,980
Total Liabilities	24,318			23,184			26,403			23,184
3.625% convertible perpetual preferred stock (at liquidation value, net of issuance costs)	249			249			249			249
Commitments and Contingencies
Stockholders’ Equity
Common stock	4			4			4			4
Additional paid-in capital	7,842			7,840			8,303			7,840
Retained earnings	3,594			3,695			3,445			3,695
Less treasury stock, at cost — 77,275,933 and 77,347,528 shares, respectively	(1,940		)	(1,942		)	(1,940		)	(1,942		)
Accumulated other comprehensive income	10			5			5			5
Noncontrolling interest	884			867			1,160			867
Total Stockholders’ Equity	10,394			10,469			10,977			10,469
Total Liabilities and Stockholders’ Equity	$	34,961		$	33,902		$	37,629		$	33,902

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Three months ended March 31,						Six months ended June 30,
	2014			2013			2014			2013
	(In millions)						(In millions)
Cash Flows from Operating Activities
Net loss	$	(67	)	(331		)	$	(147	)	$	(200	)
Adjustments to reconcile net loss to net cash provided/(used) by operating activities:
Distributions and equity in earnings of unconsolidated affiliates	(2		)	—			39			5
Depreciation and amortization	335			307			721			620
Provision for bad debts	21			9			30			23
Amortization of nuclear fuel	11			6			20			16
Amortization of financing costs and debt discount/premiums	(5		)	(13		)	(9		)	(26		)
Loss on debt extinguishment	19			2
Adjustment for debt extinguishment							21			(16		)
Amortization of intangibles and out-of-market contracts	13			31			22			124
Amortization of unearned equity compensation	8			18			24			24
Changes in deferred income taxes and liability for uncertain tax benefits	(111		)	(215		)	(514		)	(224		)
Changes in nuclear decommissioning trust liability	5			10			6			25
Changes in derivative instruments	525			317			535			174
Changes in collateral deposits supporting energy risk management activities	(407		)	(226		)	(297		)	(158		)
Loss on sale of emission allowances							2			—
Gain on sale of assets	(19		)	—			(19		)	—
Cash used by changes in other working capital	65			(39		)	(64		)	(465		)
Net Cash Provided/(Used) by Operating Activities	391			(124		)	370			(78		)
Cash Flows from Investing Activities
Acquisitions of businesses, net of cash acquired	(218		)	(18		)	(1,817		)	(39		)
Capital expenditures	(237		)	(813		)	(507		)	(1,281		)
Decrease/(Increase) in restricted cash, net	3			(13		)
Decrease in restricted cash to support equity requirements for U.S. DOE funded projects	56			12
Increase in restricted cash, net							(6		)	(31		)
Decrease/(Increase) in restricted cash to support equity requirements for U.S. DOE funded projects							21			(16		)
Decrease/(Increase) in notes receivable	1			(9		)	2			(11		)
Investments in nuclear decommissioning trust fund securities	(188		)	(95		)	(340		)	(233		)
Proceeds from sales of nuclear decommissioning trust fund securities	183			85			334			208
Proceeds from renewable energy grants	387			16			429			48
Proceeds from sale of assets, net of cash disposed of	77			—			77			—
Cash proceeds to fund cash grant bridge loan payment	57			—			57			—
Other	3			(1		)	(3		)	(20		)
Net Cash Provided/(Used) by Investing Activities	124			(836		)
Net Cash Used by Investing Activities							(1,753		)	(1,375		)
Cash Flows from Financing Activities
Payment of dividends to common and preferred stockholders	(41		)	(31		)	(91		)	(73		)
Payment for treasury stock	—			(20		)	—			(25		)
Net (payments for)/receipts from settlement of acquired derivatives that include financing elements	(223		)	98			(167		)	171
Proceeds from issuance of long-term debt	1,564			736			3,886			1,472
Contributions and sale proceeds from noncontrolling interest in subsidiaries	9			20			10			33
Proceeds from issuance of common stock	3			1			8			9
Payment of debt issuance costs	(23		)	(5		)	(43		)	(35		)
Payments for short and long-term debt	(873		)	(219		)	(2,969		)	(816		)
Net Cash Provided by Financing Activities	416			580			634			736
Effect of exchange rate changes on cash and cash equivalents	2			—			(24		)	(2		)
Net Increase/(Decrease) in Cash and Cash Equivalents	933			(380		)
Net Decrease in Cash and Cash Equivalents							(773		)	(719		)
Cash and Cash Equivalents at Beginning of Period	2,254			2,087			2,254			2,087
Cash and Cash Equivalents at End of Period	$	3,187		$	1,707		$	1,481		$	1,368

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 and energy company that ~~aspires to be~~produces, sells and delivers energy and energy services in major competitive power markets in the United States while positioning itself as a leader in the way residential, industrial and commercial consumers think about and use ~~produce~~energy products and ~~deliver energy~~services. NRG owns and ~~energy services in major competitive power markets in the United States. NRG engages in the ownership and operation of~~operates power generation facilities; engages in the trading of energy, capacity and related products; ~~the transacting~~transacts in and ~~trading of~~trades fuel and transportation services and ~~the direct sale of~~directly sells energy, services, and innovative, sustainable products to retail customers. The Company sells retail ~~electric~~electricity products and services under the name “NRG” and various brands owned by NRG. Finally, NRG ~~aspires to be~~is a ~~clean energy~~ leader ~~and is focused on~~in the deployment and commercialization of potentially transformative technologies, like electric vehicles, Distributed Solar and smart meter/home automation technology that collectively have the potential to fundamentally change the nature of the power industry ~~including a substantial change in~~and the role of the national electric transmission grid and distribution system.

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 2013 Form 10-K. Interim results are not necessarily indicative of results for a full year.

In the opinion of management, the accompanying unaudited interim condensed consolidated financial statements contain all material adjustments consisting of normal and recurring accruals necessary to present fairly the Company's consolidated financial position as of ~~March 31,~~June 30, 2014, and the results of operations, comprehensive loss and cash flows for the three and six months ended ~~March 31,~~June 30, 2014, and 2013.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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. Certain prior period depreciation amounts have been recast to revise provisional purchase accounting estimates for the GenOn acquisition.

Reclassifications

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

Note 2 — Summary of Significant Accounting Policies

Other Cash Flow Information

NRG’s investing activities exclude capital expenditures of $63127 million which were accrued and unpaid at ~~March 31,~~June 30, 2014.

Noncontrolling Interest

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

(In millions)
Balance as of December 31, 2013 $ 867
Contributions from noncontrolling interest 17
Distributions to noncontrolling interest (8 )
Non-cash adjustments for equity component of NRG Yield, Inc. convertible notes $ 23
Comprehensive loss attributable to noncontrolling interest (15 )
Balance as of March 31, 2014 $ 884



	(In millions)
Balance as of December 31, 2013	$	867
Acquisition of EME	380
Sale of assets to NRG Yield, Inc.	(41		)
Non-cash adjustments for equity component of NRG Yield, Inc. convertible notes	23
Non-cash adjustments to noncontrolling interest	(76		)
Contributions from noncontrolling interest	25
Distributions to noncontrolling interest	(15		)
Comprehensive loss attributable to noncontrolling interest	(3		)
Balance as of June 30, 2014	$	1,160

Recent Accounting Developments

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 ~~accounting~~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. The guidance of ASU No. 2014-09 is effective for annual reporting periods beginning after December 15, 2016, including interim periods therein. Early adoption is not permitted. The Company is currently evaluating the impact of the standard ~~was issued in 2013~~on the Company's results of operations, cash flows and ~~was adopted on January 1, 2014:~~financial position.

•ASU 2013-11 - In July 2013, the FASB issued ASU No. 2013-11, Income Taxes (Topic 740) Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists, or ASU No. 2013-11. The amendments of ASU No. 2013-11, which were adopted on January 1, 2014, require an entity to present an unrecognized tax benefit, or a portion of an unrecognized tax benefit, as a reduction of a deferred tax asset for a net operating loss, or NOL, a similar tax loss or tax credit ~~carryforwards~~carryforward rather than a liability when the uncertain tax position would reduce the NOL or other carryforward under the tax law of the applicable jurisdiction and the entity intends to use the deferred tax asset for that purpose. The adoption of this standard did not impact the Company's results of operations or cash flows as the unrecognized tax benefits relate to state issues and the Company either has no NOL's or the NOL's are limited for that particular jurisdiction.

Note 3 — Business Acquisitions and Dispositions

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 Oil Exploration (EOR) Limited, 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 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 CCS-EOR 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 CCS-EOR was issued on July 15, 2014, and commercial operation is expected in late 2016.

The joint venture 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 CCS-EOR. The CCS-EOR is being financed by: (i) up to $167 million from a U.S. DOE CCPI grant of which $7 million has already been received from the grant in the initial design and engineering phase, (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. The Company’s contribution will include investments already made during the development of the project.

On July 14, 2014, Petra Nova Parish Holdings LLC entered into two credit facilities, or the Petra Nova Parish Credit Agreements, to fund the cost of construction of the CCS-EOR at the W.A. Parish facility. The Petra Nova Parish Credit Agreements are comprised of a $75 million Nippon Export and Investment Insurance, or NEXI, covered loan and a $175 million Japan Bank for International Cooperation, or JBIC, facility. The NEXI covered loan has ~~completed~~an interest rate of LIBOR plus an applicable margin of 1.75% and the JBIC facility has an interest rate of LIBOR plus an applicable margin of 0.50% during the construction phase which escalates to an applicable margin of 1.50% upon completion of the CCS-EOR. Both credit facilities mature in April 2026. NRG has guaranteed its 50% share of the obligations under the Petra Nova Parish Credit Agreements.

Sales of Assets to NRG Yield, Inc.

On June 30, 2014, the Company sold the following ~~business acquisitions~~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 carrying value.

Pending Acquisition

On June 3, 2014, NRG Yield Operating LLC, or Yield Operating, a consolidated subsidiary of the Company, entered into a purchase and sale agreement with Terra-Gen Finance Company, LLC and certain of its affiliates to acquire 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 owns seven wind facilities that total 947 MWs located in Tehachapi, California and a portfolio of land leases, or the Alta Wind Assets. The purchase price of the Alta Wind Assets is $870 million, as well as working capital adjustments, plus the assumption of $1.6 billion in non-recourse project level debt. The acquisition, which is subject to customary closing conditions, including certain regulatory approvals, is expected to close during the third quarter of 2014. Power generated by the Alta Wind facility is sold to Southern California Edison under long-term power purchase agreements with 21 years of remaining contract life for Phases I-V and 22 years, beginning in 2016, for Phases X and XI.

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, commencing on February 15, 2015. The notes are ~~material to the Company's financial statements:~~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 current and future subsidiaries.

Acquisition of Dominion's Competitive Electric Retail Business

On March 31, 2014, the Company acquired the competitive retail ~~electric~~electricity business of Dominion Resources, Inc., or Dominion. The acquisition of Dominion's competitive retail electricity business increased NRG’s retail portfolio by approximately 217,000 customers as of June 30, 2014, and is expected to ~~add~~increase NRG’s retail portfolio by approximately 500,000 customers in ~~Connecticut, Illinois, Maryland, Massachusetts, New Jersey, New York, Ohio, Pennsylvania and Texas, after customary transitions, to NRG's retail portfolio~~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 $195 million as cash consideration for the acquisition, including $165 million of purchase price and $30 million paid for working capital balances, which was funded by cash on hand. The purchase price was provisionally allocated to the following: $50 million to accounts receivable-trade, ~~$145~~$62 million to customer relationships, $9 million to trade names, $10 million to current assets, $20 million to derivative assets, ~~and $30~~$46 million to current and non-current ~~liabilities.~~liabilities, and goodwill of $90 million which is not 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 generation assets. The acquired assets and liabilities are included within the Retail segment. 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. Any changes to the fair value assessments will affect the value of goodwill. 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.

EME Acquisition

On April 1, 2014, the Company acquired substantially all of the assets of ~~Edison Mission Energy, or~~ EME. EME, through its subsidiaries and affiliates, owned ~~operated,~~or leased and ~~leased~~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 $~~3.4~~3.5 billion, which was comprised of the following:


	Original Purchase Price		Purchase Price on Acquisition Date		Original Purchase Price		Purchase Price on Acquisition Date
Cash and equivalents^(a)	2,285		3,021		$	2,285	$	3,021
Common shares ^(b)	350		401		350		401
Liabilities acquired					—		71
Total purchase price	$	2,635	$	3,422	2,635		3,493
Less: cash acquired			1,422				1,422
Net purchase price			$	2,000			$	2,071

(a) The increase in cash paid relates to an increase in acquired cash on hand as well as changes in cash collateral, restricted cash and cash related to unconsolidated subsidiaries. It also reflects lease and debt payments in 2014.

(b) The increase in the value of the common shares reflects an increase in trading price of NRG common shares between October 18, 2013 and April 1, 2014. The shares of NRG common stock were given a value of $350 million in determining the cash purchase price, which was based upon the volume-weighted average trading price over the 20 trading days prior to October 18, 2013.

The purchase price 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, as described in Note 7, Debt and Capital Leases, 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 Powerton and Joliet, or 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 $485 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 ~~MATS.~~environmental regulations, as discussed further in Note 15, Environmental Matters. In addition, NRG assumed certain long-term contractual arrangements for fuel and transportation. Commitments under these arrangements totaled approximately $490 million.

On April 30, 2014, subsequent to the acquisition, the Company acquired the remaining 50% ownership of Mission Del Sol LLC, which owns the Sunrise facility, a 586 MW natural gas facility in Fellows, California, from Chevron increasing the Company's ownership interest to 100% in exchange for the Company's 50% interest in six cogeneration facilities, previously co-owned with Chevron.

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 purchase price of ~~$3.4~~$3.5 billion was provisionally allocated as follows:


	(In millions)		(In millions)
Assets
Cash	$	1,422	$	1,422
Current assets	502		676
Property, plant and equipment	2,576		2,475
Intangible assets	1,062		312
Non-current assets	655		813
Total assets acquired	6,217		5,698

Liabilities
Current and non-current liabilities	905		533
Out-of-market contracts and leases	288		43
Long-term debt	1,249		1,249
Total liabilities assumed	2,442		1,825
Less: noncontrolling interest	354		380
Net assets acquired	$	3,421	$	3,493

The Company incurred and expensed acquisition-related transaction ~~and integration~~ costs of $3$14 million inand $17 million for the ~~quarter~~three and six months ended ~~March 31,~~June 30, 2014.

Fair value measurements

The provisional fair values of the property, plant and equipment, intangible assets and out-of-market contracts at the acquisition date were measured primarily based on significant inputs that are not observable in the market and thus represent a Level 3 measurement as defined in ASC 820. Significant inputs were as follows:

Property, plant and equipment - The estimated fair values were determined primarily based on an income method using discounted cash flows and validated using a market approach based on recent transactions of comparable assets. The income approach was primarily relied upon as the forecasted cash flows more appropriately incorporate differences in regional markets, plant types, age, useful life, equipment condition and environmental controls of each asset. The income approach also allows for a more accurate reflection of current and expected market dynamics such as supply and demand, commodity prices and regulatory environment as of the acquisition date.

Intangible assets - The fair values of the ~~power purchase agreements, or~~ PPAs acquired were determined utilizing a variation of the income approach where the expected future cash flows resulting from the acquired PPAs were reduced by operating costs and charges for contributory assets and then discounted to present value at the weighted average cost of capital of an integrated utility peer group adjusted for project-specific financing attributes. The values were corroborated with available market data.

Out-of-market lease contracts - The estimated fair values of the acquired leases were determined utilizing a variation of the income approach under which the fair value of the lease was determined by discounting the future lease payments at an appropriate discount rate and comparing it to the fair value of the property, plant and equipment being leased.

Noncontrolling interest - The estimated fair value of the noncontrolling interests represent the fair value of the partners' contributions as of the acquisition date.

1415

Supplemental ~~Pro-forma~~Pro Forma Information

Since the acquisition date, EME contributed $311 million in operating revenues and $14 million in net losses attributable to NRG. The following supplemental ~~pro-forma~~pro forma information represents the results of operations as if NRG had acquired EME on January 1, 2013:


	For the quarter ended			For the year ended			For the six months ended						For the year ended
	March 31, 2014			December 31, 2013
(in millions except per share amounts)							June 30, 2014			June 30, 2013			December 31, 2013
	(in millions except per share amounts)
Operating revenues	4,044			$	12,598		$	7,655		$	5,618		$	12,598
Net loss attributable to NRG Energy, Inc.	(49		)	(1,040		)	(136		)	(390		)	(1,009		)
Loss per share attributable to NRG common stockholders:
Basic	$	(0.15	)	$	(3.09	)	(0.41		)	(1.16		)	(3.00		)
Diluted	$	(0.15	)	$	(3.09	)	(0.41		)	(1.16		)	(3.00		)

The supplemental ~~pro-forma~~pro forma information has been adjusted to include the pro-forma impact of depreciation of property, plant and equipment, amortization of lease obligations and out-of-market contracts, based on the preliminary purchase price allocations. The ~~pro-forma~~pro forma data has also been adjusted to eliminate non-recurring transaction costs incurred by NRG, as well as the related tax impact. There were no transactions during the periods between NRG and EME. The ~~pro-forma~~pro forma results are presented for illustrative purposes only and do not reflect the realization of potential cost savings or any related integration costs. The Company expects to achieve certain cost savings from the acquisition; however, there can be no assurance that these cost savings will be achieved.

2013 Acquisitions

Energy Systems Acquisition

On December 31, 2013, NRG Energy Center Omaha Holdings, LLC, an indirect wholly owned subsidiary of NRG Yield LLC, acquired 100% of Energy Systems Company, or Energy Systems, for approximately $120 million. The acquisition was financed from cash on hand. Energy Systems is an operator of steam and chilled thermal facilities that provides heating and cooling services to nonresidential customers in Omaha, Nebraska. 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 purchase price was primarily allocated to property, plant and equipment of $60 million, customer relationships of $59 million, and working capital of $1 million. The initial accounting for the business combination is not complete because the evaluations necessary to assess the fair values of certain net assets acquired and the amount of goodwill to be recognized are 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.

Gregory Acquisition

On August 7, 2013, NRG Texas Gregory, LLC, a wholly owned subsidiary of NRG, acquired Gregory Power Partners, L.P. for approximately $245 million in cash, net of $32 million cash acquired. Gregory is a cogeneration plant located in Corpus Christi, Texas, which has generation capacity of 388 MW and steam capacity of 160 MWt. The Gregory cogeneration plant provides steam, processed water and a small percentage of its electrical generation to the Corpus Christi Sherwin Alumina plant. The majority of the plant's generation is available for sale in the ERCOT market. 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 purchase price was provisionally allocated primarily to property, plant, and equipment of $248 million, current assets of $13 million, and other liabilities of $16 million. The ~~initial~~ accounting for the business combination is not complete because the evaluations necessary to assess the fair value of certain net assets acquired are still in process. The provisional amounts are subject to revision until the evaluations areGregory acquisition was completed ~~to the extent that additional information is obtained about the facts and circumstances that existed~~ as of June 30, 2014, at which point the ~~acquisition date.~~provisional fair values became final with no material changes.

1516

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 2013 Form 10-K.

For cash and cash equivalents, funds deposited by counterparties, accounts and other receivables, accounts payable, restricted cash, and cash collateral paid and received in support of energy risk management activities, the carrying amount approximates fair value because of the short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy. The estimated carrying amounts and fair values of NRG's recorded financial instruments not carried at fair market value are as follows:


	As of March 31, 2014				As of December 31, 2013				As of June 30, 2014				As of December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)								(In millions)
Assets:
Notes receivable^(a)	$	97	$	97	$	99	$	99	$	114	$	114	$	99	$	99
Liabilities:
Long-term debt, including current portion	17,478		17,631		16,804		17,222		18,988		19,576		16,804		17,222

(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 March 31, 2014								As of June 30, 2014
	Fair Value								Fair Value
(In millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities	$	—	$	—	$	18	$	18	$	—	$	—	$	18	$	18
Available-for-sale securities	8		—		—		8		14		—		—		14
Other ^(a)	22		—		11		33		21		—		11		32
Trust fund investments:
Nuclear trust fund investments:
Cash and cash equivalents	1		—		—		1		3		—		—		3
U.S. government and federal agency obligations	37		3		—		40		37		4		—		41
Federal agency mortgage-backed securities	—		62		—		62		—		62		—		62
Commercial mortgage-backed securities	—		25		—		25		—		26		—		26
Corporate debt securities	—		90		—		90		—		92		—		92
Equity securities	280		—		56		336		292		—		58		350
Foreign government fixed income securities	—		3		—		3		—		2		—		2
Other trust fund investments:
U.S. government and federal agency obligations	1		—		—		1		1		—		—		1
Derivative assets:
Commodity contracts	366		1,408		120		1,894		315		1,438		353		2,106
Interest rate contracts	—		12		—		12		—		8		—		8
Total assets	$	715	$	1,603	$	205	$	2,523	$	683	$	1,632	$	440	$	2,755
Derivative liabilities:
Commodity contracts	$	257	$	1,337	$	97	$	1,691	$	235	$	1,349	$	365	$	1,949
Interest rate contracts	—		70		—		70		—		141		—		141
Total liabilities	$	257	$	1,407	$	97	$	1,761	$	235	$	1,490	$	365	$	2,090

(a) Primarily consists of mutual funds held in rabbi trusts for non-qualified deferred compensation plans for certain former employees.

1617


	As of December 31, 2013								As of December 31, 2013
	Fair Value								Fair Value
(In millions)	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities	$	—	$	—	$	16	$	16	$	—	$	—	$	16	$	16
Available-for-sale securities	2		—		—		2		2		—		—		2
Other ^(a)	37		—		10		47		37		—		10		47
Trust fund investments:
Nuclear trust fund investments:
Cash and cash equivalents	26		—		—		26		26		—		—		26
U.S. government and federal agency obligations	40		5		—		45		40		5		—		45
Federal agency mortgage-backed securities	—		62		—		62		—		62		—		62
Commercial mortgage-backed securities	—		14		—		14		—		14		—		14
Corporate debt securities	—		70		—		70		—		70		—		70
Equity securities	276		—		56		332		276		—		56		332
Foreign government fixed income securities	—		2		—		2		—		2		—		2
Other trust fund investments:
U.S. government and federal agency obligations	1		—		—		1		1		—		—		1
Derivative assets:
Commodity contracts	346		1,126		147		1,619		346		1,126		147		1,619
Interest rate contracts	—		20		—		20		—		20		—		20
Total assets	$	728	$	1,299	$	229	$	2,256	$	728	$	1,299	$	229	$	2,256
Derivative liabilities:
Commodity contracts	$	216	$	831	$	134	$	1,181	$	216	$	831	$	134	$	1,181
Interest rate contracts	—		69		—		69		—		69		—		69
Total liabilities	$	216	$	900	$	134	$	1,250	$	216	$	900	$	134	$	1,250

(a) Primarily consists of mutual funds held in rabbi trusts for non-qualified deferred compensation plans for certain former employees.

There were no transfers during the three and six months ended ~~March 31,~~June 30, 2014 and 2013 between Levels 1 and 2. The following tables reconcile, for the three and six months ended ~~March 31,~~June 30, 2014 and 2013, 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)												Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Three months ended March 31, 2014												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			Debt Securities		Other		Trust Fund Investments		Derivatives^(a)			Total
Beginning balance as of December 31, 2013	$	16	$	10	$	56	$	13		$	95
Beginning balance													$	18	$	11	$	56	$	23		$	108		$	16	$	10	$	56	$	13		$	95
Total gains/(losses) — realized/unrealized:
Included in earnings	—		1		—		16			17			—		—		—		(12		)	(12		)	—		1		—		4			5
Included in OCI	2		—		—		—			2			—		—		—		—			—			2		—		—		—			2
Included in nuclear decom- missioning obligation													—		—		1		—			1			—		—		1		—			1
Purchases	—		—		—		(21		)	(21		)	—		—		1		(63		)	(62		)	—		—		1		(84		)	(83		)
Contracts acquired in Dominion acquisition	—		—		—		3			3
Contracts acquired in Dominion and EME acquisition													—		—		—		36			36			—		—		—		39			39
Transfers into Level 3 ^(b)	—		—		—		18			18			—		—		—		—			—			—		—		—		18			18
Transfers out of Level 3 ^(b)	—		—		—		(6		)	(6		)	—		—		—		4			4			—		—		—		(2		)	(2		)
Ending balance as of March 31, 2014	$	18	$	11	$	56	$	23		$	108
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 March 31, 2014	$	—	$	—	$	—	$	19		$	19
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.

1719


	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)										Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Three months ended March 31, 2013										Three months ended June 30, 2013											Six months ended June 30, 2013
(In millions)	Debt Securities		Trust Fund Investments		Derivatives^(a)			Total			Debt Securities		Trust Fund Investments			Derivatives^(a)			Total			Debt Securities		Trust Fund Investments		Derivatives^(a)			Total
Beginning balance as of January 1, 2013	$	12	$	47	$	(12	)	$	47
Beginning balance											$	13	$	50		$	5		$	68		$	12	$	47	$	(12	)	$	47
Total (losses)/gains — realized/unrealized:
Included in earnings	—		—		(27		)	(27		)	—		—			9			9			—		—		(18		)	(18		)
Included in OCI	1		—		—			1			2		—			—			2			3		—		—			3
Included in nuclear decommissioning obligations	—		3		—			3
Included in nuclear decom- missioning obligations											—		(1		)	—			(1		)	—		2		—			2
Purchases	—		—		(1		)	(1		)	—		1			(6		)	(5		)	—		1		(7		)	(6		)
Transfers into Level 3 ^(b)	—		—		15			15			—		—			12			12			—		—		27			27
Transfers out of Level 3 ^(b)	—		—		30			30			—		—			(32		)	(32		)	—		—		(2		)	(2		)
Ending balance as of March 31, 2013	$	13	$	50	$	5		$	68
Losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets or liabilities still held as of March 31, 2013	$	—	$	—	$	(21	)	$	(21	)
Ending balance as of June 30, 2013											$	15	$	50		$	(12	)	$	53		$	15	$	50	$	(12	)	$	53
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, 2013											—		—			24			24			—		—		3			3


(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.

Realized and unrealized gains and losses included in earnings that are related to ~~the~~ energy derivatives are recorded in operating revenues and cost of operations.

Derivative Fair Value Measurements

A portion of NRG's contracts are exchange-traded contracts with readily available quoted market prices. A majority of NRG's contracts are non-exchange-traded contracts valued using prices provided by external sources, primarily price quotations available through brokers or over-the-counter and on-line exchanges. The remainder of the assets and liabilities represent contracts for which external sources or observable market quotes are not available for the whole term or for certain delivery months or the contracts are retail and load following power contracts. These contracts are valued using various valuation techniques including but not limited to internal models that apply fundamental analysis of the market and corroboration with similar markets. As of ~~March 31,~~June 30, 2014, contracts valued with prices provided by models and other valuation techniques make up 6%17% of the total derivative assets and 6%17% of the total derivative liabilities.

The fair value of each contract is discounted using a risk free interest rate. In addition, the Company applies a credit reserve to reflect credit risk which is calculated based on published default probabilities. As of ~~March 31,~~June 30, 2014, the credit reserve ~~was not~~resulted in a ~~material amount.~~$1 million increase in fair value which is a gain in OCI. As of ~~March 31,~~June 30, 2013, the credit reserve resulted in a $51 million ~~increase~~decrease in fair value which is composed of a $32 million gain in OCI and a $23 million ~~gain~~loss in operating revenue and cost of operations.

Concentration of Credit Risk

In addition to the credit risk discussion as disclosed in Note 2, Summary of Significant Accounting Policies, to the Company's 2013 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.

1820

Counterparty Credit Risk

The Company's counterparty credit risk policies are disclosed in its 2013 Form 10-K. As of ~~March 31,~~June 30, 2014, counterparty credit exposure, excluding credit risk exposure under certain long term agreements, was $~~688~~742 million and NRG held collateral (cash and letters of credit) against those positions of $2412 million, resulting in a net exposure of $~~666~~740 million. Approximately ~~82%~~85% of the Company's exposure before collateral is expected to roll off by the end of 2015. 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	~~41.3~~34	%
Utilities, energy merchants, marketers and other	~~33.1~~31
ISOs	~~21.4~~30
Coal and emissions	~~4.2~~5
Total as of ~~March 31,~~June 30, 2014	100	%



	Net Exposure ^(a)
Category	(% of Total)
Investment grade	~~92.0~~90	%
Non-rated ^(b)	~~7.0~~6
Non-investment grade	~~1.0~~4
Total as of ~~March 31,~~June 30, 2014	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 $~~218~~149 million. 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, South Central load obligations, and solar PPAs. As external sources or observable market quotes are not available to estimate such exposure, the Company ~~values~~estimates its credit exposure for these contracts based on various techniques including, but not limited to, internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Based on these valuation techniques, as of ~~March 31,~~June 30, 2014, aggregate credit risk exposure managed by NRG to these counterparties was approximately $~~2.3~~3.5 billion, including ~~$627 million~~$1.1 billion related to assets of NRG Yield, Inc., for the next five years. The majority of these power contracts are with utilities or public power entities with strong credit quality and public utility commission or other regulatory support. However, such regulated utility counterparties can be impacted by changes in government regulations, which NRG is unable to predict.

Retail Customer Credit Risk

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

As of ~~March 31,~~June 30, 2014, the ~~Company's~~Company believes its retail customer credit exposure was diversified across many customers and various industries, as well as government entities.

1921

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 2013 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 other comprehensive income, consistent with regulatory treatment.

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


	As of March 31, 2014							As of December 31, 2013							As of June 30, 2014							As of December 31, 2013
(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)	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	$	1	$	—	$	—	—	$	26	$	—	$	—	—	$	3	$	—	$	—	—	$	26	$	—	$	—	—
U.S. government and federal agency obligations	40		1		—		10	45		1		1		9	41		2		—		9	45		1		1		9
Federal agency mortgage-backed securities	62		1		1		24	62		1		1		24	62		1		1		25	62		1		1		24
Commercial mortgage-backed securities	25		—		—		30	14		—		—		29	26		—		—		30	14		—		—		29
Corporate debt securities	90		2		1		9	70		1		1		9	92		3		—		11	70		1		1		9
Equity securities	336		205		—		—	332		204		—		—	350		219		—		—	332		204		—		—
Foreign government fixed income securities	3		—		—		12	2		—		—		9	2		—		—		16	2		—		—		9
Total	$	557	$	209	$	2		$	551	$	207	$	3		$	576	$	225	$	1		$	551	$	207	$	3

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


	Three months ended March 31,				Six months ended June 30,
	2014		2013		2014		2013
	(In millions)				(In millions)
Realized gains	$	3	$	1	$	7	$	3
Realized losses	1		1		3		4
Proceeds from sale of securities	183		85		334		208

2022

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 2013 Form 10-K.

Energy-Related Commodities

As of ~~March 31,~~June 30, 2014, NRG had energy-related derivative financial instruments extending through 2019. 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 ~~March 31,~~June 30, 2014, the Company had interest rate derivative instruments on non-recourse debt extending through 2032, the majority 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 commodity, excluding those derivatives that qualified for the NPNS exception as of ~~March 31,~~June 30, 2014 and December 31, 2013. 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							Total Volume
		March 31, 2014			December 31, 2013				June 30, 2014			December 31, 2013
Commodity	Units	(In millions)						Units	(In millions)
Emissions	Short Ton	2			—			Short Ton	1			—
Coal	Short Ton	50			51			Short Ton	70			51
Natural Gas	MMBtu	(111		)	(166		)	MMBtu	(239		)	(166		)
Oil	Barrel	1			1			Barrel	—			1
Power	MWh	(35		)	(27		)	MWh	(43		)	(27		)
Interest	Dollars	$	1,439		$	1,444		Dollars	$	2,569		$	1,444

The ~~decrease~~increase in the natural gas position was the result of additional ~~purchases~~strategic hedges entered into during the year, ~~to hedge our retail portfolio as well as~~partially offset by the settlement of positions during the period. ~~These amounts were slightly offset by natural gas sales entered into during~~The increase in the ~~year to hedge our conventional power generation.~~ interest rate swap position was primarily the result of interest rate swaps acquired in connection with EME.

Fair Value of Derivative Instruments

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


	Fair Value								Fair Value
	Derivative Assets				Derivative Liabilities				Derivative Assets				Derivative Liabilities
	March 31, 2014		December 31, 2013		March 31, 2014		December 31, 2013		June 30, 2014		December 31, 2013		June 30, 2014		December 31, 2013
	(In millions)								(In millions)
Derivatives designated as cash flow hedges:
Interest rate contracts current	$	—	$	—	$	32	$	35	$	—	$	—	$	59	$	35
Interest rate contracts long-term	8		14		31		29		7		14		74		29
Commodity contracts current	—		—		—		1		—		—		—		1
Commodity contracts long-term	—		—		—		1		—		—		—		1
Total derivatives designated as cash flow hedges	8		14		63		66		7		14		133		66
Derivatives not designated as cash flow hedges:
Interest rate contracts current	—		—		5		4		—		—		5		4
Interest rate contracts long-term	4		6		2		1		1		6		3		1
Commodity contracts current	1,573		1,328		1,467		1,015		1,701		1,328		1,672		1,015
Commodity contracts long-term	321		291		224		164		405		291		277		164
Total derivatives not designated as cash flow hedges	1,898		1,625		1,698		1,184		2,107		1,625		1,957		1,184
Total derivatives	$	1,906	$	1,639	$	1,761	$	1,250	$	2,114	$	1,639	$	2,090	$	1,250

2123

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 Not Offset in the Statement of Financial Position
	Gross Amounts of Recognized Assets / Liabilities			Derivative Instruments			Cash Collateral (Held) / Posted		Net Amount			Gross Amounts of Recognized Assets / Liabilities			Derivative Instruments			Cash Collateral (Held) / Posted			Net Amount
As of March 31, 2014	(In millions)
As of June 30, 2014												(In millions)
Commodity contracts:
Derivative assets	$	1,894		$	(1,501	)	$	—	$	393		$	2,106		$	(1,706	)	$	(4	)	$	396
Derivative liabilities	(1,691		)	1,501			38		(152		)	(1,949		)	1,706			75			(168		)
Total commodity contracts	203			—			38		241			157			—			71			228
Interest rate contracts:
Derivative assets	12			(8		)	—		4			8			(6		)	—			2
Derivative liabilities	(70		)	8			—		(62		)	(141		)	6			—			(135		)
Total interest rate contracts	(58		)	—			—		(58		)	(133		)	—			—			(133		)
Total derivative instruments	$	145		$	—		$	38	$	183		$	24		$	—		$	71		$	95



	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, 2013	(In millions)
Commodity contracts:
Derivative assets	$	1,619		$	(1,032	)	$	(62	)	$	525
Derivative liabilities	(1,181		)	1,032			18			(131		)
Total commodity contracts	438			—			(44		)	394
Interest rate contracts:
Derivative assets	20			(12		)	—			8
Derivative liabilities	(69		)	12			—			(57		)
Total interest rate contracts	(49		)	—			—			(49		)
Total derivative instruments	$	389		$	—		$	(44	)	$	345

Accumulated Other Comprehensive Loss

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


	Three months ended March 31, 2014									Three months ended June 30, 2014									Six months ended June 30, 2014
	Energy Commodities			Interest Rate			Total			Energy Commodities			Interest Rate			Total			Energy Commodities			Interest Rate			Total
	(In millions)									(In millions)
Accumulated OCI beginning balance	$	(1	)	$	(22	)	$	(23	)	$	(1	)	$	(31	)	$	(32	)	$	(1	)	$	(22	)	$	(23	)
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	—			(1		)	(1		)	—			(7		)	(7		)	—			(8		)	(8		)
Mark-to-market of cash flow hedge accounting contracts	—			(8		)	(8		)	—			(12		)	(12		)	—			(20		)	(20		)
Accumulated OCI ending balance, net of $17 tax	$	(1	)	$	(31	)	$	(32	)
Accumulated OCI ending balance, net of $29 tax										$	(1	)	$	(50	)	$	(51	)	$	(1	)	$	(50	)	$	(51	)
Losses expected to be realized from OCI during the next 12 months, net of $7 tax	$	(1	)	$	(13	)	$	(14	)	$	(1	)	$	(12	)	$	(13	)	$	(1	)	$	(12	)	$	(13	)

2224


	Three months ended March 31, 2013									Three months ended June 30, 2013									Six months ended June 30, 2013
	Energy Commodities			Interest Rate			Total			Energy Commodities			Interest Rate			Total			Energy Commodities			Interest Rate			Total
	(In millions)									(In millions)
Accumulated OCI beginning balance	$	41		$	(72	)	$	(31	)	$	42		$	(66	)	$	(24	)	$	41		$	(72	)	$	(31	)
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	(8		)	3			(5		)	(15		)	1			(14		)	(23		)	4			(19		)
Mark-to-market of cash flow hedge accounting contracts	9			3			12			(3		)	34			31			6			37			43
Accumulated OCI ending balance, net of $15 tax	$	42		$	(66	)	$	(24	)
Gains/(losses) expected to be realized from OCI during the next 12 months, net of $19 tax	$	42		$	(10	)	$	32
(Losses)/Gains recognized in income from the ineffective portion of cash flow hedges	$	(1	)	$	1		$	—
Accumulated OCI ending balance, net of $4 tax										$	24		$	(31	)	$	(7	)	$	24		$	(31	)	$	(7	)
Gains/(losses) expected to be realized from OCI during the next 12 months, net of $10 tax										$	26		$	(9	)	$	17		$	26		$	(9	)	$	17
Losses recognized in income from the ineffective portion of cash flow hedges										$	—		$	(1	)	$	(1	)	$	(1	)	$	—		$	(1	)

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 or six months ended ~~March 31,~~June 30, 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 commodity hedges is included within operating revenues and cost of operations and the effect of interest rate hedges is included in interest expense.



	Three months ended June 30,						Six months ended June 30,
	2014			2013			2014			2013
Unrealized mark-to-market results	(In millions)
Reversal of previously recognized unrealized gains on settled positions related to economic hedges	$	(5	)	$	(7	)	$	(2	)	$	(32	)
Reversal of gain positions acquired as part of the GenOn and EME acquisitions	(84		)	(99		)	(162		)	(187		)
Net unrealized (losses)/gains on open positions related to economic hedges	(30		)	204			(223		)	55
Losses on ineffectiveness associated with open positions treated as cash flow hedges	—			—			—			(1		)
Total unrealized mark-to-market (losses)/gains for economic hedging activities	(119		)	98			(387		)	(165		)
Reversal of previously recognized unrealized losses/(gains) on settled positions related to trading activity	5			(1		)	5			(29		)
Reversal of (gain)/loss positions acquired as part of the GenOn and EME acquisitions	(19		)	2			(20		)	—
Net unrealized gains/(losses) on open positions related to trading activity	14			(13		)	30			(26		)
Total unrealized mark-to-market (losses)/gains for trading activity	—			(12		)	15			(55		)
Total unrealized (losses)/gains	$	(119	)	$	86		$	(372	)	$	(220	)



	Three months ended June 30,						Six months ended June 30,
	2014			2013			2014			2013
	(In millions)
Unrealized (losses)/gains included in operating revenues	$	(48	)	$	181		$	(364	)	(340		)
Unrealized (losses)/gains included in cost of operations	(71		)	(95		)	(8		)	120
Total impact to statement of operations — energy commodities	$	(119	)	$	86		$	(372	)	$	(220	)
Total impact to statement of operations — interest rate contracts	$	(3	)	$	4		$	(7	)	$	6

Three months ended March 31,
2014 2013
Unrealized mark-to-market results (In millions)
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges $ 3
$ (25 )
Reversal of gain positions acquired as part of the Reliant Energy, Green Mountain Energy and GenOn acquisitions (78 ) (88 )
Net unrealized losses on open positions related to economic hedges (193 ) (149 )
Losses on ineffectiveness associated with open positions treated as
cash flow hedges
—
(1 )
Total unrealized mark-to-market losses for economic hedging activities (268 ) (263 )
Reversal of previously recognized unrealized gains on settled positions related to trading activity —
(28 )
Reversal of gain positions acquired as part of the GenOn acquisitions (1 ) (2 )
Net unrealized gains/(losses) on open positions related to trading activity 16
(13 )
Total unrealized mark-to-market gains/(losses) for trading activity 15
(43 )
Total unrealized losses $ (253 ) $ (306 )

Three months ended March 31,
2014 2013
(In millions)
Unrealized losses included in operating revenues $ (316 ) $ (521 )
Unrealized gains included in cost of operations 63
215
Total impact to statement of operations — energy commodities $ (253 ) $ (306 )
Total impact to statement of operations — interest rate contracts $ (4 ) $ 2

The reversal of gain or loss positions acquired as part of the ~~Reliant Energy, Green Mountain Energy~~GenOn and ~~GenOn~~EME acquisitions were valued based upon the forward prices on the acquisition dates.

For the ~~three~~six months ended ~~March 31,~~June 30, 2014, the unrealized loss from open economic hedge positions was primarily the result of a decrease in value of forward ~~sales of natural gas and electricity~~purchases due to ~~an increase~~decreases in ~~forward natural gas and electricity prices.~~

~~For the~~ ~~three~~ ~~months ended~~ ~~March 31, 2013, the unrealized loss from open economic hedge positions was primarily the result of~~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.

For the six months ended June 30, 2013, the unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward purchases due to decreases in ERCOT heat rates combined with a decrease in the value of forward sales of natural gas and electricity due to a decrease in forward natural gas and electricity prices.

As of June 30, 2013, NRG had interest rate swaps designated as cash flow hedges on the CVSR solar project. The notional amount on the swaps exceeded the actual debt draws on the project. As such, NRG discontinued cash flow hedge accounting for these contracts and $5 million of loss previously deferred in OCI was recognized in earnings for the three and six months ended June 30, 2013.

Credit Risk Related Contingent Features

Certain of the Company's hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed “adequate assurance” under the agreements, or requires the Company to post additional collateral if there were a one notch downgrade in the Company's credit rating. The collateral required for contracts with adequate assurance clauses that are in a net liability position as of ~~March 31,~~June 30, 2014 was $5571 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 $2122 million as of ~~March 31,~~June 30, 2014.

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

2426

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 2013 Form 10-K. Long-term debt and capital leases consisted of the following:


(In millions, except rates)	March 31, 2014		December 31, 2013		Current interest rate % ^(a)	June 30, 2014		December 31, 2013		Current interest rate % ^(a)

Recourse debt:
Senior notes, due 2018	$	1,130	$	1,130	7.625	$	1,130	$	1,130	7.625
Senior notes, due 2019	709		800		7.625	—		800		7.625
Senior notes, due 2019	296		602		8.500	223		602		8.500
Senior notes, due 2020	1,063		1,062		8.250	1,063		1,062		8.250
Senior notes, due 2021	1,128		1,128		7.875	1,128		1,128		7.875
Senior notes, due 2022	$	1,100	—		6.250	1,100		—		6.250
Senior notes, due 2023	990		990		6.625	990		990		6.625
Senior notes, due 2024						1,000		—		6.250
Term loan facility, due 2018	1,997		2,002		L+3.00/L+2.00	1,992		2,002		L+2.00
Indian River Power LLC, tax-exempt bonds, due 2040 and 2045	247		247		5.375 - 6.00	247		247		5.375 - 6.00
Dunkirk Power LLC, tax-exempt bonds, due 2042	59		59		5.875	59		59		5.875
Fort Bend County, tax-exempt bonds, due 2038, 2042, and 2045	67		67		4.750	67		67		4.750
Subtotal NRG recourse debt	8,786		8,087			8,999		8,087
Non-recourse debt:
GenOn senior notes, due 2017	778		782		7.875	774		782		7.875
GenOn senior notes, due 2018	774		780		9.500	769		780		9.500
GenOn senior notes, due 2020	618		621		9.875	616		621		9.875
GenOn Americas Generation senior notes, due 2021	501		503		8.500	499		503		8.500
GenOn Americas Generation senior notes, due 2031	434		435		9.125	434		435		9.125
Subtotal GenOn debt (non-recourse to NRG)	3,105		3,121			3,092		3,121
NRG Marsh Landing, due 2017 and 2023	465		473		L+2.75 - 3.00	464		473		L+2.75 - 3.00
South Trent Wind LLC, due 2020	68		69		L+2.625
NRG Energy Center Minneapolis LLC, due 2017 and 2025	125		127		5.95 - 7.25	124		127		5.95 - 7.25
NRG Solar Alpine LLC, due 2022	158		221		L+2.50	170		221		L+2.50/L+1.75
NRG Solar Borrego I LLC, due 2024 and 2038	78		78		L+2.50/5.65	77		78		L+2.50/5.65
NRG Solar Avra Valley LLC, due 2031	62		63		L+2.25
NRG West Holdings LLC, due 2023						520		512		L+2.50 - 2.875
NRG Yield Inc. Convertible Senior Notes, due 2019	323		—		3.5	324		—		3.5
NRG Yield - other	102		102		various	320		372		various
Subtotal NRG Yield debt (non-recourse to NRG)	1,381		1,133			1,999		1,783
CVSR High Plains Ranch II LLC, due 2037	798		1,104		2.339 - 3.579	798		1,104		2.339 - 3.775
NRG West Holdings LLC, due 2023	520		512		L+2.50 - 2.875
Agua Caliente Solar LLC, due 2037	889		878		2.395 - 3.633	923		878		2.395 - 3.633
Ivanpah Financing, due 2014, 2015 and 2038	1,588		1,575		1.116 - 4.256
Ivanpah Financing, due 2014, 2015, 2033 and 2038						1,595		1,575		0.437 - 4.256
NRG Peaker Finance Co. LLC, bonds due 2019	127		154		L+1.07	128		154		L+1.07
TA - High Desert LLC, due 2014, 2023 and 2033	79		80		L+2.50/5.15
NRG Solar Kansas South LLC, due 2014 and 2031	58		58		L+2.00 - 2.625
Tapestry Wind LLC, due 2021						196		—		L+2.50
Walnut Creek, term loans due 2023						409		—		L+2.25
Viento Funding II, Inc., due 2023						198		—		L+2.75
Cedro Hill Wind LLC, due 2025						113		—		L+3.125
NRG - other	146		102		various	538		102		various
Subtotal NRG non-recourse debt	4,205		4,463			4,898		3,813
Subtotal non-recourse debt (including GenOn and NRG Yield)	8,691		8,717			9,989		8,717
Subtotal long-term debt (including current maturities)	17,477		16,804			18,988		16,804
Capital leases:
Chalk Point capital lease, due 2015	9		10		8.190	7		10		8.190
Other	2		3		various	3		3		various
Subtotal long-term debt and capital leases (including current maturities)	17,488		16,817			18,998		16,817
Less current maturities	685		1,050			833		1,050
Total long-term debt and capital leases	$	16,803	$	15,767		$	18,165	$	15,767

(a) As of ~~March 31,~~June 30, 2014, L+ equals 3 month LIBOR plus x%, with the exception of the NRG Solar Kansas South LLC ~~cash grant bridge loan which are 1 month LIBOR plus x%~~ and ~~NRG Solar Kansas South LLC~~Viento Funding II term loan which is 6 month LIBOR plus x%.

2527

NRG Recourse Debt

Senior Notes

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 May 1, 2024. ~~The Company expects to utilize~~A portion of the cash proceeds were used to redeem all remaining of ~~the outstanding 8.5% and~~its 7.625% 2019 Senior Notes, and the rest of the proceeds are expected to be used to redeem all remaining $225 million of its 8.5% 2019 Senior Notes in September 2014, as ~~described~~discussed below.

In connection with the 2024 Senior Notes, NRG entered into a registration payment arrangement. Failure to file a registration statement relating to the 2024 Senior Notes by January 29, 2015 will result in a registration default. For the first 90-day period immediately following a registration default, additional interest will be paid in an amount equal to 0.25% per annum of the principal amount of 2024 Senior Notes outstanding, as applicable. The amount of interest paid will increase by an additional 0.25% per annum with respect to each subsequent 90-day period until all registration defaults are cured, up to a maximum amount of interest of 1.0% per annum of the principal amount of the 2024 Senior Notes outstanding, as applicable. The additional interest is paid on the next scheduled interest payment date and following the cure of the registration default, the additional interest payment will cease.

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 described below, and to fund the acquisition of EME, as further described in Note 3, Business Acquisitions and Dispositions.

In connection with the 2022 Senior Notes, NRG entered into a registration payment arrangement. Failure to file a registration statement relating to the 2022 Senior Notes by November 6, 2014 will result in a registration default. For the first 90-day period immediately following a registration default, additional interest will be paid in an amount equal to 0.25% per annum of the principal amount of 2022 Senior Notes outstanding, as applicable. The amount of interest paid will increase by an additional 0.25% per annum with respect to each subsequent 90-day period until all registration defaults are cured, up to a maximum amount of interest of 1.0% per annum of the principal amount of the 2022 Senior Notes outstanding, as applicable. The additional interest is paid on the next scheduled interest payment date and following the cure of the registration default, the additional interest payment will cease.

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 ~~will be~~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 ~~April~~May 21, 2014, NRG ~~gave the required notice to redeem~~redeemed for cash all of its remaining 7.625% 2019 Senior Notes at an average early redemption percentage of 103.813%. A $18 million loss on ~~May 21, 2014. The~~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.

On August 4, 2014, the Company ~~expects~~announced that it gave the required notice under the governing indenture to redeem for cash all of its remaining 8.5% 2019 Senior Notes ~~when such notes become callable.~~ on September 3, 2014, at an average early redemption percentage of 104.25%.

Senior Credit Facility

On June 4, 2013, NRG amended the Term Loan Facility to (i) obtain additional financing of $450 million, which was issued at a discount of 99.5%; and (ii) adjust the interest rate from LIBOR plus 2.50% to LIBOR plus 2.00%. In addition, the Company redeemed and re-issued $407 million of the Term Loan Facility to new lenders resulting in a $7 million loss on debt extinguishment, recorded during the three months ended June 30, 2013, which primarily consisted of the write-off of previously deferred financing costs and unamortized discount. The proceeds from the additional $450 million borrowed were used for general corporate purposes, including the redemption of the 2014 GenOn Senior Notes. Debt issuance costs of $23 million and a discount on debt issuance of $4 million will be amortized to interest expense through the maturity date of the Term Loan Facility.

The Company also amended the Revolving Credit Facility to (i) increase the capacity by $211 million to a total of $2.5 billion; (ii) adjust the interest rate to LIBOR plus 2.25%; and (iii) extend the maturity date to July 1, 2018 to coincide with the maturity date of the Term Loan Facility. As a result of the amended Revolving Credit Facility, the Company capitalized debt issuance costs of $4 million, which will be amortized to interest expense through the maturity date of the Revolving Credit Facility. A $3 million loss on debt extinguishment was recorded during the three months ended June 30, 2013 related to the write-off of previously deferred financing costs.

Senior Notes Repurchases

On December 17, 2012, NRG entered into an agreement with a financial institution to repurchase up to $200 million of the Senior Notes in the open market by February 27, 2013. In the first quarter of 2013, the Company paid $80 million, $104 million, and $42 million, at an average price of 114.179%, 111.700%, and 113.082% of face value, for repurchases of the Company's 2018 Senior Notes, 2019 Senior Notes and 2020 Senior Notes, respectively. A $28 million loss on the debt extinguishment of the 2018 Senior Notes, 2019 Senior Notes and 2020 Senior Notes was recorded during the three months ended March 31, 2013 which primarily consisted of the premiums paid on the repurchases 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 first 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.

Ivanpah Financing — Cash Grant Bridge Loans

On June 24, 2014, Solar Partners I received an extension with respect to its borrowings under the Ivanpah Credit Agreement previously due on June 27, 2014, which are subsequently due December 27, 2014. On February 27, 2014, Solar Partners II received an extension with respect to its borrowings previously due in 2014, which are subsequently due in February 2015. The borrowings of Solar Partners VIII are due in October 2014. Solar Partners I, Solar Partners II, and Solar Partners VIII submitted applications to the U.S. Department of Treasury for cash grants; any proceeds received will be utilized to repay the borrowings.

Redemption of GenOn Senior Notes

In June 2013, the Company redeemed all of the 2014 GenOn Senior Notes with an aggregate outstanding principal amount of $575 million at a redemption price of 106.778% of face value as well as any accrued and unpaid interest as of the redemption date. In connection with the redemption, an $11 million loss on the debt extinguishment of the 2014 GenOn Senior Notes was recorded during the three months ended June 30, 2013 which primarily consisted of a make whole premium payment offset by the write-off of unamortized premium.

2629

EME Project Financings

The following table summarizes the terms of the significant non-recourse project level debt assumed by NRG in the EME acquisition:



Amount in millions, except rates	Term Loan Facility				Letter of Credit Facility				Bond Facility
Non-Recourse Debt	Amount Outstanding as of June 30, 2014		Interest Rate	Maturity Date	Amount Outstanding as of June 30, 2014		Interest Rate	Maturity Date	Amount Outstanding as of June 30, 2014		Interest Rate	Maturity Date
Broken Bow Wind	$	49	3-Month LIBOR + 2.875%	12/31/2027	$	—	—	—	$	—	—	—
Cedro Hill Wind	113		3-Month LIBOR + 3.125%	12/31/2025	—		—	—	—		—	—
Crofton Bluffs	25		3-Month LIBOR + 2.875%	12/31/2027	—		—	—	—		—	—
Laredo Ridge Wind	67		3-Month LIBOR + 2.875%	3/31/2026	—		—	—	—		—	—
Tapestry Wind	196		3-Month LIBOR + 2.500%	12/21/2021	20		2.500%	12/21/2021	—		—	—
Viento Funding II	198		6-Month LIBOR + 2.750%	7/11/2023	27		2.750%	7/11/2020	—		—	—
Walnut Creek Energy	409		3-Month LIBOR + 2.250%	5/31/2023	60		2.000%	5/17/2023	—		—	—
WCEP Holding LLC	53		3-Month LIBOR + 4.000%	5/31/2023	—		—	—	—		—	—
American Bituminous	—		—	—	38		2.650%	11/7/2014	36		0.06%/ Weekly per SIFMA rate^(a)	10/1/2017
High Lonesome Mesa	—		—	—	—		—	—	62		6.850%	11/1/2017
Various	15		various	various	52		various	various	—		—	—
Total	$	1,125			$	197			$	98
(a) Securities Industry and Financial Markets Association, or SIFMA

Interest Rate Swaps — EME Project Financings

Many of EME's project subsidiaries entered into interest rate swaps, intended to hedge the risks associated with interest rates on non-recourse project level debt. These swaps amortize in proportion to their respective loans and are floating for fixed where the project subsidiary pays its counterparty the equivalent of a fixed interest payment on a predetermined notional value and will receive quarterly the equivalent of a floating interest payment based on the same notional value. All interest rate swap payments by the project subsidiary and its counterparty are made quarterly and the LIBOR is determined in advance of each interest period. The following table summarizes the swaps related to EME's project level debt as of June 30, 2014.



Non-Recourse Debt	% of Principal		Fixed Interest Rate		Floating Interest Rate	Notional Amount at June 30, 2014 (In millions)		Effective Date	Maturity Date
Walnut Creek Energy	90	%	3.543	%	3-Month LIBOR	$	368	June 28, 2013	May 31, 2023
WCEP Holdings	90	%	4.003	%	3-Month LIBOR	48		June 28, 2013	May 31, 2023
Viento Funding II	90	%	various		6-Month LIBOR	179		various	various
Viento Funding II	90	%	4.985	%	6-Month LIBOR	63		July 11, 2023	June 30, 2028
Cedro Hill	90	%	4.290	%	3-Month LIBOR	102		December 31, 2010	December 31, 2025
Laredo Ridge	90	%	3.460	%	3-Month LIBOR	60		March 31, 2011	March 31, 2026
Tapestry	90	%	2.210	%	3-Month LIBOR	176		December 30, 2011	December 21, 2021
Tapestry	75	%	3.570	%	3-Month LIBOR	60		December 21, 2021	December 21, 2029
Broken Bow	90	%	2.960	%	3-Month LIBOR	44		December 31, 2013	December 31, 2027
Crofton Bluffs	90	%	2.748	%	3-Month LIBOR	23		December 31, 2013	December 31, 2027
Total						$	1,123

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 was a default under a project financing arrangement that, after the closing of the acquisition, ripened into an event of default. 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.

NRG ~~Non-Recourse Debt~~Yield Operating LLC Senior Notes

On August 5, 2014, Yield Operating issued $500 million of senior unsecured notes with the intention of utilizing the proceeds to fund the acquisition of the Alta Wind Assets. The Yield Operating senior notes bear interest at 5.375% and mature in August 2024. Interest on the notes is payable semi-annually on February 15 and August 15 of each year, commencing on February 15, 2015. The notes are senior unsecured obligations of Yield Operating and will be guaranteed by NRG Yield LLC, Yield Operating’s parent company, and by certain of Yield Operating’s wholly owned current and future subsidiaries.

NRG Yield, Inc. Convertible 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 NRG Yield ~~Senior~~Convertible Notes. The NRG Yield ~~Senior~~Convertible Notes are convertible, under certain circumstances, into NRG Yield, Inc. Class A common stock, cash or a combination thereof at an initial conversion price of $46.55 per Class A common share, which is equivalent to an initial conversion rate of approximately 21.4822 shares of Class A common stock per $1,000 principal amount of NRG Yield ~~Senior~~Convertible Notes. Interest on the NRG Yield ~~Senior~~Convertible Notes is payable semi-annually in arrears on February 1 and August 1 of each year, commencing on August 1, 2014. The NRG Yield ~~Senior~~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 NRG Yield ~~Senior~~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. 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.

NRG Yield LLC and NRG Yield Operating LLC Revolving Credit Facility

NRG Yield LLC and ~~NRG~~ Yield Operating ~~LLC,~~ entered into a senior secured revolving credit facility, which provides a revolving line of credit of $60 million. On April 25, 2014, NRG Yield LLC and Yield Operating amended the revolving credit facility to increase the available line of credit to $450 million and extend its maturity to April 2019. The revolving credit facility can be used for cash or for the issuance of letters of credit. There was no cash drawn or letters of credit issued under the revolving credit facility as of ~~March 31,~~June 30, 2014. ~~On April 25, 2014, NRG Yield LLC and NRG Yield Operating LLC amended the revolving credit facility to increase the available line of credit to $450 million and extend its maturity to April 2019.~~

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.

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, ~~NRG~~ Yield Operating, ~~LLC,~~ the Company owns a 50% interest in GenConn, ~~a limited liability company~~ 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 $116 million as of ~~March 31,~~June 30, 2014.

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 $8480 million as of ~~March 31,~~June 30, 2014.

Texas Coastal Ventures LLC— As of June 30, 2014, NRG ~~owns~~owned a 50% interest in Texas Coastal Ventures, a joint venture with Hilcorp Energy I, L.P., through its subsidiary Petra Nova LLC. NRG's maximum exposure to loss is limited to its ~~equity~~ investment, which was $68 million as of ~~March 31,~~June 30, 2014. As further described in Note 3, Business Acquisitions and Dispositions, on July 3, 2014, NRG, through its wholly owned subsidiary Petra Nova Holdings LLC, sold 50% of its interest in Petra Nova Parish Holdings LLC to JX Nippon Oil Exploration (EOR) Limited, reducing its ownership interest in Texas Coastal Ventures to 25%.

Entities that are Consolidated

Capistrano Wind LLC— Through the acquisition of EME, the Company has a controlling financial interest in Capistrano Wind Partners, whose Class B preferred equity interest 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, 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 summarized financial information for Capistrano Wind Holdings consisted of the following:



(In millions)	June 30, 2014
Current assets	$	171
Net property, plant and equipment	644
Other long-term assets	6
Total assets	821

Current liabilities	29
Long-term debt	188
Other long-term liabilities	186
Total liabilities	403
Noncontrolling interests	$	388

2732

Note 9 — Changes in Capital Structure

As of ~~March 31,~~June 30, 2014 and December 31, 2013, 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	Issued	Treasury		Outstanding
Balance as of December 31, 2013	401,126,780	(77,347,528	)	323,779,252	401,126,780	(77,347,528	)	323,779,252
Shares issued under LTIPs	682,672	—		682,672	950,546	—		950,546
Shares issued under ESPP	—	71,595		71,595	—	71,595		71,595
Balance as of March 31, 2014	401,809,452	(77,275,933	)	324,533,519
Shares issued in connection with the EME acquisition					12,671,977	—		12,671,977
Balance as of June 30, 2014					414,749,303	(77,275,933	)	337,473,370

As discussed in Note 3, Business Acquisitions and Dispositions, on April 1, 2014, the Company issued 12,671,977 shares of NRG common stock in connection with the acquisition of EME.

Employee Stock Purchase Plan

On May 8, 2014, NRG stockholders approved an increase of 800,000 shares available for issuance under the NRG Energy, Inc. Amended and Restated Employee Stock Purchase Plan, or ESPP. Subsequent to this approval, 1,616,793 shares of treasury stock were available for issuance under the ESPP. In July 2014, 56,845 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 ~~three~~six months ended ~~March 31,~~June 30, 2014:

First Quarter 2014
Dividends per Common Share $ 0.12



	Second Quarter 2014		First Quarter 2014
Dividends per Common Share	$	0.14	$	0.12

On ~~April 21,~~July 18, 2014, NRG declared a quarterly dividend on the Company's common stock of $0.14 per share, payable ~~May~~August 15, 2014, to stockholders of record as of ~~May~~August 1, 2014, representing $0.56 on an annualized ~~basis, a 17% increase from $0.48 per share.~~

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

Note 10 — ~~Loss~~(Loss)/Earnings Per Share

Basic ~~loss~~(loss)/earnings per common share is computed by dividing net ~~loss~~(loss)/income 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)/earnings per share is computed in a manner consistent with that of basic (loss)/earnings 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~~(loss)/earnings per share is shown in the following table:

Three months ended March 31,
(In millions, except per share data) 2014 2013
Basic and diluted loss per share attributable to NRG common stockholders
Net loss attributable to NRG Energy, Inc. $ (56 ) $ (332 )
Dividends for preferred shares 2
2
Loss Available for Common Stockholders $ (58 ) $ (334 )
Weighted average number of common shares outstanding 324

323
Loss per weighted average common share — basic and diluted $ (0.18 ) $ (1.03 )



	Three months ended June 30,					Six months ended June 30,
(In millions, except per share data)	2014			2013		2014			2013
Basic (loss)/earnings per share attributable to NRG Energy, Inc. common stockholders
Net (loss)/income attributable to NRG Energy, Inc.	$	(97	)	$	124	$	(153	)	$	(208	)
Dividends for preferred shares	3			3		5			5
(Loss)/earnings available for common stockholders	$	(100	)	$	121	$	(158	)	$	(213	)
Weighted average number of common shares outstanding	337			323		331			323
(Loss)/earnings per weighted average common share — basic	$	(0.30	)	$	0.37	$	(0.48	)	$	(0.66	)
Diluted (loss)/earnings per share attributable to NRG Energy, Inc. common stockholders
Weighted average number of common shares outstanding	337			323		331			323
Incremental shares attributable to the issuance of equity compensation (treasury stock method)	—			4		—			—
Total dilutive shares	337			327		331			323
(Loss)/earnings per weighted average common share — diluted	$	(0.30	)	$	0.37	$	(0.48	)	$	(0.66	)

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~~(loss)/earnings per share:


	Three months ended March 31,		Three months ended June 30,		Six months ended June 30,
(In millions of shares)	2014	2013	2014	2013	2014	2013
Equity compensation plans	8	13	8	2	8	11
Embedded derivative of 3.625% redeemable perpetual preferred stock	16	16	16	16	16	16
Total	24	29	24	18	24	27

2834

Note 11 — Segment Reporting

Effective June ~~2013,~~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 Texas and South Central segments were combined to form the Gulf Coast segment. 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 primarily segregated based on the Retail Business, conventional power generation, ~~alternative energy~~renewable businesses, NRG Yield and corporate activities. Within NRG's conventional power generation, there are distinct components with separate operating results and management structures for the following geographical regions: ~~Texas,~~Gulf Coast, East ~~South Central, West~~ and ~~Other, which includes international businesses and maintenance services.~~West. The Company's ~~alternative energy~~renewables segment includes solar and wind assets, excluding those in the NRG Yield ~~segment, electric vehicle services and the carbon capture business.~~segment. NRG Yield includes certain of the Company's contracted generation assets including ~~three~~four natural gas or dual-fired facilities, ~~eight~~ten utility-scale solar and wind generation facilities, two portfolios of distributed solar facilities and thermal infrastructure assets. On June 30, 2014, NRG Yield acquired three projects from the Company: El Segundo Energy Center, formerly in the West segment, Kansas South and High Desert, both formerly in the renewables 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, electric vehicle services, energy services, residential solar and the carbon capture business. Intersegment sales are accounted for at market.



(In millions)				Conventional Power Generation
Three months ended June 30, 2014	Retail^(a)			Gulf Coast^(a)		East^(a)		West^(a)		Renewables^(a)			NRG Yield^(a)		Corporate^(a)(b)			Elimination			Total
Operating revenues	$	1,879		$	1,003	$	881	$	165	$	164		$	134	$	60		$	(665	)	$	3,621
Depreciation and amortization	33			144		74		27		58			36		14			—			386
Equity in earnings/(losses) of unconsolidated affiliates	—			1		1		10		(2		)	14		4			(14		)	14
(Loss)/income before income taxes	(111		)	134		6		33		1			36		(290		)	(15		)	(206		)
Net (loss)/income attributable to NRG Energy, Inc.	(112		)	134		6		33		(19		)	28		(166		)	(1		)	(97		)
Total assets as of June 30, 2014	$	5,531		$	14,459	$	10,260	$	2,158	$	8,381		$	3,236	$	28,311		$	(34,707	)	$	37,629

(In millions) Conventional Power Generation
Three months ended March 31, 2014
Retail^(a)

Texas^(a)

East^(a)

South^(a)
Central

West^(a)

Other^(a)

Alternative Energy^(a)

NRG Yield^(a)

Corporate^(a)(b)
Elimination Total
Operating revenues $ 1,526
$ 254
$ 1,400
$ 220
$ 137
$ 46
$ 54
$ 110
$ 2
$ (263 ) $ 3,486
Depreciation and amortization 33
117
66
26
18
1
51
17
6
—
335
Equity in earnings/(losses) of unconsolidated affiliates —
—
—
—
4
2
(2 ) 1
—
2
7
Income/(loss) before income taxes 291
(324 ) 219
(13 ) 16
3
(76 ) 21
(237 ) 2
(98 )
Net income/(loss) attributable to NRG Energy, Inc. $ 291
$ (324 ) $ 219
$ (13 ) $ 16
$ 1
$ (59 ) $ 14
$ (205 ) $ 4
$ (56 )
Total assets as of March 31, 2014 $ 5,173
$ 11,597
$ 9,625
$ 2,640
$ 1,671
$ 542
$ 6,006
$ 2,534
$ 28,110
$ (32,937 ) $ 34,961



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	2	$	698	$	(53	)	$	—	$	4	$	—	$	14

(a) Operating revenues include inter-segment sales and net derivative gains and losses of: $ 2
$ 289
$ 83
$ —
$ —
$ 24
$ 6
$ —
$ 2

(b) Includes loss on debt extinguishment of ~~$41 million~~

$40 million.

(In millions) Conventional Power Generation
Three months ended March 31, 2013
Retail^(c)

Texas^(c)

East^(c)

South^(c)
Central

West^(c)

Other^(c)

Alternative Energy^(c)
NRG Yield
Corporate^(c)(d)
Elimination Total
Operating revenues $ 1,231
$ 84
$ 595
$ 196
$ 91
$ 34
$ 35
$ 53
$ 4
$ (242 ) $ 2,081
Depreciation and amortization 32
113
86
24
13
1
24
10
4
—
307
Equity in earnings of unconsolidated affiliates —
—
—
—
1
1
2
4
—
(5 ) 3
Income/(loss) before income taxes 369
(426 ) (159 ) (7 ) (7 ) 4
(24 ) 11
(244 ) —
(483 )
Net income/(loss) attributable to NRG Energy, Inc. $ 369
$ (426 ) $ (159 ) $ (7 ) $ (7 ) $ 4
$ (25 ) $ 11
$ (92 ) $ —
$ (332 )



(In millions)				Conventional Power Generation
Three months ended June 30, 2013	Retail^(c)			Gulf Coast^(c)		East^(c)		West^(c)		Renewables^(c)			NRG Yield^(c)		Corporate^(c)(d)			Elimination			Total
Operating revenues	$	1,535		$	963	$	826	$	124	$	55		$	82	$	26		$	(682	)	$	2,929
Depreciation and amortization	36			136		87		12		25			10		7			—			313
Equity in earnings/(loss) of unconsolidated affiliates	—			1		—		1		(1		)	2		—			5			8
(Loss)/income before income taxes	(82		)	180		133		36		(13		)	35		(219		)	(2		)	68
Net (loss)/income attributable to NRG Energy, Inc.	$	(82	)	$	180	$	133	$	36	$	(22	)	$	35	$	(156	)	$	—		$	124

(c) Operating revenues include inter-segment sales and net derivative gains and losses of: $ 1
$ 229
$ (9 ) $ 2
$ —
$ 16
$ 4
$ —
$ 4



(c) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	1	$	606	$	66	$	3	$	—	$	—	$	6

(d)Includes loss on debt extinguishment of ~~$28 million~~.$21 million.

2935



(In millions)			Conventional Power Generation
Six months ended June 30, 2014	Retail^(e)		Gulf Coast^(e)			East^(e)		West^(e)		Renewables^(e)			NRG Yield^(e)		Corporate^(e)(f)			Elimination			Total
Operating revenues	$	3,405	$	1,477		$	2,281	$	275	$	214		$	274	$	98		$	(917	)	$	7,107
Depreciation and amortization	66		287			140		39		106			60		23			—			721
Equity in earnings/(losses) of unconsolidated affiliates	—		1			—		14		(6		)	15		4			(7		)	21
Income/(loss) before income taxes	180		(203		)	225		41		(64		)	65		(526		)	(22		)	(304		)
Net income/(loss) attributable to NRG Energy, Inc.	$	179	$	(203	)	$	225	$	41	$	(67	)	$	50	$	(372	)	$	(6	)	$	(153	)



(e) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	4	$	839	$	30	$	—	$	4	$	—	$	40

(f) Includes loss on debt extinguishment of $81 million



(In millions)			Conventional Power Generation
Six months ended June 30, 2013	Retail^(g)		Gulf Coast^(g)			East^(g)			West^(g)		Renewables^(g)			NRG Yield^(g)		Corporate^(g)(h)			Elimination			Total
Operating revenues	$	2,766	$	1,243		$	1,421		$	213	$	89		$	135	$	57		$	(914	)	$	5,010
Depreciation and amortization	68		273			173			25		48			20		13			—			620
Equity in earnings of unconsolidated affiliates	—		2			—			2		1			6		—			—			11
Income/(loss) before income taxes	287		(251		)	(25		)	32		(28		)	46		(470		)	(6		)	(415		)
Net income/(loss) attributable to NRG Energy, Inc.	$	287	$	(251	)	$	(25	)	$	32	$	(38	)	$	46	$	(255	)	$	(4	)	$	(208	)



(g) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	2	$	837	$	58	$	3	$	—	$	—	$	14

(h) Includes loss on debt extinguishment of $49 million

Note 12 — Income Taxes

Effective Tax Rate

The income tax provision consisted of the following:


	Three months ended March 31,						Three months ended June 30,						Six months ended June 30,
(In millions except otherwise noted)	2014			2013			2014			2013			2014			2013
Loss before income taxes	$	(98	)	$	(483	)
(Loss)/income before income taxes							$	(206	)	$	68		$	(304	)	$	(415	)
Income tax benefit	(31		)	(152		)	(126		)	(63		)	(157		)	(215		)
Effective tax rate	31.6		%	31.5		%	61.2		%	(92.6		)%	51.6		%	51.8		%

For the three and six months ended ~~March 31,~~June 30, 2014, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the impact of ~~non-taxable equity earnings,~~ production tax credits generated from our wind assets and the ~~impact~~recognition of ~~state and local income taxes.~~uncertain tax benefits.

For the three and six months ended ~~March 31,~~June 30, 2013, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to ~~change~~the recognition of ITCs from the Company's Agua Caliente solar project in Arizona and the ~~valuation allowance as a result~~impact of ~~capital losses generated during the period.~~non-taxable equity earnings.

Uncertain Tax Benefits

As of ~~March 31,~~June 30, 2014, NRG has recorded a non-current tax liability of ~~$63~~$68 million for uncertain tax benefits from positions taken on various state income tax returns, including accrued interest. NRG has accrued interest related to these uncertain tax benefits of $1 million for the ~~three~~six months ended ~~March 31,~~June 30, 2014, and has accrued $1415 million of interest and penalties since adoption. 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 ~~2007.~~2010. With few exceptions, state and local income tax examinations are no longer open for years before 2004. The Company's primary foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2010.

3037

Note 13 — Commitments and Contingencies

Commitments

This footnote should be read in conjunction with the complete description under Note 22, Commitments and Contingencies, to the Company's 2013 Form 10-K.

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 acquisition, ~~and~~ assets held by NRG Yield, Inc., and NRG's assets that have project-level financing to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. The Company's lien counterparties may have a claim on NRG's assets to the extent market prices exceed the hedged price. As of ~~March 31,~~June 30, 2014, hedges under the first lien were out-of-the-money for NRG on a counterparty aggregate basis.

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, LLC Asbestos Liabilities

The Company, through its subsidiary, Midwest Generation, LLC, 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, LLC.

NRG Energy Center San Francisco LLC

In 2013, NRG Energy Center San Francisco LLC received a Notice of Violation from the San Francisco Department of Public Health alleging improper monitoring of three underground storage tanks. The tanks have not leaked. ~~The Company anticipates settling this~~This matter inwas settled on July 21, 2014 for ~~approximately~~ $~~137,000~~123,270.

Louisiana Generating, LLC

Big Cajun II Alleged Opacity Violations — On September 7, 2012, LaGen received a Consolidated Compliance Order & Notice of Potential Penalty, or CCO&NPP, from the LDEQ. The CCO&NPP alleges there were opacity exceedance events from the Big Cajun II Power Plant on certain dates during the years 2007-2012. In February 2014, LaGen and LDEQ settled this matter for approximately $47,000.

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 ~~GenOn Energy Holdings'~~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 ~~GenOn Energy Holdings'~~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.

Pending 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 antitrust 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 is 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. The ~~Ninth Circuit~~Court of Appeals reversed the decision of the ~~U.S.~~ District ~~Court for the District of Nevada.~~Court. On August 26, 2013, GenOn along with the other defendants in the lawsuit filed a petition for a writ of certiorari to the U.S. Supreme Court challenging the ~~Ninth Circuit’s~~Court of Appeal’s decision. On ~~December 2, 2013,~~July 1, 2014, the U.S. Supreme Court ~~requested the views of the U.S. Solicitor General on~~granted the petition for a writ of certiorari.

In September 2012, the State of Nevada Supreme Court, which is 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. GenOn has agreed to indemnify CenterPoint against certain losses relating to these 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. The Company disputes these allegations. Plaintiffs have brought nuisance, negligence, trespass and strict liability claims seeking both damages and injunctive relief. Plaintiffs seek to certify a class that consists of people who own property or live 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. In October 2012, the ~~court~~District Court granted the Company's motion to dismiss, which ~~Plaintiffs~~plaintiffs appealed to the U.S. Court of Appeals for the Third Circuit. On August 20, 2013, the ~~Third Circuit~~Court of Appeals reversed the decision of the District Court. On September 3, 2013, the Company filed a petition for rehearing with the ~~Third Circuit~~Court of Appeals which was subsequently denied. In February 2014, the Company filed a petition for a writ of certiorari to the U.S. Supreme Court seeking review and reversal of the ~~Third Circuit~~Court of Appeals decision. ~~The District~~On June 2, 2014, the U.S. Supreme Court ~~has stayed further proceedings in the case pending a decision on~~denied the petition for a writ of certiorari. The case is proceeding in the U.S. District Court for the Western District of Pennsylvania.

Cheswick Monarch Mine NOV

In 2008, the PADEP issued an NOV related to the Monarch mine located near the Cheswick generating facility. It has not been mined for many years. The Company uses itthe Monarch mine for disposal of low-volume wastewater from the Cheswick generating facility and for disposal of leachate collected from ash disposal facilities. The NOV addresses the alleged requirement to maintain a minimum pumping volume from the mine. The PADEP indicated it will seek a civil penalty of approximately $200,000. The Company contests the allegations in the NOV and has not agreed to such penalty. The Company is currently planning to incur capital expenditures in connection with wastewater from Cheswick and leachate from ash disposal facilities.

Energy Plus Holdings

In May 2014, Energy Plus Holdings ~~continues to cooperate~~executed a settlement agreement with the Connecticut Office of Attorney General and Office of Consumer Counsel and the State of New York Office of Attorney General to resolve certain issues related to Energy Plus Holdings's sales, marketing and business practices. Energy Plus Holdings has been involved in settlement discussions with the Connecticut Office of Attorney General, the Connecticut Office of Consumer Counsel related to its sales, marketing and business practices in Connecticut. The settlement was in accordance with the Company's established reserve for this matter. Energy Plus Holdings continues to cooperate and discuss a resolution of issues with respect to its sales, marketing and business practices in New York with the New York Office of Attorney ~~General to reach a resolution of the matters in the respective states.~~General.

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 NRG 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 the Company a similar letter with respect to the Chalk Point and Dickerson facilities, threatening to sue within 60 days if the Company did not bring itself 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 Clean Water Act and Maryland environmental laws related to water. The lawsuit is ongoing and seeks injunctive relief and civil penalties in excess of $100,000.

3240

Note 14 — Regulatory Matters

This footnote should be read in conjunction with the complete description under Note 23, Regulatory Matters, to the Company's 2013 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 U.S. Court of Appeals for the District of Columbia Circuit vacated FERC’s rules (known as Order No. 745) that allow demand response resources to participate in the FERC-jurisdictional energy markets. The Court of Appeals held that the Federal Power Act 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 solely to energy market participation, but this ruling also calls into question whether demand response will be permitted to participate in the capacity markets in the future. FERC has asked the U.S. Court of Appeals for the District of Columbia Circuit to rehear en banc the decision. 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 estimate the impact on the Company at this time.

West Region

California Station Power — On December 18, 2012, in Calpine Corporation v. FERC, the U.S. Court of Appeals for the ~~D.C.~~District of Columbia Circuit upheld a decision by FERC disclaiming jurisdiction over how the states impose retail station power charges. The CPUC may now establish retail charges for future station power consumption. Due to reservation-of-rights language in the California utilities' state-jurisdictional station power tariffs, the ~~court's~~ ruling ~~arguably requires~~of the Court of Appeals may require California generators to pay state-imposed retail charges back to the date of enrollment by the facilities in the CAISO's station period program (February 1, 2009, for the Company's Encina and El Segundo facilities; March 1, 2009, for the Company's Long Beach facility).

On November 18, 2011, Southern California Edison Company, or SCE, filed with the CPUC, seeking authorization to begin charging generators station power charges, and to assess such charges retroactively, which the Company and other generators have challenged. On ~~August 13, 2012,~~July 14, 2014, the CPUC ~~Energy Division~~ issued a draft resolution ~~in which it rejected~~describing the ~~Company's arguments and approved Southern California Edison's proposed station power charges, including retroactive implementation, but proposing a credit~~method to ~~generators for some portion of their retail station power bill. However, the CPUC withdrew the draft resolution from the calendar and consideration of the measure has not yet been rescheduled.~~

~~On April 14, 2014, the CPUC put forth Draft Resolutions for how station power will~~ be ~~handled in the~~used by SCE and PG&E ~~service territories.~~to determine station power charges. The ~~Draft Resolutions establish~~draft resolution establishes a 15 minute netting period, to take effect ~~December 18, 2012,~~August 30, 2010, which means that there would be no refund liability associated with station power consumption prior to ~~December 18, 2012.~~August 30, 2010. The draft resolution remains under consideration by the CPUC and is ~~expected to take up the Draft Resolutions at its May meeting.~~scheduled for Commission action on August 14, 2014. If approved, ~~parties~~the Company would have 30 days to appeal the ruling before it would be considered final.

~~Texas~~Gulf Coast Region

South Texas Project — On March 31, 2014, STP submitted the response to a request for information from the NRC regarding the re-evaluation of the seismic hazard at the site, conducted in response to recommendation 2.1 of the Near-Term Task Force that was convened in response to the accident at Fukushima. On March 12, 2012, after the initial industry-wide submittal was reviewed by the NRC, the agency questioned the varying standards applied to risk assessment for seismic hazards used for initial licensing at some stations. As a result, all stations were directed to re-evaluate the risk against present-day requirements and the current design basis. The seismic evaluation of the STP site, recently conducted when preparing the application for a combined construction and operating license for the STP Units 3 & 4 development project, provided some assurance of the adequacy of the walk-downs and analyses to be conducted. The station followed the guidance in the “Seismic Evaluation Guidance: Screening, Prioritization, and Implementation Details (SPID) for the Resolution of Fukushima Near-Term Task Force Recommendation 2.1: Seismic” report published by the Electric Power Research Institute. This re-evaluation confirmed that the updated ground motion response spectrum does not exceed the bounds of the ~~safe shutdown earthquake found in the current design basis~~operating license and as a result, no further evaluations need to be performed.

3341

Note 15 — Environmental Matters

This footnote should be read in conjunction with the complete description under Note 24, Environmental Matters, to the Company's 2013 Form 10-K.

NRG is subject to a wide range of environmental ~~regulations~~laws in the development, ownership, construction and operation of projects in the United States and certain international regions. These laws ~~and regulations~~ generally require that governmental permits and approvals be obtained before construction and during operation of power plants. Environmental ~~regulations~~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 greenhouse gases, as well as combustion byproducts, water discharge and use, and threatened and endangered species. In general, future laws ~~and regulations~~ 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 released CSAPR ~~on July 7,~~in 2011, which was scheduled to replace CAIR onin January 1, 2012. ~~On August 21, 2012,~~In December 2011, the U.S. Court of Appeals for the ~~D.C.~~District of Columbia Circuit stayed the implementation of CSAPR and then issued an opinion in August 2012 vacating CSAPR and keeping CAIR in place until the EPA can replace it. On April 29, 2014, the U.S. Supreme Court reversed and remanded the D.C. Circuit's opinion. ~~NRG~~The Company expects further proceedings in the ~~D.C. Circuit~~Court of Appeals over the next few months. While NRG is unable to predict the final outcome of the ongoing litigation, the Company believes its investment in pollution controls and cleaner technologies coupled with planned ~~strategic~~ plant ~~retirement~~retirements should leave the fleet well positioned for compliance.

In January 2014, the EPA re-proposed the NSPS for CO₂ emissions from new fossil-fuel-fired electric generating units that had been previously proposed in April 2012. The re-proposed standards are ~~1000~~1,000 pounds of CO₂per MWh for large gas units and ~~1100~~1,100 pounds of CO₂ per MWh for coal units and small gas units. Proposed standards are in effect until a final rule is published or another rule is re-proposed. InOn June 18, 2014, the EPA ~~intends to propose another~~proposed a rule that would require states to develop CO₂ emission standards that would apply to existing fossil-fueled generating facilities. Specifically, the EPA proposed state-specific rate-based standards for CO₂ emissions, as well as guidelines for states to follow in developing plans to achieve the state-specific standards. The EPA anticipates finalizing this rule in June 2015.

Water

In May 2014, the EPA released a prepublication version of the final regulation regarding once through cooling from 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.

East Region

The MDE has announced that it intends to promulgate more stringent regulations regarding SO₂and NO_xemissions, which could negatively affect certain of the Company's coal facilities located in Maryland.

Environmental Capital Expenditures

Based on current rules, technology and preliminary plans based on some proposed rules, NRG estimates that environmental capital expenditures from 2014 through 2018 required to comply with environmental laws will be approximately $~~326~~906 million which includes $~~116~~123 million for ~~GenOn.~~GenOn and $567 million (of which $22 million is attributable to interest during construction) for plants acquired in the EME acquisition.

In connection with the acquisition of EME, as further described in Note 3, Business Acquisitions and Dispositions, NRG has committed to fund up to $350 million in capital expenditures for plant modifications at Powerton and Joliet to comply with MATS, of which the Company estimates that up to $100 million will be incurred in 2014. The Company is in the process of evaluating additional capital expenditures that will be incurred in connection with the acquisition and integration of EME. environmental regulations.

3442

Note 16 — Condensed Consolidating Financial Information

As of ~~March 31,~~June 30, 2014, the Company had outstanding $~~6.4~~6.6 billion of Senior Notes due from 2018 - ~~2023,~~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.~~subsidiaries, NRG Yield, Inc. and its subsidiaries and other subsidiaries of NRG that are subject to project financing.

Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of ~~March 31,~~June 30, 2014:



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

3543

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. ~~In addition,~~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.

3644

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Three Months Ended ~~March 31,~~June 30, 2014

(Unaudited)


	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)															(In millions)
Operating Revenues
Total operating revenues	$	2,279		$	1,251		$	—		$	(44	)	$	3,486		$	2,514		$	1,129		$	—		$	(22	)	$	3,621
Operating Costs and Expenses
Cost of operations	1,793			974			(4		)	(30		)	2,733			2,048			762			11			(4		)	2,817
Depreciation and amortization	198			134			3			—			335			211			170			5			—			386
Selling, general and administrative	105			57			64			—			226			106			82			80			—			268
Acquisition-related transaction and integration costs	—			1			11			—			12			—			7			33			—			40
Development activity expenses	—			10			9						19			—			7			14			—			21
Total operating costs and expenses	2,096			1,176			83			(30		)	3,325			2,365			1,028			143			(4		)	3,532
Gain on sale of assets	—			19			—			—			19
Operating Income/(Loss)	183			94			(83		)	(14		)	180			149			101			(143		)	(18		)	89
Other Income/(Expense)
Equity in earnings/(loss) of consolidated subsidiaries	49			(6		)	115			(158		)	—
Equity in earnings of consolidated subsidiaries																52			—			65			(117		)	—
Equity in earnings of unconsolidated affiliates	4			1			—			2			7			6			17			—			(9		)	14
Other income, net	1			4			7			(1		)	11
Other income/(loss), net																3			4			(2		)	—			5
Loss on debt extinguishment	—			(9		)	(32		)	—			(41		)	—			—			(40		)	—			(40		)
Interest expense	(6		)	(107		)	(143		)	1			(255		)	(5		)	(120		)	(149		)	—			(274		)
Total other expense	48			(117		)	(53		)	(156		)	(278		)
Total other income/(expense)																56			(99		)	(126		)	(126		)	(295		)
Income/(Loss) Before Income Taxes	231			(23		)	(136		)	(170		)	(98		)	205			2			(269		)	(144		)	(206		)
Income tax expense/(benefit)	63			(10		)	(84		)				(31		)	47			4			(177		)	—			(126		)
Net Income/(Loss)	168			(13		)	(52		)	(170		)	(67		)	158			(2		)	(92		)	(144		)	(80		)
Less: Net (loss)/income attributable to noncontrolling interest	—			(3		)	4			(12		)	(11		)
Less: Net income attributable to noncontrolling interest																—			39			5			(27		)	17
Net Income/(Loss) attributable to NRG Energy, Inc.	$	168		$	(10	)	$	(56	)	$	(158	)	$	(56	)	$	158		$	(41	)	$	(97	)	$	(117	)	$	(97	)


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

3745

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	3,841			1,736			7			(34		)	5,550
Depreciation and amortization	409			304			8			—			721
Selling, general and administrative	211			139			144			—			494
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/(loss) 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 attributable to 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 ~~March 31,~~June 30, 2014

(Unaudited)


	Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)														(In millions)
Net Income/(Loss)	$	168	$	(13	)	$	(52	)	$	(170	)	$	(67	)	$	158		$	(2	)	$	(92	)	$	(144	)	$	(80	)
Other comprehensive income, net of tax
Unrealized gain/(loss) on derivatives, net	6		(6		)	5			(14		)	(9		)	2			(20		)	(8		)	7			(19		)
Foreign currency translation adjustments, net	—		6			—			—			6			—			(1		)	(2		)	—			(3		)
Available-for-sale securities, net	—		—			4			2			6			—			5			4			(2		)	7
Defined benefit plan, net	2		—			—			—			2			(2		)	(13		)	25			—			10
Other comprehensive income	8		—			9			(12		)	5
Other comprehensive income/(loss)															—			(29		)	19			5			(5		)
Comprehensive income/(loss)	176		(13		)	(43		)	(182		)	(62		)	158			(31		)	(73		)	(139		)	(85		)
Less: Comprehensive (loss)/income attributable to noncontrolling interest	—		(5		)	4			(14		)	(15		)
Less: Comprehensive income attributable to noncontrolling interest															—			32			5			(25		)	12
Comprehensive income/(loss) attributable to NRG Energy, Inc.	176		(8		)	(47		)	(168		)	(47		)	158			(63		)	(78		)	(114		)	(97		)
Dividends for preferred shares	—		—			2			—			2			—			—			3			—			3
Comprehensive income/(loss) available for common stockholders	$	176	$	(8	)	$	(49	)	$	(168	)	$	(49	)	$	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, 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	—		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.

3847

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

~~March 31,~~June 30, 2014

(Unaudited)


	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
ASSETS	(In millions)														(In millions)
Current Assets
Cash and cash equivalents	$	22		$	1,459		$	1,706		$	—		$	3,187	$	25		$	1,121		$	335		$	—		$	1,481
Funds deposited by counterparties	4			—			—			—			4		5			4			—			—			9
Restricted cash	16			189			4			—			209		9			276			1			—			286
Accounts receivable, net	906			243			—			—			1,149		1,205			277			—			—			1,482
Inventory	380			401			—			—			781		419			577			—			—			996
Derivative instruments	970			634			—			(31		)	1,573		989			852			—			(140		)	1,701
Deferred income taxes	—			41			37			—			78		—			41			38			—			79
Cash collateral paid in support of energy risk management activities	315			372			—			—			687		282			290			—			—			572
Accounts receivable - affiliate	5,217			67			(4,043		)	(1,233		)	8		5,661			821			(4,748		)	(1,724		)	10
Renewable energy grant receivable	—			116			—			—			116		—			614			—			—			614
Prepayments and other current assets	120			447			24			—			591		128			367			32			—			527
Total current assets	7,950			3,969			(2,272		)	(1,264		)	8,383		8,723			5,240			(4,342		)	(1,864		)	7,757
Net property, plant and equipment	9,023			10,498			148			(25		)	19,644		8,884			12,563			153			(24		)	21,576
Other Assets
Investment in subsidiaries	558			(319		)	19,103			(19,342		)	—		573			(932		)	22,474			(22,115		)	—
Equity investments in affiliates	(27		)	594			—			(105		)	462		(20		)	1,014			—			(129		)	865
Notes receivable, less current portion	—			58			131			(120		)	69		—			73			108			(96		)	85
Goodwill	1,974			64			—			—			2,038		2,064			52						—			2,116
Intangible assets, net	1,075			242			4			(21		)	1,300		958			545			(47		)	(22		)	1,434
Nuclear decommissioning trust fund	557			—			—			—			557		576			—			—			—			576
Deferred income tax	3			689			724			—			1,416		8			586			906			—			1,500
Derivative instruments	130			208			—			(5		)	333		172			269			—			(28		)	413
Other non-current assets	87			280			392			—			759		96			637			574						1,307
Total other assets	4,357			1,816			20,354			(19,593		)	6,934		4,427			2,244			24,015			(22,390		)	8,296
Total Assets	$	21,330		$	16,283		$	18,230		$	(20,882	)	$	34,961	$	22,034		$	20,047		$	19,826		$	(24,278	)	$	37,629
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	1		$	664		$	20		$	—		$	685	$	1		$	813		$	19		$	—		$	833
Accounts payable	668			390			24			—			1,082		748			325			30			—			1,103
Accounts payable — affiliate	802			1,167			(736		)	(1,233		)	—		1,054			365			305			(1,724		)	—
Derivative instruments	954			581			—			(31		)	1,504		1,029			847			—			(140		)	1,736
Cash collateral received in support of energy risk management activities	4			—			—			—			4		5			4			—			—			9
Accrued expenses and other current liabilities	246			480			223			1			950		283			491			291						1,065
Total current liabilities	2,675			3,282			(469		)	(1,263		)	4,225		3,120			2,845			645			(1,864		)	4,746
Other Liabilities
Long-term debt and capital leases	317			8,147			8,460			(121		)	16,803		316			9,272			8,673			(96		)	18,165
Nuclear decommissioning reserve	298			—			—			—			298		302			—			—			—			302
Nuclear decommissioning trust liability	324			—			—			—			324		336			—			—			—			336
Deferred income taxes	1,090			(1,003		)	(63		)	—			24		1,142			(1,003		)	(68		)	—			71
Derivative instruments	176			86			—			(5		)	257		189			194			—			(29		)	354
Out-of-market contracts	123			1,034			—			—			1,157		119			1,056			—			—			1,175
Other non-current liabilities	428			622			179			1			1,230		424			583			247						1,254
Total non-current liabilities	2,756			8,886			8,576			(125		)	20,093		2,828			10,102			8,852			(125		)	21,657
Total liabilities	5,431			12,168			8,107			(1,388		)	24,318		5,948			12,947			9,497			(1,989		)	26,403
3.625% convertible perpetual preferred stock	—			—			249			—			249		—			—			249			—			249
Stockholders’ Equity	15,899			4,115			9,874			(19,494		)	10,394		16,086			7,100			10,080			(22,289		)	10,977
Total Liabilities and Stockholders’ Equity	$	21,330		$	16,283		$	18,230		$	(20,882	)	$	34,961	$	22,034		$	20,047		$	19,826		$	(24,278	)	$	37,629


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

3948

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the ~~Three~~Six Months Ended ~~March 31,~~June 30, 2014

(Unaudited)


	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)															(In millions)
Cash Flows from Operating Activities
Net Cash Provided/(Used) by Operating Activities	446			430			(886		)	401			391			$	798		$	641		$	(2,429	)	$	1,360		$	370
Cash Flows from Investing Activities
Intercompany loans to subsidiaries	(405		)	4			401			—			—
(Payments for)/proceeds from intercompany loans to subsidiaries																(808		)	(552		)	1,360			—			—
Acquisition of businesses, net of cash acquired	—			(25		)	(193		)	—			(218		)	—			(25		)	(1,792		)	—			(1,817		)
Capital expenditures	(73		)	(162		)	(2		)	—			(237		)	(9		)	(134		)	(364		)	—			(507		)
Decrease in restricted cash, net	—			3			—			—			3
(Increase)/decrease in restricted cash — U.S. DOE projects	(4		)	60			—			—			56
(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	—			1			—			—			1			—			2			—			—			2
Investments in nuclear decommissioning trust fund securities	(188		)	—			—			—			(188		)	(340		)	—			—			—			(340		)
Proceeds from sales of nuclear decommissioning trust fund securities	183			—			—			—			183			334			—			—			—			334
Proceeds from renewable energy grants	—			387			—			—			387			—			429			—			—			429
Proceeds from sale of assets, net of cash disposed of	—			—			77			—			77			—			—			77			—			77
Cash proceeds to fund cash grant bridge loan payment	—			57			—			—			57			—			57			—			—			57
Other	7			(4		)	—			—			3			(4		)	1			—			—			(3		)
Net Cash (Used)/Provided by Investing Activities	(480		)	321			283			—			124
Net Cash Used by Investing Activities																(829		)	(203		)	(721		)	—			(1,753		)
Cash Flows from Financing Activities
Proceeds from/payments for intercompany loans	—			—			401			(401		)	—
Proceeds from/(payments for) intercompany loans																—			—			1,360			(1,360		)	—
Payment of dividends to common and preferred stockholders	—			—			(41		)	—			(41		)	—			—			(91		)	—			(91		)
Net payments for settlement of acquired derivatives that include financing elements	—			(223		)	—			—			(223		)	—			(167		)	—			—			(167		)
Contributions from noncontrolling interest in subsidiaries	—			9			—			—			9			—			10			—			—			10
Proceeds from issuance of long-term debt	—			464			1,100			—			1,564			—			551			3,335			—			3,886
Proceeds from issuance of common stock	—			—			3			—			3			—			—			8			—			8
Payment of debt issuance and hedging costs	—			(9		)	(14		)	—			(23		)	—			(15		)	(28		)	—			(43		)
Payments for short and long-term debt	—			(405		)	(468		)	—			(873		)	—			(542		)	(2,427		)	—			(2,969		)
Net Cash (Used)/Provided by Financing Activities	—			(164		)	981			(401		)	416			—			(163		)	2,157			(1,360		)	634
Effect of exchange rate changes on cash and cash equivalents	—			2			—			—			2			—			(24		)	—			—			(24		)
Net (Decrease)/Increase in Cash and Cash Equivalents	(34		)	589			378			—			933			(31		)	251			(993		)	—			(773		)
Cash and Cash Equivalents at Beginning of Period	56			870			1,328			—			2,254			56			870			1,328			—			2,254
Cash and Cash Equivalents at End of Period	$	22		$	1,459		$	1,706		$	—		$	3,187		$	25		$	1,121		$	335		$	—		$	1,481


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

4049

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Three Months Ended ~~March 31,~~June 30, 2013

(Unaudited)


	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)															(In millions)
Operating Revenues
Total operating revenues	$	1,590		$	525		$	—		$	(34	)	$	2,081		$	2,171		$	850		$	—		$	(92	)	$	2,929
Operating Costs and Expenses
Cost of operations	1,258			515			7			(27		)	1,753			1,647			492			—			(88		)	2,051
Depreciation and amortization	204			100			3			—			307			207			103			3			—			313
Selling, general and administrative	115			52			67			(7		)	227			110			66			58			(4		)	230
Acquisition-related transaction and integration costs	—			29			13			—			42			—			12			15			—			27
Development activity expenses	—			6			12			—			18			—			7			14			—			21
Total operating costs and expenses	1,577			702			102			(34		)	2,347			1,964			680			90			(92		)	2,642
Operating Income/(Loss)	13			(177		)	(102		)	—			(266		)	207			170			(90		)	—			287
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries	1			(2		)	(164		)	165			—			20			(2		)	208			(226		)	—
Equity in earnings of unconsolidated affiliates	1			2			—			—			3			1			4			—			3			8
Other income, net	1			2			1			—			4			1			(2		)	1			—			—
Loss on debt extinguishment	—			—			(28		)	—			(28		)	—			(11		)	(10		)	—			(21		)
Interest expense	(5		)	(64		)	(127		)	—			(196		)	(5		)	(77		)	(124		)	—			(206		)
Total other expense	(2		)	(62		)	(318		)	165			(217		)
Income/(Loss) Before Income Taxes	11			(239		)	(420		)	165			(483		)
Total other income/(expense)																17			(88		)	75			(223		)	(219		)
Income/Loss Before Income Taxes																224			82			(15		)	(223		)	68
Income tax expense/(benefit)	21			(85		)	(88		)	—			(152		)	65			11			(139		)	—			(63		)
Net Loss	(10		)	(154		)	(332		)	165			(331		)
Net Income																159			71			124			(223		)	131
Less: Net income attributable to noncontrolling interest	—			1			—			—			1			—			4			—			3			7
Net Loss attributable to NRG Energy, Inc.	$	(10	)	$	(155	)	$	(332	)	$	165		$	(332	)
Net Income attributable to NRG Energy, Inc.																$	159		$	67		$	124		$	(226	)	$	124


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

4150

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Six Months Ended June 30, 2013

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	3,761		$	1,375		$	—		$	(126	)	$	5,010
Operating Costs and Expenses
Cost of operations	2,905			1,007			7			(115		)	3,804
Depreciation and amortization	411			203			6			—			620
Selling, general and administrative	225			118			125			(11		)	457
Acquisition-related transaction and integration costs	—			41			28			—			69
Development activity expenses	—			13			26			—			39
Total operating costs and expenses	3,541			1,382			192			(126		)	4,989
Operating Income/(Loss)	220			(7		)	(192		)	—			21
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries	21			(4		)	44			(61		)	—
Equity in earnings of unconsolidated affiliates	2			6			—			3			11
Other income, net	2			—			2			—			4
Loss on debt extinguishment	—			(11		)	(38		)	—			(49		)
Interest expense	(10		)	(141		)	(251		)	—			(402		)
Total other income/(expense)	15			(150		)	(243		)	(58		)	(436		)
Income/(Loss) Before Income Taxes	235			(157		)	(435		)	(58		)	(415		)
Income tax expense/(benefit)	86			(74		)	(227		)	—			(215		)
Net Income/(Loss)	149			(83		)	(208		)	(58		)	(200		)
Less: Net income attributable to noncontrolling interest	—			5			—			3			8
Net Income/(Loss) attributable to NRG Energy, Inc.	$	149		$	(88	)	$	(208	)	$	(61	)	$	(208	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE ~~LOSS~~INCOME

For the Three Months Ended ~~March 31,~~June 30, 2013

(Unaudited)


	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)		Consolidated			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)														(In millions)
Net Loss	$	(10	)	$	(154	)	$	(332	)	$	165	$	(331	)
Net Income															$	159		$	71		$	124		$	(223	)	$	131
Other comprehensive (loss)/income, net of tax
Unrealized (loss)/gain on derivatives, net	(9		)	5			7			4		7			(32		)	44			(15		)	20			17
Available-for-sale securities, net	—			—			2			—		2
Foreign currency translation adjustments, net															—			(15		)	(4		)	—			(19		)
Defined benefit plan	—			—			5			—		5			—			25			(5		)	—			20
Other comprehensive (loss)/income	(9		)	5			14			4		14			(32		)	54			(24		)	20			18
Comprehensive loss	(19		)	(149		)	(318		)	169		(317		)
Comprehensive income															127			125			100			(203		)	149
Less: Comprehensive income attributable to noncontrolling interest	—			1			—			—		1			—			9			—			(2		)	7
Comprehensive loss attributable to NRG Energy, Inc.	(19		)	(150		)	(318		)	169		(318		)
Comprehensive income attributable to NRG Energy, Inc.															127			116			100			(201		)	142
Dividends for preferred shares	—			—			2			—		2			—			—			3			—			3
Comprehensive loss available for common stockholders	$	(19	)	$	(150	)	$	(320	)	$	169	$	(320	)
Comprehensive income available for common stockholders															$	127		$	116		$	97		$	(201	)	$	139


(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, 2013

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Net Income/(Loss)	$	149		$	(83	)	$	(208	)	$	(58	)	$	(200	)
Other comprehensive (loss)/income, net of tax
Unrealized (loss)/gain on derivatives, net	(41		)	49			(8		)	24			24
Foreign currency translation adjustments, net	—			(15		)	(4		)	—			(19		)
Available-for-sale securities, net	—			—			2			—			2
Defined benefit plan	—			25			—			—			25
Other comprehensive (loss)/income	(41		)	59			(10		)	24			32
Comprehensive income/(loss)	108			(24		)	(218		)	(34		)	(168		)
Less: Comprehensive income attributable to noncontrolling interest	—			10			—			(2		)	8
Comprehensive income/(loss) attributable to NRG Energy, Inc.	108			(34		)	(218		)	(32		)	(176		)
Dividends for preferred shares	—			—			5			—			5
Comprehensive income/(loss) available for common stockholders	$	108		$	(34	)	$	(223	)	$	(32	)	$	(181	)


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

4252

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

December 31, 2013


	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
ASSETS	(In millions)														(In millions)
Current Assets
Cash and cash equivalents	$	56		$	870		$	1,328		$	—		$	2,254	$	56		$	870		$	1,328		$	—		$	2,254
Funds deposited by counterparties	7			56			—			—			63		7			56			—			—			63
Restricted cash	12			252			4			—			268		12			252			4			—			268
Accounts receivable, net	965			249			—			—			1,214		965			249			—			—			1,214
Inventory	436			462			—			—			898		436			462			—			—			898
Derivative instruments	866			470			—			(8		)	1,328		866			470			—			(8		)	1,328
Deferred income taxes	—			41			217			—			258		—			41			217			—			258
Cash collateral paid in support of energy risk management activities	214			62			—			—			276		214			62			—			—			276
Renewable energy grant receivable	—			539			—			—			539		—			539			—			—			539
Prepayments and other current assets	4,778			379			(3,802		)	(857		)	498		4,778			379			(3,802		)	(857		)	498
Total current assets	7,334			3,380			(2,253		)	(865		)	7,596		7,334			3,380			(2,253		)	(865		)	7,596
Net Property, Plant and Equipment	9,116			10,604			153			(22		)	19,851		9,116			10,604			153			(22		)	19,851
Other Assets
Investment in subsidiaries	32			422			18,266			(18,720		)	—		32			422			18,266			(18,720		)	—
Equity investments in affiliates	(30		)	583			—			(100		)	453		(30		)	583			—			(100		)	453
Capital leases and notes receivable, less current portion	—			62			105			(94		)	73		—			62			105			(94		)	73
Goodwill	1,973			12			—			—			1,985		1,973			12			—			—			1,985
Intangible assets, net	925			232			4			(21		)	1,140		925			232			4			(21		)	1,140
Nuclear decommissioning trust fund	551			—			—			—			551		551			—			—			—			551
Deferred income taxes	—			681			521			—			1,202					681			521			—			1,202
Derivative instruments	110			202			—			(1		)	311		110			202			—			(1		)	311
Other non-current assets	76			281			383			—			740		76			281			383			—			740
Total other assets	3,637			2,475			19,279			(18,936		)	6,455		3,637			2,475			19,279			(18,936		)	6,455
Total Assets	$	20,087		$	16,459		$	17,179		$	(19,823	)	$	33,902	$	20,087		$	16,459		$	17,179		$	(19,823	)	$	33,902
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	1		$	1,029		$	20		$	—		$	1,050	$	1		$	1,029		$	20		$	—		$	1,050
Accounts payable	652			352			34			—			1,038		652			352			34			—			1,038
Accounts payable — affiliate	1,350			760			(1,253		)	(857		)	—		1,350			760			(1,253		)	(857		)	—
Derivative instruments	859			204			—			(8		)	1,055		859			204			—			(8		)	1,055
Cash collateral received in support of energy risk management activities	6			57			—			—			63		6			57			—			—			63
Accrued expenses and other current liabilities	297			410			291			—			998		297			410			291			—			998
Total current liabilities	3,165			2,812			(908		)	(865		)	4,204		3,165			2,812			(908		)	(865		)	4,204
Other Liabilities
Long-term debt and capital leases	317			7,837			7,707			(94		)	15,767		317			7,837			7,707			(94		)	15,767
Nuclear decommissioning reserve	294			—			—			—			294		294			—			—			—			294
Nuclear decommissioning trust liability	324			—			—			—			324		324			—			—			—			324
Deferred income taxes	1,024			(1,002		)	—			—			22		1,024			(1,002		)	—			—			22
Derivative instruments	147			49			—			(1		)	195		147			49			—			(1		)	195
Out-of-market contracts	127			1,050			—			—			1,177		127			1,050			—			—			1,177
Other non-current liabilities	412			615			174			—			1,201		412			615			174			—			1,201
Total non-current liabilities	2,645			8,549			7,881			(95		)	18,980		2,645			8,549			7,881			(95		)	18,980
Total liabilities	5,810			11,361			6,973			(960		)	23,184		5,810			11,361			6,973			(960		)	23,184
3.625% Preferred Stock	—			—			249			—			249		—			—			249			—			249
Stockholders’ Equity	14,277			5,098			9,957			(18,863		)	10,469		14,277			5,098			9,957			(18,863		)	10,469
Total Liabilities and Stockholders’ Equity	$	20,087		$	16,459		$	17,179		$	(19,823	)	$	33,902	$	20,087		$	16,459		$	17,179		$	(19,823	)	$	33,902


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

4353

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the ~~Three~~Six Months Ended ~~March 31,~~June 30, 2013

(Unaudited)


	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)															(In millions)
Cash Flows from Operating Activities
Net Cash Provided/(Used) by Operating Activities	200			(241		)	(83		)	—			(124		)	$	664		$	(288	)	$	(844	)	$	390		$	(78	)
Cash Flows from Investing Activities
Intercompany loans to subsidiaries	(106		)	1			—			105			—			(393		)	3			390			—			—
Acquisition of businesses, net of cash acquired	—			(18		)	—			—			(18		)	—			(39		)	—			—			(39		)
Capital expenditures	(66		)	(731		)	(16		)	—			(813		)	(196		)	(1,081		)	(4		)	—			(1,281		)
Increase in restricted cash, net	—			(12		)	(1		)	—			(13		)
Decrease/(Increase) in restricted cash — U.S. DOE projects	—			13			(1		)	—			12
Increase in notes receivable	—			(1		)	(8		)	—			(9		)
(Increase)/decrease in restricted cash, net																(2		)	(30		)	1			—			(31		)
Increase in restricted cash — U.S. DOE projects																—			(10		)	(6		)	—			(16		)
Decrease/(increase) in notes receivable																3			(6		)	(8		)	—			(11		)
Investments in nuclear decommissioning trust fund securities	(95		)	—			—			—			(95		)	(233		)	—			—			—			(233		)
Proceeds from sales of nuclear decommissioning trust fund securities	85			—			—			—			85			208			—			—			—			208
Proceeds from renewable energy grants	—			16			—			—			16			—			48			—			—			48
Other	(1		)	—			—			—			(1		)	(8		)	(12		)	—			—			(20		)
Net Cash Used by Investing Activities	(183		)	(732		)	(26		)	105			(836		)
Net Cash (Used)/Provided by Investing Activities																(621		)	(1,127		)	373			—			(1,375		)
Cash Flows from Financing Activities
Proceeds from intercompany loans	—			—			105			(105		)	—			—			—			390			(390		)	—
Payment of dividends to preferred stockholders	—			—			(31		)	—			(31		)	—			—			(73		)	—			(73		)
Payment for treasury stock	—			—			(20		)	—			(20		)	—			—			(25		)	—			(25		)
Net (payment for)/receipts from settlement of acquired derivatives that include financing elements	(27		)	125			—			—			98			(49		)	220			—			—			171
Proceeds from issuance of long-term debt	—			728			8			—			736			—			995			477			—			1,472
Proceeds from issuance of common stock	—			—			1			—			1			—			—			9			—			9
Sale proceeds and other contributions from noncontrolling interest in subsidiaries	—			20			—			—			20			—			33			—			—			33
Payment of debt issuance costs	—			(3		)	(2		)	—			(5		)	—			(7		)	(28		)	—			(35		)
Payments for short and long-term debt	—			(15		)	(204		)	—			(219		)	—			(607		)	(209		)	—			(816		)
Net Cash (Used)/Provided by Financing Activities	(27		)	855			(143		)	(105		)	580			(49		)	634			541			(390		)	736
Net Decrease in Cash and Cash Equivalents	(10		)	(118		)	(252		)	—			(380		)
Effect of exchange rate changes on cash and cash equivalents																—			(2		)	—			—			(2		)
Net (Decrease)/Increase in Cash and Cash Equivalents																(6		)	(783		)	70			—			(719		)
Cash and Cash Equivalents at Beginning of Period	78			1,258			751			—			2,087			78			1,258			751			—			2,087
Cash and Cash Equivalents at End of Period	$	68		$	1,140		$	499		$	—		$	1,707		$	72		$	475		$	821		$	—		$	1,368


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

4454

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 ~~March 31,~~June 30, 2014 and 2013. Also refer to NRG's 2013 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 ~~Environment~~ 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.

4555

Executive Summary

Introduction and Overview

NRG Energy, Inc., or NRG or the Company, is a competitive power and energy company that ~~aspires to be~~produces, sells and delivers energy and energy services in major competitive power markets in the United States while positioning itself as a leader in the way residential, industrial and commercial consumers think about and use ~~produce~~energy products and ~~deliver energy~~services. NRG owns and ~~energy services in major competitive power markets in the United States. NRG engages in the ownership and operation of~~operates power generation facilities; engages in the trading of energy, capacity and related products; ~~the transacting~~transacts in and ~~trading of~~trades fuel and transportation ~~services~~services; and ~~the direct sale of~~directly sells energy, services, and innovative, sustainable products to retail customers. The Company sells retail ~~electric~~electricity products and services under the name “NRG” and various brands owned by NRG. Finally, NRG ~~aspires to be~~is a ~~clean energy~~ leader ~~and is focused on~~in the deployment and commercialization of potentially transformative technologies, like electric vehicles, Distributed Solar and smart meter/home automation technology that collectively have the potential to fundamentally change the nature of the power industry, ~~including a substantial change in~~and the role of the national electric transmission grid and distribution system.

The following table summarizes NRG's global generation portfolio as of ~~March 31,~~June 30, 2014, by operating segment, which includes 8697 active fossil fuel and nuclear plants, ~~eleven~~twelve Utility Scale Solar facilities and ~~four~~29 wind farms, as well as Distributed Solar facilities. ~~Also included are one~~The table below also includes two Utility Scale Solar ~~facility~~facilities and additional Distributed Solar facilities currently under construction. All Utility Scale Solar and Distributed Solar facilities are described in megawatts on an alternating current basis. MW figures provided represent nominal summer net megawatt capacity of power generated as adjusted for the Company's owned or leased interest excluding capacity from inactive/mothballed units:


	Fossil Fuel, Nuclear, and Renewable													Fossil Fuel, Nuclear, and Renewable
	(In MW)													(In MW)
	Texas	East^(a)(b)(c)(d)	South Central	West	Alternative Energy		NRG Yield		Total Domestic		Other(Inter-national)	Total Global		Gulf Coast	East^{(a)(b)(c)(d)(e)(f)(g)}		West^(h)	Renewables^(h)		NRG Yield^(h)		Total Domestic		Other(Inter-national)	Total Global
Primary Fuel-type
Natural gas ^(e)(i)	5,190	7,413	3,742	6,779	—		843		23,967		—	23,967		8,932	7,413		7,617	—		1,393		25,355		144	25,499
Coal	4,193	6,879	1,496	—	—		—		12,568		605	13,173		5,689	11,125		—	—		—		16,814		605	17,419
Oil ^(f)(j)	—	5,513	—	—	—		190		5,703		—	5,703		—	5,818		—	—		190		6,008		—	6,008
Nuclear	1,176	—	—	—	—		—		1,176		—	1,176		1,176	—		—	—		—		1,176		—	1,176
Wind	—	—	—	—	347		101		448		—	448		—	—		—	2,072		101		2,173		—	2,173
Utility Scale Solar	—	—	—	—	836		303		1,139		—	1,139		—	—		—	802		343		1,145		—	1,145
Distributed Solar	—	—	—	—	37		10		47		—	47		—	—		—	37		10		47		—	47
Total generation capacity	10,559	19,805	5,238	6,779	1,220		1,447		45,048		605	45,653		15,797	24,356		7,617	2,911		2,037		52,718		749	53,467
Capacity attributable to noncontrolling interest	—	—	—	—	(331	)	(499	)	(830	)	—	(830	)	—	(40	)	—	(630	)	(703	)	(1,373	)	—	(1,373	)
Total net generation capacity	10,559	19,805	5,238	6,779	889		948		44,218		605	44,823		15,797	24,316		7,617	2,281		1,334		51,345		749	52,094

Under Construction
Utility Scale Solar	—	—	—	—	26		—		26		—	26		—	—		—	31		—		31		—	31
Distributed Solar	—	—	—	—	6		—		6		—	6		—	—		—	6		—		6		—	6
Total under construction	—	—	—	—	32		—		32		—	32		—	—		—	37		—		37		—	37

(a) NRG notified PJM that it no longer intends to deactivate Portland Units 1 and 2 (401 MW), but instead ~~will mothball~~mothballed those units effective June 1, 2014, with an expected return to service no later than June 1, 2016 using ~~an alternative fuel.~~ultra-low sulfur diesel.

(b) NRG notified PJM that it no longer intends to place the coal-fired Units 1, 2, 3, and 4 at Shawville generating facility (597 MW) in long term protective layup, but instead will mothball those units beginning on April 16, 2015, with an expected return to service no later than June 1, 2016 using ~~an alternative fuel.~~natural gas.

(c) NRG notified PJM that it no longer intends to deactivate Chalk Point Units 1 and 2 (667 MW) on May 31, 2017, but instead has changed that deactivation date to May 31, 2018.

(d) NRG notified PJM that it no longer intends to deactivate Dickerson Units 1, 2 and 3 (537 MW) on May 31, 2017, but instead has changed that deactivation date to May 31, 2018.

(e) NRG intends to continue operations at Avon Lake Units 7 and 9 and New Castle Units 3, 4, and 5, which are currently operating coal units that had been scheduled for deactivation in April 2015. NRG intends to add natural gas capabilities at these units by summer of 2016.

(f) NRG intends to convert Units 6, 7 and 8 of the Joliet coal facility to run on natural gas no later than June 2016.

(g) NRG intends to deactivate Unit 3 of the Will County coal facility on April 15, 2015.

(h) Generation capacity and noncontrolling interest amounts reflect the sale of assets to NRG Yield, Inc. on June 30, 2014, as further described in Note 3, Business Acquisitions and Dispositions.

(i) The ~~South Central~~Gulf Coast operating segment reflects the sale of the 75 MW Bayou Cove Unit 1 on March 3, 2014.

~~(f)~~(j) The NRG Yield operating segment consists of two dual-fuel (natural gas and oil) simple-cycle generation facilities.

In addition, the Company's thermal assets, which are part of the NRG Yield operating segment, provide steam and chilled water capacity of approximately 1,464 MWt through the district energy business, 118 MWt of which is available under right-to-use provisions contained in agreements between two of NRG's thermal facilities and certain of their customers. On January 31, 2014, the Company completed the sale of Kendall, a 256 MW natural gas facility in Cambridge, MA. The Company does not anticipate returning the S.R. Bertron 727 MW natural gas facility to service in 2014.

The generation table above does not reflect 7,704 MW attributable to EME, which was acquired by the Company on April 1, 2014, bringing NRG's total fleet to approximately 53,000 MW of generating capacity. The following table reflects the portion of EME's global generation portfolio acquired by the Company on April 1, 2014:

EME Fossil Fuel and Renewable
(In MW)
East
West ^(a)
Alternative Energy Total Domestic Other (Inter-national) Total Global
Primary Fuel-type
Natural gas —
1,476
—
1,476
144
1,620
Coal 4,394
—
—
4,394
—
4,394
Oil 305
—
—
305
—
305
Wind —
—
1,724
1,724
—
1,724
Total generation capacity 4,699
1,476
1,724
7,899
144
8,043
Capacity attributable to
noncontrolling interest
(40 ) —
(299 ) —
—
(339 )
Total net generation capacity 4,659
1,476
1,425
7,899
144
7,704

~~(a) NRG completed an asset swap transaction on April 30, 2014, reducing net owned natural gas generating capacity in EME's West region by 87 MW.~~

NRG's Business Strategy

NRG's business strategy is ~~intended~~ 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 and low carbon energy solutions individualized for the benefit of the end use energy consumer. This strategy is designed to enhance the Company's core business of competitive power generation and mitigate the risk of declining power prices while continuing the Company’s commitment to safety for its employees, customers and partners.

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, which 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 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, energy consumers are expected to have increasing personal control over whom they buy their energy from, how that energy is generated and used (including their ability to self-generate from their own primarily sustainable energy resources) and what environmental impact individual choices will have.

To address these trends and effectuate the Company’s strategy, NRG remains focused on: (i) excellence in operating performance of its existing assets; (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 Business and its customers; (iv) repowering ofits power generation assets at premium sites; ~~and~~ (v) optimal hedging of generation assets and retail load operations; (vi) 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; and (vii) pursuing selective acquisitions, joint ventures, divestitures and investments. The Company's ~~advances~~progress in each of these areas ~~are driven by select acquisitions, joint ventures, and investments that~~ are more fully described in Item 1, Business - New and On-going Company Initiatives ~~and Development Projects~~and in Management's Discussion and Analysis of Financial Condition and Results of Operations, New and On-going Company Initiatives ~~and Development Projects~~of the Company's 2013 Form 10-K, and this Form 10-Q.

In addition, the Company's subsidiary, NRG Yield, Inc., is focused on enhancing value for its stockholders by: (i) providing investors with a more competitive source of equity capital that would accelerate NRG's long-term growth and acquisition strategy and optimize NRG's capital structure; and (ii) highlighting the reduced market exposure associated with the contracted conventional and renewable generation and thermal infrastructure assets ~~embedded~~that has traditionally been unrecognized when combined with NRG's merchant portfolio.

Environmental Matters

A number of regulations with the potential to affect the Company and its facilities are in development or under review by the EPA: NSPS for GHGs, NAAQS revisions and implementation, coal combustion byproducts regulation, effluent guidelines and once-through cooling regulations. While most of these regulations have been considered for some time, the outcomes and any resulting impact on NRG cannot be fully predicted until the rules are finalized (and any resulting legal challenges resolved). The Company’s environmental matters are described in the Company’s 2013 Form 10-K in Item 1, Business — Environmental Matters. These matters have been updated in Note 15, Environmental Matters, to this Form 10-Q as found in Item 1.

Regulatory Matters

The Company’s regulatory matters are described in the Company’s 2013 Form 10-K in Item 1, Business — Regulatory Matters. These matters have been updated below and in Note 14, Regulatory Matters, to this Form 10-Q as found in Item 1.

As operators 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 U.S. Commodity Futures Trading Commission, 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 the North American Electric Reliability Corporation 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.

National

Court Rejects FERC’s Jurisdiction Over Demand Response — On May 23, 2014, the U.S. Court of Appeals for the District of Columbia Circuit vacated FERC’s rules (known as Order No. 745) that allow demand response resources to participate in the FERC-jurisdictional energy markets. The Court of Appeals held that the Federal Power Act 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 solely to energy market participation, but this ruling also calls into question whether demand response will be permitted to participate in the capacity markets in the future. FERC has asked the U.S. Court of Appeals for the District of Columbia Circuit to rehear en banc the decision. The 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 estimate the impact on the Company at this time.

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. The appeal of the New Jersey decision is still pending before the U.S. Court of Appeals for the Third Circuit. These decisions may affect future capacity prices in PJM.

Capacity Replacement — On March 10, 2014, PJM filed at FERC to limit speculation in the annual capacity auction. Specifically, PJM ~~proposes~~proposed tariff changes that will restore incentives to submit offers for only capacity resources that are reasonably expected to be provided as a physical resource by the start of the delivery year. These changes include the addition of a replacement capacity adjustment charge that is intended to remove the incentive to profit from replacing capacity commitments, an increase in deficiency penalties for non-performance, and a reduction in the number of ~~Incremental Auctions~~incremental auctions from three to one. ~~If approved by~~On May 9, 2014, FERC ~~the~~rejected PJM’s proposed changes to address replacement capacity ~~replacement rules~~and incremental auction design, but established a Section 206 proceeding and technical conference to find a just and reasonable outcome. The date for this hearing has not yet been set. The 206 proceeding and technical conference could have a material impact on future PJM capacity prices.

Capacity Import Limits — On April 22, 2014, FERC approved PJM’s proposal to add a limit on the amount of capacity from external resources that PJM can reliably import into the PJM Region. The capacity import limit will be in effect for the 2017/2018 Base Residual Auction, may decrease the amount of capacity imports allowed into PJM as compared to recent auctions, and could have a material impact on future PJM capacity prices. The matter is pending rehearing at FERC.

Demand Response Operability — On May 9, 2014, FERC largely accepted PJM’s proposed changes on Demand Response Operability in an attempt to enhance the operational flexibility of demand response resources during the operating day. The approval of these changes will likely limit the amount of demand response resources eligible to participate in the PJM capacity market. The matter is pending rehearing at FERC.

New England

Performance Incentive Proposal — On January 17, 2014, ISO-NE filed at FERC to revise its forward capacity market, or FCM, by making a resource’s forward capacity market compensation dependent on resource output during short intervals of operating reserve scarcity. The ISO-NE proposal would replace the existing shortage event penalty structure with a new performance incentive, or PI, mechanism, resulting in capacity payments to resources that would be the combination of two components: (1) a base capacity payment and (2) a performance payment or charge. The performance payment or charge would be entirely dependent upon the resource’s delivery of energy or operating reserves during scarcity conditions, and could be larger than the base payment.

NEPOOL, the ISO-NE stakeholder group, filed an alternative proposal to ISO-NE’s PI proposal at FERC, under which the market rules would be revised to maintain the FCM capacity product as a tool to ensure resource adequacy, and would place real-time performance incentive-related improvements directly into the energy and reserve markets. The Company supported the NEPOOL alternative.

On May 30, 2014, FERC rejected both proposals, but found that most of the provisions in the ISO-NE proposal, with modifications, together with an increase to the reserve constraint penalty factors from the NEPOOL proposal, provided a just and reasonable structure. FERC adopted these aspects of the ISO-NE and NEPOOL proposals. FERC instituted a proceeding for further hearings and required ISO-NE to make a compliance filing to modify its proposal and adopt the increases to the reserve constraint penalty factors in NEPOOL’s proposal. The matter is pending rehearing at FERC.

Sloped Demand Curve Filing — On May 30, 2014, FERC accepted the proposed tariff revisions discussed in the April 1, 2014 ISO-NE ~~filed~~filing at FERC ~~to establish~~regarding the establishment of a sloped demand curve for use in the ISO-NE Forward Capacity Market. The ~~proposed~~accepted tariff changes ~~also seek to extend~~include extending the period during which a market participant can lock-in the capacity price for a new resource from five to seven years, ~~establishes~~establishing a limited exemption for the buyer-side market mitigation rules for ~~specific~~a set amount of renewable resources, and ~~eliminates~~eliminating the administrative pricing rules. The shift away from the current vertical demand curve and accompanying proposed changes could have a material impact on the capacity prices in future auctions. The matter is still subject to rehearing at FERC.

~~Complaint Regarding 2014 Forward Capacity Auction Results~~ — In April 2014, a number of parties protested the results of ISO-NE’s 2014 Forward Capacity Auction. Several parties alleged that the results were the result of market manipulation by one or more market participants, and that the results should be overturned. FERC's decision remains pending.

New York

NYSPSC Order Rescinding Danskammer Retirement — On October 28, 2013, the NYSPSC took emergency action to rescind its approval for the 530 MW Danskammer facility to retire on October 30, 2013. The NYSPSC’s stated goal was to allow the facility to return to service in order to constrain rate increases in New York. The ~~NYPSC~~NYSPSC approved the emergency Order and granted an extension until March 17, 2014 for Helios Capital LLC to file its plan to operate or retire the unit. On March 28, 2014, the ~~NYPSC~~NYSPSC adopted the October 28, 2013 ~~Order~~order as permanent rule. The return to service of this facility may affect capacity prices received by NRG for its resources in the Rest-of-State ~~capacity zone~~Capacity Zone and the Lower Hudson Valley ~~capacity zone.~~

~~Independent Power Producers of New York Complaint~~ — On May 10, 2013, 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. The complainants seek to prevent below-cost offers from artificially suppressing prices in the New York Control Area Installed Capacity ~~Spot Market Auction. A number of New York Transmission Owners protested the filing and the case is pending.~~Zone.

On March 25, 2014, the generators filed an Amended Complaint against the NYISO in light of the executed term sheet between Niagara Mohawk Power Corporation d/b/a National Grid and Dunkirk Power, which was filed at NYPSC in February 2014. Under the term sheet, National Grid and Dunkirk Power are to enter into a definitive agreement pursuant to which Dunkirk Power will undertake a gas addition project to enable Units 2-4 to run on natural gas in exchange for payments from National Grid over a 10-year term.

Demand Curve Reset and the Lower Hudson Valley Capacity Zone — On ~~November 29,~~May 27, 2014, FERC denied rehearing and phase-in requests regarding its August 13, 2013 order on the creation of the Lower Hudson Valley Capacity Zone. The NYISO had previously approved the creation of a new Lower Hudson Valley Capacity Zone in ~~the~~ New York, as part of the NYISO’s triennial adjustment of its capacity market parameters for the 2014-2017 periods. ~~A number~~The State of ~~parties opposing~~New York, NYSPSC and Central Hudson Gas & Electric Corp. have challenged the ~~creation~~FERC Order before the U.S. Court of Appeals for the Second Circuit.

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. The proposed project would increase the import capability into the Houston area by adding a new 345 kV double-circuit line to achieve 2,988 MVA of emergency rating for each circuit, upgrading existing substations, and upgrading an existing 345 kV line to achieve 1,450 MVA of emergency rating. The target completion for the proposed project is 2018. ERCOT's endorsement of the ~~Lower Hudson Valley Zone have petitioned FERC~~project was challenged at the PUCT by the Company and Calpine and there is a separate dispute, also before the PUCT, regarding which utilities would build the project. The proceeding to ~~reverse its decision. Rehearing remains pending.~~license the project to move forward (Certificate of Convenience and Necessity, or CCN) has yet to be initiated.

~~ERCOT~~

Operating Reserve Demand Curve Implementation — At its September 12, 2013 open meeting, the PUCT directed ERCOT to implement an operating reserve demand curve by the summer of 2014, known as ORDC B+. ORDC B+ simulates real-time co-optimization and adjusts prices to reflect outcomes expected under real-time co-optimization. The ORDC B+ ~~is expected to be in service~~was implemented on ~~or near~~ June 1, 2014. ~~The demand curve will be set to achieve an imputed value of lost load of $9,000 per MWh when ERCOT operating reserves decrease to 2,000 MWs. As part of prior market reforms,~~Under ORDC B+, the system wide offer caps ~~(currently $5,000) will increase~~increased from $5,000 to $7,000 per MWh in June 2014 and will increase to $9,000 per MWh in June 2015.

MISO

On July 5, 2013, AmerenEnergy Resources Generating Company, or Ameren, filed a complaint against MISO pertaining to the compensation for generators asked by MISO to provide service past their retirement date due to reliability concerns, or RMR Generators. Ameren asked FERC to require MISO to provide such generators their full cost of service as compensation and not merely cover the generator's incremental costs of operation going-forward costs. The ~~combination of~~Company supported the ~~ORDC B+~~Complaint. On July 22, 2014, FERC issued an Order denying the complaint in part and ~~higher offer caps is designed to result~~granting it in ~~periods of higher real time power prices, and for longer durations, when operating reserves are depleted, such as during extreme weather events and unusual facility outage conditions.~~

While there was significant activity in 2013 and early 2014 regarding additional ERCOT market design changes to address imminent shortfalls in planning reserves, the urgency of that policy discussion has eased. This is largely in reaction to ERCOT’s new load forecast methodology, disclosed in January 2014 and reflected in a February 2014 report on planning reserves, showing a slower rate of peak demand growth, and indicating adequate reserves until 2016 (followed by reserve shortfalls thereafter). Also in January 2014, the Brattle Group (commissioned by ERCOT) issued a report analyzing the economically optimal reserve margin, which identified the risk-neutral reserve margin as being 10.2%, andpart. FERC found that the ~~current market would support an 11.4% reserve margin. Brattle’s analysis also demonstrated that the ultimate customer cost of a capacity market,~~Tariff was unjust and unreasonable because it did not allow RMR Generators to obtain compensation for their fixed costs, which ~~would support the current ERCOT reliability standard (Brattle found would require a 14.1% reserve), is modest (approximately 1% impact to the customer cost)~~are recovered as depreciation expense, return on rate base and ~~that a capacity market is the most cost effective way to address the risk of blackouts due to substandard planning reserves.~~associated taxes.

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.

4960

Consolidated Results of Operations

The following table provides selected financial information for the Company:


	Three months ended March 31,								Three months ended June 30,								Six months ended June 30,
(In millions except otherwise noted)	2014			2013			Change %		2014			2013			Change %		2014			2013			Change %
Operating Revenues
Energy revenue^(a)	$	1,638		$	942		74	%	$	1,094		$	754		45	%	$	2,732		$	1,696		61	%
Capacity revenue ^(a)	501			333			50		563			428			32		1,064			761			40
Retail revenue	1,525			1,258			21		1,879			1,548			21		3,404			2,806			21
Mark-to-market for economic hedging activities	(331		)	(478		)	31		(48		)	193			(125	)	(379		)	(285		)	(33	)
Contract amortization	4			(16		)	125		2			(13		)	115		6			(29		)	121
Other revenues ^(b)	149			42			255		131			19			N/M		280			61			359
Total operating revenues	3,486			2,081			68		3,621			2,929			24		7,107			5,010			42
Operating Costs and Expenses
Generation cost of sales^(a)	1,344			817			65		1,029			772			33		2,373			1,589			49
Retail cost of sales^(a)	878			617			42		995			638			56		1,873			1,255			49
Mark-to-market for economic hedging activities	(63		)	(215		)	71		71			95			(25	)	8			(120		)	107
Contract and emissions credit amortization ^(c)	15			9			67		6			7			(14	)	21			16			31
Other cost of operations	559			525			6		716			539			33		1,275			1,064			20
Total cost of operations	2,733			1,753			56		2,817			2,051			37		5,550			3,804			46
Depreciation and amortization	335			307			9		386			313			23		721			620			16
Selling, general and administrative	226			227			—		268			230			17		494			457			8
Acquisition-related transaction and integration costs	12			42			(71	)	40			27			48		52			69			(25	)
Development activity expenses	19			18			6		21			21			—		40			39			3
Total operating costs and expenses	3,325			2,347			42		3,532			2,642			34		6,857			4,989			37
Gain on sale of assets	19			—			—		—			—			—		19			—
Operating Income/(Loss)	180			(266		)	168
Operating Income									89			287			(69	)	269			21			N/M
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	7			3			133		14			8			75		21			11			91
Other income, net	11			4			175		5			—			N/M		16			4			300
Loss on debt extinguishment	(41		)	(28		)	46		(40		)	(21		)	90		(81		)	(49		)	65
Interest expense	(255		)	(196		)	30		(274		)	(206		)	33		(529		)	(402		)	32
Total other expense	(278		)	(217		)	28		(295		)	(219		)	35		(573		)	(436		)	31
Loss before Income Taxes	(98		)	(483		)	80
(Loss)/Income before Income Taxes									(206		)	68			(403	)	(304		)	(415		)	27
Income tax benefit	(31		)	(152		)	(80	)	(126		)	(63		)	100		(157		)	(215		)	27
Net Loss	(67		)	(331		)	80
Less: Net (loss)/income attributable to noncontrolling interest	(11		)	1			N/M
Net Loss Attributable to NRG Energy, Inc.	$	(56	)	$	(332	)	83
Net (Loss)/Income									(80		)	131			(161	)	(147		)	(200		)	27
Less: Net income attributable to noncontrolling interest									17			7			143		6			8			(25	)
Net (Loss)/Income Attributable to NRG Energy, Inc.									$	(97	)	$	124		(178	)	$	(153	)	$	(208	)	26
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	$	4.94		$	3.34		48	%	$	4.67		$	4.09		14	%	$	4.80		$	3.71		29	%

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

(b) Includes unrealized trading gains and losses.

N/M - Not meaningful.

5061

Management’s discussion of the results of operations for the three months ended ~~March 31,~~June 30, 2014 and 2013

~~Loss~~(Loss)/income before income taxes — The pre-tax loss of ~~$98~~$206 million for the three months ended ~~March 31,~~June 30, 2014, compared to a pre-tax ~~loss~~income of $~~483~~68 million for the three months ended ~~March 31,~~June 30, 2013, primarily ~~reflects~~ reflects:

increased operating costs of $301 million, including operations and maintenance expense, depreciation and amortization, selling, general and administrative costs, and acquisition-related costs; and

a current year decrease from net market-to-market results for economic hedging activity of $217 million;

offset by:

an increase in gross margin of ~~$393~~$267 million comprised of an increase in Renewables gross margin of $107 million, an increase in Conventional Generation gross margin ~~a $37~~of $82 million, an increase in Yield gross margin ~~a $18~~of $50 million, ~~increase in Alternative Energy gross margin~~ and ~~a $7 million~~an increase in Retail gross ~~margin; offset by a $72~~margin of $28 million ~~increase in interest expense and loss on debt extinguishment.~~

Net ~~loss~~(Loss)/income — The ~~decrease~~increase in net loss of ~~$264~~$211 million primarily reflects the drivers discussed above, ~~offset by~~including an income tax benefit for the three months ended ~~March 31,~~June 30, 2014 of ~~$31~~$126 million, compared to an income tax benefit of $~~152~~63 million in the comparable period.

Electricity Prices

The following table summarizes average on-peak power prices for each of the major markets in which NRG operates for the three months ended ~~March 31,~~June 30, 2014 and 2013:


	Average on Peak Power Price ($/MWh)				Average on Peak Power Price ($/MWh)
	Three months ended March 31,				Three months ended June 30,
Region	2014		2013		2014		2013
Texas
Gulf Coast ^(a)
ERCOT - Houston	$	57.75	$	28.81	$	44.70	$	36.64
ERCOT - North	60.20		29.02		40.54		35.18
MISO - Louisiana Hub ^(b)					50.96		40.86
East
NY J/NYC	156.12		82.40		46.99		52.05
NY A/West NY	105.40		45.50		44.87		40.55
NEPOOL	172.98		90.10		44.31		44.98
PEPCO (PJM)	133.16		42.68		54.02		46.52
PJM West Hub	112.30		41.92		50.58		45.44
South Central^(a)
MISO - Louisiana Hub ^(b)	66.96		31.04
West
CAISO - NP15	53.24		39.57		52.50		39.06
CAISO - SP15	53.77		48.31		47.41		43.85

(a) ~~South Central~~Gulf Coast region also transacts in PJM - West Hub.

(b) ~~South Central~~Gulf Coast region, south central market 2013 price data is "into Entergy", MISO-Louisiana Hub began trading December 2013.

5162

Conventional Generation gross margin

The following is a discussion of gross margin for NRG's Conventional Generation businesses, adjusted to eliminate intersegment activity, primarily with the Retail Business.


	Three months ended March 31, 2014																														Three months ended June 30, 2014
	Conventional Generation																														Conventional Generation
(In millions except otherwise noted)	Texas			East			South Central			West			Other			Subtotal			Alternative Energy			NRG Yield			Eliminations/Corporate			Consolidated Total			Gulf Coast			East			West			Subtotal			Renewables			NRG Yield			Eliminations/Corporate			Consolidated Total
Energy revenue	$	466		$	1,275		$	153		$	50		$	—		$	1,944		$	50		$	28		$	(384	)	$	1,638		$	710		$	679		$	65		$	1,454		$	118		$	34		$	(512	)	$	1,094
Capacity revenue	8			311			66			88			—			473			—			31			(3		)	501			46			327			96			469			38			62			(6		)	563
Other revenue	21			53			—			1			46			121			5			51			(28		)	149			26			12			3			41			7			39			44			131
Generation revenue	495			1,639			219			139			46			2,538			55			110			(415		)	2,288			782			1,018			164			1,964			163			135			(474		)	1,788
Generation cost of sales	(257		)	(858		)	(157		)	(47		)	(19		)	(1,338		)	(2		)	(34		)	30			(1,344		)	(466		)	(466		)	(58		)	(990		)	(3		)	(18		)	(18		)	(1,029		)
Generation gross margin	$	238		$	781		$	62		$	92		$	27		$	1,200		$	53		$	76								$	316		$	552		$	106		$	974		$	160		$	117

Business Metrics
MWh sold (in thousands) ^(a)	10,618			12,603			4,513			617									463			227									15,759			12,378			698						2,211			636
MWh generated (in thousands)	9,855			12,512			4,397			755									563			292									14,563			12,291			1,102						2,355			778
(a) MWh sold excludes generation at facilities that generate revenue under capacity agreements.


	Three months ended March 31, 2013																													Three months ended June 30, 2013
	Conventional Generation																													Conventional Generation
(In millions except otherwise noted)	Texas			East			South Central			West			Other			Subtotal			Alternative Energy		Yield			Eliminations/Corporate			Consolidated Total			Gulf Coast			East			West			Subtotal			Renewables		NRG Yield			Eliminations/Corporate			Consolidated Total
Energy revenue	$	470		$	623		$	126		$	37		$	—		$	1,256		$	34	$	16		$	(364	)	$	942		$	689		$	510		$	40		$	1,239		$	52	$	27		$	(564	)	$	754
Capacity revenue	18			212			58			51			1			340			—		—			(7		)	333			78			252			85			415			—		19			(6		)	428
Other revenue	(14		)	13			(10		)	—			35			24			1		37			(20		)	42			11			7			1			19			1		36			(37		)	19
Generation revenue	474			848			174			88			36			1,620			35		53			(391		)	1,317			778			769			126			1,673			53		82			(607		)	1,201
Generation cost of sales	(228		)	(403		)	(145		)	(26		)	(11		)	(813		)	—		(14		)	10			(817		)	(430		)	(323		)	(28		)	(781		)	—		(15		)	24			(772		)
Generation gross margin	$	246		$	445		$	29		$	62		$	25		$	807		$	35	$	39								$	348		$	446		$	98		$	892		$	53	$	67

Business Metrics
MWh sold (in thousands) ^(a)	9,448			9,300			4,340			338									454		182									15,902			8,098			351						549		256
MWh generated (in thousands)	7,600			8,997			4,419			576									486		224									14,605			7,895			601						553		287
(a) MWh sold excludes generation at facilities that generate revenue under capacity agreements.	(a) MWh sold excludes generation at facilities that generate revenue under capacity agreements.																													(a) MWh sold excludes generation at facilities that generate revenue under capacity agreements.

	Three months ended March 31,																													Three months ended June 30,
Weather Metrics	Texas			East			South Central			West																				Gulf Coast			East			West
2014
CDDs ^(a)	50			92			38			1																				1,777			932			250
HDDs ^(a)	1,231			8,489			1,392			873																				191			1,673			226
2013
CDDs	82			89			55			1																				1,801			987			188
HDDs	983			7,427			1,100			1,198																				320			1,733			250
10 year average
CDDs	98			94			83			2																				1,928			1,001			151
HDDs	969			7,304			1,094			1,188																				156			1,694			387

(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.

5263

Conventional Generation gross margin — increased by ~~$393~~$82 million, including intercompany sales, during the three months ended ~~March 31,~~June 30, 2014, compared to the same period in 2013, due to:

Texas region (8 )
East region 336
South Central region 33
West region 30
Other ^(a)
2
$ 393

^(a)~~Other gross margin primarily represents revenues from the maintenance services business, which are eliminated in consolidation.~~



Gulf Coast region	$	(32	)
East region	106
West region	8
	$	82

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

Lower gross margin from a decrease in average realized prices $ (71 )
Higher gross margin from a 73% increase in nuclear generation driven by fewer outage hours in 2014 25
Change in commercial optimization activities 20
Higher gross margin from a 9% increase in coal generation driven by higher economic dispatch offset in part by additional outage hours in 2014 11
Higher gross margin due to the acquisition of Gregory in August 2013 11
Other (4 )
$ (8 )



Lower gross margin from a 24% decrease in nuclear generation driven by higher outage hours	$	(21	)
Lower gross margin from a decrease in average realized prices	(13		)
Lower gross margin from the sale of NOx emission credits in 2013	(14		)
Higher gross margin due to the acquisition of Gregory in August 2013	5
Changes in commercial optimization activities and other	11
	$	(32	)

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

Higher gross margin due to a 56% increase in realized energy prices, partially offset by an increase in fuel prices $ 202
Higher gross margin due to a 39% increase in generation due to weather conditions in 2014 52
Higher revenue due primarily to a 32% increase in New York and PJM hedged capacity prices 88
Other (6 )
$ 336

~~The increase in gross margin in the South Central region was driven by:~~

Higher gross margin from an increase in average realized prices, primarily driven by weather conditions in 2014 $ 13
Higher gross margin from lower coal transportation costs 8
Change in commercial optimization activities and other 12
$ 33



Higher gross margin from the acquisition of EME in April 2014	$	87
Higher gross margin from a 24% increase in New York and PJM hedged capacity prices as well as higher prices for the new Lower Hudson Valley Capacity Zone	54
Lower gross margin from a 2% decrease in generation and an 8% decrease in realized energy prices	(30		)
Changes in commercial optimization activities and other	(5		)
	$	106

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

Higher gross margin due to revenues from Resource Adequacy contracts in California, partially offset by the deactivation of the Contra Costa facility in 2013 $ 14
Increase in capacity revenue due to El Segundo Energy Center reaching COD in 2013 24
Lower gross margin due to a 59% decrease in generation primarily due to increased dispatch from competing resources, including renewable resources. (10 )
Other 2
$ 30



Higher gross margin from the acquisition of EME in April 2014	$	29
Higher capacity gross margin due primarily to increases in realized prices	11
Lower gross margin due to timing of revenues from Resource Adequacy contracts in California and the deactivation of the Contra Costa facility in 2013	(23		)
Lower gross margin primarily due to a 28% decrease in generation primarily due to increased dispatch from competing resources, including renewable resources.	(10		)
Other	1
	$	8

5364

Retail gross margin

The following is a detailed discussion of retail gross margin for NRG's Retail Business segment.


	Three months ended March 31,				Three months ended June 30,
(In millions except otherwise noted)	2014		2013		2014		2013
Mass revenues	$	997	$	777	$	1,283	$	999
Commercial and Industrial revenues	444		446		436		503
Supply management and other revenues	86		36		161		47
Retail revenue ^(a)(b)	1,527		1,259		1,880		1,549
Retail cost of sales ^(c)	1,244		983		1,525		1,222
Retail gross margin	$	283	$	276	$	355	$	327

Business Metrics ^(d)
Electricity sales volume — GWh
Mass	7,461		6,372		10,327		8,225
Commercial and Industrial ^(e)(d)	5,731		6,205		5,953		6,968
Electricity sales volume — GWh
Texas	10,778		10,557		12,890		13,070
All other regions	2,414		2,020		3,390		2,123
Average retail customers count (in thousands, metered locations)
Mass ^(f)	2,182		2,123
Mass ^{(e) (f)}					2,840		2,144
Commercial and Industrial ^(e)(d)	88		103		87		101
Retail customers count (in thousands, metered locations)
Mass ^(f)	2,183		2,129
Mass ^{(e) (g)}					2,831		2,155
Commercial and Industrial ^(e)(d)	83		102		90		99


(a)	Includes customers of the Texas General Land Office for which the Company provides services, as well as sales to utility partner and natural gas customers.


(b)	Includes intercompany sales of $2$1 million and $1 million in 2014 and 2013, respectively, representing sales from Retail to the Texas region.


(c)	Includes intercompany purchases of ~~$366~~$530 million and $584 million in 2014 and 2013.


(d)	~~Excludes metrics related to the retail electric business of Dominion, acquired on March 31, 2014.~~


~~(e)~~	Includes customers of the Texas General Land Office for which the Company provides services.


~~(f)~~(e)	Excludes utility partner and natural gas customers.


(f)	Includes 23 thousand customers from the Dominion acquisition that have transitioned to NRG customers and 485 thousand customers who are still considered Dominion customers and may or may not transition to NRG customers.


(g)	Includes 70 thousand customers from the Dominion acquisition that have transitioned to NRG customers and 396 thousand customers who are still considered Dominion customers and may or may not transition to NRG customers.

Retail gross margin — Retail gross margin increased $28 million for the three months ended ~~March 31,~~June 30, 2014, compared to the same period in 2013, driven by:

Increase due primarily to higher revenues from home and business services and changes in customer and regional mix $ 12
Unfavorable impact of higher supply costs resulting from colder than normal weather (5 )
$ 7

~~Acquisition of Dominion's Retail Business —~~ ~~On March 31, 2014, the Company acquired the retail electric business of Dominion, as described in Note 3,~~ ~~Business Acquisitions~~. With this acquisition, by the end of 2014, the Company's retail business is expected to serve approximately 500,000 additional customers in Connecticut, Illinois, Maryland, Massachusetts, New Jersey, New York, Ohio, Pennsylvania and Texas, after customary transitions.



Increase from the acquisition of Dominion's competitive retail electricity business in March 2014 and Energy Curtailment Specialists in August 2013	$	27
Increase primarily due to higher revenues from home and business services and changes in customer and regional mix	10
Unfavorable impact of higher supply costs resulting from weather conditions in 2014	(9		)
	$	28

~~Alternative Energy~~Renewables gross margin

NRG's ~~Alternative Energy~~Renewable business segment, which is comprised primarily of certain solar and wind businesses that are not part of NRG Yield, had gross margin of ~~$53~~$160 million for the three months ended ~~March 31,~~June 30, 2014, compared to gross margin of ~~$35~~$53 million for the same period in 2013. The increase in gross margin ~~resulted~~was primarily ~~from~~a result of the ~~addition of 123MW at the CVSR facility.~~EME acquisition in April 2014.

NRG Yield gross margin

NRG Yield had gross margin of ~~$76~~$117 million for the three months ended ~~March 31,~~June 30, 2014, compared to gross margin of ~~$39~~$67 million for the same period in 2013, which related primarily ~~reflects~~to Marsh Landing and El Segundo Energy Center reaching commercial operations in ~~May~~ 2013 as well as the ~~completion of the repowering at~~ Dover facility which came back online on gas in ~~2013 and the acquisition of Energy Systems in December~~May 2013.

5465

Mark-to-market for Economic Hedging Activities

Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges and ineffectiveness on cash flow hedges. Total net mark-to-market results decreased by $5$217 million during the three months ended ~~March 31,~~June 30, 2014 compared to the same period in 2013.

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

Three months ended March 31, 2014
Conventional Generation
Retail Texas East
South
Central
West Alternative Energy
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 $ —
$ (49 ) $ 21
$ (3 ) $ —
$ 1
$ (36 ) $ (66 )
Reversal of gain positions acquired as part of the GenOn acquisition —
—
(79 ) —
(1 ) —
—
(80 )
Net unrealized losses on open positions related to economic hedges (1 ) (192 ) (181 ) —
(1 ) (2 ) 192
(185 )
Total mark-to-market losses in operating revenues $ (1 ) $ (241 ) $ (239 ) $ (3 ) $ (2 ) $ (1 )
$ 156
$ (331 )
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges $ 29
$ 1
$ 4
$ (1 ) $ —
$ —
$ 36
$ 69
Reversal of loss positions acquired as part of the GenOn acquisition —
—
2
—
—
—
—
2
Net unrealized gains/(losses) on open positions related to economic hedges 193
4
(14 ) 1
—
—
(192 ) (8 )
Total mark-to-market gains/(losses) in operating costs and expenses $ 222
$ 5
$ (8 ) $ —
$ —
$ —
$ (156 ) $ 63



	Three months ended June 30, 2014
				Conventional Generation
	Retail			Gulf Coast			East			West			Renewables			Elimination^(a)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized gains on settled positions related to economic hedges	$	—		$	(38	)	$	(5	)	$	(1	)	$	(1	)	$	(39	)	$	(84	)
Reversal of gain positions acquired as part of the GenOn acquisition	—			—			(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	$	35		$	1		$	4		$	—		$	—		$	39		$	79
Reversal of loss positions acquired as part of the GenOn and EME acquisitions	—			—			5			—			—			—			5
Net unrealized (losses)/gains on open positions related to economic hedges	(283		)	(8		)	45			—			—			91			(155		)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(248	)	$	(7	)	$	54		$	—		$	—		$	130		$	(71	)


(a)	Represents the elimination of the intercompany activity between the Retail Business and the Conventional Generation and ~~Alternative Energy~~Renewable regions.


	Three months ended March 31, 2013																							Three months ended June 30, 2013
				Conventional Generation																							Conventional Generation
	Retail			Texas			East			South Central		West			Alternative Energy			Elimination^(a)			Total			Retail			Gulf Coast			East			West			Renewables		Elimination^(a)			Total
	(In millions)																							(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(2	)	$	(162	)	$	(2	)	$	9	$	(1	)	$	—		$	67		$	(91	)	$	(2	)	$	(90	)	$	(1	)	$	(1	)	$	—	$	29		$	(65	)
Reversal of gain positions acquired as part of the GenOn acquisition	—			—			(107		)	—		(1		)	—			—			(108		)	—			—			(110		)	(1		)	—		—			(111		)
Net unrealized gains/(losses) on open positions related to economic hedges																								5			271			168			—			2		(77		)	369
Total mark-to-market gains/(losses) in operating revenues																								$	3		$	181		$	57		$	(2	)	$	2	$	(48	)	$	193
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges																								$	71		$	11		$	5		$	—		$	—	$	(29	)	$	58
Reversal of loss positions acquired as part of the Reliant Energy and Green Mountain Energy and GenOn acquisitions																								2			—			10			—			—		—			12
Net unrealized (losses)/gains on open positions related to economic hedges	(5		)	(228		)	(144		)	8		5			(1		)	86			(279		)	(244		)	(1		)	1			2			—		77			(165		)
Total mark-to-market (losses)/gains in operating revenues	$	(7	)	$	(390	)	$	(253	)	$	17	$	3		$	(1	)	$	153		$	(478	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses on settled positions related to economic hedges	$	117		$	6		$	4		$	6	$	—		$	—		$	(67	)	$	66
Reversal of loss positions acquired as part of the Reliant Energy and Green Mountain Energy acquisitions	5			—			15			—		—			—			—			20
Net unrealized gains/(losses) on open positions related to economic hedges	205			8			2			2		(2		)	—			(86		)	129
Total mark-to-market gains/(losses) in operating costs and expenses	$	327		$	14		$	21		$	8	$	(2	)	$	—		$	(153	)	$	215
Total mark-to-market (losses)/gains in operating costs and expenses																								$	(171	)	$	10		$	16		$	2		$	—	$	48		$	(95	)


(a)	Represents the elimination of the intercompany activity between the Retail Business and the Conventional Generation and ~~Alternative Energy~~Renewable regions.

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.

5566

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

For the three months ended ~~March 31,~~June 30, 2014, the ~~$185~~$125 million ~~loss~~gains in operating revenues from open positions was due primarily to decreases in ERCOT heat rates partially offset by increases in ~~forward~~East power and natural gas ~~and power~~ prices. The $8$155 million loss in operating costs and expenses from open positions was due primarily to decreases in ERCOT power prices partially offset by increases in coal prices.

For the three months ended ~~March 31,~~June 30, 2013, the ~~net losses on~~$369 million gain in operating revenues from open positions ~~were~~was due primarily to ~~increases~~decreases in forward natural gas and power prices. The $165 million loss in operating costs and expenses were due to decreases in forward natural gas and power prices slightly offset by increases in coal prices.

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the three months ended ~~March 31,~~June 30, 2014 and 2013. 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 March 31,					Three months ended June 30,
(In millions)	2014		2013			2014		2013
Trading gains/(losses)
Realized	$	43	$	41		$	19	$	17
Unrealized	15		(43		)	—		(12		)
Total trading gains/(losses)	$	58	$	(2	)
Total trading gains						$	19	$	5

~~Contract Amortization Revenue~~

~~Contract amortization represents the roll-off of in-market customer contracts valued under purchase accounting and the variance of $20 million, as compared to the prior period in~~ ~~2013~~ ~~which reflects the completion of the roll-off of certain customer contracts acquired in the Reliant acquisition.~~

Other Operating Costs

Conventional Generation
Retail Texas East
South
Central
West Other Alternative Energy NRG Yield Eliminations/Corporate Total
(In millions)
Three months ended March 31, 2014 $ 69
$ 164
$ 214
$ 36
$ 46
$ 19
$ 20
$ 20
$ (29 ) $ 559
Three months ended March 31, 2013 $ 57

$ 137
$ 238
$ 29
$ 52
$ 13
$ 7
$ 14
$ (22 ) $ 525



			Conventional Generation
	Retail		Gulf Coast		East		West		Renewables		NRG Yield		Eliminations/Corporate			Total
	(In millions)
Three months ended June 30, 2014	$	74	$	188	$	332	$	45	$	51	$	27	$	(1	)	$	716
Three months ended June 30, 2013	67		170		239		45		9		17		(8		)	539

Other operating costs increased by ~~$34~~$177 million for the three months ended ~~March 31,~~June 30, 2014, compared to the same period in 2013, due to:

Increase in Texas operations and maintenance expense $ 20
Increase in Alternative Energy and NRG Yield operations and maintenance expense 13
Increase in property tax expense 11
Other (10 )
$ 34

•~~Texas operations and maintenance expense~~ - Includes an increase of $10 million for STP related to a planned outage in 2014 and an increase of $10 million at Limestone and W.A. Parish related to timing and scope of major maintenance activities.

•~~Alternative Energy and NRG Yield operations and maintenance expense~~ - Reflects increased expense for projects that reached commercial operations in 2013, including Marsh Landing and Borrego, as well as additional expense related to the Dover facility that was converted to natural gas in 2013 and the acquisition of Energy Systems Company in December 2013, as discussed in Note 3, ~~Business Acquisition~~s, ~~to this Form 10-Q as found in Item 1.~~



Increase due to the acquisition of EME in April 2014	$	134
Increase in property tax which reflects a refund in the prior year for Empire Zone credits	13
Increase in Gulf Coast operations and maintenance expense due to the scope and timing of outage activities	19
Decrease in East operations and maintenance expense as Morgantown had a significant outage in the prior year	(15		)
Increase in NRG Yield operations and maintenance expense, related to El Segundo and Marsh Landing which reached commercial operations in the second half of 2013	9
Other	17
	$	177

Depreciation and Amortization

Depreciation and amortization increased by ~~$28~~$73 million for the three months ended ~~March 31,~~June 30, 2014, compared to the same period in 2013~~. This was~~, due primarily to $52 million related to the EME acquisition in April 2014 and additional depreciation for facilities that reached commercial operations in 2013.

5667

Selling, General and Administrative Expenses

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


	Three months ended March 31,				Three months ended June 30,
(In millions)	2014		2013		2014		2013
General and administrative expenses	$	158	$	153	$	182	$	153
Selling and marketing expenses	68		74		86		77
	$	226	$	227	$	268	$	230

General and administrative expenses increased by $5$29 million for the three months ended ~~March 31,~~June 30, 2014 compared to the same period in 2013, ~~primarily from an increase~~due in ~~bad debt expense~~part to the acquisition of ~~$12~~EME in April 2014 and the presentation of Residential Solar expenses as development in prior periods as well as expansion of the Residential Solar business. Selling and marketing expenses increased by $9 million ~~offset by a decrease~~compared to the prior year, in ~~personnel costs.~~part due to the acquisition of Dominion's competitive retail electricity business.

Acquisition-related Transaction and Integration Costs

NRG incurred transaction and integration costs of ~~$12~~$40 million in the three months ended ~~March 31,~~June 30, 2014, compared to ~~$42~~$27 million for the same period in 2013.

Equity in Earnings of Unconsolidated Affiliates

NRG's equity in earnings of unconsolidated affiliates ~~was $7~~increased $6 million for the three months ended ~~March 31,~~June 30, 2014 as compared to ~~equity in earnings of unconsolidated affiliates of~~ ~~$3 million~~ ~~for~~ the same period in 2013, due primarily ~~resulting from a~~to the acquisition of EME in April 2014 offset in part by the change in fair value of the Saguaro long-term natural gas hedge ~~entered into by Saguaro in July 2013.~~and Sherbino forward gas contract.

Interest Expense

NRG's interest expense increased by $5968 million compared to the same period in 2013 due to the following:

Increase in interest expense (In millions)
Reduction to capitalized interest for projects placed in service $ 38
Issuance of 2022 Senior Notes in January 2014 12
Increase in derivative interest expense 6
Increase in other interest expense 3
$ 59



Increase in interest expense	(In millions)
Reduction to capitalized interest for projects placed in service	$	32
Increase for the acquisition of EME debt in April 2014	18
Increase for 2022 Senior Notes issued in January 2014	17
Increase for 2024 Senior Notes issued in April 2014	12
Increase in amortization of premium/discount	7
Decrease for 7.625% GenOn Senior Notes due 2014 redeemed in June 2013	(10		)
Decrease in other interest expense	(8		)
	$	68

Income Tax Benefit

For the three months ended ~~March 31,~~June 30, 2014,, NRG recorded an income tax benefit of $31$126 million on a pre-tax loss of $~~98 million~~.$206 million. For the same period in 2013,, NRG recorded an income tax benefit of $~~152~~$63 million on pre-tax ~~loss~~income of $~~483 million~~.$68 million. The effective tax rate was ~~31.6%~~61.2% and ~~31.5%~~(92.6%) for the three months ended ~~March 31,~~June 30, 2014,, and 2013,, respectively.

For the three months ended ~~March 31,~~June 30, 2014,, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the impact of ~~non-taxable equity earnings,~~ production tax credits generated from our wind assets and ~~state and local income taxes.~~the recognition of uncertain tax benefits during the quarter.

For the three months ended ~~March 31,~~June 30, 2013, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to ~~changes~~the recognition of ITCs from the Company's Agua Caliente solar project in Arizona and the ~~valuation allowance as a result~~impact of ~~capital losses generated during the period.~~non-taxable equity earnings.

Noncontrolling Interest

For the three months ended June 30, 2014, loss attributable to noncontrolling interests primarily reflects NRG Yield Inc.'s share of net income as well as income attributable to the noncontrolling partners for the Capistrano projects, offset by losses attributable to the noncontrolling partners for Ivanpah. For the three months ended June 30, 2013, income attributable to noncontrolling interests primarily reflects income attributable to the noncontrolling partner for Agua Caliente.

Management’s discussion of the results of operations for the six months ended June 30, 2014 and 2013

(Loss)/income before income taxes — The pre-tax loss of $304 million for the six months ended June 30, 2014, compared to a pre-tax loss of $415 million for the six months ended June 30, 2013, primarily reflects:

an increase in gross margin of $724 million comprised of an increase in Conventional Generation gross margin of $451 million, an increase in Renewables gross margin of $122 million, an increase in Yield gross margin of $116 million, and an increase in Retail gross margin of $35 million;

offset by:

increased operating costs of $332 million, including operations and maintenance expense, depreciation and amortization, selling, general and administrative costs, and acquisition-related costs and;

a current year decrease from net market-to-market results for economic hedging activity of $222 million

Net (Loss)/income — The decrease in net loss of $53 million primarily reflects the drivers discussed above, including an income tax benefit for the six months ended June 30, 2014 of $157 million, compared to an income tax benefit of $215 million in the comparable period.

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, 2014 and 2013:



	Average on Peak Power Price ($/MWh)
	Six months ended June 30,
Region	2014		2013
Gulf Coast ^(a)
ERCOT - Houston	$	51.22	$	32.73
ERCOT - North	50.37		32.10
MISO - Louisiana Hub ^(b)	58.96		37.06
East
NY J/NYC	101.55		67.22
NY A/West NY	75.13		43.03
NEPOOL	105.75		67.54
PEPCO (PJM)	93.59		44.60
PJM West Hub	81.44		43.68
West
CAISO - NP15	52.87		39.32
CAISO - SP15	50.59		46.08

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

(b) Gulf Coast region, south central market 2013 price data is "into Entergy", MISO-Louisiana Hub began trading December 2013.

Conventional Generation gross margin

The following is a discussion of gross margin for NRG's Conventional Generation businesses, adjusted to eliminate intersegment activity, primarily with the Retail Business.



	Six months ended June 30, 2014
	Conventional Generation
(In millions except otherwise noted)	Gulf Coast			East			West			Subtotal			Renewables			NRG Yield			Eliminations/Corporate			Consolidated Total
Energy revenue	$	1,329		$	1,954		$	115		$	3,398		$	166		$	65		$	(897	)	$	2,732
Capacity revenue	120			638			157			915			38			120			(9		)	1,064
Other revenue	47			65			4			116			10			90			64			280
Generation revenue	1,496			2,657			276			4,429			214			275			(842		)	4,076
Generation cost of sales	(880		)	(1,324		)	(103		)	(2,307		)	(4		)	(53		)	(9		)	(2,373		)
Generation gross margin	$	616		$	1,333		$	173		$	2,122		$	210		$	222

Business Metrics
MWh sold (in thousands) ^(a)	29,094			24,980			987						2,703			1,175
MWh generated (in thousands)	28,815			30,945			2,140						4,779			1,420
(a) MWh sold excludes generation at facilities that generate revenue under capacity agreements.



	Six months ended June 30, 2013
	Conventional Generation
(In millions except otherwise noted)	Gulf Coast			East			West			Subtotal			Renewables		NRG Yield			Eliminations/Corporate			Consolidated Total
Energy revenue	$	1,285		$	1,133		$	75		$	2,493		$	87	$	43		$	(927	)	$	1,696
Capacity revenue	154			464			136			754			—		19			(12		)	761
Other revenue	(13		)	20			1			8			1		73			(21		)	61
Generation revenue	1,426			1,617			212			3,255			88		135			(960		)	2,518
Generation cost of sales	(805		)	(728		)	(51		)	(1,584		)	—		(29		)	24			(1,589		)
Generation gross margin	$	621		$	889		$	161		$	1,671		$	88	$	106

Business Metrics
MWh sold (in thousands) ^(a)	29,690			17,414			720						1,002		439
MWh generated (in thousands)	26,603			16,867			1,088						1,005		471
(a) MWh sold excludes generation at facilities that generate revenue under capacity agreements.

	Six months ended June 30,
Weather Metrics	Gulf Coast			East			West
2014
CDDs ^(a)	1,864			1,024			252
HDDs ^(a)	2,813			10,162			1,099
2013
CDDs	1,938			1,076			189
HDDs	2,402			9,159			1,448
10 year average
CDDs	2,110			1,095			153
HDDs	2,215			8,998			1,575

(a)

Conventional Generation gross margin — increased by $451 million including intercompany sales, during the six months ended June 30, 2014, compared to the same period in 2013, due to:



Gulf Coast region	$	(5	)
East region	444
West region	12
	$	451

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



Lower gross margin from a decrease in average realized price	$	(79	)
Lower gross margin from the sale of NOx emission credits in 2013	(14		)
Higher gross margin from a 4% increase in coal generation driven by higher economic dispatch driven by fewer outages	12
Higher gross margin from lower coal transportation costs	12
Higher gross margin due to the acquisition of Gregory in August 2013	16
Change in commercial optimization activities and other	48
	$	(5	)

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



Higher gross margin due primarily to a 20% increase in generation and a 33% increase in realized energy prices	$	243
Higher gross margin from a 27% increase in New York and PJM hedged capacity prices as well as higher prices for the new Lower Hudson Valley Capacity Zone	142
Higher gross margin from the acquisition of EME in April 2014	87
Lower margins realized on certain load-serving contracts due to increased prices for power purchases	(40		)
Other	12
	$	444

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



Higher gross margin from the acquisition of EME in April 2014	$	29
Higher capacity gross margin due primarily to increases in realized prices	18
Lower gross margin primarily due to a 60% decrease in generation primarily due to increased dispatch from competing resources, including renewable resources.	(22		)
Lower gross margin due to the deactivation of the Contra Costa facility in 2013	(15		)
Other	2
	$	12

Retail gross margin

The following is a detailed discussion of retail gross margin for NRG's Retail Business segment.



	Six months ended June 30,
(In millions except otherwise noted)	2014		2013
Mass revenues	$	2,280	1,781
Commercial and Industrial revenues	880		950
Supply management and other revenues	247		77
Retail revenue ^(a)(b)	3,407		2,808
Retail cost of sales ^(c)	2,769		2,205
Retail gross margin	$	638	$	603

Business Metrics
Electricity sales volume — GWh
Mass	17,789		14,598
Commercial and Industrial ^(d)	11,685		13,172
Electricity sales volume — GWh
Texas	23,670		23,627
All other regions	5,804		4,143
Average retail customers count (in thousands, metered locations)
Mass ^{(e) (f)}	2,511		2,134
Commercial and Industrial ^(d)	87		102
Retail customers count (in thousands, metered locations)
Mass ^{(e) (g)}	2,831		2,155
Commercial and Industrial ^(d)	90		99


(a)	Includes customers of the Texas General Land Office for which the Company provides services, as well as sales to utility partner and natural gas customers.


(b)	Includes intercompany sales of $3 million and $2 million in 2014 and 2013, respectively, representing sales from Retail to the Texas region.


(c)	Includes intercompany purchases of $896 million in 2014 and $950 million in 2013.


(d)	Includes customers of the Texas General Land Office for which the Company provides services.


(e)	Excludes utility partner and natural gas customers.


(f)	Includes 12 thousand customers from the Dominion acquisition that have transitioned to NRG customers and 242 thousand customers who are still considered Dominion customers and may or may not transition to NRG.


(g)	Includes 70 thousand customers from the Dominion acquisition that have transitioned to NRG customers and 396 thousand customers who are still considered Dominion customers and may or may not transition to NRG.

Retail gross margin — Retail gross margin increased $35 million for the six months ended June 30, 2014, compared to the same period in 2013, driven by:



Increase from the acquisition of Dominion's competitive retail electricity business in March 2014 and Energy Curtailment Specialists in August 2013	$	31
Increase primarily due to higher revenues from home and business services and changes in customer and regional mix	18
Unfavorable impact of higher supply costs resulting from weather conditions in 2014	(14		)
	$	35

Acquisition of Dominion's Competitive Retail Electricity Business — On March 31, 2014, the Company acquired the competitive retail electricity business of Dominion, as described in Note 3, Business Acquisitions and Dispositions. The acquisition of Dominion’s competitive retail electricity business increased NRG’s retail portfolio by approximately 217,000 customers as of June 30, 2014, and is expected to increase NRG’s retail portfolio by approximately 500,000 customers in the aggregate by the end of 2014.

Renewables gross margin

NRG's Renewable business segment, which is comprised primarily of certain solar and wind businesses that are not part of NRG Yield, had gross margin of $210 million for the six months ended June 30, 2014, compared to gross margin of $88 million for the same period in 2013. The increase in gross margin was primarily a result of the EME acquisition in April 2014.

NRG Yield gross margin

NRG Yield had gross margin of $222 million for the six months ended June 30, 2014, compared to gross margin of $106 million for the same period in 2013, which related primarily to Marsh Landing and El Segundo Energy Center reaching commercial operations in 2013 as well as the Dover facility which came back on line on gas in May 2013.

Mark-to-market for Economic Hedging Activities

Mark-to-market for economic hedging activities includes asset-backed hedges that have not been designated as cash flow hedges and ineffectiveness on cash flow hedges. Total net mark-to-market results decreased by $222 million during the six months ended June 30, 2014 compared to the same period in 2013.

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, 2014
				Conventional Generation
	Retail			Gulf Coast			East			West			Renewables		Elimination^(a)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	—		$	(90	)	$	16		$	(1	)	$	—	$	(75	)	$	(150	)
Reversal of gain positions acquired as part of the GenOn acquisition	—			—			(168		)	(1		)	—		—			(169		)
Net unrealized (losses)/gains on open positions related to economic hedges	(1		)	63			(224		)	1			—		101			(60		)
Total mark-to-market (losses)/gains in operating revenues	$	(1	)	$	(27	)	$	(376	)	$	(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	$	64		$	1		$	8		$	—		$	—	$	75		$	148
Reversal of loss positions acquired as part of the GenOn and EME acquisitions	—			—			7			—			—		—			7
Net unrealized (losses)/gains on open positions related to economic hedges	(90		)	(3		)	31			—			—		(101		)	(163		)
Total mark-to-market (losses)/gains in operating costs and expenses	$	(26	)	$	(2	)	$	46		$	—		$	—	$	(26	)	$	(8	)


(a)	Represents the elimination of the intercompany activity between the Retail Business and the Conventional Generation and Renewable regions.



	Six months ended June 30, 2013
				Conventional Generation
	Retail			Gulf Coast			East			West			Renewables		Elimination^(a)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(4	)	$	(243	)	$	(3	)	$	(2	)	$	—	$	96		$	(156	)
Reversal of gain positions acquired as part of the GenOn acquisition	—			—			(217		)	(2		)	—		—			(219		)
Net unrealized gains on open positions related to economic hedges	—			51			24			5			1		9			90
Total mark-to-market (losses)/gains in operating revenues	$	(4	)	$	(192	)	$	(196	)	$	1		$	1	$	105		$	(285	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	188		$	23		$	9		$	—		$	—	$	(96	)	$	124
Reversal of loss positions acquired as part of the Reliant Energy and Green Mountain Energy and GenOn acquisitions	7			—			25			—			—		—			32
Net unrealized (losses)/gains on open positions related to economic hedges	(39		)	9			3			—			—		(9		)	(36		)
Total mark-to-market gains/(losses) in operating costs and expenses	$	156		$	32		$	37		$	—		$	—	$	(105	)	$	120


(a)	Represents the elimination of the intercompany activity between the Retail Business and the Conventional Generation and Renewable regions.

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 gain or loss positions from acquired companies were valued based upon the forward prices on the acquisition date.

For the six months ended June 30, 2014, the $60 million loss in operating revenues from open positions was due primarily to increases in forward natural gas and East power prices partially offset by decreases in ERCOT heat rates. The $163 million loss in operating costs and expenses from open positions was due primarily to decreases in ERCOT heat rates.

For the six months ended June 30, 2013, a $90 million gain in operating revenues from open positions was due to decreases in forward natural gas and power prices. The $36 million loss in operating costs and expenses from open positions was due to decreases in forward natural gas and power prices slightly offset by increases in coal prices.

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the six months ended June 30, 2014 and 2013. 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)	2014		2013
Trading gains/(losses)
Realized	$	62	$	58
Unrealized	15		(55		)
Total trading gains	$	77	$	3

Contract Amortization Revenue

Contract amortization represents the roll-off of in-market customer contracts valued under purchase accounting. The favorable change of $35 million, as compared to the prior period in 2013 reflects the completion of the roll-off of certain customer contracts acquired in the Reliant acquisition.

Other Operating Costs



			Conventional Generation
	Retail		Gulf Coast		East		West		Renewables		NRG Yield		Eliminations/Corporate			Total
	(In millions)
Six months ended June 30, 2014	$	143	$	388	$	546	$	87	$	70	$	52	$	(11	)	$	1,275
Six months ended June 30, 2013	124		334		477		97		16		31		(15		)	1,064

Other operating costs increased by $211 million for the six months ended June 30, 2014, compared to the same period in 2013, due to:



Increase due to the acquisition of EME in April 2014	$	134
Increase in Gulf Coast operations and maintenance expense primarily related to the scope and timing of outage activities	49
Increase in property tax in part due to a tax settlement in the first quarter of 2014	25
Increase in NRG Yield operations and maintenance expense related to El Segundo and Marsh Landing which reached commercial operations in 2013	16
Decrease in East operations and maintenance expense as Morgantown had a significant outage in the prior year	(21		)
Other	8
	$	211

Depreciation and Amortization

Depreciation and amortization increased by $101 million for the six months ended June 30, 2014, compared to the same period in 2013, due primarily to $52 million related to the EME acquisition in April 2014 and additional depreciation expense of $40 million as a result of El Segundo and Marsh Landing reaching commercial operations in the second half of 2013.

Selling, General and Administrative Expenses

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



	Six months ended June 30,
(In millions)	2014		2013
General and administrative expenses	$	340	$	304
Selling and marketing expenses	154		153
	$	494	$	457

General and administrative expenses increased by $36 million for the six months ended June 30, 2014 compared to the same period in 2013, due in part to the acquisition of EME in April 2014 and the presentation of Residential Solar expenses as development in prior periods as well as expansion of the Residential Solar business.

Acquisition-related Transaction and Integration Costs

NRG incurred transaction and integration costs of $52 million for the six months ended June 30, 2014, compared to $69 million for the same period in 2013.

Equity in Earnings of Unconsolidated Affiliates

NRG's equity in earnings of unconsolidated affiliates was $21 million for the six months ended June 30, 2014 compared to equity in earnings of unconsolidated affiliates of $11 million for the same period in 2013, due primarily to $7 million from a long-term natural gas hedge entered into by Saguaro in July 2013 and $4 million resulting from the acquisition of EME in April 2014.

Interest Expense

NRG's interest expense increased by $127 million compared to the same period in 2013 due to the following:



Increase in interest expense	(In millions)
Reduction to capitalized interest for projects placed in service	$	70
Increase for 2022 Senior Notes issued in January 2014	29
Decrease in amortization of premium/discount	17
Decrease for 7.625% GenOn Senior Notes due 2014 redeemed in June 2013	(21		)
Increase for the acquisition of EME debt in April 2014	18
Increase in derivative interest expense primarily for the Alpine interest rate swaps	13
Increase for 2024 Senior Notes issued in April 2014	12
Decrease in other interest expense	(11		)
	$	127

Income Tax Benefit

For the six months ended June 30, 2014, NRG recorded an income tax benefit of $157 million on pre-tax loss of $304 million. For the same period in 2013, NRG recorded an income tax benefit of $215 million on pre-tax loss of $415 million. The effective tax rate was 51.6% and 51.8 % for the six months ended June 30, 2014, and 2013, respectively.

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.

For the six months ended June 30, 2013, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the recognition of ITCs from the Company's Agua Caliente solar project in Arizona and the impact of non-taxable equity earnings.

Noncontrolling Interest

For the six months ended June 30, 2014, loss attributable to noncontrolling interests primarily reflects NRG Yield Inc.'s share of net income for the period ~~after~~as well as income attributable to the ~~initial public offering,~~noncontrolling partners for the Capistrano projects, offset by losses attributable to the noncontrolling partners for Ivanpah. For the ~~three~~six months ended ~~March 31,~~June 30, 2013, income attributable to noncontrolling interests primarily reflects income attributable to the noncontrolling partner for Agua Caliente.

5775

Liquidity and Capital Resources

Liquidity Position

As of ~~March 31,~~June 30, 2014, and December 31, 2013, NRG's liquidity, excluding collateral received, was approximately $~~4.7~~3.0 billion and $3.7 billion, respectively, comprised of the following:


(In millions)	March 31, 2014		December 31, 2013		June 30, 2014		December 31, 2013
Cash and cash equivalents	$	3,187	$	2,254	$	1,481	$	2,254
Restricted cash	209		268		286		268
Total	3,396		2,522		1,767		2,522
Total credit facility availability	1,303		1,173		1,243		1,173
Total liquidity, excluding collateral received	$	4,699	$	3,695	$	3,010	$	3,695

For the ~~three~~six months ended ~~March 31,~~June 30, 2014, total liquidity, excluding collateral received, ~~increased~~decreased by ~~$1.0 billion.~~$685 million. Changes in cash and cash equivalent balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents at ~~March 31,~~June 30, 2014 were predominantly held in money market mutual funds and bank deposits.

On April 1, 2014, to fund the acquisition of EME, the Company used cash on hand as well as $700 million of the proceeds from the issuance of the 2022 Senior Notes to fund the net cash purchase price of EME, as further described in Note 3, ~~Business Acquisitions~~.

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 other liquidity commitments. Management continues to regularly monitor the Company's ability to finance the needs of its operating, financing and investing activity within the dictates of prudent balance sheet management.

Restricted Payments Tests

Of the $1.5 billion of cash and cash equivalents of the Company as of June 30, 2014, $355 million and $35 million were held by REMA and GenOn Mid-Atlantic, 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 Gen-On 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 ~~satisfied the restricted payments tests~~ and REMA did not satisfy the restricted payments tests. As a result, as of June 30, 2014, 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~~To the extent GenOn Mid-Atlantic or REMA are able to pay dividends to GenOn, the GenOn Senior Notes due 2018 and 2020 and the related indentures restrict the ability of GenOn to incur additional liens and make certain restricted payments, including dividends. In the event of a default or if restricted payment tests are not satisfied, GenOn would not be able to distribute cash to its parent, NRG. At ~~March 31,~~June 30, 2014, GenOn met the consolidated debt ratio component of the restricted payments test.

Credit Ratings

On January 24, 2014, Moody's placed the GenOn Senior Notes' rating under review for downgrade. On April 14, 2014, the GenOn Americas Generation Senior Notes were downgraded by Moody's to Caa1 and the GenOn Senior Notes were downgraded to B3. The outlook for both the GenOn Americas Generation Senior Notes and the GenOn Senior Notes was moved to Stable.

5876

Sources of Liquidity

The principal sources of liquidity for NRG's future operating and capital expenditures are expected to be derived from new and existing financing arrangements, existing cash on hand, cash flows from operations and cash proceeds from future sales of assets to NRG Yield, Inc. As described in Note 7, Debt and Capital Leases, to this Form 10-Q and Note 12, Debt and Capital Leases, to the Company's 2013 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.

Issuance of 2022 and 2024 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. A portion of the cash proceeds was used to redeem $400 million of the Company's 2019 Senior Notes and the remaining $700 million of the cash proceeds was used to finance the EME acquisition, as discussed in Uses of Liquidity — 2014 Capital Allocation Program.

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 May 1, 2024. ~~The~~A portion of the cash proceeds was used to redeem all remaining 7.625% 2019 Senior Notes, and the rest of the proceeds are expected to be used to redeem ~~any and~~ all ~~of $299 million and $709 million of its~~remaining 8.5% ~~and 7.625%~~ 2019 Senior Notes ~~respectively,~~in September 2014, as discussed in Uses of Liquidity.

Cash Proceeds from NRG Yield, Inc. Class A Common Stock and Senior Unsecured Notes

In order to fund the purchase price of the acquisition of the Alta Wind facility, as discussed further in Note 3, Business Acquisitions and Dispositions, to this Form 10-Q, 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, commencing 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 current and future subsidiaries.

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

On ~~May 5,~~June 30, 2014, the Company ~~and~~sold the following facilities to NRG Yield, Inc. ~~entered into a definitive agreement regarding the sale of the following NRG facilities: TA~~: High Desert, RE Kansas South, and El Segundo Energy ~~Center, for~~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 ~~and working capital adjustments to be calculated at close.~~of approximately $612 million. The sale ~~is subject to certain third party~~was recorded as a transfer of entities under common control and ~~regulatory approvals and is expected to close by~~ the ~~end of the second quarter of 2014.~~related assets were transferred at carrying value.

First Lien Structure

NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, excluding GenOn, 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 coal capacity, and 10% of its other assets, excluding GenOn'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 ~~March 31,~~June 30, 2014, all hedges under the first liens were out-of-the-money on a counterparty aggregate basis.

The following table summarizes the amount of MWs hedged against the Company's coal and nuclear assets and as a percentage relative to the Company's coal and nuclear capacity under the first lien structure as of ~~March 31,~~June 30, 2014:


Equivalent Net Sales Secured by First Lien Structure ^(a)	2014		2015		2016		2017		2018		2014		2015		2016		2017		2018
In MW	1,677		898		351		211		—		1,498		1,061		405		243		—
As a percentage of total net coal and nuclear capacity ^(b)	26	%	15	%	6	%	3	%	—	%	23	%	17	%	7	%	4	%	—	%


(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 acquisition, ~~as well as~~ assets in NRG ~~Yield.~~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 ~~2014~~ Capital Allocation Program including acquisition opportunities, return of capital and dividend payments to stockholders.

Commercial Operations

NRG's commercial operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) margin and collateral required to participate in physical markets and commodity exchanges; (iii) timing of disbursements and receipts (i.e. buying fuel before receiving energy revenues); (iv) initial collateral for large structured transactions; and (v) collateral for project development. As of ~~March 31,~~June 30, 2014, commercial operations had total cash collateral outstanding of ~~$633~~$549 million, and $~~1.2~~1.1 billion outstanding in letters of credit to third parties primarily to support its commercial activities for both wholesale and retail transactions. As of ~~March 31,~~June 30, 2014, total collateral held from counterparties was $4$9 million in cash and $227 million of 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.

Cash Grant Bridge Loans

As of ~~March 31,~~June 30, 2014, the Company had a net renewable energy grant receivable of ~~$116~~$614 million which consists of ~~$41~~$539 million, net of sequestration adjustment, due from the U.S. Treasury under the 1603 Cash Grant Program in connection with the ~~Kansas South and TA High Desert projects,~~Ivanpah thermal solar project and a $75 million receivable pursuant to an indemnity agreement the Company has with SunPower Corporation, ~~Systems.~~

~~In May 2014, the Company will be submitting applications for approximately $550 million, in the aggregate, net of sequestration adjustment,~~Systems relating to the U.S. Treasury Department under the 1603 program for the Ivanpah thermal solar project and will submit applications for an additional $8 million upon the completion of various Distributed Solar projects. CVSR project.

With respect to certain projects, the Company obtained cash grant bridge loans to fund the construction costs of such projects, which were to be repaid upon receipt of the related 1603 cash grant proceeds. As of ~~March 31,~~June 30, 2014, there are approximately ~~$450~~$408 million outstanding under the cash grant bridge loans, all of which is related to the Ivanpah project and will become due and payable as follows:

Three months ending: Cash due and payable
(In millions)
June 30, 2014 $ 201
December 31, 2014 117
March 31, 2015 132
Total cash grant bridge loans due, including interest accrued to principal $ 450



Maturity date:	Cash due and payable
	(In millions)
Solar Partners VIII, October 27, 2014	$	117
Solar Partners I, December 27, 2014	159
Solar Partners II, February 27, 2015	132
Total cash grant bridge loans due, including interest accrued to principal	$	408

Since December 31, 2013, excluding CVSR, the Company has received the following cash grants as of ~~April~~June 30, 2014:



Project:	Application Amount		Sequestration Amount		Additional Reduction By U.S. Treasury ^(a)		Amount Received
	(In millions)
Alpine	$	71	$	5	$	—	$	66
Borrego	38		2		6		30
Lincoln Financial Field	6		1		—		5
Kansas South ^(b)	23		2		—		21
High Desert ^(c)	25		1		4		20
Total	$	163	$	11	$	10	$	142

(a) The Company has booked a reserve against the total remaining receivable balance for these projects in the amount of $10 million pending further discussions with U.S. Treasury.

(b) The Company was awarded and received the cash grant in April 2014.

In January 2014, the Company was awarded a cash grant from the U.S. Treasury Department in the amount of $285 million for the CVSR solar project. The amount received reflects the application amount of $414 million less a ~~sequestration adjustment of $22 million and an additional~~ reduction by Treasury of $107 million and a sequestration adjustment of $22 million. NRG maintains a receivable, net of sequestration of $107 million, ~~and is seeking reimbursement of $75 million of this amount under an indemnity agreement with SunPower Corporation, Systems,~~for which the ~~solar panel and equipment manufacturer, pertaining to Treasury's reduced cash grants for the CVSR project. The~~ Company has reserved $32 million of the balance. Pursuant to the purchase and sale agreement for the CVSR project between NRG and SunPower Corporation, Systems, or SunPower, SunPower agreed to indemnify NRG up to $75 million if Treasury 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 ~~the remaining receivable balance.~~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.

NRG believes it has complied with all material obligations under the 1603 Cash Grant Program and is actively pursuing indemnification and is working with the U.S. Treasury Department to obtain payment on the remaining 1603 applications the Company or its subsidiaries have submitted. Since the Company’s participation in the 1603 program commenced in 2010, the Company has received cash grants of approximately $612 million in the aggregate, net of sequestration adjustment, which excluding CVSR, represents a ~~97%~~95% collection rate of cash grant awards as applied for under the program.

Capital Expenditures

The following tables and descriptions summarize the Company's capital expenditures for maintenance, environmental, and growth investments for the ~~three~~six months ended ~~March 31,~~June 30, 2014, and the estimated capital expenditure and growth investments forecast for the remainder of 2014.


	Maintenance			Environmental		Growth Investments			Total			Maintenance			Environmental		Growth Investments			Total
	(In millions)											(In millions)
Gulf Coast												$	42		$	66	$	5		$	113
East	$	23		$	15	$	—		$	38		104			20		2			126
Texas	25			1		—			26
South Central	4			34		—			38
West	2			—		—			2			3			—		—			3
Other Conventional	3			—		1			4
Retail	7			—		—			7			13			—		—			13
Alternative Energy	1			—		100			101
Renewables												—			—		194			194
NRG Yield	3			—		16			19			5			—		24			29
Corporate	2			—		—			2			11			—		18			29

Total cash capital expenditures for the three months ended March 31, 2014	70			50		117			237
Total cash capital expenditures for the six months ended June 30, 2014												178			86		243			507
Other investments ^(a)	—			—		19			19			—			—		54			54
Funding from debt financing, net of fees	—			—		(118		)	(118		)	—			—		(164		)	(164		)
Funding from third party equity partners	(3		)	—		(60		)	(63		)	(3		)	—		(82		)	(85		)
Total capital expenditures and investments, net of financings	$	67		$	50	$	(42	)	$	75		175			86		51			312

Estimated capital expenditures for the remainder of 2014	$	380		$	278	$	614		$	1,272		269			267		279			815
Other investments ^(a)	—			—		291			291			—			—		38			38
Funding from debt financing, net of fees	(24		)	—		(288		)	(312		)	(29		)	—		(172		)	(201		)
Funding from third party equity partners and cash grants	(11		)	—		(342		)	(353		)	(9		)	—		(179		)	(188		)
NRG estimated capital expenditures for the remainder of 2014, net of financings	$	345		$	278	$	275		$	898		$	231		$	267	$	(34	)	$	464


(a)	Other investments includes restricted cash activity.


•	Environmental capital expenditures — For the ~~three~~six months ended ~~March 31,~~June 30, 2014, the Company's environmental capital expenditures included controls to satisfy MATS and NSR settlement at the Big Cajun II facility and NO_x controls for the Sayreville and Gilbert facilities.

Growth Investments capital expenditures — For the ~~three~~six months ended ~~March 31,~~June 30, 2014, the Company's growth investment expenditures included ~~$97~~$194 million for solar projects and ~~$20~~$42 million for the Company's ~~repowering~~other growth projects.

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 2014 through 2018 required to comply with environmental laws will be approximately $~~326~~906 million which includes $~~116~~123 million for ~~GenOn.~~GenOn and $567 million (of which $22 million is attributable to interest during construction) for plants acquired in the EME acquisition.

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 MATS, of which the Company estimates that up to $100 million will be incurred in 2014. The Company is in the process of evaluating additional capital expenditures that will be incurred in connection with the acquisition and integration of EME. environmental regulations.

2014 Capital Allocation Program

~~EME~~Pending Acquisition

As described in Note 3, Business Acquisitions and Dispositions, on June 3, 2014, Yield Operating, a consolidated subsidiary of the Company, entered into a purchase and sale agreement with the Terra-Gen Finance Company, LLC and certain of its affiliates to acquire 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 owns seven wind facilities that total 947 MWs located in Tehachapi, California and a portfolio of land leases, or the Alta Wind Assets. The purchase price of the Alta Wind Assets is $870 million, as well as working capital adjustments, plus the assumption of $1.6 billion in non-recourse project level debt. The acquisition, which is subject to customary closing conditions, including certain regulatory approvals, is expected to close during the third quarter of 2014. Power generated by the Alta Wind facility is sold to Southern California Edison under long-term power purchase agreements with 21 years of remaining contract life for Phases I-V and 22 years, beginning in 2016, for Phases X and XI.

Completed Acquisitions

On April 1, 2014, the Company acquired substantially all of the assets of ~~Edison Mission Energy, or~~ EME as described in Note 3, Business Acquisitions and Dispositions. EME, through its subsidiaries and affiliates, owned, operated, and leased 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 $~~3.4~~3.5 billion, which reflects the negotiated purchase price of $2.6 billion, an increase of $736 million in acquired cash on hand, cash collateral, restricted cash and cash on unconsolidated subsidiary, as well as an increase in the value of the 12,671,977 shares of NRG common stock issued of $51 million. The purchase price 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, as described in Note 7, Debt and Capital Leases, with the remaining funded from cash on hand. The Company also assumed non-recourse debt of approximately $1.2 billion.

The Company also acquired the competitive retail ~~electric~~electricity business of Dominion, as described in Note 3, Business Acquisitions and Dispositions and in the New and On-going Company Initiatives ~~and Development Projects~~section.

Dividends and Debt Reduction

~~On February 17, 2014, NRG~~The following table lists the dividends paid ~~a quarterly dividend on~~during the ~~Company's common stock of $0.12 per share.~~six months ended June 30, 2014:



	Second Quarter 2014		First Quarter 2014
Dividends per Common Share	$	0.14	$	0.12

On February 10, 2014, the Company redeemed $308 million of its 8.5% 2019 Senior Notes and $91 million of its 7.625% Senior Notes through a tender offer and call, at an average early redemption percentage of 106.992% and 105.500%, respectively, with a portion of the proceeds from the 2022 Senior Notes borrowing.

On April 21, 2014, the Company redeemed $74 million of its 8.5% 2019 Senior Notes and $337 million of its 7.625% Senior Notes through a tender offer and call, at an average early redemption percentage of 105.250% and 104.200%, respectively, with the proceeds from the 2024 Senior Notes borrowing.

On ~~April~~May 21, 2014, ~~NRG gave~~ the ~~required notice to redeem~~Company redeemed for cash all of its remaining 7.625% 2019 Senior Notes at an average early redemption percentage of 103.813%. A $18 million loss on ~~May 21, 2014. The~~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.

on September 3, 2014, at an average early redemption percentage of 104.25%.

Dividends and debt reduction under the ~~2014~~ Capital Allocation Program are subject to market prices, financial restrictions under the Company's debt facilities and securities laws.

6281

Cash Flow Discussion

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


	Three months ended March 31,								Six months ended June 30,
	2014		2013			Change			2014			2013			Change
	(In millions)								(In millions)
Net cash provided/(used) by operating activities	$	391	$	(124	)	$	515		$	370		$	(78	)	$	448
Net cash provided/(used) by investing activities	124		(836		)	960
Net cash used by investing activities									(1,753		)	(1,375		)	(378		)
Net cash provided by financing activities	416		580			(164		)	634			736			(102		)

Net Cash Provided/(Used) By Operating Activities

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


	(In millions)			(In millions)
Increase in operating income adjusted for non-cash items	$	589		$	467
Change in cash paid in support of risk management activities	(176		)	(26		)
Other changes in working capital	102			7
	$	515		$	448

Net Cash ~~Provided/(Used)~~Used By Investing Activities

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


	(In millions)			(In millions)
Decrease in capital expenditures due to decreased spending on maintenance and growth projects.	$	576
Increase in cash paid for acquisitions, primarily related to the EME acquisition				$	(1,778	)
Decrease in capital expenditures due to decreased spending on maintenance and growth projects				774
Increase in proceeds from renewable energy grants	371			381
Increase in cash paid for acquisitions, primarily for the Dominion retail business	(200		)
Proceeds from the sale of assets				77
Decrease in restricted cash	60			62
Proceeds from the sale of assets	77
Proceeds for payment of cash grant bridge loan	57			57
Other	19			49
	$	960		$	(378	)

Net Cash Provided By Financing Activities

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

(In millions)
Net increase in borrowings, primarily due to issuance of 6.25% Senior Notes $ 855
Decrease in financing element of acquired derivatives. (321 )
Net increase in debt payments primarily due to the redemption of Senior Notes (666 )
Cash contributions from noncontrolling interests (20 )
Increase in cash paid for debt issuance costs (16 )
Increase in payment of dividends to common stockholders (10 )
Prior year repurchase of treasury shares, offset by increase in issuance of common shares 14
$ (164 )



	(In millions)
Net increase in borrowings, primarily due to the issuance of the 2022 and 2024 Senior Notes	$	2,414
Net increase in debt payments primarily due to the redemption of 2019 Senior Notes and the repayment of the cash grant bridge loans	(2,153		)
Decrease in financing element of acquired derivatives	(338		)
Cash contributions from noncontrolling interests	(23		)
Increase in cash paid for debt issuance costs	(8		)
Increase in payment of dividends	(18		)
Prior year repurchase of treasury shares, offset by increase in issuance of common shares	24
	$	(102	)

6382

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

For the ~~three~~six months ended ~~March 31,~~June 30, 2014,, the Company had a total domestic pre-tax book loss of ~~$102~~$311 million and foreign pre-tax book income of ~~$4 million. For the~~ ~~three~~ ~~months ended~~ ~~March 31, 2014, the Company utilized domestic NOLs of $9~~$7 million. As of ~~March 31,~~June 30, 2014,, the Company has cumulative domestic NOL carryforwards of $3.1 billion and cumulative state NOL carryforwards of $3.0 billion for financial statement purposes. In addition, NRG has cumulative foreign NOL carryforwards of $76 million, of which $3 million will expire starting 2014 through 2016 and of which $73 million do not have an expiration date.

In addition to these amounts, the Company has ~~$116~~$71 million of tax effected uncertain tax benefits. As a result of the Company's tax position, and based on current forecasts, NRG anticipates income tax payments, primarily to state and local jurisdictions, of up to $40 million in 2014.

However, as the position remains uncertain for the ~~$116~~$71 million of tax effected uncertain tax benefits, the Company has recorded a non-current tax liability of ~~$63~~$68 million and may accrue the remaining balance as an increase to non-current liabilities until final resolution with the related taxing authority. The ~~$63~~$68 million non-current tax liability for uncertain tax benefits is from positions taken on various state income tax returns, including accrued interest.

New and On-going Company Initiatives ~~and Development Projects~~

~~Renewable and Clean Energy Development and Acquisitions~~

As part of its core strategy, NRG intends to continue to own, operate and invest in the development and acquisition of renewable and conventional energy projects. NRG's ~~renewable~~ strategy is intended to capitalize on ~~scale and first mover advantage in a high growth segment of the energy sector and the Company's~~its existing wholesale and retail businesses ~~in states with policies~~as well as address the increasing demand for sustainable and market opportunities conducive to the development of a growing utility scale and distributed solar business. In particular, as the installed cost of new renewable resources continues to decline, the Company intends to target opportunities in markets where alternativelow carbon energy solutions ~~have, or are becoming, increasingly price competitive to system power and~~individualized for the ~~electricity distribution systems have become increasingly susceptible to service disruption as a result~~benefit of ~~among other factors, extreme weather.~~the end use energy customer. This section briefly describes the Company's most notable current ~~activities in renewable development.~~activities.

Solar

NRG has acquired and is developing a number of solar projects utilizing photovoltaic, or PV technology. As of ~~March 31,~~June 30, 2014, NRG had ~~1,186~~1,192 MW of capacity at its commercially operating solar facilities. Below is a summary of recent developments related to solar projects:

Community Solar— In June 2014, NRG Solar Community I LLC completed a 6 MW project located on the grounds of the San Diego State University campus in Brawley, California. The Imperial Irrigation District will purchase all energy generated by the facility, under a 25-year PPA, and sell it at a competitive rate to interested customers through a community solar program.

St. Croix— In March 2014, the Company, through its wholly-owned subsidiary, NRG Solar DG LLC, acquired a 5 MW solar project in the development phase on the island of St. Croix in the U.S. Virgin Islands. NRG, through its subsidiaries, will construct, own and operate the solar project which will sell all of its power output to the Virgin Island Water and Power Authority under a 25-year PPA. The project is expected to achieve full commercial operation in the fourth quarter of 2014.

Guam Solar Project — In 2013, the Company, through its wholly-owned subsidiary, NRG Solar Guam LLC, acquired a 26 MW solar project in the development phase on the island of Guam, a U.S. territory. NRG, through its subsidiaries, will construct, own and operate the solar project which will sell all of its power output to the Guam Power Authority under a 25-year PPA. In the first quarter of 2014, construction continued on the project and is expected to attain full commercial operation in the fourth quarter of 2014.

Distributed Solar — As of ~~March 31,~~June 30, 2014, approximately 53 MWs of ~~distributed solar~~Distributed Solar projects, all of which are supported by long-term PPAs, are in operation or under construction atincluding five National Football League venues as well as other commercial or institutional sites. ~~All~~In the second quarter of 2014, the ~~Company's Distributed Solar projects~~Company began construction of a 6 MW project located on the MGM Mandalay Bay complex in ~~operation or under construction are supported~~Las Vegas, Nevada. The project is expected to be completed by ~~long-term PPAs.~~ the fourth quarter of 2014.

NRG Residential Solar Solutions — On March 27, 2014, the Company acquired one of the nation's leading residential solar companies, Roof Diagnostics Solar, or RDS, now doing business as NRG Home Solar, to support and expand the Company's efforts to empower its customers to control their own energy choices through clean self-generation. The 475 employee company is one of the largest solar sales and installation companies in the United States and has experienced significant growth in the Northeast and is now expanding into California and other areas. RDS will complement NRG's extensive network of independent solar installers and dealers and significantly increase the ability of NRG to meet the growing demand for high quality residential solar services delivered by a market leader in delivering retail electricity services in the home.

~~W.A. Parish Peaking Unit~~Petra Nova Business and Commercial Scale Carbon Capture and Sequestration with Enhanced Oil Recovery

The joint venture also owns a 75 MW peaking unit at W.A. Parish, which achieved commercial operations on June 26, 2013. The peaking unit ~~is expected to~~will be ~~retrofitted for use as~~converted into a cogeneration facility to provide power and steam ~~and power~~ to ~~operate~~ the CCS-EOR. The CCS-EOR ~~which~~ is being ~~partially funded by~~financed by: (i) up to $167 million from a ~~grant from the U.S. DOE.~~

~~Construction of the CCS-EOR is intended to allow NRG, through its wholly owned subsidiary Petra Nova LLC, to utilize the captured CO~~₂ ~~in enhanced oil recovery operations in oil fields on the Texas Gulf Coast. On May 23, 2013, the~~ U.S. DOE ~~published the Record~~CCPI grant of ~~Decision in the Federal Register, announcing its decision to provide cost-shared funding for the project in the amount of $167 million,~~which $7 million ~~of which~~ has already been received from the grant in the initial design and engineering phase, (ii) $250 million in loans provided by ~~NRG as~~the Japan Bank for International Cooperation and Mizuho Bank, Ltd., and (iii) approximately $300 million in equity contributions from each of ~~March 31, 2014.~~

~~Furthering NRG’s efforts to commercialize post-combustion carbon capture at its WA Parish plant,~~ the Company ~~began preliminary engineering~~ and ~~procurement activities in March 2014. Construction~~JX Nippon. The Company’s contribution will include investments already made during the development of the project.

The joint venture between the Company and JX Nippon also owns a 50% equity interest in Texas Coastal Ventures, LLC, which is jointly owned with Hilcorp Energy I, L.P. Texas Coastal Ventures, LLC holds the working interests in the West Ranch oilfield in Jackson County, Texas. CO2 captured by the CCS-EOR ~~project remains subject~~will be compressed and piped through an 82-mile long pipeline owned by Texas Coastal Ventures to ~~receipt of appropriate financing and negotiation of material contracts.~~the West Ranch oilfield for enhanced oil recovery operations.

Gas-To-Liquids Joint Venture

On March 24, 2014, NRG GTL Holdings LLC, a wholly owned subsidiary of NRG, entered into an agreement with Waste Management, Inc., Ventech Engineers International LLC and Velocys plc to form a joint venture to produce renewable fuels and chemicals from biogas and natural gas using smaller-scale gas-to-liquids, or GTL, technology.

The joint venture’s first facility is under development and will be located at Waste Management’s East Oak site in Oklahoma. Engineering and design work for this project is substantially complete, ~~final draft~~and material permitting documents necessary to commence construction have been ~~submitted,~~obtained. The Company's expected capital commitment for the first project is approximately $20 million.

Aspen Biomass Facility

In June 2014, NRG Energy Services LLC, a wholly-owned subsidiary of the Company, entered into an agreement with InventivEnergy, LLC to restart the 50 MW Aspen Power biomass plant in Lufkin, Texas, and ~~development activities for additional facilities are expected~~operate and maintain the facility once online to ~~commence~~provide clean, renewable power to the ERCOT market. InventivEnergy is the asset management firm overseeing the plant, which is the first clean wood-waste biomass power plant in ~~2014.~~the state.

Electric Vehicle Infrastructure Development

NRG, through its subsidiary NRG eVgo, continues to build out and operate electric vehicle, or EV, ecosystems in the San Francisco Bay Area, Los Angeles, San Diego, Washington, DC/Baltimore, Houston and the Dallas/Fort Worth Metroplex. NRG eVgo is the first company to equip major markets with privately funded infrastructure needed for successful EV adoption and integration. As of ~~March 31,~~June 30, 2014, NRG eVgo had 7291 public fast charging Freedom Station sites operational in its metro areas. NRG eVgo has an additional 3028 sites in its metro areas under construction or in permitting. NRG eVgo offers consumers a subscription-based plan that provides for all charging requirements for EVs at a competitive monthly fee. NRG eVgo achieved billable network status (the number of public charging stations that allows eVgo to bill customers for use of the charging network) in Texas in 2012, in San Francisco, San Diego, and Washington in the first quarter of 2014, and ~~is on track to achieve billable network status~~ in Los Angeles byin the second quarter of 2014.

~~During~~

In the third quarter of 2014, NRG eVgo expects to ~~initiate~~support Nissan’s expansion of its "No Charge to Charge" program, which provides Nissan customers with two years of no-cost public charging with the purchase or lease of a new Nissan LEAF, on its EZ-Charge (SM) program. The EZ-Charge (SM) program is a first-of-its-kind initiative that will offer EVLEAF drivers ~~the ability to access multiple EV charging networks with a single all-access card. The EZ-Charge platform will enable drivers of any electric car make or model~~ to carry a single access card for charging on multiple networks and will support all eVgo public charging plans as well as enable EV drivers to enroll in participating partner network plans ~~either~~ through their charging ~~company or directly with NRG eVgo.~~company. NRG eVgo expects to begin distributing EZ-Charge cards ~~this summer~~in July to ~~EV drivers with~~LEAF buyers at participating ~~plans~~dealerships in San Francisco, San Diego, Dallas-Ft. Worth, Houston, Sacramento, Seattle, Portland, OR, Nashville, Phoenix and Washington, D.C. EZ-Charge access will be available for all automakers to package with their EVs, with its first industry promotion as part of Nissan’s expansion of its "No Charge to Charge" program, which provides Nissan customers with two years of no-cost public charging with the purchase or lease of a new Nissan LEAF.

In addition, as part of a legal settlement, NRG eVgo has an agreement with the California Public Utilities Commission to build at least 200 public fast charging Freedom Station sites and wiring and associated work to prepare 10,000 commercial and multi-family parking spaces for electric vehicle charging in California by the end of 2016.

Fuel Conversions

~~Conventional Power Development and Acquisitions~~

~~Operational Improvement Activities~~

NRG intends to continue operations at the Avon Lake facility Units 7 and 9 and the New Castle ~~facilities,~~facility Units 3, 4, and 5, which are currently ~~in operation and~~operating coal units that had been scheduled for deactivation in April 2015. NRG intends to add natural gas capabilities at these ~~facilities,~~units, which isadditions are expected to be completed by the summer of 2016. The Company also expects to convert Big Cajun II, Unit 2 to natural gas capabilities by spring of 2015 as part of its environmental capital expenditures program. In late April 2014, NRG notified PJM that it no longer intends to place coal-fired Units 1, 2, 3, and 4 at Shawville generating facility (597 MW) in long term protective layup, but instead will mothball those units beginning on April 16, 2015, and then return those units to service no later than June 1, 2016 using natural gas. NRG intends to convert Units 6, 7 and 8 of the Joliet coal facility to run on natural gas no later than June 2016.

In December 2013, the New York Governor announced a deal under which the Company and National Grid expect to negotiate a contract to add natural gas to the Dunkirk facility to enable Units 2, 3 and 4 to operate on natural gas. Unit 1 will remain mothballed. The Company and National Grid agreed to the material terms of a ten-year contract, and those terms were ~~filed with~~approved by the ~~NYPSC~~NYSPSC on ~~February~~June 13, 2014. The agreement will commence when the first of three Dunkirk Units supplies power into the grid while operating on natural gas, expected in late 2015.

In late April 2014, NRG notified PJM that it no longer intends to deactivate Portland Units 1 and 2 (401 MW), but instead mothballed those units effective June 1, 2014, and will return those units to service no later than June 1, 2016 using ultra-low sulfur diesel.

Retail Growth Initiatives

On March 31, 2014, the Company acquired the competitive retail ~~electric~~electricity business of Dominion Resources, Inc., or Dominion, as described in Note 3, Business Acquisitions and Dispositions. The acquisition of Dominion's competitive retail electricity business increased NRG’s retail portfolio by approximately 217,000 customers as of June 30, 2014, and is expected to ~~add~~increase NRG’s retail portfolio by approximately 500,000 customers in ~~Connecticut, Illinois, Maryland, Massachusetts, New Jersey, New York, Ohio, Pennsylvania and Texas, after customary transitions, to NRG's retail portfolio~~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 leading retail position in Texas and will give its customers more options to improve their ability to understand and control their use of energy. The Company paid approximately $195 million as cash consideration for the acquisition, including $165 million of purchase price and $30 million paid for working capital balances, which was funded by cash on hand.

The Retail Business continues to grow customer count and innovate products and services that help change the way consumers and businesses think about and use energy. In addition, the Company has initiated a rebranding effort that is intended to establish NRG as leading customer-facing energy provider, which began with the renaming of Reliant Park in Houston, Texas to NRG Park.

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 3.625% Preferred Stock includes a feature which is considered an embedded derivative ~~per~~in accordance with ASC 815. Although it is considered an embedded derivative, it is exempt from derivative accounting as it is excluded from the scope pursuant to ASC 815. As of ~~March 31,~~June 30, 2014, based on the Company's stock price, the embedded derivative was ~~out-of-the-money~~in-the-money and had noa redemption ~~value.~~value of $74 million.

Obligations Arising Out of a Variable Interest in an Unconsolidated Entity

Variable interest in equity investments — As of ~~March 31,~~June 30, 2014, 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 ~~$270~~$264 million as of ~~March 31,~~June 30, 2014. 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 2013 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 2013 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 three months ended ~~March 31,~~June 30, 2014.

Fair Value of Derivative Instruments

NRG may enter into long-term 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 2013 Form 10‑K.

The tables below disclose the activities that include both exchange and non-exchange traded contracts accounted for at fair value in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820. Specifically, these tables disaggregate realized and unrealized changes in fair value; disaggregate estimated fair values at ~~March 31,~~June 30, 2014, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at ~~March 31,~~June 30, 2014.


Derivative Activity Gains/(Losses)	(In millions)			(In millions)
Fair value of contracts as of December 31, 2013	$	389		$	389
Contracts realized or otherwise settled during the period	(70		)	(172		)
Contracts acquired during the period	20			40
Changes in fair value	(194		)	(233		)
Fair value of contracts as of March 31, 2014	$	145
Fair value of contracts as of June 30, 2014				$	24


	Fair Value of Contracts as of March 31, 2014												Fair Value of Contracts as of June 30, 2014
Fair value hierarchy Gains/(Losses)	Maturity Less Than 1 Year		Maturity 1-3 Years			Maturity 3-5 Years			Maturity in Excess 5 Years		Total Fair Value		Maturity Less Than 1 Year			Maturity 1-3 Years			Maturity 3-5 Years			Maturity in Excess 5 Years		Total Fair Value
	(In millions)												(In millions)
Level 1	$	34	$	68		$	7		$	—	$	109	$	—		$	75		$	5		$	—	$	80
Level 2	15		(24		)	(3		)	25		13		(16		)	(35		)	(17		)	24		(44		)
Level 3	20		3			—			—		23		(19		)	7			—			—		(12		)
Total	$	69	$	47		$	4		$	25	$	145	$	(35	)	$	47		$	(12	)	$	24	$	24

The Company has elected to present derivative assets and liabilities on a trade-by-trade basis and does not offset amounts at the counterparty master agreement level. Also, collateral received or paid on the Company's derivative assets or liabilities are recorded on a separate line item on the balance sheet. Consequently, the magnitude of the changes in individual current and non-current derivative assets or liabilities is higher than the underlying credit and market risk of the Company's portfolio. As discussed in Item 3 - Quantitative and Qualitative Disclosures About Market Risk, Commodity Price Risk, to this Form 10-Q, NRG measures the sensitivity of the Company's portfolio to potential changes in market prices using VaR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG's risk management policy places a limit on one-day holding period VaR, which limits the Company's net open position. As the Company's trade-by-trade derivative accounting results in a gross-up of the Company's derivative assets and liabilities, the net derivative asset and liability position is a better indicator of NRG's hedging activity. As of ~~March 31,~~June 30, 2014, NRG's net derivative asset was $~~145~~24 million, a decrease to total fair value of ~~$244~~$365 million as compared to December 31, 2013. This decrease was driven by the roll-off of trades that settled during the period and losses in fair value, slightly offset by contracts acquired during the period.

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 ~~$265~~$376 million in the net value of derivatives as of ~~March 31,~~June 30, 2014. 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 ~~$237~~$348 million in the net value of derivatives as of ~~March 31,~~June 30, 2014.

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.

6987

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 2013 Form 10-K.

Commodity Price Risk

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

The following table summarizes average, maximum and minimum VaR for NRG's commodity portfolio, including generation assets, load obligations and bilateral physical and financial transactions, calculated using the VaR model for the three and six months ending ~~March 31,~~June 30, 2014, and 2013:


(In millions)	2014		2013		2014		2013
VaR as of March 31,	$	78	$	89
Three months ended March 31,
VaR as of June 30,					$	105	$	88
Three months ended June 30,
Average	$	88	$	97	$	112	$	86
Maximum	142		104		126		95
Minimum	73		89		97		77
Six months ended June 30,
Average					$	100	$	92
Maximum					142		104
Minimum					73		77

In order to provide additional information for comparative purposes to NRG's peers, the Company also uses VaR to estimate the potential loss of derivative financial instruments that are subject to mark-to-market accounting. These derivative instruments include transactions that were entered into for both asset management and trading purposes. The VaR for the derivative financial instruments calculated using the diversified VaR model as of ~~March 31,~~June 30, 2014 for the entire term of these instruments entered into for both asset management and trading was ~~$41~~$60 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 2013 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 ~~March 31,~~June 30, 2014, the Company would have owed the counterparties $57138 million. Based on the investment grade rating of the counterparties, NRG believes its exposure to credit risk due to nonperformance by counterparties to its hedge contracts to be insignificant.

NRG has both long and short-term debt instruments that subject the Company to the risk of loss associated with movements in market interest rates. As of ~~March 31,~~June 30, 2014, a 1% change in variable interest rates would result in a $23 million change in interest expense on a rolling twelve month basis.

As of ~~March 31,~~June 30, 2014, the fair value of the Company's debt was $~~17.6~~19.6 billion and the related carrying amount was $~~17.5~~19.0 billion. NRG estimates that a 1% decrease in market interest rates would have increased the fair value of the Company's long-term debt by $~~1.4~~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 $~~216~~282 million as of ~~March 31,~~June 30, 2014, and a 1 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral posted of approximately $~~173~~211 million as of ~~March 31,~~June 30, 2014. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of ~~March 31,~~June 30, 2014.

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.

7189

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 report on Form 10-Q.

Changes in Internal Control over Financial Reporting

~~There were no changes in NRG’s~~NRG continues to integrate certain business operations, information systems, processes and related internal control over financial reporting ~~(as such term is defined in Rule 13a-15(f) under~~as a result of business acquisitions. NRG will continue to assess the ~~Exchange Act) that occurred in the first quarter~~effectiveness of ~~2014 that materially affected, or are reasonably likely to materially affect, NRG’s~~its internal control over financial ~~reporting.~~reporting as integration activities continue.

7290

��

PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

For a discussion of material legal proceedings in which NRG was involved through ~~March 31,~~June 30, 2014, 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 2013 Form 10-K. There have been no material changes in the Company's risk factors since those reported in its 2013 Form 10‑K.

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

None.

ITEM 3 — DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4 — MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5 — OTHER INFORMATION

None.

7391

ITEM 6 — EXHIBITS



Number	Description	Method of Filing
4.1	~~One Hundred-Ninth Supplemental~~ Indenture, dated as of ~~January 27,~~April 21, 2014, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York as ~~Trustee, re: NRG Energy's 6.25% Senior Notes due 2022.~~Trustee.	Incorporated herein by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on ~~January 27,~~April 21, 2014.
4.2	Form of 6.25% Senior Note due ~~2022.~~2024.	Incorporated herein by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K filed on ~~January 27,~~April 21, 2014.
4.3	Registration Rights Agreement, dated ~~January 27,~~April 21, 2014, among NRG Energy, Inc., the guarantors named therein and ~~Barclays Capital~~Citigroup Global Markets Inc., ~~Deutsche Bank~~Merrill Lynch, Pierce, Fenner & Smith Incorporated, Credit Suisse Securities (USA), Inc., ~~Goldman, Sachs & Co.,~~J.P. Morgan ~~Stanley & Co.~~Securities LLC, ~~Credit Agricole~~Mitsubishi UFJ Securities (USA), Inc., ~~Natixis~~SMBC Nikko Securities ~~Americas LLC~~America, Inc. and ~~RBC Capital Markets, LLC, as initial purchasers.~~RBS Securities Inc.	Incorporated herein by reference to Exhibit 4.3 to the Company's Current Report on Form 8-K filed on ~~January 27,~~April 21, 2014.
4.4	One ~~Hundred-Tenth~~Hundred Eleventh Supplemental Indenture, dated as of ~~March 24,~~April 28, 2014, 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 ~~March 24,~~May 2, 2014.
4.5	First Supplemental Indenture, dated as of April 28, 2014, 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 2, 2014.
10.1	Amended and Restated Employee Stock Purchase Plan	Filed herewith
31.1	Rule 13a-14(a)/15d-14(a) certification of David W. 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 Ronald B. Stark	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

7492

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 W. CRANE
	David W. Crane
	Chief Executive Officer (Principal Executive Officer)


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


	/s/ RONALD B. STARK
	Ronald B. Stark
Date: ~~May 6,~~August 7, 2014	Chief Accounting Officer (Principal Accounting Officer)

7593



	EME Fossil Fuel and Renewable
	(In MW)
	East		West ^(a)	Alternative Energy		Total Domestic	Other (Inter-national)	Total Global
Primary Fuel-type
Natural gas	—		1,476	—		1,476	144	1,620
Coal	4,394		—	—		4,394	—	4,394
Oil	305		—	—		305	—	305
Wind	—		—	1,724		1,724	—	1,724
Total generation capacity	4,699		1,476	1,724		7,899	144	8,043
Capacity attributable to noncontrolling interest	(40	)	—	(299	)	—	—	(339	)
Total net generation capacity	4,659		1,476	1,425		7,899	144	7,704



Texas region	(8		)
East region	336
South Central region	33
West region	30
Other ^(a)	2
	$	393



Lower gross margin from a decrease in average realized prices	$	(71	)
Higher gross margin from a 73% increase in nuclear generation driven by fewer outage hours in 2014	25
Change in commercial optimization activities	20
Higher gross margin from a 9% increase in coal generation driven by higher economic dispatch offset in part by additional outage hours in 2014	11
Higher gross margin due to the acquisition of Gregory in August 2013	11
Other	(4		)
	$	(8	)



Higher gross margin due to a 56% increase in realized energy prices, partially offset by an increase in fuel prices	$	202
Higher gross margin due to a 39% increase in generation due to weather conditions in 2014	52
Higher revenue due primarily to a 32% increase in New York and PJM hedged capacity prices	88
Other	(6		)
	$	336



Higher gross margin due to revenues from Resource Adequacy contracts in California, partially offset by the deactivation of the Contra Costa facility in 2013	$	14
Increase in capacity revenue due to El Segundo Energy Center reaching COD in 2013	24
Lower gross margin due to a 59% decrease in generation primarily due to increased dispatch from competing resources, including renewable resources.	(10		)
Other	2
	$	30



Increase in Texas operations and maintenance expense	$	20
Increase in Alternative Energy and NRG Yield operations and maintenance expense	13
Increase in property tax expense	11
Other	(10		)
	$	34



Three months ending:	Cash due and payable
	(In millions)
June 30, 2014	$	201
December 31, 2014	117
March 31, 2015	132
Total cash grant bridge loans due, including interest accrued to principal	$	450

Large accelerated filer x

Accelerated filer o

Non-accelerated filer o

Smaller reporting company o

(Do not check if a smaller reporting company)