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 2013 03.31 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: March 31, 2013

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

Commission File Number: 001-15891

NRG Energy, Inc.

(Exact name of registrant as specified in its charter)



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

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

(609) 524-4500

(Registrant’s telephone number, including area code)

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

Yes x No o

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

Yes x No o

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

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

Yes o No x

As of April 30, 2013, there were 322,487,532 shares of common stock outstanding, par value $0.01 per share.

TABLE OF CONTENTS

Index



CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION	3
GLOSSARY OF TERMS	4
PART I — FINANCIAL INFORMATION	6
ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES	7
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	46
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	68
ITEM 4 — CONTROLS AND PROCEDURES	70
PART II — OTHER INFORMATION	71
ITEM 1 — LEGAL PROCEEDINGS	71
ITEM 1A — RISK FACTORS	71
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	71
ITEM 3 — DEFAULTS UPON SENIOR SECURITIES	71
ITEM 4 — MINE SAFETY DISCLOSURES	71
ITEM 5 — OTHER INFORMATION	71
ITEM 6 — EXHIBITS	72
SIGNATURES	73

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, 2012, 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;


•	Counterparties' collateral demands and other factors affecting NRG's liquidity position and financial condition;


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


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


•	The liquidity and competitiveness of wholesale markets for energy commodities;


•	Government regulation, including compliance with regulatory requirements and changes in market rules, rates, tariffs and environmental laws and increased regulation of carbon dioxide and other 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 their costs;


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


•	NRG's ability to receive 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 solar 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 and manage any acquired businesses;


•	NRG's ability to develop and maintain successful partnering relationships; and


•	NRG's ability to integrate the businesses and realize cost savings related to the merger with GenOn Energy, Inc.

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:



2012 Form 10-K		NRG’s Annual Report on Form 10-K for the year ended December 31, 2012
ASC		The FASB Accounting Standards Codification, which the FASB established as the source of authoritative U.S. GAAP
ASU		Accounting Standards Updates - updates to the ASC
BACT		Best Available Control Technology
Baseload		Units expected to satisfy minimum baseload requirements for the system and produce electricity at an essentially constant rate and run continuously
BRA		Base Residual Auction
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, share repurchases and shareholder dividends
CCUS		Carbon capture, utilization and storage project
CFTC		U.S. Commodity Futures Trading Commission
CO₂		Carbon dioxide
CPUC		California Public Utilities Commission
CSAPR		Cross-State Air Pollution Rule
CWA		Clean Water Act
Distributed Solar		Solar power projects, typically less than 20 MW in size, that primarily sell power produced to customers for usage on site, or are interconnected to sell power into the local distribution grid
DNREC		Delaware Department of Natural Resources and Environmental Control
Energy Plus		Energy Plus Holdings LLC
EPA		United States 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		Employee Stock Purchase Plan
Exchange Act		The Securities Exchange Act of 1934, as amended
FASB		Financial Accounting Standards Board
FCM		Forward Capacity Market
FERC		Federal Energy Regulatory Commission
GenOn		GenOn Energy, Inc.
GenOn Americas Generation		GenOn Americas Generation, LLC
GenOn Americas Generation Senior Notes		GenOn Americas Generation's $850 million outstanding unsecured senior notes consisting of $450 million of 8.55% 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 $2.5 billion outstanding unsecured senior notes consisting of $575 million of 7.625% senior notes due 2014, $725 million of 7.875% senior notes due 2017, $675 million of 9.5% senior notes due 2018, and $550 million of 9.875% senior notes due 2020
GHG		Greenhouse gases
Green Mountain Energy		Green Mountain Energy Company
GWh		Gigawatt hour
HAPs		Hazardous air pollutants



Heat Rate		A measure of thermal efficiency computed by dividing the total BTU content of the fuel burned by the resulting kWhs generated. Heat rates can be expressed as either gross or net heat rates, depending whether the electricity output measured is gross or net generation and is generally expressed as BTU per net kWh
High Desert		TA - High Desert LLC
High Desert Facility		High Desert's $82 million non-recourse project level financing facility under the Note Purchase and Private Shelf Agreement
Intermediate		Units expected to satisfy system requirements that are greater than baseload and less than peaking
ISO		Independent System Operator, also referred to as Regional Transmission Organization, or RTO
ITC		Investment Tax Credit
kWh		Kilowatt-hours
LIBOR		London Inter-Bank Offered Rate
LTIPs		Collectively, the NRG Long-Term Incentive Plan and the NRG GenOn Long-Term Incentive Plan
Marsh Landing		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
Merger		The merger completed on December 14, 2012 by NRG and GenOn pursuant to the Merger Agreement
Merger Agreement		Agreement and Plan of Merger by and among NRG Energy, Inc., Plus Merger Corporation and GenOn Energy, Inc. dated as of July 20, 2012
MISO		Midwest Independent Transmission System Operator, Inc.
MMBtu		Million British Thermal Units
MOPR		Minimum Offer Price Rule
MW		Megawatt
MWh		Saleable megawatt hours, net of internal/parasitic load megawatt-hours
MWt		Megawatts Thermal Equivalent
NAAQS		National Ambient Air Quality Standards
NERC		North American Electric Reliability Corporation
Net Exposure		Counterparty credit exposure to NRG, net of collateral
Net Generation		The net amount of electricity produced, expressed in kWh or MWhs, that is the total amount of electricity generated (gross) minus the amount of electricity used during generation
NJDEP		New Jersey Department of Environmental Protection
NO_x		Nitrogen oxide
NPNS		Normal Purchase Normal Sale
NRC		U.S. Nuclear Regulatory Commission
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
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
QSE		Qualified Scheduling Entities
Reliant Energy		NRG's retail business in Texas, Illinois and the Northeast
REP		Retail Electric Provider
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		Retail energy companies, collectively, Reliant Energy, Green Mountain Energy and Energy Plus, which are wholly owned subsidiaries of NRG
Revolving Credit Facility		The Company's $2.3 billion revolving credit facility due 2016, a component of the Senior Credit Facility
RGGI		Regional Greenhouse Gas Initiative
RMR		Reliability Must Run
RPM		Reliability Pricing Model
Schkopau		Kraftwerk Schkopau Betriebsgesellschaft mbH
Senior Credit Facility		NRG's senior secured facility, comprised of the $1.6 billion Term Loan Facility and the $2.3 billion Revolving Credit Facility
Senior Notes		The Company’s $5.7 billion outstanding unsecured senior notes, consisting of $1.1 billion of 7.625% senior notes due 2018, $601 million of 8.5% senior notes due 2019, $800 million of 7.625% senior notes due 2019, $1.1 billion of 8.25% senior notes due 2020, $1.1 billion of 7.875% senior notes due 2021, and $990 million of 6.625% senior notes due 2023
SO₂		Sulfur dioxide
STP		South Texas Project — nuclear generating facility located near Bay City, Texas in which NRG owns a 44% interest
STPNOC		South Texas Project Nuclear Operating Company
Term Loan Facility		The Company's $1.6 billion term loan facility due 2018, a component of the Senior Credit Facility
Texas Genco		Texas Genco LLC, now referred to as the Company's Texas Region
U.S.		United States of America
U.S. DOE		U.S. Department of Energy
U.S. DOJ		U.S. Department of Justice
U.S. GAAP		Accounting principles generally accepted in the United States
Utility Scale Solar		Solar power projects, typically 20 MW or greater in size (on an alternating current, or AC, 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
WECC		Western Electricity Coordinating Council

PART I — FINANCIAL INFORMATION

ITEM 1 — CONDENSED CONSOLIDATED FINANCIAL STATEMENTS AND NOTES

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)



	Three months ended March 31,
(In millions, except for per share amounts)	2013			2012
Operating Revenues
Total operating revenues	$	2,081		$	1,862
Operating Costs and Expenses
Cost of operations	1,765			1,583
Depreciation and amortization	298			230
Selling, general and administrative	229			206
Acquisition-related transaction and integration costs	32			—
Development activity expenses	16			13
Total operating costs and expenses	2,340			2,032
Operating Loss	(259		)	(170		)
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	3			8
Other income, net	4			1
Loss on debt extinguishment	(28		)	—
Interest expense	(196		)	(165		)
Total other expense	(217		)	(156		)
Loss Before Income Taxes	(476		)	(326		)
Income tax benefit	(149		)	(120		)
Net Loss	(327		)	(206		)
Less: Net income attributable to noncontrolling interest	1			1
Net Loss Attributable to NRG Energy, Inc.	(328		)	(207		)
Dividends for preferred shares	2			2
Loss Available for Common Stockholders	$	(330	)	$	(209	)
Loss Per Share Attributable to NRG Energy, Inc. Common Stockholders
Weighted average number of common shares outstanding — basic and diluted	323			228
Net loss per weighted average common share — basic and diluted	$	(1.02	)	$	(0.92	)
Dividends Per Common Share	$	0.09		$	—

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(Unaudited)



	Three months ended March 31,
	2013			2012
	(In millions)
Net Loss	$	(327	)	$	(206	)
Other comprehensive income/(loss), net of tax
Unrealized gain/(loss) on derivatives, net of income tax benefit of $9 and $5	7			(9		)
Foreign currency translation adjustments, net of income tax expense of $0 and $3	—			6
Available-for-sale securities, net of income tax expense of $1 and $0	2			—
Defined benefit plans, net of tax benefit of $5 and $0	5			—
Other comprehensive income/(loss)	14			(3		)
Comprehensive loss	(313		)	(209		)
Less: Comprehensive income attributable to noncontrolling interest	1			1
Comprehensive loss attributable to NRG Energy, Inc.	(314		)	(210		)
Dividends for preferred shares	2			2
Comprehensive loss available for common stockholders	$	(316	)	$	(212	)

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS



	March 31, 2013			December 31, 2012
(In millions, except shares)	(unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	1,707		$	2,087
Funds deposited by counterparties	105			271
Restricted cash	221			217
Accounts receivable — trade, less allowance for doubtful accounts of $30 and $32	982			1,061
Inventory	904			931
Derivative instruments	2,805			2,644
Cash collateral paid in support of energy risk management activities	455			229
Deferred income taxes	128			56
Prepayments and other current assets	724			460
Total current assets	8,031			7,956
Property, plant and equipment, net of accumulated depreciation of $5,680 and $5,417	20,404			20,268
Other Assets
Equity investments in affiliates	677			676
Notes receivable, less current portion	86			79
Goodwill	1,954			1,956
Intangible assets, net of accumulated amortization of $1,767 and $1,706	1,176			1,200
Nuclear decommissioning trust fund	501			473
Derivative instruments	562			662
Deferred income taxes	1,435			1,267
Other non-current assets	545			597
Total other assets	6,936			6,910
Total Assets	$	35,371		$	35,134
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	556		$	147
Accounts payable	1,054			1,170
Derivative instruments	2,493			1,981
Cash collateral received in support of energy risk management activities	105			271
Accrued expenses and other current liabilities	954			1,108
Total current liabilities	5,162			4,677
Other Liabilities
Long-term debt and capital leases	15,914			15,733
Nuclear decommissioning reserve	359			354
Nuclear decommissioning trust liability	293			273
Deferred income taxes	53			55
Derivative instruments	477			500
Out-of-market contracts	1,194			1,216
Other non-current liabilities	1,474			1,555
Total non-current liabilities	19,764			19,686
Total Liabilities	24,926			24,363
3.625% convertible perpetual preferred stock (at liquidation value, net of issuance costs)	249			249
Commitments and Contingencies
Stockholders’ Equity
Common stock	4			4
Additional paid-in capital	7,602			7,587
Retained earnings	4,124			4,483
Less treasury stock, at cost — 77,416,791 and 76,505,718 shares, respectively	(1,944		)	(1,920		)
Accumulated other comprehensive loss	(136		)	(150		)
Noncontrolling interest	546			518
Total Stockholders’ Equity	10,196			10,522
Total Liabilities and Stockholders’ Equity	$	35,371		$	35,134

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)



	Three months ended March 31,
	2013			2012
	(In millions)
Cash Flows from Operating Activities
Net loss	$	(327	)	$	(206	)
Adjustments to reconcile net loss to net cash used by operating activities:
Depreciation and amortization	298			230
Provision for bad debts	9			7
Amortization of nuclear fuel	6			6
Amortization of financing costs and debt discount/premiums	(13		)	8
Loss on debt extinguishment	2			—
Amortization of intangibles and out-of-market contracts	31			42
Amortization of unearned equity compensation	18			—
Changes in deferred income taxes and liability for uncertain tax benefits	(212		)	(129		)
Changes in nuclear decommissioning trust liability	10			8
Changes in derivative instruments	317			187
Changes in collateral deposits supporting energy risk management activities	(226		)	(187		)
Cash used by changes in other working capital	(37		)	(42		)
Net Cash Used by Operating Activities	(124		)	(76		)
Cash Flows from Investing Activities
Acquisitions of businesses, net of cash acquired	(18		)	—
Capital expenditures	(813		)	(639		)
Increase in restricted cash, net	(13		)	(20		)
Decrease in restricted cash to support equity requirements for U.S. DOE funded projects	12			95
Increase in notes receivable	(9		)	(7		)
Investments in nuclear decommissioning trust fund securities	(95		)	(126		)
Proceeds from sales of nuclear decommissioning trust fund securities	85			119
Proceeds from renewable energy grants	16			28
Other	(1		)	7
Net Cash Used by Investing Activities	(836		)	(543		)
Cash Flows from Financing Activities
Payment of dividends to common and preferred stockholders	(31		)	(2		)
Payment for treasury stock	(20		)	—
Net receipts/(payments for) settlement of acquired derivatives that include financing elements	98			(20		)
Sale proceeds and other contributions from noncontrolling interests in subsidiaries	20			178
Proceeds from issuance of long-term debt	736			415
Proceeds from issuance of common stock	1			—
Payment of debt issuance and hedging costs	(5		)	(10		)
Payments for short and long-term debt	(219		)	(34		)
Net Cash Provided by Financing Activities	580			527
Effect of exchange rate changes on cash and cash equivalents	—			1
Net Decrease in Cash and Cash Equivalents	(380		)	(91		)
Cash and Cash Equivalents at Beginning of Period	2,087			1,105
Cash and Cash Equivalents at End of Period	$	1,707		$	1,014

See accompanying notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 — Basis of Presentation

NRG Energy, Inc., or NRG or the Company, is a competitive power and energy company that aspires to be a leader in the way the industry and consumers think about, use, produce and deliver energy and energy services in major competitive power markets in the United States. At its core, NRG is a wholesale power generator engaged in the ownership and operation of power generation facilities; the trading of energy, capacity and related products; and the transacting in and trading of fuel and transportation services. Second, while leveraging its core wholesale power business, NRG is a retail energy company engaged in the supply of energy, services, and innovative, sustainable products to retail customers in competitive markets through multiple channels and brands like Reliant Energy, Green Mountain Energy and Energy Plus (collectively, the Retail Business). Finally, NRG is a clean energy leader and is focused on the deployment and commercialization of potentially disruptive technologies, like electric vehicles, Distributed Solar and smart meter technology, which have the potential to change the nature of the power supply industry. On December 14, 2012, the Company acquired GenOn as further described in Note 3, Business Acquisitions and Dispositions, and has reported results of operations from the acquisition date forward.

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 Company's 2012 Form 10-K. Interim results are not necessarily indicative of results for a full year.

In the opinion of management, the accompanying unaudited interim condensed consolidated financial statements contain all material adjustments consisting of normal and recurring accruals necessary to present fairly the Company's consolidated financial position as of March 31, 2013, and the results of operations, comprehensive loss and cash flows for the three months ended March 31, 2013, and 2012.

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.

Reclassifications

Certain prior-year amounts have been reclassified for comparative purposes. The reclassifications did not affect results from operations or cash flows. The Company reclassified certain plant-related expenses from selling, general and administrative to cost of operations and certain general and administrative expenses to development activity expenses.

Note 2 — Summary of Significant Accounting Policies

Development Activity Expenses

Development activity expenses include project development costs, which are expensed in the preliminary stages of a project and capitalized when the project is deemed to be commercially viable. Commercial viability is determined by one or a series of actions including, among others, Board of Director approval pursuant to a formal project plan that subjects the Company to significant future obligations that can only be discharged by the use of a Company asset. When a project is available for operations, capitalized project development costs are reclassified to property, plant and equipment and amortized on a straight-line basis over the estimated useful life of the project's related assets. Capitalized costs are charged to expense if a project is abandoned or management otherwise determines the costs to be unrecoverable.

Development activity expenses also include selling, general, and administrative expenses associated with the current operations of certain developing businesses including residential solar, electric vehicles, waste-to-energy, carbon capture and other emerging technologies. The revenue associated with these businesses was immaterial for the three months ended March 31, 2013 and 2012. When it is determined that a business will remain an ongoing part of the Company's operations or when operating revenues become material relative to the operating costs of the underlying business, the Company no longer classifies a business as a development activity.

Other Cash Flow Information

NRG’s investing activities exclude capital expenditures of $51 million which were accrued and unpaid at March 31, 2013, primarily for solar projects under construction.

Noncontrolling Interests

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



	(In millions)
Balance as of December 31, 2012	$	518
Contributions from noncontrolling interest	27
Comprehensive income attributable to noncontrolling interest	1
Balance as of March 31, 2013	$	546

Recent Accounting Developments

ASU 2011-11 - Effective January 1, 2013, the Company adopted the provisions of ASU No. 2011-11, Balance Sheet (Topic 210) Disclosures about Offsetting Assets and Liabilities, or ASU No. 2011-11, and began providing enhanced disclosures regarding the effect or potential effect of netting arrangements on an entity's financial position by improving information about financial instruments and derivative instruments that either (1) offset in accordance with either ASC 210-20-45 or ASC 810-20-45 or (2) are subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset. Reporting entities are required to disclose both gross and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. The disclosures required by ASU No. 2011-11 are required to be adopted retroactively. As this guidance provides only disclosure requirements, the adoption of this standard did not impact the Company's results of operations, cash flows or financial position.

ASU 2013-02 - Effective January 1, 2013, the Company adopted the provisions of ASU No. 2013-02, Other Comprehensive Income (Topic 220) Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income, or ASU No. 2013-02, and began reporting the effect of significant reclassifications out of accumulated other comprehensive income on the respective line items in net income within the notes to the financial statements if the amount being reclassified is required under U.S. GAAP to be reclassified in its entirety to net income in the same reporting period. For other amounts not required by U.S. GAAP to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference other disclosures which provide additional information about the amounts. The provisions of ASU No. 2013-02 are required to be adopted prospectively. As this guidance provides only presentation requirements, the adoption of this standard did not impact the Company's results of operations, cash flows or financial position.

Note 3 — Business Acquisitions and Dispositions

GenOn Acquisition

On December 14, 2012, NRG completed the acquisition of GenOn Energy, Inc., or GenOn. GenOn, a generator of wholesale electricity, has baseload, intermediate and peaking power generation facilities using coal, natural gas and oil, totaling approximately 21,440 MW. Consideration for the acquisition was valued at $2.2 billion and was comprised of 0.1216 shares of NRG common stock for each outstanding share of GenOn, including restricted stock units outstanding, on the acquisition date, except for fractional shares which were paid in cash. The Company issued 93.9 million shares of NRG common stock, or 29% of total common shares outstanding following the closing of the transaction. The acquisition was recorded as a business combination, 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 evaluations necessary to assess the fair value of certain net assets acquired is still in process. See Note 3, Business Acquisitions and Dispositions in the Company's 2012 Form 10-K for additional information related to the GenOn acquisition.

The following table summarizes the provisional amounts recognized for assets acquired and liabilities assumed as of the acquisition date as well as adjustments made in the first quarter of 2013 to the amounts initially recorded in 2012. The measurement period adjustments did not have a significant impact on the Company's consolidated statements of operations, cash flows or financial position in any period. 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.



(in millions)	Amounts Recognized as of Acquisition Date (as previously reported)		Measurement Period Adjustments			Amounts Recognized as of Acquisition Date (as adjusted)
Assets
Cash	$	983	$	—		$	983
Current and non-current assets	1,385		—			1,385
Property, plant and equipment	3,936		—			3,936
Derivative assets	1,157		—			1,157
Deferred income taxes	2,265		6			2,271
Total assets acquired	$	9,726	$	6		$	9,732

Liabilities
Current and non-current liabilities	$	1,312	$	17		$	1,329
Out-of-market contracts and leases	1,064		—			1,064
Derivative liabilities	399		—			399
Long-term debt and capital leases	4,203		—			4,203
Total liabilities assumed	6,978		17			6,995
Net assets acquired	2,748		(11		)	2,737
Consideration paid	2,188					2,188
Gain on bargain purchase	$	560	$	(11	)	$	549

2012 Dispositions

Agua Caliente

On January 18, 2012, the Company completed the sale of a 49% interest in NRG Solar AC Holdings LLC, the indirect owner of the Agua Caliente project, to MidAmerican Energy Holdings Company, or MidAmerican. A majority of the $122 million of cash consideration received at closing represented 49% of construction costs funded by NRG's equity contributions. The excess of the consideration over the carrying value of the divested interest was recorded to additional paid-in capital. MidAmerican will fund its proportionate share of future equity contributions and other credit support for the project. NRG continues to hold a majority interest in and consolidate the project.

Saale Energie GmbH

On July 17, 2012, the Company completed the sale of its 100% interest in Saale Energie GmbH, which holds a 41.9% interest in Kraftwerke Schkopau GbR and a 44.4% interest in Kraftwerke Schkopau Betriebsgesllschaft mbH, collectively, Schkopau. Schkopau holds a fixed 400 MW participation in the 900 MW Schkopau Power Station located in Germany. In connection with the sale of Schkopau, NRG entered into a foreign currency swap contract to hedge the impact of exchange rate fluctuations on the sale proceeds of €141 million. The Company received cash consideration, net of selling expenses, of $174 million, which included $4 million related to the settlement of the swap contract that was recorded as a gain within Other income, net in the quarter ended September 30, 2012. The cash consideration approximated the book value of the net assets, including cash of $38 million, on the date of the sale.

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 2012 Form 10-K.

For cash and cash equivalents, funds deposited by counterparties, accounts receivable, accounts payable, accrued expenses and other current liabilities, restricted cash, and cash collateral paid and received in support of energy risk management activities, the carrying amount approximates fair value because of the short-term maturity of those instruments and are classified as Level 1 within the fair value hierarchy.

The estimated carrying amounts and fair values of NRG's recorded financial instruments not carried at fair market value are as follows:



	As of March 31, 2013				As of December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Assets:
Notes receivable^(a)	$	97	$	97	$	88	$	88
Liabilities:
Long-term debt, including current portion	16,457		17,133		15,866		16,492

(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 1 within the fair value hierarchy. The fair value of debt securities, non publicly-traded long-term debt, and certain notes receivable of the Company are based on expected future cash flows discounted at market interest rates, or current interest rates for similar instruments with equivalent credit quality and are classified as Level 3 within the fair value hierarchy.

Recurring Fair Value Measurements

Debt securities, equity securities, and trust fund investments, which are comprised of various U.S. debt and equity securities, and derivative assets and liabilities, are carried at fair market value.

The following tables present assets and liabilities measured and recorded at fair value on the Company's condensed consolidated balance sheet on a recurring basis and their level within the fair value hierarchy:



	As of March 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	$	—	$	—	$	13	$	13
Other ^(a)	45		—		—		45
Trust fund investments:
Cash and cash equivalents	1		—		—		1
U.S. government and federal agency obligations	34		6		—		40
Federal agency mortgage-backed securities	—		57		—		57
Commercial mortgage-backed securities	—		16		—		16
Corporate debt securities	1		78		—		79
Equity securities	258		—		50		308
Foreign government fixed income securities	—		1		—		1
Derivative assets:
Commodity contracts	1,719		1,547		99		3,365
Interest rate contracts	—		2		—		2
Total assets	$	2,058	$	1,707	$	162	$	3,927
Derivative liabilities:
Commodity contracts	$	1,606	$	1,143	$	94	$	2,843
Interest rate contracts	—		127		—		127
Total liabilities	$	1,606	$	1,270	$	94	$	2,970

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



	As of December 31, 2012
	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	$	—	$	—	$	12	$	12
Other ^(a)	44		—		—		44
Trust fund investments:
Cash and cash equivalents	10		—		—		10
U.S. government and federal agency obligations	34		—		—		34
Federal agency mortgage-backed securities	—		59		—		59
Commercial mortgage-backed securities	—		9		—		9
Corporate debt securities	—		80		—		80
Equity securities	233		—		47		280
Foreign government fixed income securities	—		2		—		2
Derivative assets:
Commodity contracts	1,457		1,711		135		3,303
Interest rate contracts	—		3		—		3
Total assets	$	1,778	$	1,864	$	194	$	3,836
Derivative liabilities:
Commodity contracts	$	1,144	$	1,047	$	147	$	2,338
Interest rate contracts	—		143		—		143
Total liabilities	$	1,144	$	1,190	$	147	$	2,481

(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 months ended March 31, 2013, and 2012, between Levels 1 and 2. The following tables reconcile, for the three months ended March 31, 2013 and 2012, the beginning and ending balances for financial instruments that are recognized at fair value in the consolidated financial statements at least annually using significant unobservable inputs:



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


(a)	Consists of derivatives 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 March 31, 2012
(In millions)	Debt Securities		Trust Fund Investments		Derivatives^(a)			Total
Beginning balance as of January 1, 2012	$	7	$	42	$	8		$	57
Total gains - realized/unrealized:
Included in earnings	—		—		17			17
Included in OCI	1		—		—			1
Included in nuclear decommissioning obligations	—		4		—			4
Purchases	—		—		(4		)	(4		)
Transfers into Level 3 ^(b)	—		—		10			10
Transfers out of Level 3 ^(b)	—		—		12			12
Ending balance as of March 31, 2012	$	8	$	46	$	43		$	97
The amount of the total gains for the period included in earnings attributable to the change in unrealized derivatives relating to assets still held as of March 31, 2012	$	—	$	—	$	18		$	18


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


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

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

Derivative Fair Value Measurements

A majority of NRG's contracts are exchange-traded contracts with readily available quoted market prices. A portion 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. For the majority of NRG markets, the Company receives quotes from multiple sources. To the extent that NRG receives multiple quotes, the Company's prices reflect the average of the bid-ask mid-point prices obtained from all sources that NRG believes provide the most liquid market for the commodity. If the Company receives one quote, then the mid-point of the bid-ask spread for that quote is used. The terms for which such price information is available vary by commodity, region and product. A significant portion of the fair value of the Company's derivative portfolio is based on price quotes from brokers in active markets who regularly facilitate those transactions and the Company believes such price quotes are executable. The Company does not use third party sources that derive price based on proprietary models or market surveys. 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. Contracts valued with prices provided by models and other valuation techniques make up 3% of the total derivative assets and 3% 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. To the extent that NRG's net exposure under a specific master agreement is an asset, the Company uses the counterparty's default swap rate. If the net exposure under a specific master agreement is a liability, the Company uses NRG's default swap rate. The credit reserve is added to the discounted fair value to reflect the exit price that a market participant would be willing to receive to assume NRG's liabilities or that a market participant would be willing to pay for NRG's assets. As of March 31, 2013, the credit reserve resulted in a $5 million increase in fair value which is composed of a $3 million gain in OCI, and a $2 million gain in operating revenue and cost of operations. As of March 31, 2012, the credit reserve resulted in an $8 million increase in fair value which is composed of a $1 million gain in OCI and a $7 million gain 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 2012 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 monitors and manages counterparty credit risk through credit policies that include: (i) an established credit approval process; (ii) daily monitoring of counterparties' credit limits; (iii) the use of credit mitigation measures such as margin, collateral, prepayment arrangements, or volumetric limits; (iv) the use of payment netting arrangements; and (v) the use of master netting agreements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. Risk surrounding counterparty performance and credit could ultimately impact the amount and timing of expected cash flows. The Company seeks to mitigate counterparty credit risk with a diversified portfolio of counterparties. The Company also has credit protection within various agreements to call on additional collateral support if and when necessary. Cash margin is collected and held at NRG to cover the credit risk of the counterparty until positions settle.

As of March 31, 2013, counterparty credit exposure to a portion of the Company's counterparties was $1.3 billion and NRG held collateral (cash and letters of credit) against those positions of $105 million, resulting in a net exposure of $1.2 billion. Approximately 83% of the Company's exposure before collateral is expected to roll off by the end of 2014. 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 Normal Purchase Normal Sale, or NPNS, and non-derivative transactions. The exposure is shown net of collateral held, and includes amounts net of receivables or payables.



	Net Exposure ^(a)
Category	(% of Total)
Financial institutions	51	%
Utilities, energy merchants, marketers and other	37
Independent System Operators, or ISOs	11
Coal and emissions	1
Total as of March 31, 2013	100	%



	Net Exposure ^(a)
Category	(% of Total)
Investment grade	93	%
Non-rated ^(b)	6
Non-Investment grade	1
Total as of March 31, 2013	100	%


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


(b)	For non-rated counterparties, the majority 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 representing more than 10% of total net exposure discussed above and the aggregate of such counterparties' exposure was $412 million. Changes in hedge positions and market prices will affect credit exposure and counterparty concentration. Given the credit quality, diversification and term of the exposure in the portfolio, NRG does not anticipate a material impact on the Company's financial position or results of operations from nonperformance by any of NRG's counterparties.

Counterparty credit exposure described above excludes credit risk exposure under certain long term agreements, including California tolling agreements, South Central load obligations, and solar Power Purchase Agreements, or PPAs. As external sources or observable market quotes are not available to estimate such exposure, the Company valued these contracts based on various techniques including, but not limited to, internal models based on a fundamental analysis of the market and extrapolation of observable market data with similar characteristics. Based on these valuation techniques, as of March 31, 2013, credit risk exposure to these counterparties attributable to NRG's ownership interests was approximately $1.3 billion for the next five years. This amount excludes potential credit exposures for projects with long term PPAs that have not reached commercial operations. Many of these power contracts are with utilities or public power entities that have strong credit quality and specific public utility commission or other regulatory support. These factors significantly reduce the risk of loss.

Retail Customer Credit Risk

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

As of March 31, 2013, the Company's retail customer credit exposure was diversified across many customers and various industries, with a significant portion of the exposure with government entities.

Note 5 — Nuclear Decommissioning Trust Fund

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, or ASC 980, because the Company's nuclear decommissioning activities are subject to approval by the PUCT with regulated rates that are designed to recover all decommissioning costs and that can be charged to and collected from the ratepayers per PUCT mandate. Since the Company is in compliance with PUCT rules and regulations regarding decommissioning trusts and the cost of decommissioning is the responsibility of the Texas ratepayers, not NRG, all realized and unrealized gains or losses (including other-than-temporary impairments) related to the Nuclear Decommissioning Trust Fund are recorded to nuclear decommissioning trust liability and are not included in net income or accumulated other comprehensive income, consistent with regulatory treatment.

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



	As of March 31, 2013					As of December 31, 2012
(In millions, except otherwise noted)	Fair Value		Unrealized Gains ^(a)		Weighted- average maturities (in years)	Fair Value		Unrealized Gains ^(a)		Weighted- average maturities (in years)
Cash and cash equivalents	$	1	$	—	—	$	10	$	—	—
U.S. government and federal agency obligations	39		2		9	33		2		10
Federal agency mortgage-backed securities	57		2		25	59		2		23
Commercial mortgage-backed securities	16		—		29	9		—		30
Corporate debt securities	79		3		10	80		4		11
Equity securities	308		169		—	280		143		—
Foreign government fixed income securities	1		—		11	2		—		6
Total	$	501	$	176		$	473	$	151

(a) There were no unrealized losses as of March 31, 2013 or December 31, 2012.

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



	Three months ended March 31,
	2013		2012
	(In millions)
Realized gains	$	1	$	3
Realized losses	1		2
Proceeds from sale of securities	85		119

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 2012 Form 10-K.

Energy-Related Commodities

As of March 31, 2013, NRG had energy-related derivative financial instruments extending through 2015, which are designated as cash flow hedges.

Interest Rate Swaps

NRG is exposed to changes in interest rates through the Company's issuance of variable and fixed rate debt. In order to manage the Company's interest rate risk, NRG enters into interest rate swap agreements. As of March 31, 2013, the Company had interest rate derivative instruments on non-recourse debt extending through 2030, the majority of which are designated as cash flow hedges.

Volumetric Underlying Derivative Transactions

The following table summarizes the net notional volume buy/(sell) of NRG's open derivative transactions broken out by commodity, excluding those derivatives that qualified for the NPNS exception as of March 31, 2013 and December 31, 2012. 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
Commodity	Units	March 31, 2013			December 31, 2012
		(In millions)
Emissions	Short Ton	(1		)	(1		)
Coal	Short Ton	45			37
Natural Gas	MMBtu	(330		)	(413		)
Oil	Barrel	1			1
Power	MWh	(18		)	(14		)
Interest	Dollars	$	1,650		$	2,612

The decrease in the natural gas position was the result of additional purchases entered into during the year to hedge our retail portfolio as well as the settlement of positions during the period. These amounts were slightly offset by natural gas sales entered into during the year to hedge our conventional power generation. The decrease in the interest rate position was primarily the result of the settlement of interest rate swaps.

Fair Value of Derivative Instruments

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



	Fair Value
	Derivative Assets				Derivative Liabilities
	March 31, 2013		December 31, 2012		March 31, 2013		December 31, 2012
	(In millions)
Derivatives Designated as Cash Flow Hedges:
Interest rate contracts current	$	—	$	—	$	29	$	29
Interest rate contracts long-term	2		3		85		96
Commodity contracts current	—		—		5		3
Commodity contracts long-term	—		—		1		1
Total Derivatives Designated as Cash Flow Hedges	2		3		120		129
Derivatives Not Designated as Cash Flow Hedges:
Interest rate contracts current	—		—		4		7
Interest rate contracts long-term	—		—		9		11
Commodity contracts current	2,805		2,644		2,455		1,942
Commodity contracts long-term	560		659		382		392
Total Derivatives Not Designated as Cash Flow Hedges	3,365		3,303		2,850		2,352
Total Derivatives	$	3,367	$	3,306	$	2,970	$	2,481

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



	Gross Amounts Not Offset in the Statement of Financial Position
	Gross Amounts of Recognized Assets / Liabilities			Derivative Instruments			Cash Collateral (Held) / Posted			Net Amount
As of March 31, 2013	(in millions)
Commodity contracts:
Derivative assets	$	3,365		$	(2,545	)	$	(225	)	$	595
Derivative liabilities	(2,843		)	2,545			19			(279		)
Total commodity contracts	522			—			(206		)	316
Interest rate contracts:
Derivative assets	2			—			—			2
Derivative liabilities	(127		)	—			—			(127		)
Total interest rate contracts	(125		)	—			—			(125		)
Total derivative instruments	$	397		$	—		$	(206	)	$	191



	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, 2012	(in millions)
Commodity contracts:
Derivative assets	$	3,303		$	(2,024	)	$	(374	)	$	905
Derivative liabilities	(2,338		)	2,024			28			(286		)
Total commodity contracts	965			—			(346		)	619
Interest rate contracts:
Derivative assets	3			—			—			3
Derivative liabilities	(143		)	—			—			(143		)
Total interest rate contracts	(140		)	—			—			(140		)
Total derivative instruments	$	825		$	—		$	(346	)	$	479

Accumulated Other Comprehensive Income

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



	Three months ended March 31, 2013									Three months ended March 31, 2012
	Energy Commodities			Interest Rate			Total			Energy Commodities			Interest Rate			Total
	(In millions)
Accumulated OCI beginning balance	$	41		$	(72	)	$	(31	)	$	188		$	(56	)	$	132
Reclassified from accumulated OCI to income:
Due to realization of previously deferred amounts	(8		)	3			(5		)	(31		)	3			(28		)
Mark-to-market of cash flow hedge accounting contracts	9			3			12			13			6			19
Accumulated OCI ending balance, net of $15 and $82 tax, respectively	$	42		$	(66	)	$	(24	)	$	170		$	(47	)	$	123
Gains/(losses) expected to be realized from OCI during the next 12 months, net of $19 and $66 tax, respectively	$	42		$	(10	)	$	32		$	137		$	(23	)	$	114
(Losses)/gains recognized in income from the ineffective portion of cash flow hedges	$	(1	)	$	1		$	—		$	(1	)	$	(2	)	$	(3	)

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.

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 March 31,
(In millions)	2013			2012
Unrealized mark-to-market results
Reversal of previously recognized unrealized gains on settled positions related to economic hedges	$	(25	)	$	(41	)
Reversal of (gain)/loss positions acquired as part of the Reliant Energy, Green Mountain Energy and GenOn acquisitions	(88		)	14
Net unrealized losses on open positions related to economic hedges	(149		)	(137		)
Losses on ineffectiveness associated with open positions treated as cash flow hedges	(1		)	(1		)
Total unrealized mark-to-market losses for economic hedging activities	(263		)	(165		)
Reversal of previously recognized unrealized gains on settled positions related to trading activity	(28		)	(30		)
Reversal of gain positions acquired as part of the GenOn acquisitions	(2		)	—
Net unrealized (losses)/gains on open positions related to trading activity	(13		)	28
Total unrealized mark-to-market losses for trading activity	(43		)	(2		)
Total unrealized losses	$	(306	)	$	(167	)



	Three months ended March 31,
(In millions)	2013			2012
Revenue from operations — energy commodities	$	(521	)	$	38
Cost of operations	215			(205		)
Total impact to statement of operations — energy commodities	$	(306	)	$	(167	)
Total impact to statement of operations — interest rate contracts	$	2		$	(1	)

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

For the three months ended March 31, 2013, the unrealized loss from open economic hedge positions was primarily the result of a decrease in value of forward purchases and sales of natural gas and electricity due to an increase in forward natural gas and electricity prices.

For the three months ended March 31, 2012, the unrealized loss from open economic hedge positions was the result of a decrease in value of forward purchases of coal, due to decreases in forward coal prices along with a decrease in value of forward purchases and sales of natural gas and electricity, due to a decrease in forward power and gas prices and increases in ERCOT heat rates.

Credit Risk Related Contingent Features

Certain of the Company's hedging agreements contain provisions that require the Company to post additional collateral if the counterparty determines that there has been deterioration in credit quality, generally termed “adequate assurance” under the agreements, or requires the Company to post additional collateral if there were a one notch downgrade in the Company's credit rating. The collateral required for contracts with adequate assurance clauses that are in a net liability position as of March 31, 2013 was $75 million. The collateral required for contracts with credit rating contingent features was $56 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 $38 million as of March 31, 2013.

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 11, Debt and Capital Leases, to the Company's 2012 Form 10-K.

Long-term debt and capital leases consisted of the following:



	March 31, 2013		December 31, 2012		Interest rate % ^(a)
	(In millions, except rates)
NRG Recourse Debt:
Senior notes, due 2018	$	1,130	$	1,200	7.625
Senior notes, due 2019	800		800		7.625
Senior notes, due 2019	601		693		8.500
Senior notes, due 2020	1,063		1,100		8.250
Senior notes, due 2021	1,128		1,128		7.875
Senior notes, due 2023	990		990		6.625
Term loan facility, due 2018	1,569		1,573		L+2.50 - 3.00
Indian River Power LLC, tax-exempt bonds, due 2040 and 2045	247		247		5.375 - 6.000
Dunkirk Power LLC, tax-exempt bonds, due 2042	59		59		5.875
Fort Bend County, tax-exempt bonds, due 2038 and 2042	35		28		4.750
Subtotal NRG Recourse Debt	7,622		7,818
NRG Non-Recourse Debt:
GenOn senior notes, due 2014	610		617		7.625
GenOn senior notes, due 2017	795		800		7.875
GenOn senior notes, due 2018	796		801		9.500
GenOn senior notes, due 2020	629		631		9.875
GenOn Americas Generation senior notes, due 2021	508		509		8.500
GenOn Americas Generation senior notes, due 2031	436		437		9.125
GenOn Marsh Landing term loans, due 2017 and 2023	435		390		L+2.50 - 2.75
CVSR - High Plains Ranch II LLC, due 2037	995		786		0.611 - 2.935
NRG West Holdings LLC, term loan, due 2023	407		350		L+2.25 - 2.75
Agua Caliente Solar, LLC, due 2037	683		640		2.395 - 3.256
Ivanpah Financing, due 2014 and 2038	1,510		1,437		1.116 - 4.256
South Trent Wind LLC, financing agreement, due 2020	72		72		L+2.625
NRG Peaker Finance Co. LLC, bonds, due 2019	174		173		L+1.07
NRG Energy Center Minneapolis LLC, senior secured notes, due 2013, 2017 and 2025	134		137		5.95 - 7.31
NRG Solar Alpine LLC, due 2013 and 2022	228		2		L+2.25 - 2.50
NRG Solar Borrego LLC, due 2024 and 2038	81		—		L+2.50/5.65
NRG Solar Avra Valley LLC	69		66		L+2.25
TA - High Desert LLC, due 2013, 2023 and 2033	82		—		L+2.50/5.15
Other	191		200		various
Subtotal NRG Non-Recourse Debt	8,835		8,048
Subtotal long-term debt (including current maturities)	16,457		15,866
Capital leases:
Chalk Point capital lease, due 2015	13		14		8.190
Subtotal	16,470		15,880
Less current maturities	556		147
Total long-term debt and capital leases	$	15,914	$	15,733

(a) L+ equals 3 month LIBOR plus x%, with the exception of (i) GenOn Marsh Landing term loans, (ii) NRG Solar Alpine LLC cash grant loans and (iii) NRG Solar Avra Valley LLC cash grant loans which are 1 month LIBOR plus x%.

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, primarily consisting of the premiums paid on the repurchases and the write-off of previously deferred financing costs.

Alpine Financing

On March 16, 2012 NRG Solar Alpine LLC, a wholly owned subsidiary of NRG, entered into a credit agreement with a group of lenders for a $166 million construction loan that will convert to a term loan upon completion of the project and a $68 million cash grant loan. On January 15, 2013, the credit agreement was amended reducing the cash grant loan to $63 million. On March 26, 2013, NRG Solar Alpine LLC met the conditions under the credit agreement to convert the construction loan for the facility to a term loan. Immediately prior to the conversion, the Company drew an additional $164 million under the construction loan and $62 million under the cash grant loan. The term loan amortizes on a predetermined schedule with final maturity in November 2022. As of March 31, 2013, $166 million was outstanding under the term loan, $62 million under the cash grant loan, and $36 million of letters of credit were issued under the credit agreement.

Borrego Financing

On March 28, 2013, NRG, through its wholly-owned subsidiary, NRG Solar Borrego LLC, or Borrego, entered into a credit agreement with a group of lenders, or the Borrego Financing Agreement, for $45 million of 5.65% fixed rate notes and a $36 million term loan. The term loan has an interest rate of 3 month LIBOR plus an applicable margin of 2.50%, which escalates 0.25% on the fourth and eighth anniversary of the closing date. The fixed rate notes mature in February 2038 and the term loan matures in December 2024. Both amortize based upon predetermined schedules. The Borrego Financing Agreement also includes a letter of credit facility on behalf of Borrego of up to $5 million. Borrego pays an availability fee of 100% of the applicable margin on issued letters of credit. As of March 31, 2013, $45 million was outstanding under the fixed rate notes, $36 million was outstanding under the term loans, and $5 million of letters of credit in support of the project were issued.

Under the terms of the Borrego Financing Agreement, on March 28, 2013, Borrego was required to enter into two fixed for floating interest rate swaps that would fix the interest rate for a minimum of 75% of the outstanding notional amount. Borrego will pay its counterparty the equivalent of a 1.125% fixed interest payment on a predetermined notional value, and Borrego will receive quarterly the equivalent of a floating interest payment based on a 3 month LIBOR calculated on the same notional value through June 30, 2020. All interest rate swap payments by Borrego and its counterparties are made quarterly and the LIBOR rate is determined in advance of each interest period. The original notional amount of the swaps, which became effective April 3, 2013, is $15 million and will amortize in proportion to the term loan.

High Desert Facility

In March 2013, the Company, through its wholly-owned subsidiary, NRG Solar PV LLC, acquired High Desert, a 20 MW utility-scale photovoltaic solar facility located in Lancaster, California shortly, before commercial operation. As part of the acquisition of High Desert, NRG recorded $82 million of non-recourse project level debt issued under the High Desert Facility which is comprised of $53 million of fixed rate notes due 2033 at an interest rate of 5.15% and $7 million of floating rate notes due 2023, $22 million of bridge notes due the earlier of 10 days after receipt of the cash grant or August 2013, and a revolving facility of $12 million. The floating rate notes, bridge notes and revolving facility have an interest rate of 3 month LIBOR plus 2.5%. The revolving facility can be used in cash or for the issuance of up to $9 million in letters of credit. As of March 31, 2013, $9 million of letters of credit were issued under the revolving facility. The notes amortize on predetermined schedules and are secured by all of the assets of High Desert.

Note 8 — Variable Interest Entities, or VIEs

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 subsidiary, NRG Connecticut Peaking Development LLC, NRG owns a 50% interest in GenConn, a limited liability company which owns and operates two 200 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 $129 million as of March 31, 2013.

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 $89 million as of March 31, 2013.

Texas Coastal Ventures, LLC — NRG owns a 50% interest in Texas Coastal Ventures, a joint venture with Hilcorp Energy I, L.P., through its subsidiary Petra Nova LLC. NRG's maximum exposure to loss is limited to its equity investment, which was $59 million as of March 31, 2013.

Note 9 — Changes in Capital Structure

As of March 31, 2013, and December 31, 2012, the Company had 500,000,000 shares of common stock authorized. The following table reflects the changes in NRG's common shares issued and outstanding:



	Issued	Treasury		Outstanding
Balance as of December 31, 2012	399,112,616	(76,505,718	)	322,606,898
Shares issued under LTIP	707,261	—		707,261
Shares issued under ESPP	—	61,219		61,219
Capital Allocation Program repurchases	—	(972,292	)	(972,292	)
Balance as of March 31, 2013	399,819,877	(77,416,791	)	322,403,086

2013 Capital Allocation Program

On February 27, 2013, the Company announced its intention to increase NRG's annual common stock dividend by 33%, to $0.48 per share, commencing with the next quarterly payment. On April 19, 2013, NRG declared a quarterly dividend on the Company's common stock of $0.12 per share, payable May 15, 2013, to shareholders of record as of May 1, 2013.

In addition, the Company is authorized to repurchase $200 million of its common stock under the 2013 Capital Allocation Program. During the first quarter, the Company purchased 972,292 shares of NRG common stock for approximately $25 million at a volume weighted average cost of $25.88 per share, of which 195,210 shares settled in April 2013 for which $5 million was accrued as of March 31, 2013. The Company intends to complete its remaining $175 million of share repurchases by the end of 2013. The Company's common stock dividend and share repurchases are subject to available capital, market conditions, and compliance with associated laws and regulations.

Note 10 — Loss Per Share

Basic loss per common share is computed by dividing net loss less accumulated preferred stock dividends by the weighted average number of common shares outstanding. Shares issued and treasury shares repurchased during the year are weighted for the portion of the year that they were outstanding.

The reconciliation of NRG's basic and diluted loss per share is shown in the following table:



	Three months ended March 31,
(In millions, except per share data)	2013			2012
Basic and diluted loss per share attributable to NRG common stockholders
Numerator:
Net loss attributable to NRG Energy, Inc.	$	(328	)	$	(207	)
Preferred stock dividends	(2		)	(2		)
Net loss attributable to NRG Energy, Inc. available to common stockholders	$	(330	)	$	(209	)
Denominator:
Weighted average number of common shares outstanding	323			228
Basic and diluted loss per share:
Net loss attributable to NRG Energy, Inc.	$	(1.02	)	$	(0.92	)

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



	Three months ended March 31,
(In millions of shares)	2013	2012
Equity compensation plans	13	12
Embedded derivative of 3.625% redeemable perpetual preferred stock	16	16
Total	29	28

Note 11 — Segment Reporting

The Company's businesses are primarily segregated based on the Retail Business, conventional power generation, alternative energy businesses and corporate activities. Within NRG's conventional power generation operations, there are distinct components with separate operating results and management structures for the following geographical regions: Texas, East, South Central, West and Other, which includes its international businesses, thermal and chilled water business and maintenance services. The Company's alternative energy businesses include solar and wind assets, electric vehicle services and the carbon capture business. Intersegment sales are accounted for at market.



(In millions)			Conventional Power Generation
Three months ended March 31, 2013	Retail^(a)		Texas^(a)			East^(a)			South Central^(a)			West			Other^(a)		Alternative Energy^(a)			Corporate^(a)(b)			Elimination			Total
Operating revenues	$	1,231	$	84		$	595		$	196		$	91		$	73	$	50		$	8		$	(247	)	$	2,081
Depreciation and amortization	32		112			78			24			13			5		30			4			—			298
Equity in earnings/(loss) of unconsolidated affiliates	—		—			4			—			1			1		(3		)	—			—			3
Income/(loss) before income taxes	369		(426		)	(155		)	(7		)	(7		)	5		(23		)	(232		)	—			(476		)
Net income/(loss) attributable to NRG Energy, Inc.	$	369	$	(426	)	$	(155	)	$	(7	)	$	(7	)	$	5	$	(24	)	$	(83	)	$	—		$	(328	)
Total assets	$	3,273	$	10,705		$	7,772		$	2,033		$	1,936		$	812	$	6,516		$	28,069		$	(25,745	)	$	35,371



(a) Includes intersegment sales and derivative gains and losses of:	$	1	$	229	$	(9	)	$	2	$	—	$	16	$	4	$	4

(b)Includes loss on debt extinguishment of $28 million.



(In millions)			Conventional Power Generation
Three months ended March 31, 2012	Retail		Texas^(c)			East^(c)			South Central			West			Other^(c)		Alternative Energy^(c)			Corporate			Elimination			Total
Operating revenues	$	1,166	$	458		$	148		$	173		$	42		$	94	$	22		$	3		$	(244	)	$	1,862
Depreciation and amortization	41		114			32			23			2			4		11			3			—			230
Equity in earnings/(loss) of unconsolidated affiliates	—		—			5			—			(2		)	3		2			—			—			8
Income/(loss) before income taxes	7		(74		)	(44		)	(30		)	(14		)	10		(13		)	(168		)	—			(326		)
Net income/(loss) attributable to NRG Energy, Inc.	$	7	$	(74	)	$	(44	)	$	(30	)	$	(14	)	$	8	$	(14	)	$	(46	)	$	—		$	(207	)



(c) Includes intersegment sales and derivative gains and losses of:	$	—	$	182	$	35	$	—	$	—	$	20	$	4	$	—

Note 12 — Income Taxes

Effective Tax Rate

The income tax provision consisted of the following:



	Three months ended March 31,
(In millions except otherwise noted)	2013			2012
Loss before income taxes	$	(476	)	$	(326	)
Income tax benefit	(149		)	(120		)
Effective tax rate	31.3		%	36.8		%

For the three months ended March 31, 2013, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to changes in the valuation allowance as a result of capital losses generated during the period.

For the three months ended March 31, 2012, 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.

Uncertain tax benefits

As of March 31, 2013, NRG has recorded a non-current tax liability of $74 million for uncertain tax benefits from positions taken on various state tax returns, including accrued interest. NRG has accrued interest related to these uncertain tax benefits of $1 million for the three months ended March 31, 2013, and has accrued $17 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. Prior to the GenOn acquisition, the Company was not subject to U.S. federal income tax examinations for years prior to 2007. As a result of the acquisition, the Company is subject to U.S. federal income tax examinations for certain subsidiaries for years subsequent to 2001. With few exceptions, state and local income tax examinations are no longer open for years before 2003. The Company's primary foreign operations are also no longer subject to examination by local jurisdictions for years prior to 2004.

Note 13 — Commitments and Contingencies

Commitments

First Lien Structure

NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, excluding assets acquired in the GenOn acquisition, to reduce the amount of cash collateral and letters of credit that it would otherwise be required to post from time to time to support its obligations under out-of-the-money hedge agreements for forward sales of power or MWh equivalents. The Company's lien counterparties may have a claim on NRG's assets to the extent market prices exceed the hedged price. As of March 31, 2013, hedges under the first lien were out-of-the-money for NRG on a counterparty aggregate basis.

Contingencies

Set forth below is a description of the Company's material legal proceedings. 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.

Louisiana Generating, LLC

In 2009, the U.S. DOJ, on behalf of the EPA, and later the Louisiana Department of Environmental Quality, or LDEQ, on behalf of the State of Louisiana, sued Louisiana Generating, LLC, or LaGen, a wholly-owned subsidiary of NRG, in federal district court in the Middle District of Louisiana alleging violations of the CAA at the Big Cajun II power plant. On March 6, 2013, the court entered a Consent Decree resolving the matter. The Consent Decree requires LaGen to install certain emission control technologies on two coal-fired units, convert one unit at Big Cajun II to natural gas, pay a civil penalty of $3.5 million, complete mitigation projects of $10.5 million within five years and imposes annual limits for SO₂ and NO_X. Further discussion on this matter can be found in Note 15, Environmental Matters - South Central Region.

In a related matter, soon after the filing of the above referenced U.S. DOJ lawsuit, LaGen sought insurance coverage from its insurance carrier, Illinois Union Insurance Company, or ILU. ILU denied coverage and refused to provide a defense for LaGen, and thereafter LaGen filed a lawsuit in federal district court in the Middle District of Louisiana (which was consolidated with a prior suit filed by ILU) seeking a declaration that ILU must provide coverage to LaGen for the defense costs incurred in defending the U.S. DOJ lawsuit as well as indemnity costs. LaGen and ILU both filed motions for summary judgment and on January 30, 2012, the court issued an order granting LaGen's motion finding that ILU has a duty to defend LaGen. The trial court certified the summary judgment for immediate interlocutory appeal, and on May 25, 2012, ILU filed a petition with the U.S. Circuit Court of Appeals for the Fifth Circuit seeking to appeal the trial court's summary judgment ruling. The Fifth Circuit granted the petition on September 4, 2012. ILU filed a related notice of appeal on June 14, 2012, which also seeks review of the trial court's summary judgment ruling. The Company filed a motion to consolidate the two appeals which the court granted on October 24, 2012. The Fifth Circuit heard oral arguments on March 6, 2013.

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 with the potential for penalties in excess of $100,000. The CCO&NPP alleges there were opacity exceedance events from the Big Cajun II Power Plant on certain dates during the years 2007-2012. On October 8, 2012, LaGen filed a Request for Administrative Adjudicatory hearing and is cooperating with the LDEQ and responding in good faith to the CCO&NPP.

Global Warming

In February 2008, the Native Village of Kivalina and the City of Kivalina, Alaska filed a suit in the United States District Court for the Northern District of California against GenOn and 23 other electric generating and oil and gas companies. The lawsuit sought damages of up to $400 million for the cost of relocating the village allegedly because of global warming caused by the greenhouse gas emissions of the defendants. In late 2009, the District Court ordered that the case be dismissed and the plaintiffs appealed. In September 2012, the United States Court of Appeals for the Ninth Circuit dismissed plaintiffs' appeal. In October 2012, the plaintiffs petitioned for en banc rehearing of the case; which petition was denied in November 2012. In February 2013, plaintiffs filed a petition with the U.S. Supreme Court seeking review of the decision from the U.S. Court of Appeals. The Company believes claims such as this lack legal merit.

Actions Pursued by MC Asset Recovery

Under the plan of reorganization that was approved in conjunction with Mirant Corporation's emergence from bankruptcy protection on January 3, 2006, or the Plan, the rights to 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 now governed by a manager who is independent of NRG and GenOn. Under the Plan, any cash recoveries obtained by MC Asset Recovery from the actions transferred to it, net of fees and costs incurred in prosecuting the actions, are to be paid to the unsecured creditors of GenOn Energy Holdings in the Chapter 11 proceedings and the holders of the equity interests in GenOn Energy Holdings immediately prior to the effective date of the Plan except where such a recovery results in an allowed claim in the bankruptcy proceedings, as described below. MC Asset Recovery is a disregarded entity for income tax purposes, and NRG, GenOn and GenOn Energy Holdings are responsible for income taxes related to its operations. The Plan provides that GenOn Energy Holdings may not reduce payments to be made to unsecured creditors and former holders of equity interests from recoveries obtained by MC Asset Recovery for the taxes owed by GenOn Energy Holdings, if any, on any net recoveries up to $175 million. If the aggregate recoveries exceed $175 million net of costs, then GenOn Energy Holdings may reduce the payments by the amount of any taxes it will owe or NOLs it may utilize with respect to taxable income resulting from the amount in excess of $175 million.

One of the two remaining actions transferred to MC Asset Recovery seeks to recover damages from Commerzbank AG and various other banks (the Commerzbank Defendants) for alleged fraudulent transfers that occurred prior to the filing of GenOn Energy Holdings' bankruptcy proceedings. In its amended complaint, MC Asset Recovery alleges that the Commerzbank Defendants in 2002 and 2003 received payments totaling approximately €153 million directly or indirectly from GenOn Energy Holdings under a guarantee provided by GenOn Energy Holdings in 2001 of certain equipment purchase obligations. MC Asset Recovery alleges that at the time GenOn Energy Holdings provided the guarantee and made the payments to the Commerzbank Defendants, GenOn Energy Holdings was insolvent and did not receive fair value for those transactions. In December 2010, the United States 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 United States District Court's dismissal of its complaint against the Commerzbank Defendants to the United States Court of Appeals for the Fifth Circuit. In March 2012, the United States Court of Appeals for the Fifth Circuit reversed the United States 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 on these avoidance claims, the Commerzbank Defendants have asserted that they will seek to file claims in GenOn Energy Holdings' bankruptcy proceedings for the amount of those recoveries. GenOn Energy Holdings would vigorously contest the allowance of any such claims on the ground that, among other things, the recovery of such amounts by MC Asset Recovery does not reinstate any enforceable pre-petition obligation that could give rise to a claim. If such a claim were to be allowed by the Bankruptcy Court as a result of a recovery by MC Asset Recovery, then the Plan provides that the Commerzbank Defendants are entitled to the same distributions as previously made under the Plan to holders of similar allowed claims. Holders of previously allowed claims similar in nature to the claims that the Commerzbank Defendants would seek to assert have received 43.87 shares of GenOn Energy Holdings common stock for each $1,000 of claim allowed by the Bankruptcy Court. 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, the order entered by the Bankruptcy Court in December 2005, confirming the Plan provides that 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, rather than distribute such amount to the unsecured creditors and former equity holders as described above.

Pending Natural Gas Litigation

NRG's subsidiary, GenOn, is party to five lawsuits, several 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 United States 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 United States Court of Appeals for the Ninth Circuit. The Ninth Circuit has reversed the decision of the United States District Court for the District of Nevada. 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 filed a petition for certiorari to the United States Supreme Court. GenOn has agreed to indemnify CenterPoint against certain losses relating to these lawsuits.

New Source Review Matters

The EPA and various states are investigating compliance of coal and oil-fueled electric generating facilities with the pre-construction permitting requirements of the CAA known as “new source review.” Since 2000, the EPA has made information requests concerning several of the Company's plants. The Company continues to correspond with the EPA regarding some of these requests. The EPA agreed to share information relating to its investigations with state environmental agencies. In 2005 and 2006, the Company received an NOV from the EPA alleging that past work at Big Cajun II violated regulations regarding new source review. In January 2009, the EPA issued an NOV alleging that past work at the Shawville, Portland and Keystone generating facilities violated regulations regarding new source review. In June 2011, the EPA issued an NOV alleging that past work at the Niles and Avon Lake generating facilities violated regulations regarding new source review. In April 2013, the Connecticut Department of Energy and Environmental Protection issued four NOVs alleging that past work at combustion turbines at three of the Company's Connecticut Jet Power facilities and Middletown violated regulations regarding new source review.

In December 2007, the NJDEP sued GenOn in the United States District Court for the Eastern District of Pennsylvania, alleging that new source review violations occurred at the Portland generating facility. The suit seeks installation of BACT for each pollutant, to enjoin GenOn from operating the generating facility if it is not in compliance with the CAA and civil penalties. The suit also named past owners of the plant as defendants, but the claims against the past owners have since been dismissed. In March 2009, the Connecticut Department of Environmental Protection became an intervening party to the suit. The Company believes that the work listed by the EPA and the work subject to the NJDEP suit were conducted in compliance with applicable regulations. The parties appeared for mediation before the magistrate judge on April 10, 2013. The parties reached a settlement in principle of this matter on that date, which has not yet been finalized.

In addition, the NJDEP filed two administrative petitions with the EPA in 2010 alleging that the Portland generating facility's emissions were significantly contributing to nonattainment and/or interfering with the maintenance of certain NAAQS in New Jersey. In November 2011, the EPA published a final rule in response to one of the petitions that will require the two coal-fired units to reduce maximum allowable SO2 emissions by about 60% starting in January 2013 and by about 80% starting in January 2015. In January 2012, the Company challenged the rule in the United States Court of Appeals for the Third Circuit. If the rule is not vacated or otherwise modified by the court, the Company has several compliance options in 2013 and 2014 that include using lower sulfur coals (although this may at times reduce how much the Company is able to generate) or running just one unit at a time. Starting in January 2015, these units will be subject to more stringent rate limits, which will require either material capital expenditures and higher operating costs or the retirement of these two units.

Cheswick Class Action Complaint

In April 2012, a putative class action lawsuit was filed 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 United States District Court for the Western District of Pennsylvania. In October 2012, the court granted the Company's motion to dismiss, which Plaintiffs have appealed to the U.S. Court of Appeals for the Third Circuit.

Cheswick Monarch Mine NOV

In 2008, the Pennsylvania Department of Environmental Protection, or PADEP, issued an NOV related to the Monarch mine located near the Cheswick generating facility. It has not been mined for many years. The Company uses it for disposal of low-volume wastewater from the Cheswick generating facility and for disposal of leachate collected from ash disposal facilities. The NOV addresses the alleged requirement to maintain a minimum pumping volume from the mine. The PADEP indicated it may assess a civil penalty in excess of $100,000. The Company contests the allegations in the NOV and has not agreed to such penalty. The Company is currently planning capital expenditures in connection with wastewater from Cheswick and leachate from ash disposal facilities.

Ormond Beach Alleged Federal Clean Water Act Violations

In October 2012, the Wishtoyo Foundation, a California-based cultural and environmental advocacy organization, through its Ventura Coastkeeper Program, filed suit in the United States District Court for the Central District of California regarding alleged violations of the CWA associated with discharges of stormwater from the Ormond Beach generating facility. The Wishtoyo Foundation alleges that elevated concentrations of pollutants in stormwater discharged from the Ormond Beach generating facility are affecting adjacent aquatic resources in violation of (a) the Statewide General Industrial Stormwater permit (a general National Pollution Discharge Elimination System permit issued by the California State Water Resources Control Board that authorizes stormwater discharges from industrial facilities in California) and (b) the state's Porter-Cologne Water Quality Control Act. The Wishtoyo Foundation further alleges that the Company has not implemented effective stormwater control and treatment measures and that the Company has not complied with the sampling and reporting requirements of the General Industrial Stormwater permit. The Company has signed a consent decree that, if entered by the court, would settle this matter and obligate the Company to make operational changes and pay $79,000 in legal fees, $65,000 for supplemental environmental projects and $15,000 for monitoring costs.

Maryland Fly Ash Facilities

The Company has three fly ash facilities in Maryland: Faulkner, Westland and Brandywine. Fly ash from the Morgantown and Chalk Point generating facilities is disposed of at Brandywine. Fly ash from the Dickerson generating facility is disposed of at Westland. Fly ash is no longer disposed of at the Faulkner facility. As described below, the MDE had sued GenOn MD Ash Management and GenOn Mid-Atlantic regarding Faulkner, Brandywine and Westland. The MDE also had threatened not to renew the water discharge permits for all three facilities.

Faulkner Litigation — In May 2008, the MDE sued GenOn MidAtlantic and GenOn MD Ash Management in the Circuit Court for Charles County, Maryland alleging violations of Maryland's water pollution laws at Faulkner. The MDE contended that the operation of Faulkner had resulted in the discharge of pollutants that exceeded Maryland's water quality criteria and without the appropriate NPDES permit. The MDE also alleged that GenOn failed to perform certain sampling and reporting required under an applicable NPDES permit. The MDE complaint requested that the court (i) prohibit continuation of the alleged unpermitted discharges, (ii) require GenOn to cease from further disposal of any coal combustion byproducts at Faulkner and close and cap the existing disposal cells and (iii) assess civil penalties. In July 2008, GenOn filed a motion to dismiss the complaint, arguing that the discharges are permitted by a December 2000 Consent Order. In January 2011, the MDE dismissed without prejudice its complaint and informed GenOn that it intended to file a similar lawsuit in federal court. In May 2011, the MDE filed a complaint against GenOn Mid-Atlantic and GenOn MD Ash Management in the U.S. District Court for the District of Maryland alleging violations at Faulkner of the Clean Water Act and Maryland's Water Pollution Control Law. The MDE contends that (i) certain of GenOn's water discharges are not authorized by the existing permit and (ii) operation of the Faulkner facility has resulted in discharges of pollutants that violate water quality criteria. The complaint asked the court to, among other things, (i) enjoin further disposal of coal ash; (ii) enjoin discharges that are not authorized by the existing permit; (iii) require numerous technical studies; (iv) impose civil penalties and (v) award MDE attorneys' fees. The Company disputed these allegations.

Brandywine Litigation — In April 2010, the MDE filed a complaint against GenOn MidAtlantic and GenOn MD Ash Management in the United States District Court for the District of Maryland asserting violations at Brandywine of the CWA and Maryland's Water Pollution Control Law. The MDE contended that the operation of Brandywine has resulted in discharges of pollutants that violate Maryland's water quality criteria. The complaint requested that the court, among other things, (i) enjoin further disposal of coal combustion waste at Brandywine, (ii) require the existing open disposal cells to be closed and capped within one year, (iii) impose civil penalties and (iv) award MDE attorneys' fees. The Company disputed the allegations. In September 2010, four environmental advocacy groups became intervening parties in the proceeding.

Westland Litigation — In January 2011, the MDE informed GenOn that it intended to sue for alleged violations at Westland of Maryland's water pollution laws, which suit was filed in United States District Court for the District of Maryland in December 2012.

Permit Renewals — In March 2011, the MDE tentatively determined to deny the GenOn application for the renewal of the water discharge permit for Brandywine, which could have resulted in a significant increase in operating expenses for the Company's Chalk Point and Morgantown generating facilities. The MDE also had indicated that it was planning to deny the Company's applications for the renewal of the water discharge permits for Faulkner and Westland. Denial of the renewal of the water discharge permit for the latter facility could have resulted in a significant increase in operating expenses for the Dickerson generating facility.

Settlement — In June 2011, the MDE agreed to stay the litigation related to Faulkner and Brandywine, not to pursue its tentative denial of the Brandywine water discharge permit and not to act on renewal applications for Faulkner or Westland while settlement discussions occurred. As a condition to obtaining the stay, GenOn agreed in principle to pay a civil penalty of $1.9 million if the matters were settled. In 2012, GenOn agreed to pay an additional $0.6 million (for agreed prospective penalties while the settlement is implemented) if a comprehensive settlement were reached. The Company believes it is adequately reserved for such settlement. GenOn also developed a technical solution, which includes installing synthetic caps on the closed cells of each of the three ash facilities, for which $47 million has been reserved. At this time, the Company cannot reasonably estimate the upper range of its obligation for remediating the sites the Company has not: (i) finished assessing each site including identifying the full impacts to both ground and surface water and the impacts to the surrounding habitat; (ii) finalized with the MDE the standards to which it must remediate; and (iii) identified the technologies required, if any, to meet the yet to be determined remediation standards at each site nor the timing of the design and installation of such technologies. A hearing was held on March 18, 2013 on entry of the Consent Decree. In April 2013, GenOn MD Ash Management and MDE signed a slightly revised Consent Decree, which was approved by the court on April 30, 2013. Accordingly, these issues have been resolved.

Energy Plus Holdings, LLC Purported Class Actions

Energy Plus Holdings, LLC is a defendant in six purported class action lawsuits, two in New York, two in New Jersey, and two in Pennsylvania. On February 28, 2013, Energy Plus entered into a settlement agreement with plaintiffs which resolves all of the claims in the six pending suits, subject to court approval. On March 26, 2013, the United States District Court, Southern District of New York entered an order preliminarily approving the settlement and scheduling a final approval hearing for July 16, 2013. Energy Plus continues to cooperate with the Connecticut Attorney General and Office of Consumer Counsel and the State of New York Office of Attorney General to resolve issues related to Energy Plus's sales, marketing and business practices raised by the class actions. Energy Plus and the Connecticut Attorney General and Office of Consumer Counsel have been involved in settlement discussions and their efforts to reach a resolution continue.

Purported Class Actions related to July 22, 2012 Announcement of NRG/GenOn Merger Agreement

NRG has been named as a defendant in eight purported class actions pending in Texas and Delaware, related to its announcement of its agreement to acquire all outstanding shares of GenOn. These cases have been consolidated into one state court case in each of Delaware and Texas and a federal court case in Texas. The plaintiffs generally allege breach of fiduciary duties, as well as conspiracy, aiding and abetting breaches of fiduciary duties. Plaintiffs are generally seeking to: be certified as a class; enjoin the merger; direct the defendant to exercise their fiduciary duties; rescind the acquisition and be awarded attorneys' fees costs and other relief that the court deems appropriate. Plaintiffs also demanded that there be additional disclosures regarding the merger terms. On October 24, 2012, the parties to the Delaware state court case executed a Memorandum of Understanding to resolve the Delaware purported class action lawsuit. In March 2013, the parties finalized the settlement of the Delaware action. The hearing on the class action settlement of the Delaware action is scheduled for June 3, 2013.

Notice of Intent to File Citizens Suit - Chalk Point, Dickerson and Morgantown

On January 25, 2013, Food & Water Watch, the Patuxent Riverkeeper and the Potomac Riverkeeper, or the Citizens Group, sent NRG a letter alleging that the Chalk Point, Dickerson and Morgantown generating facilities were violating the terms of the three National Pollution Discharge Elimination System Permits by discharging nitrogen and phosphorous in excess of the limits in each permit. The Citizens Group threatens to bring a lawsuit if the Company does not bring itself into compliance within 60 days of the letter. The Citizens Group said it intended to seek civil penalties and injunctive relief against the Company if they file a lawsuit. On March 21, 2013 the MDE sent the Company a similar letter with respect to the Chalk Point and Dickerson facilities, threatening to sue within 60 days if the Company does not bring itself into compliance.

Note 14 — Regulatory Matters

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 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.

East Region

Reliability Must Run Agreements for Elrama and Niles — In May 2012, GenOn filed with the FERC an RMR rate schedule governing operation of unit 4 of the Elrama generating facility and unit 1 of the Niles generating facility. PJM determined that each of these units was needed past their planned deactivation date of June 1, 2012 to maintain transmission system reliability on the PJM system pending the completion of transmission upgrades. The RMR rate schedule sets forth the terms, conditions and cost-based rates under which GenOn operated the units for reliability purposes through September 30, 2012, the date PJM indicated the units would no longer be needed for reliability. In July 2012, the FERC accepted GenOn's RMR rate schedule subject to hearing and settlement procedures. In the settlement discussions ordered by the FERC or in any subsequent hearing, the Company's RMR rate schedule may be modified from that which was filed. The rates GenOn charged are subject to refund pending a ruling or settlement. We anticipate filing a partial settlement of all outstanding issues in May 2013. Any eventual settlement must be approved by the FERC.

Retail

Midwest ISO SECA — Green Mountain Energy previously provided competitive retail energy supply in the Midwest ISO region during the relevant period of January 1, 2002, to December 31, 2005. By order dated November 18, 2004, the FERC eliminated certain regional through-and-out transmission rates charged by transmission owners in MISO and PJM. In order to temporarily compensate the transmission owners for lost revenues, FERC ordered MISO, PJM and their respective transmission owners to revamp the way that ISOs manage certain cross-system congestion costs, known as Seams Elimination Charge/Cost Adjustments/Assignments, or SECA, charges effective December 1, 2004, through March 31, 2006. The tariff amendments filed by MISO and the MISO transmission owners allocated certain SECA charges to various zones and sub-zones within MISO, including a sub-zone called the Green Mountain Energy Company Sub-zone. During several years of extensive litigation before the FERC, several transmission owners sought to recover SECA charges from Green Mountain Energy. Green Mountain Energy denied responsibility for any SECA charges and did not pay any asserted SECA charges.

On May 21, 2010, the FERC issued two orders, including its Order on Initial Decision, in which the FERC determined that approximately $22 million plus interest of SECA charges were owed not by Green Mountain Energy but rather by BP Energy - one of Green Mountain Energy's suppliers during the period at issue. On August 19, 2010, the transmission owners and MISO made compliance filings in accordance with the FERC's Orders allocating SECA charges to a BP Energy Sub-zone, and making no allocation to a Green Mountain Energy sub-zone. The FERC has not yet ruled on those compliance filings.

On September 30, 2011, the FERC issued orders denying all requests for rehearing and again determined that SECA charges were not owed by Green Mountain Energy. Numerous parties, including BP Energy, sought judicial review of the FERC's orders, and Green Mountain Energy was granted intervenor status in the consolidated appeals. Most appellants subsequently settled with the transmission owners and withdrew their appeals, including BP Energy, which agreed to pay approximately $24 million to the three transmission owners signing the agreement, with another $1 million offered to the remaining PJM transmission owners, should they choose to join the settlement; all chose to do so. FERC approved the settlement, and BP Energy moved to dismiss its appeals; its motions to dismiss were granted by the Court.

West Region

California Station Power — On December 18, 2012, in Calpine Corporation v. FERC, the U.S. Court of Appeals for the D.C. Circuit upheld a decision by the FERC disclaiming jurisdiction over how the states impose retail station power charges. The CPUC may now establish retail charges for future station power consumption. Due to reservation-of-rights language in the California utilities' state-jurisdictional station power tariffs, the Court's ruling arguably requires 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 filed with the CPUC, seeking authorization to begin charging generators station power charges, and to assess such charges retroactively, which the Company and other generators have challenged. On August 13, 2012, the CPUC Energy Division issued a draft resolution in which it rejected the Company's arguments and approved Southern California Edison's proposed station power charges, including retroactive implementation, but proposing a credit to generators for some portion of their retail station power bill. However, the CPUC withdrew the draft resolution from the calendar and consideration of the measure has not yet been rescheduled. The Company believes it has established an appropriate reserve.

Note 15 — Environmental Matters

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

Environmental Capital Expenditures

Based on current rules, technology and preliminary plans based on some proposed rules, NRG estimates that environmental capital expenditures from 2013 through 2017 required to comply with environmental laws will be approximately $528 million, consisting of $317 million for legacy NRG facilities and $211 million for GenOn facilities. These costs are primarily associated with controls to satisfy the MATS and recent NSR settlement at Big Cajun II and MATS at W.A. Parish, Limestone, and Conemaugh and NO_x controls for Sayreville and Gilbert. The decrease from NRG's previous estimate is related to changes in technology related to complying with MATS and the NSR settlement at Big Cajun II, and the selection of more cost-effective environmental compliance solutions at Cheswick. NRG continues to explore cost-effective compliance alternatives to further reduce costs.

NRG's contracts with the Company's rural electric cooperative customers in the South Central region allow for recovery of a portion of the region's environmental capital costs incurred as the result of complying with any change in environmental law. Cost recoveries begin once the environmental equipment becomes operational and include a return on capital. The actual recoveries will depend, among other things, on the timing of the completion of the capital projects and the remaining duration of the contracts.

The EPA released CSAPR on July 7, 2011, which was scheduled to replace CAIR on January 1, 2012. On August 21, 2012, the U.S. Court of Appeals for the D.C. Circuit issued an opinion vacating CSAPR and keeping CAIR in place until the EPA can replace it. The EPA has petitioned the Supreme Court seeking review of this decision. This decision was beneficial to the Company as it eliminated an SO₂allowance reduction which was to have occurred before the MATS compliance date. While NRG is unable to predict the final outcome of the replacement rule, the Company's investment in pollution controls and cleaner technologies coupled with planned strategic plant retirements positions the fleet for compliance.

East Region

The EPA and various states are investigating compliance of coal-fueled electric generating facilities with the pre-construction permitting requirements of the CAA known as “new source review,” or NSR. In January 2009, GenOn received an NOV from the EPA alleging that past work at Keystone, Portland and Shawville generating facilities violated regulations regarding NSR. In June 2011, GenOn received an NOV from the EPA alleging that past work at Avon Lake and Niles generating stations violated NSR. In December 2007, the NJDEP filed suit alleging that NSR violations occurred at the Portland generating station. NRG believes the suits are without merit and the subject work was conducted in compliance with applicable regulations. All but the Keystone generating units are scheduled for retirement by April 2015. Additionally, in April 2013, the Connecticut Department of Energy and Environmental Protection issued four NOVs alleging that past work at oil-fired combustion turbines at the Torrington Terminal, Franklin, Branford and Middletown violated regulations regarding NSR.

In 2008, the PADEP issued an NOV related to the inactive Monarch mine where low-volume wastewater from the Cheswick Generating Station and ash leachate was historically disposed. Resolution of the NOV could result in operational requirements such as pumping a minimum volume of water from the mine and a penalty in excess of $100,000.

In January 2006, NRG's Indian River Operations, Inc. received a letter of informal notification from DNREC stating that it may be a potentially responsible party with respect to Burton Island Old Ash Landfill, a historic captive landfill located at the Indian River facility. On October 1, 2007, NRG signed an agreement with DNREC to investigate the site through the Voluntary Clean-up Program. On February 4, 2008, DNREC issued findings that no further action is required in relation to surface water and that a previously planned shoreline stabilization project would satisfactorily address shoreline erosion. The landfill itself required a Remedial Investigation and Feasibility Study to determine the type and scope of any additional required work. The DNREC approved the Feasibility Study in December 2012 and a proposed Plan of Remediation is under development at the DNREC. A final remedy based on the approved study should be consistent with the NRG reserve and should not be material. On May 29, 2008, DNREC requested that NRG's Indian River Operations, Inc. participate in the development and performance of a Natural Resource Damage Assessment, or NRDA, at the Burton Island Old Ash Landfill. NRG is currently working with DNREC and other trustees to close out the assessment process.

The MDE sued GenOn for alleged violations of water pollution laws at three fly ash disposal sites in Maryland: Falkner (2008/2011), Brandywine (2010), and Westland (2012). On April 30, 2013, the court approved the consent decree resolving these issues. GenOn has since discontinued use of the Faulkner disposal site and opened a new, state of the art carbon burnout facility at its Morgantown plant that allows greater beneficial reuse (as a cement substitute).

For further discussion of these matters, refer to Note 13, Commitments and Contingencies.

South Central Region

In 2009, the U.S. DOJ, on behalf of the EPA, and later the Louisiana Department of Environmental Quality on behalf of the state of Louisiana, sued LaGen in federal district court in the Middle District of Louisiana alleging violations of the CAA at the Big Cajun II power plant. On March 6, 2013, the court entered a Consent Decree resolving the matter. In addition to a fine of $3.5 million and mitigation projects totaling $10.5 million, the terms of the agreement include: (a) annual emission caps for NO_x and SO₂; (b) installation of SNCRs on Units 1, 2 and 3 by May 1, 2014; (c) installation of DSI on Unit 1 by April 15, 2015 followed by a further reduction in SO₂ in March 2025; (d) conversion of Unit 2 to gas; and (e) surrender of any excess allowances associated with the NRG owned portion of the plant. For further discussion of this matter, please refer to Note 13, Commitments and Contingencies.

Note 16 — Condensed Consolidating Financial Information

As of March 31, 2013, the Company had outstanding $5.7 billion of Senior Notes due from 2018 - 2023, 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.

Unless otherwise noted below, each of the following guarantor subsidiaries fully and unconditionally guaranteed the Senior Notes as of March 31, 2013:



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

NRG conducts much of its business through and derives much of its income from its subsidiaries. Therefore, the Company's ability to make required payments with respect to its indebtedness and other obligations depends on the financial results and condition of its subsidiaries and NRG's ability to receive funds from its subsidiaries. Except for NRG Bayou Cove, LLC, which is subject to certain restrictions under the Company's Peaker financing agreements, there are no restrictions on the ability of any of the guarantor subsidiaries to transfer funds to NRG. In addition, 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 Securities and Exchange Commission's Regulation S-X. The financial information may not necessarily be indicative of results of operations or financial position had the guarantor subsidiaries or non-guarantor subsidiaries operated as independent entities.

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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Three Months Ended March 31, 2013

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Operating Revenues
Total operating revenues	$	1,590		$	525		$	—		$	(34	)	$	2,081
Operating Costs and Expenses
Cost of operations	1,258			527			7			(27		)	1,765
Depreciation and amortization	204			91			3			—			298
Selling, general and administrative	115			54			67			(7		)	229
Acquisition-related transaction and integration costs	—			19			13			—			32
Development activity expenses	—			4			12			—			16
Total operating costs and expenses	1,577			695			102			(34		)	2,340
Operating Income/(Loss)	13			(170		)	(102		)	—			(259		)
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries	1			(4		)	(157		)	160			—
Equity in earnings of unconsolidated affiliates	1			2			—			—			3
Other income, net	1			2			1			—			4
Loss on debt extinguishment	—			—			(28		)	—			(28		)
Interest expense	(5		)	(64		)	(127		)	—			(196		)
Total other expense	(2		)	(64		)	(311		)	160			(217		)
Income/(Loss) Before Income Taxes	11			(234		)	(413		)	160			(476		)
Income tax expense/(benefit)	21			(85		)	(85		)	—			(149		)
Net Loss	(10		)	(149		)	(328		)	160			(327		)
Less: Net income attributable to noncontrolling interest	—			1			—			—			1
Net Loss attributable to NRG Energy, Inc.	$	(10	)	$	(150	)	$	(328	)	$	160		$	(328	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE LOSS

For the Three Months Ended March 31, 2013

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)		Consolidated Balance
	(In millions)
Net Loss	$	(10	)	$	(149	)	$	(328	)	$	160	$	(327	)
Other comprehensive (loss)/income, net of tax
Unrealized (loss)/gain on derivatives, net	(9		)	5			7			4		7
Foreign currency translation adjustments, net	—			—			—			—		—
Available-for-sale securities, net of income tax benefit	—			—			2			—		2
Defined benefit plan, net of income tax benefit	—			—			5			—		5
Other comprehensive (loss)/income	(9		)	5			14			4		14
Comprehensive loss	(19		)	(144		)	(314		)	164		(313		)
Less: Comprehensive income attributable to noncontrolling interest	—			1			—			—		1
Comprehensive loss attributable to NRG Energy, Inc.	(19		)	(145		)	(314		)	164		(314		)
Dividends for preferred shares	—			—			2			—		2
Comprehensive loss available for common stockholders	$	(19	)	$	(145	)	$	(316	)	$	164	$	(316	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

March 31, 2013

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
ASSETS	(In millions)
Current Assets
Cash and cash equivalents	$	68		$	1,140		$	499		$	—		$	1,707
Funds deposited by counterparties	—			105			—			—			105
Restricted cash	12			200			9			—			221
Accounts receivable, net	740			242			—			—			982
Inventory	446			460			(2		)	—			904
Derivative instruments	2,344			514			—			(53		)	2,805
Deferred income taxes	—			88			40			—			128
Cash collateral paid in support of energy risk management activities	301			154			—			—			455
Accounts receivable - affiliate	2,880			(105		)	(2,737		)	(33		)	5
Prepayments and other current assets	115			573			39			(8		)	719
Total current assets	6,906			3,371			(2,152		)	(94		)	8,031
Net property, plant and equipment	9,773			10,516			135			(20		)	20,404
Other Assets
Investment in subsidiaries	247			(114		)	17,565			(17,698		)	—
Equity investments in affiliates	32			635			10			—			677
Notes receivable, less current portion	3			73			220			(210		)	86
Goodwill	1,941			13			—			—			1,954
Intangible assets, net	1,005			190			33			(52		)	1,176
Nuclear decommissioning trust fund	501			—			—			—			501
Deferred income tax	(948		)	1,909			474			—			1,435
Derivative instruments	168			398			—			(4		)	562
Other non-current assets	75			263			207			—			545
Total other assets	3,024			3,367			18,509			(17,964		)	6,936
Total Assets	$	19,703		$	17,254		$	16,492		$	(18,078	)	$	35,371
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	1		$	580		$	16		$	(41	)	$	556
Accounts payable	509			511			34			—			1,054
Accounts payable - affiliate	(283		)	1,897			(1,614		)	—			—
Derivative instruments	2,261			285			—			(53		)	2,493
Deferred income taxes	130			—			(130		)	—			—
Cash collateral received in support of energy risk management activities	—			105			—			—			105
Accrued expenses and other current liabilities	245			510			199			—			954
Total current liabilities	2,863			3,888			(1,495		)	(94		)	5,162
Other Liabilities
Long-term debt and capital leases	312			8,511			7,301			(210		)	15,914
Nuclear decommissioning reserve	359			—			—			—			359
Nuclear decommissioning trust liability	293			—			—			—			293
Deferred income taxes	—			53			—			—			53
Derivative instruments	303			178			—			(4		)	477
Out-of-market contracts	174			1,051			—			(31		)	1,194
Other non-current liabilities	510			716			248			—			1,474
Total non-current liabilities	1,951			10,509			7,549			(245		)	19,764
Total liabilities	4,814			14,397			6,054			(339		)	24,926
3.625% convertible perpetual preferred stock	—			—			249			—			249
Stockholders’ Equity	14,889			2,857			10,189			(17,739		)	10,196
Total Liabilities and Stockholders’ Equity	$	19,703		$	17,254		$	16,492		$	(18,078	)	$	35,371


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2013

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Cash Flows from Operating Activities
Net loss	$	(10	)	$	(149	)	$	(328	)	$	160		$	(327	)
Adjustments to reconcile net loss to net cash provided/(used) by operating activities:
Distributions and equity in earnings of unconsolidated affiliates and consolidated subsidiaries	(2		)	5			157			(160		)	—
Depreciation and amortization	204			91			3			—			298
Provision for bad debts	9			—			—			—			9
Amortization of nuclear fuel	6			—			—			—			6
Amortization of financing costs and debt discount/premiums	—			(20		)	7			—			(13		)
Loss on debt extinguishment	—			—			2			—			2
Amortization of intangibles and out-of-market contracts	30			1			—			—			31
Amortization of unearned equity compensation	—			—			18			—			18
Changes in deferred income taxes and liability for uncertain tax benefits	21			(85		)	(148		)	—			(212		)
Changes in nuclear decommissioning trust liability	10			—			—			—			10
Changes in derivative instruments	225			105			(13		)	—			317
Changes in collateral deposits supporting energy risk management activities	(220		)	(6		)	—			—			(226		)
Cash (used)/provided by changes in other working capital	(73		)	(183		)	219			—			(37		)
Net Cash Provided/(Used) by Operating Activities	200			(241		)	(83		)	—			(124		)
Cash Flows from Investing Activities
Intercompany loans to subsidiaries	(106		)	1			—			105			—
Acquisition of businesses, net of cash acquired	—			(18		)				—			(18		)
Capital expenditures	(66		)	(731		)	(16		)	—			(813		)
Increase in restricted cash, net	—			(12		)	(1		)	—			(13		)
Decrease/(increase) in restricted cash - U.S. DOE projects	—			13			(1		)	—			12
Increase in notes receivable	—			(1		)	(8		)	—			(9		)
Investments in nuclear decommissioning trust fund securities	(95		)	—			—			—			(95		)
Proceeds from sales of nuclear decommissioning trust fund securities	85			—			—			—			85
Proceeds from renewable energy grants	—			16			—			—			16
Other	(1		)	—			—			—			(1		)
Net Cash Used by Investing Activities	(183		)	(732		)	(26		)	105			(836		)
Cash Flows from Financing Activities
Proceeds from intercompany loans				—			105			(105		)	—
Payment of dividends to common and preferred stockholders	—			—			(31		)	—			(31		)
Payment for treasury stock	—			—			(20		)	—			(20		)
Net (payments for)/receipt of settlement of acquired derivatives that include financing elements	(27		)	125			—			—			98
Contributions from noncontrolling interest in subsidiaries	—			20			—			—			20
Proceeds from issuance of long-term debt	—			728			8			—			736
Proceeds from issuance of common stock	—			—			1			—			1
Payment of debt issuance and hedging costs	—			(3		)	(2		)	—			(5		)
Payments for short and long-term debt	—			(15		)	(204		)	—			(219		)
Net Cash (Used)/Provided by Financing Activities	(27		)	855			(143		)	(105		)	580
Net Decrease in Cash and Cash Equivalents	(10		)	(118		)	(252		)	—			(380		)
Cash and Cash Equivalents at Beginning of Period	78			1,258			751			—			2,087
Cash and Cash Equivalents at End of Period	$	68		$	1,140		$	499		$	—		$	1,707


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

For the Three Months Ended March 31, 2012

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Operating Revenues
Total operating revenues	$	1,778		$	101		$	—		$	(17	)	$	1,862
Operating Costs and Expenses
Cost of operations	1,532			60			6			(15		)	1,583
Depreciation and amortization	214			13			3			—			230
Selling, general and administrative	122			10			76			(2		)	206
Development activity expenses	—			—			13			—			13
Total operating costs and expenses	1,868			83			98			(17		)	2,032
Operating (Loss)/Income	(90		)	18			(98		)	—			(170		)
Other Income/(Expense)
Equity in earnings/(losses) of consolidated subsidiaries	6			(2		)	(20		)	16			—
Equity in (losses)/earnings of unconsolidated affiliates	(2		)	10			—			—			8
Other income, net	(1		)	1			1			—			1
Interest expense	(5		)	(14		)	(146		)	—			(165		)
Total other (expense)/income	(2		)	(5		)	(165		)	16			(156		)
(Loss)/Income Before Income Taxes	(92		)	13			(263		)	16			(326		)
Income tax benefit	(28		)	(36		)	(56		)	—			(120		)
Net (Loss)/Income	(64		)	49			(207		)	16			(206		)
Less: Net income attributable to noncontrolling interest	—			1			—			—			1
Net (Loss)/Income attributable to NRG Energy, Inc.	$	(64	)	$	48		$	(207	)	$	16		$	(207	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME

For the Three Months Ended March 31, 2012

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries		NRG Energy, Inc. (Note Issuer)			Eliminations^(a)		Consolidated Balance
	(In millions)
Net Loss/(Income)	$	(64	)	$	49	$	(207	)	$	16	$	(206	)
Other comprehensive (loss)/income, net of tax
Unrealized (loss)/gain on derivatives, net	(13		)	7		(3		)	—		(9		)
Foreign currency translation adjustments, net	—			6		—			—		6
Other comprehensive (loss)/income	(13		)	13		(3		)	—		(3		)
Comprehensive (loss)/income	(77		)	62		(210		)	16		(209		)
Less: Comprehensive income attributable to noncontrolling interest	—			1		—			—		1
Comprehensive (loss)/income attributable to NRG Energy, Inc.	(77		)	61		(210		)	16		(210		)
Dividends for preferred shares	—			—		2			—		2
Comprehensive (loss)/income available for common stockholders	$	(77	)	$	61	$	(212	)	$	16	$	(212	)


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING BALANCE SHEETS

December 31, 2012



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
ASSETS	(In millions)
Current Assets
Cash and cash equivalents	$	78		$	1,258		$	751		$	—		$	2,087
Funds deposited by counterparties	131			140			—			—			271
Restricted cash	11			196			10			—			217
Accounts receivable-trade, net	807			254			—			—			1,061
Inventory	472			459			—			—			931
Derivative instruments	2,058			604			—			(18		)	2,644
Deferred income taxes	(153		)	10			199			—			56
Cash collateral paid in support of energy risk management activities	81			148			—			—			229
Accounts receivable - affiliate	2,887			(231		)	(2,581		)	10			85
Prepayments and other current assets	79			233			63			—			375
Total current assets	6,451			3,071			(1,558		)	(8		)	7,956
Net Property, Plant and Equipment	9,905			10,262			121			(20		)	20,268
Other Assets
Investment in subsidiaries	244			(102		)	17,655			(17,797		)	—
Equity investments in affiliates	33			633			10			—			676
Capital leases and notes receivable, less current portion	3			74			531			(529		)	79
Goodwill	1,944			12			—			—			1,956
Intangible assets, net	1,042			177			33			(52		)	1,200
Nuclear decommissioning trust fund	473			—			—			—			473
Deferred income taxes	(915		)	1,829			353			—			1,267
Derivative instruments	149			515			—			(2		)	662
Other non-current assets	85			302			210			—			597
Total other assets	3,058			3,440			18,792			(18,380		)	6,910
Total Assets	$	19,414		$	16,773		$	17,355		$	(18,408	)	$	35,134
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	1		$	137		$	15		$	(6	)	$	147
Accounts payable	541			583			46			—			1,170
Accounts payable - affiliate	(55		)	1,421			(1,366		)				—
Derivative instruments	1,726			271			2			(18		)	1,981
Cash collateral received in support of energy risk management activities	131			140			—			—			271
Accrued expenses and other current liabilities	354			511			243			—			1,108
Total current liabilities	2,698			3,063			(1,060		)	(24		)	4,677
Other Liabilities
Long-term debt and capital leases	310			8,456			7,496			(529		)	15,733
Nuclear decommissioning reserve	354			—			—			—			354
Nuclear decommissioning trust liability	273			—			—			—			273
Deferred income taxes	—			55			—			—			55
Derivative instruments	312			190			—			(2		)	500
Out-of-market contracts	180			1,067			—			(31		)	1,216
Other non-current liabilities	618			802			135			—			1,555
Total non-current liabilities	2,047			10,570			7,631			(562		)	19,686
Total liabilities	4,745			13,633			6,571			(586		)	24,363
3.625% Preferred Stock	—			—			249			—			249
Stockholders’ Equity	14,669			3,140			10,535			(17,822		)	10,522
Total Liabilities and Stockholders’ Equity	$	19,414		$	16,773		$	17,355		$	(18,408	)	$	35,134


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

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2012

(Unaudited)



	Guarantor Subsidiaries			Non-Guarantor Subsidiaries			NRG Energy, Inc. (Note Issuer)			Eliminations^(a)			Consolidated Balance
	(In millions)
Cash Flows from Operating Activities
Net (loss)/income	$	(64	)	$	49		$	(207	)	$	16		$	(206	)
Adjustments to reconcile net (loss)/income to net cash provided/(used) by operating activities:
Distributions and equity in losses/(earnings) of unconsolidated affiliates and consolidated subsidiaries	9			(5		)	(17		)	13			—
Depreciation and amortization	214			13			3			—			230
Provision for bad debts	7			—			—			—			7
Amortization of nuclear fuel	6			—			—			—			6
Amortization of financing costs and debt discount/premiums	—			2			6			—			8
Amortization of intangibles and out-of market commodity contracts	42			—			—			—			42
Changes in deferred income taxes and liability for uncertain tax benefits	(29		)	(44		)	(56		)	—			(129		)
Changes in nuclear decommissioning trust liability	8			—			—			—			8
Changes in derivative instruments	186			—			1			—			187
Changes in collateral deposits supporting energy risk management activities	(187		)	—			—			—			(187		)
Cash provided/(used) by changes in other working capital	104			33			(147		)	(32		)	(42		)
Net Cash Provided/(used) by Operating Activities	296			48			(417		)	(3		)	(76		)
Cash Flows from Investing Activities
Intercompany loans to subsidiaries	(201		)	—			108			93			—
Capital expenditures	(69		)	(554		)	(16		)	—			(639		)
Increase in restricted cash, net	(1		)	(19		)	—			—			(20		)
Decrease in restricted cash - U.S. DOE projects	—			71			24			—			95
Increase in notes receivable	—			(7		)	—			—			(7		)
Investments in nuclear decommissioning trust fund securities	(126		)	—			—			—			(126		)
Proceeds from sales of nuclear decommissioning trust fund securities	119			—			—			—			119
Proceeds from renewable energy grants	—			28			—			—			28
Other	2			4			1			—			7
Net Cash (Used)/Provided by Investing Activities	(276		)	(477		)	117			93			(543		)
Cash Flows from Financing Activities
Proceeds from intercompany loans	—			(108		)	201			(93		)	—
Payment of dividends to preferred stockholders	—			—			(2		)	—			(2		)
Payment of intercompany dividends	—			(3		)	—			3			—
Net payment for settlement of acquired derivatives that include financing elements	(20		)	—			—			—			(20		)
Proceeds from issuance of long-term debt	9			406			—			—			415
Sale proceeds and other contributions from noncontrolling interest in subsidiaries	—			178			—			—			178
Payment of debt issuance and hedging costs	—			(10		)	—			—			(10		)
Payments for short and long-term debt	—			(30		)	(4		)	—			(34		)
Net Cash (Used)/Provided by Financing Activities	(11		)	433			195			(90		)	527
Effect of exchange rate changes on cash and cash equivalents	—			1			—			—			1
Net Increase/(Decrease) in Cash and Cash Equivalents	9			5			(105		)	—			(91		)
Cash and Cash Equivalents at Beginning of Period	44			85			976			—			1,105
Cash and Cash Equivalents at End of Period	$	53		$	90		$	871		$	—		$	1,014


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

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

As you read this discussion and analysis, refer to NRG's Condensed Consolidated Statements of Operations to this Form 10-Q, which present the results of operations for the three months ended March 31, 2013 and 2012. Also refer to NRG's 2012 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; Strategy section; Business Environment section, including how regulation, weather, and other factors affect NRG's business; and Critical Accounting Policies and Estimates section.

The discussion and analysis below has been organized as follows:


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


•	Results of operations;


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


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

Executive Summary

Introduction and Overview

NRG Energy, Inc., or NRG or the Company, is a competitive power and energy company that aspires to be a leader in the way the industry and consumers think about, use, produce and deliver energy and energy services in major competitive power markets in the United States. At its core, NRG is a wholesale power generator engaged in the ownership and operation of power generation facilities; the trading of energy, capacity and related products; and the transacting in and trading of fuel and transportation services. Second, while leveraging its core wholesale power business, NRG is a retail energy company engaged in the supply of energy, services, and innovative, sustainable products to retail customers in competitive markets through multiple channels and brands like Reliant Energy, Green Mountain Energy, and Energy Plus (collectively, the Retail Business). Finally, NRG is a clean energy leader and is focused on the deployment and commercialization of potentially disruptive technologies, like electric vehicles, Distributed Solar and smart meter technology, which have the potential to change the nature of the power supply industry. On December 14, 2012, the Company acquired GenOn as further described in Note 3, Business Acquisitions and Dispositions, and has reported results of operations from the acquisition date forward.

NRG's Business Strategy

The Company's business is focused on: (i) excellence in safety and operating performance of its existing assets; (ii) serving the energy needs of end-use residential, commercial and industrial customers in competitive markets through multiple brands and channels with a variety of retail energy products and services differentiated by innovative features, premium service, sustainability, and loyalty/affinity programs; (iii) optimal hedging of generation assets and retail load operations; (iv) repowering of power generation assets at premium sites; (v) investing in, and deploying, alternative energy technologies both in its wholesale and, particularly, in and around its Retail Business and its customers; (vi) pursuing selective acquisitions, joint ventures, divestitures and investments; and (vii) 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.

The Company believes that the American energy industry is going to be increasingly impacted by the long-term societal trend towards sustainability, which is both generational and irreversible. Moreover, 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 American energy sector over the years to come. As a result, energy consumers will have increasing personal control over whom they buy their energy from, how that energy is generated and used and what environmental impact these individual choices will have. The Company's initiatives in this area of future growth are focused on: (i) renewables, with a concentration in solar development; (ii) electric vehicle ecosystems; (iii) customer-facing energy products and services, including smart energy services that give consumers individual energy insights, choices and convenience, a variety of renewable and energy efficiency products, and numerous loyalty and affinity options and tailored product and service bundles sold through unique retail sales channels; and (iv) construction of other forms of on-site clean power generation. The Company's advances in each of these areas are driven by select acquisitions, joint ventures, and investments that are more fully described in Item 1, Business - New and On-going Company Initiatives and Development Projects of the Company's 2012 Form 10-K, and this Form 10-Q.

In summary, NRG's business strategy is intended to maximize stockholder value through the production and sale of safe, reliable and affordable power to its customers in the markets served by the Company, while aggressively positioning the Company to meet the market's increasing demand for sustainable and low carbon energy solutions. This strategy is designed to enhance the Company's core business of competitive power generation and mitigate the risk of declining power prices. The Company expects to become a leading provider of sustainable energy solutions that promotes national energy security, while utilizing the Company's Retail Business to complement and advance both initiatives.

Environmental Matters

Environmental Regulatory Landscape

A number of regulations with the potential to affect the Company and its facilities are in development or under review by the EPA: NSPS for GHGs, NAAQS revisions and implementation, coal combustion byproducts regulation, effluent limitation guidelines and once-through cooling regulations. While most of these regulations have been considered for some time, the outcomes and any resulting impact on NRG cannot be fully predicted until the rules are finalized (and any resulting legal challenges resolved).

Air

The CAA and the resulting regulations (as well as similar state and local requirements) have the potential to impact air emissions, operating practices and pollution control equipment at power plants. Under the CAA, the EPA sets NAAQS for certain pollutants including SO₂, ozone, and PM_2.5. Most of the Company's facilities are located in or near areas that are classified by the EPA as not achieving certain NAAQS (non-attainment areas). The relevant NAAQS have become more stringent and NRG expects that trend to continue. The Company expects increased regulation at both the federal and state levels of its air emissions and maintains a comprehensive compliance strategy to address these continuing and new requirements. Complying with increasingly stringent NAAQS may require the installation of additional emissions control equipment at some NRG facilities. Significant changes to air regulatory programs to which the Company is subject are described below. See Item 1, Business - Environmental Matters of NRG's 2012 Form 10-K for a full description of environmental matters impacting the Company.

Cross-State Air Pollution Rule — In 2005, EPA promulgated CAIR which established SO₂ and NO_x cap-and-trade programs applicable directly to states and indirectly to generating facilities in the eastern United States. In July 2008, the D.C. Circuit in State of North Carolina v. Environmental Protection Agency issued an opinion that would have vacated CAIR. In December 2008 the D.C. Circuit issued a second opinion that simply remanded the case to the EPA without vacating CAIR.

In August 2011, the EPA finalized CSAPR, which was intended to replace CAIR starting in 2012. It was designed to address interstate SO₂ and NO_Xemissions from certain power plants in the eastern half of the United States. In September 2011, GenOn and others asked the D.C. Circuit to stay and vacate CSAPR because, among other reasons, the rule circumvented the state implementation plan process expressly provided for in the CAA, afforded affected parties no time to install compliance equipment before the compliance period starts and included numerous material changes from the proposed rule, which deprived parties of an opportunity to provide comments. In December 2011, the court issued an order that stayed implementation of CSAPR and ordered EPA to keep CAIR in place until the court could rule on the legal deficiencies alleged with respect to CSAPR. In August 2012, the D.C. Circuit issued an order vacating CSAPR and keeping CAIR in place. In October 2012, the EPA filed a petition asking the D.C. Circuit to rehear the case en banc, which was denied in January 2013. The EPA has petitioned the U.S. Supreme Court seeking review of the D.C. Circuit's decision.

East Region

In February 2013, RGGI, Inc. released a proposed model rule that if promulgated by the nine RGGI member states, would reduce the CO₂ emissions cap from 165 million tons to 91 million tons in 2014 with a 2.5% reduction each year from 2015 to 2020. Each of the RGGI states may propose regulations to implement the model rule, and these states may adopt and finalize these regulations later this year. If this occurs, the Company expects earnings at its plants in Connecticut, Delaware, Massachusetts, New York, and particularly those in Maryland, to be negatively affected. The extent to which they would be negatively affected depends on the price of the CO₂ emissions allowances, which in turn will be significantly influenced by future natural gas prices, power prices, generation resource mix, and dispatch order.

Regulatory Matters

As operators of power plants and participants in wholesale and retail energy markets, certain NRG entities are subject to regulation by various federal and state government agencies. These include the CFTC, FERC, NRC, and the PUCT, as well as other public utility commissions in certain states where NRG's generating, thermal, or distributed generation assets are located. In addition, NRG is subject to the market rules, procedures and protocols of the various ISO markets in which it participates. Likewise, certain NRG entities participating in the retail markets are subject to rules and regulations established by the states in which NRG entities are licensed to sell at retail. NRG must also comply with the mandatory reliability requirements imposed by NERC and the regional reliability entities in the regions where the Company operates.

NRG's operations within the ERCOT footprint are not subject to rate regulation by the FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce. These operations are subject to regulation by PUCT, as well as to regulation by the NRC with respect to the Company's ownership interest in STP.

East Region

PJM — On April 12, 2011, FERC issued an order addressing a complaint filed by PJM Power Providers Group seeking to require PJM to address the potential adverse impacts of out-of-market generation on the PJM Reliability Pricing Model, or RPM, capacity market, as well as PJM's subsequent submission seeking revisions to the capacity market design, in particular the MOPR. In its order, FERC generally strengthened the MOPR and the protections against market price distortion from out-of-market generation. On November 17, 2011, FERC largely denied rehearing its April 12, 2011 order. Several parties have appealed FERC's decision to federal court, and those appeals have been consolidated in the Third Circuit Court of Appeals. The outcome of this proceeding could affect the Company's ability to meet its obligations under New Jersey's Long-Term Capacity Agreement Pilot Program, as well as drive future capacity prices.

On December 7, 2012, PJM filed comprehensive revisions to its MOPR rules at FERC. On May 2, 2013, FERC accepted PJM's proposal in part, and rejected it in part. Among other things, FERC approved the portions of the PJM proposal that exempt many new entrants from MOPR rules, including projects proposed by merchant generators, public power entities and certain self-supply entities. This exemption is subject to certain conditions designed to limit the financial incentive of such entities to suppress market prices. However, FERC rejected PJM's proposal to eliminate the unit specific review process, and instead directed PJM to continue allowing units to demonstrate their actual costs and revenues, and bid into the auction at that price. These changes will be in effect for the 2013 BRA.

PJM Demand Response Coalition Complaint — On April 4, 2013, a coalition of demand response providers filed a complaint against PJM alleging that PJM was improperly implementing certain provisions of its tariff regarding the ability of demand response providers to participate in the 2013 BRA. On April 17, 2013, the FERC granted the complaint, ruling that PJM's tariff did not authorize PJM to collect much of the information it had requested as a condition of participation in the BRA. The granting of the complaint could have a material impact on prices in the upcoming auction.

New York

NYISO May 2013 Capacity Auction Results — On May 3, 2013, the NYISO announced that the monthly spot capacity auction prices for the May 2013 delivery month were not calculated properly due to an anomaly in the data used to calculate the Minimum Unforced Capacity Requirements for Load Serving Entities and to translate the Installed Capacity, or ICAP, Demand Curves into Unforced Capacity, or UCAP, Demand Curves for the Summer Capability Period beginning May 1, 2013. The NYISO stated that the issue impacted the May 2013 ICAP Spot Market Auction clearing prices for New York Control Area and the New York City and Long Island Localities. On May 4, 2013, the NYISO stated that it was correcting May auction prices. NRG does not anticipate that the error will have any impact on future monthly auctions.

Dunkirk Power LLC Reliability Service — On March 14, 2012, Dunkirk Power LLC, or Dunkirk Power, filed a notice with the NYSPSC of its intent to mothball the Dunkirk Station no later than September 10, 2012. The effects of the mothball on electric system reliability were reviewed by Niagara Mohawk Power Corporation, d/b/a National Grid, or NG. As a result of those studies, NG determined that the mothball of the Dunkirk Station would have a negative impact on the reliability of the New York transmission system and that portions of the Dunkirk Station may be retained for reliability purposes via a non-market compensation arrangement. On July 12, 2012, Dunkirk Power filed a RMR agreement with the FERC. On July 20, 2012, NG and Dunkirk Power agreed on the material terms for a bilateral reliability support services, or RSS, agreement and submitted those terms to the NYSPSC for rate recovery in NG's rates. On August 16, 2012, the NYSPSC approved terms and on August 27, 2012, Dunkirk Power and NG entered into the RSS agreement that began on September 1, 2012 and will expire on May 31, 2013. In late 2012, NG issued a request for proposals with respect to its reliability need in the Dunkirk area for the two years beginning June 1, 2014. Dunkirk Power submitted a proposal and signed a second, two-year, contract on March 4, 2013 pursuant to which one unit at Dunkirk will continue operating through May 31, 2015. The contract was then submitted to the NYSPSC for approval and we anticipate approval in May 2013.

Champlain-Hudson Transmission Line — On April 18, 2013, the NYSPSC approved construction of the Champlain-Hudson transmission line from Canada into New York City. Construction of this transmission expansion could have a material impact on capacity and energy prices in New York.

Changes in Accounting Standards

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

Consolidated Results of Operations

The following table provides selected financial information for the Company:



	Three months ended March 31,
(In millions except otherwise noted)	2013			2012			Change %
Operating Revenues
Energy revenue^(a)	$	942		$	434		117	%
Capacity revenue ^(a)	333			174			91
Retail revenue	1,258			1,196			5
Mark-to-market for economic hedging activities	(478		)	40			N/M
Contract amortization	(16		)	(31		)	48
Other revenues ^(b)	42			49			(14	)
Total operating revenues	2,081			1,862			12
Operating Costs and Expenses
Generation cost of sales^(a)	823			448			84
Retail cost of sales^(a)	617			608			1
Mark-to-market for economic hedging activities	(215		)	205			(205	)
Contract and emissions credit amortization ^(c)	3			7			(57	)
Other cost of operations	537			315			70
Total cost of operations	1,765			1,583			11
Depreciation and amortization	298			230			30
Selling, general and administrative	229			206			11
Acquisition-related transaction and integration costs	32			—			N/M
Development activity expenses	16			13			23
Total operating costs and expenses	2,340			2,032			15
Operating Loss	(259		)	(170		)	52
Other Income/(Expense)
Equity in earnings of unconsolidated affiliates	3			8			(63	)
Other income, net	4			1			300
Loss on debt extinguishment	(28		)	—			N/M
Interest expense	(196		)	(165		)	19
Total other expense	(217		)	(156		)	39
Loss before Income Taxes	(476		)	(326		)	46
Income tax benefit	(149		)	(120		)	24
Net Loss	(327		)	(206		)	59
Less: Net income attributable to noncontrolling interest	1			1			—
Net Loss Attributable to NRG Energy, Inc.	$	(328	)	$	(207	)	58
Business Metrics
Average natural gas price — Henry Hub ($/MMBtu)	$	3.34		$	2.74		22	%


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


(b)	Includes unrealized trading gains and losses.


(c)	Includes amortization of SO₂ and NO_xcredits and excludes amortization of Regional Greenhouse Gas Initiative, or RGGI, credits.

N/M - Not meaningful.

Management’s discussion of the results of operations for the three months ended March 31, 2013, and 2012

Loss before income taxes — The pre-tax loss of $476 million for the three months ended March 31, 2013, compared to a pre-tax loss of $326 million for the three months ended March 31, 2012, primarily reflects:


•	in the current year, a $304 million increase in Conventional Generation gross margin, a $4 million decrease in Retail gross margin, and a $31 million increase in Alternative Energy gross margin; offset by


•	a $348 million increase in operating costs primarily from increased operations and maintenance expenses, depreciation and amortization, selling, general and administrative expenses, acquisition-related transaction and integration costs, and development activity expenses;


•	an increase of $59 million in interest expense and loss on debt extinguishment; and


•	a $98 million decrease in net mark-to-market results from economic hedging activities.

Net loss — The increase in net loss of $121 million primarily reflects the drivers discussed above, offset by an income tax benefit for the three months ended March 31, 2013 of $149 million, compared with an income tax benefit of $120 million in the comparable period.

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 businesses.



	Three months ended March 31, 2013
	Conventional Generation
(In millions except otherwise noted)	Texas			East			South Central			West			Other			Subtotal			Alternative Energy		Eliminations/Corporate			Consolidated Total
Energy revenue	$	470		$	623		$	126		$	37		$	—		$	1,256		$	50	$	(364	)	$	942
Capacity revenue	18			212			58			51			1			340			—		(7		)	333
Other revenue	(14		)	13			(10		)	—			72			61			1		(20		)	42
Generation revenue	474			848			174			88			73			1,657			51		$	(391	)	$	1,317
Generation cost of sales	(228		)	(409		)	(145		)	(26		)	(28		)	(836		)	—		13			(823		)
Generation gross margin	$	246		$	439		$	29		$	62		$	45		$	821		$	51

Business Metrics
MWh sold (in thousands)	9,448			9,317			4,340			338									656
MWh generated (in thousands)	7,543			8,973			4,376			338									656
Average on-peak market power prices ($/MWh) ^(a)(b)	$	29.06		$	61.96		$	31.04		$	44.32								N/A

(a) Average on-peak market power prices calculated based on average settled market prices in the following zones: for Texas region, in ERCOT - Houston and ERCOT - North; for Northeast region, in NYISO - West, NYISO - New York City, ISO - NE - Mass Hub, PJM - West Hub and PJM - DPL; and for West region, in CAISO - NP15 and CAISO - SP15.
(b) Average on-peak market power prices for South Central region are calculated based on average day ahead market prices for "into Entergy" as published in the Platts Megawatt Daily report.



	Three months ended March 31, 2012
	Conventional Generation
(In millions except otherwise noted)	Texas			East			South Central			West			Other			Subtotal			Alternative Energy		Eliminations/Corporate			Consolidated Total
Energy revenue	$	479		$	87		$	111		$	22		$	16		$	715		$	19	$	(300	)	$	434
Capacity revenue	18			57			61			29			17			182			—		(8		)	174
Other revenue	8			6			(4		)	(3		)	61			68			1		(20		)	49
Generation revenue	505			150			168			48			94			965			20		$	(328	)	$	657
Generation cost of sales	(192		)	(82		)	(114		)	(14		)	(46		)	(448		)	—		—			(448		)
Generation gross margin	$	313		$	68		$	54		$	34		$	48		$	517		$	20

Business Metrics
MWh sold (in thousands)	8,324			1,296			4,127			371									426
MWh generated (in thousands)	6,320			900			4,263			371									426
Average on-peak market power prices ($/MWh) ^(a)(b)	$	25.32		$	35.87		$	24.41		$	27.22								N/A

(a) Average on-peak market power prices calculated based on average settled market prices in the following zones: for Texas region, in ERCOT - Houston and ERCOT - North; for Northeast region, in NYISO - West, NYISO - New York City, ISO - NE - Mass Hub, PJM - West Hub and PJM - DPL; and for West region, in CAISO - NP15 and CAISO - SP15.
(b) Average on-peak market power prices for South Central region are calculated based on average day ahead market prices for "into Entergy" as published in the Platts Megawatt Daily report.

	Three months ended March 31,
Weather Metrics	Texas			East			South Central			West
2013
CDDs ^(a)	82			—			4			—
HDDs ^(a)	983			3,004			1,898			1,428
2012
CDDs	157			—			52			—
HDDs	786			2,511			1,321			1,416
10 year average
CDDs	103			—			18			4
HDDs	1,030			3,035			1,801			1,382

(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 $304 million, including intercompany sales, during the three months ended March 31, 2013, compared to the same period in 2012, due to:



Decrease in Texas region	$	(67	)
Increase in East region	371
Decrease in South Central region	(25		)
Increase in West region	28
Other ^(a)	(3		)
	$	304


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

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



Lower gross margin from a decrease in average realized energy prices	$	(67	)
Higher gross margin from a 30% increase in coal generation driven by 11% fewer outage hours in 2013	35
Change in unrealized commercial optimization activities	(24		)
Lower gross margin due to higher replacement energy costs for the STP Unit 2 unplanned outage in 2013	(5		)
Other	(6		)
	$	(67	)

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



Higher gross margin from the acquisition of GenOn in December 2012	$	346
Higher gross margin from coal plants due to a 33% increase in energy prices	20
Higher capacity revenue due to a 26% increase in New York and PJM hedged capacity prices	15
Lower margins realized on certain load-serving contracts due to increased pricing for power purchases as well as an increase in load serving contract purchases for sales to Energy Plus.	(15		)
Higher revenue due to RSS contract revenues in western New York	12
Other	(7		)
	$	371

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



Lower gross margin from higher gas prices	$	(14	)
Lower gross margin due to higher coal transportation costs	(7		)
Higher gross margin from higher contract sales due to more favorable weather	4
Change in unrealized commercial optimization activities and other	(8		)
	$	(25	)

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



Higher gross margin from the acquisition of GenOn in December 2012	$	32
Decrease in capacity revenue due to lower pricing and outage penalties at Encina and El Segundo	(8		)
Higher gross margin due to increases in average realized energy prices	4
Decrease due to higher emissions expense	(4		)
Change in unrealized commercial optimization activities and other	4
	$	28

Retail gross margin

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

Selected Income Statement Data



	Three months ended March 31,
(In millions except otherwise noted)	2013		2012
Operating Revenues
Mass revenues	$	782	$	760
Commercial and Industrial revenues	446		411
Supply management and other revenues	31		26
Retail operating revenues ^(a)(b)	1,259		1,197
Retail cost of sales ^(c)	983		917
Retail gross margin	$	276	$	280

Business Metrics
Electricity sales volume — GWh
Mass	6,372		6,049
Commercial and Industrial ^(d)	6,205		6,070
Electricity sales volume — GWh
Texas	10,557		11,109
All other regions	2,020		1,010
Average retail customers count (in thousands, metered locations)
Mass ^(e)	2,123		2,007
Commercial and Industrial ^(d)	103		80
Retail customers count (in thousands, metered locations)
Mass ^(e)	2,129		2,016
Commercial and Industrial ^(d)	102		83


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


(b)	Includes intercompany sales of $1 million in both 2013 and 2012, representing sales from Retail to the Texas region.


(c)	Includes intercompany purchases of $366 million and $309 million, respectively.


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


(e)	Excludes utility partner customers.


•	Retail gross margin — Retail gross margin decreased $4 million for the three months ended March 31, 2013, compared to the same period in 2012, driven by:



Increase in customer count and usage	$	18
Decrease in unit margins due to customer and regional mix and lower prices on customer acquisition and renewals consistent with competitive offers	(17		)
Unfavorable impact of weather as compared to 2012	(5		)
	$	(4	)


•	Trends — Customer counts increased by approximately 21,000 since December 31, 2012, which was primarily due to selling and marketing efforts in ERCOT and the Northeast markets. Competition and higher supply costs based on forward natural gas prices and higher heat rates could drive lower unit margins in the future.

Alternative Energy gross margin

NRG's Alternative Energy business segment, which is comprised mainly of the solar and wind businesses, had gross margin of $51 million for the three months ended March 31, 2013, compared to gross margin of $20 million for the same period in 2012. The increase in gross margin primarily resulted from an additional 224,000 MWh of utility scale solar generation in 2013 as a result of new projects and project phases reaching COD during the period including 120 MW for Agua Caliente, 127 MW for CVSR, 66 MW for each of Alpine and Borrego and 26 MW for Avra Valley.

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 $98 million during the three months ended March 31, 2013 compared to the same period in 2012.

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



	Three months ended March 31, 2013
	Retail			Texas			East			South Central		West			Alternative Energy			Elimination^(a)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(2	)	$	(162	)	$	(2	)	$	9	$	(1	)	$	—		$	67		$	(91	)
Reversal on gain positions acquired as part of the GenOn acquisition	—			—			(107		)	—		(1		)	—			—			(108		)
Net unrealized (losses)/gains on open positions related to economic hedges	(5		)	(228		)	(144		)	8		5			(1		)	86			(279		)
Total mark-to-market (losses)/gains in operating revenues	$	(7	)	$	(390	)	$	(253	)	$	17	$	3		$	(1	)	$	153		$	(478	)
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized losses/(gains) on settled positions related to economic hedges	$	117		$	6		$	4		$	6	$	—		$	—		$	(67	)	$	66
Reversal of loss positions acquired as part of the Reliant Energy, Green Mountain Energy and GenOn acquisitions	5			—			15			—		—			—			—			20
Net unrealized gains/(losses) on open positions related to economic hedges	205			8			2			2		(2		)	—			(86		)	129
Total mark-to-market gains/(losses) in operating costs and expenses	$	327		$	14		$	21		$	8	$	(2	)	$	—		$	(153	)	$	215


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



	Three months ended March 31, 2012
	Retail			Texas			East			South Central			West			Alternative Energy		Elimination^(a)			Total
	(In millions)
Mark-to-market results in operating revenues
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	(2	)	$	(188	)	$	(2	)	$	10		$	1		$	—	$	62		$	(119	)
Net unrealized gains/(losses) on open positions related to economic hedges	6			141			—			(10		)	(7		)	3		26			159
Total mark-to-market gains/(losses) in operating revenues	$	4		$	(47	)	$	(2	)	$	—		$	(6	)	$	3	$	88		$	40
Mark-to-market results in operating costs and expenses
Reversal of previously recognized unrealized (gains)/losses on settled positions related to economic hedges	$	129		$	6		$	3		$	2		$	—		$	—	$	(62	)	$	78
Reversal of loss positions acquired as part of the Reliant Energy and Green Mountain Energy acquisitions	14			—			—			—			—			—		—			14
Net unrealized losses on open positions related to economic hedges	(176		)	(48		)	(13		)	(34		)	—			—		(26		)	(297		)
Total mark-to-market losses in operating costs and expenses	$	(33	)	$	(42	)	$	(10	)	$	(32	)	$	—		$	—	$	(88	)	$	(205	)


(a)	Represents the elimination of the intercompany activity between the Retail businesses and the Conventional Generation and Alternative Energy 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 reversal of gain or loss positions acquired as part of the Reliant Energy, Green Mountain Energy and GenOn acquisitions were valued based upon the forward prices on the acquisition date.

For the three months ended March 31, 2013, the net losses on open positions were due to increases in forward natural gas and power prices.

For the three months ended March 31, 2012, the net losses on open positions were due to a decrease in forward coal and power prices and 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 three months ended March 31, 2013 and 2012. The realized and unrealized financial and physical trading results are included in operating revenue. The Company's trading activities are subject to limits within the Company's Risk Management Policy.



	Three months ended March 31,
(In millions)	2013			2012
Trading gains/(losses)
Realized	$	41		$	11
Unrealized	(43		)	(2		)
Total trading (losses)/gains	$	(2	)	$	9

Contract Amortization Revenue

Contract amortization represents the roll-off of in-market customer contracts valued under purchase accounting and the favorable change of $15 million as compared to the prior period in 2012 related primarily to lower contract amortization for Reliant Energy and Green Mountain Energy of $11 million and $4 million, respectively.

Other Operating Costs



	Retail		Texas		East		South Central		West		Other		Alternative Energy		Eliminations/Corporate			Total
	(In millions)
Three months ended March 31, 2013	$	57	$	137	$	238	$	29	$	53	$	25	$	10	$	(12	)	$	537
Three months ended March 31, 2012	$	57	$	147	$	56	$	21	$	15	$	28	$	6	$	(15	)	$	315

Other operating costs increased by $222 million for the three months ended March 31, 2013 compared to the same period in 2012, due to:



Increase in operations and maintenance expense for GenOn plants acquired in December 2012	$	219
Decrease in Texas region operations and maintenance expense, primarily from additional maintenance on Limestone in 2012	(8		)
Increase in South Central region operations and maintenance expense, due to steam turbine maintenance at Cottonwood in 2013	7
Other	4
	$	222

Depreciation and Amortization

Depreciation and amortization increased by $68 million, due primarily to $59 million from the acquisition of GenOn in December 2012, as well as approximately $9 million of additional depreciation from solar facilities that reached commercial operations in late 2012 and early 2013.

Selling, General and Administrative Expenses

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



	Three months ended March 31,
(In millions)	2013		2012
General and administrative expenses	$	150	$	135
Selling and marketing expenses	79		71
	$	229	$	206

General and administrative expenses increased by $15 million for the three months ended March 31, 2013, compared to the same period in 2012, which was due primarily to the following:

•Increase in general and administrative costs for GenOn, which was acquired in December 2012, of $50 million.

•Impact in prior year of the CDWR settlement of $20 million;

•Impact in prior year of transaction costs associated with the sale of 49% of Agua Caliente; and


•	Decrease in other general and administrative expenses of $7 million.

Selling and marketing expenses increased due to customer growth efforts and new market expansion by the Retail Business.

Acquisition-related Transaction and Integration Costs

In connection with the Merger, NRG incurred transaction and integration costs of $32 million in the three months ended March 31, 2013 consisting primarily of severance costs.

Equity in Earnings of Unconsolidated Affiliates

NRG's equity earnings from unconsolidated affiliates were $3 million for the three months ended March 31, 2013 compared to $8 million for the same period in 2012 primarily due to a $5 million decrease in the fair value of Sherbino's forward gas contract.

Loss on Debt Extinguishment

A loss on debt extinguishment of $28 million was recorded in the three months ended March 31, 2013 related to open market repurchases of the 2018 Senior Notes, 2019 Senior Notes and 2020 Senior Notes. These losses primarily consisted of the premiums paid on redemption and the write-off of previously deferred financing costs.

Interest Expense

NRG's interest expense increased by $31 million compared to the same period in 2012 due to the following:



Increase/(decrease) in interest expense	(In millions)
Increase for acquisition of GenOn in December 2012	$	45
Decrease for 2017 Senior Notes redeemed in September 2012	(20		)
Increase for 2023 Senior Notes issued in September 2012	16
Decrease for the repricing of the term loan in February 2013	(8		)
Increase from additional project financings	12
Decrease for higher capitalized interest	(8		)
Decrease in amortization of deferred financing costs and other interest expense	(6		)
Total	$	31

Income Tax Benefit

For the three months ended March 31, 2013, NRG recorded an income tax benefit of $149 million on pre-tax loss of $476 million. For the same period in 2012, NRG recorded an income tax benefit of $120 million on a pre-tax loss of $326 million. The effective tax rate was 31.3% and 36.8% for the three months ended March 31, 2013, and 2012, respectively.

For the three months ended March 31, 2012, NRG's overall effective tax rate was different than the statutory rate of 35% primarily due to the generation of ITCs from the Company's Agua Caliente solar project in Arizona.

Liquidity and Capital Resources

Liquidity Position

As of March 31, 2013, and December 31, 2012, NRG's liquidity, excluding collateral received, was approximately $3.1 billion and $3.4 billion, respectively, comprised of the following:



(In millions)	March 31, 2013			December 31, 2012
Cash and cash equivalents	$	1,707		$	2,087
Funds deposited by counterparties	105			271
Restricted cash	221			217
Total	2,033			2,575
Revolving Credit Facility availability	1,157			1,058
Total liquidity	3,190			3,633
Less: Funds deposited as collateral by hedge counterparties	(105		)	(271		)
Total liquidity, excluding collateral received	$	3,085		$	3,362

For the three months ended March 31, 2013, total liquidity, excluding collateral received, decreased by $277 million. Changes in cash and cash equivalent balances are further discussed hereinafter under the heading Cash Flow Discussion. Cash and cash equivalents and funds deposited by counterparties at March 31, 2013 were predominantly held in money market funds invested in treasury securities, treasury repurchase agreements or government agency debt.

Funds deposited by counterparties consist of cash held by the Company as a result of collateral posting obligations from its counterparties. Some amounts are segregated into separate accounts and are not contractually restricted but, based on the Company's intention, are not available for the payment of general corporate obligations. Depending on market fluctuations and the settlement of the underlying contracts, the Company will refund this collateral to the hedge counterparties pursuant to the terms and conditions of the underlying trades. Since collateral requirements fluctuate daily and the Company cannot predict if any collateral will be held for more than twelve months, the funds deposited by counterparties are classified as a current asset on the Company's consolidated balance sheets, with an offsetting liability for this cash collateral received within current liabilities, identified as cash collateral received in support of energy risk management activities. Changes in funds deposited by counterparties are closely associated with the Company's operating activities and are classified as an operating activity in the Company's consolidated statements of cash flows.

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.

SOURCES OF LIQUIDITY

The principal sources of liquidity for NRG's future operating and capital expenditures are expected to be derived from new and existing financing arrangements, existing cash on hand and cash flows from operations. As described in Note 7, Debt and Capital Leases, to this Form 10-Q and Note 11, Debt and Capital Leases, to the Company's 2012 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.

In addition, NRG has granted first liens to certain counterparties on a substantial portion of the Company's assets, excluding assets acquired in the GenOn acquisition. 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 in-the-money to NRG, the counterparty would have no claim under the lien program. The lien program limits the volume that can be hedged, not the value of underlying out-of-the-money positions. The first lien program does not require NRG to post collateral above any threshold amount of exposure. Within the first lien structure, the Company can hedge up to 80% of its coal and nuclear capacity, excluding GenOn coal capacity, and 10% of its other assets, excluding GenOn's other assets, with these counterparties for the first 60 months and then declining thereafter. Net exposure to a counterparty on all trades must be positively correlated to the price of the relevant commodity for the first lien to be available to that counterparty. The first lien structure is not subject to unwind or termination upon a ratings downgrade of a counterparty and has no stated maturity date.

The Company's lien counterparties may have a claim on its assets to the extent market prices exceed the hedged prices. As of March 31, 2013, in aggregate, the hedge portfolio under the lien was out-of-the-money.

The following table summarizes the amount of MWs hedged against the Company's coal and nuclear assets and as a percentage relative to the Company's coal and nuclear capacity under the first lien structure as of March 31, 2013:



Equivalent Net Sales Secured by First Lien Structure ^(a)	2013		2014		2015		2016		2017
In MW ^(b)	1,313		1,439		461		546		166
As a percentage of total net coal and nuclear capacity ^(c)	21	%	22	%	7	%	9	%	3	%


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


(b)	2013 MW value consists of May through December positions only.


(c)	Net coal and nuclear capacity represents 80% of the Company’s total coal and nuclear assets eligible under the first lien which excludes coal assets acquired in the GenOn acquisition.

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) corporate financial transactions including return of capital and dividend payments to stockholders.

Commercial Operations

NRG's commercial operations activities require a significant amount of liquidity and capital resources. These liquidity requirements are primarily driven by: (i) margin and collateral posted with counterparties; (ii) margin and collateral required to participate in physical markets and commodity exchanges; (iii) timing of disbursements and receipts (i.e. buying fuel before receiving energy revenues); (iv) initial collateral for large structured transactions; and (v) collateral for project development. As of March 31, 2013, commercial operations had total cash collateral outstanding of $455 million, and $760 million outstanding in letters of credit to third parties primarily to support its commercial activities for both wholesale and retail transactions. As of March 31, 2013, total collateral held from counterparties was $105 million in cash, and $45 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.

Capital Expenditures

The following tables and descriptions summarize the Company's capital expenditures, including accruals, for maintenance, environmental, and growth investments for the three months ended March 31, 2013, and the estimated capital expenditure and growth investments forecast for the remainder of 2013.



	Maintenance			Environmental			Growth Investments			Total
	(In millions)
East	$	31		$	13		$	—		$	44
Texas	35			—			—			35
South Central	6			4			—			10
West	2			—			68			70
Other Conventional	2			—			5			7
Retail	8			—			—			8
Alternative Energy	—			—			267			267
Corporate	1			—			—			1
Total capital expenditures for the three months ended March 31, 2013	85			17			340			442
Accrual impact	10			(3		)	364			371
Total cash capital expenditures for the three months ended March 31, 2013	95			14			704			813
Other investments ^(a)	—			—			34			34
Funding from debt financing, net of fees	—			—			(732		)	(732		)
Funding from third party equity partners	—			—			(35		)	(35		)
Total capital expenditures and investments, net of financings	$	95		$	14		$	(29	)	$	80

Estimated capital expenditures for the remainder of 2013	$	383		$	156		$	1,070		$	1,609
Other investments ^(a)	—			—			278			278
Funding from debt financing, net of fees	(24		)	(8		)	(793		)	(825		)
Funding from third party equity partners and cash grants	—			—			(276		)	(276		)
NRG estimated capital expenditures for the remainder of 2013, net of financings	$	359		$	148		$	279		$	786


(a)	Other investments includes restricted cash activity.

•

Environmental capital expenditures — For the three months ended March 31, 2013, the Company's environmental capital expenditures included $11 million related to the upgrades at Conemaugh including the installation of selective catalytic reduction technology on both units for enhanced mercury oxidation and removal as well as reduction in NO_x emissions and the completion of upgrades to the existing flue-gas desulfurization systems for enhanced performance.


•	Growth Investments capital expenditures — For the three months ended March 31, 2013, the Company's growth investment expenditures included $245 million for solar projects and $93 million for the Company's repowering projects.

Environmental Capital Expenditures

Based on current rules, technology and preliminary plans based on some proposed rules, NRG estimates that environmental capital expenditures from 2013 through 2017 required to comply with environmental laws will be approximately $528 million, consisting of $317 million for legacy NRG facilities and $211 million for GenOn facilities. These costs are primarily associated with controls to satisfy the MATS and recent NSR settlement at Big Cajun II and MATS at W.A. Parish, Limestone, and Conemaugh and NO_xcontrols for Sayreville and Gilbert. The decrease from NRG's previous estimate is related to changes in technology related to complying with MATS and the NSR settlement at Big Cajun II, and the selection of more cost-effective environmental solutions at Cheswick. NRG continues to explore cost-effective compliance alternatives to further reduce costs.

NRG's current contracts with the Company's rural electrical customers in the South Central region allow for recovery of a portion of the region's capital costs once in operation, along with a capital return incurred by complying with any change in law, including interest over the asset life of the required expenditures. The actual recoveries will depend, among other things, on the timing of the completion of the capital projects and the remaining duration of the contracts.

2013 Capital Allocation Program

During 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 open market repurchases of the Company's 2018 Senior Notes, 2019 Senior Notes, and 2020 Senior Notes, respectively.

In addition, the Company is authorized to repurchase $200 million of its common stock under the 2013 Capital Allocation Program. During the first quarter of 2013, the Company purchased 972,292 shares of NRG common stock for $25 million, at an average cost of $25.88 per share, of which 195,210 shares settled in April 2013 for which $5 million was accrued as of March 31, 2013. The Company intends to complete the remaining $175 million of share repurchases by the end of 2013.

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

Cash Flow Discussion

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



Three months ended March 31,	2013			2012			Change
	(In millions)
Net cash used by operating activities	$	(124	)	$	(76	)	$	(48	)
Net cash used by investing activities	(836		)	(543		)	(293		)
Net cash provided by financing activities	580			527			53

Net Cash Used By Operating Activities

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



	(In millions)
Increase in operating income adjusted for non-cash charges	$	(16	)
Change in cash paid in support of risk management activities, primarily related to margin posted for retail supply positions	(39		)
Other changes in working capital	7
	$	(48	)

Net Cash Used By Investing Activities

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



	(In millions)
Increase in capital expenditures due to increased spending on maintenance and growth projects	$	(174	)
Increase in restricted cash, which mainly supports equity requirements for U.S. DOE funded projects	(76		)
Increase in cash paid for acquisitions, which primarily reflects the acquisition of High Desert in 2013	(18		)
Decrease in cash grant receipts in 2013	(12		)
Other	(13		)
	$	(293	)

Net Cash Provided By Financing Activities

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



	(In millions)
Net increase in borrowings, primarily related to financing arrangements for the Borrego and Alpine solar projects	$	321
Increase in financing element of acquired derivatives due to acquisition of GenOn	118
Net increase in debt payments primarily related to open market repurchases of Senior Notes in 2013	(185		)
Prior year proceeds from the sale of noncontrolling interest, related primarily to sale of 49% interest of Agua Caliente in 2012, offset by contributions from noncontrolling interests in both years	(158		)
Payment of dividends to common stockholders in 2013	(29		)
Cash paid for repurchase of treasury stock in 2013	(20		)
Other	6
	$	53

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

For the three months ended March 31, 2013, the Company had a total domestic pre-tax book loss of $478 million and foreign pre-tax book income of $2 million. For the three months ended March 31, 2013, the Company generated domestic net operating losses, or NOLs, of $25 million. As of March 31, 2013, the Company has cumulative domestic NOL carryforwards of $1.7 billion for financial statement purposes. In addition, NRG has cumulative foreign NOL carryforwards of $310 million, of which $69 million will expire starting 2013 through 2018 and of which $242 million do not have an expiration date.

In addition to these amounts, the Company has $196 million of tax effected uncertain tax benefits. As a result of the Company's tax position, and based on current forecasts, NRG anticipates income tax payments, primarily to state and local jurisdictions, of up to $40 million in 2013.

However, as the position remains uncertain for the $196 million of tax effected uncertain tax benefits, the Company has recorded a non-current tax liability of $74 million and may accrue the remaining balance as an increase to non-current liabilities until final resolution with the related taxing authority. The $74 million non-current tax liability for uncertain tax benefits is primarily from positions taken on various state returns, including accrued interest.

New and On-going Company Initiatives and Development Projects

Renewable Development and Acquisitions

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

Solar

NRG has acquired and is developing a number of solar projects utilizing photovoltaic, or PV, as well as solar thermal technologies. The following table is a brief summary of the Company's major Utility Scale Solar projects as of March 31, 2013 that are or were under construction during the first quarter. As of March 31, 2013, NRG had 500 MW of capacity at its commercially operating solar facilities, which includes the assets in service at Agua Caliente, CVSR, Alpine, Borrego and High Desert, among others.



NRG Owned Projects	Location	PPA	MW ^(a)	Expected COD	Status
Ivanpah ^(b)	Ivanpah, CA	20 - 25 year	392	2013	Under Construction
Agua Caliente ^(c)	Yuma County, AZ	25 year	290	2012 - 2014	Partially In-Service
CVSR ^(d)	San Luis Obispo, CA	25 year	250	2012 - 2013	Partially In-Service
Alpine	Lancaster, CA	20 year	66	2013	In-Service
Borrego	Borrego Springs, CA	25 year	26	2013	In-Service
High Desert	Lancaster, CA	20 year	20	2013	In-Service


(a)	Represents total project size.


(b)	NRG owns a 50.1% stake in the Ivanpah solar project.


(c)	NRG owns a 51% stake in the 290 MW Agua Caliente project which includes 253 MW that have reached commercial operations as of March 31, 2013.


(d)	CVSR has 127 MW in operation as of March 31, 2013.

Below is a summary of recent developments related to solar projects:

Ivanpah — Construction related matters have resulted in delays for the first two units of the Ivanpah project. As a result, the first unit of the Ivanpah project is now expected to be completed and producing power by the end of September 2013 instead of July 2013. The second and third units are now both expected to be completed in the fourth quarter of 2013 instead of the third and fourth quarter of 2013, respectively. Power generated from Ivanpah will be sold to Southern California Edison and PG&E under multiple 20 to 25 year PPAs.

Agua Caliente — On January 18, 2012, the Company completed the sale of a 49% interest in NRG Solar AC Holdings LLC, the indirect owner of Agua Caliente, to MidAmerican Energy Holdings Company. Operations are scheduled to commence in phases through the first quarter of 2014, with 253 MW having achieved commercial operations from January through December of 2012. Power generated from Agua Caliente is being sold to PG&E under a 25 year PPA. While full commercial operations of the entire project will be achieved in early 2014, the maximum capacity deliverable under the PPA of 290 MWs is expected to be on-line by the third quarter of 2013.

CVSR — NRG owns 100% of the 250 MW CVSR project in eastern San Luis Obispo County, California. Operations commenced on the first 22 MW phase in September 2012 and 105 MWs for Phases 2 and 4 in December 2012, with the final phase expected during the fourth quarter of 2013. Power generated from CVSR is sold to PG&E under a 25 year PPA.

Alpine — Alpine, located in Lancaster, CA, is a 66 MW photovoltaic facility utilizing First Solar thin film solar modules. The project reached commercial operations in January 2013. Power generated from Alpine will be sold to PG&E under a 20 year PPA.

Borrego — Borrego, located in Borrego Springs, CA, is a 26 MW facility utilizing SunPower's Oasis photovoltaic power block with single axis tracking. The project reached commercial operations in February 2013 and obtained financing on March 28, 2013, as discussed in Note 7, Debt and Capital Leases. Power generated from Borrego is sold to San Diego Gas and Electric under a 25 year PPA.

High Desert — In March 2013, the Company, through its wholly-owned subsidiary, NRG Solar PV LLC, acquired High Desert, a 20 MW utility-scale photovoltaic solar facility located in Lancaster, California. The project was financed with $24 million in equity and $82 million of nonrecourse project level debt as discussed in Note 7, Debt and Capital Leases. The solar facility provides electricity to Southern California Edison under a 20-year PPA.

Distributed Solar — In February 2013, solar power generating systems at Lincoln Financial Field in Philadelphia, PA and at Arizona State University in Tempe, Arizona achieved commercial operation, along with several other smaller projects in Arizona. All of the Company's Distributed Solar projects in operation or under construction are supported by long-term PPAs.

Conventional Power Development and Acquisitions

Projects Under Construction and Completed in 2013

The Company's El Segundo Energy Center LLC, or ESEC, is continuing construction at its El Segundo Power Generating Station, a 550 MW fast start, gas turbine combined cycle generating facility in El Segundo, California. The facility is being constructed pursuant to a 10 year, 550 MW PPA with Southern California Edison. The Company expects a commercial operation date of August 1, 2013.

The Company completed construction of the Marsh Landing project, a 720 MW natural gas-fired peaking facility adjacent to the Company's Contra Costa generating facility near Antioch, California, in 2013. The output of the facility is contracted to PG&E pursuant to a 10 year PPA. The project achieved commercial operations on May 1, 2013.

Gregory Acquisition

On April 2, 2013, NRG Texas Gregory LLC, a wholly-owned subsidiary of NRG, entered into an agreement with a consortium of affiliates of Atlantic Power Corporation, John Hancock Life Insurance Company (U.S.A.), and Rockland Capital, LLC to acquire the Gregory cogeneration plant in Corpus Christi, Texas. NRG expects to pay approximately $244 million for the plant, which has generation capacity of 400 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 Gregory acquisition is expected to close in the third quarter of 2013, subject to customary closing conditions and regulatory approvals. On April 25, 2013, the Federal Trade Commission granted early termination of the Hart-Scott-Rodino pre-merger notification waiting period.

Retail Growth Initiatives

NRG's Retail Business continues to develop innovative products and services that help change the way consumers and businesses think about and use energy.

The Company is expanding its partnership with Nest Labs to include the Nest Learning Thermostat with its retail electricity plans through an exclusive energy provider relationship in Texas and the Northeast competitive electricity markets. This partnership brings together the Company's competitive and innovative electricity plans, its energy management services, and Nest's learning thermostat. Together, the Company and Nest Labs provide residential and small business customers with insights, choices and convenient ways to manage energy use.

In the Northeast, the Company also continued its retail market expansion and growth initiatives during the quarter. The Company entered the Maryland retail electricity market with its Green Mountain Energy brand. In addition, the Company entered into an agreement to acquire from another retailer contracts representing approximately 20,000 customers in Pennsylvania and New Jersey.

Electric Vehicle Infrastructure Development

NRG, through its subsidiary eVgo, continues its build out and operation of electric vehicle charging ecosystems designed to equip entire major markets with the privately funded infrastructure needed for successful EV adoption and integration. The Company's markets include Houston, Dallas/Fort Worth, Washington, DC/Baltimore, and California. As of March 31, 2013, eVgo had 17 public fast charging Freedom Station sites operational in Houston and 20 in Dallas/Fort Wort, which comprise the largest privately-funded comprehensive direct current fast-charging networks in the nation. In addition, eVgo had 6 sites in the Washington, DC/Baltimore market under construction or in permitting. In the newly entered California markets, eVgo had 10 sites in permitting. eVgo offers consumers a subscription-based plan that provides for all charging requirements for EVs at a competitive monthly fee.

eVgo is building out its California ecosystems in accordance with its agreement with the CPUC to spend approximately $100 million over the next four to six years to build at least 200 public fast charging Freedom Station sites and wiring and associated work to prepare 10,000 commercial and multi-family parking spaces for electric vehicle charging in the state.

W.A. Parish Peaking Unit and Commercial Scale Carbon Capture, Utilization and Storage System

The Company is continuing construction of the 75 MW peaking unit at W.A. Parish and anticipates a commercial operations date during the second quarter of 2013. The unit is expected to be retrofitted for use as a cogeneration facility to provide steam and power to operate the CCUS, which is being partially funded by a grant from the US DOE.

Construction of the CCUS is intended to allow NRG, through its wholly owned subsidiary Petra Nova LLC, or Petra Nova, to utilize the captured CO₂ in enhanced oil recovery operations in oil fields on the Texas Gulf Coast. In December of 2012, the final air permit was issued by the Texas Commission on Environmental Quality for the full carbon capture system. The final Environmental Impact Statement is approved and the Record of Decision is expected to be issued by the U.S. DOE in May 2013. Construction of the CCUS is subject to receipt of appropriate financing and negotiation of material contracts.

Off-Balance Sheet Arrangements

Obligations under Certain Guarantee Contracts

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

Retained or Contingent Interests

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

Derivative Instrument Obligations

The Company's 3.625% Preferred Stock includes a feature which is considered an embedded derivative per ASC 815. Although it is considered an embedded derivative, it is exempt from derivative accounting as it is excluded from the scope pursuant to ASC 815. As of March 31, 2013, based on the Company's stock price, the embedded derivative was out-of-the-money and had no redemption value.

Obligations Arising Out of a Variable Interest in an Unconsolidated Entity

Variable interest in equity investments — As of March 31, 2013, 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 $233 million as of March 31, 2013. This indebtedness may restrict the ability of these subsidiaries to issue dividends or distributions to NRG. See also Note 15, Investments Accounted for by the Equity Method and Variable Interest Entities, to the Company's 2012 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 2012 Form 10-K. See also Note 7, Debt and Capital Leases, and Note 13, Commitments and Contingencies, to this Form 10-Q for a discussion of new commitments and contingencies that also include contractual obligations and commercial commitments that occurred during the three months ended March 31, 2013.

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 2012 Form 10‑K.

The tables below disclose the activities that include both exchange and non-exchange traded contracts accounted for at fair value in accordance with ASC 820, Fair Value Measurements and Disclosures, or ASC 820. Specifically, these tables disaggregate realized and unrealized changes in fair value; disaggregate estimated fair values at March 31, 2013, based on their level within the fair value hierarchy defined in ASC 820; and indicate the maturities of contracts at March 31, 2013.



Derivative Activity Gains/(Losses)	(In millions)
Fair value of contracts as of December 31, 2012	$	825
Contracts realized or otherwise settled during the period	(151		)
Changes in fair value	(277		)
Fair value of contracts as of March 31, 2013	$	397



	Fair Value of Contracts as of March 31, 2013
Fair value hierarchy Gains/(Losses)	Maturity Less Than 1 Year		Maturity 1-3 Years		Maturity 3-5 Years			Maturity in Excess 5 Years		Total Fair Value
	(In millions)
Level 1	$	45	$	34	$	34		$	—	$	113
Level 2	265		90		(79		)	3		279
Level 3	2		3		—			—		5
Total	$	312	$	127	$	(45	)	$	3	$	397

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 Value at Risk, or VaR, a statistical model which attempts to predict risk of loss based on market price and volatility. NRG's risk management policy places a limit on one-day holding period VaR, which limits the Company's net open position. As the Company's trade-by-trade derivative accounting results in a gross-up of the Company's derivative assets and liabilities, the net derivative asset and liability position is a better indicator of NRG's hedging activity. As of March 31, 2013, NRG's net derivative asset was $397 million, a decrease to total fair value of $428 million as compared to December 31, 2012. This decrease was primarily driven by the roll-off of trades that settled during the period in addition to losses in fair value due to the increases in natural gas and power prices.

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 $369 million in the net value of derivatives as of March 31, 2013. 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 $336 million in the net value of derivatives as of March 31, 2013.

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 2012 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 Value at Risk, or VaR. NRG uses a Monte Carlo simulation based VaR model to estimate the potential loss in the fair value of the Company's energy assets and liabilities, which includes generation assets, load obligations and bilateral physical and financial transactions.

As of March 31, 2013, the VaR for NRG's commodity portfolio, including generation assets, load obligations and bilateral physical and financial transactions calculated using the VaR model was $89 million.

The following table summarizes average, maximum and minimum VaR for NRG for the three months ended March 31, 2013, and 2012:



(In millions)	2013		2012
VaR as of March 31,	$	89	$	51
Three months ended March 31,
Average	$	97	$	34
Maximum	104		53
Minimum	89		24

In order to provide additional information for comparative purposes to NRG's peers, the Company also uses VaR to estimate the potential loss of derivative financial instruments that are subject to mark-to-market accounting. These derivative instruments include transactions that were entered into for both asset management and trading purposes. The VaR for the derivative financial instruments calculated using the diversified VaR model as of March 31, 2013 for the entire term of these instruments entered into for both asset management and trading was $60 million, primarily driven by asset-backed transactions.

Interest Rate Risk

NRG is exposed to fluctuations in interest rates through the Company's 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 11, Debt and Capital Leases, of the Company's 2012 Form 10-K, as well as Note 7, Debt and Capital Leases of this Form 10-Q, for more information on the Company's interest rate swaps.

If all of the above swaps had been discontinued on March 31, 2013, the Company would have owed the counterparties $131 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.

As part of the CVSR financing, the Company entered into swaptions with a notional value of $251 million in order to hedge the project interest rate risk. If the swaptions were discontinued on March 31, 2013, the counterparty would have owed the Company approximately $2 million.

NRG has both long and short-term debt instruments that subject the Company to the risk of loss associated with movements in market interest rates. As of March 31, 2013, a 1% change in interest rates would result in a $17 million change in interest expense on a rolling twelve month basis.

As of March 31, 2013, the fair value of the Company's debt was $17.1 billion and the related carrying amount was $16.5 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 $1.2 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 $156 million as of March 31, 2013, and a 1 MMBtu/MWh change in heat rates for heat rate positions would result in a change in margin collateral posted of approximately $98 million as of March 31, 2013. This analysis uses simplified assumptions and is calculated based on portfolio composition and margin-related contract provisions as of March 31, 2013.

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 Securities Exchange Act of 1934, as amended, or the Exchange Act. Based on this evaluation, the Company's principal executive officer, principal financial officer and principal accounting officer concluded that the disclosure controls and procedures were effective as of the end of the period covered by this report on Form 10-Q.

Changes in Internal Control over Financial Reporting

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

PART II — OTHER INFORMATION

ITEM 1 — LEGAL PROCEEDINGS

For a discussion of material legal proceedings in which NRG was involved through March 31, 2013, 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 2012 Form 10-K.

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



For the period ended March 31, 2013	Total number of shares purchased	Average price paid per share^(a)		Total number of shares purchased under the 2013 Capital Allocation Program	Dollar value of shares that may be purchased under the 2013 Capital Allocation Program^(b)
January 1- January 31	—	$	—	—	$	200,000,000
February 1- February 28	—	—		—	200,000,000
March 1- March 31	972,292	25.88		972,292	174,828,171
First quarter 2013 Total	972,292	$	25.88	972,292	$	174,828,171

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

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

On February 27, 2013, the Company announced a plan to repurchase $200 million of its common stock under the 2013 Capital Allocation Program. During the first quarter, the Company purchased 972,292 shares of NRG common stock for $25 million at an average cost of $25.88 per share, of which 195,210 shares settled in April 2013 for which $5 million was accrued as of March 31, 2013. The Company intends to complete its remaining $175 million of share repurchases by the end of 2013, subject to available capital, market conditions, and compliance with associated laws and regulations.

ITEM 3 — DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4 — MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5 — OTHER INFORMATION

None.

ITEM 6 — EXHIBITS



Number	Description	Method of Filing
4.1	Seventy-Seventh Supplemental Indenture, dated as of January 3, 2013, 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 January 9, 2013.
4.2	Seventy-Eighth Supplemental Indenture, dated as of January 3, 2013, 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 January 9, 2013.
4.3	Seventy-Ninth Supplemental Indenture, dated as of January 3, 2013, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York.	Incorporated herein by reference to Exhibit 4.3 to the Company's Current Report on Form 8-K filed on January 9, 2013.
4.4	Eightieth Supplemental Indenture, dated as of January 3, 2013, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York.	Incorporated herein by reference to Exhibit 4.4 to the Company's Current Report on Form 8-K filed on January 9, 2013.
4.5	Eighty-First Supplemental Indenture, dated as of January 3, 2013, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York.	Incorporated herein by reference to Exhibit 4.5 to the Company's Current Report on Form 8-K filed on January 9, 2013.
4.6	Eighty-Second Supplemental Indenture, dated as of January 3, 2013, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York.	Incorporated herein by reference to Exhibit 4.6 to the Company's Current Report on Form 8-K filed on January 9, 2013.
4.7	Eighty-Third Supplemental Indenture, dated as of March 13, 2013, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York.	Incorporated herein by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on March 13, 2013.
4.8	Eighty-Fourth Supplemental Indenture, dated as of March 13, 2013, 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 March 13, 2013.
4.9	Eighty-Fifth Supplemental Indenture, dated as of March 13, 2013, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York.	Incorporated herein by reference to Exhibit 4.3 to the Company's Current Report on Form 8-K filed on March 13, 2013.
4.10	Eighty-Sixth Supplemental Indenture, dated as of March 13, 2013, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York.	Incorporated herein by reference to Exhibit 4.4 to the Company's Current Report on Form 8-K filed on March 13, 2013.
4.11	Eighty-Seventh Supplemental Indenture, dated as of March 13, 2013, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York.	Incorporated herein by reference to Exhibit 4.5 to the Company's Current Report on Form 8-K filed on March 13, 2013.
4.12	Eighty-Eighth Supplemental Indenture, dated as of March 13, 2013, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York.	Incorporated herein by reference to Exhibit 4.6 to the Company's Current Report on Form 8-K filed on March 13, 2013.
4.13	Eighty-Ninth Supplemental Indenture, dated as of March 13, 2013, among NRG Energy, Inc., the guarantors named therein and Law Debenture Trust Company of New York.	Incorporated herein by reference to Exhibit 4.7 to the Company's Current Report on Form 8-K filed on March 13, 2013.
10.1	First Amendment Agreement, dated as of February 6, 2013, to the Amended and Restated Credit Agreement and the Second Amended and Restated Collateral Trust Agreement.	Filed herewith
31.1	Rule 13a-14(a)/15d-14(a) certification of David W. Crane	Filed herewith
31.2	Rule 13a-14(a)/15d-14(a) certification of Kirkland B. Andrews	Filed herewith
31.3	Rule 13a-14(a)/15d-14(a) certification of Ronald B. Stark	Filed herewith
32	Section 1350 Certification	Filed herewith
101 INS	XBRL Instance Document	Filed herewith
101 SCH	XBRL Taxonomy Extension Schema	Filed herewith
101 CAL	XBRL Taxonomy Extension Calculation Linkbase	Filed herewith
101 DEF	XBRL Taxonomy Extension Definition Linkbase	Filed herewith
101 LAB	XBRL Taxonomy Extension Label Linkbase	Filed herewith
101 PRE	XBRL Taxonomy Extension Presentation Linkbase	Filed herewith

SIGNATURES

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



	NRG ENERGY, INC. (Registrant)

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


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


	/s/ RONALD B. STARK
	Ronald B. Stark
Date: May 7, 2013	Chief Accounting Officer (Principal Accounting Officer)