Edgar Filing: NRG ENERGY, INC.

Large accelerated filer x

Accelerated filer o

Non-accelerated filer o

Smaller reporting company o

(Do not check if a smaller reporting company)

NRG 2014 09.30 10Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



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

		For the Quarterly Period Ended: September 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 October 31, 2014, there were 338,108,633 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	7
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES	7
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	58
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	91
ITEM 4 — CONTROLS AND PROCEDURES	93
PART II — OTHER INFORMATION	94
ITEM 1 — LEGAL PROCEEDINGS	94
ITEM 1A — RISK FACTORS	94
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	94
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES	94
ITEM 4 — MINE SAFETY DISCLOSURES	94
ITEM 5 — OTHER INFORMATION	94
ITEM 6 — EXHIBITS	95
SIGNATURES	96

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
BTU		British Thermal Unit
CAIR		Clean Air Interstate Rule
CAISO		California Independent System Operator
Capital Allocation Program		NRG's plan of allocating capital between debt reduction, reinvestment in the business, investment in acquisition opportunities, share repurchases and shareholder dividends
CCF		Carbon Capture Facility
CCPI		Clean Coal Power Initiative
CenterPoint		CenterPoint Energy, Inc. and its subsidiaries, on and after August 31, 2002, and Reliant Energy, Incorporated and its subsidiaries prior to August 31, 2002
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 that primarily sell power produced to customers for usage on site, or are interconnected to sell power into the local distribution grid
Dodd-Frank Act		The Dodd-Frank Wall Street Reform and Consumer Protection Act
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 8.50% 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 $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
Goal Zero		Goal Zero LLC
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
Kansas South		NRG Solar Kansas South LLC
kWh		Kilowatt-hours
LaGen		Louisiana Generating LLC
LIBOR		London Inter-Bank Offered Rate
LDEQ		Louisiana Department of Environmental Quality
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
Midwest Generation		Midwest Generation, LLC
MISO		Midcontinent Independent System Operator, Inc.
MMBtu		Million British Thermal Units
MVA		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
NOL		Net Operating Loss
NOV		Notice of Violation
NO_x		Nitrogen oxide
NPNS		Normal Purchase Normal Sale
NRC		U.S. Nuclear Regulatory Commission
NRG Yield		Reporting segment including the following projects: Alpine, Alta Wind, 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 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
Pure Energies		Pure Energies Group Inc.
Reliant Energy		Reliant Energy Retail Services, LLC
REMA		NRG REMA LLC (formerly known as GenOn REMA, 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, Goal Zero 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
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 billion outstanding unsecured senior notes, consisting of $1.1 billion of 7.625% senior notes due 2018, $1.1 billion of 8.25% senior notes due 2020, $1.1 billion of 7.875% senior notes due 2021, $1.1 billion of 6.25% senior notes due 2022, $990 million of 6.625% senior notes due 2023, and $1.0 billion of 6.25% senior notes due 2024
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, to commercial businesses, universities, hospitals and governmental units
U.S.		United States of America
U.S. DOE		U.S. Department of Energy
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 September 30,						Nine months ended September 30,
(In millions, except for per share amounts)	2014			2013			2014			2013
Operating Revenues
Total operating revenues	$	4,569		$	3,490		$	11,676		$	8,500
Operating Costs and Expenses
Cost of operations	3,278			2,373			8,828			6,177
Depreciation and amortization	375			327			1,096			947
Impairment losses	70			—			70			—
Selling, general and administrative	258			213			752			670
Acquisition-related transaction and integration costs	17			26			69			95
Development activity expenses	22			24			62			63
Total operating costs and expenses	4,020			2,963			10,877			7,952
Gain on sale of assets	—			—			19			—
Operating Income	549			527			818			548
Other Income/(Expense)
Equity in earnings/(loss) of unconsolidated affiliates	18			(5		)	39			6
Other (expense)/income, net	(3		)	5			13			9
Loss on debt extinguishment	(13		)	(1		)	(94		)	(50		)
Interest expense	(280		)	(228		)	(809		)	(630		)
Total other expense	(278		)	(229		)	(851		)	(665		)
Income/(Loss) Before Income Taxes	271			298			(33		)	(117		)
Income tax expense/(benefit)	89			160			(68		)	(55		)
Net Income/(Loss)	182			138			35			(62		)
Less: Net income attributable to noncontrolling interest	14			19			20			27
Net Income/(Loss) Attributable to NRG Energy, Inc.	168			119			15			(89		)
Dividends for preferred shares	2			2			7			7
Income/(Loss) Available for Common Stockholders	$	166		$	117		$	8		$	(96	)
Earnings/(Loss) Per Share Attributable to NRG Energy, Inc. Common Stockholders
Weighted average number of common shares outstanding — basic	338			323			333			323
Earnings/(Loss) per Weighted Average Common Share — Basic	$	0.49		$	0.36		$	0.02		$	(0.30	)
Weighted average number of common shares outstanding — diluted	343			327			338			323
Earnings/(Loss) per Weighted Average Common Share — Diluted	$	0.48		$	0.36		$	0.02		$	(0.30	)
Dividends Per Common Share	$	0.14		$	0.12		$	0.40		$	0.33

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

(Unaudited)



	Three months ended September 30,						Nine months ended September 30,
	2014			2013			2014			2013
	(In millions)
Net Income/(Loss)	$	182		$	138		$	35		$	(62	)
Other Comprehensive (Loss)/Income, net of tax
Unrealized gain/(loss) on derivatives, net of income tax expense/(benefit) of $4, $(5), $(11), and $(2)	4			(16		)	(24		)	8
Foreign currency translation adjustments, net of income tax benefit of $(6), $(1), $(2), and $(13)	(6		)	5			(3		)	(14		)
Available-for-sale securities, net of income tax (benefit)/expense of $(1), $0, $0, and $1	(2		)	—			2			2
Defined benefit plans, net of tax expense/(benefit) of $0, $0, $(7), and $4	(3		)	—			9			25
Other comprehensive (loss)/income	(7		)	(11		)	(16		)	21
Comprehensive Income/(Loss)	175			127			19			(41		)
Less: Comprehensive income attributable to noncontrolling interest	17			18			14			26
Comprehensive Income/(Loss) Attributable to NRG Energy, Inc.	158			109			5			(67		)
Dividends for preferred shares	2			2			7			7
Comprehensive Income/(Loss) Available for Common Stockholders	$	156		$	107		$	(2	)	$	(74	)

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS



	September 30, 2014			December 31, 2013
(In millions, except shares)	(unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	1,953		$	2,254
Funds deposited by counterparties	3			63
Restricted cash	339			268
Accounts receivable — trade, less allowance for doubtful accounts of $27 and $40	1,554			1,214
Inventory	1,051			898
Derivative instruments	1,397			1,328
Cash collateral paid in support of energy risk management activities	375			276
Deferred income taxes	79			258
Renewable energy grant receivable, net	614			539
Current assets held-for-sale	32			19
Prepayments and other current assets	475			479
Total current assets	7,872			7,596
Property, plant and equipment, net of accumulated depreciation of $7,584 and $6,573	22,181			19,851
Other Assets
Equity investments in affiliates	797			453
Notes receivable, less current portion	80			73
Goodwill	2,452			1,985
Intangible assets, net of accumulated amortization of $1,333 and $1,977	2,880			1,140
Nuclear decommissioning trust fund	569			551
Derivative instruments	427			311
Deferred income taxes	1,476			1,202
Non-current assets held-for-sale	54			—
Other non-current assets	1,281			740
Total other assets	10,016			6,455
Total Assets	$	40,069		$	33,902
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	854		$	1,050
Accounts payable	1,098			1,038
Derivative instruments	1,365			1,055
Cash collateral received in support of energy risk management activities	3			63
Current liabilities held-for-sale	23			—
Accrued expenses and other current liabilities	1,200			998
Total current liabilities	4,543			4,204
Other Liabilities
Long-term debt and capital leases	19,919			15,767
Nuclear decommissioning reserve	306			294
Nuclear decommissioning trust liability	323			324
Deferred income taxes	24			22
Derivative instruments	326			195
Out-of-market contracts	1,245			1,177
Non-current liabilities held-for-sale	31			—
Other non-current liabilities	1,385			1,201
Total non-current liabilities	23,559			18,980
Total Liabilities	28,102			23,184
3.625% convertible perpetual preferred stock (at liquidation value, net of issuance costs)	249			249
Redeemable noncontrolling interest in subsidiaries	28			2
Commitments and Contingencies
Stockholders’ Equity
Common stock	4			4
Additional paid-in capital	8,314			7,840
Retained earnings	3,564			3,695
Less treasury stock, at cost — 77,219,145 and 77,347,528 shares, respectively	(1,939		)	(1,942		)
Accumulated other comprehensive (loss)/income	(5		)	5
Noncontrolling interest	1,752			865
Total Stockholders’ Equity	11,690			10,467
Total Liabilities and Stockholders’ Equity	$	40,069		$	33,902

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Nine months ended September 30,
	2014			2013
	(In millions)
Cash Flows from Operating Activities
Net Income/(loss)	$	35		$	(62	)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities:
Distributions and equity in earnings of unconsolidated affiliates	32			23
Depreciation and amortization	1,096			947
Provision for bad debts	49			49
Amortization of nuclear fuel	33			27
Amortization of financing costs and debt discount/premiums	(9		)	(22		)
Adjustment for debt extinguishment	24			(15		)
Amortization of intangibles and out-of-market contracts	52			75
Amortization of unearned equity compensation	32			32
Changes in deferred income taxes and liability for uncertain tax benefits	(75		)	39
Changes in nuclear decommissioning trust liability	12			25
Changes in derivative instruments	248			189
Changes in collateral deposits supporting energy risk management activities	(100		)	(59		)
Loss/(gain) on sale of emission allowances	2			(8		)
Gain on sale of assets	(26		)	—
Impairment losses	70			—
Cash used by changes in other working capital	(361		)	(417		)
Net Cash Provided by Operating Activities	1,114			823
Cash Flows from Investing Activities
Acquisitions of businesses, net of cash acquired	(2,832		)	(374		)
Capital expenditures	(675		)	(1,581		)
Increase in restricted cash, net	(52		)	(67		)
Decrease/(increase) in restricted cash to support equity requirements for U.S. DOE funded projects	21			(20		)
Decrease/(increase) in notes receivable	21			(22		)
Investments in nuclear decommissioning trust fund securities	(475		)	(369		)
Proceeds from sales of nuclear decommissioning trust fund securities	463			344
Proceeds from renewable energy grants	431			52
Proceeds from sale of assets, net of cash disposed of	153			13
Cash proceeds to fund cash grant bridge loan payment	57			—
Other	(70		)	(7		)
Net Cash Used by Investing Activities	(2,958		)	(2,031		)
Cash Flows from Financing Activities
Payment of dividends to common and preferred stockholders	(140		)	(113		)
Payment for treasury stock	—			(25		)
Net (payments for)/receipts from settlement of acquired derivatives that include financing elements	(64		)	177
Proceeds from issuance of long-term debt	4,456			1,605
Contributions and sale proceeds from noncontrolling interest in subsidiaries	639			504
Proceeds from issuance of common stock	15			14
Payment of debt issuance costs	(57		)	(43		)
Payments for short and long-term debt	(3,308		)	(868		)
Net Cash Provided by Financing Activities	1,541			1,251
Effect of exchange rate changes on cash and cash equivalents	2			(1		)
Net (Decrease)/Increase in Cash and Cash Equivalents	(301		)	42
Cash and Cash Equivalents at Beginning of Period	2,254			2,087
Cash and Cash Equivalents at End of Period	$	1,953		$	2,129

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 — Basis of Presentation

NRG Energy, Inc., or NRG or the Company, is a competitive power company that produces, sells and delivers energy and energy services in major competitive power markets in the U.S. while positioning itself as a leader in the way residential, industrial and commercial consumers think about and use energy products and services. As one of the largest power generators in the U.S., the Company owns and operates approximately 53,000 MWs of generation; engages in the trading of wholesale energy, capacity and related products around those generation assets; transacts in and trades fuel and transportation services; and directly sells energy, services, and innovative, sustainable products and services to retail customers under the name “NRG” and various other retail brand names owned by NRG.

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 September 30, 2014, and the results of operations, comprehensive loss and cash flows for the three and nine months ended September 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 year 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 $148 million which were accrued and unpaid at September 30, 2014.

Noncontrolling Interest

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



	(In millions)
Balance as of December 31, 2013	$	865
Acquisition of EME	353
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	(75		)
Contributions from NRG Yield, Inc. public offering	630
Contributions from noncontrolling interest	20
Distributions to noncontrolling interest	(37		)
Comprehensive income attributable to noncontrolling interest	14
Balance as of September 30, 2014	$	1,752

As described in Note 3, Business Acquisitions and Dispositions, in order to fund the purchase price of the Alta Wind Assets 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. NRG Yield, Inc. utilized the proceeds of the offering to acquire additional units of NRG Yield LLC. Following the offering, the Company owned 55.3% of NRG Yield LLC and as a result continues to consolidate NRG Yield, Inc. through its controlling interest. The contributions are reflected as an increase to the Company's noncontrolling interest balance.

Cash Proceeds from Wind Tax Equity Arrangement

On November 3, 2014, the Company sold an economic interest in a portfolio of wind assets for gross proceeds of approximately $195 million, in order to monetize cash and tax benefits associated with the projects. The Company will continue to manage the portfolio of wind assets, which were primarily acquired in connection with the acquisition of EME, and will continue to consolidate the assets, with the contributions presented as noncontrolling interests in the Company’s consolidated balance sheet.

Impairment Losses

During the three months ended September 30, 2014, the Company determined that it will pursue mothballing the 463 MW natural gas-fired Osceola facility, in Saint Cloud, Florida. The Company considered this to be an indicator of impairment and performed an impairment test for these assets under ASC 360, Property, Plant and Equipment. The carrying amount of the assets was lower than the future net cash flows expected to be generated by the assets and as a result, the assets are considered to be impaired. The Company measured the impairment loss as the difference between the carrying amount and the fair value of the assets. Due to the location of the facility, it was determined that the best indicator of fair value is the market value of the combustion turbines. The Company recorded an impairment loss of approximately $60 million, which represents the excess of the carrying value over the fair market value. In addition, during the three months ended September 30, 2014, the Company recorded an impairment loss of $10 million to reduce the carrying value of certain solar panels to their approximate fair value.

Assets and Liabilities Held for Sale

During the three months ended September 30, 2014, the Company entered into separate agreements to sell its 50% interest in Sabine Cogen, L.P. and its 50% interest in the American Bituminous Power Partners, L.P. waste coal facility. These transactions are expected to close in the fourth quarter of 2014. As a result, the Company has classified the related assets and liabilities as "held-for-sale" in the consolidated balance sheet as of September 30, 2014.

Redeemable Noncontrolling Interest in Subsidiaries

Redeemable noncontrolling interest in subsidiaries represent third-party interests in the net assets under certain arrangements that the Company has entered into to finance the cost of solar energy systems under operating leases. To the extent that the third-party has the right to redeem their interests for cash or other assets, the Company has included the noncontrolling interest attributable to the third party as a component of temporary equity in the mezzanine section of the consolidated balance sheet.

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 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 on the Company's results of operations, cash flows and 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 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 NOLs or the NOLs are limited for that particular jurisdiction.

Note 3 — Business Acquisitions and Dispositions

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

Acquisition of Alta Wind

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

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

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



	(In millions)
Assets
Cash	$	22
Current and non-current assets	49
Property, plant and equipment	1,057
Intangible assets	1,420
Total assets acquired	2,548

Liabilities
Debt	1,591
Current and non-current liabilities	34
Total liabilities assumed	1,625
Net assets acquired	$	923

Fair value measurements

The provisional fair values of the property, plant and equipment and intangible assets 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 cost approach based on the replacement cost of the assets less economic obsolescence. The income approach was applied by determining the enterprise value for each acquired entity and subtracting the fair value of the intangible assets and working capital to determine the implied value of the tangible fixed assets. This methodology was primarily relied upon as the forecasted cash flows incorporate the specific attributes of each asset including age, useful life, equipment condition and technology. The income approach also allows for an accurate reflection of current and expected market dynamics such as supply and demand and regulatory environment as of the acquisition date.

Intangible assets — The fair values of the PPAs acquired were determined utilizing a variation of the income approach where the incremental future cash flows resulting from the acquired PPAs compared to the cash flows based on current market prices were discounted to present value at the weighted average cost of debt of the utility off-taker, as the PPA was determined to be a debt-like instrument for the off-taker. The values were corroborated with available market data. The PPA values will be amortized over an average period of 22 years.

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

Petra Nova Parish Holdings LLC also owns a 75 MW peaking unit at W.A. Parish, which achieved commercial operations on June 26, 2013. The peaking unit will be converted into a cogeneration facility to provide power and steam to the CCF. The CCF 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 and $26 million has already been received from the grant under the construction 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 CCF 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 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 CCF. Both credit facilities mature in April 2026. NRG has guaranteed its 50% share of the obligations under the Petra Nova Parish Credit Agreements through mechanical completion as defined by the credit agreements.

Sales of Assets to NRG Yield, Inc.

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

Acquisition of Dominion's Competitive Electric Retail Business

On March 31, 2014, the Company acquired the competitive retail electricity business of Dominion Resources, Inc., or Dominion. The acquisition of Dominion's competitive retail electricity business is expected to increase NRG’s retail portfolio by approximately 540,000 customers in the aggregate by the end of 2014. The acquisition supports NRG's ongoing efforts to expand the Company's retail footprint in the Northeast and to grow its retail position in Texas. The Company paid approximately $192 million as cash consideration for the acquisition, including $165 million of purchase price and $27 million paid for working capital balances, which was funded by cash on hand. The purchase price was provisionally allocated to the following: $40 million to accounts receivable-trade, $62 million to customer relationships, $9 million to trade names, $14 million to current assets, $21 million to derivative assets, $45 million to current and non-current liabilities, and goodwill of $91 million of which $8 million is deductible for U.S. income tax purposes in future periods. The factors that resulted in goodwill arising from the acquisition include the revenues associated with new customers in new regions and through the synergies associated with combining a new retail business with the Company's 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 EME. EME, through its subsidiaries and affiliates, owned or leased and operated a portfolio of approximately 8,000 MW consisting of wind energy facilities and coal- and gas-fired generating facilities. The Company paid an aggregate purchase price of $3.5 billion, which was comprised of the following:



	Original Purchase Price		Purchase Price on Acquisition Date
Cash and equivalents^(a)	$	2,285	$	3,016
Common shares ^(b)	350		401
Liabilities acquired	—		57
Total purchase price	2,635		3,474
Less: cash acquired			1,422
Net purchase price			$	2,052

(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 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 Power Holdings Inc. 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 Power Holdings Inc.

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 $3.5 billion was provisionally allocated as follows:



	Acquisition Date		Measurement period adjustments			Revised Acquisition Date
	(In millions)
Assets
Cash	1,422		—			$	1,422
Current assets	676		(8		)	668
Property, plant and equipment	2,475		(144		)	2,331
Intangible assets	312		11			323
Goodwill	—		200			200
Non-current assets	813		18			831
Total assets acquired	5,698		77			5,775

Liabilities
Current and non-current liabilities	533		25			558
Out-of-market contracts and leases	43		98			141
Long-term debt	1,249		—			1,249
Total liabilities assumed	1,825		123			1,948
Less: noncontrolling interest	380		(27		)	353
Net assets acquired	$	3,493	$	(19	)	$	3,474

The Company incurred and expensed acquisition-related transaction costs related to the acquisition of EME of $17 million for the nine months ended September 30, 2014. There were no acquisition-related transaction costs incurred during the three months ended September 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 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. The PPAs will be amortized over an average term of 12 years.

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.

The Company recorded goodwill of approximately $200 million, all of which is deductible for U.S. income tax purposes in future periods. The goodwill primarily represents the Company's ability to further monetize certain of the assets in the portfolio through the sale of assets to NRG Yield, Inc. or to other partners with the ability to further utilize the related tax benefits. The goodwill will be recorded in the Renewables segment.

Supplemental Pro Forma Information

Since the acquisition date, EME contributed $703 million in operating revenues and $58 million in net income attributable to NRG. The following supplemental pro forma information represents the results of operations as if NRG had acquired EME on January 1, 2013:



	For the nine months ended					For the year ended
(in millions except per share amounts)	September 30, 2014		September 30, 2013			December 31, 2013

Operating revenues	$	12,234	$	9,486		$	12,598
Net income/(loss) attributable to NRG Energy, Inc.	47		(702		)	(1,004		)
Earnings/(loss) per share attributable to NRG common stockholders:
Basic	0.14		(2.09		)	(2.99		)
Diluted	0.14		(2.09		)	(2.99		)

The supplemental 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 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 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 accounting for Energy Systems was completed as of September 30, 2014, at which point the provisional fair values became final with no material changes.

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 accounting for the Gregory acquisition was completed as of June 30, 2014, at which point the provisional fair values became final with no material changes.

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 September 30, 2014				As of December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Assets:
Notes receivable^(a)	$	95	$	95	$	99	$	99
Liabilities:
Long-term debt, including current portion	20,764		20,843		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 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 September 30, 2014
	Fair Value
(In millions)	Level 1		Level 2		Level 3		Total
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities	$	—	$	—	$	18	$	18
Available-for-sale securities	42		—		—		42
Other ^(a)	21		—		11		32
Nuclear trust fund investments:
Cash and cash equivalents	2		—		—		2
U.S. government and federal agency obligations	39		3		—		42
Federal agency mortgage-backed securities	—		68		—		68
Commercial mortgage-backed securities	—		25		—		25
Corporate debt securities	—		85		—		85
Equity securities	291		—		54		345
Foreign government fixed income securities	—		2		—		2
Other trust fund investments:
U.S. government and federal agency obligations	1		—		—		1
Derivative assets:
Commodity contracts	357		1,170		285		1,812
Interest rate contracts	—		10		—		10
Equity contracts	—		—		2		2
Total assets	$	753	$	1,363	$	370	$	2,486
Derivative liabilities:
Commodity contracts	$	240	$	1,061	$	258	$	1,559
Interest rate contracts	—		132		—		132
Total liabilities	$	240	$	1,193	$	258	$	1,691

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



	As of December 31, 2013
	Fair Value
(In millions)	Level 1		Level 2		Level 3		Total
Investment in available-for-sale securities (classified within other non-current assets):
Debt securities	$	—	$	—	$	16	$	16
Available-for-sale securities	2		—		—		2
Other ^(a)	37		—		10		47
Nuclear trust fund investments:
Cash and cash equivalents	26		—		—		26
U.S. government and federal agency obligations	40		5		—		45
Federal agency mortgage-backed securities	—		62		—		62
Commercial mortgage-backed securities	—		14		—		14
Corporate debt securities	—		70		—		70
Equity securities	276		—		56		332
Foreign government fixed income securities	—		2		—		2
Other trust fund investments:
U.S. government and federal agency obligations	1		—		—		1
Derivative assets:
Commodity contracts	346		1,126		147		1,619
Interest rate contracts	—		20		—		20
Total assets	$	728	$	1,299	$	229	$	2,256
Derivative liabilities:
Commodity contracts	$	216	$	831	$	134	$	1,181
Interest rate contracts	—		69		—		69
Total liabilities	$	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 nine months ended September 30, 2014 and 2013 between Levels 1 and 2. The following tables reconcile, for the three and nine months ended September 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)
	Three months ended September 30, 2014													Nine months ended September 30, 2014
(In millions)	Debt Securities		Other		Trust Fund Investments			Derivatives^(a)			Total			Debt Securities		Other		Trust Fund Investments			Derivatives^(a)			Total
Beginning balance	$	18	$	11	$	58		$	(12	)	$	75		$	16	$	10	$	56		$	13		$	95
Total gains/(losses) — realized/unrealized:
Included in earnings	—		—		—			(22		)	(22		)	—		1		—			(18		)	(17		)
Included in OCI	—		—		—			—			—			2		—		—			—			2
Included in nuclear decom- missioning obligation	—		—		(4		)	—			(4		)	—		—		(3		)	—			(3		)
Purchases	—		—		—			63			63			—		—		1			(21		)	(20		)
Contracts acquired in Dominion and EME acquisition	—		—		—			—			—			—		—		—			39			39
Transfers into Level 3 ^(b)	—		—		—			(1		)	(1		)	—		—		—			17			17
Transfers out of Level 3 ^(b)	—		—		—			1			1			—		—		—			(1		)	(1		)
Ending balance as of September 30, 2014	$	18	$	11	$	54		$	29		$	112		$	18	$	11	$	54		$	29		$	112
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 September 30, 2014	$	—	$	—	$	—		$	5		$	5		$	—	$	—	$	—		$	26		$	26


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


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



	Fair Value Measurement Using Significant Unobservable Inputs (Level 3)
	Three months ended September 30, 2013										Nine months ended September 30, 2013
(In millions)	Debt Securities		Trust Fund Investments		Derivatives^(a)			Total			Debt Securities		Trust Fund Investments		Derivatives^(a)			Total
Beginning balance	$	15	$	50	$	(12	)	$	53		$	12	$	47	$	(12	)	$	47
Total (losses)/gains — realized/unrealized:
Included in earnings	—		—		14			14			—		—		(4		)	(4		)
Included in OCI	—		—		—			—			3		—		—			3
Included in nuclear decom- missioning obligations	—		5		—			5			—		7		—			7
Purchases	—		—		4			4			—		1		(3		)	(2		)
Transfers into Level 3 ^(b)	—		—		(36		)	(36		)	—		—		(9		)	(9		)
Transfers out of Level 3 ^(b)	—		—		23			23			—		—		21			21
Ending balance as of September 30, 2013	$	15	$	55	$	(7	)	$	63		$	15	$	55	$	(7	)	$	63
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 September 30, 2013	—		—		(7		)	(7		)	—		—		(4		)	(4		)


(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 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 September 30, 2014, contracts valued with prices provided by models and other valuation techniques make up 16% of the total derivative assets and 15% 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 September 30, 2014, the credit reserve resulted in a $1 million increase in fair value which is a gain in OCI. As of September 30, 2013, the credit reserve resulted in a $1 million decrease in fair value which is composed of a $1 million gain in OCI and a $2 million 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.

Counterparty Credit Risk

The Company's counterparty credit risk policies are disclosed in its 2013 Form 10-K. As of September 30, 2014, counterparty credit exposure, excluding credit risk exposure under certain long term agreements, was $677 million and NRG held collateral (cash and letters of credit) against those positions of $1 million, resulting in a net exposure of $676 million. Approximately 78% 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	38	%
Utilities, energy merchants, marketers and other	38
ISOs	24
Total as of September 30, 2014	100	%



	Net Exposure ^(a)
Category	(% of Total)
Investment grade	89	%
Non-rated ^(b)	11
Total as of September 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 $181 million as of September 30, 2014. 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 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 September 30, 2014, aggregate credit risk exposure managed by NRG to these counterparties was approximately $4.4 billion, including $1.8 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 September 30, 2014, the Company believes its retail customer credit exposure was diversified across many customers and various industries, as well as government entities.

Note 5 — Nuclear Decommissioning Trust Fund

This footnote should be read in conjunction with the complete description under Note 6, Nuclear Decommissioning Trust Fund, to the Company's 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 September 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)
Cash and cash equivalents	$	2	$	—	$	—	—	$	26	$	—	$	—	—
U.S. government and federal agency obligations	42		2		—		9	45		1		1		9
Federal agency mortgage-backed securities	68		1		—		25	62		1		1		24
Commercial mortgage-backed securities	25		—		1		30	14		—		—		29
Corporate debt securities	85		2		1		10	70		1		1		9
Equity securities	345		210		—		—	332		204		—		—
Foreign government fixed income securities	2		—		—		16	2		—		—		9
Total	$	569	$	215	$	2		$	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.



	Nine months ended September 30,
	2014		2013
	(In millions)
Realized gains	$	15	$	10
Realized losses	5		7
Proceeds from sale of securities	463		344

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

Interest Rate Swaps

NRG is exposed to changes in interest rates through the Company's issuance of variable and fixed rate debt. In order to manage the Company's interest rate risk, NRG enters into interest rate swap agreements. As of September 30, 2014, the Company had interest rate derivative instruments on non-recourse debt extending through 2032, some of which are designated as cash flow hedges.

Volumetric Underlying Derivative Transactions

The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by category, excluding those derivatives that qualified for the NPNS exception as of September 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
		September 30, 2014			December 31, 2013
Category	Units	(In millions)
Emissions	Short Ton	1			—
Coal	Short Ton	60			51
Natural Gas	MMBtu	(150		)	(166		)
Oil	Barrel	—			1
Power	MWh	(52		)	(27		)
Interest	Dollars	$	3,459		$	1,444
Equity	Shares	2			—

The increase in the interest rate swap position was primarily the result of interest rate swaps acquired in connection with EME and Alta Wind.

Fair Value of Derivative Instruments

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



	Fair Value
	Derivative Assets				Derivative Liabilities
	September 30, 2014		December 31, 2013		September 30, 2014		December 31, 2013
	(In millions)
Derivatives designated as cash flow hedges:
Interest rate contracts current	$	—	$	—	$	53	$	35
Interest rate contracts long-term	8		14		66		29
Commodity contracts current	—		—		—		1
Commodity contracts long-term	—		—		—		1
Total derivatives designated as cash flow hedges	8		14		119		66
Derivatives not designated as cash flow hedges:
Interest rate contracts current	—		—		6		4
Interest rate contracts long-term	2		6		7		1
Commodity contracts current	1,397		1,328		1,306		1,015
Commodity contracts long-term	415		291		253		164
Equity contracts long-term	2		—		—		—
Total derivatives not designated as cash flow hedges	1,816		1,625		1,572		1,184
Total derivatives	$	1,824	$	1,639	$	1,691	$	1,250

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



	Gross Amounts Not Offset in the Statement of Financial Position
	Gross Amounts of Recognized Assets / Liabilities			Derivative Instruments			Cash Collateral (Held) / Posted			Net Amount
As of September 30, 2014	(In millions)
Commodity contracts:
Derivative assets	$	1,812		$	(1,433	)	$	(3	)	$	376
Derivative liabilities	(1,559		)	1,433			15			(111		)
Total commodity contracts	253			—			12			265
Interest rate contracts:
Derivative assets	10			(8		)	—			2
Derivative liabilities	(132		)	8			—			(124		)
Total interest rate contracts	(122		)	—			—			(122		)
Equity contracts:
Derivative assets	2			—			—			2
Total derivative instruments	$	133		$	—		$	12		$	145



	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 September 30, 2014									Nine months ended September 30, 2014
	Energy Commodities			Interest Rate			Total			Energy Commodities			Interest Rate			Total
	(In millions)
Accumulated OCI beginning balance	$	(1	)	$	(50	)	$	(51	)	$	(1	)	$	(22	)	$	(23	)
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	—			11			11			—			3			3
Mark-to-market of cash flow hedge accounting contracts	—			(7		)	(7		)	—			(27		)	(27		)
Accumulated OCI ending balance, net of $25 tax	$	(1	)	$	(46	)	$	(47	)	$	(1	)	$	(46	)	$	(47	)
Losses expected to be realized from OCI during the next 12 months, net of $6 tax	$	(1	)	$	(10	)	$	(11	)	$	(1	)	$	(10	)	$	(11	)



	Three months ended September 30, 2013									Nine months ended September 30, 2013
	Energy Commodities			Interest Rate			Total			Energy Commodities			Interest Rate			Total
	(In millions)
Accumulated OCI beginning balance	$	24		$	(31	)	$	(7	)	$	41		$	(72	)	$	(31	)
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	(15		)	2			(13		)	(38		)	6			(32		)
Mark-to-market of cash flow hedge accounting contracts	1			(4		)	(3		)	7			33			40
Accumulated OCI ending balance, net of $13 tax	$	10		$	(33	)	$	(23	)	$	10		$	(33	)	$	(23	)
Gains/(losses) expected to be realized from OCI during the next 12 months, net of $1 tax	$	11		$	(9	)	$	2		$	11		$	(9	)	$	2
Gains recognized in income from the ineffective portion of cash flow hedges	$	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 nine months ended September 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 September 30,						Nine months ended September 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	$	(1	)	$	(48	)	$	(3	)	$	(80	)
Reversal of acquired gain positions related to economic hedges	(87		)	(82		)	(249		)	(269		)
Net unrealized gains/(losses) on open positions related to economic hedges	162			76			(61		)	131
Gains on ineffectiveness associated with open positions treated as cash flow hedges	—			1			—			—
Total unrealized mark-to-market gains/(losses) for economic hedging activities	74			(53		)	(313		)	(218		)
Reversal of previously recognized unrealized (gains)/losses on settled positions related to trading activity	(1		)	(13		)	4			(42		)
Reversal of acquired gain positions related to trading activity	(8		)	(2		)	(28		)	(2		)
Net unrealized gains on open positions related to trading activity	15			26			45			—
Total unrealized mark-to-market gains/(losses) for trading activity	6			11			21			(44		)
Total unrealized gains/(losses)	$	80		$	(42	)	$	(292	)	$	(262	)



	Three months ended September 30,						Nine months ended September 30,
	2014			2013			2014			2013
	(In millions)
Unrealized gains/(losses) included in operating revenues	$	159		$	(64	)	$	(205	)	$	(404	)
Unrealized (losses)/gains included in cost of operations	(79		)	22			(87		)	142
Total impact to statement of operations — energy commodities	$	80		$	(42	)	$	(292	)	$	(262	)
Total impact to statement of operations — interest rate contracts	$	1		$	4		$	(6	)	$	10

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

For the nine months ended September 30, 2014, the unrealized loss from open economic hedge positions was primarily the result of a decrease in value of forward sales of electricity due to increases in power prices and ERCOT heat rates.

For the nine months ended September 30, 2013, the unrealized gain from open economic hedge positions was primarily the result of an increase in value of forward sales of natural gas and electricity due to a decrease in forward natural gas and power 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 nine months ended September 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 September 30, 2014 was $70 million. The collateral required for contracts with credit rating contingent features as of September 30, 2014 was $40 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 $25 million as of September 30, 2014.

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

Note 7 — Debt and Capital Leases

This footnote should be read in conjunction with the complete description under Note 12, Debt and Capital Leases, to the Company's 2013 Form 10-K. Long-term debt and capital leases consisted of the following:



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

Recourse debt:
Senior notes, due 2018	$	1,130	$	1,130	7.625
Senior notes, due 2019	—		800		7.625
Senior notes, due 2019	—		602		8.500
Senior notes, due 2020	1,063		1,062		8.250
Senior notes, due 2021	1,128		1,128		7.875
Senior notes, due 2022	1,100		—		6.250
Senior notes, due 2023	990		990		6.625
Senior notes, due 2024	1,000		—		6.250
Term loan facility, due 2018	1,987		2,002		L+2.00
Tax-exempt bonds	373		373		4.750 - 6.00
Subtotal NRG recourse debt	8,771		8,087
Non-recourse debt:
GenOn senior notes	2,146		2,183		7.875 - 9.875
GenOn Americas Generation senior notes	931		938		8.500 - 9.125
Subtotal GenOn debt (non-recourse to NRG)	3,077		3,121
NRG Yield Operating LLC Senior Notes, due 2024	500		—		5.375
NRG Yield Inc. Convertible Senior Notes, due 2019	325		—		3.5
NRG West Holdings LLC, due 2023	506		512		L+2.25 - 2.875
NRG Marsh Landing, due 2017 and 2023	477		473		L+1.75 - 1.875
Alta Wind I - V lease financing arrangements, due 2034 and 2035	1,046		—		5.70-7.01
Alta Wind X, due 2020	300		—		L+2.00
Alta Wind XI, due 2020	191		—		L+2.00
NRG Solar Alpine LLC, due 2022	166		221		L+2.50/L+1.75
NRG Energy Center Minneapolis LLC, due 2017 and 2025	122		127		5.95 - 7.25
NRG Yield - other	450		450		various
Subtotal NRG Yield debt (non-recourse to NRG)	4,083		1,783
Ivanpah Financing, due 2014, 2015, 2033 and 2038	1,591		1,575		0.437 - 4.256
Agua Caliente Solar LLC, due 2037	898		878		2.395 - 3.633
CVSR High Plains Ranch II LLC, due 2037	815		1,104		2.339 - 3.775
Walnut Creek, term loans due 2023	391		—		L+2.25
Viento Funding II, Inc., due 2023	198		—		L+2.75
Tapestry Wind LLC, due 2021	195		—		L+2.50
NRG Peaker Finance Co. LLC, bonds due 2019	129		154		L+1.07
Cedro Hill Wind LLC, due 2025	112		—		L+3.125
NRG - other	504		102		various
Subtotal NRG non-recourse debt	4,833		3,813
Subtotal non-recourse debt (including GenOn and NRG Yield)	11,993		8,717
Subtotal long-term debt (including current maturities)	20,764		16,804
Capital leases:
Chalk Point capital lease, due 2015	6		10		8.190
Other	3		3		various
Subtotal long-term debt and capital leases (including current maturities)	20,773		16,817
Less current maturities	854		1,050
Total long-term debt and capital leases	$	19,919	$	15,767

(a) As of September 30, 2014, L+ equals 3 month LIBOR plus x%, with the exception of the Viento Funding II term loan which is 6 month LIBOR plus x%.

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. A portion of the cash proceeds were used to redeem all remaining of its 7.625% 2019 Senior Notes, and the rest of the proceeds were used to redeem all remaining $225 million of its 8.5% 2019 Senior Notes in September 2014, as 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.

Redemptions of 8.5% and 7.625% 2019 Senior Notes

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

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

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

On September 3, 2014, the Company redeemed for cash all of its remaining 8.5% 2019 Senior Notes at an average early redemption percentage of 104.25%. A $13 million loss on debt extinguishment of the 8.5% 2019 Senior Notes was recorded during the three months ended September 30, 2014, primarily consisting of the premiums paid on the redemption and the write-off of previously deferred financing costs.

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 February 27, 2015. On October 16, 2014, Solar Partners VIII received an extension with respect to its borrowings previously due on October 27, 2014, which are subsequently due April 27, 2015. 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.

Acquired EME and Alta Wind Project Financings

The following table summarizes the terms of the significant non-recourse project level debt assumed by the Company in the acquisitions of EME and the Alta Wind Assets:



Amount in millions, except rates	Term Loan Facility				Letter of Credit Facility				Bond/ Note Payable
Non-Recourse Debt	Amount Outstanding as of September 30, 2014		Interest Rate	Maturity Date	Amount Outstanding as of September 30, 2014		Interest Rate	Maturity Date	Amount Outstanding as of September 30, 2014		Interest Rate	Maturity Date
EME project financings
Broken Bow Wind	$	49	3-Month LIBOR + 2.875%	12/31/2027	$	10	2.875%	12/21/2022	$	—	—	—
Cedro Hill Wind	112		3-Month LIBOR + 3.125%	12/31/2025	10		3.336%	12/22/2017	—		—	—
Crofton Bluffs	25		3-Month LIBOR + 2.875%	12/31/2027	3		2.875%	12/14/2022	—		—	—
Laredo Ridge Wind	67		3-Month LIBOR + 2.875%	3/31/2026	8		2.875%	3/18/2018	—		—	—
Tapestry Wind	195		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	391		3-Month LIBOR + 2.250%	5/31/2023	48		2.000%	5/17/2023	—		—	—
WCEP Holding LLC	53		3-Month LIBOR + 4.000%	5/31/2023	—		—	—	—		—	—
High Lonesome Mesa	—		—	—	7		4.000%	11/1/2017	62		6.850%	11/1/2017
Various	11		various	various	14		various	various	—		—	—
Subtotal EME	1,101				147				62
Alta Wind project financings
Alta Realty	—		—	—	—		—	—	34		7.000%	1/31/2031
Alta Wind Asset Management	20		3-Month LIBOR + 2.375%	5/15/2031	—		—	—	—		—	—
Alta X	300		3-Month LIBOR + 2.000%	3/31/2020	5		2.000%	3/31/2020	—		—	—
Alta XI	191		3-Month LIBOR + 2.000%	3/31/2020	—		—	—	—		—	—
Subtotal Alta Wind	511				5				34
Total	$	1,612			$	152			$	96

All of the assets of Alta X and Alta XI are pledged as collateral under their respective agreements.

Alta Wind Lease financing arrangements

Alta Wind Holdings (Alta Wind II - V) and Alta I have finance lease obligations issued under lease transactions whereby the respective operating entities sold and leased back undivided interests in specific assets of the projects. All of the assets of Alta I - V are pledged as collateral under these arrangements. The sale and related lease transactions are accounted for as financing arrangements as the operating entities have continued involvement with the property.



Amount in millions, except rates	Lease Financing Arrangement				Letter of Credit Facility
Non-Recourse Debt	Amount Outstanding as of September 30, 2014		Interest Rate	Maturity Date	Amount Outstanding as of September 30, 2014		Interest Rate	Maturity Date
Alta Wind I	$	263	7.015%	12/30/2034	$	16	3.250%	1/5/2016
Alta Wind II	207		5.696%	12/30/2034	25		2.750%	12/31/2017
Alta Wind III	215		6.067%	12/30/2034	25		2.750%	4/13/2018
Alta Wind IV	139		5.938%	12/30/2034	18		2.750%	5/20/2018
Alta Wind V	222		6.071%	6/30/2035	28		2.750%	6/13/2018
Total	$	1,046			$	112

Interest Rate Swaps — EME and Alta Wind Project Financings

Many of EME and Alta Wind'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 and Alta Wind project level debt as of September 30, 2014.

Non-Recourse Debt

% of Principal

Fixed Interest Rate

Floating Interest Rate

Notional Amount at September 30, 2014

(In millions)

Effective Date

Maturity Date

EME Project Financings

Broken Bow

90%

2.960%

3-Month LIBOR

December 31, 2013

December 31, 2027

Cedro Hill

90%

4.290%

3-Month LIBOR

101

December 31, 2010

December 31, 2025

Crofton Bluffs

90%

2.748%

3-Month LIBOR

December 31, 2013

December 31, 2027

Laredo Ridge

90%

3.460%

3-Month LIBOR

March 31, 2011

March 31, 2026

Tapestry

90%

2.210%

3-Month LIBOR

175

December 30, 2011

December 21, 2021

Tapestry

50%

3.570%

3-Month LIBOR

December 21, 2021

December 21, 2029

Viento Funding II

90%

various

6-Month LIBOR

179

various

Viento Funding II

90%

4.985%

6-Month LIBOR

July 11, 2023

June 30, 2028

Walnut Creek Energy

90%

3.543%

3-Month LIBOR

352

June 28, 2013

May 31, 2023

WCEP Holdings

90%

4.003%

3-Month LIBOR

June 28, 2013

May 31, 2023

Subtotal EME

1,106

Alta Wind Project Financings

Alta X

100%

various

3-Month LIBOR

216

December 31, 2013

December 31, 2015

Alta X

100%

various

3-Month LIBOR

December 31, 2013

December 31, 2025

Alta X

100%

various

3-Month LIBOR

162

December 31, 2015

December 31, 2020

Alta X

100%

various

3-Month LIBOR

103

December 31, 2020

December 31, 2025

Alta XI

100%

various

3-Month LIBOR

138

December 31, 2013

December 31, 2015

Alta XI

100%

various

3-Month LIBOR

December 31, 2013

December 31, 2025

Alta XI

100%

various

3-Month LIBOR

103

December 31, 2015

December 31, 2020

Alta XI

100%

various

3-Month LIBOR

December 31, 2020

December 31, 2025

AWAM

100%

2.470%

3-Month LIBOR

May 22, 2013

May 15, 2031

Subtotal Alta Wind

944

Total

2,050

High Lonesome Mesa Facility

Prior to the Company's acquisition of EME, an intercompany tax credit agreement related to the High Lonesome Mesa facility was terminated. The termination resulted in an event of default under the project financing arrangement. As a result, the balance under the project financing arrangement is classified as current and the lender can request repayment at any time. The facility is secured by the assets of High Lonesome Mesa and is non-recourse to NRG.

NRG Yield Operating LLC Senior Notes

On August 5, 2014, Yield Operating issued $500 million of senior unsecured notes and utilized 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 are 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 Convertible Notes. The NRG Yield 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 Convertible Notes. Interest on the NRG Yield 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 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 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 Yield Operating 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 and $27 million of letters of credit issued under the revolving credit facility as of September 30, 2014.

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, Yield Operating, the Company owns a 50% interest in GenConn, which owns and operates two 190 MW peaking generation facilities in Connecticut at NRG's Devon and Middletown sites. NRG's maximum exposure to loss is limited to its equity investment, which was $114 million as of September 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 $81 million as of September 30, 2014.

Entities that are Consolidated

Capistrano Wind Partners — Through the acquisition of EME, the Company has a controlling financial interest in Capistrano Wind Partners, whose Class B preferred equity 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 Company does not consolidate Capistrano Wind Partners for tax purposes.

The summarized financial information for Capistrano Wind Holdings consisted of the following:



(In millions)	September 30, 2014
Current assets	$	24
Net property, plant and equipment	604
Other long-term assets	146
Total assets	774

Current liabilities	32
Long-term debt	186
Other long-term liabilities	146
Total liabilities	364

Noncontrolling interests	$	358

Note 9 — Changes in Capital Structure

As of September 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
Balance as of December 31, 2013	401,126,780	(77,347,528	)	323,779,252
Shares issued under LTIPs	1,407,434	—		1,407,434
Shares issued under ESPP	—	128,383		128,383
Shares issued in connection with the EME acquisition	12,671,977	—		12,671,977
Balance as of September 30, 2014	415,206,191	(77,219,145	)	337,987,046

Employee Stock Purchase Plan

On May 8, 2014, NRG stockholders approved an increase of 800,000 shares available for issuance under the ESPP. As of September 30, 2014, 1,560,005 shares of treasury stock were available for issuance under the ESPP.

NRG Common Stock Dividends

The following table lists the dividends paid during the nine months ended September 30, 2014:



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

On October 14, 2014, NRG declared a quarterly dividend on the Company's common stock of $0.14 per share, payable November 17, 2014, to stockholders of record as of November 3, 2014, representing $0.56 on an annualized basis.

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

Note 10 — Earnings/(Loss) Per Share

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



	Three months ended September 30,				Nine months ended September 30,
(In millions, except per share data)	2014		2013		2014		2013
Basic earnings/(loss) per share attributable to NRG Energy, Inc. common stockholders
Net income/(loss) attributable to NRG Energy, Inc.	$	168	$	119	$	15	$	(89	)
Dividends for preferred shares	2		2		7		7
Earnings/(loss) available for common stockholders	$	166	$	117	$	8	$	(96	)
Weighted average number of common shares outstanding	338		323		333		323
Earnings/(loss) per weighted average common share — basic	$	0.49	$	0.36	$	0.02	$	(0.30	)
Diluted earnings/(loss) per share attributable to NRG Energy, Inc. common stockholders
Weighted average number of common shares outstanding	338		323		333		323
Incremental shares attributable to the issuance of equity compensation (treasury stock method)	5		4		5		—
Total dilutive shares	343		327		338		323
Earnings/(loss) per weighted average common share — diluted	$	0.48	$	0.36	$	0.02	$	(0.30	)

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



	Three months ended September 30,		Nine months ended September 30,
(In millions of shares)	2014	2013	2014	2013
Equity compensation plans	1	2	1	10
Embedded derivative of 3.625% redeemable perpetual preferred stock	16	16	16	16
Total	17	18	17	26

Note 11 — Segment Reporting

Effective June 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, 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: Gulf Coast, East and West. The Company's renewables segment includes solar and wind assets, excluding those in the NRG Yield segment. NRG Yield includes certain of the Company's contracted generation assets. On June 30, 2014, NRG Yield, Inc. 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 September 30, 2014	Retail^(a)		Gulf Coast^(a)		East^(a)		West^(a)		Renewables^(a)			NRG Yield		Corporate^(a)			Elimination			Total
Operating revenues	$	2,329	$	1,035	$	1,255	$	212	$	154		$	161	$	96		$	(673	)	$	4,569
Depreciation and amortization	32		151		65		18		64			34		11			—			375
Impairment losses	—		—		60		—		10			—		—			—			70
Equity in earnings/(losses) of unconsolidated affiliates	—		—		—		15		(1		)	11		(3		)	(4		)	18
Loss on debt extinguishment	—		—		—		—		—			—		(13		)	—			(13		)
Income/(loss) before income taxes	88		147		223		76		(22		)	41		(225		)	(57		)	271
Net income/(loss) attributable to NRG Energy, Inc.	88		147		223		76		(34		)	25		(310		)	(47		)	168
Total assets as of September 30, 2014	$	5,996	$	14,658	$	10,347	$	2,306	$	8,200		$	5,899	$	29,752		$	(37,089	)	$	40,069



(a) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	1	$	626	$	(28	)	$	30	$	(5	)	$	—	$	49



(In millions)				Conventional Power Generation
Three months ended September 30, 2013	Retail^(b)			Gulf Coast^(b)		East^(b)		West^(b)			Renewables^(b)			NRG Yield		Corporate^(b)			Elimination			Total
Operating revenues	$	1,994		$	1,125	$	1,011	$	109		$	74		$	126	$	66		$	(1,015	)	$	3,490
Depreciation and amortization	37			141		87		12			24			18		8			—			327
Equity in earnings/(loss) of unconsolidated affiliates	—			1		—		(10		)	2			12		—			(10		)	(5		)
Loss on debt extinguishment	—			—		—		—			—			—		(1		)	—			(1		)
(Loss)/income before income taxes	(56		)	282		241		22			9			54		(202		)	(52		)	298
Net (loss)/income attributable to NRG Energy, Inc.	$	(56	)	$	282	$	241	$	22		$	(7	)	$	40	$	(365	)	$	(38	)	$	119



(b) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	2	$	932	$	29	$	1	$	16	$	—	$	35



(In millions)			Conventional Power Generation
Nine months ended September 30, 2014	Retail^(c)		Gulf Coast^(c)			East^(c)		West^(c)		Renewables^(c)			NRG Yield		Corporate^(c)			Elimination			Total
Operating revenues	$	5,734	$	2,512		$	3,536	$	487	$	368		$	435	$	194		$	(1,590	)	$	11,676
Depreciation and amortization	98		438			205		57		170			94		34			—			1,096
Impairment losses	—		—			60		—		10			—		—			—			70
Equity in earnings/(losses) of unconsolidated affiliates	—		1			—		29		(7		)	26		1			(11		)	39
Loss on debt extinguishment	—		—			—		—		—			—		(94		)	—			(94		)
Income/(loss) before income taxes	268		(56		)	448		117		(86		)	106		(751		)	(79		)	(33		)
Net income/(loss) attributable to NRG Energy, Inc.	$	267	$	(56	)	$	448	$	117	$	(101	)	$	75	$	(682	)	$	(53	)	$	15



(c) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	5	$	1,459	$	2	$	30	$	5	$	—	$	89



(In millions)			Conventional Power Generation
Nine months ended September 30, 2013	Retail^(d)		Gulf Coast^(d)		East^(d)		West^(d)			Renewables^(d)			NRG Yield		Corporate^(d)			Elimination			Total
Operating revenues	$	4,760	$	2,368	$	2,432	$	322		$	163		$	261	$	123		$	(1,929	)	$	8,500
Depreciation and amortization	105		414		260		37			72			38		21			—			947
Equity in earnings/(losses) of unconsolidated affiliates	—		3		—		(8		)	3			18		—			(10		)	6
Loss on debt extinguishment	—		—		—		—			—			—		(50		)	—			(50		)
Income/(loss) before income taxes	231		31		216		54			(19		)	100		(672		)	(58		)	(117		)
Net income/(loss) attributable to NRG Energy, Inc.	$	231	$	31	$	216	$	54		$	(45	)	$	86	$	(620	)	$	(42	)	$	(89	)



(d) Operating revenues include inter-segment sales and net derivative gains and losses of:	$	4	$	1,769	$	87	$	4	$	16	$	—	$	49

Note 12 — Income Taxes

Effective Tax Rate

The income tax provision consisted of the following:



	Three months ended September 30,						Nine months ended September 30,
(In millions except otherwise noted)	2014			2013			2014			2013
Income/(loss) before income taxes	$	271		$	298		$	(33	)	$	(117	)
Income tax expense/(benefit)	89			160			(68		)	(55		)
Effective tax rate	32.8		%	53.7		%	206.1		%	47.0		%

For the three and nine months ended September 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 a benefit resulting from the recognition of previously uncertain tax benefits that were settled upon IRS audit during the second quarter of 2014.

For the three months ended September 30, 2013, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to state and local income taxes.

For the nine months ended September 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, partially offset by state and local income taxes.

Uncertain Tax Benefits

As of September 30, 2014, NRG has recorded a non-current tax liability of $56 million for uncertain tax benefits from positions taken on various state income tax returns, including accrued interest. NRG has accrued interest related to these uncertain tax benefits of $1 million for the nine months ended September 30, 2014. In addition, the Company has reversed $6 million of tax and $3 million of interest previously accrued for positions effectively settled upon state audit during the third quarter of 2014. NRG has accrued $11 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 2010. With few exceptions, state and local income tax examinations are no longer open for years before 2007. The Company's primary foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2010.

Note 13 — Commitments and Contingencies

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 and EME (Midwest Generation) acquisitions, assets held by NRG Yield, Inc. and NRG's assets that have project-level financing, to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. The Company's lien counterparties may have a claim on NRG's assets to the extent market prices exceed the hedged price. As of September 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 Asbestos Liabilities

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

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. This matter was settled on July 21, 2014 for $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 Mirant's bankruptcy proceedings. In December 2010, the U.S. District Court for the Northern District of Texas dismissed MC Asset Recovery's complaint against the Commerzbank Defendants. In January 2011, MC Asset Recovery appealed the District Court's dismissal of its complaint against the Commerzbank Defendants to the U.S. Court of Appeals for the Fifth Circuit. In March 2012, the Court of Appeals reversed the District Court's dismissal and reinstated MC Asset Recovery's amended complaint against the Commerzbank Defendants. If MC Asset Recovery succeeds in obtaining any recoveries from the Commerzbank Defendants, the Commerzbank Defendants have asserted that they will seek to file claims in Mirant's bankruptcy proceedings for the amount of those recoveries. GenOn Energy Holdings would vigorously contest the allowance of any such claims. If the Commerzbank Defendants were to receive an allowed claim as a result of a recovery by MC Asset Recovery on its claims against them, GenOn Energy Holdings would retain from the net amount recovered by MC Asset Recovery an amount equal to the dollar amount of the resulting allowed claim.

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 Court of Appeals reversed the decision of the District 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 Court of Appeal’s decision. On July 1, 2014, the U.S. Supreme Court granted the petition for a writ of certiorari. On September 18, 2014, GenOn along with its co-defendants filed their Opening Brief with the U.S. Supreme Court.

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 District Court granted the Company's motion to dismiss, which plaintiffs appealed to the U.S. Court of Appeals for the Third Circuit. On August 20, 2013, the Court of Appeals reversed the decision of the District Court. On September 3, 2013, the Company filed a petition for rehearing with the 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 Court of Appeals decision. On June 2, 2014, the U.S. Supreme Court 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's subsidiary discharged approved wastewaters into the Monarch mine including low-volume wastewater from the Cheswick generating facility and leachate collected from ash disposal facilities. The NOV addresses a permit requirement to pump a minimum water volume from the mine. On September 2, 2014, the Company's subsidiary that owns the Cheswick generating facility, the Commonwealth of Pennsylvania and the PADEP entered into a Consent Order and Agreement resolving the NOV. Pursuant to that Consent Order and Agreement, the Company's subsidiary will, among other things, cease wastewater discharges to the mine, construct a waste treatment facility and contribute $200,000 to the Indianola Mine Trust. The Company's subsidiary 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 executed a settlement agreement with the Connecticut Office of Attorney General and 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.

Maryland Department of the Environment v. GenOn Chalk Point and GenOn Mid-Atlantic

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

Midwest Generation New Source Review Litigation

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

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

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

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. The U.S. Court of Appeals for the District of Columbia Circuit denied FERC's request to rehear en banc the decision. The decision could be appealed to the U.S. Supreme Court. The eventual outcome of this proceeding could result in refunds of payments made for non-jurisdictional services and resettlement of wholesale markets but it is not possible to estimate the impact on the Company at this time. On October 20, 2014, the U.S. Court of Appeals for the District of Columbia Circuit issued a stay of its decision until at least December 16, 2014, with the possibility of a longer stay if the government seeks U.S. Supreme Court review.

West Region

California Station Power — On December 18, 2012, in Calpine Corporation v. FERC, the U.S. Court of Appeals for the 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 ruling 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 14, 2014, the CPUC approved a resolution describing the method to be used by SCE and PG&E to determine station power charges. The resolution establishes a 15 minute netting period, to take effect August 30, 2010, which means that there would be no refund liability associated with station power consumption prior to August 30, 2010. The resolution is pending rehearing. The Company has accrued sufficient funds to pay the charges.

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 operating license and as a result, no further evaluations need to be performed.

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 laws in the development, ownership, construction and operation of projects in the U.S. and certain international regions. These laws generally require that governmental permits and approvals be obtained before construction and during operation of power plants. Environmental laws have become increasingly stringent and NRG expects this trend to continue. The electric generation industry is likely to face new requirements to address various emissions, including GHG, as well as combustion byproducts, water discharge and use, and threatened and endangered species. In general, future laws are expected to require the addition of emissions controls or other environmental controls or to impose certain restrictions on the operations of the Company's facilities, which could have a material effect on the Company's operations.

The EPA released CSAPR in 2011, which was scheduled to replace CAIR in January 2012. In December 2011, the U.S. Court of Appeals for the 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 could replace it. On April 29, 2014, the U.S. Supreme Court reversed and remanded the D.C. Circuit's decision. In October 2014, the D.C. Circuit lifted the stay of CSAPR. Accordingly, the Company expects compliance to begin in January 2015. Further proceedings in the Court of Appeals are scheduled to occur 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 plant 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 1,000 pounds of CO₂per MWh for large gas units and 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. On June 18, 2014, the EPA 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. Comments on this proposal are due in December 2014. The EPA anticipates finalizing this rule in June 2015.

Water

In August 2014, the EPA finalized the 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

In October 2014, the MDE released a draft of a proposed regulation regarding NO_xemissions from coal-fired electric generating units. MDE has stated that the draft will be proposed in the Maryland Register in December 2014 and finalized in 2015. If finalized in its current form, the regulation would require the Company to: (1) install and operate state-of-the-art controls (e.g., SCRs) by June 1, 2020 at the three Dickerson coal-fired units and one of the Chalk Point coal-fired units; (2) retire the units; or (3) convert the fuel source for the units from coal to natural gas. The implementation of the MDE regulations could negatively affect certain of the Company’s coal facilities 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 $877 million which includes $109 million for 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 environmental regulations.

Note 16 — Condensed Consolidating Financial Information

As of September 30, 2014, the Company had outstanding $6.4 billion of Senior Notes due from 2018 - 2024, as shown in Note 7, Debt and Capital Leases. These Senior Notes are guaranteed by certain of NRG's current and future 100% owned domestic subsidiaries, or guarantor subsidiaries. These guarantees are both joint and several. The non-guarantor subsidiaries include all of NRG's foreign subsidiaries and certain domestic subsidiaries, including GenOn and its subsidiaries and NRG Yield, Inc. and its subsidiaries.

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



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

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

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

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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Three Months Ended September 30, 2014

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	3,216		$	1,375		$	—		$	(22	)	$	4,569
Operating Costs and Expenses
Cost of operations	2,506			761			(5		)	16			3,278
Depreciation and amortization	216			154			5			—			375
Impairment losses	—			70			—			—			70
Selling, general and administrative	110			82			66			—			258
Acquisition-related transaction and integration costs	1			4			12			—			17
Development activity expenses	—			8			14			—			22
Total operating costs and expenses	2,833			1,079			92			16			4,020
Operating Income/(Loss)	383			296			(92		)	(38		)	549
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	186			15			319			(520		)	—
Equity in earnings of unconsolidated affiliates	3			19			—			(4		)	18
Other income/(loss), net	1			1			(19		)	14			(3		)
Loss on debt extinguishment	—			—			(13		)	—			(13		)
Interest expense	(4		)	(132		)	(143		)	(1		)	(280		)
Total other income/(expense)	186			(97		)	144			(511		)	(278		)
Income Before Income Taxes	569			199			52			(549		)	271
Income tax expense/(benefit)	169			42			(122		)	—			89
Net Income	400			157			174			(549		)	182
Less: Net income attributable to noncontrolling interest	—			37			6			(29		)	14
Net Income attributable to NRG Energy, Inc.	$	400		$	120		$	168		$	(520	)	$	168


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Nine Months Ended September 30, 2014

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	8,009		$	3,755		$	—		$	(88	)	$	11,676
Operating Costs and Expenses
Cost of operations	6,347			2,497			2			(18		)	8,828
Depreciation and amortization	625			458			13			—			1,096
Impairment losses	—			70			—			—			70
Selling, general and administrative	321			221			210			—			752
Acquisition-related transaction and integration costs	1			12			56			—			69
Development activity expenses	—			25			37			—			62
Total operating costs and expenses	7,294			3,283			318			(18		)	10,877
Gain on sale of assets	—			19			—			—			19
Operating Income/(Loss)	715			491			(318		)	(70		)	818
Other Income/(Expense)
Equity in earnings of consolidated subsidiaries	287			9			499			(795		)	—
Equity in earnings of unconsolidated affiliates	13			37			—			(11		)	39
Other income/(loss), net	5			9			(14		)	13			13
Loss on debt extinguishment	—			(9		)	(85		)	—			(94		)
Interest expense	(15		)	(359		)	(435		)				(809		)
Total other income/(expense)	290			(313		)	(35		)	(793		)	(851		)
Income/(Loss) Before Income Taxes	1,005			178			(353		)	(863		)	(33		)
Income tax expense/(benefit)	279			36			(383		)	—			(68		)
Net Income	726			142			30			(863		)	35
Less: Net income attributable to noncontrolling interest	—			73			15			(68		)	20
Net Income attributable to NRG Energy, Inc.	$	726		$	69		$	15		$	(795	)	$	15


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME

For the Three Months Ended September 30, 2014

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Net Income	$	400		$	157		$	174		$	(549	)	$	182
Other comprehensive (loss)/income, net of tax
Unrealized (loss)/gain on derivatives, net	(7		)	2			3			6			4
Foreign currency translation adjustments, net	—			(9		)	3			—			(6		)
Available-for-sale securities, net	—			(21		)	19			—			(2		)
Defined benefit plan, net	—			55			(58		)	—			(3		)
Other comprehensive (loss)/income	(7		)	27			(33		)	6			(7		)
Comprehensive income	393			184			141			(543		)	175
Less: Comprehensive income/(loss) attributable to noncontrolling interest	—			17			(17		)	17			17
Comprehensive income attributable to NRG Energy, Inc.	393			167			158			(560		)	158
Dividends for preferred shares	—			—			2			—			2
Comprehensive income available for common stockholders	$	393		$	167		$	156		$	(560	)	$	156


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

For the Nine Months Ended September 30, 2014

(Unaudited)



	Guarantor Subsidiaries		Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations(a)			Consolidated
	(In millions)
Net Income	$	726	$	142		$	30		$	(863	)	$	35
Other comprehensive income/(loss), net of tax
Unrealized gain/(loss) on derivatives, net	1		(24		)	—			(1		)	(24		)
Foreign currency translation adjustments, net	—		(4		)	1			—			(3		)
Available-for-sale securities, net	—		3			(1		)	—			2
Defined benefit plan, net	—		42			(33		)	—			9
Other comprehensive income/(loss)	1		17			(33		)	(1		)	(16		)
Comprehensive income/(loss)	727		159			(3		)	(864		)	19
Less: Comprehensive income/(loss) attributable to noncontrolling interest	—		10			(8		)	12			14
Comprehensive income attributable to NRG Energy, Inc.	727		149			5			(876		)	5
Dividends for preferred shares	—		—			7			—			7
Comprehensive income/(loss) available for common stockholders	$	727	$	149		$	(2	)	$	(876	)	$	(2	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

September 30, 2014

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
ASSETS	(In millions)
Current Assets
Cash and cash equivalents	$	18		$	1,624		$	311		$	—		$	1,953
Funds deposited by counterparties	—			3			—			—			3
Restricted cash	12			326			1			—			339
Accounts receivable, net	1,257			297			—			—			1,554
Inventory	463			588			—			—			1,051
Derivative instruments	876			690			—			(169		)	1,397
Cash collateral paid in support of energy risk management activities	173			202			—			—			375
Accounts receivable - affiliate	6,808			960			(5,313		)	(2,447		)	8
Deferred income taxes	—			93			(14		)	—			79
Renewable energy grant receivable	—			614			—			—			614
Current assets held-for-sale	—			32			—			—			32
Prepayments and other current assets	97			331			39			—			467
Total current assets	9,704			5,760			(4,976		)	(2,616		)	7,872
Net property, plant and equipment	8,736			13,314			156			(25		)	22,181
Other Assets
Investment in subsidiaries	478			431			22,399			(23,308		)	—
Equity investments in affiliates	(18		)	919			—			(104		)	797
Notes receivable, less current portion	—			69			42			(31		)	80
Goodwill	2,065			387			—			—			2,452
Intangible assets, net	932			1,952			4			(8		)	2,880
Nuclear decommissioning trust fund	569			—			—			—			569
Derivative instruments	221			252			2			(48		)	427
Deferred income tax	—			468			1,008			—			1,476
Non-current assets held-for-sale	—			54			—			—			54
Other non-current assets	102			610			569			—			1,281
Total other assets	4,349			5,142			24,024			(23,499		)	10,016
Total Assets	$	22,789		$	24,216		$	19,204		$	(26,140	)	$	40,069
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	2		$	833		$	50		$	(31	)	$	854
Accounts payable	772			299			27			—			1,098
Accounts payable — affiliate	1,105			1,789			(447		)	(2,447		)	—
Derivative instruments	847			687			—			(169		)	1,365
Cash collateral received in support of energy risk management activities	—			3			—			—			3
Deferred income taxes	6			—			(6		)	—			—
Current liabilities held-for-sale	—			23			—			—			23
Accrued expenses and other current liabilities	310			580			310			—			1,200
Total current liabilities	3,042			4,214			(66		)	(2,647		)	4,543
Other Liabilities
Long-term debt and capital leases	316			11,189			8,414			—			19,919
Nuclear decommissioning reserve	306			—			—			—			306
Nuclear decommissioning trust liability	323			—			—			—			323
Deferred income taxes	1,299			(1,039		)	(236		)	—			24
Derivative instruments	218			156			—			(48		)	326
Out-of-market contracts	115			1,130			—			—			1,245
Non-current liabilities held-for-sale	—			31			—			—			31
Other non-current liabilities	419			659			307			—			1,385
Total non-current liabilities	2,996			12,126			8,485			(48		)	23,559
Total liabilities	6,038			16,340			8,419			(2,695		)	28,102
3.625% convertible perpetual preferred stock	—			—			249			—			249
Redeemable noncontrolling interest in subsidiaries	—			28			—			—			28
Stockholders’ Equity	16,751			7,848			10,536			(23,445		)	11,690
Total Liabilities and Stockholders’ Equity	$	22,789		$	24,216		$	19,204		$	(26,140	)	$	40,069


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2014

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Cash Flows from Operating Activities
Net Cash Provided/(Used) by Operating Activities	$	1,378		$	(77	)	$	(2,019	)	$	1,832		$	1,114
Cash Flows from Investing Activities
(Payments for)/proceeds from intercompany loans to subsidiaries	(1,382		)	(450		)	1,832						—
Acquisition of businesses, net of cash acquired	—			(25		)	(2,807		)	—			(2,832		)
Capital expenditures	(16		)	(180		)	(479		)	—			(675		)
Increase in restricted cash, net				(52		)				—			(52		)
Decrease/(increase) in restricted cash — U.S. DOE projects	—			24			(3		)	—			21
Decrease in notes receivable	—			21			—			—			21
Investments in nuclear decommissioning trust fund securities	(475		)	—			—			—			(475		)
Proceeds from sales of nuclear decommissioning trust fund securities	463			—			—			—			463
Proceeds from renewable energy grants	—			431			—			—			431
Proceeds from sale of assets, net of cash disposed of	—			—			153			—			153
Cash proceeds to fund cash grant bridge loan payment	—			57			—			—			57
Other	(6		)	(16		)	(48		)	—			(70		)
Net Cash Used by Investing Activities	(1,416		)	(190		)	(1,352		)	—			(2,958		)
Cash Flows from Financing Activities
Proceeds from/(payments for) intercompany loans	—			—			1,832			(1,832		)	—
Payment of dividends to common and preferred stockholders	—			—			(140		)	—			(140		)
Net payments for settlement of acquired derivatives that include financing elements	—			(64		)	—			—			(64		)
Contributions from noncontrolling interest in subsidiaries	—			639			—			—			639
Proceeds from issuance of long-term debt	—			1,121			3,335			—			4,456
Proceeds from issuance of common stock	—			—			15			—			15
Payment of debt issuance and hedging costs	—			(28		)	(29		)	—			(57		)
Payments for short and long-term debt	—			(649		)	(2,659		)	—			(3,308		)
Net Cash Provided by Financing Activities	—			1,019			2,354			(1,832		)	1,541
Effect of exchange rate changes on cash and cash equivalents	—			2			—			—			2
Net (Decrease)/Increase in Cash and Cash Equivalents	(38		)	754			(1,017		)	—			(301		)
Cash and Cash Equivalents at Beginning of Period	56			870			1,328			—			2,254
Cash and Cash Equivalents at End of Period	$	18		$	1,624		$	311		$	—		$	1,953


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Three Months Ended September 30, 2013

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	2,463		$	1,015		$	—		$	12		$	3,490
Operating Costs and Expenses
Cost of operations	1,769			579			(6		)	31			2,373
Depreciation and amortization	214			110			3			—			327
Selling, general and administrative	115			55			37			6			213
Acquisition-related transaction and integration costs	—			14			12			—			26
Development activity expenses	—			12			12			—			24
Total operating costs and expenses	2,098			770			58			37			2,963
Operating Income/(Loss)	365			245			(58		)	(25		)	527
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries	29			(10		)	291			(310		)	—
Equity in (losses)/earnings of unconsolidated affiliates	(10		)	10			—			(5		)	(5		)
Other income, net	3			5			1			(4		)	5
Loss on debt extinguishment	—			(1		)	—			—			(1		)
Interest expense	(7		)	(87		)	(137		)	3			(228		)
Total other income/(expense)	15			(83		)	155			(316		)	(229		)
Income Before Income Taxes	380			162			97			(341		)	298
Income tax expense/(benefit)	126			64			(30		)	—			160
Net Income	254			98			127			(341		)	138
Less: Net income attributable to noncontrolling interest	—			43			8			(32		)	19
Net Income attributable to NRG Energy, Inc.	$	254		$	55		$	119		$	(309	)	$	119


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Nine Months Ended September 30, 2013

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations(a)			Consolidated
	(In millions)
Operating Revenues
Total operating revenues	$	6,224		$	2,390		$	—		$	(114	)	$	8,500
Operating Costs and Expenses
Cost of operations	4,674			1,586			1			(84		)	6,177
Depreciation and amortization	625			313			9			—			947
Selling, general and administrative	340			173			162			(5		)	670
Acquisition-related transaction and integration costs	—			55			40			—			95
Development activity expenses	—			25			38			—			63
Total operating costs and expenses	5,639			2,152			250			(89		)	7,952
Operating Income/(Loss)	585			238			(250		)	(25		)	548
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries	50			(14		)	335			(371		)	—
Equity in (losses)/earnings of unconsolidated affiliates	(8		)	16			—			(2		)	6
Other income, net	5			5			3			(4		)	9
Loss on debt extinguishment	—			(12		)	(38		)	—			(50		)
Interest expense	(17		)	(228		)	(388		)	3			(630		)
Total other income/(expense)	30			(233		)	(88		)	(374		)	(665		)
Income/(Loss) Before Income Taxes	615			5			(338		)	(399		)	(117		)
Income tax expense/(benefit)	212			(10		)	(257		)	—			(55		)
Net Income/(Loss)	403			15			(81		)	(399		)	(62		)
Less: Net income attributable to noncontrolling interest	—			48			8			(29		)	27
Net Income/(Loss) attributable to NRG Energy, Inc.	$	403		$	(33	)	$	(89	)	$	(370	)	$	(89	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME

For the Three Months Ended September 30, 2013

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)		Eliminations^(a)			Consolidated
	(In millions)
Net Income	$	254		$	98		$	127	$	(341	)	$	138
Other comprehensive (loss)/income, net of tax
Unrealized (loss)/gain on derivatives, net	(13		)	(8		)	17		(12		)	(16		)
Foreign currency translation adjustments, net	—			4			1		—			5
Other comprehensive (loss)/income	(13		)	(4		)	18		(12		)	(11		)
Comprehensive income	241			94			145		(353		)	127
Less: Comprehensive income attributable to noncontrolling interest	—			29			9		(20		)	18
Comprehensive income attributable to NRG Energy, Inc.	241			65			136		(333		)	109
Dividends for preferred shares	—			—			2		—			2
Comprehensive income available for common stockholders	$	241		$	65		$	134	$	(333	)	$	107


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

For the Nine Months Ended September 30, 2013

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated
	(In millions)
Net Income/(Loss)	$	403		$	15		$	(81	)	$	(399	)	$	(62	)
Other comprehensive (loss)/income, net of tax
Unrealized (loss)/gain on derivatives, net	(54		)	41			9			12			8
Foreign currency translation adjustments, net	—			(11		)	(3		)	—			(14		)
Available-for-sale securities, net	—			—			2			—			2
Defined benefit plan	—			25			—			—			25
Other comprehensive (loss)/income	(54		)	55			8			12			21
Comprehensive income/(loss)	349			70			(73		)	(387		)	(41		)
Less: Comprehensive income attributable to noncontrolling interest	—			39			9			(22		)	26
Comprehensive income/(loss) attributable to NRG Energy, Inc.	349			31			(82		)	(365		)	(67		)
Dividends for preferred shares	—			—			7			—			7
Comprehensive income/(loss) available for common stockholders	$	349		$	31		$	(89	)	$	(365	)	$	(74	)


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

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
ASSETS	(In millions)
Current Assets
Cash and cash equivalents	$	56		$	870		$	1,328		$	—		$	2,254
Funds deposited by counterparties	7			56			—			—			63
Restricted cash	12			252			4			—			268
Accounts receivable, net	965			249			—			—			1,214
Inventory	436			462			—			—			898
Derivative instruments	866			470			—			(8		)	1,328
Accounts receivable - affiliate	4,584			132			(3,834		)	(874		)	8
Deferred income taxes	—			41			217			—			258
Cash collateral paid in support of energy risk management activities	214			62			—			—			276
Renewable energy grant receivable	—			539			—			—			539
Current assets held-for-sale	—			19			—			—			19
Prepayments and other current assets	194			228			32			17			471
Total current assets	7,334			3,380			(2,253		)	(865		)	7,596
Net Property, Plant and Equipment	9,116			10,604			153			(22		)	19,851
Other Assets
Investment in subsidiaries	32			422			18,266			(18,720		)	—
Equity investments in affiliates	(30		)	583			—			(100		)	453
Capital leases and notes receivable, less current portion	—			62			105			(94		)	73
Goodwill	1,973			12			—			—			1,985
Intangible assets, net	925			232			4			(21		)	1,140
Nuclear decommissioning trust fund	551			—			—			—			551
Deferred income taxes				681			521			—			1,202
Derivative instruments	110			202			—			(1		)	311
Other non-current assets	76			281			383			—			740
Total other assets	3,637			2,475			19,279			(18,936		)	6,455
Total Assets	$	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
Accounts payable	652			352			34			—			1,038
Accounts payable — affiliate	1,350			760			(1,253		)	(857		)	—
Derivative instruments	859			204			—			(8		)	1,055
Cash collateral received in support of energy risk management activities	6			57			—			—			63
Accrued expenses and other current liabilities	297			410			291			—			998
Total current liabilities	3,165			2,812			(908		)	(865		)	4,204
Other Liabilities
Long-term debt and capital leases	317			7,837			7,707			(94		)	15,767
Nuclear decommissioning reserve	294			—			—			—			294
Nuclear decommissioning trust liability	324			—			—			—			324
Deferred income taxes	1,024			(1,002		)	—			—			22
Derivative instruments	147			49			—			(1		)	195
Out-of-market contracts	127			1,050			—			—			1,177
Other non-current liabilities	412			615			174			—			1,201
Total non-current liabilities	2,645			8,549			7,881			(95		)	18,980
Total liabilities	5,810			11,361			6,973			(960		)	23,184
3.625% Preferred Stock	—			—			249			—			249
Redeemable noncontrolling interest in subsidiaries	—			2			—			—			2
Stockholders’ Equity	14,277			5,096			9,957			(18,863		)	10,467
Total Liabilities and Stockholders’ Equity	$	20,087		$	16,459		$	17,179		$	(19,823	)	$	33,902


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Nine Months Ended September 30, 2013

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Cash Flows from Operating Activities
Net Cash Provided/(Used) by Operating Activities	$	1,334		$	135		$	(1,800	)	$	1,154		$	823
Cash Flows from Investing Activities
Intercompany loans to subsidiaries	(1,158		)	4			1,154			—			—
Acquisition of businesses, net of cash acquired	—			(59		)	(315		)	—			(374		)
Capital expenditures	(154		)	(1,388		)	(39		)	—			(1,581		)
(Increase)/decrease in restricted cash, net	(7		)	(61		)	1			—			(67		)
Increase in restricted cash — U.S. DOE projects	—			(18		)	(2		)	—			(20		)
Decrease/(increase) in notes receivable	2			(16		)	(8		)	—			(22		)
Investments in nuclear decommissioning trust fund securities	(369		)	—			—			—			(369		)
Proceeds from sales of nuclear decommissioning trust fund securities	344			—			—			—			344
Proceeds from renewable energy grants	—			52			—			—			52
Proceeds from sale of assets	13			—			—			—			13
Other	7			(1		)	(13		)	—			(7		)
Net Cash (Used)/Provided by Investing Activities	(1,322		)	(1,487		)	778			—			(2,031		)
Cash Flows from Financing Activities
Proceeds from intercompany loans	—			—			1,154			(1,154		)	—
Payment of dividends to preferred stockholders	—			—			(113		)	—			(113		)
Payment for treasury stock	—			—			(25		)	—			(25		)
Net (payment for)/receipts from settlement of acquired derivatives that include financing elements	(67		)	244			—			—			177
Proceeds from issuance of long-term debt	—			1,120			485			—			1,605
Proceeds from issuance of common stock	—			—			14			—			14
Sale proceeds and other contributions from noncontrolling interest in subsidiaries	—			504			—			—			504
Payment of debt issuance costs	—			(9		)	(34		)	—			(43		)
Payments for short and long-term debt	—			(654		)	(214		)	—			(868		)
Net Cash (Used)/Provided by Financing Activities	(67		)	1,205			1,267			(1,154		)	1,251
Effect of exchange rate changes on cash and cash equivalents	—			(1		)	—			—			(1		)
Net (Decrease)/Increase in Cash and Cash Equivalents	(55		)	(148		)	245			—			42
Cash and Cash Equivalents at Beginning of Period	78			1,258			751			—			2,087
Cash and Cash Equivalents at End of Period	$	23		$	1,110		$	996		$	—		$	2,129


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

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

As you read this discussion and analysis, refer to NRG's Condensed Consolidated Statements of Operations to this Form 10-Q, which present the results of operations for the three and nine months ended September 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 section, including how regulation, weather, and other factors affect NRG's business; and Critical Accounting Policies and Estimates section.

The discussion and analysis below has been organized as follows:


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


•	Results of operations;


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


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

Executive Summary

Introduction and Overview

The following table summarizes NRG's global generation portfolio as of September 30, 2014, by operating segment:



	Global Generation Portfolio by Operating Segment^(a)
	(In MW)
	Gulf Coast	East		West	Renewables		NRG Yield^(b)		Total Domestic		Other(Inter-national)	Total Global
Primary Fuel-type
Natural gas	8,932	7,413		7,617	—		1,393		25,355		144	25,499
Coal	5,689	11,125		—	—		—		16,814		605	17,419
Oil	—	5,818		—	—		190		6,008		—	6,008
Nuclear	1,176	—		—	—		—		1,176		—	1,176
Wind	—	—		—	2,072		1,048		3,120		—	3,120
Utility Scale Solar	—	—		—	802		343		1,145		—	1,145
Distributed Solar	—	—		—	37		10		47		—	47
Total generation capacity	15,797	24,356		7,617	2,911		2,984		53,665		749	54,414
Capacity attributable to noncontrolling interest	—	(40	)	—	(630	)	(1,334	)	(2,004	)	—	(2,004	)
Total net generation capacity	15,797	24,316		7,617	2,281		1,650		51,661		749	52,410

Under Construction
Natural gas	330	—		—	—		—		330		—	330
Utility Scale Solar	—	—		—	31		—		31		—	31
Distributed Solar	—	—		—	8		—		8		—	8
Total under construction	330	—		—	39		—		369		—	369

(a) Includes 97 active fossil fuel and nuclear plants, 14 Utility Scale Solar facilities, 36 wind farms and multiple Distributed Solar facilities. 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.

(b) 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.

The Company has begun to reorganize its existing businesses and personnel on the basis of their key target customer segments in order to better serve those energy consumers with the type and quality of energy services that each segment demands: (i) NRG Business, primarily representing the Company’s existing wholesale operations, commercial operations, reliability and demand side management business, engineering, procurement and construction (EPC) function, distributed generation, energy services and other critical related functions serving commercial and industrial customers and other load serving entities; (ii) NRG Home, primarily representing the Company’s conventional retail business, residential solar business and personal power products and services aimed at homeowners and other individual energy consumers; and (iii) NRG Renew, primarily representing the renewable development company, as well as the operations of the existing renewable assets owned by NRG Yield. NRG Carbon 360, formerly Petra Nova, and NRG eVgo, two distinct businesses with close customer or asset connections to NRG’s core businesses, have dedicated management and are organized separately within NRG because of their distinct capital structure, success metrics and competitive environment. These five companies, plus NRG Yield, collectively will represent the “NRG Group of Companies”.

NRG Yield

NRG Yield, Inc. is a publicly traded dividend growth-oriented company formed to serve as the primary vehicle through which the NRG Group of Companies, supported by NRG Renew and NRG Business, owns, operates and acquires diversified contracted renewable and conventional generation and thermal infrastructure assets. As of September 30, 2014, NRG owns 55.3% of the outstanding common stock of NRG Yield, Inc. NRG Yield, Inc.’s contracted generation portfolio collectively represents 2,861 net MW. Each of the assets sells substantially all of its output pursuant to long-term, fixed price offtake agreements with creditworthy counterparties. NRG Yield, Inc. also owns thermal infrastructure assets with an aggregate steam and chilled water capacity of 1,346 net MWt and electric generation capacity of 123 net MW. These thermal infrastructure assets provide steam, hot water and/or chilled water, and in some instances electricity, to commercial businesses, universities, hospitals and governmental units in multiple locations, principally through long-term contracts or pursuant to rates regulated by state utility commissions.

NRG's Strategy

NRG's strategy, encapsulated in “Enhance Generation, Expand Retail and Go Green while engaging in Smart Capital Allocation” is designed 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 intended to enable the Company to achieve substantial sustainable growth at reasonable margins notwithstanding long-term weakness in fundamental supply-demand dynamics for conventional generation and load while continuing the Company’s commitment to safety for its employees, customers and partners and the provision of safe, affordable, reliable and increasingly sustainable energy for its customers.

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, the Company expects energy consumers to demand increased personal control over their energy choices.

To address these trends and effectuate the Company’s strategy, NRG remains focused on: (i) excellence in operating performance of its existing assets including repowering its power generation assets at premium sites and optimal hedging of generation assets and retail load operations; (ii) serving the energy needs of end-use residential, commercial and industrial customers in competitive markets through multiple brands and channels with a variety of retail energy products and services differentiated by innovative features, premium service, sustainability, and loyalty/affinity programs; (iii) investing in, and deploying, alternative energy technologies both in its wholesale portfolio through its wind and solar portfolio and, particularly, in and around its Retail Business and its customers as it transforms this part of its business into a technology-driven provider of retail energy services; and (iv) engaging in a proactive capital allocation plan focused on achieving the regular return of and on stockholder capital within the dictates of prudent balance sheet management; including pursuing selective acquisitions, joint ventures, divestitures and investments. The Company's progress in each of these areas are more fully described in Item 1, Business — New and On-going Company Initiatives and in Management's Discussion and Analysis of Financial Condition and Results of Operations, New and On-going Company Initiatives 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 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 and effluent guidelines. 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 owners of power plants and participants in wholesale and retail energy markets, certain NRG entities are subject to regulation by various federal and state government agencies. These include the 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

Nuclear Regulatory Commission Approves Final Rule on Storage of Spent Fuel — On August 26, 2014, the NRC revised its generic determination regarding the environmental impacts of the continued storage of spent nuclear fuel beyond a reactor’s licensed life for operation and prior to ultimate disposal and approved a final rule. Upon the effective date of the final rule, the NRC approved lifting its suspension of final licensing actions on nuclear power plant licenses and renewals.

East Region

PJM

New Jersey and Maryland’s Generator Contracting Programs — The New Jersey Board of Public Utilities and the Maryland Public Service Commission awarded long-term power purchase contracts to generation developers to encourage the construction of new generation capacity in the respective States. The constitutionality of the long-term contracts was challenged and the U.S. District Court for the District of New Jersey (in an October 25, 2013 decision) and the U.S. District Court for the District of Maryland (in an October 24, 2013 decision) found that the respective contracts violated the Supremacy Clause of the U.S. Constitution and were preempted. On June 30, 2014, the U.S. Court of Appeals for the Fourth Circuit affirmed the Maryland District Court's decision. On September 11, 2014, the U.S. Court of Appeals for the Third Circuit affirmed the New Jersey District Court's decision. 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 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 from three to one. On May 9, 2014, FERC rejected PJM’s proposed changes to address replacement capacity and incremental auction design, but established a Section 206 proceeding and technical conference to find a just and reasonable outcome. On August 18, 2014, PJM requested that FERC defer further action in the proceeding. The Section 206 proceeding and technical conference could have a material impact on future PJM capacity prices.

Capacity Performance Proposal — On October 7, 2014, PJM issued a proposal to substantially revamp its capacity market. If approved by the PJM Board of Directors and by FERC, future annual capacity auctions would procure two categories of capacity resources: “Capacity Performance” resources and “Base Capacity” resources. Under the proposal, only resources with a firm fuel supply would be eligible to supply the Capacity Performance product. PJM is likely to file its proposal at FERC in November 2014. Should the proposal be approved by FERC, it is likely to have a material impact on future PJM capacity prices.

New York

Demand Curve Reset and the Lower Hudson Valley Capacity Zone — On 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 New York, as part of the NYISO’s triennial adjustment of its capacity market parameters for the 2014-2017 periods. The State of New York, NYSPSC and Central Hudson Gas & Electric Corp. have challenged the FERC Order before the U.S. Court of Appeals for the Second Circuit. The U.S. Court of Appeals for the Second Circuit held oral argument on September 12, 2014. The matter remains pending.

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 project is under challenge at the PUCT by the Company and Calpine and a hearing was held on October 17, 2014; a final decision on the challenge may be made by the end of the year. The licensing proceeding to allow the utility to move forward with the project (Certificate of Convenience and Necessity, or CCN) has yet to be initiated.

Operating Reserve Demand Curve Implementation — At the direction of the PUCT, ERCOT implemented an operating reserve demand curve, known as ORDC B+, on June 1, 2014. ORDC B+ simulates real-time co-optimization of energy and reserves and uses price adders during scarcity conditions to reflect price formation outcomes expected under real-time co-optimization. Under ORDC B+, real time energy price could rise to $9,000 per MWh during extreme scarcity events (due to value of lost load assumptions in the price curve), despite the system wide offer cap of $7,000 per MWh (which was raised from $5,000 in June 2014); the offer cap 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 Company supported the complaint. On July 22, 2014, FERC issued an Order denying the complaint in part and granting it in part. FERC found that the Tariff was unjust and unreasonable because it did not allow RMR Generators to obtain compensation for their fixed costs, which are recovered as depreciation expense, return on rate base and associated taxes. The matter is pending rehearing.

Changes in Accounting Standards

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

Consolidated Results of Operations

The following table provides selected financial information for the Company:



	Three months ended September 30,								Nine months ended September 30,
(In millions except otherwise noted)	2014			2013			Change %		2014			2013			Change %
Operating Revenues
Energy revenue^(a)	$	1,462		$	931		57	%	$	4,194		$	2,627		60	%
Capacity revenue ^(a)	533			534			—		1,597			1,295			23
Retail revenue	2,324			1,999			16		5,728			4,805			19
Mark-to-market for economic hedging activities	153			(75		)	304		(226		)	(360		)	37
Contract amortization	(11		)	(3		)	(267	)	(5		)	(32		)	84
Other revenues ^(b)	108			104			4		388			165			135
Total operating revenues	4,569			3,490			31		11,676			8,500			37
Operating Costs and Expenses
Generation cost of sales^(a)	1,191			999			19		3,564			2,588			38
Retail cost of sales^(a)	1,336			879			52		3,209			2,134			50
Mark-to-market for economic hedging activities	79			(22		)	459		87			(142		)	161
Contract and emissions credit amortization ^(c)	6			9			(33	)	27			25			8
Other cost of operations	666			508			31		1,941			1,572			23
Total cost of operations	3,278			2,373			38		8,828			6,177			43
Depreciation and amortization	375			327			15		1,096			947			16
Impairment losses	70			—			N/M		70			—			N/M
Selling, general and administrative	258			213			21		752			670			12
Acquisition-related transaction and integration costs	17			26			(35	)	69			95			(27	)
Development activity expenses	22			24			(8	)	62			63			(2	)
Total operating costs and expenses	4,020			2,963			36		10,877			7,952			37
Gain on sale of assets	—			—			—		19			—			N/M
Operating Income	549			527			4		818			548			49
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	18			(5		)	460		39			6			N/M
Other (expense)/income, net	(3		)	5			(160	)	13			9			44
Loss on debt extinguishment	(13		)	(1		)	N/M		(94		)	(50		)	88
Interest expense	(280		)	(228		)	23		(809		)	(630		)	28
Total other expense	(278		)	(229		)	21		(851		)	(665		)	28
Income/(Loss) before Income Taxes	271			298			(9	)	(33		)	(117		)	72
Income tax expense/(benefit)	89			160			(44	)	(68		)	(55		)	(24	)
Net Income/(Loss)	182			138			32		35			(62		)	156
Less: Net income attributable to noncontrolling interest	14			19			(26	)	20			27			(26	)
Net Income/(Loss) Attributable to NRG Energy, Inc.	$	168		$	119		41		$	15		$	(89	)	117
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	$	4.06		$	3.58		13	%	$	4.55		$	3.67		24	%

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

(b) Includes unrealized trading gains and losses.

N/M - Not meaningful.

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

Income before income taxes — The pre-tax income of $271 million for the three months ended September 30, 2014, compared to pre-tax income of $298 million for the three months ended September 30, 2013, primarily reflects:


•	an increase in gross margin of $204 million comprised of an increase in Renewables gross margin of $80 million, an increase Conventional Generation gross margin of $46 million, an increase in Yield gross margin of $43 million and an increase in Retail gross margin of $35 million;


•	a current year increase from net mark to market results for economic hedges activity of $127 million;

offset by:


•	a net increase in operating costs of $312 million including operations and maintenance expense, depreciation and amortization, impairment losses, selling, general and administrative costs, and acquisition related costs

Net income — The increase in net income of $44 million primarily reflects the drivers discussed above, including an income tax expense for the three months ended September 30, 2014 of $89 million, compared to $160 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 September 30, 2014 and 2013:



	Average on Peak Power Price ($/MWh) ^(a)
	Three months ended September 30,
Region	2014		2013
Gulf Coast ^(b)
ERCOT - Houston	$	38.58	$	43.55
ERCOT - North	37.96		38.58
MISO - Louisiana Hub ^(c)	39.15		38.41
East
NY J/NYC	41.19		66.64
NY A/West NY	43.02		53.83
NEPOOL	41.28		53.37
PEPCO (PJM)	45.25		54.35
PJM West Hub	41.34		47.97
West
CAISO - NP15	48.47		41.62
CAISO - SP15	49.16		46.38

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

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

(c) 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.



	Three months ended September 30, 2014
	Conventional Generation
(In millions except otherwise noted)	Gulf Coast			East			West			Subtotal			Renewables			NRG Yield			Eliminations/Corporate			Consolidated Total
Energy revenue	$	790		$	874		$	113		$	1,777		$	192		$	54		$	(561	)	$	1,462
Capacity revenue	78			324			110			512			(37		)	65			(7		)	533
Other revenue	28			24			1			53			2			48			5			108
Generation revenue	896			1,222			224			2,342			157			167			(563		)	2,103
Generation cost of sales	(525		)	(558		)	(85		)	(1,168		)	(3		)	(20		)	—			(1,191		)
Generation gross margin	$	371		$	664		$	139		$	1,174		$	154		$	147

Business Metrics
MWh sold (in thousands) ^(a)	19,720			12,161			1,439						1,782			715
MWh generated (in thousands)	16,888			14,097			1,919						2,116			1,467
(a) MWh sold excludes generation at facilities that generate revenue under capacity agreements.



	Three months ended September 30, 2013
	Conventional Generation
(In millions except otherwise noted)	Gulf Coast			East			West			Subtotal			Renewables			NRG Yield			Eliminations/Corporate			Consolidated Total
Energy revenue	$	824		$	698		$	34		$	1,556		$	66		$	41		$	(732	)	$	931
Capacity revenue	106			325			72			503			—			57			(26		)	534
Other revenue	19			32			1			52			9			29			14			104
Generation revenue	949			1,055			107			2,111			75			127			(744		)	1,569
Generation cost of sales	(535		)	(419		)	(29		)	(983		)	(1		)	(23		)	8			(999		)
Generation gross margin	$	414		$	636		$	78		$	1,128		$	74		$	104

Business Metrics
MWh sold (in thousands) ^(a)	18,457			9,971			410						540			199
MWh generated (in thousands)	17,383			9,527			905						571			995
(a) MWh sold excludes generation at facilities that generate revenue under capacity agreements.

	Three months ended September 30,
Weather Metrics	Gulf Coast			East			West
2014
CDDs ^(a)	3,118			1,987			803
HDDs ^(a)	6			239			3
2013
CDDs	3,193			2,148			613
HDDs	—			304			17
10 year average
CDDs	3,156			2,178			591
HDDs	8			257			26

(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.

Conventional Generation gross margin — increased by $46 million, including intercompany sales, during the three months ended September 30, 2014, compared to the same period in 2013, due to:



Gulf Coast region	$	(43	)
East region	28
West region	61
	$	46

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



Lower gross margin from a decrease in average realized prices	$	(21	)
Lower gross margin from an 8% decrease in coal generation from lower economic dispatch due to higher outage hours	(17		)
Changes in commercial optimization activities and other	(5		)
	$	(43	)

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



Higher gross margin from the acquisition of EME in April 2014	$	109
Lower gross margin from a 13% decrease in generation and a 6% decrease in realized energy prices	(35		)
Lower gross margin from a 17% decrease in PJM hedged capacity prices	(53		)
Higher gross margin from new load-serving contracts in 2014	19
Changes in commercial optimization activities and other	(12		)
	$	28

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



Higher gross margin from the acquisition of EME in April 2014	$	38
Higher capacity gross margin due primarily to increases in realized prices	17
Other	6
	$	61

Retail gross margin

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



	Three months ended September 30,
(In millions except otherwise noted)	2014		2013
Mass revenues	$	1,666	$	1,374
Commercial and Industrial revenues	445		535
Supply management and other revenues	214		91
Retail revenue ^(a)(b)	2,325		2,000
Retail cost of sales ^(c)	1,919		1,629
Retail gross margin	$	406	$	371

Business Metrics
Electricity sales volume — GWh
Mass	13,293		10,902
Commercial and Industrial ^(d)	6,060		7,378
Electricity sales volume — GWh
Texas	15,856		15,708
All other regions	3,497		2,572
Average retail customers count (in thousands, metered locations)
Mass ^(e)	2,833		2,157
Commercial and Industrial ^(d)	90		101
Retail customers count (in thousands, metered locations)
Mass ^(e)	2,830		2,153
Commercial and Industrial ^(d)	87		106


(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 $1 million in 2014 and 2013 representing sales from Retail to the Texas region.


(c)	Includes intercompany purchases of $583 million and $750 million in 2014 and 2013.


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


(e)	Excludes utility partner and natural gas customers.


•	Retail gross margin — Retail gross margin increased $35 million for the three months ended September 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	$	29
Increase primarily due to higher revenues from home and business services and an increase in mass customer counts	11
Other	(5		)
	$	35

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 $154 million for the three months ended September 30, 2014, compared to gross margin of $74 million for the same period in 2013. The increase in gross margin was primarily a result of the EME acquisition in April 2014 as well as the CVSR and Ivanpah projects which reached commercial operations in late 2013 and early 2014.

NRG Yield gross margin

NRG Yield had gross margin of $147 million for the three months ended September 30, 2014, compared to gross margin of $104 million for the same period in 2013, which related primarily to the acquisition of the Alta Wind Assets in August 2014 as well as the acquisition of Energy Systems Company in December 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 increased by $127 million during the three months ended September 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 September 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 losses/(gains) on settled positions related to economic hedges	$	—		$	126	$	11		$	(3	)	$	1		$	122		$	257
Reversal of acquired (gain)/loss positions related to economic hedges	—			—		(70		)	2			—			—			(68		)
Net unrealized gains/(losses) on open positions related to economic hedges	1			9		93			(2		)	(1		)	(136		)	(36		)
Total mark-to-market gains/(losses) in operating revenues	$	1		$	135	$	34		$	(3	)	$	—		$	(14	)	$	153
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(138	)	$	1	$	1		$	—		$	—		$	(122	)	$	(258	)
Reversal of acquired (gain)/loss positions related to economic hedges	(22		)	—		3			—			—			—			(19		)
Net unrealized gains/(losses) on open positions related to economic hedges	84			2		(24		)	—			—			136			198
Total mark-to-market (losses)/gains in operating costs and expenses	$	(76	)	$	3	$	(20	)	$	—		$	—		$	14		$	(79	)


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



	Three months ended September 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	$	(1	)	$	55	$	4		$	(1	)	$	—		$	(52	)	$	5
Reversal of acquired (gain)/loss positions related to economic hedges	—			—		(82		)	1			—			—			(81		)
Net unrealized gains/(losses) on open positions related to economic hedges	3			115		34			2			(1		)	(152		)	1
Total mark-to-market gains/(losses) in operating revenues	$	2		$	170	$	(44	)	$	2		$	(1	)	$	(204	)	$	(75	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(116	)	$	9	$	2		$	—		$	—		$	52		$	(53	)
Reversal of acquired (gain)/loss positions related to economic hedges	(8		)	—		7			—			—			—			(1		)
Net unrealized (losses)/gains on open positions related to economic hedges	(66		)	5		(15		)	—			—			152			76
Total mark-to-market (losses)/gains in operating costs and expenses	$	(190	)	$	14	$	(6	)	$	—		$	—		$	204		$	22


(a)	Represents the elimination of the intercompany activity between Retail, 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 acquired gain or loss positions were valued based upon the forward prices on the acquisition date.

For the three months ended September 30, 2014, the $153 million gains in operating revenues from economic hedge positions was driven by the reversal of previously recognized unrealized losses on contracts that settled during the period slightly offset by a decrease in value of open positions as a result of increases in power prices. The $79 million loss in operating costs and expenses from economic hedge positions was driven by the reversal of previously recognized unrealized gains on contracts that settled during the period largely offset by an increase in value of open positions as a result of increases in ERCOT heat rates partially offset by decreases in coal prices.

For the three months ended September 30, 2013, the $75 million loss in operating revenues from economic hedge positions was driven primarily by the reversal of previously recognized unrealized gains on acquired contracts that settled during the period. The $22 million gain in operating costs and expenses from economic hedge positions was driven by an increase in value of open positions as a result of increases in ERCOT heat rates largely offset by the reversal of previously recognized unrealized gains on contracts that settled during the period.

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the three months ended September 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 September 30,
(In millions)	2014		2013
Trading gains
Realized	$	33	$	2
Unrealized	6		11
Total trading gains	$	39	$	13

Other Operating Costs



			Conventional Generation
	Retail		Gulf Coast		East		West		Renewables		NRG Yield		Eliminations/Corporate		Total
	(In millions)
Three months ended September 30, 2014	$	90	$	163	$	290	$	39	$	43	$	32	$	9	$	666
Three months ended September 30, 2013	74		139		222		33		10		21		9		508

Other operating costs increased by $158 million for the three months ended September 30, 2014, compared to the same period in 2013, due to:



Increase due to the acquisition of EME in April 2014	$	111
Increase in Gulf Coast operations and maintenance expense primarily due to increased normal maintenance at STP, and costs for the disposal of fixed assets at the STP and WA Parish plants	29
Increase in Renewables operations and maintenance expense related to Ivanpah and CVSR reaching commercial operations in late 2013 and early 2014	15
Decrease in East operations and maintenance expense due to a 13% decrease in generation and the sale of Kendall in the first quarter of 2014	(10		)
Increase in NRG Yield operations and maintenance expense due to the acquisition of Alta Wind	7
Other	6
	$	158

Depreciation and Amortization

Depreciation and amortization increased by $48 million for the three months ended September 30, 2014, compared to the same period in 2013, due primarily to $14 million from the acquisition of EME, $7 million from the acquisition of Alta Wind and $19 million for Ivanpah which reached commercial operations in January 2014.

Impairment Losses

For the three months ended September 30, 2014, the Company recorded impairment losses of $60 million related to the Osceola facility and $10 million related to certain solar panels, as described in Note 2, Summary of Significant Accounting Policies.

Selling, General and Administrative Expenses

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



	Three months ended September 30,
(In millions)	2014		2013
General and administrative expenses	$	160	$	134
Selling and marketing expenses	98		79
	$	258	$	213

General and administrative expenses increased by $26 million for the three months ended September 30, 2014 compared to the same period in 2013, due in part to the acquisition of EME in April 2014 and the expansion of the Residential Solar business as well as the presentation of Residential Solar expenses as development in prior periods. Selling and marketing expenses increased by $19 million compared to the prior year primarily due to the expansion of the Residential Solar business.

Acquisition-related Transaction and Integration Costs

NRG incurred transaction and integration costs of $17 million in the three months ended September 30, 2014, compared to $26 million for the same period in 2013.

Equity in Earnings of Unconsolidated Affiliates

NRG's equity in earnings of unconsolidated affiliates increased $23 million for the three months ended September 30, 2014 as compared to the same period in 2013, due primarily to $11 million from the acquisition of EME in April 2014.

Interest Expense

NRG's interest expense increased by $52 million compared to the same period in 2013 due to the following:



Increase in interest expense	(In millions)
Increase for issuance of 2022 and 2024 Senior Notes in January and April 2014	$	33
Reduction to capitalized interest for projects placed in service	19
Increase for the acquisition of EME in April 2014	14
Increase for the acquisition of Alta Wind in August 2014	12
Increase for issuance of Yield Convertible Notes and Senior Notes in February and August	9
Decrease for 7.625% and 8.5% Senior Notes due 2019 redeemed in February 2014	(31		)
Decrease in other interest expense	(4		)
	$	52

Income Tax Expense

For the three months ended September 30, 2014, NRG recorded an income tax expense of $89 million on pre-tax income of $271 million. For the same period in 2013, NRG recorded an income tax expense of $160 million on pre-tax income of $298 million. The effective tax rate was 32.8% and 53.7% for the three months ended September 30, 2014, and 2013, respectively.

For the three months ended September 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.

For the three months ended September 30, 2013, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to state and local income taxes.

Noncontrolling Interest

For the three months ended September 30, 2014, income 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 September 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 nine months ended September 30, 2014 and 2013

Loss before income taxes — The pre-tax loss of $33 million for the nine months ended September 30, 2014, compared to a pre-tax loss of $117 million for the nine months ended September 30, 2013, primarily reflects:


•	an increase in gross margin of $928 million comprised of an increase in Conventional Generation gross margin of $497 million, an increase in Renewables gross margin of $202 million, an increase in NRG Yield gross margin of $159 million, and an increase in Retail gross margin of $70 million;

offset by:


•	a net increase in operating costs of $644 million, including operations and maintenance expense, depreciation and amortization, impairment losses, 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 $95 million

Net Income — The increase in net income of $97 million primarily reflects the drivers discussed above, including an income tax benefit for the nine months ended September 30, 2014 of $68 million, compared to $55 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 nine months ended September 30, 2014 and 2013:



	Average on Peak Power Price ($/MWh) ^(a)
	Nine months ended September 30,
Region	2014		2013
Gulf Coast ^(b)
ERCOT - Houston	$	47.01	$	36.33
ERCOT - North	46.23		34.26
MISO - Louisiana Hub ^(c)	52.36		37.51
East
NY J/NYC	81.43		67.03
NY A/West NY	64.43		46.63
NEPOOL	84.26		62.81
PEPCO (PJM)	77.48		47.85
PJM West Hub	68.08		45.09
West
CAISO - NP15	51.41		40.09
CAISO - SP15	50.11		46.18

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

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

(c) 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.



	Nine months ended September 30, 2014
	Conventional Generation
(In millions except otherwise noted)	Gulf Coast			East			West			Subtotal			Renewables			NRG Yield			Eliminations/Corporate			Consolidated Total
Energy revenue	$	2,119		$	2,828		$	228		$	5,175		$	358		$	119		$	(1,458	)	$	4,194
Capacity revenue	198			962			267			1,427			1			185			(16		)	1,597
Other revenue	75			89			5			169			12			138			69			388
Generation revenue	2,392			3,879			500			6,771			371			442			(1,405		)	6,179
Generation cost of sales	(1,405		)	(1,882		)	(188		)	(3,475		)	(7		)	(73		)	(9		)	(3,564		)
Generation gross margin	$	987		$	1,997		$	312		$	3,296		$	364		$	369

Business Metrics
MWh sold (in thousands) ^(a)	48,814			37,141			2,426						4,486			1,828
MWh generated (in thousands)	45,747			38,905			3,640						4,837			4,070
(a) MWh sold excludes generation at facilities that generate revenue under capacity agreements.



	Nine months ended September 30, 2013
	Conventional Generation
(In millions except otherwise noted)	Gulf Coast			East			West			Subtotal			Renewables			NRG Yield			Eliminations/Corporate			Consolidated Total
Energy revenue	$	2,109		$	1,831		$	109		$	4,049		$	153		$	84		$	(1,659	)	$	2,627
Capacity revenue	260			789			208			1,257			—			76			(38		)	1,295
Other revenue	6			52			2			60			10			102			(7		)	165
Generation revenue	2,375			2,672			319			5,366			163			262			(1,704		)	4,087
Generation cost of sales	(1,340		)	(1,147		)	(80		)	(2,567		)	(1		)	(52		)	32			(2,588		)
Generation gross margin	$	1,035		$	1,525		$	239		$	2,799		$	162		$	210

Business Metrics
MWh sold (in thousands) ^(a)	48,146			27,386			1,246						2,121			934
MWh generated (in thousands)	45,341			26,542			2,165						1,767			2,488
(a) MWh sold excludes generation at facilities that generate revenue under capacity agreements.

	Nine months ended September 30,
Weather Metrics	Gulf Coast			East			West
2014
CDDs ^(a)	4,982			3,011			1,054
HDDs ^(a)	2,819			10,401			1,102
2013
CDDs	5,131			3,224			802
HDDs	2,410			9,464			1,465
10 year average
CDDs	5,266			3,273			744
HDDs	2,223			9,255			1,601

(a)

Conventional Generation gross margin — increased by $497 million including intercompany sales, during the nine months ended September 30, 2014, compared to the same period in 2013, due to:



Gulf Coast region	$	(48	)
East region	472
West region	73
	$	497

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



Lower gross margin from a decrease in average realized prices	$	(77	)
Lower gross margin from bi-lateral contracts with load serving entities, including the Retail entities	(26		)
Change in commercial optimization activities	39
Higher gross margin due to the acquisition of Gregory in August 2013	15
Higher gross margin from lower coal transportation costs	13
Other	(12		)
	$	(48	)

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



Higher gross margin from the acquisition of EME in April 2014	$	196
Higher gross margin due primarily to an 8% increase in generation and a 20% increase in realized energy prices	165
Higher gross margin from a 10% increase in New York hedged capacity prices as well as higher prices for the new Lower Hudson Valley Capacity Zone	70
Change in commercial optimization activities	29
Other	12
	$	472

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



Higher gross margin from the acquisition of EME in April 2014	$	67
Higher capacity gross margin due primarily to increases in realized prices	33
Lower gross margin due to the deactivation of the Contra Costa facility in 2013	(15		)
Lower gross margin primarily due to a 30% decrease in generation primarily due to increased dispatch from competing resources, including renewable resources.	(14		)
Other	2
	$	73

Retail gross margin

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



	Nine months ended September 30,
(In millions except otherwise noted)	2014		2013
Mass revenues	$	3,948	3,155
Commercial and Industrial revenues	1,325		1,485
Supply management and other revenues	459		168
Retail revenue ^(a)(b)	5,732		4,808
Retail cost of sales ^(c)	4,688		3,834
Retail gross margin	$	1,044	$	974

Business Metrics
Electricity sales volume — GWh
Mass	31,082		25,499
Commercial and Industrial ^(d)	17,745		20,550
Electricity sales volume — GWh
Texas	39,526		39,335
All other regions	9,301		6,715
Average retail customers count (in thousands, metered locations)
Mass ^(e)	2,618		2,141
Commercial and Industrial ^(d)	88		102
Retail customers count (in thousands, metered locations)
Mass ^(e)	2,830		2,153
Commercial and Industrial ^(d)	87		106


(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 $4 million and $3 million in 2014 and 2013, respectively, representing sales from Retail to the Texas region.


(c)	Includes intercompany purchases of $1,479 million in 2014 and $1,700 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.


•	Retail gross margin — Retail gross margin increased $70 million for the nine months ended September 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	$	60
Increase primarily due to higher revenues from home and business services and an increase in mass customer counts	29
Unfavorable impact of higher supply costs resulting from weather conditions in 2014	(19		)
	$	70

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 is expected to increase NRG’s retail portfolio by approximately 540,000 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 $364 million for the nine months ended September 30, 2014, compared to gross margin of $162 million for the same period in 2013. The increase in gross margin was primarily a result of the EME acquisition in April 2014 as well as the CVSR and Ivanpah projects which reached commercial operations in late 2013 and early 2014, respectively.

NRG Yield gross margin

NRG Yield had gross margin of $369 million for the nine months ended September 30, 2014, compared to gross margin of $210 million for the same period in 2013, which related primarily to the acquisition of the Alta Wind Assets in August 2014 as well as the acquisition of Energy Systems Company in December 2013 as well as Marsh Landing and El Segundo Energy Center reaching commercial operations in 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 $95 million during the nine months ended September 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:



	Nine months ended September 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 losses/(gains) on settled positions related to economic hedges	$	—		$	36		$	27		$	(4	)	$	1		$	47		$	107
Reversal of acquired (gain)/loss positions related to economic hedges	—			—			(238		)	1			—			—			(237		)
Net unrealized gains/(losses) on open positions related to economic hedges	—			72			(131		)	(1		)	(1		)	(35		)	(96		)
Total mark-to-market gains/(losses) in operating revenues	$	—		$	108		$	(342	)	$	(4	)	$	—		$	12		$	(226	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(74	)	$	2		$	9		$	—		$	—		$	(47	)	$	(110	)
Reversal of acquired (gain)/loss positions related to economic hedges	(22		)	—			10			—			—			—			(12		)
Net unrealized (losses)/gains on open positions related to economic hedges	(6		)	(1		)	7			—			—			35			35
Total mark-to-market (losses)/gains in operating costs and expenses	$	(102	)	$	1		$	26		$	—		$	—		$	(12	)	$	(87	)


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



	Nine months ended September 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	$	(5	)	$	(188	)	$	1		$	(3	)	$	—	$	44		$	(151	)
Reversal of acquired gain positions related to economic hedges	—			—			(299		)	(1		)	—		—			(300		)
Net unrealized gains/(losses) on open positions related to economic hedges	3			166			58			7			—		(143		)	91
Total mark-to-market (losses)/gains in operating revenues	$	(2	)	$	(22	)	$	(240	)	$	3		$	—	$	(99	)	$	(360	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	72		$	32		$	11		$	—		$	—	$	(44	)	$	71
Reversal of acquired (gain)/loss positions related to economic hedges	(1		)	—			32			—			—		—			31
Net unrealized (losses)/gains on open positions related to economic hedges	(105		)	14			(12		)	—			—		143			40
Total mark-to-market (losses)/gains in operating costs and expenses	$	(34	)	$	46		$	31		$	—		$	—	$	99		$	142


(a)	Represents the elimination of the intercompany activity between Retail, 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 nine months ended September 30, 2014, the $226 million loss in operating revenues from economic hedge positions was driven by the reversal of previously recognized unrealized gains on acquired contracts that settled during the period and a decrease in value of open positions as a result of increases in power prices partially offset by decreases in natural gas prices. The $87 million loss in operating costs and expenses from economic hedge positions was driven by the reversal of previously recognized unrealized gains on contracts that settled during the period slightly offset by an increase in value of open positions as a result of increases in ERCOT heat rates partially offset by decreases in coal prices.

For the nine months ended September 30, 2013, the $360 million loss in operating revenues from economic hedge positions was driven by the reversal of previously recognized unrealized gains on acquired contracts that settled during the period partially offset by an increase in value of open positions as a result of decreases in natural gas and power prices. The $142 million gain in operating costs and expenses from economic hedge positions was driven by the reversal of previously recognized unrealized losses on contracts that settled during the period and an increase in value of open positions as a result of increases in ERCOT heat rates.

In accordance with ASC 815, the following table represents the results of the Company's financial and physical trading of energy commodities for the nine months ended September 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.



	Nine months ended September 30,
(In millions)	2014		2013
Trading gains/(losses)
Realized	$	95	$	60
Unrealized	21		(44		)
Total trading gains	$	116	$	16

Contract Amortization Revenue

Contract amortization represents the roll-off of in-market customer contracts valued under purchase accounting. The favorable change of $27 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)
Nine months ended September 30, 2014	$	233	$	551	$	836	$	126	$	113	$	84	$	(2	)	$	1,941
Nine months ended September 30, 2013	198		473		699		130		26		52		(6		)	1,572

Other operating costs increased by $369 million for the nine months ended September 30, 2014, compared to the same period in 2013, due to:



Increase due to the acquisition of EME in April 2014	$	245
Increase in Gulf Coast operations and maintenance expense primarily related to the scope of the STP Unit 1 planned outage, the timing and scope of outages at certain gas plants, and increased normal maintenance as well as costs for the disposal of fixed assets at STP and certain coal plants	53
Increase in NRG Yield operations and maintenance expense related to El Segundo and Marsh Landing which reached commercial operations in 2013 and the acquisition of Alta Wind	32
Increase in Renewables operations and maintenance expense related to Ivanpah and CVSR reaching commercial operations in late 2013 and early 2014	36
Other	3
	$	369

Depreciation and Amortization

Depreciation and amortization increased by $149 million for the nine months ended September 30, 2014, compared to the same period in 2013, due primarily to $64 million related to the EME acquisition in April 2014 and additional depreciation expense of $82 million as a result of El Segundo, Marsh Landing, and Ivanpah reaching commercial operations in late 2013.

Impairment Losses

For the nine months ended September 30, 2014, the Company recorded impairment losses of $60 million related to the Osceola facility and $10 million related to certain solar panels, as described in Note 2, Summary of Significant Accounting Policies.

Selling, General and Administrative Expenses

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



	Nine months ended September 30,
(In millions)	2014		2013
General and administrative expenses	$	500	$	431
Selling and marketing expenses	252		239
	$	752	$	670

General and administrative expenses increased by $69 million for the nine months ended September 30, 2014 compared to the same period in 2013, due in part to the acquisition of EME in April 2014 and the expansion of the Residential Solar business as well as the presentation of Residential Solar expenses as development in prior periods. Selling and marketing expenses increased by $13 million primarily due to the expansion of the Residential Solar business.

Acquisition-related Transaction and Integration Costs

NRG incurred transaction and integration costs of $69 million for the nine months ended September 30, 2014, compared to $95 million for the same period in 2013.

Equity in Earnings of Unconsolidated Affiliates

NRG's equity in earnings of unconsolidated affiliates was $39 million for the nine months ended September 30, 2014 compared to equity in earnings of unconsolidated affiliates of $6 million for the same period in 2013, due primarily to $12 million of income in the current year from a long-term natural gas hedge entered into by Saguaro in July 2013 compared to losses of $8 million in the prior year, and $16 million resulting from the acquisition of EME in April 2014.

Interest Expense

NRG's interest expense increased by $179 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	$	89
Increase for issuance of 2022 and 2024 Senior Notes in January and April 2014	76
Increase for the acquisition of EME in April 2014	23
Increase in derivative interest expense primarily for the Alpine interest rate swaps	17
Increase in amortization of premium/discount	17
Increase for issuance of Yield Convertible Notes and Senior Notes in February and August	15
Increase for the acquisition of Alta Wind in August 2014	12
Decrease for 7.625% and 8.5% Senior Notes due 2019 redeemed in February 2014	(49		)
Decrease for 7.625% GenOn Senior Notes due 2014 redeemed in June 2013	(21		)
	$	179

Income Tax Benefit

For the nine months ended September 30, 2014, NRG recorded an income tax benefit of $68 million on pre-tax loss of $33 million. For the same period in 2013, NRG recorded an income tax benefit of $55 million on pre-tax loss of $117 million. The effective tax rate was 206.1% and 47.0% for the nine months ended September 30, 2014, and 2013, respectively.

For the nine months ended September 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 a benefit resulting from the recognition of previously uncertain tax benefits that were settled upon IRS audit during the second quarter of 2014.

Noncontrolling Interest

For the nine months ended September 30, 2014, income attributable to noncontrolling interests primarily reflects NRG Yield, Inc.'s share of net income for the period 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 nine months ended September 30, 2013, income attributable to noncontrolling interests primarily reflects income attributable to the noncontrolling partner for Agua Caliente.

Liquidity and Capital Resources

Liquidity Position

As of September 30, 2014, and December 31, 2013, NRG's liquidity, excluding collateral received, was approximately $3.6 billion and $3.7 billion, respectively, comprised of the following:



(In millions)	September 30, 2014		December 31, 2013
Cash and cash equivalents	$	1,953	$	2,254
Restricted cash	339		268
Total	2,292		2,522
Total credit facility availability	1,302		1,173
Total liquidity, excluding collateral received	$	3,594	$	3,695

For the nine months ended September 30, 2014, total liquidity, excluding collateral received, decreased by $101 million. Changes in cash and cash equivalent balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents at September 30, 2014 were predominantly held in money market mutual funds and bank deposits.

Management believes that the Company's liquidity position and cash flows from operations will be adequate to finance operating and maintenance capital expenditures, to fund dividends to NRG's common and preferred stockholders, and 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 $1.9 billion of cash and cash equivalents of the Company as of September 30, 2014, $129 million and $320 million were held by GenOn Mid-Atlantic and REMA, respectively. The ability of certain of GenOn’s and GenOn Americas Generation’s subsidiaries to pay dividends and make distributions is restricted under the terms of certain agreements, including the 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 and REMA did not satisfy the restricted payments tests. As a result, as of September 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.

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 September 30, 2014, GenOn met the consolidated debt ratio component of the restricted payments test.

Credit Ratings

On October 20, 2014, Standard & Poor’s lowered its corporate credit ratings on GenOn, GenOn Mid-Atlantic, REMA and GenOn Americas Generation to B- from B. The ratings outlook for GenOn, GenOn Mid-Atlantic, REMA and GenOn Americas Generation is stable. Standard & Poor’s also lowered the issue ratings on the $770 million of pass-through certificates of GenOn Mid-Atlantic and the GenOn Americas Generation Senior Notes to B from BB-.

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.

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 November 4, 2014, the Company and NRG Yield, Inc. entered into a definitive agreement regarding the sale of certain NRG facilities, including Walnut Creek, the Tapestry projects (Buffalo Bear, Pinnacle and Taloga), and Laredo Ridge, for total expected cash consideration of $480 million plus assumed project level debt and working capital adjustments to be calculated at close. The sale is subject to customary closing conditions and is expected to close by the end of the fourth quarter of 2014.

Cash Proceeds from Residential Solar Financing Arrangements

The Company has entered into various arrangements to monetize the tax attributes of residential solar assets subject to lease and power purchase agreements. As of September 30, 2014, the Company has received approximately $28 million in funding related to these arrangements and has $110 million of availability for future funding under these arrangements.

Cash Proceeds from Wind Tax Equity Arrangement

First Lien Structure

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

The Company's lien counterparties may have a claim on its assets to the extent market prices exceed the hedged prices. As of September 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 September 30, 2014:



Equivalent Net Sales Secured by First Lien Structure ^(a)	2014		2015		2016		2017		2018
In MW	1,398		970		331		201		—
As a percentage of total net coal and nuclear capacity ^(b)	22	%	16	%	5	%	3	%	—	%


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


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

Uses of Liquidity

The Company's requirements for liquidity and capital resources, other than for operating its facilities, can generally be categorized by the following: (i) commercial operations activities; (ii) debt service obligations; (iii) capital expenditures, including repowering and renewable development, and environmental; and (iv) allocations in connection with the Capital Allocation Program including acquisition opportunities, 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 September 30, 2014, commercial operations had total cash collateral outstanding of $360 million, and $798 million outstanding in letters of credit to third parties primarily to support its commercial activities for both wholesale and retail transactions. As of September 30, 2014, total collateral held from counterparties was $3 million in cash and $7 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 September 30, 2014, the Company had a net renewable energy grant receivable of $614 million which consists of $539 million, net of sequestration adjustment, due from the U.S. Treasury under the 1603 Cash Grant Program in connection with the Ivanpah thermal solar project and a $75 million receivable pursuant to an indemnity agreement the Company has with SunPower Corporation, Systems relating to the 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 September 30, 2014, there are approximately $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:



Maturity date:	Cash due and payable
	(In millions)
Solar Partners I, December 27, 2014	$	159
Solar Partners II, February 27, 2015	132
Solar Partners VIII, April 27, 2015	117
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 September 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	23		2		—		21
High Desert	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.

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 reduction by Treasury of $107 million and a sequestration adjustment of $22 million. NRG maintains a receivable, net of sequestration, of $107 million, for which 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 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 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 nine months ended September 30, 2014, and the estimated capital expenditure and growth investments forecast for the remainder of 2014.



	Maintenance			Environmental		Growth Investments			Total
	(In millions)
Gulf Coast	$	76		$	75	$	6		$	157
East	95			103		4			202
West	3			—		—			3
Retail	22			—		—			22
Renewables	—			—		229			229
NRG Yield	3			—		25			28
Corporate	20			—		14			34
Total cash capital expenditures for the nine months ended September 30, 2014	219			178		278			675
Other investments ^(a)	—			—		44			44
Funding from debt financing, net of fees	—			—		(164		)	(164		)
Funding from third party equity partners	(8		)	—		(121		)	(129		)
Total capital expenditures and investments, net of financings	211			178		37			426

Estimated capital expenditures for the remainder of 2014	196			128		197			521
Other investments ^(a)	—			—		10			10
Funding from debt financing, net of fees	(21		)	—		(22		)	(43		)
Funding from third party equity partners and cash grants	(4		)	—		(153		)	(157		)
NRG estimated capital expenditures for the remainder of 2014, net of financings	$	171		$	128	$	32		$	331


(a)	Other investments includes restricted cash activity.


•	Environmental capital expenditures — For the nine months ended September 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 nine months ended September 30, 2014, the Company's growth investment expenditures included $228 million for solar projects and $50 million for the Company's 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 $877 million which includes $109 million for 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 environmental regulations.

2014 Capital Allocation Program

Completed Acquisitions

As described in Note 3, Business Acquisitions and Dispositions, on August 12, 2014, NRG Yield, Inc., through its subsidiary Yield Operating, completed the acquisition of 100% of the membership interests of Alta Wind Asset Management Holdings, LLC, Alta Wind Company, LLC, Alta Wind X Holding Company, LLC, and Alta Wind XI Holding Company, LLC, which collectively 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 was $923 million, as well as working capital adjustments, plus the assumption of $1.6 billion in non-recourse project level debt. 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 Alta I-V and 22 years, beginning in 2016, for Alta X and XI.

In addition, the Company acquired Goal Zero and Pure Energies, as described in the New and On-going Company Initiatives section of this Form 10-Q.

Dividends

The following table lists the dividends paid during the nine months ended September 30, 2014:



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

Debt Reduction

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

Cash Flow Discussion

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



	Nine months ended September 30,
	2014			2013			Change
	(In millions)
Net cash provided by operating activities	$	1,114		$	823		$	291
Net cash used by investing activities	(2,958		)	(2,031		)	(927		)
Net cash provided by financing activities	1,541			1,251			290

Net Cash Provided By Operating Activities

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



	(In millions)
Increase in operating income adjusted for non-cash items	$	286
Change in cash paid in support of risk management activities	(41		)
Other changes in working capital	46
	$	291

Net Cash Used By Investing Activities

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



	(In millions)
Increase in cash paid for acquisitions, primarily related to the EME and Alta Wind acquisitions	$	(2,458	)
Decrease in capital expenditures due to decreased spending on maintenance and growth projects	906
Increase in proceeds from renewable energy grants	379
Proceeds from the sale of assets	140
Decrease in restricted cash	56
Proceeds for payment of cash grant bridge loan	57
Other	(7		)
	$	(927	)

Net Cash Provided By Financing Activities

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



	(In millions)
Net increase in borrowings, primarily due to the issuance of the 2022 and 2024 Senior Notes	$	2,851
Net increase in debt payments primarily due to the redemption of 2019 Senior Notes and the repayment of the cash grant bridge loans	(2,440		)
Decrease in financing element of acquired derivatives	(241		)
Cash contributions from noncontrolling interests	135
Increase in cash paid for debt issuance costs	(14		)
Increase in payment of dividends	(27		)
Prior year repurchase of treasury shares, offset by increase in issuance of common shares	26
	$	290

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

For the nine months ended September 30, 2014, the Company had a total domestic pre-tax book loss of $39 million and foreign pre-tax book income of $6 million. As of September 30, 2014, the Company has cumulative domestic NOL carryforwards of $3.0 billion and cumulative state NOL carryforwards of $3.0 billion for financial statement purposes. In addition, NRG has cumulative foreign NOL carryforwards of $241 million, of which $6 million will expire starting 2014 through 2016 and of which $235 million do not have an expiration date.

In addition to these amounts, the Company has $68 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 $30 million in 2014.

However, as the position remains uncertain for the $68 million of tax effected uncertain tax benefits, the Company has recorded a non-current tax liability of $56 million and may accrue the remaining balance as an increase to non-current liabilities until final resolution with the related taxing authority. The $56 million non-current tax liability for uncertain tax benefits is from positions taken on various state income tax returns, including accrued interest.

New and On-going Company Initiatives

As part of its core strategy, NRG intends to continue to own, operate and invest in the development and acquisition of conventional and renewable energy projects. NRG's strategy is intended to capitalize on its existing wholesale and retail businesses as well as address the increasing demand for sustainable and low carbon energy solutions individualized for the benefit of the end use energy customer. This section briefly describes the Company's most notable current activities.

Conventional Generation

New ERCOT Peaking Plant

The Company obtained an air permit in August 2014, and delivered notice to proceed in September 2014, for a new peaking facility in ERCOT. In 2012, the Company entered into agreements to acquire the former New Albany, Mississippi simple-cycle peaking power plant. The transaction contemplates the current owners disassembling the 360 MW (330 MW summer) facility and rebuilding it on retained land at the site of the Company’s former P.H. Robinson Electric Generating Station in Bacliff, Texas. The Company will acquire the facility upon successful commercial operation. The addition of these peakers will improve the Company’s ability to respond to volatile prices and to meet its peak load, at a cost of approximately $400 per kw.

Fuel Additions and Conversions

NRG intends to continue operations at the Avon Lake facility Units 7 and 9 and the New Castle facility 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, which additions are expected to be completed by the summer of 2016. In addition, the Company expects to complete the conversion of 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 add natural gas burning capability to Units 6, 7 and 8 of the Joliet coal facility 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 approved by the NYSPSC on 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.

NRG Home Solar

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 has now expanded into California and other areas.

On October 1, 2014, the Company acquired Pure Energies, a residential solar industry company focused on web and telephonic based customer acquisition. Pure Energies enables a simplified customer adoption process and provides NRG Home Solar national sales capabilities. Additionally, the Pure Energies acquisition may provide a valuable sales channel for NRG's Retail Business, including NRG's Goal Zero line of portable solar and energy storage products.

In addition to leveraging NRG’s Retail Business, the combination of RDS and Pure Energies provides NRG Home Solar the platform to meet the growing demand for high quality residential solar services delivered by a market leader in delivering retail electricity services in the home.

Retail Growth Initiatives

On March 31, 2014, the Company acquired the competitive retail 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 is expected to increase NRG’s retail portfolio by approximately 540,000 customers in the aggregate by the end of 2014. The acquisition supports NRG's ongoing efforts to expand the Company's retail footprint in the Northeast and to grow its 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 $192 million as cash consideration for the acquisition, including $165 million of purchase price and $27 million paid for working capital balances, which was funded by cash on hand.

On September 16, 2014, the Company acquired Goal Zero, a leading provider of portable solar power and battery pack products and accessories. Through this acquisition, NRG adds new portable power products to its NRG Home strategy and strengthens cross-selling opportunities between mass market system power, residential solar and personal power via partnerships, sales channels and customer bases.

Petra Nova Business and Commercial Scale Carbon Capture and Sequestration with Enhanced Oil Recovery

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 CCF at the W.A. Parish facility with a consortium of Mitsubishi Heavy Industries America, Inc. and TIC - The Industrial Company. Notice to proceed for the construction of the CCF was issued on July 15, 2014, and commercial operation is expected in late 2016.

Petra Nova CCS I LLC, a wholly owned subsidiary of Petra Nova Parish Holdings LLC, owns a 75 MW peaking unit at W.A. Parish, which achieved commercial operations on June 26, 2013. The peaking unit will be converted into a cogeneration facility to provide power and steam to the CCF. The CCF 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 and $26 million has already been received from the grant under the construction phase, (ii) $250 million in loans provided by the Japan Bank for International Cooperation and Mizuho Bank, Ltd., of which $68 million has been drawn, 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.

Petra Nova LLC, a wholly owned subsidiary of Petra Nova Parish Holdings LLC, 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 CCF will be compressed and piped through an 82-mile long pipeline owned by TCV Pipeline, LLC, a subsidiary of Texas Coastal Ventures, to the West Ranch oilfield for enhanced oil recovery operations. NRG continues to assess oilfield opportunities both along the Gulf Coast and nationally as it looks to further monetize the carbon output of NRG's fleet.

Electric Vehicle Infrastructure Development

NRG, through its subsidiary NRG eVgo, continues to build out and operate comprehensive electric vehicle, or EV, infrastructure in the U.S. NRG eVgo provides comprehensive EV charging — at public, home, multi-family and workplace locations — in major metropolitan areas throughout the country. As of September 30, 2014, NRG eVgo had 106 public fast charging Freedom Station sites operational and an additional 48 sites 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 as well as walk-up charging.

In the third quarter of 2014, NRG eVgo initiated support of Nissan’s expanded "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. During the third quarter of 2014, 6,654 EZ-Charge cards were distributed to eligible customers across all eligible markets. NRG eVgo also signed an agreement with BMW to offer i3 owners in California a one-year embedded subscription through 2015. These two agreements and NRG eVgo trial programs at more than 200 participating auto dealers have resulted in significant increases in customer count.

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 associated work to prepare 10,000 commercial and multi-family parking spaces for electric vehicle charging in California by the end of 2016.

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 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 September 30, 2014, based on the Company's stock price, the embedded derivative was in-the-money and had a redemption value of $10 million.

Obligations Arising Out of a Variable Interest in an Unconsolidated Entity

Variable interest in equity investments — As of September 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 $297 million as of September 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 September 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 September 30, 2014, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at September 30, 2014.



Derivative Activity Gains/(Losses)	(In millions)
Fair value of contracts as of December 31, 2013	$	389
Contracts realized or otherwise settled during the period	(239		)
Contracts acquired during the period	35
Changes in fair value	(52		)
Fair value of contracts as of September 30, 2014	$	133



	Fair Value of Contracts as of September 30, 2014
	Maturity
Fair value hierarchy Gains/(Losses)	1 Year or Less			Greater than 1 Year to 3 Years			Greater than 3 Years to 5 Years			Greater than 5 Years		Total Fair Value
	(In millions)
Level 1	$	29		$	88		$	—		$	—	$	117
Level 2	(8		)	(3		)	(11		)	9		(13		)
Level 3	11			15			—			3		29
Total	$	32		$	100		$	(11	)	$	12	$	133

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 September 30, 2014, NRG's net derivative asset was $133 million, a decrease to total fair value of $256 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 $394 million in the net value of derivatives as of September 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 $371 million in the net value of derivatives as of September 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.

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 nine months ending September 30, 2014, and 2013:



(In millions)	2014		2013
VaR as of September 30,	$	85	$	83
Three months ended September 30,
Average	$	86	$	85
Maximum	104		93
Minimum	77		75
Nine months ended September 30,
Average	$	95	$	89
Maximum	142		104
Minimum	73		75

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 September 30, 2014 for the entire term of these instruments entered into for both asset management and trading was $68 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 September 30, 2014, the Company would have owed the counterparties $124 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 September 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 September 30, 2014, the fair value and related carrying value of the Company's debt was $20.8 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 $1.5 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 $267 million as of September 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 $190 million as of September 30, 2014. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of September 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.

ITEM 4 — CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

NRG continues to integrate certain business operations, information systems, processes and related internal control over financial reporting as a result of business acquisitions. NRG will continue to assess the effectiveness of its internal control over financial reporting as integration activities continue.

PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

For a discussion of material legal proceedings in which NRG was involved through September 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

Under the Dodd-Frank Act, each operator of a coal or other mine is required to include certain mine safety results within its periodic reports filed with the Securities and Exchange Commission. In accordance with the reporting requirements included in Section 1503(a) of the Dodd-Frank Act and Item 104 of Regulation S-K, the required mine safety results regarding certain mining safety and health matters are discussed below and are detailed further in Exhibit 95 to this Quarterly Report on Form 10-Q.

NRG owns a 50% indirect ownership interest in American Bituminous Power Partners, L.P. (“Ambit”), an operator of coal mines located in Grant Town, West Virginia that are subject to regulation by the Mine Safety and Health Administration (“MSHA”) under the Federal Mine Safety and Health Act (the “Mine Act”). On September 23, 2014, Ambit was issued Citation Number 8059310 due to an unsafe means of access for the sixth floor of the prep plant at the Grant Town facility. The citation was issued as Significant & Substantial under Section 104 of the Mine Act and was issued directly to Ambit under its MSHA Mine ID Number (46-08264). The proposed penalty has not yet been assessed.

ITEM 5 — OTHER INFORMATION

None.

ITEM 6 — EXHIBITS



Number	Description	Method of Filing
4.1	One Hundred-Twelfth Supplemental Indenture, dated as of October 3, 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 October 3, 2014.
4.2	Second Supplemental Indenture, dated as of October 3, 2014, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York.	Incorporated herein by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K filed on October 3, 2014.
31.1	Rule 13a-14(a)/15d-14(a) certification of David Crane.	Filed herewith.
31.2	Rule 13a-14(a)/15d-14(a) certification of Kirkland B. Andrews.	Filed herewith.
31.3	Rule 13a-14(a)/15d-14(a) certification of Ronald B. Stark.	Filed herewith.
32	Section 1350 Certification.	Filed herewith.
95	Mine Safety Disclosures.	Filed herewith.
101 INS	XBRL Instance Document.	Filed herewith.
101 SCH	XBRL Taxonomy Extension Schema.	Filed herewith.
101 CAL	XBRL Taxonomy Extension Calculation Linkbase.	Filed herewith.
101 DEF	XBRL Taxonomy Extension Definition Linkbase.	Filed herewith.
101 LAB	XBRL Taxonomy Extension Label Linkbase.	Filed herewith.
101 PRE	XBRL Taxonomy Extension Presentation Linkbase.	Filed herewith.

SIGNATURES

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



	NRG ENERGY, INC. (Registrant)

	/s/ DAVID CRANE
	David Crane
	Chief Executive Officer (Principal Executive Officer)


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


	/s/ RONALD B. STARK
	Ronald B. Stark
Date: November 5, 2014	Chief Accounting Officer (Principal Accounting Officer)