UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~June~~September 30, 2012

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 333-63240

GenOn Americas Generation, LLC

(Exact Name of Registrant as Specified in Its Charter)

51-0390520

(I.R.S. Employer Identification No.)

Commission File Number: 333-61668

GenOn Mid-Atlantic, LLC

(Exact Name of Registrant as Specified in Its Charter)

58-2574140

(I.R.S. Employer Identification No.)

Delaware

Delaware
(State or Other Jurisdiction of Incorporation or Organization)

1000 Main Street,
Houston, Texas		77002
(Address of Principal Executive Offices)		(Zip Code)

(State or Other Jurisdiction of Incorporation or Organization)

1000 Main Street,
Houston, Texas		77002
(Address of Principal Executive Offices)		(Zip Code)

(832) 357-3000

(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. (As a voluntary filer not subject to filing requirements, the registrant nevertheless filed all reports which would have been required to be filed by Section 15(d) of the Exchange Act during the preceding 12 months had the registrant been required to file reports pursuant to Section 15(d) of the Securities Exchange Act of 1934 solely as a result of having registered debt securities under the Securities Act of 1933.)

GenOn Americas Generation, LLC	o Yes o No
GenOn Mid-Atlantic, LLC	o Yes o No

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).

GenOn Americas Generation, LLC	x Yes o No
GenOn Mid-Atlantic, LLC	x Yes o No

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.

Large accelerated filer Accelerated filer Non-accelerated filer Smaller reporting company GenOn Americas Generation, LLC o o x o GenOn Mid-Atlantic, LLC o o x o (Do not check if a smaller reporting company)

(Do not check if a smaller reporting company)

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

GenOn Americas Generation, LLC	o Yes x No
GenOn Mid-Atlantic, LLC	o Yes x No

All of the registrant’s outstanding membership interests are held by its parent and there are no membership interest held by nonaffiliates.

Registrant		Parent
GenOn Americas Generation, LLC		GenOn Americas, Inc.
GenOn Mid-Atlantic, LLC		GenOn North America, LLC

This combined Form 10-Q is separately filed by GenOn Americas Generation, LLC and GenOn Mid-Atlantic, LLC. Information contained in this combined Form 10-Q relating to GenOn Americas Generation, LLC and GenOn Mid-Atlantic, LLC is filed by such registrant on its own behalf and each registrant makes no representation as to information relating to registrants other than itself.

NOTE: WHEREAS GENON AMERICAS GENERATION, LLC AND GENON MID-ATLANTIC, LLC MEET THE CONDITIONS SET FORTH IN GENERAL INSTRUCTION H(1)(a) AND (b) OF FORM 10-Q, THIS COMBINED FORM 10-Q IS BEING FILED WITH THE REDUCED DISCLOSURE FORMAT PURSUANT TO GENERAL INSTRUCTION H(2).

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TABLE OF CONTENTS

	Glossary of Certain Defined Terms	iv
	Cautionary Statement Regarding Forward-Looking Information	vii
PART I
FINANCIAL INFORMATION
ITEM 1.	FINANCIAL STATEMENTS	1
	GenOn Americas Generation, LLC:
	Condensed Consolidated Statements of Operations (Unaudited) Three and Six Months Ended June 30, 2012 and 2011	1
	Condensed Consolidated Statements of Operations (Unaudited) Three and Nine Months Ended September 30, 2012 and 2011	1
	Condensed Consolidated Balance Sheets (Unaudited) June 30, 2012 and December 31, 2011	2
	Condensed Consolidated Balance Sheets (Unaudited) September 30, 2012 and December 31, 2011	2
	Condensed Consolidated Statements of Cash Flows (Unaudited) Six Months Ended June 30, 2012 and 2011	3
	Condensed Consolidated Statements of Cash Flows (Unaudited) Nine Months Ended September 30, 2012 and 2011	3
	GenOn Mid-Atlantic, LLC:
	Condensed Consolidated Statements of Operations (Unaudited) Three and Six Months Ended June 30, 2012 and 2011	4
	Condensed Consolidated Statements of Operations (Unaudited) Three and Nine Months Ended September 30, 2012 and 2011	4
	Condensed Consolidated Balance Sheets (Unaudited) June 30, 2012 and December 31, 2011	5
	Condensed Consolidated Balance Sheets (Unaudited) September 30, 2012 and December 31, 2011	5
	Condensed Consolidated Statements of Cash Flows (Unaudited) Six Months Ended June 30, 2012 and 2011	6
	Condensed Consolidated Statements of Cash Flows (Unaudited) Nine Months Ended September 30, 2012 and 2011	6
	Combined Notes to Condensed Consolidated Financial Statements (Unaudited)	7
ITEM 2.	MANAGEMENT’S NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS AND FINANCIAL CONDITION	42
	Overview	42
	Hedging Activities	42
	Dodd-Frank Act	43
	Capital Expenditures and Capital Resources	4443
	Environmental Matters	44
	Regulatory Matters	4546
	Commodity Prices and Generation Volumes	46
	Capacity Sales	4647
	Results of Operations	47
	Financial Condition	56
	Liquidity and Capital Resources	56
	Historical Cash Flows	59
	Recently Adopted Accounting Guidance	6162
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	6263
ITEM 4.	CONTROLS AND PROCEDURES	6263
	Effectiveness of Disclosure Controls and Procedures	6263
	Changes in Internal Control over Financial Reporting	6263
PART II
OTHER INFORMATION
ITEM 1.	LEGAL PROCEEDINGS	6364
ITEM 1A.	RISK FACTORS	6364
ITEM 6.	EXHIBITS
	GenOn Americas Generation, LLC	6465
	GenOn Mid-Atlantic, LLC	6566

iii

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Glossary of Certain Defined Terms

ancillary services		services that ensure reliability and support the transmission of electricity from generation sites to customer loads. Such services include regulation service, reserves and voltage support.
Bankruptcy Court		United States Bankruptcy Court for the Northern District of Texas, Fort Worth Division.
baseload generating units		units designed to satisfy minimum baseload requirements of the system, ~~and~~ produce electricity at an essentially constant rate and run continuously.
CAIR		Clean Air Interstate Rule.
CAISO		California Independent System Operator.
capacity		amount of energy that could have been generated at continuous full-power operation during the period.
CFTC		U.S. Commodity Futures Trading Commission.
Clean Air Act		Federal Clean Air Act.
Clean Water Act		Federal Water Pollution Control Act.
CO2		carbon dioxide.
CSAPR		Cross-State Air Pollution Rule.
dark spread		the difference between power prices and the cost to generate electricity with coal.
D.C. Circuit		the United States Court of Appeals for the District of Columbia Circuit.
Dodd-Frank Act		the Dodd-Frank Wall Street Reform and Consumer Protection Act.
EPA		United States Environmental Protection Agency.
EPC		engineering, procurement and construction.
Exchange Act		Securities Exchange Act of 1934, as amended.
FASB		Financial Accounting Standards Board.
FERC		Federal Energy Regulatory Commission.
GAAP		United States generally accepted accounting principles.
GenOn		GenOn Energy, Inc. (formerly known as RRI Energy, Inc.) and, except where the context indicates otherwise, its subsidiaries, after giving effect to the Mirant/RRI Merger.
GenOn Americas		GenOn Americas, Inc.
GenOn Americas Generation		GenOn Americas Generation, LLC.
GenOn California North		GenOn California North, LLC.
GenOn Chalk Point		GenOn Chalk Point, LLC.
GenOn credit facilities		senior secured term loan and revolving credit facility of GenOn and certain of its subsidiaries.
GenOn Energy Holdings		GenOn Energy Holdings, Inc. (formerly known as Mirant Corporation) and, except where the context indicates otherwise, its subsidiaries.
GenOn Energy Management		GenOn Energy Management, LLC.
GenOn Energy Services		GenOn Energy Services, LLC.
GenOn Marsh Landing		GenOn Marsh Landing, LLC.

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GenOn Energy Management		GenOn Energy Management, LLC.
GenOn Energy Services		GenOn Energy Services, LLC.
GenOn Marsh Landing		GenOn Marsh Landing, LLC.
GenOn Mid-Atlantic		GenOn Mid-Atlantic, LLC and its subsidiaries, which include the baseload units at two generating facilities under operating leases.
GenOn North America		GenOn North America, LLC.
GenOn Potomac River		GenOn Potomac River, LLC.
intermediate generating units		units designed to satisfy system requirements that are greater than baseload and less than peaking.
ISO		independent system operator.
ISO-NE		Independent System Operator-New England.
LIBOR		London InterBank Offered Rate.
MADEP		Massachusetts’ Department of Environmental Protection.
MDE		Maryland Department of the Environment.
Mirant		GenOn Energy Holdings, Inc. (formerly known as Mirant Corporation) and, except where the context indicates otherwise, its subsidiaries.
Mirant/RRI Merger		the merger completed on December 3, 2010 pursuant to the Mirant/RRI Merger Agreement.
Mirant/RRI Merger Agreement		the agreement by and among Mirant Corporation, RRI Energy, Inc. and RRI Energy Holdings, Inc. dated as of April 11, 2010.
Mirant Debtors		GenOn Energy Holdings, Inc. (formerly known as Mirant Corporation) and certain of its subsidiaries.
MPSC		Maryland Public Service Commission.
MW		megawatt.
MWh		megawatt hour.
NAAQS		National Ambient Air Quality Standards.
net generating capacity		net summer capacity.
NOL		net operating loss.
NOV		notice of violation.
NOx		nitrogen oxides.
NPDES		national pollutant discharge elimination system.
NRG		NRG Energy, Inc.
NRG Merger		the merger contemplated in the NRG Merger Agreement.
NRG Merger Agreement		the agreement by and among NRG Energy, Inc., Plus Merger Corporation and GenOn Energy, Inc. dated as of July 20, 2012.
NYISO		New York Independent System Operator.
NYMEX		New York Mercantile Exchange.
OTC		over-the-counter.
peaking generating units		units designed to satisfy demand requirements during the periods of greatest or peak load on the system.
PEPCO		Potomac Electric Power Company.
PG&E		Pacific Gas & Electric Company.
PJM		PJM Interconnection, LLC.

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PEPCO		Potomac Electric Power Company.
PG&E		Pacific Gas & Electric Company.
PJM		PJM Interconnection, LLC.
Plan		the plan of reorganization that was approved in conjunction with Mirant Corporation’s, GenOn Americas Generation’s and GenOn Mid-Atlantic’s emergence from bankruptcy protection on January 3, 2006.
PPA		power purchase agreement.
retirement		the unit has been removed from service and is unavailable for service and not expected to return to service in the future.
ROC		Risk Oversight Committee.
RRI Energy		RRI Energy, Inc., which changed its name to GenOn Energy, Inc. in connection with the Mirant/RRI Merger.
RTO		regional transmission organization.
scrubbers		flue gas desulfurization emissions controls.
Securities Act		Securities Act of 1933, as amended.
SO2		sulfur dioxide.
spark spread		the difference between power prices and the cost to generate electricity with natural gas.
Stone & Webster		Stone & Webster, Inc.
SWD		surface water discharge.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

In addition to historical information, the information presented in this report includes forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. These statements involve known and unknown risks and uncertainties and relate to our revenues, income, capital structure and other financial items, future events, our future financial performance or our projected business results and our view of economic and market conditions. In some cases, one can identify forward-looking statements by words such as “may,” “will,” “should,” “could,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “expect,” “intend,” “seek,” “plan,” “think,” “anticipate,” “estimate,” “predict,” “target,” “potential” or “continue” or the negative of these terms or comparable words.

Forward-looking statements are only predictions. Actual events or results may differ materially from any forward-looking statement as a result of various factors, which include:

· more stringent (or changes in the application of) environmental laws and regulations (including the cumulative effect of many such regulations) that restrict our ability or render it uneconomic to operate our assets, including regulations related to air emissions, disposal of ash and other byproducts, wastewater discharge and cooling water systems;

· changes in market conditions, including developments in the supply, demand, volume and pricing of electricity and other commodities such as coal and natural gas in the energy markets, including efforts to reduce demand for electricity and to encourage the development of renewable sources of electricity, and the extent and timing of the entry of additional competition in our markets;

· legislative and regulatory initiatives regarding deregulation, regulation or restructuring of the industry of generating, transmitting and distributing electricity (the electricity industry); changes in state, federal and other regulations affecting the electricity industry (including rate and other regulations); changes in tax laws and regulations to which we and our subsidiaries are subject; and changes in, or changes in the application of, other laws and regulations to which we and our subsidiaries and affiliates are or could become subject;

· conflicts between reliability needs and environmental rules, particularly with increasingly stringent environmental restrictions;

· price mitigation strategies employed by ISOs or RTOs that reduce our revenue and may result in a failure to compensate our generating units adequately for all of their costs;

· legal and political challenges to or changes in the rules used to calculate payments for capacity, energy and ancillary services or the establishment of bifurcated markets, incentives or other market design changes that give preferential treatment to new generating facilities over existing generating facilities;

· the failure of our generating facilities to perform as expected, including outages for unscheduled maintenance or repair;

· our failure to use new or advanced power generation technologies;

· strikes, union activity or labor unrest;

· our ability to develop or recruit capable leaders and our ability to retain or replace the services of key employees;

· weather and other natural phenomena, including hurricanes and earthquakes;

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· our failure to provide a safe working environment for our employees and visitors thereby increasing our exposure to additional liability, loss of productive time, other costs and a damaged reputation;

· hazards customary to the power generation industry, including those listed in this cautionary statement and elsewhere in this report, and the possibility that we may not have adequate insurance to cover losses resulting from such hazards or the inability of our insurers to provide agreed upon coverage;

· the ability of GenOn Americas Generation to execute the business plan in northern California, including entering into new arrangements for sales of capacity, energy and other products from its existing generating facilities;

· our relative lack of geographic diversification of revenue sources resulting in concentrated exposure to the PJM market;

· our ability to enter into intermediate and long-term contracts to sell power or to hedge economically our expected future generation of power, and to obtain adequate supplies and deliveries of fuel for our generating facilities, at our required specifications and on terms and prices acceptable to us;

· failure to obtain adequate supplies of fuels, including from curtailments of the transportation of fuels;

· the cost and availability of emissions allowances;

· the curtailment of operations and reduced prices for electricity resulting from transmission constraints;

· terrorist activities, cyberterrorism and inadequate cybersecurity, or the occurrence of a catastrophic loss and the possibility that we may not have adequate insurance to cover losses resulting from such hazards or the inability of our insurers to provide agreed upon coverage;

· deterioration in the financial condition of our counterparties, including financial counterparties, and the failure of such parties to pay amounts owed to us beyond collateral posted or to perform obligations or services due to us;

· poor economic and financial market conditions, including impacts on financial institutions and other current and potential counterparties, and negative impacts on liquidity in the power and fuel markets in which we hedge economically and transact;

· increased credit standards, margin requirements, market volatility or other market conditions that could increase our obligations to post collateral beyond amounts that are expected, including additional collateral costs associated with OTC hedging activities as a result of new or proposed laws, rules and regulations governing derivative financial instruments (such as the Dodd-Frank Act and related pending rulemaking proceedings);

· our inability to access effectively the OTC and exchange-based commodity markets or changes in commodity market conditions and liquidity, including as a result of new or proposed laws, rules and regulations governing derivative financial instruments (such as the Dodd-Frank Act and related pending rulemaking proceedings), which may affect our ability to engage in hedging and, for GenOn Americas Generation, proprietary trading activities as expected, or may result in material losses from open positions;

· volatility in our gross margin as a result of changes in the fair value of our derivative financial instruments used in our hedging and GenOn Americas Generation’s proprietary trading activities and volatility in our cash flow from operations resulting from working capital requirements, including collateral, to support our hedging and GenOn Americas Generation’s proprietary trading activities;

· the disposition of pending or threatened litigation, including environmental litigation;

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· our ability to access contractors and equipment necessary to operate and maintain our generating facilities and to design, engineer, procure and construct capital improvements required or deemed advisable;

· the inability of GenOn Americas Generation’s operating subsidiaries to generate sufficient cash to support their operations;

· the ability of lenders under GenOn’s revolving credit facility to perform their obligations;

· GenOn Americas Generation’s consolidated indebtedness and the possibility that GenOn Americas Generation or its subsidiaries may incur additional indebtedness in the future;

· restrictions on the ability of GenOn Americas Generation’s subsidiaries to pay dividends, make distributions or otherwise transfer funds to GenOn Americas Generation, including restrictions on GenOn Mid-Atlantic contained in its operating lease documents, which may affect GenOn Americas Generation’s ability to access the cash flows of those subsidiaries to make debt service and other payments;

· failure or inability to comply with provisions of GenOn Mid-Atlantic’s leases, GenOn Americas Generation’s affiliates’ loan agreements and debt, which may lead to a breach and, if not remedied, result in an event of default thereunder, which could result in such lessors, lenders and debt holders exercising remedies, limit access to needed liquidity and damage our reputation and relationships with financial institutions;

· covenants contained in our credit facilities, debt and leases that restrict our current and future operations, particularly our ability to respond to changes or take certain actions that may be in our long-term best interests;

· our ability to borrow additional funds and access capital markets; and

· the successful and timely completion of the proposed NRG Merger, which could be materially and adversely affected by, among other things, resolving any litigation brought in connection with the proposed NRG Merger, the timing and terms and conditions of required stockholder, governmental and regulatory approvals, and the ability to maintain relationships with employees, customers or suppliers as well as the ability to integrate the businesses and realize cost savings.

Many of these risks, uncertainties and assumptions are beyond our ability to control or predict. All forward-looking statements contained herein are expressly qualified in their entirety by cautionary statements contained throughout this report. Because of these risks, uncertainties and assumptions, you should not place undue reliance on these forward-looking statements. Furthermore, forward-looking statements speak only as of the date they are made. We undertake no obligation to update publicly or revise any forward-looking statements to reflect events or circumstances that may arise after the date of this report.

In addition to the discussion of certain risks in “Management’s Narrative Analysis of the Results of Operations and Financial Condition” and the accompanying combined notes to GenOn Americas Generation’s and GenOn Mid-Atlantic’s interim financial statements, other factors that could affect our future performance are set forth in our 2011 Annual Report on Form 10-K. Our filings and other important information are also available on our investor relations page at www.genon.com/investors.aspx.

Certain Terms

As used in this report, unless the context requires otherwise, “we,” “us,” “our” and “GenOn Americas Generation” refer to GenOn Americas Generation, LLC and its consolidated subsidiaries and “GenOn Mid-Atlantic” refer to GenOn Mid-Atlantic, LLC and its consolidated subsidiaries.

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PART I

FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

GENON AMERICAS GENERATION, LLC AND SUBSIDIARIES

(Wholly-Owned Indirect Subsidiary of GenOn Energy, Inc.)

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

	Three Months Ended June 30,						Six Months Ended June 30,
	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(in millions)
Operating revenues (including unrealized gains (losses) of $(94), $(12), $44 and $(107), respectively)	$	489		$	715		$	1,171		$	1,253
Operating revenues (including unrealized gains (losses) of $(243), $37, $(199) and $(70), respectively)	$	690		$	929		$	1,861		$	2,182
Operating revenues—affiliate (including unrealized gains (losses) of $26, $(2), $(37) and $8, respectively)	65			2			35			13
Operating revenues—affiliate (including unrealized gains (losses) of $76, $(27), $39 and $(19), respectively)	158			(16		)	193			(3		)
Total operating revenues	~~554~~848			~~717~~913			12,~~206~~054			12,~~266~~179
Cost of fuel, electricity and other products (including unrealized (gains) losses of $39, $(15), $74 and $(29), respectively)	224			138			407			303
Cost of fuel, electricity and other products (including unrealized (gains) losses of $(55), $11, $19 and $(18), respectively)	231			210			638			513
Cost of fuel, electricity and other products—affiliate (including unrealized (gains) losses of $0, $0, $(9) and $0, respectively)	229			330			453			500
Cost of fuel, electricity and other products—affiliate (including unrealized (gains) losses of $5, $(1), $(4) and $(1), respectively)	491			494			944			994
Total cost of fuel, electricity and other products	~~453~~722			~~468~~704			~~860~~1,582			~~803~~1,507
Gross Margin (excluding depreciation and amortization)	~~101~~126			~~249~~209			~~346~~472			~~463~~672
Operating Expenses:
Operations and maintenance	5971			~~118~~73			~~141~~212			~~197~~270
Operations and maintenance—affiliate	6157			5953			~~119~~176			~~119~~172
Depreciation and amortization	41			42			81122			82124
Gain on sales of assets, net	(1		)	—			(1		)	—
Impairment losses	—			128			—			128
Loss on sales of assets, net—affiliate	—			1			—			1
Gain on sales of assets, net	—			(6		)	(1		)	(5		)
Total operating expenses	160			220			340			399
Loss on sales of assets, net—affiliate	—			2			—			2
Operating Income (Loss)	(59		)	29			6			64
Total operating expenses	169			292			509			691
Operating Loss	(43		)	(83		)	(37		)	(19		)
Other Income (Expense), net:
Interest expense	(18		)	(2119		)	(3654		)	(5170		)
Interest expense—affiliate	(21		)	—(4		)	(34		)	—(4		)
Other, net	—			—			—			(23		)
Total other expense, net	(2019		)	(2123		)	(3958		)	(7497		)
Net Income (Loss)	$	(79	)	$	8		$	(33	)	$	(10	)
Net Loss	$	(62	)	$	(106	)	$	(95	)	$	(116	)

The accompanying combined notes are an integral part of these unaudited condensed consolidated financial statements

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GENON AMERICAS GENERATION, LLC AND SUBSIDIARIES
(Wholly-Owned Indirect Subsidiary of GenOn Energy, Inc.)

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	June 30, 2012			December 31, 2011
	September 30, 2012			December 31, 2011
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents	$	~~443~~335		$	267
Funds on deposit	~~146~~142			316
Receivables, net	~~301~~255			288
Receivables, net—affiliate	2924			22
Notes receivable—affiliate	~~168~~187			181
Derivative contract assets	~~879~~632			977
Derivative contract assets—affiliate	7564			44
Inventories	~~253~~234			257
Prepaid rent and other expenses	~~104~~119			113
Total current assets	21,~~398~~992			2,465
Property, plant and equipment, gross	3,~~949~~958			3,894
Accumulated depreciation and amortization	(1,~~027~~062		)	(960		)
Property, Plant and Equipment, net	2,~~922~~896			2,934
Noncurrent Assets:
Intangible assets, net	2726			28
Derivative contract assets	~~741~~588			731
Derivative contract assets—affiliate	4044			29
Prepaid rent	~~436~~412			386
Other	2821			16
Total noncurrent assets	1,~~272~~091			1,190
Total Assets	$	65,~~592~~979		$	6,589
LIABILITIES AND MEMBER’S EQUITY
Current Liabilities:
Current portion of long-term debt	$	5		$	4
Accounts payable and accrued liabilities	~~579~~400			509
Payables, net—affiliate	~~142~~137			93
Notes payable—affiliate	7988			47
Derivative contract liabilities	~~590~~379			700
Derivative contract liabilities—affiliate	~~142~~95			76
Other	1422			25
Total current liabilities	1,~~551~~126			1,454
Noncurrent Liabilities:
Long-term debt, net of current portion	~~859~~858			862
Derivative contract liabilities	~~150~~141			100
Derivative contract liabilities—affiliate	9568			89
Other	~~105~~106			119
Total noncurrent liabilities	1,~~209~~173			1,170
Commitments and Contingencies
Member’s Equity:
Member’s interest	3,~~832~~680			3,965
Total member’s equity	3,~~832~~680			3,965
Total Liabilities and Member’s Equity	$	65,~~592~~979		$	6,589

The accompanying combined notes are an integral part of these unaudited condensed consolidated financial statements

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GENON AMERICAS GENERATION, LLC AND SUBSIDIARIES
(Wholly-Owned Indirect Subsidiary of GenOn Energy, Inc.)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Six Months Ended June 30,
	Nine Months Ended September 30,
	2012			2011
	(in millions)
Cash Flows from Operating Activities:
Net loss	$	(3395	)	$	(10116	)
Adjustments to reconcile net loss and changes in operating assets and liabilities to net cash provided by operating activities:
Depreciation and amortization	81122			82124
(Gain) loss on sales of assets, net	(1		)	1
Impairment losses	—			128
Unrealized losses	58			70
Gain on sales of assets, net	(1		)	(3		)
Unrealized losses	175			70
Excess materials and supplies inventory reserve	6			—
Lower of cost or market inventory adjustments	3445			1
Loss on early extinguishment of debt	—			23
Reversal of Potomac River settlement obligation	(31		)	—
Large scale remediation and settlement costs	(3		)	30
Changes in operating assets and liabilities	107			68
Other, net	—			(2		)
Total adjustments	251			275
Changes in operating assets and liabilities	16			12
Net cash provided by operating activities	218			265
Total adjustments	329			383
Net cash provided by operating activities	234			267
Cash Flows from Investing Activities:
Capital expenditures	(~~151~~175		)	(47130		)
Proceeds from the sales of assets	—1			49
Restricted funds on deposit, net	166			~~723~~700
Issuance of notes receivable—affiliate	13(6		)	(~~147~~164		)
Net cash provided by investing activities	28			533
Net cash provided by (used in) investing activities	(14		)	415
Cash Flows from Financing Activities:
Repayment of long-term debt	(23		)	(1,~~403~~404		)
Issuance of notes payable—affiliate	3241			2634
Capital contributions	—			~~444~~474
Distributions to member	(~~100~~190		)	(100		)
Net cash used in financing activities	(70152		)	(~~1,033~~996		)
Net Increase (Decrease) in Cash and Cash Equivalents	~~176~~68			(~~235~~314		)
Cash and Cash Equivalents, beginning of period	267			514
Cash and Cash Equivalents, end of period	$	~~443~~335		$	~~279~~200
Supplemental Disclosures:
Cash paid for interest, net of amounts capitalized	$	35		$	59
Cash refunds received for income taxes	$	—		$	1
Supplemental Disclosure for Non-Cash Financing Activities:
Conversion to equity of notes payable to affiliate	$	—		$	2

The accompanying combined notes are an integral part of these unaudited condensed consolidated financial statements

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GENON MID-ATLANTIC, LLC AND SUBSIDIARIES
(Wholly-Owned Indirect Subsidiary of GenOn Energy, Inc.)

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

	Three Months Ended June 30,						Six Months Ended June 30,
	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(in millions)
Operating revenues (including unrealized gains (losses) of $(63), $6, $(7) and $(39), respectively)	$	8		$	45		$	135		$	44
Operating revenues (including unrealized gains (losses) of $(88), $(3), $(95) and $(42), respectively)	$	(27	)	$	41		$	108		$	85
Operating revenues—affiliate (including unrealized gains (losses) of $(3), $(33), $8 and $(39), respectively)	200			235			393			534
Operating revenues—affiliate (including unrealized gains (losses) of $(49), $0, $(41) and $(39), respectively)	228			287			621			821
Total operating revenues	~~208~~201			~~280~~328			~~528~~729			~~578~~906
Cost of fuel, electricity and other products (including unrealized (gains) losses of $0)	32			24			68			913
Cost of fuel, electricity and other products—affiliate (including unrealized (gains) losses of $47, $(15), $72 and $(27), respectively)	150			111			262			240
Cost of fuel, electricity and other products—affiliate (including unrealized (gains) losses of $(46), $9, $26 and $(18), respectively)	101			170			363			410
Total cost of fuel, electricity and other products	~~153~~103			~~113~~174			~~268~~371			~~249~~423
Gross Margin (excluding depreciation and amortization)	5598			~~167~~154			~~260~~358			~~329~~483
Operating Expenses:
Operations and maintenance	3954			~~101~~53			~~102~~156			~~163~~216
Operations and maintenance—affiliate	4342			4243			83125			82125
Depreciation and amortization	30			30			5989			5989
Gain on sales of assets, net	(1		)	—			(1		)	—
Impairment losses	—			94			—			94
Total operating expenses	111			173			243			304
Gain on sales of assets, net	—			—			(1		)	—
Operating Income (Loss)	(56		)	(6		)	17			25
Total operating expenses	126			220			369			524
Operating Loss	(28		)	(66		)	(11		)	(41		)
Other Expense, net:
Interest expense	(1—		)	(1—		)	(1		)	(1		)
Interest expense—affiliate	(1		)	—(3		)	(23		)	—(3		)
Total other expense, net	(21		)	(13		)	(34		)	(14		)
Net Income (Loss)	$	(58	)	$	(7	)	$	14		$	24
Net Loss	$	(29	)	$	(69	)	$	(15	)	$	(45	)

The accompanying combined notes are an integral part of these unaudited condensed consolidated financial statements

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GENON MID-ATLANTIC, LLC AND SUBSIDIARIES (Wholly-Owned Indirect Subsidiary of GenOn Energy, Inc.)

(Wholly-Owned Indirect Subsidiary of GenOn Energy, Inc.)

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	June 30, 2012			December 31, 2011
	September 30, 2012			December 31, 2011
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents	$	~~200~~171		$	68
Funds on deposit	32			198
Receivables, net	2321			25
Receivables, net—affiliate	5939			44
Derivative contract assets	~~245~~248			208
Derivative contract assets—affiliate	~~139~~96			191
Inventories	~~149~~135			167
Prepaid rent and other expenses	98105			100
Total current assets	~~945~~847			1,001
Property, plant and equipment, gross	3,~~104~~109			3,054
Accumulated depreciation and amortization	(~~667~~694		)	(610		)
Property, Plant and Equipment, net	2,~~437~~415			2,444
Noncurrent Assets:
Intangible assets, net	16			16
Derivative contract assets	~~484~~403			526
Derivative contract assets—affiliate	~~138~~101			105
Prepaid rent	~~436~~412			386
Other	2			—
Total noncurrent assets	~~1,076~~934			1,033
Total Assets	$	4,~~458~~196		$	4,478
LIABILITIES AND MEMBER’S EQUITY
Current Liabilities:
Current portion of long-term debt	$	5		$	4
Accounts payable and accrued liabilities	~~195~~124			151
Payables, net—affiliate	4031			44
Derivative contract liabilities—affiliate	188			168
Derivative contract liabilities	7			—
Other	14			24
Derivative contract liabilities—affiliate	126			168
Total current liabilities	442			391
Other	22			24
Total current liabilities	315			391
Noncurrent Liabilities:
Long-term debt, net of current portion	1110			14
Derivative contract liabilities	24			—
Derivative contract liabilities—affiliate	9578			68
Other	67			78
Total noncurrent liabilities	~~175~~159			160
Commitments and Contingencies
Member’s Equity:
Member’s interest	3,~~841~~722			3,927
Total member’s equity	3,~~841~~722			3,927
Total Liabilities and Member’s Equity	$	4,~~458~~196		$	4,478

The accompanying combined notes are an integral part of these unaudited condensed consolidated financial statements

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GENON MID-ATLANTIC, LLC AND SUBSIDIARIES (Wholly-Owned Indirect Subsidiary of GenOn Energy, Inc.)

(Wholly-Owned Indirect Subsidiary of GenOn Energy, Inc.)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Six Months Ended June 30,
	Nine Months Ended September 30,
	2012			2011
	(in millions)
Cash Flows from Operating Activities:
Net income	$	14		$	24
Net loss	$	(15	)	$	(45	)
Adjustments to reconcile net income and changes in operating assets and liabilities to net cash provided by operating activities:
Adjustments to reconcile net loss and changes in operating assets and liabilities to net cash provided by operating activities:
Depreciation and amortization	5989			5989
Impairment losses	—			94
Gain on sales of assets, net	(1		)	—
Unrealized losses	71162			5163
Excess materials and supplies inventory reserve	4			—
Lower of cost or market inventory adjustments	3445			—1
Reversal of Potomac River settlement obligation	(31		)	—
Large scale remediation and settlement costs	(3		)	30
Changes in operating assets and liabilities	5531			~~(25~~14		)
Total adjustments	~~188~~296			~~115~~291
Net cash provided by operating activities	~~202~~281			~~139~~246
Cash Flows from Investing Activities:
Capital expenditures	(~~134~~151		)	(43126		)
Restricted funds on deposit, net	166			(143		)
Proceeds from the sales of assets	—			1
Net cash provided by (used in) investing activities	32			(186		)
Restricted funds on deposit, net	166			(166		)
Net cash provided by (used in) investing activities	15			(291		)
Cash Flows from Financing Activities:
Repayment of long-term debt	(23		)	(23		)
Distributions to member	(~~100~~190		)	(100		)
Net cash used in financing activities	(102		)	(102		)
Capital contributions	—			30
Net Increase (Decrease) in Cash and Cash Equivalents	132			(149		)
Net cash used in financing activities	(193		)	(73		)
Net Increase (Decrease) in Cash and Cash Equivalents	103			(118		)
Cash and Cash Equivalents, beginning of period	68			202
Cash and Cash Equivalents, end of period	$	~~200~~171		$	5384
Supplemental Disclosures:
Cash refunds received for income taxes	$	—		$	1

The accompanying combined notes are an integral part of these unaudited condensed consolidated financial statements

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GENON AMERICAS GENERATION, LLC AND SUBSIDIARIES GENON MID-ATLANTIC, LLC AND SUBSIDIARIES

GENON MID-ATLANTIC, LLC AND SUBSIDIARIES

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1. Description of Business and Accounting and Reporting Policies

Background

GenOn Americas Generation is a wholesale generator with ~~approximately~~ 9,~~729~~247 MW of net electric generating capacity located, in many cases, near major metropolitan load centers in the Eastern PJM and Northeast regions and northern California. GenOn Americas Generation also operates integrated asset management and proprietary trading operations. See note 2 for a discussion of ~~two~~one generating ~~facilities~~facility that we retired in 2012 and one that we expect to retire in ~~2012 and~~ 2013.

GenOn Mid Atlantic operates and owns or leases 54,~~209~~727 MW of net electric generating capacity in the Washington, D.C. area. GenOn Mid-Atlantic’s electric generating capacity is part of the 9,~~729~~247 MW of net electric generating capacity of GenOn Americas Generation. GenOn Mid-Atlantic’s generating facilities serve the Eastern PJM markets. The PJM ISO operates the largest centrally dispatched control area in the United States.

We are Delaware limited liability companies and indirect wholly-owned subsidiaries of GenOn. GenOn Mid-Atlantic is a wholly-owned subsidiary of GenOn North America and an indirect wholly-owned subsidiary of GenOn Americas Generation.

On July 20, 2012, GenOn entered into the NRG Merger Agreement with NRG Energy, Inc. and a direct wholly-owned subsidiary of NRG. See note 9.

We have a number of service arrangements for labor and administrative services with GenOn Energy Services. GenOn Energy Management provides services to certain operating subsidiaries of GenOn Americas, outside of GenOn Americas Generation, which include the bidding and dispatch of the generating units, fuel procurement and the execution of contracts, including economic hedges, to reduce price risk. See note 5.

Proposed Merger with NRG

On July 20, 2012, GenOn entered into the NRG Merger Agreement with NRG Energy, Inc. and a direct wholly-owned subsidiary of NRG. Upon the terms and subject to the conditions set forth in the NRG Merger Agreement, which has been approved by the boards of directors of GenOn and NRG, a wholly-owned subsidiary of NRG will merge with and into GenOn, with GenOn continuing as the surviving corporation and a wholly owned subsidiary of NRG.

The NRG Merger is intended to qualify as a tax-free reorganization under the IRC, as amended, so that none of GenOn, NRG or any of GenOn’s stockholders generally will recognize any gain or loss in the transaction, except with respect to cash received in lieu of fractional shares of NRG common stock.

Completion of the NRG Merger is contingent upon, among other things, (a) approvals by NRG stockholders of the issuance of NRG common stock in the NRG Merger and the approval and adoption of the amendment to NRG’s certificate of incorporation to allow the size of NRG’s board of directors to be increased to 16 in connection with the closing of the NRG Merger, at a meeting to be held on November 9, 2012, (b) adoption of the NRG Merger Agreement by GenOn’s stockholders, at a meeting to be held on November 9, 2012, (c) effectiveness of an NRG registration statement on Form S-4, which occurred on October 5, 2012, and approval of the New York Stock Exchange listing for the NRG common stock to be issued in the NRG Merger, (d) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, which occurred on September 21, 2012 and (e) receipt of all required regulatory approvals, including approvals from the Public Utility Commission of Texas, which occurred on October 25, 2012, the FERC and the New York Public Service Commission.

GenOn and NRG are also subject to restrictions on their respective ability to solicit alternative acquisition proposals and to provide information to, and engage in discussion with, third parties, except under limited circumstances to permit GenOn’s or NRG’s board of directors to comply with their respective fiduciary duties. The

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NRG Merger Agreement contains termination rights for both GenOn and NRG and further provides that, upon termination of the NRG Merger Agreement under specified circumstances, NRG may be required to pay a termination fee of $120 million to GenOn and GenOn may be required to pay NRG a termination fee of $60 million.

We anticipate completing the NRG Merger by the first quarter of 2013. Prior to the completion of the NRG Merger, we and NRG will continue to operate as independent companies. Except for specific references to the pending NRG Merger, the disclosures contained in this report on Form 10-Q relate solely to us. Information concerning the proposed NRG Merger is included in a joint proxy statement/prospectus contained in the registration statement on Form S-4, which NRG filed with the Securities and Exchange Commission in connection with the NRG Merger on October 5, 2012.

Basis of Presentation

The consolidated interim financial statements and notes (interim financial statements) are unaudited, omit certain disclosures and should be read in conjunction with our audited consolidated financial statements and notes in our 2011 Annual Report on Form 10-K. These interim financial statements have been prepared in accordance with GAAP from records maintained by us. All significant intercompany accounts and transactions have been eliminated in consolidation. The interim financial statements reflect all normal recurring adjustments necessary, in management’s opinion, to present fairly our financial position and results of operations for the reported periods. Amounts reported for interim periods may not be indicative of a full year period because of seasonal fluctuations in demand for electricity and energy services, changes in commodity prices, and changes in regulations, timing of maintenance and other expenditures, dispositions, changes in interest expense and other factors. Certain prior period amounts have been reclassified to conform to the current period financial statement presentation.

At ~~June~~September 30, 2012 and December 31, 2011, substantially all of our subsidiaries are wholly-owned and located in the United States. We do not consolidate two power generating facilities, which are under operating leases.

The preparation of interim financial statements in conformity with GAAP requires management to make various estimates and assumptions that affect the reported amounts of assets and liabilities, disclosures of contingent assets and liabilities at the date of the interim financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from those estimates. Our significant estimates include:

· estimating the fair value of certain derivative contracts;

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· estimating the inventory reserve;

· estimating the useful lives of long-lived assets;

· estimating future costs and the valuation of asset retirement obligations;

· estimating future cash flows in determining impairments of long-lived assets and definite-lived intangible assets; and

· estimating losses to be recorded for contingent liabilities.

We evaluate events that occur after the balance sheet date but before the financial statements are issued for potential recognition or disclosure. Based on the evaluation, we determined that there were no material subsequent events for recognition or disclosure other than those disclosed herein.

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Funds on Deposit

Funds on deposit are included in current and noncurrent assets in the consolidated balance sheets. Funds on deposit include the following:

GenOn Americas Generation

	June 30, 2012		December 31, 2011
	September 30, 2012		December 31, 2011
	(in millions)
Cash collateral posted — energy trading and marketing	$	91	$	118
Cash collateral posted – energy trading and marketing	$	90	$	118
Cash collateral posted — other operating activities(1)	62		38
Cash collateral posted – other operating activities(1)	59		38
GenOn Mid-Atlantic restricted cash(2)	—		166
Total current and noncurrent funds on deposit	~~153~~149		322
Less: Current funds on deposit	~~146~~142		316
Total noncurrent funds on deposit	$	7	$	6

(1) Includes $32 million related to the Potomac River obligation under the 2008 agreement with the City of Alexandria, which were returned to us in October 2012. See note 2.

(2) Represents cash reserved in respect of interlocutory liens related to the scrubber contract litigation, which was settled in June 2012. See note 8.

GenOn Mid-Atlantic

	June 30, 2012		December 31, 2011
	September 30, 2012		December 31, 2011
	(in millions)
Cash collateral posted(1)	$	32	$	32
GenOn Mid-Atlantic restricted cash(2)	—		166
Total current and noncurrent funds on deposit	32		198
Less: Current funds on deposit	32		198
Total noncurrent funds on deposit	$	—	$	—

(1) Represents amount related to the Potomac River obligation under the 2008 agreement with the City of Alexandria, which were returned to us in October 2012. See note 2.

(2) Represents cash reserved in respect of interlocutory liens related to the scrubber contract litigation, which was settled in June 2012. See note 8.

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Inventories

Inventories were comprised of the following:

GenOn Americas Generation

	June 30, 2012		December 31, 2011
	September 30, 2012		December 31, 2011
	(in millions)
Fuel inventory:
Coal	$	8367	$	92
Fuel oil	5761		68
Natural gas	—		1
Other	1		3
Materials and supplies(1)	6970		74
Purchased emissions allowances	4335		19
Total inventories	$	~~253~~234	$	257

(1) Amount is net of an inventory reserve of $6 million and $0 at ~~June~~September 30, 2012 and December 31, 2011, respectively. See note 2.

GenOn Mid-Atlantic

	June 30, 2012		December 31, 2011
	September 30, 2012		December 31, 2011
	(in millions)
Fuel inventory:
Coal	$	8367	$	92
Fuel oil	1718		20
Other	1		3
Materials and supplies(1)	4849		52
Total inventories	$	~~149~~135	$	167

(1) Amount is net of an inventory reserve of $4 million and $0 at ~~June~~September 30, 2012 and December 31, 2011, respectively. See note 2.

During the three months ended ~~June~~September 30, 2012 and 2011, GenOn Americas Generation recorded $911 million and $~~1 million~~0, respectively, and during the ~~six~~nine months ended ~~June~~September 30, 2012 and 2011, GenOn Americas Generation recorded $3445 million and $1 million, respectively, for lower of average cost or market valuation adjustments in cost of fuel, electricity and other products.

During the three months ended ~~June~~September 30, 2012 and 2011, GenOn Mid-Atlantic recorded $911 million and $0, respectively, and during the ~~six~~nine months ended ~~June~~September 30, 2012 and 2011, GenOn Mid-Atlantic recorded $3445 million and $01 million, respectively, for lower of average cost or market valuation adjustments in cost of fuel, electricity and other products.

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Capitalization of Interest Cost (GenOn Americas Generation)

GenOn Americas Generation incurred the following interest costs:

	Three Months Ended June 30,						Six Months Ended June 30,
	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(in millions)
Total interest costs	$	19		$	2120		$	3857		$	5272
Capitalized and included in property, plant and equipment, net	(1		)	—(1		)	(23		)	(12		)
Interest expense	$	18		$	2119		$	3654		$	5170

The amounts of capitalized interest above include interest accrued. During the three months ended September 30, 2012 and ~~six~~2011, no cash was paid for interest. During the nine months ended ~~June~~September 30, 2012 and 2011, cash paid for interest was $37 million and $60 million, respectively, of which $2 million and $1 million, respectively were capitalized.

Guarantees and Indemnifications (GenOn Americas Generation)

GenOn generally conducts its business through various holding companies, including GenOn Americas Generation, and various operating subsidiaries, which enter into contracts as part of their business activities. In certain instances, the contractual obligations of such subsidiaries are guaranteed by, or otherwise supported by, GenOn or another of its subsidiaries, including by letters of credit issued under the GenOn credit facilities. At ~~June~~September 30, 2012, $~~186~~134 million of letters of credit was posted by GenOn for the benefit of GenOn Americas Generation.

In addition, GenOn Americas Generation and its subsidiaries enter into various contracts that include indemnification and guarantee provisions. Examples of these contracts include financing and lease arrangements, purchase and sale agreements, agreements to purchase or sell commodities, construction agreements and agreements with vendors. Although the primary obligation of GenOn Americas Generation or a subsidiary under such contracts is to pay money or render performance, such contracts may include obligations to indemnify the counterparty for damages arising from the breach thereof and, in certain instances, other existing or potential liabilities. In many cases GenOn Americas Generation’s maximum potential liability cannot be estimated because some of the underlying agreements contain no limits on potential liability.

Recently Adopted Accounting Guidance

Fair Value Measurement and Disclosure. We adopted FASB accounting guidance for the first quarter ~~ended~~of ~~March 31,~~ 2012 that requires disclosure of the following:

· quantitative information about the unobservable inputs used in a fair value measurement that is categorized within Level 3 of the fair value hierarchy;

· for those fair value measurements categorized within Level 3 of the fair value hierarchy, both the valuation processes used and the sensitivity of the fair value measurement to changes in unobservable inputs and the interrelationships between those unobservable inputs, if any; and

· the categorization by level of the fair value hierarchy for items that are not measured at fair value in the statement of financial position but for which the fair value is required to be disclosed.

See note 3 for these additional disclosures.

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New Accounting Guidance Not Yet Adopted at ~~June~~September 30, 2012

Balance Sheet Offsetting. In December 2011, the FASB issued updated guidance to provide enhanced disclosures such that users of the financial statements will be able to better evaluate the effect or potential effect of netting arrangements in the balance sheet. The guidance requires improved information about financial instruments and derivative instruments that are either offset according to specific guidance or subject to an enforceable master netting agreement or similar arrangement. The disclosures will provide both net and gross information for these assets and liabilities. Although we do not currently elect to offset assets and liabilities within the scope of the guidance, expanded disclosures will be required starting for the first quarter ~~ended~~of ~~March 31,~~ 2013, along with retrospective presentation of prior periods.

2. ~~Expected~~ Retirements of Generating Facilities

Potomac River Generating Facility

During 2011, GenOn Mid-Atlantic entered into an agreement with the City of Alexandria, Virginia to remove permanently from service the 482 MW Potomac River generating facility. The agreement, which amends our Project Schedule and Agreement, dated July 2008 with the City of Alexandria, provides for the retirement of the Potomac River generating facility on October 1, 2012, subject to the determination of PJM that the retirement of the facility will not affect reliability and the consent of PEPCO. PJM made the necessary determination and in June 2012 PEPCO gave its consent. As a result, the Potomac River generating facility ~~will~~was be retired onin October 1, 2012. Upon retirement of the Potomac River generating facility, all funds in the escrow account ($32 million) established under the July 2008 agreement ~~will~~were be distributed to us, ~~provided,~~in ~~that, if the retirement of the facility occurs after January~~October ~~1, 2014, $750,000 of such funds will be paid to the City of Alexandria~~2012. We therefore reversed $31 million and $1 million of the previously recorded obligation under the 2008 agreement with the City of Alexandria as a reduction in operations and maintenance expense during the ~~three~~second ~~months~~and ~~ended~~fourth ~~June~~quarters ~~30,~~of 2012, respectively.

Contra Costa Generating Facility

A subsidiary of GenOn Americas Generation entered into an agreement with PG&E in September 2009 for 674 MW at Contra Costa for the period from November 2011 through April 2013. At the end of the agreement, and subject to any necessary regulatory approvals, we have agreed to retire the Contra Costa facility.

Expenses, Property, Plant and Equipment, and Materials and Supplies Inventory Related to Retirements

In connection with our decision to retire the generating facilities, we evaluated our materials and supplies inventory and determined that we have excess inventory. GenOn Americas Generation and GenOn Mid-Atlantic established a reserve of $6 million and $4 million, respectively, recorded to operations and maintenance expense during the ~~three~~first ~~months~~quarter ~~ended~~of ~~March 31,~~ 2012 relating to excess inventory. We will continue to monitor the inventory balances and could ~~have~~make changes to the reserve in the future. At ~~June~~ September 30, 2012, the aggregate carrying value of property, plant and equipment, net and materials and supplies inventory, net for the ~~generating~~Potomac ~~facilities~~River toand beContra ~~retired~~Costa generating facilities was $54 million and $1 million, respectively, for GenOn Americas Generation and $0 and $1 million, respectively, for GenOn Mid-Atlantic. In addition to the excess materials and supplies inventory reserve recorded in the first quarter, GenOn Americas Generation and GenOn Mid-Atlantic incurred $4 million during the three months ended September 30, 2012 for costs to retire the Potomac River and Contra Costa generating facilities, which is included in operations and maintenance expense. We expect to incur ~~other~~additional costs in the future in connection with the ~~retirements~~deactivations, such as severance and other plant shutdown costs.

If market conditions and/or environmental and regulatory factors or assumptions change in the future, forecasted returns on investments necessary to comply with environmental regulations could change resulting in possible incremental investments if returns improve or deactivation of additional generating units or facilities if returns deteriorate. Such deactivations could result in additional charges, including impairments, severance costs and other plant shutdown costs.

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3. Financial Instruments

Derivatives and Hedging Activities

In connection with the business of generating electricity, we are exposed to energy commodity price risk associated with the acquisition of fuel and emissions allowances needed to generate electricity, the price of electricity produced and sold, and the fair value of fuel inventories. Through our asset management activities, we enter into a variety of exchange-traded and OTC energy and energy-related derivative financial instruments, such as forward contracts, futures contracts, option contracts and financial swap agreements to manage exposure to commodity price risks. These contracts have varying terms and durations, which range from a few days to years, depending on the instrument. GenOn Americas Generation’s proprietary trading activities also utilize similar derivative contracts in markets where it has a physical presence to attempt to generate incremental gross margin. GenOn Americas Generation’s fuel oil management activities use derivative financial instruments to hedge economically the fair value of physical fuel oil inventories, optimize the approximately two million barrels of storage capacity that it owns, and attempt to profit from market opportunities related to timing and/or differences in the pricing of various products. The open positions in GenOn Americas Generation’s trading activities comprising proprietary trading and fuel oil management activities expose it to risks associated with changes in energy commodity prices.

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depending on the instrument. GenOn Americas Generation’s proprietary trading activities also utilize similar derivative contracts in markets where it has a physical presence to attempt to generate incremental gross margin. GenOn Americas Generation’s fuel oil management activities use derivative financial instruments to hedge economically the fair value of physical fuel oil inventories, optimize the approximately two million barrels of storage capacity that it owns, and attempt to profit from market opportunities related to timing and/or differences in the pricing of various products. The open positions in GenOn Americas Generation’s trading activities comprising proprietary trading and fuel oil management activities expose it to risks associated with changes in energy commodity prices.

Derivative financial instruments are recorded in the consolidated balance sheets at fair value, except for derivative contracts that qualify for and for which we have elected the normal purchase or normal sale exceptions, which are not reflected in the consolidated balance sheet or results of operations prior to accrual of the settlement. We present our derivative contract assets and liabilities on a gross basis (regardless of master netting arrangements with the same counterparty). Cash collateral amounts are also presented on a gross basis.

During the second quarter of 2012, we could no longer assert that physical delivery was probable for the remaining coal agreements for which we had elected the normal purchase exception. As such, the normal purchase exception was removed, and we ~~recorded~~are ~~the~~required to apply fair value ofaccounting to these contracts onin the ~~balance~~current ~~sheet~~period ~~at June 30, 2012 as a net derivative liability of $45 million~~ and ~~immediately recognized that amount in earnings as unrealized losses in cost of fuel, electricity and other products~~prospectively.

If certain criteria are met, a derivative financial instrument may be designated as a fair value hedge or cash flow hedge. We did not have any derivative financial instruments designated as fair value or cash flow hedges for accounting purposes during the ~~six~~nine months ended ~~June~~September 30, 2012 or 2011.

For our derivative financial instruments, changes in such instruments’ fair values are recognized currently in earnings. Our derivative financial instruments are categorized based on the business objective the instrument is expected to achieve: asset management or trading, which includes GenOn Americas Generation’s proprietary trading and fuel oil management. For asset management activities, changes in fair value and settlement of derivative financial instruments used to hedge electricity economically are reflected in operating revenue and changes in fair value and settlement of derivative financial instruments used to hedge fuel economically are reflected in cost of fuel, electricity and other products in the consolidated statements of operations. Changes in the fair value and settlements of derivative financial instruments for GenOn Americas Generation’s proprietary trading and fuel oil management activities are recorded on a net basis as operating revenue in the consolidated statements of operations.

We also consider risks associated with interest rates, counterparty credit and our own non-performance risk when valuing derivative financial instruments. The nominal value of the derivative contract assets and liabilities is discounted to account for time value using a LIBOR forward interest rate curve based on the tenor of the transactions being valued.

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GenOn Americas Generation

The following table presents the fair value of GenOn Americas Generation’s derivative financial instruments (including amounts with affiliates):

											Net Derivative
	Derivative Contract Assets				Derivative Contract Liabilities						Contract
	Current		Long-Term		Current			Long-Term			Assets (Liabilities)
	(in millions)
June 30, 2012
September 30, 2012
Commodity Contracts:
Asset management	$	~~645~~522	$	~~772~~623	$	(~~426~~304	)	$	(~~236~~197	)	$	~~755~~644
Trading activities	~~309~~174		9		(~~306~~170		)	(912		)	31
Total derivatives	$	~~954~~696	$	~~781~~632	$	(~~732~~474	)	$	(~~245~~209	)	$	~~758~~645
December 31, 2011
Commodity Contracts:
Asset management	$	562	$	757	$	(314	)	$	(186	)	$	819
Trading activities	459		3		(462		)	(3		)	(3		)
Total derivatives	$	1,021	$	760	$	(776	)	$	(189	)	$	816

The following table presents the net gains (losses) for derivative financial instruments (including amounts with affiliates) recognized in income in the consolidated statements of operations:

	Three Months Ended June 30,
	Three Months Ended September 30,
	2012						2011
Derivatives Not Designated as Hedging Instruments	Operating Revenues			Cost of Fuel, Electricity and Other Products			Operating Revenues			Cost of Fuel, Electricity and Other Products
	(in millions)
Asset Management Commodity Contracts:
Unrealized	$	(79164	)	$	~~(39~~50	)	$	(251	)	$	15(10	)
Realized(1)(2)	~~113~~82			(1213		)	6357			(1315		)
Total asset management	$	34(82	)	$	~~(51~~37	)	$	3856		$	2(25	)
Trading Commodity Contracts:
Unrealized	$	11(3	)	$	—		$	11		$	—
Realized(1)(2)	—8			—			(113		)	—
Total trading	$	115		$	—		$	10(2	)	$	—
Total derivatives	$	45(77	)	$	~~(51~~37	)	$	4854		$	2(25	)

13(1) Represents the total cash settlements of derivative financial instruments during each reporting period (composed of the sum of the quarterly settlements) that existed at the beginning of each respective period.

(2) Excludes settlement value of fuel contracts classified as inventory.

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	Six Months Ended June 30,
	Nine Months Ended September 30,
	2012						2011
Derivatives Not Designated as Hedging Instruments	Operating Revenues			Cost of Fuel, Electricity and Other Products			Operating Revenues			Cost of Fuel, Electricity and Other Products
	(in millions)
Asset Management Commodity Contracts:
Unrealized	$	3(161	)	$	(6515	)	$	(8788	)	$	2919
Realized(1)(2)	~~256~~338			(2841		)	~~131~~188			(2439		)
Total asset management	$	~~259~~177		$	(9356	)	$	44100		$	5(20	)
Trading Commodity Contracts:
Unrealized	$	41		$	—		$	(121	)	$	—
Realized(1)(2)	(53		)	—			5(8		)	—
Total trading	$	(14	)	$	—		$	(79	)	$	—
Total derivatives	$	~~258~~181		$	(9356	)	$	3791		$	5(20	)

(1) Represents the total cash settlements of derivative financial instruments during each reporting period (composed of the sum of the quarterly settlements) that existed at the beginning of each respective period.

(2) Excludes settlement value of fuel contracts classified as inventory.

The following tables present the notional quantity on long (short) positions for derivative financial instruments:

	Notional Volumes at June 30, 2012
	Notional Volumes at September 30, 2012
Derivative Instruments	Derivative Contract Assets		Derivative Contract Liabilities		Net Derivative Contracts
	(in millions)
Commodity Contracts (in equivalent MWh):
Power(1)	(691	)	32(38	)	(3739	)
Natural gas	(21	)	3(1	)	1—
Coal	(1	)	1715		1614

(1) Includes MWh equivalent of natural gas transactions used to hedge power economically.

	Notional Volumes at December 31, 2011
Derivative Instruments	Derivative Contract Assets		Derivative Contract Liabilities	Net Derivative Contracts
	(in millions)
Commodity Contracts (in equivalent MWh):
Power(1)	(97	)	61	(36	)
Natural gas	(9	)	10	1
Coal	3		8	11

(1) Includes MWh equivalent of natural gas transactions used to hedge power economically.

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GenOn Mid-Atlantic

The following table presents the fair value of GenOn Mid-Atlantic’s derivative financial instruments:

											Net Derivative
											Contract
	Derivative Contract Assets				Derivative Contract Liabilities						Assets
	Current		Long-Term		Current			Long-Term			(Liabilities)
	(in millions)
June 30, 2012
September 30, 2012
Commodity Contracts:
Asset management	$	~~245~~248	$	~~484~~403	$	—(7	)	$	(24	)	$	~~727~~640
Asset management—affiliate	~~139~~96		~~138~~101		(~~188~~126		)	(9578		)	(67		)
Total derivatives	$	~~384~~344	$	~~622~~504	$	(~~188~~133	)	$	(9782	)	$	~~721~~633
December 31, 2011
Commodity Contracts:
Asset management	$	208	$	526	$	—		$	—		$	734
Asset management—affiliate	191		105		(168		)	(68		)	60
Total derivatives	$	399	$	631	$	(168	)	$	(68	)	$	794

The following table presents the net gains (losses) for derivative financial instruments recognized in income in the consolidated statements of operations:

	Three Months Ended June 30,
	Three Months Ended September 30,
	2012						2011
Derivatives Not Designated as Hedging Instruments	Operating Revenues			Cost of Fuel, Electricity and Other Products			Operating Revenues			Cost of Fuel, Electricity and Other Products
	(in millions)
Asset Management Commodity Contracts:
Unrealized	$	(66137	)	$	~~(47~~46	)	$	(273	)	$	15(9	)
Realized(1)(2)	~~106~~82			(21		)	6154			—
Total asset management	$	40(55	)	$	~~(49~~45	)	$	3451		$	15(9	)

	Six Months Ended June 30,
	2012					2011
Derivatives Not Designated as Hedging Instruments	Operating Revenues		Cost of Fuel, Electricity and Other Products			Operating Revenues			Cost of Fuel, Electricity and Other Products
	(in millions)
Asset Management Commodity Contracts:
Unrealized	$	1	$	(72	)	$	(78	)	$	27
Realized(1)(2)	244		(3		)	122			—
Total asset management	$	245	$	(75	)	$	44		$	27

(2) Excludes settlement value of fuel contracts classified as inventory.

	Nine Months Ended September 30,
	2012						2011
Derivatives Not Designated as Hedging Instruments	Operating Revenues			Cost of Fuel, Electricity and Other Products			Operating Revenues			Cost of Fuel, Electricity and Other Products
	(in millions)
Asset Management Commodity Contracts:
Unrealized	$	(136	)	$	(26	)	$	(81	)	$	18
Realized(1)(2)	326			(4		)	176			—
Total asset management	$	190		$	(30	)	$	95		$	18

(2) Excludes settlement value of fuel contracts classified as inventory.

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The following tables present the notional quantity on long (short) positions for derivative financial instruments:

	Notional Volumes at June 30, 2012
	Notional Volumes at September 30, 2012
Derivative Instruments	Derivative Contract Assets		Derivative Contract Liabilities		Net Derivative Contracts
	(in millions)
Commodity Contracts (in equivalent MWh):
Power(1)	(4930	)	12(9	)	(3739	)
Natural gas	—		1		1
Coal	(1	)	15		14
Coal	(1	)	17		16

(1) Includes MWh equivalent of natural gas transactions used to hedge power economically.

	Notional Volumes at December 31, 2011
Derivative Instruments	Derivative Contract Assets		Derivative Contract Liabilities	Net Derivative Contracts
	(in millions)
Commodity Contracts (in equivalent MWh):
Power(1)	(56	)	19	(37	)
Coal	3		8	11

(1) Includes MWh equivalent of natural gas transactions used to hedge power economically.

Fair Value Measurements

Fair Value Hierarchy and Valuation Techniques. We apply recurring fair value measurements to our financial assets and liabilities. In estimating fair value, we generally use a market approach and incorporate assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and/or the risks inherent in the inputs to the valuation techniques. The fair value measurement inputs we use vary from readily observable prices for exchange-traded instruments to price curves that cannot be validated through external pricing sources. Based on the observability of the inputs used in the valuation techniques, the financial assets and liabilities carried at fair value in the financial statements are classified as follows:

Level 1: Represents unadjusted quoted market prices in active markets for identical assets or liabilities that are accessible at the measurement date. This category primarily includes natural gas and crude oil futures traded on the NYMEX and swaps cleared against NYMEX prices. Interest bearing funds are also valued using Level 1 inputs.

Level 2: Represents quoted market prices for similar assets or liabilities in active markets, quoted market prices in markets that are not active or other inputs that are observable or can be corroborated by observable market data. This category primarily includes non-exchange-traded derivatives such as OTC forwards, swaps and options, and certain energy derivative instruments that are cleared and settled through exchanges.

Level 3: Represents commodity derivative instruments whose fair value is estimated based on internally developed models and methodologies utilizing significant inputs that are generally less readily observable from market sources (such as implied volatilities and correlations). The OTC, complex or structured derivative instruments that are transacted in less liquid markets with limited pricing information are included in Level 3. Examples are coal contracts, power transmission congestion products, less liquid power and natural gas contracts, and options valued using internally developed inputs.

In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the level in the fair value hierarchy within which the fair value measurement in its entirety falls must be determined based on the lowest level input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and consideration of factors specific to the asset or liability.

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A significant amount of the fair value of our derivative contract assets and liabilities is based on observable quoted prices from exchanges and indicative quoted prices from independent brokers in active markets that regularly facilitate our transactions. An active market is considered to have transactions with sufficient frequency and volume to provide pricing information on an ongoing basis. We think that these prices represent the best available information for valuation purposes. In determining the fair value of derivative contract assets and liabilities, we use third-party market pricing where available. For transactions classified in Level 1 of the fair value hierarchy, we use the unadjusted published settled prices on the valuation date. For transactions classified in Level 2 of the fair value hierarchy, we value these transactions using indicative quoted prices from independent brokers or other widely-accepted valuation methodologies. Transactions are classified in Level 2 if substantially all (greater than 90%) of the fair value can be corroborated using observable market inputs such as transactable broker quotes. In accordance with the exit price objective under the fair value measurements accounting guidance, the fair value of our derivative contract assets and liabilities is determined based on the net underlying position of the recorded derivative contract assets and liabilities using bid prices for assets and ask prices for liabilities. The quotes we obtain from brokers are non-binding in nature, but are from brokers that typically transact in the market being quoted and are based on their knowledge of market transactions on the valuation date. We typically obtain multiple broker quotes as of the valuation date that extend for the tenor of the underlying contracts for each delivery location. The number of quotes that we can obtain depends on the relative liquidity of the delivery location on the valuation date. If multiple broker quotes are received for a contract, we use an average of the quoted bid or ask prices. If only one broker quote is received for a delivery location and it cannot be validated through other external sources, we will assign the quote to a lower level within the fair value hierarchy. In some instances, we may combine broker quotes for a liquid delivery hub with broker quotes for the price spread between the liquid delivery hub and the delivery location under the contract. We also may apply interpolation techniques to value monthly strips if broker quotes are only available on a seasonal or annual basis. We perform validation procedures on the broker quotes at least monthly. The validation procedures include reviewing the quotes for accuracy and comparing them to our internal price curves. In certain instances, we may exclude from consideration a broker quote if it is a clear outlier and other quotes are obtained. At ~~June~~September 30, 2012, we obtained broker quotes for 100% of our delivery locations classified in Level 2 of the fair value hierarchy.

Inactive markets are considered to be those markets with few transactions, noncurrent pricing or prices that vary over time or among market makers. Our transactions in Level 3 of the fair value hierarchy may involve transactions whereby observable market data, such as broker quotes, are not available for substantially all of the tenor of the contract or we are only able to obtain indicative broker quotes that cannot be corroborated by observable market data. In such cases, we may apply valuation techniques such as extrapolation and other quantitative methods to determine fair value. Our techniques for fair value estimation include assumptions for market prices, including market price volatility and the volatility of the spread between multiple market prices. Proprietary models may also be used to estimate the fair value of derivative contract assets and liabilities that may be structured or otherwise tailored. The degree of estimation increases for longer duration contracts, contracts with multiple pricing features, option contracts and off-hub delivery points. At ~~June~~September 30, 2012, GenOn Americas Generation’s assets and liabilities classified as Level 3 in the fair value hierarchy represented 43% of its total derivative contract assets and 19% of its total derivative contract liabilities. At ~~June~~September 30, 2012, GenOn Mid-Atlantic’s assets and liabilities classified as Level 3 in the fair value hierarchy represented 1% of its total derivative contract assets and 5145% of its total derivative contract liabilities.

The fair value of our derivative contract assets and liabilities is also affected by assumptions as to time value, credit risk and non-performance risk. The nominal value of derivatives is discounted to account for time value using a LIBOR forward interest rate curve based on the tenor of the transaction. Derivative contract assets are reduced to reflect the estimated default risk of counterparties on their contractual obligations. The counterparty default risk for our overall net position is measured based on published spreads on credit default swaps for counterparties, where available, or proxies based upon published spreads, applied to our current exposure and potential loss exposure from the financial commitments in our risk management portfolio. The fair value of derivative contract liabilities is reduced to reflect the estimated risk of default on contractual obligations to counterparties and is measured based on published default rates of our debt, where available, or proxies based upon published spreads. Credit risk and non-performance risk are calculated with consideration of our master netting agreements with counterparties and our exposure is reduced by cash collateral posted to us against these obligations.

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Information about Sensitivity to Changes in Significant Unobservable Inputs. The significant unobservable inputs used in the fair value measure of our commodity instruments categorized within Level 3 of the fair value hierarchy are estimates of future market volatility, estimates of forward congestion power price spreads and estimates of counterparty credit risk and our own non-performance risk. These assumptions are generally independent of each other. Volatility curves and power prices spreads are generally based on observable markets where available, or derived from historical prices and forward market prices from similar observable markets when not available. Increases in the price or volatility of the spread on a long position would result in a higher fair value measurement. Increases in the price or volatility of the spread on a short position would result in a lower fair value measurement. A change in the assumption used for the probability of default is accompanied by a directionally similar change in the adjustment to reflect the estimated default risk of counterparties on their contractual obligations, or the estimated risk of default on our own contractual obligations to counterparties.

Risk Management. The Risk and Finance Oversight Committee of GenOn’s Board of Directors is responsible for oversight of the risk management of our commercial activities and enterprise risk management. In order to ensure proper daily oversight of our commercial risk controls, the Risk and Finance Oversight Committee has established the ROC with membership determined by GenOn’s Chief Executive Officer. The ROC is responsible for ensuring that the necessary policies, procedures and systems are in place to measure, monitor and report on the risks associated with our commercial activities. The ROC is also responsible for safeguarding proprietary models against the negative impact of inadequate model control by providing oversight and control to model development, back-testing and verification, automation, security and revision control. The ROC must approve new valuation models or fundamental modifications to existing models. Model forecasts are back-tested annually and the results reviewed with the ROC.

Comprehensive, accurate and timely reporting and monitoring is essential to effectively manage market, credit and operational risks and to protect against large unanticipated losses. Management has established reporting and monitoring functions, which include daily and weekly reporting, to inform the ROC and GenOn’s Chief Risk Officer of its activities. The chair of the ROC reports to the Risk and Finance Oversight Committee on a quarterly basis, or more frequently, if events and circumstances dictate.

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GenOn Americas Generation

Fair Value of Derivative Instruments and Certain Other Assets. The fair value measurements of GenOn Americas Generation’s financial assets and liabilities (including amounts with affiliates) by class are as follows:

	June 30, 2012
	September 30, 2012
	Level 1(1)		Level 2(1)(2)		Level 3			Total Fair Value
	(in millions)
Derivative contract assets:
Commodity Contracts
Asset Management:
Power	$	~~175~~148	$	~~1,199~~969	$	1812		$	1,~~392~~129
Fuel	21		21		2114		(3)	2516
Total Asset Management	~~177~~149		~~1,201~~970		3926			1,~~417~~145
Trading Activities	4416		~~241~~151		3316			~~318~~183
Total derivative contract assets	$	~~221~~165	$	1,~~442~~121	$	7242		$	1,~~735~~328
Derivative contract liabilities:
Commodity Contracts
Asset Management:
Power	$	~~132~~110	$	~~348~~268	$	13		$	~~493~~391
Fuel	72		21		~~160~~107		(3)	~~169~~110
Total Asset Management	~~139~~112		~~350~~269		~~173~~120			~~662~~501
Trading Activities	5118		~~252~~155		129			~~315~~182
Total derivative contract liabilities	$	~~190~~130	$	~~602~~424	$	~~185~~129		$	~~977~~683
Interest-bearing funds(4)	$	~~472~~369	$	—	$	—		$	~~472~~369

(1) Transfers between Level 1 and Level 2 are recognized as of the end of the reporting period. There were no transfers during the ~~six~~nine months ended ~~June~~September 30, 2012.

(2) Option contracts comprised 1% of GenOn Americas Generation’s net derivative contract assets.

(3) Primarily relates to coal.

(4) Represents investments in money market funds and is included in cash and cash equivalents, funds on deposit and other noncurrent assets in the consolidated balance sheet. Of interest-bearing funds, GenOn Americas Generation had $~~434~~331 million included in cash and cash equivalents, $32 million included in funds on deposit and $6 million included in other noncurrent assets.

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	December 31, 2011
	Level 1(1)		Level 2(1)(2)			Level 3			Total Fair Value
	(in millions)
Derivative contract assets:
Commodity Contracts
Asset Management:
Power	$	118	$	1,169		$	17		$	1,304
Fuel	2		—			13		(3)	15
Total Asset Management	120		1,169			30			1,319
Trading Activities	124		302			36			462
Total derivative contract assets	$	244	$	1,471		$	66		$	1,781

Derivative contract liabilities:
Commodity Contracts
Asset Management:
Power	$	108	$	298		$	9		$	415
Fuel	19		(9		)	75		(3)	85
Total Asset Management	127		289			84			500
Trading Activities	142		309			14			465
Total derivative contract liabilities	$	269	$	598		$	98		$	965

Interest-bearing funds(4)	$	421	$	—		$	—		$	421

(1) Transfers between Level 1 and Level 2 are recognized as of the end of the reporting period. There were no significant transfers during 2011.

(2) Option contracts comprised 1% of GenOn Americas Generation’s net derivative contract assets.

(3) Primarily relates to coal.

(4) Represents investments in money market funds and is included in cash and cash equivalents, funds on deposit and other noncurrent assets in the consolidated balance sheet. Of interest-bearing funds, GenOn Americas Generation had $249 million included in cash and cash equivalents, $166 million included in funds on deposit and $6 million included in other noncurrent assets.

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The following is a reconciliation of changes (comprised of the sum of the quarterly changes) in fair value of net commodity derivative contract assets and liabilities (including amounts with affiliates) classified as Level 3 during the ~~six~~nine months ended ~~June~~September 30, 2012 and 2011:

	Net Derivatives Contracts (Level 3)
	Asset Management			Trading Activities			Total
	(in millions)
Balance, January 1, 2012 (net asset (liability))	$	(54	)	$	22		$	(32	)
Total gains (losses) realized/unrealized:
Included in earnings(1)	(~~112~~98		)	2112			(9186		)
Purchases(2)	—			—			—
Issuances(2)	—			—			—
Settlements (3)	3258			(2227		)	1031
Transfers into Level 3(4)	—			—			—
Transfers out of Level 3(4)	—			—			—
Balance, June 30, 2012 (net asset (liability))	$	(134	)	$	21		$	(113	)
Balance, September 30, 2012 (net asset (liability))	$	(94	)	$	7		$	(87	)
Balance, January 1, 2011 (net asset (liability))	$	(68	)	$	2		$	(66	)
Total gains (losses) realized/unrealized:
Included in earnings(1)	29—			49			339
Purchases(2)	—			—			—
Issuances(2)	—			—			—
Settlements(3)	611			(25		)	46
Transfers into Level 3(4)	—			—			—
Transfers out of Level 3(4)	—12			—			—12
Balance, June 30, 2011 (net asset (liability))	$	(33	)	$	4		$	(29	)
Balance, September 30, 2011 (net asset (liability))	$	(45	)	$	6		$	(39	)

(1) Represents the fair value, as of the end of each reporting period, of Level 3 contracts entered into during each reporting period and the gains and losses attributable to Level 3 contracts that existed as of the beginning of each reporting period and were still held at the end of each reporting period.

(2) Contracts entered into during each reporting period are reported with other changes in fair value.

(3) Represents the reversal of previously recognized unrealized gains and losses from settlement of contracts during each reporting period.

(4) Denotes the total contracts that existed at the beginning of each reporting period and were still held at the end of each reporting period that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during each reporting period. Amounts reflect fair value as of the end of each reporting period.

The following ~~table~~tables ~~presents~~present the amounts included in income related to derivative contract assets and liabilities (including amounts with affiliates) classified as Level 3:

	Three Months Ended June 30,
	Three Months Ended September 30,
	2012									2011
	Operating Revenues			Cost of Fuel, Electricity and Other Products			Total			Operating Revenues			Cost of Fuel, Electricity and Other Products			Total
	(in millions)
Gains (losses) included in income	$	(3320	)	$	~~(50~~46	)	$	~~(83~~26	)	$	7(3	)	$	15(7	)	$	22(10	)
Gains (losses) included in income (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets still held at June 30	$	(31	)	$	(90	)	$	(121	)	$	7		$	15		$	22
Gains (losses) included in income (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets still held at September 30	$	(18	)	$	45		$	27		$	(2	)	$	(6	)	$	(8	)

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	Six Months Ended June 30,
	Nine Months Ended September 30,
	2012									2011
	Operating Revenues			Cost of Fuel, Electricity and Other Products			Total			Operating Revenues		Cost of Fuel, Electricity and Other Products		Total
	(in millions)
Gains (losses) included in income	$	(424	)	$	(7731	)	$	(8155	)	$	107	$	2720	$	3727
Gains (losses) included in income (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets still held at June 30	$	(3	)	$	(117	)	$	(120	)	$	10	$	28	$	38
Gains (losses) included in income (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets still held at September 30	$	(21	)	$	(72	)	$	(93	)	$	8	$	22	$	30

Information about Sensitivity to Changes in Significant Unobservable Inputs. The following table presents the range of sensitivity of unobservable inputs used in fair value measurements categorized within Level 3 of the fair value hierarchy:

	Quantitative Information about Level 3 Fair Value Measurements(1)
	Net Fair Value at June 30, 2012			Valuation Techniques	Unobservable Input	Range (Weighted Average)
	Net Fair Value at September 30, 2012			Valuation Techniques	Unobservable Input	Range (Weighted Average)
	(in millions)
Credit valuation adjustment	$	(1	)	Internal model	~~Counterparty~~Own credit risk	20% to (20)%~~(2)~~	(2)
Credit valuation adjustment	$	6		Internal model	Own credit risk	20% to (20)%(2)

(1) Excludes immaterial unobservable inputs related to power transmission congestion products, power swaps, ~~and~~ physical gas premiums on transactions and credit valuation adjustments related to counterparty credit risk.

(2) Represents the range of the credit default swap spread curves used in the valuation analysis that we think market participants might use when pricing the contracts.

At ~~June~~September 30, 2012, net fair value asset of $256 million for power transactions and net fair value liability of $~~140~~92 million for fuel transactions classified as Level 3 were priced based on unadjusted indicative broker quotes that cannot be corroborated by observable market data. Quantitative information is excluded for these fair value measurements.

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GenOn Mid-Atlantic

Fair Value of Derivative Instruments and Certain Other Assets. The fair value measurements of GenOn Mid-Atlantic’s financial assets and liabilities (including amounts with affiliates) by class are as follows:

	June 30, 2012
	September 30, 2012
	Level 1(1)		Level 2(1) (2)		Level 3			Total Fair Value
	(in millions)
Derivative contract assets:
Commodity Contracts
Asset Management:
Power	$	7058	$	~~928~~786	$	—		$	~~998~~844
Fuel	1—		1—		64		(3)	84
Total derivative contract assets	$	7158	$	~~929~~786	$	64		$	~~1,006~~848
Derivative contract liabilities:
Commodity Contracts
Asset Management:
Power	$	2620	$	~~112~~99	$	—		$	~~138~~119
Fuel	2—		1—		~~144~~96		(3)	~~147~~96
Total derivative contract liabilities	$	2820	$	~~113~~99	$	~~144~~96		$	~~285~~215
Interest-bearing funds(4)	$	~~231~~203	$	—	$	—		$	~~231~~203

(1) Transfers between Level 1 and Level 2 are recognized as of the end of the reporting period. There were no transfers during the ~~six~~nine months ended ~~June~~September 30, 2012.

(2) Option contracts comprised less than 1% of GenOn Mid-Atlantic’s net derivative contract assets.

(3) Primarily relates to coal.

(4) Represents investments in money market funds and is included in cash and cash equivalents and funds on deposit in the consolidated balance sheet. Of interest-bearing funds, GenOn Mid-Atlantic had $~~199~~171 million included in cash and cash equivalents and $32 million included in funds on deposit.

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	December 31, 2011
	Level 1(1)		Level 2(1) (2)		Level 3			Total Fair Value
	(in millions)
Derivative contract assets:
Commodity Contracts
Asset Management:
Power	$	39	$	982	$	—		$	1,021
Fuel	—		—		9		(3)	9
Total derivative contract assets	$	39	$	982	$	9		$	1,030

Derivative contract liabilities:
Commodity Contracts
Asset Management:
Power	$	29	$	131	$	1		$	161
Fuel	3		—		72		(3)	75
Total derivative contract liabilities	$	32	$	131	$	73		$	236

Interest-bearing funds(4)	$	230	$	—	$	—		$	230

(1) Transfers between Level 1 and Level 2 are recognized as of the end of the reporting period. There were no significant transfers during 2011.

(2) Option contracts comprised less than 1% of GenOn Mid-Atlantic’s net derivative contract assets.

(3) Primarily relates to coal.

(4) Represents investments in money market funds and is included in cash and cash equivalents and funds on deposit in the consolidated balance sheet. Of interest-bearing funds, GenOn Mid-Atlantic had $64 million included in cash and cash equivalents and $166 million included in funds on deposit.

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	Asset Management
	(in millions)
Balance, January 1, 2012 (net asset (liability))	$	(64	)
Total gains (losses) realized/unrealized:
Included in earnings(1)	(~~116~~99		)
Purchases(2)	—
Issuances(2)	—
Settlements(3)	4271
Transfers into Level 3(4)	—
Transfers out of Level 3(4)	—
Balance, June 30, 2012 (net asset (liability))	$	(138	)
Balance, September 30, 2012 (net asset (liability))	$	(92	)
Balance, January 1, 2011 (net asset (liability))	$	(69	)
Total gains (losses) realized/unrealized:
Included in earnings(1)	25(5		)
Purchases(2)	—
Issuances(2)	—
Settlements(3)	713
Transfers into Level 3(4)	—
Transfers out of Level 3(4)	—12
Balance, June 30, 2011 (net asset (liability))	$	(37	)
Balance, September 30, 2011 (net asset (liability))	$	(49	)

(2) Contracts entered into during each reporting period are reported with other changes in fair value.

(3) Represents the reversal of previously recognized unrealized gains and losses from settlement of contracts during each reporting period.

The following ~~table~~tables ~~presents~~present the amounts included in income related to derivative contract assets and liabilities (including amounts with affiliates) classified as Level 3:

	Three Months Ended June 30,
	Three Months Ended September 30,
	2012								2011
	Operating Revenues		Cost of Fuel, Electricity and Other Products			Total			Operating Revenues			Cost of Fuel, Electricity and Other Products			Total
	(in millions)
Gains (losses) included in income	$	—	$	~~(50~~46	)	$	~~(50~~46	)	$	(5	)	$	16(7	)	$	21(12	)
Gains (losses) included in income (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets still held at June 30	$	—	$	(90	)	$	(90	)	$	5		$	16		$	21
Gains (losses) included in income (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets still held at September 30	$	—	$	45		$	45		$	(7	)	$	(7	)	$	(14	)

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	Six Months Ended June 30,
	Nine Months Ended September 30,
	2012								2011
	Operating Revenues		Cost of Fuel, Electricity and Other Products			Total			Operating Revenues			Cost of Fuel, Electricity and Other Products		Total
	(in millions)
Gains (losses) included in income	$	1	$	(7529	)	$	(7428	)	$	5—		$	2820	$	3320
Gains (losses) included in income (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets still held at June 30	$	—	$	(115	)	$	(115	)	$	5		$	28	$	33
Gains (losses) included in income (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets still held at September 30	$	—	$	(70	)	$	(70	)	$	(2	)	$	21	$	19

	Quantitative Information about Level 3 Fair Value Measurements(1)
	Net Fair Value at June 30, 2012		Valuation Techniques	Unobservable Input	Range (Weighted Average)
	Net Fair Value at September 30, 2012		Valuation Techniques	Unobservable Input	Range (Weighted Average)
	(in millions)
Credit valuation adjustment	$	41	Internal model	Own credit risk	20% to (20)%~~(2)~~	(2)

(1) Excludes immaterial unobservable inputs related to power transmission congestion products, ~~physical gas premiums on transactions~~ and credit valuation adjustment related to counterparty credit risk.

(2) Represents the range of the credit default swap spread curves used in the valuation analysis that we think market participants might use when pricing the contracts.

At ~~June~~September 30, 2012, net fair value liability of $~~141~~93 million for fuel transactions classified as Level 3 were priced based on unadjusted indicative broker quotes that cannot be corroborated by observable market data. Quantitative information is excluded for these fair value measurements.

Counterparty Credit Concentration Risk

We are exposed to the default risk of the counterparties with which we transact. We manage our credit risk by entering into master netting agreements and requiring most counterparties to post cash collateral or other credit enhancements based on the net exposure and the credit standing of the counterparty. We also have non-collateralized power hedges entered into by GenOn Mid-Atlantic. These transactions are senior unsecured obligations of GenOn Mid-Atlantic and the counterparties and have not required either party to post cash collateral for initial margin. Since April 2012, the counterparties, in some cases, have been required to post cash collateral to secure credit exposure above an agreed threshold as a result of changes in power or natural gas prices. At ~~June~~September 30, 2012 and December 31, 2011, $~~171~~ 107 million and $4 million, respectively, of cash collateral posted to GenOn Americas Generation by counterparties under master netting agreements were included in accounts payable and accrued liabilities in GenOn Americas Generation’s consolidated balance sheets. Our credit valuation adjustment on derivative contract assets was $208 million and $47 million at ~~June~~September 30, 2012 and December 31, 2011, respectively.

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We monitor counterparty credit concentration risk on both an individual basis and a group counterparty basis. The following tables highlight the credit quality and the balance sheet settlement exposures related to these activities:

GenOn Americas Generation

	June 30, 2012
	September 30, 2012
Credit Rating Equivalent	Gross Exposure Before Collateral(1)		Net Exposure Before Collateral(2)		Collateral(3)		Exposure Net of Collateral		% of Net Exposure
	(dollars in millions)
Clearing and Exchange	$	~~669~~303	$	~~298~~91	$	~~298~~91	$	—	—
Investment Grade:
Financial institutions	~~821~~721		~~784~~686		~~168~~106		~~616~~580		7476	%
Energy companies	~~382~~291		~~176~~160		2—		~~174~~160		21	%
Non-investment Grade:
Energy companies	136		72		1—		62		1—	%
No External Ratings:
Internally-rated investment grade	2717		2617		—		2617		32	%
Internally-rated non-investment grade	116		115		—		115		1	%
Total	$	1,~~923~~344	$	~~1,302~~961	$	~~469~~197	$	~~833~~764	100	%

	December 31, 2011
Credit Rating Equivalent	Gross Exposure Before Collateral(1)		Net Exposure Before Collateral(2)		Collateral(3)		Exposure Net of Collateral		% of Net Exposure
	(dollars in millions)

Clearing and Exchange	$	710	$	217	$	217	$	—	—
Investment Grade:
Financial institutions	856		814		—		814		82	%
Energy companies	369		148		3		145		14	%
Non-investment Grade:
Energy companies	7		3		1		2		—
No External Ratings:
Internally-rated investment grade	18		18		—		18		2	%
Internally-rated non-investment grade	15		15		—		15		2	%
Total	$	1,975	$	1,215	$	221	$	994	100	%

(1) Gross exposure before collateral represents credit exposure, including both realized and unrealized transactions, before (a) applying the terms of master netting agreements with counterparties and (b) netting of transactions with clearing brokers and exchanges. The table excludes amounts related to contracts classified as normal purchases/normal sales and non-derivative contractual commitments that are not recorded at fair value in the consolidated balance sheets, except for any related accounts receivable. Such contractual commitments contain credit and economic risk if a counterparty does not perform. Non-performance could have a material adverse effect on our future results of operations, financial condition and cash flows.

(2) Net exposure before collateral represents the credit exposure, including both realized and unrealized transactions, after applying the terms of master netting agreements and the netting of transactions with clearing brokers and exchanges.

(3) Collateral includes cash and letters of credit received from counterparties.

GenOn Americas Generation had credit exposure to two investment grade counterparties at ~~June~~September 30, 2012 and December 31, 2011, each representing an exposure of more than 10% of total credit exposure, net of collateral and totaling $~~439~~428 million and $664 million at ~~June~~September 30, 2012 and December 31, 2011, respectively.

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GenOn Mid-Atlantic

	June 30, 2012
	September 30, 2012
Credit Rating Equivalent	Gross Exposure Before Collateral(1)(4)		Net Exposure Before Collateral(2)		Collateral(3)		Exposure Net of Collateral		% of Net Exposure
	(dollars in millions)
Investment Grade:
Financial institutions	$	~~774~~682	$	~~772~~672	$	~~168~~106	$	~~604~~566	99	%
Non-investment Grade:
Energy companies	1		1		—		1		—
No External Ratings:
Internally-rated non-investment grade	83		83		—		83		1	%
Total	$	~~782~~686	$	~~780~~676	$	~~168~~106	$	~~612~~570	100	%

	December 31, 2011
Credit Rating Equivalent	Gross Exposure Before Collateral(1)(4)		Net Exposure Before Collateral(2)		Collateral(3)		Exposure Net of Collateral		% of Net Exposure
	(dollars in millions)
Investment Grade:
Financial institutions	$	805	$	802	$	—	$	802	98	%
Non-investment Grade:
Energy companies	1		1		—		1		—
No External Ratings:
Internally-rated non-investment grade	13		13		—		13		2	%
Total	$	819	$	816	$	—	$	816	100	%

(3) Collateral includes cash and letters of credit received from counterparties.

(4) Amounts do not include exposures with affiliates or exposures incurred by GenOn Mid-Atlantic in connection with transactions entered into with external counterparties by affiliates on its behalf, with the exception of coal purchases.

GenOn Mid-Atlantic had credit exposure to three and two investment grade counterparties at ~~June~~September 30, 2012 and December 31, 2011, respectively, each representing an exposure of more than 10% of total credit exposure, net of collateral and totaling $~~512~~489 million and $664 million at ~~June~~September 30, 2012 and December 31, 2011, respectively.

GenOn Americas Generation and GenOn Mid-Atlantic Credit Risk

Our standard industry contracts contain credit-risk-related contingent features such as ratings-related thresholds whereby we would be required to post additional cash collateral or letters of credit as a result of a credit event, including a downgrade. Additionally, some of our contracts contain adequate assurance language, which is generally subjective in nature that could require us to post additional cash collateral or letters of credit as a result of a credit event, including a downgrade. However, as a result of our current credit rating, we are typically required to post collateral in the normal course of business to offset either substantially or completely the net liability positions, after applying the terms of master netting agreements. At ~~June~~September 30, 2012, the fair value of GenOn Americas Generation’s financial instruments with credit-risk-related contingent features in a net liability position was $21 million for which GenOn Americas Generation had posted collateral of $15 million, including cash and letters of credit. At June 30, 2012, GenOn Mid-Atlantic did not have any financial instruments with credit-risk-related contingent features in a net liability position.

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~~At June~~$22 ~~30,~~million ~~2012~~for ~~and~~which ~~December 31, 2011,~~ GenOn Americas Generation had ~~$94~~posted ~~million~~collateral ~~and~~of $6418 million, ~~respectively,~~including of cash ~~collateral~~and ~~posted~~letters ~~with~~of ~~counterparties~~credit. At ~~under~~September 30, ~~master~~2012, ~~netting~~GenOn ~~agreements~~Mid-Atlantic did ~~that~~not ~~was~~have ~~included~~any infinancial ~~funds~~instruments onwith ~~deposit~~credit-risk-related contingent features in ~~the~~a ~~consolidated~~net ~~balance~~liability ~~sheets~~position.

At September 30, 2012 and December 31, 2011, GenOn Americas Generation had $80 million and $64 million, respectively, of cash collateral posted with counterparties under master netting agreements that was included in funds on deposit in the consolidated balance sheets.

Fair Values of Other Financial Instruments (GenOn Americas Generation)

The fair values of certain funds on deposit, receivables, net, receivables, net—affiliate, notes receivable—affiliate, accounts payable and accrued liabilities, payables, net—affiliate and notes payable—affiliate approximate their carrying amounts.

The carrying amounts and fair values of GenOn Americas Generation’s debt are as follows:

	Carrying Amount		Level 1		Level 2(1)		Level 3		Total Fair Value
	(in millions)
June 30, 2012
September 30, 2012
Liabilities:
Long and short-term debt	$	~~864~~863	$	—	$	~~773~~924	$	—	$	~~773~~924
December 31, 2011
Liabilities:
Long and short-term debt	$	866	$	—	$	797	$	—	$	797

(1) The fair value of long and short-term debt is estimated using broker quotes for instruments that are publicly traded.

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4. Long-Term Debt

Outstanding debt was as follows:

	June 30, 2012							December 31, 2011
	September 30, 2012							December 31, 2011
	Stated Interest Rate(1)		Long-~~term~~Term			Current		Stated Interest Rate(1)		Long-~~term~~Term			Current
	(in millions, except interest rates)
Bonds and Notes:
GenOn Americas Generation:
Senior unsecured notes, due 2021	8.50	%	$	450		$	—	8.50	%	$	450		$	—
Senior unsecured notes, due 2031	9.125		400			—		9.125		400			—
Unamortized debt discounts			(2		)	—				(2		)	—
GenOn Mid-Atlantic:
GenOn Chalk Point capital lease, due 2015	8.19		1110			5		8.19		14			4
Total			$	~~859~~858		$	5			$	862		$	4

(1) The stated interest rates are at ~~June~~September 30, 2012 and December 31, 2011, respectively.

5. Related Party Arrangements and Transactions

Administrative Services Provided by GenOn Energy Services

GenOn Energy Services provides us with various management, personnel and other services directly relating to our facilities. We reimburse GenOn Energy Services for amounts equal to GenOn Energy Services’ costs of providing such services. The total costs incurred for these services by GenOn Energy Services have been included in the consolidated statements of operations as follows:

GenOn Americas Generation

	Three Months Ended June 30,				Six Months Ended June 30,
	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
	(in millions)
Cost of fuel, electricity and other products—affiliate	$	2	$	32	$	46	$	57
Operations and maintenance expense—affiliate	36		3531		75111		6798
Total	$	38	$	3833	$	79117	$	72105

GenOn Mid-Atlantic

	Three Months Ended June 30,				Six Months Ended June 30,
	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
	(in millions)
Cost of fuel, electricity and other products—affiliate	$	2	$	32	$	46	$	57
Operations and maintenance expense—affiliate	22		2019		4466		3857
Total	$	24	$	2321	$	4872	$	4364

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GenOn’s corporate overhead costs are allocated based on each operating subsidiary’s planned operating expenses relative to all operating subsidiaries. These allocations and charges are not necessarily indicative of what would have been incurred had we been an unaffiliated entity. We incurred the following in costs under these arrangements, which are included in operations and maintenance expense—affiliate in our consolidated statements of operations:

	Three Months Ended June 30,				Six Months Ended June 30,
	Three Months Ended September 30,				Nine Months Ended September 30,
	2012		2011		2012		2011
	(in millions)
GenOn Americas Generation	$	3127	$	3229	$	5683	$	6594
GenOn Mid-Atlantic	$	2017	$	2119	$	3653	$	4261

Services Provided by GenOn Energy Management

GenOn Americas Generation

GenOn Energy Management provides services to certain of GenOn’s indirect operating subsidiaries through power, fuel supply and services agreements. The services include the bidding and dispatch of the generating units, fuel procurement and the execution of contracts, including economic hedges, to reduce price risk. These transactions are recorded as operating revenues—affiliate and cost of fuel, electricity and other products—affiliate, as appropriate, in the consolidated statements of operations. Amounts due from and to GenOn’s indirect operating subsidiaries are recorded as receivables, net—affiliate or payables, net—affiliate, as appropriate. Substantially all energy marketing overhead expenses are allocated to GenOn’s operating subsidiaries. During the three months ended ~~June~~September 30, 2012 and 2011, GenOn Americas Generation recorded a reduction to operations and maintenance expense—affiliate of $6 million and $87 million, respectively, and during the ~~six~~nine months ended ~~June~~September 30, 2012 and 2011, GenOn Americas Generation recorded a reduction to operations and maintenance expense—affiliate of $1218 million and $1320 million, respectively, related to the allocations of energy marketing overhead expenses to affiliates that are not included in the GenOn Americas Generation consolidated statements of operations.

GenOn Mid-Atlantic

GenOn Mid-Atlantic receives services from GenOn Energy Management which include the bidding and dispatch of the generating units, procurement of fuel and other products and the execution of contracts, including economic hedges, to reduce price risk. These transactions are recorded as operating revenues—affiliate, cost of fuel, electricity and other products—affiliate and operations and maintenance expense—affiliate, as appropriate, in the consolidated statements of operations. Amounts due to and from GenOn Energy Management under the power, fuel supply and services agreements are recorded as payables, net—affiliate or receivables, net—affiliate, as appropriate. Under these agreements, GenOn Energy Management resells GenOn Mid-Atlantic’s energy products in the PJM spot and forward markets and to other third parties. GenOn Mid-Atlantic is paid the amount received by GenOn Energy Management for such capacity and energy. GenOn Mid-Atlantic has counterparty credit risk in the event that GenOn Energy Management is unable to collect amounts owed from third parties for the resale of GenOn Mid-Atlantic’s energy products. Substantially all energy marketing overhead expenses are allocated to GenOn’s operating subsidiaries. During the three months ended ~~June~~September 30, 2012 and 2011, GenOn Mid-Atlantic incurred $1 million of energy marketing overhead expense. During the ~~six~~nine months ended ~~June~~September 30, 2012 and 2011, GenOn Mid-Atlantic incurred $2 3 million of energy marketing overhead expense. These costs are included in operations and maintenance expense—affiliate in GenOn Mid-Atlantic’s consolidated statements of operations.

Intercompany Cash Management Program (GenOn Americas Generation)

In January 2011, GenOn Americas Generation and certain of its subsidiaries began participating in separate intercompany cash management programs whereby cash balances at GenOn Americas Generation and the respective participating subsidiaries were transferred to central concentration accounts to fund working capital and other needs ~~of the respective participants. The balances under this program are reflected as notes receivable—affiliate and notes~~

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of the respective participants. The balances under this program are reflected as notes receivable—affiliate and notes payable—affiliate in GenOn Americas Generation’s consolidated balance sheets as appropriate. The notes are due on demand and accrue interest on the net position, which is payable quarterly, at the short term yield of the Federated Investors Treasury Obligation Fund or such other fund designated by GenOn Energy Holdings. At ~~June~~September 30, 2012 and December 31, 2011, GenOn Americas Generation had a net current notes receivable from GenOn Energy Holdings of $8999 million and $~~129~~130 million, respectively, related to its intercompany cash management program. During the three and ~~six~~nine months ended ~~June~~September 30, 2012 and 2011, GenOn Americas Generation earned an insignificant amount of net interest income related to these notes.

Purchased Emissions Allowances (GenOn Mid-Atlantic)

GenOn Energy Management maintains on behalf of GenOn Mid-Atlantic an inventory of certain purchased emissions allowances related to the Regional Greenhouse Gas Initiative. The emissions allowances are sold by GenOn Energy Management to GenOn Mid-Atlantic as they are needed for operations. GenOn Mid-Atlantic purchases emissions allowances from GenOn Energy Management at GenOn Energy Management’s original cost to purchase the allowances. For allowances that have been purchased by GenOn Energy Management from a GenOn affiliate, the price paid by GenOn Energy Management is determined by market indices.

Emissions allowances purchased from GenOn Energy Management that were utilized during the three months ended ~~June~~September 30, 2012 and 2011, were $47 million and ~~$6 million, respectively, and~~ during the ~~six~~nine months ended ~~June~~September 30, 2012 and 2011, were $714 million and $1421 million, respectively, and are recorded in cost of fuel, electricity and other products—affiliate in GenOn Mid-Atlantic’s consolidated statements of operations.

Proposed NRG Merger

The proposed NRG Merger iscould ~~expected to~~ affect the allocation of costs for the administrative services currently provided by GenOn Energy Services for both GenOn Americas Generation and GenOn Mid-Atlantic subsequent to completion of the NRG Merger but changes to the allocation of costs compared to historical levels cannot be estimated at this time. See note 91.

6. Income Taxes

GenOn Americas Generation

GenOn Americas Generation and most of its subsidiaries are limited liability companies that are treated as branches of GenOn Americas for income tax purposes. As a result, GenOn Americas and GenOn have direct liability for the majority of the United States federal and state income taxes relating to GenOn Americas Generation’s operations. Two of GenOn Americas Generation’s subsidiaries, Hudson Valley Gas Corporation and GenOn Special Procurement, Inc., exist as regarded corporate entities for income tax purposes. GenOn Kendall, which had previously existed as a regarded entity, was converted to a disregarded entity effective January 1, 2011. For these subsidiaries that continue to exist as corporate regarded entities, GenOn Americas Generation allocates current and deferred income taxes to each corporate regarded entity as if such entity were a single taxpayer utilizing the asset and liability method to account for income taxes. To the extent GenOn Americas Generation provides tax expense or benefit, any related tax payable or receivable to GenOn is reclassified to equity in the same period because GenOn Americas Generation does not have a tax sharing agreement with GenOn.

If GenOn Americas Generation were to be allocated income taxes attributable to its operations, the pro forma income tax ~~provision (~~benefit) attributable to income before taxes would be $0 million and $~~(8)~~11 million during the three months ended ~~June~~September 30, 2012 and 2011, respectively, and $0 million and $101 million during the ~~six~~nine months ended ~~June~~September 30, 2012 and 2011, respectively. The pro forma balance of GenOn Americas Generation’s net deferred income taxes is $0 at ~~June~~September 30, 2012.

On July 20, 2012, GenOn entered into the NRG Merger Agreement. GenOn and its subsidiaries will experience an ownership change under the applicable tax rules as a result of the NRG Merger. Immediately following the NRG Merger, GenOn and NRG will be members of the same consolidated federal income tax group. ~~The ability of this consolidated tax group to deduct the pre-NRG Merger NOL carry forwards of GenOn against the~~

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The ability of this consolidated tax group to deduct the pre-NRG Merger NOL carry forwards of GenOn against the post-NRG Merger taxable income of the group will be substantially limited as a result of the ownership change. Therefore if GenOn Americas Generation were to be allocated income taxes attributable to its operations, its pro forma NOLs would be substantially limited. See note 91.

GenOn Mid-Atlantic

GenOn Mid-Atlantic and its subsidiaries are limited liability companies and are not subject to United States federal or state income taxes. As such, GenOn Mid-Atlantic is treated as though it were a branch of GenOn Americas Generation’s parent, GenOn Americas, for income tax purposes, and not as a separate taxpayer. GenOn Americas and GenOn are directly responsible for income taxes related to GenOn Mid-Atlantic’s operations. If GenOn Mid-Atlantic were to be allocated income taxes attributable to its operations, the pro forma income tax ~~provision (~~benefit) attributable to income before taxes would be $~~(22)~~12 million and $~~(2)~~33 million during the three months ended ~~June~~September 30, 2012 and 2011, respectively, and $6 million and $1023 million during the ~~six~~nine months ended ~~June~~September 30, 2012 and 2011, respectively. The balance of GenOn Mid-Atlantic’s pro forma deferred income taxes would be a net deferred tax liability of $~~247~~223 million at ~~June~~September 30, 2012.

7. Segment Reporting (GenOn Americas Generation)

We have five segments: Eastern PJM, Northeast, California, Energy Marketing and Other Operations. The segments are determined based on how the business is managed and align with the information provided to the chief operating decision maker for purposes of assessing performance and allocating resources. Generally, GenOn Americas Generation’s segments are engaged in the sale of electricity, capacity, and ancillary and other energy services from their generating facilities in hour-ahead, day-ahead and forward markets in bilateral and ISO markets. GenOn Americas Generation also engages in proprietary trading, fuel oil management and natural gas transportation and storage activities. Operating revenues consist of (a) power generation revenues, (b) contracted and capacity revenues, (c) power hedging revenues and (d) fuel sales and proprietary trading revenues.

The Eastern PJM segment consists of ~~four~~three generating facilities located in Maryland ~~and Virginia with total net generating capacity of 5,209 MW~~. The Northeast segment consists of four generating facilities located in Massachusetts and New York ~~with total net generating capacity of 2,535 MW~~. The California segment consists of two generating facilities located in or near the City of San Francisco~~, with total net generating capacity of 1,985 MW~~. ~~The total net generating capacity for California excludes the Potrero generating facility (362 MW), which was shut down in February 2011.~~ See note 2 for a discussion of the Contra Costa generating ~~facilities~~facility that we expect to retire in ~~2012 and~~ 2013. The Energy Marketing segment consists of proprietary trading, fuel oil management and natural gas transportation and storage activities. Other Operations includes parent company adjustments for affiliate transactions of GenOn Americas Generation. All revenues are generated and long-lived assets are located within the United States.

33The following table summarizes changes in our net generating capacity by segment:

	Eastern PJM		Northeast	California		Total
	(in MWs)
MWs in service at January 1, 2011	5,204		2,535	2,347		10,086
Potrero generating facility deactivated in February 2011	—		—	(362	)	(362	)
Rating changes for generating facilities in 2011	5		—	—		5
MWs in service at September 30, 2011	5,209		2,535	1,985		9,729
Potomac River generating facility deactivated in October 2012	(482	)	—	—		(482	)
MWs in service at November 9, 2011	4,727		2,535	1,985		9,247

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GenOn Americas Generation’s measure of profit or loss for the reportable segments is operating income/loss. This measure represents the lowest level of information that is provided to the chief operating decision maker for GenOn Americas Generation’s reportable segments. In the following tables, eliminations are primarily related to intercompany revenues and intercompany cost of fuel, electricity and other products.

	Eastern PJM			Northeast			California		Energy Marketing			Other Operations			Eliminations			Total
	(in millions)
Three Months Ended June 30, 2012:
Three Months Ended September 30, 2012:
Operating revenues(1)	$	8(27	)	$	32		$	2324	$	~~455~~691		$	—		$	—		$	~~489~~690
Operating revenues—affiliate(2)	~~200~~228			2548			—		~~138~~266			—			(~~298~~384		)	65158
Total operating revenues	~~208~~201			2850			2324		~~593~~957			—			(~~298~~384		)	~~554~~848
Cost of fuel, electricity and other products(3)	32			1			—		~~157~~114			63114			—			~~224~~231
Cost of fuel, electricity and other products—affiliate(4)	~~150~~101			1225			—		~~428~~863			(63114		)	(~~298~~384		)	~~229~~491
Total cost of fuel, electricity and other products	~~153~~103			1326			—		~~585~~977			—			(~~298~~384		)	~~453~~722
Gross margin (excluding depreciation and amortization)	5598			1524			2324		8(20		)	—			—			~~101~~126
Operating Expenses:
Operations and maintenance	3954		~~(5)~~	139			65		—1			12			—			5971
Operations and maintenance—affiliate	4342			109			8		1—			(12		)	—			6157
Depreciation and amortization	30			6			34		—			21			—			41
Gain on sales of assets, net	(1—		)	—			—		—			—			—			(1—		)
Total operating expenses	~~111~~126			2924			17		1			21			—			~~160~~169
Operating income (loss)	$	(5628	)	$	~~(14~~—	)	$	67	$	7(21	)	$	(21	)	$	—		$	(5943	)

(1) Includes unrealized losses of $6388 million and $31155 million for Eastern PJM and Energy Marketing, respectively.

(2) Includes unrealized gains (losses) of $(349) million, $(121) million and $41126 million for Eastern PJM, Northeast and Energy Marketing, respectively.

(3) Includes unrealized ~~losses~~gains of $3955 million for Energy Marketing.

(4) Includes unrealized (gains) losses of $47(46) million, $(93) million and $~~(38)~~54 million for Eastern PJM, Northeast and Energy Marketing, respectively.

~~(5) Includes $31 million of income related to the reversal of the Potomac River obligation under the 2008 agreement with the City of Alexandria.~~35

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	Eastern PJM			Northeast			California		Energy Marketing			Other Operations			Eliminations			Total
	(in millions)
Six Months Ended June 30, 2012:
Nine Months Ended September 30, 2012:
Operating revenues(1)	$	~~135~~108		$	68		$	4569	$	~~985~~1,676		$	—		$	—		$	1,~~171~~861
Operating revenues—affiliate(2)	~~393~~621			61109			—		~~121~~387			—			(~~540~~924		)	35193
Total operating revenues	~~528~~729			67117			4569		12,~~106~~063			—			(~~540~~924		)	12,~~206~~054
Cost of fuel, electricity and other products(3)	68			23			—		~~256~~370			~~143~~257			—			~~407~~638
Cost of fuel, electricity and other products—affiliate(4)	~~262~~363			3661			—		~~838~~1,701			(~~143~~257		)	(~~540~~924		)	~~453~~944
Total cost of fuel, electricity and other products	~~268~~371			3864			—		12,~~094~~071			—			(~~540~~924		)	~~860~~1,582
Gross margin (excluding depreciation and amortization)	~~260~~358			2953			4569		12(8		)	—			—			~~346~~472
Operating Expenses:
Operations and maintenance	~~102~~156		(5)	2231			1520		12			13			—			~~141~~212
Operations and maintenance—affiliate	83125			2029			1624		1			(13		)	—			~~119~~176
Depreciation and amortization	5989			1218			711		—			34			—			81122
Gain on sales of assets, net	(1		)	—			—		—			—			—			(1		)
Total operating expenses	~~243~~369			5478			3855		23			34			—			~~340~~509
Operating income (loss)	$	17(11	)	$	(25	)	$	714	$	10(11	)	$	(34	)	$	—		$	6(37	)
Total assets at June 30, 2012	$	4,458		$	452		$	138	$	2,052		$	176		$	(684	)	$	6,592
Total assets at September 30, 2012	$	4,196		$	450		$	148	$	1,492		$	175		$	(482	)	$	5,979

(1) Includes unrealized ~~gains (~~losses) of $~~(7)~~95 million and $51104 million for Eastern PJM and Energy Marketing, respectively.

(2) Includes unrealized gains (losses) of $8(41) million, $(89) million and $~~(37)~~89 million for Eastern PJM, Northeast and Energy Marketing, respectively.

(3) Includes unrealized losses of $7419 million for Energy Marketing.

(4) Includes unrealized (gains) losses of $7226 million, $(912) million and $(7218) million for Eastern PJM, Northeast and Energy Marketing, respectively.

(5) Includes $31 million of income related to the reversal of the Potomac River obligation under the 2008 agreement with the City of Alexandria.

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	Eastern PJM			Northeast			California			Energy Marketing			Other Operations			Eliminations			Total
	(in millions)
Three Months Ended June 30, 2011:
Three Months Ended September 30, 2011:
Operating revenues(1)	$	4541		$	42		$	22		$	~~644~~864		$	—		$	—		$	~~715~~929
Operating revenues—affiliate(2)	~~235~~287			4552			—			7342			—			(~~351~~397		)	2(16		)
Total operating revenues	~~280~~328			4954			22			~~717~~906			—			(~~351~~397		)	~~717~~913
Cost of fuel, electricity and other products(3)	24			21			(1—		)	3372			~~102~~133			—			~~138~~210
Cost of fuel, electricity and other products—affiliate(4)	~~111~~170			2535			(2—		)	~~649~~819			(~~102~~133		)	(~~351~~397		)	~~330~~494
Total cost of fuel, electricity and other products	~~113~~174			2736			(3—		)	~~682~~891			—			(~~351~~397		)	~~468~~704
Gross margin (excluding depreciation and amortization)	~~167~~154			2218			2522			3515			—			—			~~249~~209
Operating Expenses:
Operations and maintenance	~~101~~53		(5)	11			64			—1			—4			—			~~118~~73
Operations and maintenance—affiliate	4243			109			96			(21		)	—(4		)	—			5953
Depreciation and amortization	30			67			4			1—			1			—			42
Loss on sales of assets, net	—			1			—			—			—			—			1
Impairment losses(6)	94			20			14			—			—			—			128
Total operating expenses	173			28			19			(1		)	1			—			220
Gain on sales of assets, net	—			—			(4		)	—			—			—			(4		)
Operating income (loss)	$	(6	)	$	(6	)	$	6		$	36		$	(1	)	$	—		$	29
Total operating expenses	220			$	47		$	24		$	—		$	1		$	—		$	292
Operating income (loss)	$	(66	)	$	(29	)	$	(2	)	$	15		$	(1	)	$	—		$	(83	)

(1) Includes unrealized gains (losses) of $6 (3) million and $~~(18)~~ 40 million for Eastern PJM and Energy Marketing, respectively.

(2) Includes unrealized ~~gains (~~losses) of $(332) million, ~~$1 million~~ and $30 (25) million for ~~Eastern PJM,~~ Northeast and Energy Marketing, respectively.

(3) Includes unrealized ~~gains~~losses of $15 11 million for Energy Marketing.

(4) Includes unrealized (gains) losses of $~~(15)~~9 million, $1 million and $15(11) million for Eastern PJM, Northeast and Energy Marketing, respectively.

(5) Includes $30 million of expense for large scale remediation and settlement costs.

36(6) Represents impairment losses for the write-off of excess NOx and SO2 emissions allowances as a result of the CSAPR.

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	Eastern PJM			Northeast			California			Energy Marketing		Other Operations			Eliminations			Total
	(in millions)
Six Months Ended June 30, 2011:
Nine Months Ended September 30, 2011:
Operating revenues(1)	$	4485		$	911		$	5072		$	12,~~150~~014	$	—		$	—		$	12,~~253~~182
Operating revenues—affiliate(2)	~~534~~821			84136			—			~~129~~171		—			(~~734~~1,131		)	13(3		)
Total operating revenues	~~578~~906			93147			5072			12,~~279~~185		—			(~~734~~1,131		)	12,~~266~~179
Cost of fuel, electricity and other products(3)	913			34			—			47119		~~244~~377			—			~~303~~513
Cost of fuel, electricity and other products—affiliate(4)	~~240~~410			5287			(2		)	12,~~187~~006		(~~243~~376		)	(~~734~~1,131		)	~~500~~994
Total cost of fuel, electricity and other products	~~249~~423			5591			(2		)	12,~~234~~125		1			(~~734~~1,131		)	~~803~~1,507
Gross margin (excluding depreciation and amortization)	~~329~~483			3856			5274			4560		(1		)	—			~~463~~672
Operating Expenses:
Operations and maintenance	~~163~~216		(5)	2132			1216			12		—4			—			~~197~~270
Operations and maintenance—affiliate	82125			1928			1723			1—		—(4		)	—			~~119~~172
Depreciation and amortization	5989			1219			711			1		34			—			82124
Loss on sales of assets, net	—			1			—			—		—			—			1
Impairment losses(6)	94			20			14			—		—			—			128
Total operating expenses	304			53			36			3		3			—			399
Gain on sales of assets, net	—			1			(4		)	—		—			—			(3		)
Operating income (loss)	$	25		$	(15	)	$	16		$	42	$	(4	)	$	—		$	64
Total operating expenses	524			100			60			3		4			—			691
Operating income (loss)	$	(41	)	$	(44	)	$	14		$	57	$	(5	)	$	—		$	(19	)
Total assets at December 31, 2011	$	4,478		$	454		$	135		$	2,012	$	177		$	(667	)	$	6,589

(1) Includes unrealized losses of $39 (42) million and $68(28) million for Eastern PJM and Energy Marketing, respectively.

(2) Includes unrealized gains (losses) of $(39) million, $(1012) million and $5732 million for Eastern PJM, Northeast and Energy Marketing, respectively.

(3) Includes unrealized gains of $29 (18) million for Energy Marketing.

(4) Includes unrealized (gains) losses of $(2718) million, $(21) million and $2918 million for Eastern PJM, Northeast and Energy Marketing, respectively.

(5) Includes $30 million of expense for large scale remediation and settlement costs.

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(in millions)
Operating income (loss) for all segments	$	(59	)	$	29		$	6		$	64
Interest expense	(18		)	(21		)	(36		)	(51		)
Interest expense—affiliate	(2		)	—			(3		)	—
Other, net	—			—			—			(23		)
Income (loss) before income taxes	$	(79	)	$	8		$	(33	)	$	(10	)

(6) Represents impairment losses for the write-off of excess NOx and SO2 emissions allowances as a result of the CSAPR.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
	(in millions)

Operating loss for all segments	$	(43	)	$	(83	)	$	(37	)	$	(19	)
Interest expense	(18		)	(19		)	(54		)	(70		)
Interest expense—affiliate	(1		)	(4		)	(4		)	(4		)
Other, net	—			—			—			(23		)
Loss before income taxes	$	(62	)	$	(106	)	$	(95	)	$	(116	)

8. Litigation and Other Contingencies

We are involved in a number of legal proceedings. In certain cases, plaintiffs seek to recover large or unspecified damages, and some matters may be unresolved for several years. We cannot currently determine the outcome of the proceedings described below or estimate the reasonable amount or range of potential losses, if any, and therefore have not made any provision for such matters unless specifically noted below.

Scrubber Contract Litigation

In January 2011, Stone & Webster, the EPC contractor for the scrubber projects at the Chalk Point, Dickerson and Morgantown generating facilities, filed two suits against GenOn Mid-Atlantic and one suit against GenOn Chalk Point (a subsidiary of GenOn Mid-Atlantic) in the United States District Court for the District of Maryland. Stone & Webster claimed that it had not been paid in accordance with the terms of the EPC agreements for the scrubber projects and sought liens against the properties, which the court granted. We disputed Stone & Webster’s

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Chalk Point (a subsidiary of GenOn Mid-Atlantic) in the United States District Court for the District of Maryland. Stone & Webster claimed that it had not been paid in accordance with the terms of the EPC agreements for the scrubber projects and sought liens against the properties, which the court granted. We disputed Stone & Webster’s allegations and in February 2011 filed a related action against Stone &Webster in the United States District Court for the Southern District of New York. The proceedings in Maryland were stayed pending resolution of the proceeding in New York.

In June 2012, we executed a settlement agreement with Stone & Webster. Under the terms of the settlement agreement GenOn agreed to pay Stone & Webster $107.1 million in settlement of all outstanding invoices and amounts claimed to be owed by Stone & Webster in connection with the construction of the scrubber projects. As part of the settlement, Stone & Webster released the $165.6 million in interlocutory liens that had been filed by Stone & Webster on the Chalk Point, Dickerson and Morgantown generating facilities. As a result of the release of the liens, GenOn Mid-Atlantic released the $165.6 million in reserved cash during June 2012 (previously included as funds on deposit in the consolidated balance sheets). In connection with the settlement agreement, we dismissed our dispute filed in the United States District Court for the Southern District of New York.

We incurred $1.7 billion in capital expenditures from 2007 to 2012 for compliance with the Maryland Healthy Air Act.

Bowline Property Tax Dispute

In 2011, 2010 and 2009 we filed suit against the town of Haverstraw, New York to challenge the property tax assessment of the Bowline generating facility for each respective tax year. Although the assessments for the 2011 and 2010 tax years were reduced significantly from the assessment received in 2009, they continue to exceed significantly the estimated fair value of the generating facility. The tax litigation for all three years has been combined for trial purposes. While we are unable to predict the outcome of this litigation, if we are successful we expect to receive a refund for each of the years under protest.

Environmental Matters

New Source Review Matters. The EPA and various states are investigating compliance of coal-fueled electric generating facilities with the pre-construction permitting requirements of the Clean Air Act known as “new source review.” Since 2000, the EPA has made information requests concerning the Chalk Point, Dickerson, Morgantown and Potomac River generating facilities. We are corresponding or have corresponded with the EPA regarding all of these requests. The EPA agreed to share information relating to its investigations with state environmental agencies.

Maryland Fly Ash Facilities. We have three fly ash facilities in Maryland: Faulkner, Westland and Brandywine. We dispose of fly ash from our Morgantown and Chalk Point generating facilities at Brandywine. We dispose of fly ash from our Dickerson generating facility at Westland. We no longer dispose of fly ash at the Faulkner facility. As described below, the MDE has sued us regarding Faulkner and Brandywine and threatened to sue regarding 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 us 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 we failed to perform certain sampling and reporting required under an applicable NPDES permit. The MDE complaint requested that the court (a) prohibit continuation of the alleged unpermitted discharges, (b) require us to cease from further disposal of any coal combustion byproducts at Faulkner and close and cap the existing disposal cells and (c) assess civil penalties. In July 2008, we 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 us that it intended to file a similar lawsuit in federal court. In May 2011, the MDE filed a complaint against us in the United States 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 (a) certain of our water discharges are not authorized by our existing permit and (b) operation of the Faulkner facility has resulted in discharges of pollutants that violate water quality criteria. The complaint asks the court to, among other things, (a) enjoin further disposal of coal ash;

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existing permit and (b) operation of the Faulkner facility has resulted in discharges of pollutants that violate water quality criteria. The complaint asks the court to, among other things, (a) enjoin further disposal of coal ash; (b) enjoin discharges that are not authorized by our existing permit; (c) require numerous technical studies; (d) impose civil penalties and (e) award MDE attorneys’ fees. We dispute the allegations.

Brandywine Litigation. In April 2010, the MDE filed a complaint against us in the United States District Court for the District of Maryland asserting violations at Brandywine of the Clean Water Act and Maryland’s Water Pollution Control Law. The MDE contends that the operation of Brandywine has resulted in discharges of pollutants that violate Maryland’s water quality criteria. The complaint requests that the court, among other things, (a) enjoin further disposal of coal combustion waste at Brandywine, (b) require us to close and cap the existing open disposal cells within one year, (c) impose civil penalties and (d) award MDE attorneys’ fees. We dispute the allegations. In September 2010, four environmental advocacy groups became intervening parties in the proceeding.

Threatened Westland Litigation. In January 2011, the MDE informed us that it intended to sue us for alleged violations at Westland of Maryland’s water pollution laws. To date, MDE has not sued us regarding our ash disposal.

Permit Renewals. In March 2011, the MDE tentatively determined to deny our application for the renewal of the water discharge permit for Brandywine, which could result in a significant increase in operating expenses for our Chalk Point and Morgantown generating facilities. The MDE also had indicated that it was planning to deny our 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 result in a significant increase in operating expenses for our Dickerson generating facility.

Stay and Settlement Discussions. In June 2011, the MDE agreed to stay the litigation related to Faulkner and Brandywine while we pursued settlement of allegations related to the three Maryland ash facilities. MDE also agreed not to pursue its tentative denial of our application to renew our water discharge permit at Brandywine and agreed not to act on our renewal applications for Faulkner or Westland while we were discussing settlement. As a condition to obtaining the stay, we agreed in principle to pay a civil penalty of $21.59 million (for alleged past violations) to the MDE if we reach a comprehensive settlement regarding all of the allegations related to the three Maryland ash facilities. We accrued $1.9 million during 2011 and an additional $0.6 million ~~during~~(for agreed prospective penalties while we implement the ~~three~~settlement) ~~months~~during ~~ended~~the ~~June 30,~~second quarter of 2012 for a total of $2.5 million. We also developed a technical solution, which includes installing synthetic caps on the closed cells of each of the three ash facilities. During 2011, we accrued $47 million for the estimated cost of the technical solution. We have nearly concluded our settlement discussions with the MDE. ~~We expect to sign a consent decree settling these matters in August 2012.~~ At this time, we cannot reasonably estimate the upper range of our obligations for remediating the sites for the following reasons: (a) we have not finished assessing each site including identifying the full impacts to both ground and surface water and the impacts to the surrounding habitat; (b) we have not finalized with the MDE the standards to which we must remediate; and (c) we have not identified the technologies required, if any, to meet the mandated remediation standards at each site nor the timing of the design and installation of such technologies.

Brandywine Storm Damage and Ash Recovery. As a result of Hurricane Irene and Tropical Storm Lee in August and September 2011, an estimated 8,800 cubic yards of coal fly ash stored in one of the cells at the Brandywine ash disposal site flowed onto 18 acres of private property adjacent to the site. During 2011, we accrued $10 million for the estimated costs to remove and clean up the ash. We have removed the released ash from the private property and ~~are~~completed ~~finalizing~~ the remaining clean-up activities ~~with the MDE and the property owners~~. ~~Nearing~~We ~~completion, we have been able to define more narrowly our costs and have therefore~~ adjusted our estimate and reversed $4 million during the ~~three~~second ~~months~~quarter ~~ended~~of ~~June 30,~~ 2012. WeDuring ~~are~~the ~~pursuing~~third ~~recovery~~quarter ~~under~~of ~~our~~2012, we received $2 million of insurance ~~policies~~proceeds ~~for~~in connection with our claims associated with the costs to remove and clean up the ash.

Brandywine Filling of Wetlands. While expanding and installing a liner at the Brandywine ash disposal site, we inadvertently filled wetlands without having all of the requisite permits. The MDE also has alleged that we violated the notice requirements of our sediment and erosion control plan. In ~~March 2012, the MDE informed us that it was considering seeking a fine in excess of $100,000 to settle the storm damage and the filling of wetlands without requisite permits. In~~ July 2012, the MDE filed a complaint in the Circuit Court for Prince George’s County, Maryland, for civil penalties and injunctive relief in connection

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~~Maryland,~~with ~~for~~the ~~civil~~storm ~~penalties~~damage and ~~injunctive~~the ~~relief~~filling ~~related~~of tothe ~~this matter~~wetlands. We ~~are currently in settlement discussions with the MDE but~~ have agreed ~~in principle~~ to settle ~~this~~these ~~matter~~matters by paying a fine of $300,000.

Ash Disposal Facility Closures. We are responsible for environmental costs related to the future closures of several ash disposal facilities. GenOn Americas Generation has accrued the estimated discounted costs ($15 million and $14 million at ~~June~~September 30, 2012 and December 31, 2011, respectively) associated with these environmental liabilities as part of its asset retirement obligations. GenOn Mid-Atlantic ~~recorded~~has accrued the estimated discounted costs ($13 million and $12 million at ~~June~~September 30, 2012 and December 31, 2011, respectively) associated with these environmental liabilities as part of its asset retirement obligations. These amounts are exclusive of the $47 million accrual for the technical solution for the three ash facilities in Maryland discussed above.

Chapter 11 Proceedings

In July 2003, and various dates thereafter, the Mirant Debtors, including us, filed voluntary petitions in the Bankruptcy Court for relief under Chapter 11 of the United States Bankruptcy Code. GenOn Energy Holdings, we and most of the other Mirant Debtors emerged from bankruptcy on January 3, 2006, when the Plan became effective. The remaining Mirant Debtors emerged from bankruptcy on various dates in 2007. Approximately 461,000 of the shares of GenOn Energy Holdings common stock to be distributed under the Plan have not yet been distributed and have been reserved for distribution with respect to claims disputed by the Mirant Debtors that have not been resolved. Upon the Mirant/RRI Merger, those reserved shares converted into a reserve for approximately 1.3 million shares of GenOn common stock. Under the terms of the Plan, upon the resolution of such a disputed claim, the claimant will receive the same pro rata distributions of GenOn common stock, cash, or both as previously allowed claims, regardless of the price at which the GenOn common stock is trading at the time the claim is resolved. If the aggregate amount of any such payouts results in the number of reserved shares being insufficient, additional shares of GenOn common stock may be issued to address the shortfall.

9. Subsequent Event

The NRG Merger is intended to qualify as a tax-free reorganization under the IRC, as amended, so that none of GenOn, NRG or any of GenOn’s stockholders generally will recognize any gain or loss in the transaction, except that its stockholders will recognize gain with respect to cash received in lieu of fractional shares of NRG common stock.

Completion of the NRG Merger is contingent upon, among other things, (a) approvals by NRG stockholders of the issuance of NRG common stock in the NRG Merger and the approval and adoption of the amendment to NRG’s certificate of incorporation to allow the size of NRG’s board of directors to be increased to 16 in connection with the closing of the NRG Merger, (b) adoption of the NRG Merger Agreement by GenOn’s stockholders, (c) effectiveness of an NRG registration statement on Form S-4 and approval of the New York Stock Exchange listing for the NRG common stock to be issued in the NRG Merger, (d) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, and (e) receipt of all required regulatory approvals, including approvals from the FERC, the Public Utility Commission of Texas, and the New York Public Service Commission (or the determination by the Public Utility Commission of Texas and the New York Public Service Commission that no approval is required).

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termination of the NRG Merger Agreement under specified circumstances, NRG may be required to pay a termination fee of $120 million to GenOn and GenOn may be required to pay NRG a termination fee of $60 million.

We anticipate completing the NRG Merger by the first quarter of 2013. Prior to the completion of the NRG Merger, we and NRG will continue to operate as independent companies. Except for specific references to the pending NRG Merger, the disclosures contained in this report on Form 10-Q relate solely to us. Information concerning the proposed NRG Merger will be included in a joint proxy statement/prospectus contained in the registration statement on Form S-4, which NRG will file with the Securities and Exchange Commission in connection with the NRG Merger.

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ITEM 2. MANAGEMENT’S NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS AND FINANCIAL CONDITION

This section is intended to provide the reader with information that will assist in understanding GenOn Americas Generation’s and GenOn Mid-Atlantic’s interim financial statements, the changes in those financial statements from period to period and the primary factors contributing to those changes. The following discussion should be read in conjunction with GenOn Americas Generation’s and GenOn Mid-Atlantic’s interim financial statements and their 2011 Annual Report on Form 10-K. The results of operations by segment (for GenOn Americas Generation) and critical accounting estimates have been omitted from this Item 2 pursuant to the reduced disclosure format permitted by General Instruction H(2) to Form 10-Q. For discussion on the segments for GenOn Americas Generation, see note 7 to our interim financial statements.

Overview

GenOn Americas Generation is a wholesale generator with ~~approximately~~ 9,~~279~~247 MW of net electric generating capacity located, in many cases, near major metropolitan load centers in the Eastern PJM and Northeast regions and northern California. GenOn Mid-Atlantic is a wholesale generator with ~~approximately 5~~4,~~209~~727 MW of net electric generating capacity located near major metropolitan load centers in the Eastern PJM region. See note 7 to our interim financial statements. GenOn Americas Generation provides GenOn Mid-Atlantic with services that consist primarily of dispatching electricity, hedging the price of electricity we expect to generate, selling capacity and procuring and managing fuel and providing logistical support for the operation of the facilities (for example, by procuring transportation for coal and natural gas). GenOn Americas Generation also operates integrated asset management and proprietary trading operations. Our customers are principally ISOs, RTOs and investor-owned utilities.

Proposed Merger with NRG. On July 20, 2012, GenOn entered into the NRG Merger Agreement with NRG Energy, Inc. and a direct wholly-owned subsidiary of NRG. Upon the terms and subject to the conditions set forth in the NRG Merger Agreement, which has been approved by the boards of directors of GenOn and NRG, a wholly-owned subsidiary of NRG will merge with and into GenOn, with GenOn continuing as the surviving corporation and a wholly owned subsidiary of NRG. See note 1 to our interim financial statements.

Completion of the NRG Merger is contingent upon, among other things, (a) approvals by NRG stockholders of the issuance of NRG common stock in the NRG Merger and the approval and adoption of the amendment to NRG’s certificate of incorporation to allow the size of NRG’s board of directors to be increased to 16 in connection with the closing of the NRG Merger, (b) adoption of the NRG Merger Agreement by GenOn’s stockholders, (c) effectiveness of an NRG registration statement on Form S-4 and approval of the New York Stock Exchange listing for the NRG common stock to be issued in the NRG Merger, (d) expiration or termination of the applicable Hart-Scott-Rodino Act waiting period, and (e) receipt of all required regulatory approvals, including approvals from the FERC, the Public Utility Commission of Texas, and the New York Public Service Commission (or the determination by the Public Utility Commission of Texas and the New York Public Service Commission that no approval is required).

We anticipate completing the NRG Merger by the first quarter of 2013. Prior to the completion of the NRG Merger, we and NRG will continue to operate as independent companies. Except for specific references to the pending NRG Merger, the disclosures contained in this report on Form 10-Q relate solely to us. Information concerning the proposed NRG Merger will be included in a joint proxy statement/prospectus contained in the registration statement on Form S-4, which NRG will file with the Securities and Exchange Commission in connection with the NRG Merger. See note 9 to our interim financial statements.

Hedging Activities

We hedge economically a substantial portion of our PJM coal-fired baseload generation and certain of our other generation (for GenOn Americas Generation). We generally do not hedge our intermediate and peaking units for tenors greater than 12 months. We hedge economically using products which we expect to be effective to mitigate the price risk of our generation. However, as a result of market liquidity limitations, our hedges often are not an exact match for the generation being hedged, and we have some risks resulting from price differentials for different delivery points. In addition, we have risks for implied differences in heat rates when we hedge economically power using natural gas. Currently, a significant portion of our hedges are financial swap transactions between GenOn Mid-Atlantic and financial counterparties that are senior unsecured obligations of GenOn Mid-Atlantic and the counterparties. Some of GenOn Mid-Atlantic’s hedges are executed through an affiliate owned by GenOn Americas Generation. At October 8, 2012, GenOn Americas Generation’s aggregate hedge levels based on expected generation for each year were as follows:

	2012(1)		2013		2014		2015		2016

Power	103	%	86	%	71	%	38	%	27	%
Fuel	94	%	54	%	14	%	4	%	—	%

(1) Percentages represent the period from November through December 2012.

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~~not~~At ~~an exact match for the generation being hedged~~October 8, ~~and we have some risks resulting from price differentials for different delivery points. In addition~~2012, ~~we have risks for implied differences in heat rates when we hedge economically power using natural gas. Currently, a significant portion of our hedges are financial swap transactions between~~ GenOn Mid-Atlantic ~~and financial counterparties that are senior unsecured obligations of GenOn Mid-Atlantic and the counterparties. Some of GenOn Mid-Atlantic~~’s ~~hedges are executed through an affiliate owned by GenOn Americas Generation. At July 9, 2012, GenOn Americas Generation’s~~ aggregate hedge levels based on expected generation for each year were as follows:

	2012(1)		2013		2014		2015		2016
Power	~~109~~106	%	8894	%	4577	%	3541	%	2529	%
Fuel	9096	%	5758	%	1315	%	—4	%	—	%

(1) Percentages represent the period from ~~August~~November through December 2012.

At July 9, 2012, GenOn Mid-Atlantic’s aggregate hedge levels based on expected generation for each year were as follows:

	2012(1)		2013		2014		2015		2016
Power	113	%	98	%	50	%	39	%	27	%
Fuel	92	%	62	%	14	%	—	%	—	%

(1) Percentages represent the period from August through December 2012.

Dodd-Frank Act

The Dodd-Frank Act, which was enacted in July 2010, increases the regulation of transactions involving OTC derivative financial instruments. Under the Dodd-Frank Act, entities defined as “swap dealers” and “major swap participants” will face costly requirements for clearing and posting margin, as well as additional requirements for reporting and business conduct. The CFTC and the United States Securities and Exchange Commission adopted a joint rule further defining the terms “swap dealer” and “major swap participant,” among others. We ~~are~~have ~~currently~~reviewed ~~reviewing~~ the definitions in the rule to determine the impact, if any, on our commercial activity. ~~Although~~ Based on the analysis of our facts and circumstances, we do not ~~expect~~think that our commercial activity toresults ~~result~~ in our designation as a “swap dealer” or “major swap participant,.” Accordingly, we will not be subject to the direct costs and additional reporting and business conduct rules imposed on “swap ~~dealer~~dealers” ~~definition~~and in“major ~~particular~~swap isparticipants.” However, ~~ambiguous~~the inimposition ~~certain~~of ~~respects~~such costs and ~~the~~additional ~~designation~~regulatory asburdens ~~such~~on ~~will~~other bemarket ~~decided~~participants bymay ~~facts~~reduce liquidity in the markets in which we transact and, ~~circumstance~~thus, ~~tests~~may substantially increase the cost of or even limit our ability to effectively hedge.

InCapital ~~addition,~~Expenditures ~~in early July 2012, the “swap” definition~~ and ~~end-user~~Capital exemption final rules were approved by the CFTC and we expect they will be published in the Federal Register soon. Once published, the “swap” definition rule will trigger a 60-day clock for enforceability of some Dodd-Frank Act requirements, including spot-month position limits for designated energy, futures and price-linked swaps. We think ambiguity remains as to electric power ISO/RTO products, including Financial Transmission Rights. Several ISO’s, including PJM, CAISO, ISO-NE and the NYISO, have filed exemption applications with the CFTC; however, the CFTC has not yet responded to their exemption requests. The CFTC extended the exemptive relief from certain provisions of the Commodity Exchange Act to December 31, 2012, or until a date the CFTC may otherwise determine with respect to a particular requirement under the Commodity Exchange Act.Resources

During the nine months ended September 30, 2012, GenOn Americas Generation invested $173 million (of which $151 million relates to GenOn Mid-Atlantic) for capital expenditures, excluding capitalized interest paid. Capital expenditures for the period primarily related to a $107.1 million settlement payment resulting from the scrubber contract litigation, maintenance capital expenditures and the construction of an ash beneficiation facility. We incurred $1.7 billion in capital expenditures from 2007 to 2012 for compliance with the Maryland Healthy Air Act. See note 8 to our interim financial statements for further discussion of the scrubber contract litigation settlement.

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Capital Expenditures and Capital Resources

During the six months ended June 30, 2012, GenOn Americas Generation invested $149 million (of which $134 million relates to GenOn Mid-Atlantic) for capital expenditures, excluding capitalized interest paid. Capital expenditures for the period primarily related to a $107.1 million settlement payment resulting from the scrubber contract litigation, the construction of an ash beneficiation facility and maintenance capital expenditures. We incurred $1.7 billion in capital expenditures from 2007 to 2012 for compliance with the Maryland Healthy Air Act. See note 8 to our interim financial statements for further discussion of the scrubber contract litigation settlement.

The following table details the expected timing of payments for GenOn Americas Generation’s estimated capital expenditures for the remainder of 2012 and 2013:

	July 1, 2012 through December 31, 2012		2013
	October 1, 2012 through December 31, 2012		2013
	(in millions)
Maintenance	$	3615	$	6364
Environmental	74		2111
Construction	4		—3
Total	$	4723	$	8478

The following table details the expected timing of payments for GenOn Mid-Atlantic’s estimated capital expenditures for the remainder of 2012 and 2013:

	July 1, 2012 through December 31, 2012		2013
	October 1, 2012 through December 31, 2012		2013
	(in millions)
Maintenance	$	196	$	4345
Environmental	23		63
Construction	54		—3
Total	$	2613	$	4951

We expect that available cash and future cash flows from operations will be sufficient to fund these capital expenditures. Other environmental capital expenditures set forth above could significantly increase subject to the content and timing of final rules and future market conditions.

We expect industry retirements of coal-fired generating facilities to contribute to a tightening of supply and demand fundamentals and to higher prices for the remaining generating facilities which will more than offset reduced earnings from our unit retirements. ~~Consequently,~~We we expect the resulting higher market prices to provide adequate returns on investment in environmental controls necessary to meet promulgated and anticipated requirements at certain of our facilities. Accordingly, we expect to invest approximately $373 million to $487 million, including $341 million to $452 million ~~for~~at Chalk Point unit 2 and Dickerson at GenOn Mid-Atlantic and $32 million to $35 million at Kendall, over the next ~~ten~~decade ~~years~~ for selective catalytic reduction emissions controls and other major environmental controls to meet certain air and water quality requirements, which we expect to fund from existing sources of liquidity.

Environmental Matters

~~Federal Rules Regarding CO2~~CSAPR. In 2005, ~~light~~the ofEPA promulgated the ~~United~~CAIR, ~~States~~which ~~Supreme~~established ~~Court~~SO2 and ~~ruling~~NOx cap-and-trade programs applicable directly to states and indirectly to generating facilities in ~~Massachusetts~~the veastern United States. The ~~EPA~~NOx cap-and-trade ~~that~~program ~~greenhouse~~has ~~gases~~two ~~fit~~components: ~~within~~an ~~the~~annual ~~Clean~~program ~~Air~~and ~~Act’s~~an ~~definition~~ozone-season ofprogram. The ~~“air~~CAIR ~~pollutant,”~~SO2 cap-and-trade program builds off the ~~EPA~~existing ~~has~~acid ~~proposed~~rain cap-and-trade ~~promulgated~~program ~~regulations~~but ~~regarding~~requires ~~the~~generating ~~emission~~facilities ofto ~~greenhouse~~surrender ~~gases. In~~twice ~~September 2009,~~as ~~the~~many ~~EPA~~allowances ~~issued~~to acover ~~rule~~emissions ~~that~~through 2014 and approximately three times as many

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~~requires~~allowances ~~owners~~starting ~~of facilities~~ in ~~many~~2015. Florida, ~~sectors~~Illinois, ofMaryland, ~~the~~Mississippi, ~~economy~~New Jersey, ~~including~~New ~~power~~York, ~~generation~~Ohio, toPennsylvania ~~report~~and ~~annually~~Virginia are subject to the ~~EPA~~CAIR’s ~~the~~SO2 trading ~~quantity~~program and ~~source~~both ofits ~~greenhouse~~NOx trading ~~gas emissions released from those facilities~~programs. InMassachusetts ~~addition~~is tosubject ~~this~~only ~~reporting~~to ~~requirement,~~ the ~~EPA~~CAIR’s ~~has~~ozone-season ~~promulgated~~NOx trading ~~several rules that address greenhouse gas emissions~~program. InThese ~~December~~cap-and-trade ~~2009,~~programs ~~under~~were ato ~~portion~~be ofimplemented ~~the~~in ~~Clean~~two ~~Air Act that regulates vehicles~~phases, with the ~~EPA~~first ~~determined~~phase ~~that~~going ~~elevated~~into ~~concentrations~~effect ~~of greenhouse gases~~ in ~~the~~2009 ~~atmosphere~~for ~~endanger~~NOx and ~~the~~2010 ~~public’s~~for ~~health~~ SO2 and ~~welfare~~more ~~through~~stringent ~~their~~caps ~~contribution~~going tointo ~~climate~~effect ~~change~~in ~~(Endangerment Finding)~~2015. In ~~April~~July ~~2010~~2008, the ~~EPA~~D.C. ~~finalized~~Circuit ~~a rule to regulate greenhouse gases from vehicles beginning~~ in ~~model~~State ~~year~~of ~~2012~~North ~~(Vehicle~~Carolina ~~Rule)~~v. In ~~April~~Environmental ~~2010,~~Protection ~~the~~Agency ~~EPA also~~ issued ~~its~~an ~~“Reconsideration~~opinion ~~of Interpretation of Regulations~~ that ~~Determine~~would ~~Pollutants~~have ~~Covered~~vacated ~~by Clean Air Act Permitting Programs” (Tailoring Rule), which addresses~~ the ~~scope of pollutants subject to certain permitting requirements under the Clean Air Act as well as when such requirements become effective~~CAIR. ~~The~~Various ~~EPA~~parties ~~has~~filed ~~stated~~requests ~~that,~~for ~~because~~rehearing ofwith the ~~vehicle~~D.C. ~~rule,~~Circuit ~~emissions of greenhouse gases from new stationary sources such as power plants~~ and ~~from~~in ~~major~~December ~~modifications~~2008, tothe ~~such sources are subject to certain Clean Air Act permitting requirements as of January 2011~~D. ~~These~~C. ~~permitting~~Circuit ~~requirements~~issued ~~require~~a ~~such~~second ~~sources~~opinion toin ~~use~~which ~~“best~~it ~~available~~granted ~~control~~rehearing ~~technology”~~only to ~~limit their greenhouse gases. Legal challenges to~~ the ~~Endangerment~~extent ~~Finding,~~that ~~the~~it ~~Vehicle~~remanded ~~Rule and~~ the ~~Tailoring~~case ~~Rule~~to ~~were consolidated and in June 2012,~~ the ~~United~~EPA ~~States~~without ~~Court~~vacating ~~of Appeals for~~ the ~~District of Columbia Circuit denied or dismissed the petitions seeking review of these rules~~CAIR.

In August 2011, the EPA finalized the CSAPR, which was intended to replace the CAIR starting in 2012. In September 2011, we and others asked the D.C. Circuit to stay and vacate the CSAPR because, among other reasons, the rule circumvents the state implementation plan process expressly provided for in the Clean Air Act, affords affected parties no time to install compliance equipment before the compliance period starts and includes numerous material changes from the proposed rule, which deprived parties of an opportunity to provide comments. In December 2011, the court ordered the EPA to stay implementation of the CSAPR and to keep CAIR in place until the court ruled on the legal deficiencies alleged with respect to the CSAPR. The CSAPR would have addressed interstate transport of emissions of NOx and SO2. The CSAPR would have established limitations on NOx and/or SO2 emissions from electric generating units that are (i) greater than 25 megawatts and (ii) located in 28 states (in the eastern half of the United States) that the EPA determined contribute significantly to nonattainment in other states, or to interfere with maintenance in other states, of one or more of three NAAQS: (a) the annual NAAQS for fine particulate matter (PM2.5) promulgated in 1997; (b) the “24-hour” NAAQS for PM2.5 promulgated in 2006 and (c) the ozone NAAQS promulgated in 1997. The CSAPR would have created “emission budgets” for each of the covered states and allocated emissions allowances (denominated in tons of emissions) to each of the 28 states regulated under the CSAPR. In August 2012, the D.C. Circuit issued an opinion vacating the 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.

Federal Rules Regarding CO2. In light of the United States Supreme Court ruling in Massachusetts v. EPA that greenhouse gases fit within the Clean Air Act’s definition of “air pollutant,” the EPA promulgated regulations regarding the emission of greenhouse gases. In September 2009, the EPA issued a rule that requires owners of facilities in many sectors of the economy, including power generation, to report annually to the EPA the quantity and source of greenhouse gas emissions released from those facilities. In addition to this reporting requirement, the EPA has promulgated several rules that address greenhouse gas emissions. In December 2009, under a portion of the Clean Air Act that regulates vehicles, the EPA determined that elevated concentrations of greenhouse gases in the atmosphere endanger the public’s health and welfare through their contribution to climate change (Endangerment Finding). In April 2010, the EPA finalized a rule to regulate greenhouse gases from vehicles beginning in model year 2012 (Vehicle Rule). In April 2010, the EPA also issued its “Reconsideration of Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs” (Tailoring Rule), which addresses the scope of pollutants subject to certain permitting requirements under the Clean Air Act as well as when such requirements become effective. The EPA has stated that, because of the vehicle rule, emissions of greenhouse gases from new stationary sources such as power plants and from major modifications to such sources are subject to certain Clean Air Act permitting requirements as of January 2011. These permitting requirements require such sources to use “best available control technology” to limit their greenhouse gases. Legal challenges to the Endangerment Finding, the Vehicle Rule and the Tailoring Rule were consolidated and in June 2012, the D.C. Circuit denied or dismissed the petitions seeking review of these rules.

In April 2012, the EPA proposed a rule under the New Source Performance Standard section of the Clean Air Act that will limit the CO2 emissions from new fossil-fuel-fired boilers, integrated gasification combined cycle units and stationary combined cycle turbine units greater than 25 MWs. The proposed limit is 1000 pounds of CO2 per MWh, which cannot be achieved by coal-fired units unless technology to capture and store CO2 is installed, which is not commercially available and faces several unresolved legal and regulatory issues. The proposed rule does not apply to simple cycle combustion turbines or existing units. Even though this proposed rule has not been finalized, it is applicable from the time it was proposed unless the EPA issues a final rule that is different or the courts or the United States Congress modify it. We expect the EPA to issue another rule that will require states to develop CO2 standards that would be applicable to existing fossil-fueled generating facilities.

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Canal NPDES and SWD Permit. In August 2008, the EPA renewed the NPDES permit for the Canal generating facility but sought to impose a requirement that the facility install a closed cycle cooling system. The same permit was concurrently issued by MADEP as a state SWD permit. We appealed both the NPDES permit and the SWD permit. In December 2008, the EPA requested a stay to the appeal proceedings, withdrew the provisions related to the closed cycle cooling requirements and re-noticed those provisions for additional public comment. Rather than grant the stay sought by the EPA, the Environmental Appeals Board has dismissed the appeal without prejudice. The parallel MADEP proceeding, which had been stayed, also has been dismissed without prejudice. In the absence of permit renewals, the Canal generating facility will continue to operate under its current NPDES and SWD permits.

Regulatory Matters

State and local regulatory authorities historically have overseen the distribution and sale of electricity at retail to the ultimate end user, as well as the siting, permitting and construction of generating and transmission facilities. In some markets, state regulators have proposed initiatives to provide long-term contracts for new generating capacity in order, among other things, to reduce future capacity prices in PJM.

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PJM. In January 2011, New Jersey enacted legislation which requires the New Jersey Board of Public Utilities to implement a Long Term Capacity Agreement Pilot Program providing for new generating capacity in the state. The new generating capacity would be required to participate and be accepted as a capacity resource in the PJM capacity market. The New Jersey Board of Public Utilities awarded three contracts for new generating capacity as required by the statute. In May 2012, two of the three projects were accepted as a capacity resource in the 2015/2016 RPM capacity auction, while the third project failed to clear the auction. Because the law could have a negative effect on capacity prices in PJM in future years, in February 2011, a group of companies filed suit in the U.S. District Court for the District of New Jersey asking the court to declare the New Jersey legislation unconstitutional. We are not a party to the ongoing proceeding.

In September 2011, the MPSC issued a request for proposal for up to 1,500 MWs of new natural gas-fired generating capacity to be located in the Southwestern Mid-Atlantic Area Council zone of PJM. The order provided for project submittals and a MPSC hearing in January 2012 to determine whether new generating capacity is needed to meet the long-term anticipated demand in Maryland. We filed comments with the MPSC stating there is no need for additional capacity at this time. In April 2012, the MPSC ordered the state’s three public utility companies to enter into a contract with CPV Maryland, LLC for the output of a new 661 MW combined cycle facility in the Southwestern Mid-Atlantic Area Council zone of PJM to be constructed and operational by 2015. The contract required the generating facility be bid into the PJM capacity market in a manner consistent with the PJM tariff. CPV Maryland, LLC bid into the PJM capacity market for the 2015/2016 auction year and cleared the auction. In April 2012, certain companies (not including us) filed in the U.S. District Court for the District of Maryland a complaint for declaratory and injunctive relief barring the implementation of the MPSC order. There have been petitions for judicial review onof the administrative record filed by certain companies (not including us) in various circuit courts in Maryland. It is possible that the MPSC will continue to seek additional contracts for new generating capacity. Such contracts could result in reduced future capacity prices and energy prices in PJM. A number of companies (including us) have publicly indicated that they intend to pursue changes in the PJM auction rules to ensure that future RPM auctions are not adversely affected as a result of such contracting and bidding practices.

Some companies (including us) have publicly indicated that they intend to pursue changes in the PJM auction rules to ensure that future RPM auctions are not adversely affected as a result of such contracting and bidding practices.

Commodity Prices and Generation Volumes

The prices for power and natural gas are low compared to several years ago. The energy gross margin from our baseload coal units is negatively affected by these price levels. For that portion of the volumes of generation that we have hedged, we are generally unaffected by subsequent changes in commodity prices because our realized gross margin will reflect the contractual prices of our power and fuel contracts. We continue to add economic hedges to manage the risks associated with volatility in prices and to achieve more predictable realized gross margin. However, we expect realized gross margin will be lower for 2012 compared with 2011.

We experienced a decrease in power generation volumes during the six months ended June 30, 2012, as compared to the same period in 2011, particularly in GenOn Americas Generation’s Eastern PJM segment (GenOn Mid-Atlantic). The decrease in generation occurred primarily at our coal-fired facilities and was caused by a combination of unseasonably mild weather and contracting dark spreads resulting from decreasing natural gas prices. Consequently, we have significant coal inventories at our generating facilities, and in the case of our GenOn Mid-Atlantic facilities, such inventories were at the maximum available storage capacity of such facilities. In April 2012, we issued notices of force majeure under the respective coal contracts as it was impossible for us to take coal at such facilities. Recently we issued notices to the affected coal suppliers that the force majeure conditions have abated and, accordingly, we expect to resume shipments in accordance with the coal contracts. A number of the suppliers disputed our invocation of force majeure. In our communications with the affected coal suppliers, we have advised them that we expect to take all the coal for which we have contracted, at the contracted prices, as we are able to do so.

Capacity Sales

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~~July~~hedges 9,to ~~2012,~~manage ~~total~~the ~~projected~~risks ~~contracted~~associated ~~capacity~~with ~~and~~volatility ~~PPA~~in ~~revenues for which~~ prices ~~have~~and ~~been~~to ~~set~~achieve ~~for~~more ~~the~~predictable ~~last~~realized ~~six~~gross ~~months~~margin. However, ofwe ~~2012~~expect ~~and~~realized ~~2013-2016~~gross ~~are~~margin ~~$1.3~~will ~~billion~~be ~~and~~lower ~~$1.0 billion~~ for ~~GenOn~~2012 ~~Americas~~compared ~~Generation~~with ~~and GenOn Mid-Atlantic, respectively~~2011.

We experienced a decrease in power generation volumes during the nine months ended September 30, 2012, as compared to the same period in 2011, particularly in GenOn Americas Generation’s Eastern PJM segment (GenOn Mid-Atlantic). The decrease in generation occurred at our coal-fired facilities and was caused primarily by contracting dark spreads resulting from decreasing natural gas prices. Consequently, we have significant coal inventories at our generating facilities, and in the case of our GenOn Mid-Atlantic facilities, such inventories were at the maximum available storage capacity of such facilities. In April 2012, we issued notices of force majeure under the respective coal contracts as it was impossible for us to take coal at such facilities. Recently we issued notices to the affected coal suppliers that the force majeure conditions have abated and, accordingly, we resumed shipments in accordance with the coal contracts. A number of the suppliers disputed our invocation of force majeure. In our communications with the affected coal suppliers, we have advised them that we expect to take all the coal for which we have contracted, at the contracted prices, as we are able to do so.

Capacity Sales

Capacity sales, whether made bilaterally or through periodic auction processes in the ISO and RTO markets in which we participate, provide an important source of predictable revenues for us over the contracted periods. At October 8, 2012, total projected contracted capacity and PPA revenues for which prices have been set for the last three months of 2012 and 2013-2016 are $1.2 billion and $969 million for GenOn Americas Generation and GenOn Mid-Atlantic, respectively.

Results of Operations

Non-GAAP Performance Measures. The following discussion includes the non-GAAP financial measures realized gross margin and unrealized gross margin to reflect how we manage our business. In our discussion of the results, we include the components of realized gross margin, which are energy, contracted and capacity, and realized value of hedges. Management generally evaluates our operating results excluding the impact of unrealized gains and losses. When viewed with our GAAP financial results, these non-GAAP financial measures may provide a more complete understanding of factors and trends affecting our business. Realized gross margin represents our gross margin (excluding depreciation and amortization) less unrealized gains and losses on derivative financial instruments. Conversely, unrealized gross margin represents our unrealized gains and losses on derivative financial instruments. None of our derivative financial instruments recorded at fair value is designated as a hedge and changes in their fair values are recognized currently in income as unrealized gains or losses. As a result, our financial results are, at times, volatile and subject to fluctuations in value primarily because of changes in forward electricity and fuel prices. Realized gross margin, together with its components energy, contracted and capacity, and realized value of hedges, provide a measure of performance that eliminates the volatility reflected in unrealized gross margin, which is created by significant shifts in market values between periods.

We use these non-GAAP financial measures in communications with investors, analysts, rating agencies, banks and other parties. We think these non-GAAP financial measures provide meaningful representations of our consolidated operating performance and are useful to us and others in facilitating the analysis of our results of operations from one period to another. We encourage our investors to review our financial statements and other publicly filed reports in their entirety and not to rely on a single financial measure.

The foregoing non-GAAP financial measures may not be comparable to similarly titled non-GAAP financial measures used by other companies.

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Three Months Ended ~~June~~September 30, 2012 Compared to Three Months Ended ~~June~~September 30, 2011

GenOn Americas Generation

We reported a net loss of $7962 million and ~~net income of~~ $8106 million during the three months ended ~~June~~September 30, 2012 and 2011, respectively. The change in net ~~income/~~loss is detailed as follows:

	Three Months Ended June 30,						Increase/
	Three Months Ended September 30,						Increase/
	2012			2011			(Decrease)
	(in millions)
Gross margin:
Energy	$	3090		$	8071		$	~~(50~~19	)
Contracted and capacity	90100			~~105~~89			~~(15~~11		)
Realized value of hedges	8853			6349			254
Total realized gross margin	~~208~~243			~~248~~209			~~(40~~34		)
Unrealized gross margin	(~~107~~117		)	1—			(~~108~~117		)
Total gross margin (excluding depreciation and amortization)	~~101~~126			~~249~~209			(~~148~~83		)
Operating expenses:
Operations and maintenance	5971			~~118~~73			(592		)
Operations and maintenance—affiliate	6157			5953			24
Depreciation and amortization	41			42			(1		)
Gain on sales of assets, net	(1		)	—			(1		)
Impairment losses	—			128			(128		)
Loss on sales of assets, net—affiliate	—			1			(1		)
Gain on sales of assets, net	—			(6		)	6
Total operating expenses	160			220			(60		)
Loss on sales of assets, net—affiliate	—			2			(2		)
Operating income (loss)	(59		)	29			(88		)
Total operating expenses	169			292			(123		)
Operating loss	(43		)	(83		)	40
Other expense, net:
Interest expense, net	(18		)	(2119		)	(31		)
Interest expense, net—affiliate	(21		)	—(4		)	23
Total other expense, net	(2019		)	(2123		)	(14		)
Net income (loss)	$	(79	)	$	8		$	(87	)
Net loss	$	(62	)	$	(106	)	$	44

Realized Gross Margin. For a discussion of realized gross margin, see “~~Six~~Nine Months Ended ~~June~~September 30, 2012 Compared to ~~Six~~Nine Months Ended ~~June~~September 30, 2011—GenOn Americas Generation—Realized Gross Margin.”

During the three months ended ~~June~~September 30, 2012, our realized gross margin ~~decrease~~increase of $4034 million was principally a result of the following:

· $5019 million ~~decrease~~increase in energy primarily as a result of (a) aan $2511 million ~~decrease~~increase resulting from ~~reduced~~increased generation volumes for gas-fired units as a result of ~~contracting~~expanding ~~dark~~spark spreads ~~for our coal-fired units~~, partially offset by ana ~~increase~~decrease in generation volumes for ~~our gas~~coal-fired units as a result of ~~expanding~~contracting ~~spark~~dark spreads and (b) aan $258 million ~~decrease~~increase in our Energy Marketing segment primarily as a result of decreases in ~~income~~losses from ~~proprietary~~fuel ~~trading;~~oil ~~and~~management activities;

· $1511 million ~~decrease~~increase in contracted and capacity primarily ~~from~~as ~~lower~~a result of higher capacity prices in Eastern PJM; ~~partially offset by~~and

· $254 million increase in realized value of hedges, primarily as a result of a $4134 million increase in power hedges resulting from lower prices, partially offset by a $1431 million decrease in coal hedges resulting from lower prices.

Unrealized Gross Margin. Unrealized gross margin represents the net unrealized gain or loss on our derivative contracts, including the reversal of unrealized gains and losses recognized in prior periods and changes in value for

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· unrealized losses of $~~107~~117 million during the three months ended ~~June~~September 30, 2012, which included a $6863 million net decrease in the value of hedge and proprietary trading contracts for future periods and $54 million associated with the reversal of previously recognized unrealized gains from power and fuel contracts that settled during the period ~~and a $39 million net decrease in the value of hedge and proprietary trading contracts for future periods~~. The decrease in value was primarily related to ~~decreases~~increases in forward ~~coal~~power ~~prices~~ and ~~the~~natural ~~recognition~~gas ~~of certain coal agreements at fair value beginning in May 2012~~prices, partially offset by ~~decreases~~increases in forward ~~power~~coal ~~and natural gas~~ prices ~~in future years~~; and

· unrealized gains or losses of $~~1 million~~0 during the three months ended ~~June~~September 30, 2011, which included a $5739 million net increase in the value of hedge and proprietary trading contracts for future periods, offset by $5639 million associated with the reversal of previously recognized unrealized gains from power and fuel contracts that settled during the period.

Operating Expenses. ~~Our~~The decrease of $123 million in operating expenses ~~decrease~~was primarily the result of a $60128 million ~~was~~decrease ~~principally~~in impairment losses for the write-off of excess NOx and SO2 emissions allowances as a result of the ~~following:~~CSAPR recorded in 2011.

~~· $57~~GenOn ~~million decrease in operations and maintenance expense primarily related to the following:~~Mid-Atlantic

~~· $33~~We ~~million~~reported ~~change~~a innet ~~large~~loss ~~scale~~of ~~remediation~~$29 million and ~~settlement costs as we accrued~~ $30 69 million ~~for~~during ~~remediation~~the ~~costs~~three atmonths ~~our~~ended ~~Maryland~~September 30, ~~ash~~2012 ~~facilities~~and in 2011, ~~and~~respectively. The ~~reversed~~decrease ain net $3loss ~~million~~is indetailed ~~2012;~~as follows:

· $31 million reversal of the previously recorded Potomac River obligation under the 2008 agreement with the City of Alexandria; partially offset by

	Three Months Ended September 30,						Increase/
	2012			2011			(Decrease)
	(in millions)
Gross margin:
Energy	$	73		$	63		$	10
Contracted and capacity	61			54			7
Realized value of hedges	55			49			6
Total realized gross margin	189			166			23
Unrealized gross margin	(91		)	(12		)	(79		)
Total gross margin (excluding depreciation and amortization)	98			154			(56		)
Operating expenses:
Operations and maintenance	54			53			1
Operations and maintenance—affiliate	42			43			(1		)
Depreciation and amortization	30			30			—
Impairment losses	—			94			(94		)
Total operating expenses	126			220			(94		)
Operating loss	(28		)	(66		)	38
Other expense, net:
Interest expense, net—affiliate	(1		)	(3		)	2
Total other expense, net	(1		)	(3		)	2
Net loss	$	(29	)	$	(69	)	$	40

~~· $11~~Realized ~~million~~Gross ~~reversal~~Margin. For ofa ~~Montgomery~~discussion ~~County~~of ~~Carbon~~realized ~~levy~~gross ~~assessment~~margin, insee ~~2011,~~“Nine ~~which~~Months ~~included~~Ended $8September ~~million~~30, ~~related~~2012 Compared to ~~the~~Nine ~~refund~~Months ~~received~~Ended inSeptember ~~the~~30, ~~third~~2011—GenOn ~~quarter~~Mid-Atlantic—Realized ofGross ~~2011~~Margin.”

~~Interest~~During ~~Expense,~~the ~~Net. Interest~~three ~~expense~~months ended September 30, ~~net~~2012, ~~decrease~~our ofrealized $3gross ~~million~~margin ~~related~~increase toof ~~lower~~$23 ~~interest~~million ~~expense~~was asprincipally a result of ~~repayment~~the ~~in 2011 of GenOn Americas Generation senior unsecured notes.~~following:

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~~GenOn~~· $10 ~~Mid~~million increase in energy, primarily as a result of an increase in generation volumes for gas-~~Atlantic~~fired units as a result of expanding spark spreads, partially offset by a decrease in generation volumes for coal-fired units as a result of contracting dark spreads;

~~We reported a net loss of~~ · $~~58 million and $~~7 million ~~during~~increase ~~the~~in ~~three~~contracted ~~months ended June 30, 2012~~ and ~~2011,~~capacity ~~respectively. The~~primarily ~~increase~~as ina ~~net~~result ~~loss~~of ishigher ~~detailed~~capacity asprices; ~~follows:~~and

	Three Months Ended June 30,						Increase/
	2012			2011			(Decrease)
	(in millions)
Gross margin:
Energy	$	29		$	47		$	(18	)
Contracted and capacity	52			66			(14		)
Realized value of hedges	87			66			21
Total realized gross margin	168			179			(11		)
Unrealized gross margin	(113		)	(12		)	(101		)
Total gross margin (excluding depreciation and amortization)	55			167			(112		)
Operating expenses:
Operations and maintenance	39			101			(62		)
Operations and maintenance—affiliate	43			42			1
Depreciation and amortization	30			30			—
Gain on sales of assets, net	(1		)	—			(1		)
Total operating expenses	111			173			(62		)
Operating loss	(56		)	(6		)	(50		)
Other expense, net:
Interest expense, net	(1		)	(1		)	—
Interest expense, net—affiliate	(1		)	—			1
Total other expense, net	(2		)	(1		)	1
Net loss	$	(58	)	$	(7	)	$	(51	)

· $6 million increase in realized value of hedges, primarily as a result of a $36 million increase in power hedges primarily resulting from lower prices, partially offset by a $31 million decrease in coal hedges resulting from lower prices.

Realized Gross Margin. For a discussion of realized gross margin, see “Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011—GenOn Mid-Atlantic—Realized Gross Margin.”

During the three months ended June 30, 2012, our realized gross margin decrease of $11 million was principally a result of the following:

· $18 million decrease in energy, primarily as a result of a decrease in generation volumes for coal-fired units as a result of contracting dark spreads, partially offset by an increase in generation volumes for gas-fired units as a result of expanding spark spreads; and

· $14 million decrease in contracted and capacity primarily as a result of lower capacity prices; partially offset by

· $21 million increase in realized value of hedges, primarily as a result of a $35 million increase in power hedges primarily resulting from lower prices, partially offset by a $14 million decrease in coal hedges resulting from lower prices.

Unrealized Gross Margin. Unrealized gross margin represents the net unrealized gain or loss on our derivative contracts, including the reversal of unrealized gains and losses recognized in prior periods and changes in value for future periods. Our unrealized gross margin for both periods reflects the following:

· unrealized losses of $~~113~~91 million during the three months ended ~~June~~September 30, 2012, which included $7352 million associated with the reversal of previously recognized unrealized gains from power and fuel contracts that settled during the period and a $4039 million net decrease in the value of hedge contracts for future periods. The decrease in value was primarily related to ~~decreases~~increases in forward ~~coal~~power and natural gas prices, ~~and~~partially ~~the~~offset ~~recognition~~by ofincreases in forward coal prices; and

· unrealized losses of $12 million during the three months ended September 30, 2011, which included $41 million associated with the reversal of previously recognized unrealized gains from power and fuel contracts that settled during the period, partially offset by a $29 million net increase in the value of hedge contracts for future periods. The increase in value primarily related to decreases in forward power and natural gas prices.

Operating Expenses. The decrease of $94 million in operating expenses was primarily the result of a $94 million decrease in impairment losses for the write-off of excess NOx and SO2 emissions allowances as a result of the CSAPR recorded in 2011.

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certain coal agreements at fair value beginning in May 2012, partially offset by decreases in forward power and natural gas prices in future years; and

· unrealized losses of $12 million during the three months ended June 30, 2011, which included $60 million associated with the reversal of previously recognized unrealized gains from power and fuel contracts that settled during the period, partially offset by a $48 million net increase in the value of hedge contracts for future periods. The increase in value primarily related to decreases in forward power and natural gas prices and increases in forward coal prices.

Operating Expenses. Our operating expenses decrease of $62 million was principally a result of the following:

· $61 million decrease in operations and maintenance expense primarily related to the following:

· $33 million change in large scale remediation and settlement costs as we accrued $30 million for remediation costs at our Maryland ash facilities in 2011 and reversed a net $3 million in 2012;

· $31 million reversal of the previously recorded Potomac River obligation under the 2008 agreement with the City of Alexandria; partially offset by

· $11 million reversal of Montgomery County Carbon levy assessment in 2011, which included $8 million related to the refund received in the third quarter of 2011.

Operating Statistics

The following table summarizes power generation volumes by segment for GenOn Americas Generation:

	Three Months Ended June 30,		Increase/		Increase/
	Three Months Ended September 30,		Increase/		Increase/
	2012	2011	(Decrease)		(Decrease)(1)
	(in gigawatt hours)
Eastern PJM:
Baseload	12,~~374~~795	23,~~612~~024	(~~1,238~~229	)	(478	)%
Intermediate	~~1,366~~793	~~242~~456	~~1,124~~337		NM74	%
Peaking	4571	2957	1614		5525	%
Total Eastern PJM	23,~~785~~659	23,~~883~~537	~~(98~~122	)	(3	)%
Northeast:
Baseload	~~347~~380	~~374~~301	~~(27~~79	)	(726	)%
Intermediate	30282	47164	~~(17~~118	)	~~(36~~72	)%
Peaking	19	18	—1		013	%
Total Northeast	~~378~~671	~~422~~473	~~(44~~198	)	~~(10~~42	)%
California:
Intermediate	38129	4128	(3101	)	(7NM	)%
Total California	38129	4128	(3101	)	(7NM	)%
Total	34,~~201~~459	34,~~346~~038	~~(145~~421	)	(410	)%

(1) NM means not meaningful.

GenOn Mid-Atlantic’s power generation volumes for the three months ended September 30, 2012 were 3,659 gigawatt hours compared to 3,537 gigawatt hours during the same period in 2011.

The total increase in power generation volumes during the three months ended September 30, 2012, as compared to the same period in 2011, is explained by segment below.

Eastern PJM. The net increase in generation volumes results from an increase in our intermediate and peaking generation volumes for gas-fired units primarily as a result of expanding spark spreads and a decrease in our baseload generation unplanned outages, partially offset by a decrease in our baseload generation volumes primarily as a result of contracting dark spreads for coal-fired units.

Northeast. The increase in generation volumes was primarily as a result of reduced outages and expanding spark spreads.

California. The increase in generation volumes was primarily as a result of expanding spark spreads.

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~~GenOn~~Nine ~~Mid-Atlantic’s~~Months ~~power~~Ended ~~generation volumes for the three months ended June~~September 30, 2012 ~~were~~Compared ~~2,785~~to ~~gigawatt~~Nine ~~hours~~Months ~~compared~~Ended ~~to 2~~September 30,~~883~~ ~~gigawatt hours during the same period in~~ 2011.

The total decrease in power generation volumes during the three months ended June 30, 2012, as compared to the same period in 2011, is explained by segment below.

Eastern PJM. The net decrease in generation volumes results from a decrease in our baseload generation volumes primarily as a result of contracting dark spreads for coal-fired unites, offset in part by an increase in our intermediate generation volumes for gas-fired units primarily as a result of expanding spreads.

Northeast. The decrease in generation volumes was primarily as a result of an outage at one of our generating facilities.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

GenOn Americas Generation

We reported a net loss of $3395 million and $10116 million during the ~~six~~nine months ended ~~June~~September 30, 2012 and 2011, respectively. The ~~increase~~decrease in net loss is detailed as follows:

	Six Months Ended June 30,						Increase/
	Nine Months Ended September 30,						Increase/
	2012			2011			(Decrease)
	(in millions)
Gross margin:
Energy	$	14104		$	~~177~~248		$	(~~163~~144	)
Contracted and capacity	~~175~~275			~~226~~315			(5140		)
Realized value of hedges	~~215~~268			~~130~~179			8589
Total realized gross margin	~~404~~647			~~533~~742			(~~129~~95		)
Unrealized gross margin	(58175		)	(70		)	12(105		)
Total gross margin (excluding depreciation and amortization)	~~346~~472			~~463~~672			(~~117~~200		)
Operating expenses:
Operations and maintenance	~~141~~212			~~197~~270			(5658		)
Operations and maintenance—affiliate	~~119~~176			~~119~~172			—4
Depreciation and amortization	81122			82124			(12		)
Gain on sales of assets, net	(1		)	—			(1		)
Impairment losses	—			128			(128		)
Loss on sales of assets, net—affiliate	—			1			(1		)
Gain on sales of assets, net	(1		)	(5		)	4
Total operating expenses	340			399			(59		)
Loss on sales of assets, net—affiliate	—			2			(2		)
Operating income	6			64			(58		)
Total operating expenses	509			691			(182		)
Operating loss	(37		)	(19		)	(18		)
Other expense, net:
Interest expense, net	(3654		)	(5170		)	~~(15~~16		)
Interest expense, net—affiliate	(34		)	—(4		)	3—
Other, net	—			(23		)	(23		)
Total other expense, net	(3958		)	(7497		)	~~(35~~39		)
Net loss	$	(3395	)	$	(10116	)	$	~~(23~~21	)

Realized Gross Margin. Our realized gross margin consists of energy, contracted and capacity and realized value of hedges. Energy represents gross margin from the generation of electricity, fuel sales and purchases at market prices, fuel handling, steam sales and our proprietary trading and fuel oil management activities. Contracted and capacity represents gross margin received from capacity sold in ISO and RTO administered capacity markets, reliability-must-run arrangements (which we had at Potrero through February 2011), PPAs and tolling agreements, and ancillary services. Realized value of hedges represents the actual margin upon the settlement of our power and fuel hedging contracts and the difference between market prices and contract costs for fuel. Power hedging contracts include sales of both power and natural gas used to hedge power prices, as well as hedges to capture the incremental value related to the geographic location of our physical assets.

During the nine months ended September 30, 2012, our realized gross margin decrease of $95 million was principally a result of the following:

· $144 million decrease in energy primarily as a result of (a) a $83 million decrease resulting from reduced generation volumes as a result of contracting dark spreads for our coal-fired units, partially offset by an increase in generation volumes for our gas-fired units as a result of expanding spark spreads, (b) $13 million increase in lower of cost or market inventory adjustments, net and (c) a $48 million decrease in our

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~~contracts~~Energy ~~include~~Marketing ~~sales~~segment ofprimarily ~~both power and natural gas used to hedge power prices,~~ as ~~well~~a asresult ~~hedges~~of todecreases ~~capture~~in ~~the~~income ~~incremental~~from ~~value~~proprietary ~~related~~trading toand ~~the~~fuel ~~geographic~~oil ~~location~~management ofactivities; ~~our physical assets.~~and

~~During~~· $40 ~~the~~million ~~six~~decrease ~~months~~in ~~ended~~contracted ~~June 30,~~and ~~2012,~~capacity ~~our~~primarily ~~realized~~from ~~gross~~lower ~~margin~~capacity ~~decrease~~prices ofin ~~$129~~Eastern ~~million~~PJM; ~~was~~partially ~~principally~~offset ~~a result of the following:~~by

· $~~163~~89 million ~~decrease~~increase in ~~energy~~realized ~~primarily~~value ~~as a result~~ of ~~(a) a~~hedges, ~~$87~~primarily ~~million decrease resulting from reduced generation volumes~~ as a result of ~~contracting dark spreads for our coal-fired units, partially offset by an increase in generation volumes for our gas-fired units as~~ a ~~result of expanding spark spreads, (b)~~ $20148 million increase in ~~lower~~power ofhedges ~~cost~~resulting orfrom ~~market~~lower ~~inventory adjustments~~prices, ~~net~~partially ~~and~~offset ~~(c)~~ by a $5759 million decrease in ~~our~~coal ~~Energy~~and ~~Marketing~~gas ~~segment~~hedges ~~primarily~~resulting ~~as a result of decreases in income~~ from ~~proprietary~~lower ~~trading and fuel oil management activities; and~~prices.

· $51 million decrease in contracted and capacity primarily from lower capacity prices in Eastern PJM; partially offset by

· $85 million increase in realized value of hedges, primarily as a result of a $114 million increase in power hedges resulting from lower prices, partially offset by a $23 million decrease in coal hedges resulting from lower prices.

· unrealized losses of $58175 million during the ~~six~~nine months ended ~~June~~September 30, 2012, which included $~~171~~225 million associated with the reversal of previously recognized unrealized gains from power and fuel contracts that settled during the period. The decrease was offset by a $~~113~~50 million net increase in the value of hedge and proprietary trading contracts for future periods primarily related to decreases in forward power and natural gas prices, offset by decreases in forward coal prices; and

· unrealized losses of $70 million during the ~~six~~nine months ended ~~June~~September 30, 2011, which included $~~123~~162 million associated with the reversal of previously recognized unrealized gains from power and fuel contracts that settled during the period, offset by a $5392 million net increase in the value of hedge and proprietary trading contracts for future periods. The increase in value was primarily related to decreases in forward power and natural gas prices and increases in forward coal prices.

Operating Expenses. Our operating expenses decrease of $59182 million was principally a result of the following:

· $56128 million decrease in ~~operations~~impairment losses for the write-off of excess NOx and ~~maintenance~~SO2 ~~expense~~emissions ~~primarily~~allowances ~~related~~as toa result of the ~~following:~~CSAPR recorded in 2011; and

· $3354 million ~~change~~decrease in ~~large~~operations ~~scale remediation~~ and ~~settlement~~maintenance ~~costs~~expense asprimarily werelated ~~accrued~~to ~~$30~~the ~~million for remediation costs at our Maryland ash facilities in 2011 and reversed a net $3 million in 2012; and~~following:

· $3135 million ~~reversal~~change ofin ~~the~~large ~~previously~~scale ~~recorded~~remediation ~~Potomac~~and ~~River~~settlement ~~obligation~~costs ~~under~~as ~~the~~we ~~2008~~accrued ~~agreement~~$30 ~~with~~million ~~the~~for ~~City~~remediation ofcosts ~~Alexandria;~~at ~~partially~~our ~~offset~~Maryland byash facilities in 2011 and reversed $6 million in 2012;

· $831 million reversal of ~~Montgomery~~the ~~County~~previously ~~Carbon levy assessment~~ recorded inPotomac ~~2011,~~River ~~which~~obligation ~~included~~under ~~$8 million related to~~ the ~~refund~~2008 ~~received~~agreement inwith the ~~third~~City ~~quarter~~ of ~~2011.~~Alexandria; and

~~Interest Expense, Net. Interest expense, net decrease of~~ · $158 million ~~related~~decrease toin ~~lower~~major ~~interest~~litigation ~~expense~~costs, asnet ~~a result~~ of ~~repayment~~recoveries; inpartially ~~2011~~offset ~~of GenOn Americas Generation senior unsecured notes.~~by

· $8 million reversal of Montgomery County Carbon levy assessment recorded in 2011; and

· $6 million resulting from changes in asset retirement obligation assumptions in 2011.

Interest Expense, Net. Interest expense, net decrease of $16 million primarily related to lower interest expense as a result of repayment in 2011 of GenOn Americas Generation senior unsecured notes.

Other, Net. Other, net change of $23 million was a result of loss on early extinguishment of debt primarily related to a $16 million premium and a $7 million write-off of unamortized debt issuance costs related to the GenOn North America senior notes that were repaid in 2011.

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GenOn Mid-Atlantic

We reported a net ~~income~~loss of $1415 million and $2445 million during the ~~six~~nine months ended ~~June~~September 30, 2012 and 2011, respectively. The decrease in net income is detailed as follows:

	Six Months Ended June 30,						Increase/
	Nine Months Ended September 30,						Increase/
	2012			2011			(Decrease)
	(in millions)
Gross margin:
Energy	$	1487		$	~~108~~171		$	(9484	)
Contracted and capacity	~~101~~162			~~143~~197			(4235		)
Realized value of hedges	~~216~~271			~~129~~178			8793
Total realized gross margin	~~331~~520			~~380~~546			(4926		)
Unrealized gross margin	(71162		)	(5163		)	(2099		)
Total gross margin (excluding depreciation and amortization)	~~260~~358			~~329~~483			(69125		)
Operating expenses:
Operations and maintenance	~~102~~156			~~163~~216			(6160		)
Operations and maintenance—affiliate	83125			82125			1—
Depreciation and amortization	5989			5989			—
Impairment losses	—			94			(94		)
Gain on sales of assets, net	(1		)	—			(1		)
Total operating expenses	~~243~~369			~~304~~524			(61155		)
Operating income	17			25			(8		)
Operating loss	(11		)	(41		)	30
Other expense, net:
Interest expense, net	(1		)	(1		)	—
Interest expense, net—affiliate	(23		)	—(3		)	2—
Total other expense, net	(34		)	(14		)	2—
Net income	$	14		$	24		$	(10	)
Net loss	$	(15	)	$	(45	)	$	30

Realized Gross Margin. Our realized gross margin consists of energy, contracted and capacity and realized value of hedges. Energy represents gross margin from the generation of electricity, fuel sales and purchases at market prices and fuel handling. Contracted and capacity represents gross margin received from capacity and ancillary services sold in the PJM market. Realized value of hedges represents the actual margin upon the settlement of our power and fuel hedging contracts and the difference between market prices and contract costs for fuel. Power hedging contracts include sales of both power and natural gas used to hedge power prices, as well as hedges to capture the incremental value related to the geographic location of our physical assets.

During the ~~six~~nine months ended ~~June~~September 30, 2012, our realized gross margin decrease of $4926 million was principally a result of the following:

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· $9484 million decrease in energy primarily as a result of (a) a $7471 million decrease resulting from reduced generation volumes as a result of contracting dark spreads for our coal-fired units, partially offset by an increase in generation volumes for our gas-fired units as a result of expanding spark spreads and (b) $2013 million increase in lower of cost or market inventory adjustments, net; and

· $4235 million decrease in contracted and capacity primarily as a result of lower capacity prices; partially offset by

· $8793 million increase in realized value of hedges, primarily as a result of a $~~111~~148 million increase in power hedges primarily resulting from lower prices, partially offset by a $2355 million decrease in coal and gas hedges resulting from lower prices.

· unrealized losses of $71162 million during the ~~six~~nine months ended ~~June~~September 30, 2012, which included $~~174~~226 million associated with the reversal of previously recognized unrealized gains from power and fuel contracts that settled during the period. The decrease was offset by a $~~103~~64 million net increase in the value of hedge contracts for future periods primarily related to decreases in forward power and natural gas prices, offset by decreases in coal prices; and

· unrealized losses of $5163 million during the ~~six~~nine months ended ~~June~~September 30, 2011, which included $~~114~~155 million associated with the reversal of previously recognized unrealized gains from power and fuel contracts that settled during the period, offset by a $6392 million net increase in the value of hedge contracts for future periods. The increase in value was primarily related to decreases in forward power and natural gas prices and increases in forward coal prices.

Operating Expenses. Our operating expenses decrease of $61155 million was principally a result of the following:

· $94 million decrease in impairment losses for the write-off of excess NOx and SO2 emissions allowances as a result of the CSAPR recorded in 2011; and

· $60 million decrease in operations and maintenance expense primarily related to the following:

· $3335 million change in large scale remediation and settlement costs as we accrued $30 million for remediation costs at our Maryland ash facilities in 2011 and reversed ~~a net~~ $36 million in 2012; and

· $31 million reversal of the previously recorded Potomac River obligation under the 2008 agreement with the City of Alexandria; ~~partially offset by~~and

· $8 million ~~reversal~~decrease ofin ~~Montgomery~~major ~~County~~litigation ~~Carbon levy assessment recorded in 2011~~costs, ~~which~~net ~~included~~of $8recoveries; ~~million~~partially ~~related~~offset ~~to the refund received in the third quarter of 2011.~~by

· $8 million reversal of Montgomery County Carbon levy assessment recorded in 2011; and

· $6 million resulting from changes in asset retirement obligation assumptions in 2011.

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Operating Statistics

The following table summarizes power generation volumes by segment for GenOn Americas Generation:

	Six Months Ended June 30,		Increase/		Increase/
	Nine Months Ended September 30,		Increase/		Increase/
	2012	2011	(Decrease)		(Decrease)(1)
	(in gigawatt hours)
Eastern PJM:
Baseload	25,~~606~~401	69,~~123~~147	(3,~~517~~746	)	(5741	)%
Intermediate	12,~~590~~383	~~263~~719	1,~~327~~664		NM
Peaking	55126	43100	1226		2826	%
Total Eastern PJM	47,~~251~~910	69,~~429~~966	(2,~~178~~056	)	(3421	)%
Northeast:
Baseload	~~689~~1,069	~~753~~1,054	~~(64~~15	)	(81	)%
Intermediate	35317	67231	~~(32~~86	)	~~(48~~37	)%
Peaking	110	19	—1		011	%
Total Northeast	~~725~~1,396	~~821~~1,294	~~(96~~102	)	~~(12~~8	)%
California:
Intermediate	46175	5280	(695	)	~~(12~~119	)%
Total California	46175	5280	(695	)	~~(12~~119	)%
Total	59,~~022~~481	711,~~302~~340	(21,~~280~~859	)	(3116	)%

(1) NM means not meaningful.

GenOn Mid-Atlantic’s power generation volumes for the ~~six~~nine months ended ~~June~~September 30, 2012 were 47,~~251~~910 gigawatt hours compared to 69,~~429~~966 gigawatt hours during the same period in 2011.

The total decrease in power generation volumes during the ~~six~~nine months ended ~~June~~September 30, 2012, as compared to the same period in 2011, is explained by segment below.

Eastern PJM. The net decrease in generation volumes results from a decrease in our baseload generation volumes primarily as a result of contracting dark spreads for coal-fired ~~unites~~units, offset in part by an increase in our intermediate generation volumes for gas-fired units primarily as a result of expanding spark spreads, and a decrease in baseload generation unplanned outages.

Northeast. The ~~decrease~~increase in generation volumes was primarily as a result of anreduced ~~outage~~outages atand ~~one~~expanding ofspark ~~our generating facilities~~spreads.

California. The increase in generation volumes was primarily as a result of expanding spark spreads.

Financial Condition

Liquidity and Capital Resources

Management thinks that our liquidity position and cash flows from operations will be adequate (a) to fund operating, maintenance and capital expenditures, (b) to fund GenOn Americas Generation’s debt service, (c) to service GenOn Mid-Atlantic’s operating leases and (d) to meet other liquidity requirements. Management regularly monitors our ability to fund our operating, financing and investing activities. See note 4 to our interim financial statements for additional discussion of GenOn Americas Generation’s debt.

Sources of Funds and Capital Structure

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~~made~~Sources ~~under~~of ~~GenOn’s~~Funds ~~senior secured revolving credit facility~~ and ~~(c) at~~Capital ~~its discretion, capital contributions or intercompany loans from GenOn for GenOn Americas Generation or from GenOn North America for GenOn Mid-Atlantic.~~Structure

The principal sources of our liquidity are expected to be: (a) existing cash on hand and expected cash flows from our operations and the operations of our subsidiaries, (b) at its discretion, letters of credit issued or borrowings made under GenOn’s senior secured revolving credit facility and (c) at its discretion, capital contributions or intercompany loans from GenOn for GenOn Americas Generation or from GenOn North America for GenOn Mid-Atlantic.

Our operating cash flows may be affected by, among other things: (a) demand for electricity; (b) the difference between the cost of fuel used to generate electricity and the market value of the electricity generated; (c) commodity prices (including prices for electricity, emissions allowances, natural gas, coal and oil); (d) operations and maintenance expenses in the ordinary course; (e) planned and unplanned outages; (f) terms with trade creditors; and (g) cash requirements for capital expenditures relating to certain facilities (including those necessary to comply with environmental regulations).

The table below sets forth total cash and cash equivalents of GenOn Americas Generation and its subsidiaries at ~~June~~September 30, 2012 (in millions):

Cash and Cash Equivalents:
GenOn Americas Generation (excluding GenOn Mid-Atlantic)	$	~~243~~164
GenOn Mid-Atlantic	~~200~~171
Total cash and cash equivalents(1)	$	~~443~~335

(1) We have $~~354~~169 million of collateral deposits from counterparties (including brokers), which are included in accounts payable and accrued liabilities.

We consider all short-term investments with an original maturity of three months or less to be cash equivalents. At ~~June~~September 30, 2012, except for amounts held in bank accounts to cover upcoming payables, all of our cash and cash equivalents were invested in AAA-rated United States Treasury money market funds.

GenOn Americas Generation is a holding company. The chart below is a summary representation of our capital structure and is not a complete corporate organizational chart.

(1) At ~~June~~September 30, 2012, the present value of lease payments under the GenOn Mid-Atlantic operating leases was $~~826~~ 846 million (assuming a 10% discount rate) and the termination value of the GenOn Mid-Atlantic operating leases was $1.2 billion.

Except for existing cash on hand, GenOn Americas Generation is a holding company that is dependent on the distributions and dividends of its subsidiaries for liquidity and, at its discretion, additional capital contributions from GenOn. A substantial portion of cash from its operations is generated by GenOn Mid-Atlantic.

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ofExcept ~~four~~for ~~fiscal~~existing ~~quarters,~~cash ~~commencing~~on ~~with~~hand, ~~the~~GenOn ~~fiscal~~Americas ~~quarter~~Generation ~~in which such payment~~ is ~~proposed~~a toholding becompany ~~made;~~that ~~and~~is ~~(c) no~~dependent ~~significant~~on ~~lease~~the ~~default~~distributions ~~or event of default has occurred~~ and isdividends ~~continuing. In the event~~ of aits ~~default~~subsidiaries ~~under~~for ~~the~~liquidity ~~operating leases or if the restricted payments test is not satisfied~~and, ~~GenOn~~at ~~Mid-Atlantic~~its ~~would not be able to distribute cash. At June 30~~discretion, ~~2012,~~additional ~~GenOn~~capital ~~Mid-Atlantic~~contributions ~~satisfied~~from ~~the restricted payments test~~GenOn. ~~GenOn~~A ~~Mid-Atlantic’s~~substantial ~~ability~~portion toof ~~satisfy~~cash ~~the~~from ~~criteria set by this covenant in the future could be impaired by the factors which negatively affect the performance of~~ its ~~generating facilities, including the interruptions in~~ operations oris ~~curtailment~~generated ofby ~~operations~~GenOn ~~to comply with environmental restrictions~~Mid-Atlantic.

GenOn Mid-Atlantic’s ability to pay dividends and make distributions is restricted under the terms of its operating leases. Under the operating leases, GenOn Mid-Atlantic is not permitted to make any distributions and other restricted payments unless: (a) it satisfies the fixed charge coverage ratio for the most recently ended period of four fiscal quarters; (b) it is projected to satisfy the fixed charge coverage ratio for each of the two following periods of four fiscal quarters, commencing with the fiscal quarter in which such payment is proposed to be made; and (c) no significant lease default or event of default has occurred and is continuing. In the event of a default under the operating leases or if the restricted payments test is not satisfied, GenOn Mid-Atlantic would not be able to distribute cash. At September 30, 2012, GenOn Mid-Atlantic satisfied the restricted payments test. GenOn Mid-Atlantic’s ability to satisfy the criteria set by this covenant in the future could be impaired by the factors which negatively affect the performance of its generating facilities, including interruptions in operations or curtailments of operations to comply with environmental restrictions.

The ability of GenOn Americas Generation to pay its obligations is dependent on the receipt of dividends from GenOn North America and, in turn, GenOn Mid-Atlantic; capital contributions or intercompany loans from GenOn; and its ability to refinance all or a portion of those obligations as they become due.

Uses of Funds

Our requirements for liquidity and capital resources, other than for the day-to-day operation of our generating facilities, are significantly influenced by the following items: (a) capital expenditures, including capital expenditures to meet environmental regulations, (b) debt service for GenOn Americas Generation, (c) payments under the GenOn Mid-Atlantic operating leases and (d) collateral required for GenOn Americas Generation’s asset management and proprietary trading and fuel oil management activities.

Capital Expenditures. Our estimated capital expenditures, excluding capitalized interest, for the period ~~July~~October 1, 2012 through December 31, 2013 will be $~~131~~101 million, including $7564 million relating to GenOn Mid-Atlantic. See “Capital Expenditures and Capital Resources” for further discussion of our capital expenditures.

Cash Collateral and Letters of Credit. In order to sell power and purchase fuel in the forward markets and perform other energy trading and marketing activities, we often are required to provide credit support to our counterparties or make deposits with brokers. In addition, we often are required to provide credit support for various contractual and other obligations incurred in connection with our commercial and operating activities, including obligations in respect of transmission and interconnection access, participation in power pools, rent reserves, power purchases and sales, fuel and emission purchases and sales, construction, equipment purchases and other operating activities. Credit support includes cash collateral, letters of credit, surety bonds and financial guarantees. In the event that we default, the counterparty ~~can~~is permitted to draw on a letter of credit or surety bond or apply cash collateral held to satisfy the existing amounts outstanding under an open contract. Our requirements for collateral and, accordingly, liquidity are highly dependent on the level of our hedging activities, forward prices for energy, emissions allowances and fuel, commodity market volatility, credit terms with third parties and regulation of energy contracts.

At ~~June~~September 30, 2012, we had $~~153~~149 million of posted cash collateral and GenOn had $~~186~~134 million of letters of credit outstanding under its revolving credit facility on our behalf primarily to support our asset management activities, trading activities, rent reserve requirements and other commercial arrangements.

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The following table summarizes cash collateral posted with counterparties and brokers, letters of credit issued and surety bonds provided for GenOn Americas Generation:

	June 30, 2012		December 31, 2011
	September 30, 2012		December 31, 2011
	(in millions)
Cash collateral posted—energy trading and marketing	$	9190	$	118
Cash collateral posted—other operating activities	6259		38
Letters of credit—rent reserves(1)	~~135~~75		101
Letters of credit—energy trading and marketing(1)	4149		39
Letters of credit—other operating activities(1)	10		31
Surety bonds	6		6
Total	$	~~345~~289	$	333

(1) Represents letters of credit posted by GenOn for the benefit of GenOn Americas Generation.

Historical Cash Flows

GenOn Americas Generation

	Six Months Ended June 30,						Increase/
	Nine Months Ended September 30,						Increase/
	2012			2011			(Decrease)
	(in millions)
Net cash provided by operating activities	$	~~218~~234		$	~~265~~267		$	(4733	)
Net cash provided by investing activities	28			533			(505		)
Net cash provided by (used in) investing activities	(14		)	415			(429		)
Net cash used in financing activities	(70152		)	(~~1,033~~996		)	~~963~~844

Operating Activities. Our cash provided by operating activities is affected by seasonality, changes in energy prices and fluctuations in our working capital requirements. Net cash provided by operating activities before changes in operating assets and liabilities decreased $8637 million for the ~~six~~nine months ended ~~June~~September 30, 2012, compared to the same period in 2011, primarily resulting from lower net income, adjusted for non-cash items, in 2012. Changes in our cash flows from operating activities before changes in operating assets and liabilities were generally consistent with changes in our results of operations, adjusted for non-cash items. See “Results of Operations” for additional information related to our performance in 2012 as compared to the same period in 2011.

~~Operating~~Cash provided by changes in operating assets and liabilities increased ~~cash~~ by $394 million primarily as a result of the following:

· ~~Accounts~~Funds ~~payable,~~on ~~collateral~~deposit. An increase in cash provided of $~~223~~61 million primarily as a result of $~~225~~7 million ~~posted~~of bycollateral returned from our counterparties in 2012 compared to $254 million ~~posted~~of ~~by our counterparties in 2011 primarily resulting from a contract modification in April 2012 to require a counterparty to post cash~~ collateral toposted ~~secure credit exposure above an agreed threshold as a result of changes~~ in ~~power or natural gas prices~~2011; ~~and~~

· ~~Funds~~Accounts onpayable, ~~deposit~~collateral. An increase in cash provided of $~~123~~40 million ~~primarily~~ as a result of $340 million ofposted ~~additional~~by ~~collateral returned from~~ our counterparties in 2012 compared to less than $~~120~~1 million ofposted ~~additional~~by ~~collateral~~our ~~posted~~counterparties in 2011. primarily resulting from a contract modification in April 2012 to require a counterparty to post cash collateral to secure credit exposure above an agreed threshold as a result of changes in power or natural gas prices; and

~~The~~· Other ~~increases~~operating assets and liabilities. An increase in cash provided byof ~~operating~~$3 ~~activities~~million ~~were~~related ~~partially~~to ~~offset~~changes byin ~~the~~other ~~following:~~operating assets and liabilities.

· Net receivables and accounts payable and accrued liabilities. A decrease in cash provided of $185 million primarily as a result of an increase in accounts payable due to affiliates in 2011; and

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~~· Inventories. An~~The ~~increase~~increases in cash ~~used~~provided ofby ~~$91~~operating ~~million~~activities ~~primarily~~were ~~related~~partially tooffset ~~changes~~by inthe ~~fuel oil and coal inventory and purchased emissions allowances; and~~following:

· ~~Taxes other than income taxes~~Inventories. An increase in cash used of $1665 million primarily asrelated ato ~~result~~changes ofin ~~property~~fuel ~~tax~~oil ~~payments.~~and coal inventory and purchased emissions allowances;

~~Investing~~· Taxes ~~Activities. Net~~other ~~cash~~than ~~provided~~income bytaxes. An ~~investing~~increase ~~activities~~in ~~decreased~~cash byused of $~~505~~17 million ~~for the six months ended June 30, 2012, compared to the same period in 2011. This difference was~~ primarily as a result of ~~the~~property ~~following:~~tax payments; and

· Net receivables and accounts payable and accrued liabilities. A decrease in cash provided of $18 million primarily as a result of an increase in accounts payable due to affiliates in 2011.

Investing Activities. Net cash provided by investing activities decreased by $429 million for the nine months ended September 30, 2012, compared to the same period in 2011. This difference was primarily a result of the following:

· Restricted funds on deposit—debt financing. A decrease in cash provided of $866 million primarily related to funds received from the GenOn debt financing on December 3, 2010, which were subsequently placed in restricted deposits at December 31, 2010 and withdrawn to repay long-term debt during 2011; and

· Capital expenditures. An increase in cash used of $~~104~~45 million primarily related to a $107.1 million payment in connection with the scrubber contract litigation settlement in 2012, partially offset by a $68 million payment related to the Maryland scrubber projects in 2011.

The decreases in cash provided by and increases in cash used in investing activities were partially offset by the following:

· Restricted funds on deposit—liens under scrubber contract litigation. A change in cash of $~~309~~331 million ~~primarily~~ related to $~~143~~165.6 million of funds placed in restricted deposits in 2011 as a result of the scrubber contract litigation and related liens and $165.6 million of those same liens released in 2012 in connection with the settlement; and

· Issuance of notes receivable—affiliate. AnA ~~increase~~decrease in cash ~~provided~~used of $~~160~~158 million related to the repayment of intercompany debt in 2011.

Financing Activities. Net cash used in financing activities decreased by $~~963~~844 million for the ~~six~~nine months ended ~~June~~September 30, 2012, compared to the same period in 2011. This difference was primarily a result of the following:

· Repayment of long-term debt. A decrease in cash used of $1.4 billion primarily related to repayment during 2011 of GenOn Americas Generation senior unsecured notes and GenOn North America senior unsecured notes; partially offset by

· Capital Contributions. A decrease in cash provided of $~~444~~474 million related to contributions made by our member in 2011.; and

~~GenOn~~· Distribution ~~Mid-Atlantic~~to member. An increase in cash used of $90 million related to distributions to our member. In 2012, we distributed $190 million compared to $100 million distributed in 2011.

	Six Months Ended June 30,						Increase/
	2012			2011			(Decrease)
	(in millions)
Net cash provided by operating activities	$	202		$	139		$	63
Net cash provided by (used in) investing activities	32			(186		)	218
Net cash used in financing activities	(102		)	(102		)	—

Operating Activities. Our cash provided by operating activities is affected by seasonality, changes in energy prices and fluctuations in our working capital requirements. Net cash provided by operating activities before changes in operating assets and liabilities decreased $17 million for the six months ended June 30, 2012, compared to the same period in 2011. Changes in our cash flows from operating activities before changes in operating assets and liabilities were generally consistent with changes in our results of operations, adjusted for non-cash items. See “Results of Operations” for additional information related to our performance in 2012 as compared to the same period in 2011.

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~~Operating~~GenOn ~~assets and liabilities increased cash by $80 million primarily as a result of the following:~~Mid-Atlantic

· Accounts payable, collateral. An increase in cash provided of $168 million posted by our counterparties in 2012 primarily resulting from a contract modification in April 2012 to require a counterparty to post cash collateral to secure credit exposure above an agreed threshold as a result of changes in power or natural gas prices; partially offset by

	Nine Months Ended September 30,						Increase/
	2012			2011			(Decrease)
	(in millions)

Net cash provided by operating activities	$	281		$	246		$	35
Net cash provided by (used in) investing activities	15			(291		)	306
Net cash used in financing activities	(193		)	(73		)	(120		)

~~· Net~~Operating ~~receivables~~Activities. ~~and~~Our ~~accounts~~cash ~~payable~~provided by operating activities is affected by seasonality, changes in energy prices and ~~accrued~~fluctuations ~~liabilities~~in our working capital requirements. ANet ~~decrease~~cash provided by operating activities before changes in ~~cash~~operating ~~provided~~assets ofand liabilities increased $7318 million ~~primarily~~for asthe anine ~~result~~months ofended anSeptember 30, ~~increase~~2012, compared to the same period in ~~accounts~~2011. Changes ~~receivables~~in ~~due~~our cash flows from ~~affiliates~~operating activities before changes in ~~2012~~operating assets and anliabilities ~~increase~~were generally consistent with changes in ~~accounts~~our ~~payable~~results ~~due~~of operations, adjusted for non-cash items. See “Results of Operations” for additional information related to ~~affiliates~~our performance in ~~2011;~~2012 ~~and~~as compared to the same period in 2011.

~~· Taxes~~Cash ~~other~~provided ~~than~~by ~~income~~changes ~~taxes. An~~in ~~increase~~operating inassets ~~cash~~and ~~used~~liabilities ofincreased by $1617 million primarily as a result of ~~property~~the ~~tax payments.~~following:

~~Investing~~· Accounts ~~Activities~~payable, collateral. ~~Net~~An increase in cash provided of $106 million posted by~~/used~~ our counterparties in ~~investing~~2012 ~~activities~~primarily ~~changed~~resulting byfrom ~~$218~~a ~~million~~contract ~~for~~modification ~~the~~in ~~six~~April 2012 ~~months~~to ~~ended~~require ~~June 30,~~a ~~2012,~~counterparty ~~compared~~to post cash collateral to ~~the~~secure ~~same~~credit ~~period~~exposure inabove ~~2011. This~~an ~~difference~~agreed ~~was~~threshold ~~primarily~~as a result of ~~the~~changes ~~following:~~in power or natural gas prices;

· ~~Restricted funds on deposit—liens under scrubber contract litigation~~ Inventories. AAn ~~change~~increase in cash provided of $~~309~~20 million primarily related to ~~$143~~changes ~~million of funds placed~~ in ~~restricted~~fuel ~~deposits~~oil ~~in 2011 as a result of the scrubber contract litigation~~ and ~~related~~coal ~~liens and $165.6 million of those same liens released in 2012 in connection with the settlement~~inventory; ~~partially offset by~~and

· ~~Capital~~ Other ~~expenditures~~operating assets and liabilities. An increase in cash ~~used~~provided of $919 million ~~primarily~~ related to achanges ~~$107.1 million payment~~ in ~~connection~~other ~~with~~operating ~~the~~assets ~~scrubber~~and ~~contract litigation settlement in 2012~~liabilities.

The increases in cash provided by operating activities were partially offset by the following:

· Net receivables and accounts payable and accrued liabilities. A decrease in cash provided of $101 million primarily as a result of an decrease in accounts receivables due from affiliates in 2011, partially offset by an decrease in accounts payable due to affiliates in 2011; and

· Taxes other than income taxes. An increase in cash used of $17 million primarily as a result of property tax payments.

Investing Activities. Net cash provided by/used in investing activities changed by $306 million for the nine months ended September 30, 2012, compared to the same period in 2011. This difference was primarily a result of the following:

· Restricted funds on deposit—liens under scrubber contract litigation. A change in cash of $331 million related to $165.6 million of funds placed in restricted deposits in 2011 as a result of the scrubber contract litigation and related liens and $165.6 million of those same liens released in 2012 in connection with the settlement; partially offset by

· Capital expenditures. An increase in cash used of $25 million primarily related to a $107.1 million payment in connection with the scrubber contract litigation settlement in 2012, partially offset by a $68 million payment related to the Maryland scrubber projects in 2011.

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Financing Activities. Net cash used in financing activities increased by $120 million for the nine months ended September 30, 2012, compared to the same period in 2011. This difference was primarily a result of the following:

· Distribution to member. An increase in cash used of $90 million related to distributions to our member. In 2012, we distributed $190 million compared to $100 million distributed in 2011; and

· Capital contributions. A decrease in cash provided of $30 million related to contributions made by our member in 2011.

Recently Adopted Accounting Guidance

See note 1 to our interim financial statements for further information related to our recently adopted accounting guidance.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Item 3 has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction H(2) to Form 10-Q.

ITEM 4. CONTROLS AND PROCEDURES

Effectiveness of Disclosure Controls and Procedures

As required by Exchange Act Rule 13a-15(b), our management, including our Chief Executive Officer and our Chief Financial Officer, conducted an assessment of the effectiveness of the design and operation of our disclosure controls and procedures (as defined by Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of ~~June~~September 30, 2012. Based upon this assessment, our management concluded that, as of ~~June~~September 30, 2012, the design and operation of these disclosure controls and procedures were effective.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal controls over financial reporting that have occurred during the quarter ended ~~June~~September 30, 2012 that have materially affected or are reasonably likely to materially affect the internal controls over financial reporting.

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PART II

OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See note 8 to our interim financial statements.

ITEM 1A. RISK FACTORS

We will be subject to various uncertainties and contractual restrictions while the NRG Merger is pending that could adversely affect our financial results.

Uncertainty about the effect of the NRG Merger on employees, customers, suppliers and others may have an adverse effect on our business. These uncertainties may impair our ability to attract, retain and motivate key personnel until the NRG Merger is completed and for a period of time thereafter, and could cause customers, suppliers and others that deal with us to seek to change existing business relationships.

Employee retention and recruitment may be particularly challenging prior to the completion of the NRG Merger, as employees and prospective employees may experience uncertainty about their future roles with the combined company.

The pursuit of the NRG Merger and the preparation for the integration of the companies may place a significant burden on our management and internal resources. Any significant diversion of management attention away from ongoing business and any difficulties encountered in the NRG Merger integration process could adversely affect our business, results of operations and financial condition.

In addition, the NRG Merger Agreement restricts us, without NRG’s consent, from making certain acquisitions and dispositions and taking other specified actions. These restrictions may prevent us from pursuing attractive business opportunities and making other changes to our business prior to completion of the NRG Merger or termination of the NRG Merger Agreement.

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ITEM 6. EXHIBITS

GenOn Americas Generation

Exhibit No.		Exhibit Name

3.1		Certificate of Formation for Mirant Americas Generation, LLC, filed with the Delaware Secretary of State dated at November 1, 2001 (Incorporated herein by reference to Exhibit 3.1 to Registrant’s Quarterly Report on Form 10-Q filed November 9, 2001, File No. 333-63240)

3.2		Certificate of Amendment to Certificate of Formation of Mirant Americas Generation, LLC, filed with the Delaware Secretary of State dated at December 3, 2010 (Incorporated herein by reference to Exhibit 3.2A1 to Registrant’s Annual Report on Form 10-K filed March 1, 2011, File No. 333-63240)

3.2		Second Amended and Restated Limited Liability Agreement for GenOn Americas Generation, LLC dated December 3, 2010 (Incorporated herein by reference to Exhibit 3.3A1 to Registrant’s Annual Report on Form 10-K filed March 1, 2011, File No. 333-63240)

31.1A1*		Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under Securities Exchange Act of 1934

31.2A3*		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under Securities Exchange Act of 1934

32.1A1*		Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(b))

32.2A3*		Certification of the Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(b))

101*		Interactive Data File

* Asterisk indicates exhibits filed herewith.

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GenOn Mid-Atlantic

Exhibit No.		Exhibit Name

3.1		Certificate of Formation of Southern Energy Mid-Atlantic, LLC, dated at July 12, 2000 (Incorporated herein by reference to Exhibit 3.1 to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

3.2		Certificate of Amendment to Certificate of Formation of Mirant Mid-Atlantic, LLC, filed with the Delaware Secretary of State dated at January 20, 2011 (Incorporated herein by reference to Exhibit 3.2A2 to Registrant’s Annual Report on Form 10-K filed March 1, 2011, File No. 333-63240)

3.3		Second Amended and Restated Limited Liability Company Agreement of GenOn Mid-Atlantic, LLC, dated January 20, 2011 (Incorporated herein by reference to Exhibit 3.2A2 to Registrant’s Annual Report on Form 10-K filed March 1, 2011, File No. 333-63240)

31.1A2*		Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under Securities Exchange Act of 1934

31.2A4*		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under Securities Exchange Act of 1934

32.1A2*		Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(b))

32.2A4*		Certification of the Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(b))

101*		Interactive Data File

* Asterisk indicates exhibits filed herewith.

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SIGNATURES

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

	GENON AMERICAS GENERATION, LLC
Date: August 9, 2012	By:	/s/ THOMAS C. LIVENGOOD
Date: November 9, 2012	By:	/s/ THOMAS C. LIVENGOOD
		Thomas C. Livengood
		Senior Vice President and Controller
		Senior Vice President and Controller (Duly Authorized Officer and Principal Accounting Officer)
		(Duly Authorized Officer and Principal Accounting Officer)

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SIGNATURES

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

	GENON MID-ATLANTIC, LLC
Date: August 9, 2012	By:	/s/ THOMAS C. LIVENGOOD
Date: November 9, 2012	By:	/s/ THOMAS C. LIVENGOOD
		Thomas C. Livengood
		Senior Vice President and Controller
		Senior Vice President and Controller (Duly Authorized Officer and Principal Accounting Officer)
		(Duly Authorized Officer and Principal Accounting Officer)

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