UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended ~~June~~September 30, 2011

¨	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.)

Identification No.)

Commission File Number: 333-61668

GenOn Mid-Atlantic, LLC

(Exact Name of Registrant as Specified in Its Charter)

58-2574140


Delaware		58-2574140
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

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

(I.R.S. Employer

Identification No.)

Delaware

(State or Other Jurisdiction of

Incorporation or Organization)

1000 Main Street,

Houston, Texas

(Address of Principal Executive Offices)

77002

(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		¨ Yes ¨ No
GenOn Mid-Atlantic, LLC		¨ Yes ¨ 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		þ Yes ¨ No
GenOn Mid-Atlantic, LLC		þ Yes ¨ 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.

	September 30,	September 30,	September 30,	September 30,
	Large accelerated filer	Accelerated filer	Non-accelerated filer	Smaller reporting company
GenOn Americas Generation, LLC	¨	¨	þ	¨
GenOn Mid-Atlantic, LLC	¨	¨	þ	¨


	Large accelerated filer	Accelerated filer	Non-accelerated filer	Smaller reporting company
GenOn Americas Generation, LLC	¨	¨	þ	¨
GenOn Mid-Atlantic, LLC	¨	¨	þ	¨

(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		¨ Yes þ No
GenOn Mid-Atlantic, LLC		¨ Yes þ 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).

TABLE OF CONTENTS

Glossary of Certain Defined Terms iii Cautionary Statement Regarding Forward-Looking Information vi


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 Nine Months Ended September 30, 2011 and 2010	1
	Condensed Consolidated Balance Sheets (Unaudited) September 30, 2011 and December 31, 2010	2
	Condensed Consolidated Statements of Cash Flows (Unaudited) Nine Months Ended September 30, 2011 and 2010	3
	GenOn Mid-Atlantic, LLC:
	Condensed Consolidated Statements of Operations (Unaudited) Three and Nine Months Ended September 30, 2011 and 2010	4
	Condensed Consolidated Balance Sheets (Unaudited) September 30, 2011 and December 31, 2010	5
	Condensed Consolidated Statements of Cash Flows (Unaudited) Nine Months Ended September 30, 2011 and 2010	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
	GenOn Americas Generation, LLC:
	Overview	42
	Merger of Mirant and RRI Energy	42
	Hedging Activities	42
	Capital Expenditures and Capital Resources	44
	Environmental Matters	44
	Potrero Shutdown	47
	Potomac River Retirement	47
	Commodity Prices	48
	Results of Operations	48
	Financial Condition	54
	Historical Cash Flows	57
	Recently Adopted Accounting Guidance	59
	GenOn Mid-Atlantic, LLC:
	Overview	60
	Merger of Mirant and RRI Energy	60
	Hedging Activities	60
	Capital Expenditures and Capital Resources	62
	Environmental Matters	62
	Potomac River Retirement	62
	Commodity Prices	62
	Results of Operations	63
	Financial Condition	66
	Historical Cash Flows	68
	Recently Adopted Accounting Guidance	68

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, 2011 and 2010	1
	Condensed Consolidated Balance Sheets June 30, 2011 (Unaudited) and December 31, 2010	2
	Condensed Consolidated Statements of Member’s Equity (Unaudited) Six Months Ended June 30, 2011	3
	Condensed Consolidated Statements of Cash Flows (Unaudited) Six Months Ended June 30, 2011 and 2010	4
	GenOn Mid-Atlantic, LLC:
	Condensed Consolidated Statements of Operations (Unaudited) Three and Six Months Ended June 30, 2011 and 2010	5
	Condensed Consolidated Balance Sheets June 30, 2011 (Unaudited) and December 31, 2010	6
	Condensed Consolidated Statements of Member’s Equity (Unaudited) Six Months Ended June 30, 2011	7
	Condensed Consolidated Statements of Cash Flows (Unaudited) Six Months Ended June 30, 2011 and 2010	8
	Combined Notes to Condensed Consolidated Financial Statements (Unaudited)	9
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	41
	GenOn Americas Generation, LLC:
	Overview	41
	Merger of Mirant and RRI Energy	41
	Hedging Activities	41
	Capital Expenditures and Capital Resources	42
	Environmental Matters	43
	Potrero Shutdown	45
	Commodity Prices	45
	Results of Operations	45
	Financial Condition	51
	Historical Cash Flows	54
	GenOn Mid-Atlantic, LLC:
	Overview	56
	Merger of Mirant and RRI Energy	56
	Hedging Activities	56
	Capital Expenditures and Capital Resources	57
	Environmental Matters	58
	Commodity Prices	58
	Results of Operations	58
	Financial Condition	62
	Historical Cash Flows	63
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS	65

ITEM 4.	CONTROLS AND PROCEDURES	65
	Effectiveness of Disclosure Controls and Procedures	65
	Changes in Internal Control Over Financial Reporting	65
	PART II
ITEM 1.	LEGAL PROCEEDINGS	66
ITEM 6.	EXHIBITS
	GenOn Americas Generation, LLC	66
	GenOn Mid-Atlantic, LLC	68

Glossary of Certain Defined Terms


ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS	69

ITEM 4.	CONTROLS AND PROCEDURES	69
	Effectiveness of Disclosure Controls and Procedures	69
	Changesin Internal Control Over Financial Reporting	69

PART II

ITEM 1.	LEGAL PROCEEDINGS	70

ITEM 6.	EXHIBITS
	GenOn Americas Generation, LLC	70
	GenOn Mid-Atlantic, LLC	71

AB 32		California’s Global Warming Solutions Act.
ancillary services		Services that ensure reliability and support the transmission of electricity from generation sites to customer loads. Such services include regulation service, spinning and non-spinning reserves and voltage support.
Administrative Services Agreement		Management, personnel and services agreement with GenOn Energy Services, effective January 3, 2006.
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		Energy that could have been generated at continuous full-power operation during the period.
CARB		California Air Resources Board.
CFTC		Commodity Futures Trading Commission.
Clean Air Act		Federal Clean Air Act.
CO2		Carbon dioxide.
CSAPR		Cross-State Air Pollution Rule.
dark spread		The difference between power prices and coal fuel costs.
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 Merger.
GenOn Americas		GenOn Americas, Inc. (formerly known as Mirant Americas, Inc.).
GenOn Americas Generation		GenOn Americas Generation, LLC (formerly known as Mirant Americas Generation, LLC).
GenOn California North		GenOn California North, LLC (formerly known as Mirant California, LLC).
GenOn Chalk Point		GenOn Chalk Point, LLC (formerly known as Mirant Chalk Point, LLC).
GenOn credit facilities		Senior secured term loan and revolving credit facility of GenOn and certain of its subsidiaries.

iii

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 (formerly known as Mirant Energy Trading, LLC).
GenOn Energy Services		GenOn Energy Services, LLC (formerly known as Mirant Services, LLC).
GenOn Kendall		GenOn Kendall, LLC (formerly known as Mirant Kendall, LLC).
GenOn Marsh Landing		GenOn Marsh Landing, LLC (formerly known as Mirant Marsh Landing, LLC).
GenOn Mid-Atlantic		GenOn Mid-Atlantic, LLC (formerly known as Mirant Mid-Atlantic, LLC) and, except where the context indicates otherwise, its subsidiaries.
GenOn North America		GenOn North America, LLC (formerly known as Mirant North America, LLC).
GenOn Potomac River		GenOn Potomac River, LLC (formerly known as Mirant Potomac River, LLC).
HAP		Hazardous Air Pollutant.
Hudson Valley Gas		Hudson Valley Gas Corporation.
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.
MDE		Maryland Department of the Environment.
Merger		The merger completed on December 3, 2010 pursuant to the Merger Agreement.
Merger Agreement		The agreement by and among Mirant Corporation, RRI Energy, Inc. and RRI Energy Holdings, Inc. dated as of April 11, 2010.
Mirant		GenOn Energy Holdings, Inc. (formerly known as Mirant Corporation) and, except where the context indicates otherwise, its subsidiaries.
MW		Megawatt.
MWh		Megawatt hour.
NAAQS		National Ambient Air Quality Standards.
net generating capacity		Net summer capacity.
NOV		Notice of violation.
NOx		Nitrogen oxides.
NPDES		National pollutant discharge elimination system.
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.
PG&E		Pacific Gas & Electric Company.

Glossary of Certain Defined Terms


AB 32		California’s Global Warming Solutions Act.

ancillary services		Services that ensure reliability and support the transmission of electricity from generation sites to customer loads. Such services include regulation service, spinning and non-spinning reserves and voltage support.

Administrative Services Agreement		Management, personnel and services agreement with GenOn Energy Services, effective January 3, 2006.

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		Energy that could have been generated at continuous full-power operation during the period.

CARB		California Air Resources Board.

CFTC		Commodity Futures Trading Commission.

Clean Air Act		Federal Clean Air Act.

CO₂		Carbon dioxide.

CSAPR		Cross-State Air Pollution Rule.

dark spread		The difference between power prices and coal fuel costs.

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 Merger.

GenOn Americas		GenOn Americas, Inc. (formerly known as Mirant Americas, Inc.).

GenOn Americas Generation		GenOn Americas Generation, LLC (formerly known as Mirant Americas Generation, LLC).

GenOn California North		GenOn California North, LLC (formerly known as Mirant California, LLC).

GenOn Chalk Point		GenOn Chalk Point, LLC (formerly known as Mirant Chalk Point, LLC).

GenOn credit facilities		Senior secured term loan and revolving credit facility of GenOn and certain of its subsidiaries.

PJM		PJM Interconnection, LLC.
GenOn Energy Holdings		GenOn Energy Holdings, Inc. (formerly known as Mirant Corporation) and, except where the context indicates otherwise, its subsidiaries.
Plan		The plan of reorganization that was approved in conjunction with Mirant Corporation’s, GenOn Americas Generation, LLC’s and GenOn Mid-Atlantic, LLC’s emergence from bankruptcy protection on January 3, 2006.
GenOn Energy Management		GenOn Energy Management, LLC (formerly known as Mirant Energy Trading, LLC).
Power Sale, Fuel Supply and Services
GenOn Energy Services		GenOn Energy Services, LLC (formerly known as Mirant Services, LLC).
Agreement		Power sale, fuel supply and services agreement with Mirant Americas Energy Marketing, LP. effective January 3, 2006. As of February 1, 2006, the agreement was transferred to GenOn Energy Management.
GenOn Kendall		GenOn Kendall, LLC (formerly known as Mirant Kendall, LLC).
PPA		Power purchase agreement.
GenOn Marsh Landing		GenOn Marsh Landing, LLC (formerly known as Mirant Marsh Landing, LLC).
RGGI		Regional Greenhouse Gas Initiative.
GenOn Mid-Atlantic		GenOn Mid-Atlantic, LLC (formerly known as Mirant Mid-Atlantic, LLC) and, except where the context indicates otherwise, its subsidiaries.
RMR		Reliability-must-run.
GenOn North America		GenOn North America, LLC (formerly known as Mirant North America, LLC).
RPM		Model utilized by PJM to meet load serving entities’ forecasted capacity obligations through a forward-looking commitment of capacity resources.
GenOn Potomac River		GenOn Potomac River, LLC (formerly known as Mirant Potomac River, LLC).
RRI Energy		RRI Energy, Inc., which changed its name to GenOn Energy, Inc. in connection with the Merger.
HAPs		Hazardous Air Pollutants.
RTO		Regional Transmission Organization.
Hudson Valley Gas		Hudson Valley Gas Corporation.
SCR		Selective catalytic reduction emissions controls.
intermediate generating units		Units designed to satisfy system requirements that are greater than baseload and less than peaking.
scrubbers		Flue gas desulfurization emissions controls.
ISO		Independent system operator.
SEC		United States Securities and Exchange Commission.
ISO-NE		Independent System Operator-New England.
Securities Act		Securities Act of 1933, as amended.
LIBOR		London InterBank Offered Rate.
SO2		Sulfur dioxide.
MDE		Maryland Department of the Environment.
Stone & Webster		Stone & Webster, Inc.
Merger		The merger completed on December 3, 2010 pursuant to the Merger Agreement.
Virginia DEQ		Virginia Department of Environmental Quality.
Merger Agreement		The agreement by and among Mirant Corporation, RRI Energy, Inc. and RRI Energy Holdings, Inc. dated as of April 11, 2010.
WCI		Western Climate Initiative.
Mirant		GenOn Energy Holdings, Inc. (formerly known as Mirant Corporation) and, except where the context indicates otherwise, its subsidiaries.
MW		Megawatt.
MWh		Megawatt hour.
NAAQS		National Ambient Air Quality Standards.
net generating capacity		Net summer capacity.
NOV		Notice of violation.
NOx		Nitrogen oxides.
NPDES		National pollutant discharge elimination system.
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.

Plan		The plan of reorganization that was approved in conjunction with Mirant Corporation’s, GenOn Americas Generation, LLC’s and GenOn Mid-Atlantic, LLC’s emergence from bankruptcy protection on January 3, 2006.

Power Sale, Fuel Supply and Services Agreement		Power sale, fuel supply and services agreement with Mirant Americas Energy Marketing, LP. effective January 3, 2006. As of February 1, 2006, the agreement was transferred to GenOn Energy Management.

PPA		Power purchase agreement.

RGGI		Regional Greenhouse Gas Initiative.

RMR		Reliability-must-run.

RRI Energy		RRI Energy, Inc., which changed its name to GenOn Energy, Inc. in connection with the Merger.

RTO		Regional Transmission Organization.

SCR		Selective catalytic reduction emissions controls.

scrubbers		Flue gas desulfurization emissions controls.

SEC		United States Securities and Exchange Commission.

Securities Act		Securities Act of 1933, as amended.

SO₂		Sulfur dioxide.

spark spread		The difference between power prices and natural gas fuel costs.

Stone & Webster		Stone & Webster, Inc.

swaption		An option that grants the holder the right, but not the obligation, to enter into the underlying swap.

WCI		Western Climate Initiative.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

In addition to historical information, the information presented in this combined Form 10-Q 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 terminology 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 other comparable terminology.

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:

•

our ability to integrate successfully the businesses following the Merger or realize cost savings and any other synergies as a result of the Merger;

•

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 supply and delivery of fuel for our generating facilities, at our required specifications and on terms and prices acceptable to us;

•

failure to obtain adequate fuel supply, including from curtailments of the transportation of fuel;

•

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;

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

•

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

•

hazards customary to the power generation industry 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;

•

our failure to utilize new, or advancements in, 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;

•

the cost and availability of emissions allowances;

•

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

•

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

vii

•

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

•

war, terrorist activities, cyberterrorism and inadequate cybersecurity, or the occurrence of a catastrophic loss;

•

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;

•

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 asset management and, for GenOn Americas Generation, proprietary trading and fuel oil management activities as expected, or may result in material ~~gains or~~ 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 asset management and GenOn Americas Generation’s proprietary trading and fuel oil management activities and volatility in our cash flow from operations resulting from working capital requirements, including collateral, to support our asset management and GenOn Americas Generation’s proprietary trading and fuel oil management activities;

•

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, environmental and other laws and regulations to which we and our subsidiaries and affiliates are or could become subject;

•

more stringent 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;

•

increased regulation that limits our access to adequate water supplies and landfill options needed to support power generation or that increases the costs of cooling water and handling, transporting and disposing of ash and other byproducts;

•

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 disposition of pending or threatened litigation, including environmental litigation;

viii

•

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;

vii

•

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 to comply with provisions of GenOn Mid-Atlantic’s operating leases, GenOn Americas Generation’s debt and affiliates’ loan agreements and debt 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 affiliates’ 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; and

•

our and our affiliates’ ability to borrow additional funds and access capital markets.

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. Our filings and other important information are also available on our investor relations page at www.genon.com/investors.aspx.

In addition to the discussion of certain risks in “Management’s ~~Discussion~~Narrative ~~and Analysis~~ of ~~Financial~~the ~~Condition and~~ Results of Operations and Financial Condition” and the accompanying combined notes to GenOn Americas Generation, LLC’s and GenOn Mid-Atlantic, LLC’s interim financial statements, other factors that could affect our future performance are set forth in our ~~2010~~ 2010 Annual Report on Form 10-K.

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.

~~viii~~ ix

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)

		September 30,			September 30,			September 30,			September 30,
	Three Months EndedJune 30,						Six Months EndedJune 30,
	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in millions)
Operating revenues (including unrealized gains (losses) of $(12) million, $(231) million, $(107) million and $132 million, respectively)	$	715		$	244		$	1,253		$	1,124
Operating revenues (including unrealized gains (losses) of $37 million, $154 million, $(70) million and $286 million, respectively)	$	929		$	775		$	2,182		$	1,899
Operating revenues—affiliate (including unrealized gains (losses) of $(2) million, $0, $8 million and $0, respectively)		2			—			13			—
Operating revenues—affiliate (including unrealized gains (losses) of $(27) million, $0, $(19) million and $0, respectively)		(16	)		—			(3	)		—
Total operating revenues		~~717~~913			~~244~~775			12,~~266~~179			1,~~124~~899
Cost of fuel, electricity and other products (including unrealized (gains) losses of $(15) million, $109 million, $(29) million and $120 million, respectively)		138			271			303			475
Cost of fuel, electricity and other products (including unrealized (gains) losses of $11 million, $(13) million, $(18) million and $107 million, respectively)		210			245			513			720
Cost of fuel, electricity and other products—affiliate (including unrealized (gains) losses of $0, $0, $0 and $0, respectively)		330			1			500			4
Cost of fuel, electricity and other products—affiliate (including unrealized (gains) losses of $(1) million, $0, $(1) million and $0, respectively)		494			2			994			6
Total cost of fuel, electricity and other products		~~468~~704			~~272~~247			~~803~~1,507			~~479~~726
Gross Margin (excluding depreciation and amortization)		~~249~~209			~~(28~~528	)		~~463~~672			~~645~~1,173
Operating Expenses:
Operations and maintenance		~~118~~73			9388			~~197~~270			~~182~~270
Operations and maintenance—affiliate		5953			7274			~~119~~172			~~142~~216
Depreciation and amortization		42			5052			82124			99151
(Gain) loss on sales of assets, net		1			(1	)		1			(3	)
Impairment losses		128			—			128			—
Total operating expenses		220			214			399			420
Gain on sales of assets, net		(6	)		(1	)		(5	)		(4	)
Operating Income (Loss)		29			(242	)		64			225
Loss on sales of assets, net—affiliate		2			—			2			—
Total operating expenses		292			213			691			633
Operating Income (Loss)		(83	)		315			(19	)		540
Other Income (Expense), net:
Interest expense		(2119	)		(4951	)		(5170	)		(99150	)
Other, net		—			(1	)		(23	)		(2	)
Interest expense—affiliate		(4	)		—			(4	)		—
Total other expense, net		(21	)		(50	)		(74	)		(101	)
Other, net		—			1			(23	)		(1	)
Net Income (Loss)	$	8		$	(292	)	$	(10	)	$	124
Total other expense, net		(23	)		(50	)		(97	)		(151	)
Income (Loss) Before Income Taxes		(106	)		265			(116	)		389
Benefit for income taxes		—			(1	)		—			(1	)
Net Income (Loss)	$	(106	)	$	266		$	(116	)	$	390

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

GENON AMERICAS GENERATION, LLC AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

		September 30,			September 30,
	June 30, 2011			December 31, 2010
	September 30, 2011			December 31, 2010
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents	$	~~279~~200		$	514
Funds on deposit		~~349~~301			949
Receivables		~~306~~230			363
Receivables—affiliate		4229			4
Notes receivable—affiliate		~~147~~164			—
Derivative contract assets		~~777~~658			1,288
Derivative contract assets—affiliate		3924			5
Inventories		~~239~~256			295
Prepaid expenses and other current assets		~~107~~105			124
Total current assets		21,~~285~~967			3,542
Property, plant and equipment, gross		3,~~976~~878			3,946
Accumulated depreciation and amortization		(~~940~~920	)		(869	)
Property, Plant and Equipment, net		32,~~036~~958			3,077
Noncurrent Assets:
Intangible assets, net		9826			101
Derivative contract assets		~~564~~546			689
Derivative contract assets—affiliate		1713			3
Prepaid rent		~~398~~374			348
Debt issuance costs, net		6			12
Other		4143			41
Total noncurrent assets		1,~~124~~008			1,194
Total Assets	$	65,~~445~~933		$	7,813
LIABILITIES AND MEMBER’S EQUITY
Current Liabilities
Current Liabilities:
Current portion of long-term debt	$	4		$	1,389
Accounts payable and accrued liabilities		~~440~~324			527
Payable—affiliate		282			54
Payables—affiliate		141			54
Notes payable—affiliate		2432			—
Derivative contract liabilities		~~662~~516			1,130
Derivative contract liabilities—affiliate		2416			3
Other		1317			8
Total current liabilities		1,~~449~~050			3,111
Noncurrent Liabilities:
Long-term debt, net of current portion		~~864~~863			866
Derivative contract liabilities		8765			173
Derivative contract liabilities—affiliate		1632			—
Other		~~120~~90			90
Total noncurrent liabilities		1,~~087~~050			1,129
Commitments and Contingencies
Member’s Equity:
Member’s interest		3,~~909~~833			3,573
Total member’s equity		3,~~909~~833			3,573
Total Liabilities and Member’s Equity	$	65,~~445~~933		$	7,813

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

GENON AMERICAS GENERATION, LLC AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED STATEMENTS OF ~~MEMBER’S~~CASH ~~EQUITY~~FLOWS (UNAUDITED)

		September 30,			September 30,
	Member’sInterest
	Nine Months Ended September 30,
	(in millions)
	2011			2010
Balance, December 31, 2010	$	3,573
	(in millions)
Net loss		(10	)
Cash Flows from Operating Activities:
Distribution to member		(100	)
Net income (loss)	$	(116	)	$	390
Capital contributions		446
Adjustments to reconcile net income (loss) and changes in other operating assets and liabilities to net cash provided by operating activities:
Balance, June 30, 2011	$	3,909
Depreciation and amortization		122			158
Impairment losses		128			—
Gain on sales of assets, net		(3	)		(4	)
Net changes in derivative contracts		70			(179	)
Lower of cost or market inventory adjustments		1			22
Loss on early extinguishment of debt		23			—
Funds on deposit		(54	)		(25	)
Changes in other operating assets and liabilities		96			59
Total adjustments		383			31
Net cash provided by operating activities		267			421
Cash Flows from Investing Activities:
Capital expenditures		(130	)		(207	)
Proceeds from the sales of assets		9			4
Restricted funds on deposit, net		700			—
Issuance of notes receivable—affiliate		(164	)		—
Net cash provided by (used in) investing activities		415			(203	)
Cash Flows from Financing Activities:
Redemption of preferred stock		—			95
Repayment of long-term debt		(1,404	)		(71	)
Issuance of notes payable—affiliate		34			—
Distributions to member		(100	)		(109	)
Capital contributions		474			—
Net cash used in financing activities		(996	)		(85	)
Net Increase (Decrease) in Cash and Cash Equivalents		(314	)		133
Cash and Cash Equivalents, beginning of period		514			404
Cash and Cash Equivalents, end of period	$	200		$	537
Supplemental Disclosures:
Cash paid for interest, net of amounts capitalized	$	59		$	94
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

GENON AMERICAS GENERATION, LLC AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

		September 30,			September 30,
	Six Months Ended June 30,
	2011			2010
	(in millions)
Cash Flows from Operating Activities:
Net income (loss)	$	(10	)	$	124
Adjustments to reconcile net income (loss) and changes in other operating assets and liabilities to net cash provided by operating activities:
Depreciation and amortization		82			104
(Gain) loss on sales of assets, net		1			(3	)
Net changes in derivative contracts		70			(12	)
Lower of cost or market inventory adjustments		1			20
Loss on early extinguishment of debt		23			—
Funds on deposit		(120	)		7
Changes in other operating assets and liabilities		218			(87	)
Total adjustments		275			29
Net cash provided by operating activities		265			153
Cash Flows from Investing Activities:
Capital expenditures		(47	)		(155	)
Proceeds from the sales of assets		4			3
Restricted funds on deposit, net		723			—
Issuance of notes receivable—affiliate		(147	)		—
Net cash provided by (used in) investing activities		533			(152	)
Cash Flows from Financing Activities:
Redemption of preferred stock		—			95
Repayments of long-term debt		(1,403	)		(69	)
Issuance of notes payable—affiliate		26			—
Distribution to member		(100	)		—
Capital contributions		444			—
Net cash provided by (used in) financing activities		(1,033	)		26
Net Increase (Decrease) in Cash and Cash Equivalents		(235	)		27
Cash and Cash Equivalents, beginning of period		514			404
Cash and Cash Equivalents, end of period	$	279		$	431
Supplemental Disclosures:
Cash paid for interest, net of amounts capitalized	$	59		$	92
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

GENON MID-ATLANTIC, LLC AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

		September 30,			September 30,			September 30,			September 30,
	Three Months EndedJune 30,						Six Months EndedJune 30,
	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in millions)
Operating revenues (including unrealized gains (losses) of $6 million, $(97) million, $(39) million and $103 million, respectively)	$	45		$	(39	)	$	44		$	219
Operating revenues (including unrealized gains (losses) of $(3) million, $124 million, $(42) million and $227 million, respectively)	$	41		$	165		$	85		$	384
Operating revenues—affiliate (including unrealized gains (losses) of $(33) million, $(108) million, $(39) million and $30 million, respectively)		235			209			534			690
Operating revenues—affiliate (including unrealized gains (losses) of $0, $32 million, $(39) million and $62 million, respectively)		287			488			821			1,178
Total operating revenues		~~280~~328			~~170~~653			~~578~~906			~~909~~1,562
Cost of fuel, electricity and other products (including unrealized (gains) losses of $0, $0, $0 and $0, respectively)		24			54			913			913
Cost of fuel, electricity and other products—affiliate (including unrealized (gains) losses of $(15) million, $112 million, $(27) million and $104 million, respectively)		111			245			240			396
Cost of fuel, electricity and other products—affiliate (including unrealized (gains) losses of $9 million, $(23) million, $(18) million and $81 million, respectively)		170			178			410			574
Total cost of fuel, electricity and other products		~~113~~174			~~250~~182			~~249~~423			~~405~~587
Gross Margin (excluding depreciation and amortization)		~~167~~154			~~(80~~471	)		~~329~~483			~~504~~975
Operating Expenses:
Operations and maintenance		~~101~~53			7065			~~163~~216			~~135~~200
Operations and maintenance—affiliate		4243			4751			82125			95146
Depreciation and amortization		30			36			5989			69105
Gain on sales of assets, net—affiliate		—			(1	)		—			(3	)
Impairment losses		94			—			94			—
Total operating expenses		173			152			304			296
Gain on sales of assets, net—affiliate		—			—			—			(3	)
Operating Income (Loss)		(6	)		(232	)		25			208
Total operating expenses		220			152			524			448
Operating Income (Loss)		(66	)		319			(41	)		527
Other Income (Expense), net:
Interest expense		(1—	)		—(1	)		(1	)		(12	)
Other, net		—			(1	)		—			(1	)
Interest expense—affiliate		(3	)		—			(3	)		—
Total other expense, net		(1	)		(1	)		(1	)		(2	)
Other, net		—			—			—			(1	)
Net Income (Loss)	$	(7	)	$	(233	)	$	24		$	206
Total other expense, net		(3	)		(1	)		(4	)		(3	)
Income (Loss) Before Income Taxes		(69	)		318			(45	)		524
Benefit for income taxes		—			(1	)		—			(1	)
Net Income (Loss)	$	(69	)	$	319		$	(45	)	$	525

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

GENON MID-ATLANTIC, LLC AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

		September 30,			September 30,
	June 30,2011			December 31,2010
	September 30, 2011			December 31, 2010
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents	$	5384		$	202
Funds on deposit		~~147~~166			2
Receivables		2319			21
Receivables—affiliate		~~146~~28			169
Derivative contract assets		~~155~~170			162
Derivative contract assets—affiliate		~~136~~113			245
Inventories		~~152~~157			122
Prepaid rent		96			96
Other		36			11
Total current assets		~~911~~839			1,030
Property, plant and equipment, gross		3,~~079~~041			3,046
Accumulated depreciation and amortization		(~~567~~577	)		(513	)
Property, Plant and Equipment, net		2,~~512~~464			2,533
Noncurrent Assets:
Intangible assets, net		7114			71
Derivative contract assets		~~474~~452			516
Derivative contract assets—affiliate		4438			97
Prepaid rent		~~398~~374			348
Other		2932			31
Total noncurrent assets		~~1,016~~910			1,063
Total Assets	$	4,~~439~~213		$	4,626
LIABILITIES AND MEMBER’S EQUITY
Current Liabilities:
Current portion of long-term debt	$	4		$	4
Accounts payable and accrued liabilities		6482			63
Payable—affiliate		129			114
Payables—affiliate		37			114
Derivative contract liabilities		84			18
Derivative contract liabilities—affiliate		~~135~~123			231
Contract retention liability		~~130~~65			132
Other		1523			8
Total current liabilities		~~485~~338			570
Noncurrent Liabilities:
Long-term debt, net of current portion		1615			18
Derivative contract liabilities—affiliate		4133			94
Other		8150			52
Total noncurrent liabilities		~~138~~98			164
Commitments and Contingencies
Member’s Equity:
Member’s interest		3,~~816~~777			3,892
Total member’s equity		3,~~816~~777			3,892
Total Liabilities and Member’s Equity	$	4,~~439~~213		$	4,626

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

GENON MID-ATLANTIC, LLC AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY (UNAUDITED)

		September 30,
	Member’sInterest
	(in millions)
Balance, December 31, 2010	$	3,892
Net income		24
Distribution to member		(100	)
Balance, June 30, 2011	$	3,816

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

GENON MID-ATLANTIC, LLC AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

		September 30,			September 30,
	Six Months Ended June 30,
	Nine Months Ended September 30,
	2011			2010
	(in millions)
Cash Flows from Operating Activities:
Net income	$	24		$	206
Net income (loss)	$	(45	)	$	525
Adjustments to reconcile net income and changes in other operating assets and liabilities to net cash provided by operating activities:
Adjustments to reconcile net income (loss) and changes in other operating assets and liabilities to net cash provided by operating activities:
Depreciation and amortization		5989			69105
Impairment losses		94			—
Gain on sales of assets, net—affiliate		—			(3	)
Net changes in derivative contracts		5163			(29208	)
Lower of cost or market inventory adjustments		—1			1213
Changes in other operating assets and liabilities		544			~~(24~~14	)
Total adjustments		~~115~~291			25(79	)
Net cash provided by operating activities		~~139~~246			~~231~~446
Cash Flows from Investing Activities:
Capital expenditures		(43126	)		(~~144~~194	)
Proceeds from the sales of assets		—1			4
Restricted funds on deposit, net		(~~143~~166	)		—
Net cash used in investing activities		(~~186~~291	)		(~~140~~190	)
Cash Flows from Financing Activities:
Redemption of preferred stock		—			95
Repayment of long-term debt		(23	)		(23	)
Distribution to member		(100	)		(150	)
Distributions to member		(100	)		(200	)
Net cash used in financing activities		(102	)		(57	)
Capital contributions		30			—
Net Increase (Decrease) in Cash and Cash Equivalents		(149	)		34
Net cash used in financing activities		(73	)		(108	)
Net Increase (Decrease) in Cash and Cash Equivalents		(118	)		148
Cash and Cash Equivalents, beginning of period		202			125
Cash and Cash Equivalents, end of period	$	5384		$	~~159~~273
Supplemental Disclosures:
Cash paid for interest	$	—		$	1
Cash refunds received for income taxes	$	1		$	—

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

GENON AMERICAS GENERATION, 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 provides energy, capacity, ancillary and other energy services to wholesale customers in competitive energy markets in the United States through ownership and operation of, and contracting for, power generation capacity. GenOn Americas Generation is a wholesale generator with approximately 9,724 MW of net electric generating capacity in the Eastern PJM and Northeast regions and northern California. GenOn Americas Generation also operates integrated asset management and energy marketing organizations, including proprietary trading operations.

GenOn Mid-Atlantic operates and owns or leases 5,204 MW of net electric generating capacity in the Washington, D.C. area. GenOn Mid-Atlantic’s electric generating capacity is part of the 9,724 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. The chart below is a summary representation of our organizational structure and reportable segments and is not a complete organizational chart of GenOn.

LOGO

(1)	GenOn Power Generation, LLC’s subsidiaries include former RRI Energy generating facilities acquired as a result of the Merger.

We have a number of service agreements 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 56 for further discussion of arrangements with these related parties.

Merger of Mirant and RRI Energy

On December 3, 2010, Mirant and RRI Energy completed the Merger. See note 1 to our consolidated financial statements in our 2010 Annual Report on Form 10-K for additional information on the Merger.

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 2010 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.

At ~~June~~September 30, 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;

•

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.

108

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

		September 30,		September 30,
	June 30,2011		December 31,2010
	September 30,2011		December 31,2010
	(in millions)
Cash collateral posted(1)	$	240	$	120
Cash collateral posted – energy trading and marketing	$	135	$	80
GenOn Mid-Atlantic restricted cash(2)		143		—
Cash collateral posted – other operating activities(1)		39		40
GenOn Mid-Atlantic restricted cash(2)		166		—
Funds deposited with the trustee to discharge the GenOn North America senior notes, due 2013(3)		—		866
Total current and noncurrent funds on deposit		~~383~~340		986
Less: Current funds on deposit		~~349~~301		949
Total noncurrent funds on deposit	$	3439	$	37

(1) ~~Represents~~Includes ~~cash collateral posted for energy trading and marketing and other operating activities; includes~~ $32 million related to the Potomac River Settlement (see note 10 to our consolidated financial statements in our 2010 Annual Report on Form 10-K and note 2).

(2) Represents cash reserved in respect of interlocutory liens related to the scrubber contract litigation. See note 89.

(3) See note 34 for discussion of the related debt.

GenOn Mid-Atlantic

		September 30,		September 30,
	June 30,2011		December 31,2010
	September 30,2011		December 31,2010
	(in millions)
GenOn Mid-Atlantic restricted cash(1)	$	~~143~~166	$	—
Cash collateral posted(2)		32		32
Total current and noncurrent funds on deposit		~~175~~198		32
Less: Current funds on deposit		~~147~~166		2
Total noncurrent funds on deposit	$	2832	$	30

(1) Represents cash reserved in respect of interlocutory liens related to the scrubber contract litigation. See note 89.

(2)	Represents amount related to the Potomac River Settlement (see note 10 to our consolidated financial statements in our 2010 Annual Report on Form 10-K.)

Inventories

Inventories were comprised of the following:

GenOn Americas Generation

		September 30,		September 30,
	June 30,2011		December 31,2010
	September 30,2011		December 31,2010
	(in millions)
Fuel inventory:
Coal	$	7984	$	52
Fuel oil		5272		136
Other		43		1
Materials and supplies		7374		72
Purchased emissions allowances		3123		34
Total inventories	$	~~239~~256	$	295

119

GenOn Mid-Atlantic

		September 30,		September 30,
	June 30,2011		December 31,2010
	September 30,2011		December 31,2010
	(in millions)
Fuel inventory:
Coal	$	7984	$	52
Fuel oil		2119		20
Other		2		1
Materials and supplies		5052		49
Total inventories	$	~~152~~157	$	122

During the three months ended ~~June~~September 30, 2011 and 2010, GenOn Americas Generation recorded $~~1 million~~0 and $12 2 million, respectively, and during the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010, GenOn Americas Generation recorded $1 million and $2022 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, 2011 and 2010, GenOn Mid-Atlantic recorded $0 and $41 million, respectively, and during the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010, GenOn Mid-Atlantic recorded $0 1 million and $1213 million, respectively, for lower of average cost or market valuation adjustments in cost of fuel, electricity and other products.

Capitalization of Interest Cost (GenOn Americas Generation)

GenOn Americas Generation incurred the following interest costs:

		September 30,			September 30,			September 30,			September 30,
	Three Months EndedJune 30,						Six Months EndedJune 30,
	Three Months EndedSeptember 30,						Nine Months EndedSeptember 30,
	2011			2010			2011			2010
	(in millions)
Total interest costs	$	2120		$	5052		$	5272		$	~~102~~154
Capitalized and included in property, plant and equipment, net		—(1	)		(1	)		(12	)		(34	)
Interest expense	$	2119		$	4951		$	5170		$	99150

The amounts of capitalized interest above include interest accrued. During the three months ended ~~June~~September 30, 2011 and 2010, cash paid for interest was $~~60 million~~0 and $932 million, respectively, ofand ~~which~~we $1did ~~million~~not ~~and~~capitalize ~~$3 million,~~any ~~respectively,~~interest ~~were~~in ~~capitalized~~either period. During the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010, cash paid for interest was $60 million and $9597 million, respectively, of which $1 million and $3 million, respectively, were capitalized.

Recently Adopted Accounting Guidance

We adopted FASB accounting guidance for the quarter ended March 31, 2011 that requires a reconciliation for Level 3 fair value measurements, including presenting separately the amounts of purchases, issuances and settlements on a gross basis. See note 23 for additional information on fair value measurements.

New Accounting Guidance Not Yet Adopted at ~~June~~September 30, 2011

Fair Value Measurement and Disclosure. In May 2011, the FASB issued new fair value measurement and disclosure guidance. The new standard does not extend the use of fair value but rather provides guidance about how fair value should be determined and requires additional disclosures. The guidance is not expected to have a material effect on our fair value measurements, but will require disclosure of the following:

1210

•

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.

We will present the additional disclosures as required in our Form 10-Q for the quarter ended March 31, 2012.

2. ~~Financial~~ ~~Instruments~~Impairment of Long-Lived Assets and Emissions Allowances

We evaluate long-lived assets, such as property, plant and equipment and purchased intangible assets subject to amortization, for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Such evaluations are performed in accordance with the accounting guidance related to evaluating long-lived assets for impairment. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future cash flows, an impairment charge is recognized as the amount by which the carrying amount of the asset exceeds its fair value.

Granted Emissions Credits

In August 2011, the EPA finalized the regulations to replace the CAIR with the CSAPR starting in 2012. The CSAPR addresses interstate transport of emissions of NO_x and SO₂. The CSAPR establishes limitations on NO_x and/or SO₂ emissions from electric generating units that are (i) greater than 25 megawatts and (ii) located in 27 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 (PM_2.5) promulgated in 1997; (b) the “24-hour” NAAQS for PM_2.5 promulgated in 2006 and (c) the ozone NAAQS promulgated in 1997. The CSAPR creates “emission budgets” for each of the covered states and allocates emissions allowances (denominated in tons of emissions) to each of the 27 states regulated under the CSAPR. Under the EPA federal implementation plan, for 2012, GenOn Americas Generation was allocated 9,642, 4,311, and 19,285 allowances under the CSAPR for annual NO_x, ozone-season NO_x, and SO₂, respectively. For 2012, GenOn Mid-Atlantic was allocated 9,476, 4,194, and 18,925 allowances under the CSAPR for annual NO_x, ozone-season NO_x, and SO₂, respectively. The federal implementation plan has also outlined EPA-determined allocations in the same amounts for 2013, although the CSAPR contemplates that states after 2012 may allocate allowances in a different manner than allocated initially under the CSAPR. In October 2011, the EPA proposed revisions to the final CSAPR that, if finalized, would provide GenOn Americas Generation with a small allowance increase in each compliance year. As a result, the expected CSAPR allowances for GenOn Americas Generation would be 9,683, 4,345 and 19,339 in 2012 and 2013, for annual NO_x, ozone-season NO_x and SO₂, respectively. The CSAPR limits each electric generating unit’s NO_x and SO₂ emissions to amounts covered by the number of allowances held by that source in allowance accounts under the program (which may be purchased or otherwise acquired from other sources, subject to certain limitations in the rule). The NO_x allowances from the CAIR program will not be used in the CSAPR program and accordingly will have no value after 2011. The SO₂ allowances used for compliance in the CAIR program are the acid rain program allowances, which will have negligible value after 2011. As a result of the CSAPR, GenOn Americas Generation recorded impairment losses of $128 million for (a) the write-off of excess NO_x and SO₂ emissions allowances included in intangible assets ($70 million) and (b) the write-off of excess NO_x and SO₂emissions allowances previously included in property, plant and equipment ($58 million) during the three months ended September 30, 2011. As a result of the CSAPR, GenOn Mid-Atlantic recorded impairment losses of $94 million for (a) the write-off of excess NO_x and SO₂ emissions allowances included in intangible assets ($56 million) and (b) the write-off of excess NO_x and SO₂emissions allowances previously included in property, plant and equipment ($38 million) during the three months ended September 30, 2011. The emissions allowances within property, plant and equipment and intangible assets had previously been included with a generating facility asset group for purposes of impairment testing. As (a) there will be no future use of the NO_x emissions allowances and (b) the SO₂ emission allowances will have negligible value after 2011 under the CSAPR and their price has fallen sharply, we evaluated, in conjunction with preparing these interim financial statements, these emissions allowances for impairment separately from the generating facility asset group and determined that impairments existed.

At GenOn Americas Generation, CAIR NO_xemissions allowances of $43 million will have no value after 2011, and were therefore fully impaired. The excess acid rain program SO₂ emissions allowances of $86 million will have negligible value after 2011 and were impaired to their estimated fair value of $1 million based on their current market prices obtained from brokers. The excess acid rain program SO₂ emissions allowances were categorized in Level 3 in the fair value hierarchy.

At GenOn Mid-Atlantic, CAIR NO_xemissions allowances of $43 million will have no value after 2011, and were therefore fully impaired. The excess acid rain program SO₂ emissions allowances of $52 million will have negligible value after 2011 and were impaired to their estimated fair value of $1 million based on their current market prices obtained from brokers. The excess acid rain program SO₂ emissions allowances were categorized in Level 3 in the fair value hierarchy.

Potomac River Retirement

In the fourth quarter of 2010, GenOn Mid-Atlantic recorded impairment losses of $42 million to reduce the carrying value of the Potomac River generating facility to its estimated fair value of approximately $1 million. In addition, as a result of the impairment of the Potomac River generating facility, GenOn Mid-Atlantic recorded $32 million in operations and maintenance expense and corresponding liabilities associated with our commitment to reduce particulate emissions as part of the agreement with the City of Alexandria, Virginia. This $32 million is held in an escrow account. The planned capital investment would not be recovered in future periods based on the current projected cash flows of the Potomac River generating facility. See note 3(d) to our consolidated financial statements in our 2010 Annual Report on Form 10-K for further discussion.

In August 2011, GenOn Mid-Atlantic entered into an agreement with the City of Alexandria, Virginia to remove permanently from service its Potomac River generating facility. The agreement, which amends GenOn Mid-Atlantic’s Project Schedule and Agreement, dated July 17, 2008 with the City of Alexandria, provides for the retirement of the Potomac River generating facility on October 1, 2012, subject to the receipt of all necessary consents and approvals. PJM has determined that the retirement of the facility will not affect reliability. GenOn Mid-Atlantic must now receive consent from PEPCO. GenOn Mid-Atlantic will reverse the previously recorded obligation upon the receipt of consent from PEPCO and will recognize a reduction in operations and maintenance expense. If the PEPCO consent has not been received by July 3, 2012, the Potomac River generating facility will be retired within 90 days after the receipt thereof. Upon retirement of the Potomac River generating facility, all funds in the escrow account ($32 million) established under the July 17, 2008 agreement shall be distributed to GenOn Mid-Atlantic, provided, that, if the retirement of the facility is after January 1, 2014, $750,000 of such funds shall be paid to the City of Alexandria.

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 three million barrels of storage capacity that it owns or leases, 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.

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.

GenOn Americas Generation

The following table presents the fair value of GenOn Americas Generation’s derivative financial instruments:

		September 30,		September 30,		September 30,			September 30,			September 30,
	Derivative Contract Assets				Derivative Contract Liabilities						Net ~~DerivativeContractAssets (Liabilities)~~DerivativeContract
	Current		Long-Term		Current			Long- Term			Assets (Liabilities)
	(in millions)
June 30, 2011
September 30, 2011
Commodity Contracts:
Asset management	$	~~367~~338	$	~~554~~540	$	(~~221~~184	)	$	(7680	)	$	~~624~~614
Trading activities		~~449~~344		2719		(~~465~~348	)		(2717	)		(162	)
Total derivatives	$	~~816~~682	$	~~581~~559	$	(~~686~~532	)	$	(~~103~~97	)	$	~~608~~612
December 31, 2010
Commodity Contracts:
Asset management	$	442	$	623	$	(279	)	$	(102	)	$	$684
Trading activities		851		69		(854	)		(71	)		(5	)
Total derivatives	$	1,293	$	692	$	(1,133	)	$	(173	)	$	679

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

		September 30,			September 30,			September 30,			September 30,
	Three Months Ended June 30,
	Three Months Ended September 30,
	2011						2010
Derivatives Not Designated as Hedging Instruments	OperatingRevenues			Cost of Fuel,Electricity andOther Products			OperatingRevenues			Cost of Fuel,Electricity andOther Products
	(in millions)
Asset Management Commodity Contracts:
Unrealized	$	(251	)	$	15(10	)	$	~~(218~~164	)	$	~~(109~~13	)
Realized(1)(2)		6357			(1315	)		9154			(1169	)
Total asset management	$	3856		$	2(25	)	$	~~(127~~218	)	$	(~~120~~56	)
Trading Commodity Contracts:
Unrealized	$	11		$	—		$	(1310	)	$	—
Realized(1)(2)		(113	)		—			~~(21~~—	)		—
Total trading	$	10(2	)	$	—		$	(3410	)	$	—
Total derivatives	$	4854		$	2(25	)	$	~~(161~~208	)	$	(~~120~~56	)

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

(2)	Effective January 1, 2011, excludes settlement value of fuel contracts classified as inventory.

		September 30,			September 30,			September 30,			September 30,
	Nine Months Ended September 30,
	2011						2010
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	$	(88	)	$	19		$	299		$	(107	)
Realized⁽¹⁾⁽²⁾		188			(39	)		230			(95	)

Total asset management	$	100		$	(20	)	$	529		$	(202	)


Trading Commodity Contracts:
Unrealized	$	(1	)	$	—		$	(13	)	$	—
Realized⁽¹⁾⁽²⁾		(8	)		—			(2	)		—

Total trading	$	(9	)	$	—		$	(15	)	$	—


Total derivatives	$	91		$	(20	)	$	514		$	(202	)

(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)	Effective January 1, 2011, excludes settlement value of fuel contracts classified as inventory.

		September 30,			September 30,			September 30,			September 30,
	Six Months Ended June 30,
	2011						2010
Derivatives Not Designated as Hedging Instruments	OperatingRevenues			Cost of Fuel,Electricity andOther Products			OperatingRevenues			Cost of Fuel,Electricity andOther Products
	(in millions)
Asset Management Commodity Contracts:
Unrealized	$	(87	)	$	29		$	135		$	(120	)
Realized(1)(2)		131			(24	)		176			(26	)
Total asset management	$	44		$	5		$	311		$	(146	)
Trading Commodity Contracts:
Unrealized	$	(12	)	$	—		$	(3	)	$	—
Realized(1)(2)		5			—			(2	)		—
Total trading	$	(7	)	$	—		$	(5	)	$	—
Total derivatives	$	37		$	5		$	306		$	(146	)

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

(2) Effective January 1, 2011, excludes settlement value of fuel contracts classified as inventory.

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

		September 30,			September 30,			September 30,
	Notional Volumes at June 30, 2011
	Notional Volumes at September 30, 2011
Derivative Instruments	DerivativeContractAssets			DerivativeContractLiabilities			NetDerivativeContracts
	(in millions)
Commodity Contracts (in equivalent MWh):
Power(1)		(1956	)		~~(28~~21	)		(4735	)
Natural gas		(2418	)		2519			1
Fuel oil		2(1	)		(21	)		—
Coal		74			59			1213

		September 30,			September 30,			September 30,
	Notional Volumes at December 31, 2010
Derivative Instruments	Derivative Contract Assets			Derivative Contract Liabilities			Net Derivative Contracts
	(in millions)
Commodity Contracts (in equivalent MWh):
Power⁽¹⁾		(23	)		(15	)		(38	)
Natural gas		(28	)		29			1
Fuel oil		2			(3	)		(1	)
Coal		9			7			16

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

GenOn Mid-Atlantic

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

		September 30,		September 30,		September 30,			September 30,			September 30,
	Derivative Contract Assets				Derivative Contract Liabilities						Net ~~DerivativeContractAssets(Liabilities)~~Derivative Contract Assets
	Current		Long-Term		Current			Long-Term			(Liabilities)
	(in millions)
June 30, 2011
September 30, 2011
Commodity Contracts:
Asset management	$	~~155~~170	$	~~474~~452	$	(84	)	$	—		$	~~621~~618
Asset management—affiliate		136		44		(135	)		(41	)		4
Asset management – affiliate		113		38		(123	)		(33	)		(5	)
Total derivatives	$	~~291~~283	$	~~518~~490	$	(~~143~~127	)	$	(4133	)	$	~~625~~613
December 31, 2010
Commodity Contracts:
Asset management	$	162	$	516	$	(18	)	$	—		$	660
Asset management—affiliate		245		97		(231	)		(94	)		17
Asset management – affiliate		245		97		(231	)		(94	)		17
Total derivatives	$	407	$	613	$	(249	)	$	(94	)	$	677

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

		September 30,			September 30,			September 30,			September 30,
	Three Months Ended June 30,
	Three Months Ended September 30,
	2011						2010
Derivatives Not Designated as Hedging Instruments	OperatingRevenues			Cost of Fuel,Electricity andOther Products			OperatingRevenues			Cost of Fuel,Electricity andOther Products
	(in millions)
Asset Management Commodity Contracts:
Unrealized	$	(273	)	$	15(9	)	$	~~(205~~156	)	$	~~(112~~23	)
Realized(1)(2)		6154			—			8654			(458	)
Total asset management	$	3451		$	15(9	)	$	~~(119~~210	)	$	(~~116~~35	)

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

(2)	Effective January 1, 2011, excludes settlement value of fuel contracts classified as inventory.

		September 30,			September 30,		September 30,		September 30,
	Six Months Ended June 30,
	Nine Months Ended September 30,
	2011					2010
Derivatives Not Designated as Hedging Instruments	OperatingRevenues			Cost of Fuel,Electricity andOther Products		OperatingRevenues		Cost of Fuel,Electricity andOther Products
	(in millions)
Asset Management Commodity Contracts:
Unrealized	$	(7881	)	$	2718	$	~~133~~289	$	(~~104~~81	)
Realized(1)(2)		~~122~~176			—		~~161~~215		(462	)
Total asset management	$	4495		$	2718	$	~~294~~504	$	(~~108~~143	)

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

(2)	Effective January 1, 2011, excludes settlement value of fuel contracts classified as inventory.

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

		September 30,			September 30,			September 30,
	Notional Volumes at June 30, 2011
	Notional Volumes at September 30, 2011
Derivative Instruments	Derivative ContractAssets			Derivative ContractLiabilities			Net DerivativeContracts
	(in millions)
Commodity Contracts (in equivalent MWh):
Power(1)		(2940	)		(6	)		(3534	)
Coal		54			89			13
	Notional Volumes at December 31, 2010
Derivative Instruments	Derivative ContractAssets			Derivative ContractLiabilities			Net DerivativeContracts
	(in millions)
Commodity Contracts (in equivalent MWh):
Power(1)		(40	)		4			(36	)
Coal		6			10			16

		September 30,			September 30,		September 30,
	Notional Volumes at December 31, 2010
Derivative Instruments	Derivative Contract Assets			Derivative Contract Liabilities		Net Derivative Contracts
	(in millions)
Commodity Contracts (in equivalent MWh):
Power⁽¹⁾		(40	)		4		(36	)
Coal		6			10		16

(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. The 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:		This category includes the 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, power and natural gas contracts, and options valued using internally developed inputs.

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. The 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:

This category includes the 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, 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.

Most 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 that 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 September 30, 2011, we obtained broker quotes for 100% of our delivery locations classified in Level 2 of the fair value hierarchy.

~~Most~~Inactive ~~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~~are ~~regularly facilitate our transactions. An active market is~~ considered to ~~have~~be ~~transactions~~those markets with ~~sufficient~~few ~~frequency~~transactions, ~~and volume to~~noncurrent ~~provide~~ pricing ~~information~~or onprices ~~an ongoing basis. We think~~ that ~~these~~vary ~~prices~~over ~~represent~~time ~~the~~or ~~best~~among ~~available information for valuation purposes. In determining the fair value of derivative contract assets and liabilities, we use third-party~~ market ~~pricing~~ ~~where available~~makers. ~~For~~Our transactions ~~classified~~ in Level 13 of the fair value hierarchy, wemay ~~use~~involve ~~the~~transactions ~~unadjusted~~whereby ~~published~~observable ~~settled~~market ~~prices~~data, onsuch ~~the~~as ~~valuation~~broker ~~date.~~quotes, ~~For~~are ~~transactions~~not ~~classified~~available infor ~~Level~~substantially 2all of the ~~fair value hierarchy, we value these~~ ~~transactions~~tenor ~~using~~of ~~indicative~~the ~~quoted~~contract ~~prices from independent brokers~~ or ~~other~~we ~~widely-accepted valuation methodologies. Transactions~~ are ~~classified~~only inable ~~Level 2~~to ifobtain ~~substantially~~indicative ~~all~~broker ~~(greater~~quotes ~~than~~that ~~90%)~~cannot ~~of the fair value can~~ be corroborated ~~using~~ by observable market ~~inputs such as transactable broker quotes~~data. In ~~accordance~~such ~~with~~cases, ~~the~~we ~~exit~~may ~~price~~apply ~~objective~~valuation ~~under~~techniques ~~the~~such ~~fair~~as ~~value~~extrapolation ~~measurements~~and ~~accounting~~other ~~guidance,~~quantitative ~~the~~methods to determine fair value. ofProprietary ~~our~~models ~~derivative~~may ~~contract~~also ~~assets~~be ~~and~~used ~~liabilities~~to isestimate ~~determined based on~~ the ~~net~~fair ~~underlying~~value ~~position~~ of ~~the recorded~~ derivative contract assets and liabilities ~~using~~that ~~bid~~may ~~prices~~be ~~for~~structured ~~assets~~or ~~and~~otherwise ~~ask prices for liabilities~~tailored. ~~The~~Our ~~quotes~~techniques ~~that~~for wefair ~~obtain~~value ~~from~~estimation ~~brokers~~include ~~are~~assumptions ~~non-binding~~for inmarket ~~nature~~prices, ~~but are from brokers that typically~~ ~~transact~~correlation ~~in the market being quoted~~ and ~~are based on their knowledge of market transactions on the valuation date~~volatility. WeThe ~~typically~~degree ~~obtain multiple broker quotes as~~ of ~~the~~estimation ~~valuation~~increases ~~date that extend~~ for ~~the~~longer ~~tenor~~duration ofcontracts, ~~the underlying~~ contracts ~~for~~with ~~each delivery~~multiple ~~location.~~pricing ~~The~~features, ~~number~~option ofcontracts ~~quotes~~and ~~that~~off-hub ~~we can obtain depends on the relative liquidity of the~~ delivery ~~location on the valuation date~~points. IfAt ~~multiple~~September 30, ~~broker quotes are received for a contract~~2011, weGenOn ~~use~~Americas anGeneration’s ~~average of the quoted bid or ask prices. If~~assets ~~only one broker quote is received for a delivery location~~ and itliabilities ~~cannot~~classified beas ~~validated~~Level 3 ~~through~~in ~~other external sources, we will assign~~ the ~~quote to a lower level within the~~ fair value hierarchy. Inrepresented ~~some~~approximately ~~instances,~~3% weof ~~may~~its ~~combine~~total ~~broker~~derivative ~~quotes~~contract ~~for~~assets ~~a liquid delivery hub with broker quotes for the price spread between the liquid delivery hub~~ and ~~the~~13% ~~delivery~~of ~~location~~its ~~under~~total ~~the~~derivative contract. ~~We also may apply interpolation techniques to value monthly strips if broker quotes are only available on a seasonal or annual basis~~liabilities. WeAt ~~perform~~September 30, ~~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~~2011, weGenOn ~~may~~Mid-Atlantic’s ~~exclude~~assets ~~from consideration a broker quote if it is a clear outlier~~ and ~~other~~liabilities ~~quotes~~classified ~~are~~as ~~obtained. At June~~Level ~~30,~~3 ~~2011,~~in wethe ~~obtained~~fair ~~broker~~value ~~quotes~~hierarchy ~~for~~represented ~~100~~approximately 2% of ~~our~~its ~~delivery~~total ~~locations~~derivative ~~classified~~contract inassets ~~Level~~and 242% of ~~the~~its ~~fair~~total ~~value~~derivative ~~hierarchy~~contract liabilities.

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. Proprietary models may also be used to estimate the fair value of derivative contract assets and liabilities that may be structured or otherwise tailored. Our techniques for fair value estimation include assumptions for market prices, correlation and volatility. The degree of estimation increases for longer duration contracts, contracts with multiple pricing features, option contracts and off-hub delivery points. At June 30, 2011, GenOn Americas Generation’s assets and liabilities classified as Level 3 in the fair value hierarchy represented approximately 4% of its total derivative contract assets and 11% of its total derivative contract liabilities. At June 30, 2011, GenOn Mid-Atlantic’s assets and liabilities classified as Level 3 in the fair value hierarchy represented approximately 4% of its total derivative contract assets and 38% 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 to us. 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.

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 by class are as follows:

		September 30,		September 30,		September 30,		September 30,
	June 30, 2011
	September 30, 2011
	Level 1(1)		Level 2(1) (2)		Level 3		~~Total~~TotalFair ~~FairValue~~Value
	(in millions)
Derivative contract assets:
Commodity Contracts
Asset Management:
Power	$	1031	$	~~855~~810	$	148	$	~~879~~849
Fuel		24		83		3222		4229
Total Asset Management		1235		~~863~~813		4630		~~921~~878
Trading Activities		~~214~~202		~~253~~148		913		~~476~~363
Total derivative contract assets	$	~~226~~237	$	~~1,116~~961	$	5543	$	1,~~397~~241
Derivative contract liabilities:
Commodity Contracts
Asset Management:
Power	$	1944	$	~~179~~124	$	87	$	~~206~~175
Fuel		1419		62		7168		9189
Total Asset Management		3363		~~185~~126		7975		~~297~~264
Trading Activities		~~223~~213		~~264~~145		57		~~492~~365
Total derivative contract liabilities	$	~~256~~276	$	~~449~~271	$	8482	$	~~789~~629
Interest-bearing funds(3)	$	~~454~~391	$	—	$	—	$	~~454~~391

(1) Transfers between Level 1 and Level 2 are recognized as of the end of the reporting period. There were no significant transfers during the ~~six~~nine months ended ~~June~~September 30, 2011.

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

(3) 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. GenOn Americas Generation had $~~273~~187 million of interest-bearing funds included in cash and cash equivalents, $~~147~~166 million included in funds on deposit and $3438 million included in other noncurrent assets.

		September 30,		September 30,		September 30,		September 30,
	December 31, 2010
	Level 1⁽¹⁾		Level 2^(1) (2)		Level 3		Total Fair Value
	(in millions)
Derivative contract assets:
Commodity Contracts
Asset Management:
Power	$	1	$	1,022	$	2	$	1,025
Fuel		4		3		33		40

Total Asset Management		5		1,025		35		1,065
Trading Activities		530		385		5		920

Total derivative contract assets	$	535	$	1,410	$	40	$	1,985


Derivative contract liabilities:
Commodity Contracts
Asset Management:
Power	$	12	$	248	$	4	$	264
Fuel		18		—		99		117

Total Asset Management		30		248		103		381
Trading Activities		533		389		3		925

Total derivative contract liabilities	$	563	$	637	$	106	$	1,306


Interest-bearing funds⁽³⁾	$	547	$	—	$	—	$	547

(1)	Transfers between Level 1 and Level 2 are recognized as of the end of the reporting period. There were no significant transfers during 2010.

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

(3)

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. GenOn Americas Generation had $508 million of interest-bearing funds included in cash and cash equivalents, $2 million included in funds on deposit and $37 million included in other noncurrent assets.

The following is a reconciliation of changes (composed of the sum of the quarterly changes) in fair value of net commodity derivative contract assets and liabilities classified as Level 3 during the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010, respectively:

		September 30,			September 30,			September 30,
	Net Derivatives Contracts (Level 3)
	AssetManagement			~~TradingActivities~~Trading Activities			Total
	(in millions)
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	)
Balance, January 1, 2010 (net asset (liability))	$	19		$	13		$	32
Total gains (losses) realized/unrealized:
Included in earnings(1)		(~~133~~45	)		(1622	)		(~~149~~67	)
Purchases(2)		—			—			—
Issuances(2)		—			—			—
Settlements(5)		(1680	)		2228			6(52	)
Transfers in and out of Level 3(4)		38			—(1	)		3837
Balance, June 30, 2010 (net asset (liability))	$	(92	)	$	19		$	(73	)
Balance, September 30, 2010 (net asset (liability))	$	(68	)	$	18		$	(50	)

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

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

(3) Effective January 1, 2011, represents the reversal of previously recognized unrealized gains and losses from settlement of contracts during each ~~quarterly~~ reporting period.

(4) Denotes the total contracts that existed at the beginning of each ~~quarterly~~ reporting period and were still held at the end of each ~~quarterly~~ 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 ~~quarterly~~ reporting period. Amounts reflect fair value as of the end of each ~~quarterly~~ reporting period.

(5) Represents the total cash settlements of contracts during each ~~quarterly~~ reporting period that existed at the beginning of each ~~quarterly~~ reporting period.

The following table presents the amounts included in income related to derivative contract assets and liabilities classified as Level 3:

		September 30,			September 30,			September 30,			September 30,			September 30,			September 30,
	Three Months Ended June 30,
	Three Months Ended September 30,
	2011									2010
	OperatingRevenues			Cost ~~ofFuel~~of Fuel,Electricityand OtherProducts			Total			OperatingRevenues			Cost ~~ofFuel~~of Fuel,Electricityand OtherProducts			Total
	(in millions)
Gains (losses) included in income	$	7(3	)	$	15(7	)	$	22(10	)	$	(361	)	$	~~(113~~24	)	$	~~(149~~23	)
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	$	7		$	15		$	22		$	(31	)	$	(113	)	$	(144	)
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	$	(2	)	$	(6	)	$	(8	)	$	(1	)	$	24		$	23

		September 30,		September 30,		September 30,		September 30,		September 30,			September 30,
	Six Months Ended June 30,
	Nine Months Ended September 30,
	2011						2010
	OperatingRevenues		Cost ~~ofFuel~~of Fuel,Electricityand OtherProducts		Total		OperatingRevenues		Cost ~~ofFuel~~of Fuel,Electricityand OtherProducts			Total
	(in millions)
Gains (losses) included in income	$	107	$	2720	$	3727	$	21	$	(~~107~~83	)	$	(~~105~~82	)
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	$	10	$	28	$	38	$	7	$	(107	)	$	(100	)
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	$	8	$	22	$	30	$	6	$	(83	)	$	(77	)

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 by class are as follows:

		September 30,		September 30,		September 30,		September 30,
	June 30, 2011
	September 30, 2011
	Level 1(1)		Level 2(1) (2)		Level 3		TotalFair Value
	(in millions)
Derivative contract assets:
Commodity Contracts
Asset Management:
Power	$	16	$	~~774~~748	$	4—	$	~~779~~754
Fuel		—		1		2918		3019
Total derivative contract assets	$	16	$	~~775~~749	$	3318	$	~~809~~773
Derivative contract liabilities:
Commodity Contracts
Asset Management:
Power	$	1118	$	~~103~~73	$	—1	$	~~114~~92
Fuel		—2		—		7066		7068
Total derivative contract liabilities	$	1120	$	~~103~~73	$	7067	$	~~184~~160
Interest-bearing funds(3)	$	~~223~~277	$	—	$	—	$	~~223~~277

(1) Transfers between Level 1 and Level 2 are recognized as of the end of the reporting period. There were no significant transfers during the ~~six~~nine months ended ~~June~~September 30, 2011.

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

(3) Represents investments in money market funds and are included in cash and cash equivalents, funds on deposit and other noncurrent assets in the consolidated balance sheet. GenOn Mid-Atlantic had $4879 million of interest-bearing funds included in cash and cash equivalents, $~~147~~166 million included in funds on deposit and $2832 million included in other noncurrent assets.

		September 30,		September 30,		September 30,		September 30,
	December 31, 2010
	Level 1⁽¹⁾		Level 2^(1) (2)		Level 3		Total Fair Value
	(in millions)
Derivative contract assets:
Commodity Contracts
Asset Management:
Power	$	1	$	986	$	—	$	987
Fuel		—		2		31		33

Total derivative contract assets	$	1	$	988	$	31	$	1,020


Derivative contract liabilities:
Commodity Contracts
Asset Management:
Power	$	12	$	231	$	1	$	244
Fuel		—		—		99		99

Total derivative contract liabilities	$	12	$	231	$	100	$	343


Interest-bearing funds⁽³⁾	$	234	$	—	$	—	$	234

(1)	Transfers between Level 1 and Level 2 are recognized as of the end of the reporting period. There were no significant transfers during 2010.

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

(3)

Represents investments in money market funds and are included in cash and cash equivalents, funds on deposit and other noncurrent assets in the consolidated balance sheet. GenOn Mid-Atlantic had $202 million of interest-bearing funds included in cash and cash equivalents, $2 million included in funds on deposit and $30 million included in other noncurrent assets.

~~The~~23 following is a reconciliation of changes in fair value of net commodity derivative contract assets and liabilities classified as Level 3 during the six months ended June 30, 2011 and 2010, respectively:

		September 30,
	AssetManagement
	(in millions)
Balance, January 1, 2011 (net asset (liability))	$	(69	)
Total gains (losses) realized/unrealized:
Included in earnings(1)		25
Purchases(2)		—
Issuances(2)		—
Settlements(3)		7
Transfers into Level 3(4)		—
Transfers out of Level 3(4)		—
Balance, June 30, 2011 (net asset (liability))	$	(37	)
Balance, January 1, 2010 (net asset (liability))	$	13
Total gains (losses) realized/unrealized:
Included in earnings(1)		(146	)
Purchases(2)		—
Issuances(2)		—
Settlements(5)		(4	)
Transfers in and out of Level 3(4)		38
Balance, June 30, 2010 (net asset (liability))	$	(99	)

~~(1)~~The ~~Represents~~following ~~the~~is ~~fair~~a ~~value,~~reconciliation as of ~~the~~changes ~~end~~(composed of ~~each~~the ~~quarterly~~sum ~~reporting period,~~ of ~~Level~~the 3quarterly ~~contracts~~changes) in ~~entered~~fair ~~into~~value ~~during~~of ~~each~~net ~~quarterly~~commodity ~~reporting~~derivative ~~period~~contract ~~and~~assets ~~the gains~~ and ~~losses~~liabilities ~~attributable~~classified toas Level 3 ~~contracts~~during ~~that existed as of~~ the ~~beginning~~nine ofmonths ~~each~~ended ~~quarterly~~September 30, ~~reporting~~2011 ~~period~~ and ~~were~~2010, ~~still~~respectively: ~~held at the end of each quarterly reporting period.~~

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

		September 30,
	Asset Management
	(in millions)

Balance, January 1, 2011 (net asset (liability))	$	(69	)
Total gains (losses) realized/unrealized:
Included in earnings⁽¹⁾		(5	)
Purchases⁽²⁾		—
Issuances⁽²⁾		—
Settlements⁽³⁾		13
Transfers into Level 3⁽⁴⁾		—
Transfers out of Level 3⁽⁴⁾		12

Balance, September 30, 2011 (net asset (liability))	$	(49	)


Balance, January 1, 2010 (net asset (liability))	$	13
Total gains (losses) realized/unrealized:
Included in earnings⁽¹⁾		(64	)
Purchases⁽²⁾		—
Issuances⁽²⁾		—
Settlements⁽⁵⁾		(63	)
Transfers in and out of Level 3⁽⁴⁾		38

Balance, September 30, 2010 (net asset (liability))	$	(76	)

(31) ~~Effective~~Represents ~~January~~the 1,fair ~~2011~~value, ~~represents~~as of the ~~reversal~~end of ~~previously~~each ~~recognized~~reporting ~~unrealized~~period, of Level 3 contracts entered into during each reporting period and the gains and losses ~~from~~attributable ~~settlement~~to ofLevel 3 contracts ~~during~~that existed as of the beginning of each ~~quarterly~~reporting period and were still held at the end of each reporting period.

(42) ~~Denotes~~Contracts ~~the~~entered ~~total~~into ~~contracts~~during ~~that existed at the beginning of~~ each ~~quarterly~~ reporting period ~~and~~are ~~were~~reported ~~still~~with ~~held~~other atchanges ~~the~~in end of each quarterly 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 quarterly reporting period. Amounts reflect fair value ~~as of the end of each quarterly reporting period~~.

(53) ~~Represents~~Effective ~~the~~January ~~total~~1, ~~cash~~2011, ~~settlements~~represents ofthe ~~contracts~~reversal ~~during~~of ~~each~~previously ~~quarterly~~recognized ~~reporting~~unrealized ~~period~~gains ~~that~~and ~~existed~~losses atfrom ~~the~~settlement ~~beginning~~ of ~~each~~contracts ~~quarterly~~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.

(5)	Represents the total cash settlements of contracts during each reporting period that existed at the beginning of each reporting period.

The following table presents the amounts included in income related to derivative contract assets and liabilities classified as Level 3:

		September 30,			September 30,			September 30,			September 30,			September 30,			September 30,
	Three Months Ended June 30,
	Three Months Ended September 30,
	2011									2010
	OperatingRevenues			Cost of Fuel,~~Electricity~~Electricityand ~~andOther Products~~OtherProducts			Total			OperatingRevenues			Cost of Fuel,~~Electricity~~Electricityand ~~andOther Products~~OtherProducts			Total
	(in millions)
Gains (losses) included in income	$	(5	)	$	16(7	)	$	21(12	)	$	—(1	)	$	~~(113~~24	)	$	~~(113~~23	)
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	$	5		$	16		$	21		$	—		$	(113	)	$	(113	)
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	$	(7	)	$	(7	)	$	(14	)	$	(1	)	$	24		$	23

		September 30,			September 30,		September 30,		September 30,			September 30,			September 30,
	Six Months Ended June 30,
	Nine Months Ended September 30,
	2011							2010
	OperatingRevenues			Cost of Fuel,~~Electricity~~Electricityand ~~andOther Products~~OtherProducts		Total		OperatingRevenues			Cost of Fuel,~~Electricity~~Electricityand ~~andOther Products~~OtherProducts			Total
	(in millions)
Gains (losses) included in income	$	5—		$	2820	$	3320	$	(62	)	$	~~(106~~2	)	$	~~(112~~4	)
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	$	5		$	28	$	33	$	(6	)	$	(106	)	$	(112	)
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	$	(2	)	$	21	$	19	$	2		$	2		$	4

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 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 do not require either party to post cash collateral for initial margin or for securing exposure as a result of changes in power or natural gas prices. ~~Our~~GenOn Americas Generation and GenOn Mid-Atlantic credit valuation ~~adjustment~~adjustments on derivative contract assets ~~was~~were $1550 million and $19 million at ~~June~~September 30, 2011 and December 31, 2010, respectively.

At ~~June~~September 30, 2011 and December 31, 2010, $~~7 million and $~~3 million, ~~respectively,~~ of cash collateral posted to GenOn Americas Generation by counterparties under master netting agreements ~~were~~was included in accounts payable and accrued liabilities on GenOn Americas Generation’s consolidated balance sheets.

We also 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

		September 30,		September 30,		September 30,		September 30,		September 30,
	June 30, 2011
	September 30, 2011
Credit Rating Equivalent	GrossExposureBeforeCollateral(1)		NetExposureBeforeCollateral(2)		Collateral(3)		ExposureNet ofCollateral		% of NetExposure
	(dollars in millions)
Clearing and Exchange	$	~~536~~448	$	142	$	142	$	—
Investment Grade:
Financial institutions		~~702~~730		~~654~~690		—		~~654~~690		7679	%
Energy companies		~~254~~212		~~136~~126		2		~~134~~124		1514	%
Non-investment Grade:
Energy companies		198		198		5—		148		21	%
No External Ratings:
Internally-rated investment grade		3836		3836		—1		3835		4	%
Internally-rated non-investment grade		2421		2421		—		2421		32	%
Total	$	1,~~573~~455	$	~~872~~923	$	845	$	~~864~~878		100	%

		September 30,		September 30,		September 30,		September 30,		September 30,
	December 31, 2010
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	$	987	$	39	$	39	$	—
Investment Grade:
Financial institutions		806		707		—		707		78	%
Energy companies		337		130		2		128		14	%
Non-investment Grade:
Energy companies		15		15		—		15		2	%
No External Ratings:
Internally-rated investment grade		34		27		—		27		3	%
Internally-rated non-investment grade		26		26		—		26		3	%

Total	$	2,205	$	944	$	41	$	903		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 the 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 with counterparties and netting of transactions with clearing brokers and exchanges.

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

GenOn Mid-Atlantic

		September 30,		September 30,		September 30,		September 30,		September 30,
	June 30, 2011
	September 30, 2011
Credit Rating Equivalent	GrossExposureBeforeCollateral(1),(4)		NetExposureBeforeCollateral(2)		Collateral(3)		ExposureNet ofCollateral		% of NetExposure
	(dollars in millions)
Investment Grade:
Financial institutions	$	~~656~~687	$	~~645~~678	$	—	$	~~645~~678		9596	%
Non-investment Grade:
Energy companies		127		127		—		127		21	%
No External Ratings:
Internally-rated non-investment grade		2421		2421		—		2421		3	%
Total	$	~~692~~715	$	~~681~~706	$	—	$	~~681~~706		100	%

		September 30,		September 30,		September 30,		September 30,		September 30,
	December 31, 2010
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	$	714	$	695	$	—	$	695		95	%
Non-investment Grade:
Energy companies		13		13		—		13		2	%
No External Ratings:
Internally-rated non-investment grade		25		25		—		25		3	%

Total	$	752	$	733	$	—	$	733		100	%

(1)

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

(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 Americas Generation had credit exposure to two investment grade counterparties at ~~June~~September 30, 2011 and December 31, 2010, respectively, each representing an exposure of more than 10% of total credit exposure, net of collateral and totaling $~~550~~586 million and $568 million at ~~June~~September 30, 2011 and December 31, 2010, respectively.

GenOn Mid-Atlantic had credit exposure to ~~two~~ two investment grade counterparties at ~~June~~September 30, 2011 and three investment grade counterparties at December 31, 2010, respectively, each representing an exposure of more than 10% of total credit exposure, net of collateral and totaling $~~550~~586 million and $653 million at ~~June~~September 30, 2011 and December 31, 2010, respectively.

GenOn Americas Generation and GenOn Mid-Atlantic Credit Risk

Our standard industry contracts contain credit-risk-related contingent features such as 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 language, which is generally ~~subjective~~ 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 September 30, 2011, the fair value of GenOn Americas Generation’s financial instruments with credit-risk-related contingent features in a net liability position was $11 million for which GenOn Americas Generation had posted collateral of $9 million, including cash and letters of credit. At September 30, 2011, GenOn Mid-Atlantic did not have any financial instruments with credit-risk-related contingent features in a net liability position.

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, 2011, ~~the~~and ~~fair~~December 31, ~~value~~2010, of GenOn Americas Generation’s ~~financial instruments with credit-risk-related contingent features in a net liability position was~~had $2154 million ~~for~~and ~~which GenOn Americas Generation had posted collateral of~~ $19 1 million, ~~including~~respectively, ~~cash and letters~~ of ~~credit.~~cash Atcollateral ~~June 30,~~posted ~~2011,~~with ~~GenOn~~counterparties ~~Mid-Atlantic~~under ~~did~~master ~~not~~netting ~~have~~agreements ~~any~~that ~~financial~~was ~~instruments~~included ~~with~~in ~~credit-risk-related contingent~~funds ~~features~~on indeposit aon ~~net~~the ~~liability~~consolidated ~~position~~balance sheets.

At June 30, 2011 and December 31, 2010, GenOn Americas Generation had $70 million and $1 million, respectively, of cash collateral posted with counterparties under master netting agreements that was included in funds on deposit on the consolidated balance sheets.

Fair Values of Other Financial Instruments (GenOn Americas Generation)

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

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

September 30,

June 30, 2011

December 31, 2010

September 30, 2011

December 31, 2010

CarryingAmount

Fair Value

CarryingAmount

Fair Value

~~(in millions)~~

(in millions)

Liabilities:

Long and short-term debt(1)

~~868~~867

~~861~~748

2,255

2,~~272~~273

_________________

(1)	The fair value of GenOn Americas Generation’s long- and short-term debt is estimated using reported market prices, when available.

34. Long-Term Debt

Outstanding debt was as follows:

		September 30,			September 30,			September 30,		September 30,			September 30,			September 30,
	June 30, 2011								December 31, 2010
	September 30, 2011								December 31, 2010
	StatedInterestRate(1)			Long-term			Current		StatedInterestRate(1)			Long-term			Current
	StatedInterestRate (1)			Long-term			Current		StatedInterestRate(1)			Long-term			Current
	(in millions, except interest rates)
Bonds and Notes:
GenOn Americas Generation:
Senior unsecured notes, due 2011(2)		—		$	—		$	—		8.30	%	$	—		$	535
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, net		—			(2	)		—		—			(2	)		—
GenOn North America:
Senior notes, due 2013(3)		—			—			—		7.375			—			850
GenOn Mid-Atlantic:								—
GenOn Chalk Point capital lease, due 2011 to 2015		8.19	%		1615			4		8.19			18			4
Total				$	~~864~~863		$	4				$	866		$	1,389

(1) The stated interest rates are at ~~June~~September 30, 2011 and December 31, 2010.

(2)	These notes were repaid on May 2, 2011.

(3)	These notes were discharged at the closing of the Merger on December 3, 2010 and were redeemed on January 3, 2011 at a call price of 101.844% of the principal amount.

GenOn North America Senior Notes Due 2013

Upon the closing of the Merger, the senior ~~secured~~ notes due 2013 of GenOn North America (issued in 2005) were discharged following the ~~deposit~~ deposit with the trustee of funds sufficient to pay the redemption price thereof, plus accrued interest to the date of redemption. The amount of funds on deposit with the trustee was $866 million at December 31, 2010 and was recorded as ~~restricted~~ restricted cash included in funds on deposit on the consolidated balance sheet.

On January 3, 2011, the senior ~~secured~~ notes were redeemed at the call price of 101.844% of the principal amount plus accrued and unpaid interest through the date of redemption. The total payment on the date of redemption was $866 million and a $23 million loss on early extinguishment of debt (in other, net on the consolidated statement of operations) was recognized during the three months ended March 31, 2011, which includes a $16 million premium and $7 million of unamortized debt issuance costs.

GenOn Americas Generation Senior Notes

On May 2, 2011, GenOn Americas Generation repaid the $535 million of senior notes that came due.

45. Guarantees and Letters of Credit

GenOn generally conducts its business through various intermediate 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.

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 (including for commodities), construction agreements and agreements with vendors. Although the primary obligation 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.

Upon issuance or modification of a guarantee, GenOn Americas Generation determines if the obligation is subject to initial recognition and measurement of a liability and/or disclosure of the nature and terms of the guarantee. Generally, guarantees of the performance of a third party are subject to the recognition and measurement, and the disclosure provisions, of the accounting guidance related to guarantees. Such guarantees must initially be recorded at fair value, as determined in accordance with the accounting guidance.

Following is a summary of letters of credit issued and surety bonds provided:

		September 30,		September 30,
	June 30,2011		December 31,2010
	September 30,2011		December 31,2010
	(in millions)
Letters of credit—rent reserves(1)	$	9875	$	101
Letters of credit—energy trading and marketing activities(1)		4730		63
Letters of credit—other operating activities(1)		33		31
Surety bonds		82		7
Total	$	~~186~~140	$	202

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

This note should be read in conjunction with note 7 to our consolidated financial statements in our 2010 Annual Report on Form 10-K.

56. Related Party Arrangements and Transactions

Administrative Services Agreement with GenOn Energy Services

GenOn Energy Services provides us with various management, personnel and other services as set forth in the Administrative Services Agreement. We reimburse GenOn Energy Services for amounts equal to GenOn Energy Services’ costs of providing such services.

The total costs incurred under the Administrative Services Agreement with GenOn Energy Services have been included in our unaudited condensed consolidated statements of operations as follows:

GenOn Americas Generation

		September 30,		September 30,		September 30,		September 30,
	Three Months EndedJune 30,				Six Months EndedJune 30,
	Three Months EndedSeptember 30,				Nine Months EndedSeptember 30,
	2011		2010		2011		2010
	(in millions)
Cost of fuel, electricity and other products—affiliate	$	32	$	12	$	57	$	46
Operations and maintenance expense—affiliate		3531		4041		6798		80121
Total	$	3833	$	4143	$	72105	$	84127

GenOn Mid-Atlantic

		September 30,		September 30,		September 30,		September 30,
	Three Months EndedJune 30,				Six Months EndedJune 30,
	Three Months EndedSeptember 30,				Nine Months EndedSeptember 30,
	2011		2010		2011		2010
	(in millions)
Cost of fuel, electricity and other products—affiliate	$	32	$	12	$	57	$	46
Operations and maintenance expense—affiliate		2019		2425		3857		4970
Total	$	2321	$	2527	$	4364	$	5376

Services Provided by GenOn Energy Management

GenOn Americas Generation

As a result of the Merger, 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 unaudited condensed consolidated statements of operations. Amounts due from and to GenOn’s indirect operating subsidiaries are recorded as accounts receivable—affiliate or net payable—affiliate, as appropriate. Substantially all energy marketing overhead expenses are allocated to GenOn’s operating subsidiaries. During the three and ~~six~~nine months ended ~~June~~September 30, 2011, GenOn Americas Generation recorded a reduction to operations and maintenance expense—affiliate of $87 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 unaudited condensed 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, ~~fuel~~ 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, ~~and~~ cost of fuel, electricity and other products—affiliate and operations and maintenance expense—affiliate, as appropriate, in the unaudited condensed consolidated statements of operations. Amounts due to and from GenOn Energy Management under the Power Sale, Fuel Supply and Services Agreement are recorded as a net payable—affiliate or accounts receivable—affiliate, as appropriate. Substantially all energy marketing overhead expenses are allocated to GenOn’s operating subsidiaries. During the three months ended ~~June~~September 30, 2011 and 2010, GenOn Mid-Atlantic incurred $1 million and $3 million, respectively, of energy marketing overhead expenses. During the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010, GenOn Mid-Atlantic incurred $23 million and $710 million, respectively, of energy marketing overhead expenses. These costs are included in operations and maintenance expense—affiliate in GenOn Mid-Atlantic’s unaudited condensed consolidated statements of operations.

Power Sales and Fuel Supply Arrangement with GenOn Energy Management (GenOn Mid-Atlantic)

GenOn Mid-Atlantic operates under a Power Sale, Fuel Supply and Services Agreement with GenOn Energy Management. Amounts due to GenOn Energy Management for fuel purchases and due from GenOn Energy Management for power and capacity sales are recorded as a payable—affiliate or accounts receivable—affiliate in GenOn Mid-Atlantic’s unaudited condensed consolidated balance sheets.

Under the Power Sale, Fuel Supply and Services Agreement, 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.

Services Agreement with GenOn Marsh Landing (GenOn Americas Generation)

During 2010, GenOn Energy Management entered into a services agreement with GenOn Marsh Landing that includes the bidding and dispatch of the Marsh Landing generating units, fuel procurement and the execution of contracts to reduce price risk, except to the extent that GenOn Marsh Landing contracts directly with third-parties, including the PPA with PG&E. As reimbursement for such services, GenOn Marsh Landing has agreed to pay GenOn Energy Management the allocated cost to GenOn Energy Management of providing such services.

Administration Arrangements with GenOn Energy Services

Prior to the completion of the Merger, substantially all of GenOn’s corporate overhead costs were allocated to its operating subsidiaries based on an average of each operating subsidiaries’ gross margin, labor costs and net property, plant and equipment relative to all operating subsidiaries. For periods subsequent to the completion of the Merger, GenOn’s corporate overhead costs are allocated based on each operating subsidiaries’ planned operating expenses relative to all operating subsidiaries. Management has concluded that this method of allocating overhead costs is reasonable. During the three and ~~six~~nine months ended ~~June~~September 30, 2011 and 2010, we incurred the following in costs under these arrangements, which are included in operations and maintenance expense—affiliate in our unaudited condensed consolidated statements of operations:

		September 30,		September 30,		September 30,		September 30,
	Three Months Ended June 30,				Six Months Ended June 30,
	Three Months EndedSeptember 30,				Nine Months EndedSeptember 30,
	2011		2010		2011		2010
	(in millions)
GenOn Americas Generation	$	3229	$	3233	$	6594	$	6295
GenOn Mid-Atlantic	$	2119	$	2022	$	4261	$	3961

These allocations and charges are not necessarily indicative of what would have been incurred had we been an unaffiliated entity.

Notes Receivable from Affiliate and Notes Payable to Affiliate (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 from affiliate and notes payable to affiliate. The notes are due on demand and accrue interest, which is payable quarterly, at the yield of a short term Treasury security fund. At ~~June~~September 30, 2011 GenOn Americas Generation had current notes receivable from GenOn Energy Holdings of $~~145~~ 161 million related to its intercompany cash management program. During the three and ~~six~~nine months ended ~~June~~ September 30, 2011, GenOn Americas Generation earned an insignificant amount of interest income related to the notes receivable. At ~~June~~September 30, 2011 GenOn Americas Generation had current notes payable to GenOn Energy Holdings of $2431 million related to its intercompany cash management program. During the three and ~~six~~nine months ended ~~June~~September 30, 2011, GenOn Americas Generation ~~paid~~incurred an insignificant amount of interest expense related to the notes payable.

Purchased Emissions Allowances (GenOn Mid-Atlantic)

In the first quarter of 2009, GenOn Energy Management began maintaining on behalf of GenOn Mid-Atlantic an inventory of certain purchased emissions allowances. 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 in the three months ended ~~June~~September 30, 2011 and 2010, were $67 million and $79 million, respectively, and in the ~~six~~ nine months ended ~~June~~September 30, 2011 and 2010, were $1421 million and $1625 million, respectively, and are recorded in cost of fuel, electricity and other products—affiliate in GenOn Mid-Atlantic’s unaudited condensed ~~consolidated~~ consolidated statements of operations.

Immaterial Misstatement of Post-Employment Benefits in Prior Periods

During the second quarter of 2011, we identified an under accrual of post-employment benefits relating to over ten years up to and through 2010. In those years, we did not recognize a liability for future expected costs of benefits for inactive employees who were unable to perform services because of a disability. For GenOn Americas Generation, for 2010, 2009, 2008, 2007 and 2006, its operations and maintenance expense was understated by $0, $1 million, $1 million, $1 million and $2 million, respectively, and its net income/loss for these years was misstated by the same amounts. For GenOn Mid-Atlantic, for 2010, 2009, 2008, 2007 and 2006, its operations and maintenance expense was understated by $0, $0, $1 million, $1 million and $1 million, respectively, and its net income/loss for these years was misstated by the same amounts. The misstatements had no effect on cash flows for any of the periods.

To correct the misstatements, we recorded the following immaterial adjustments to the prior period financial statements presented in this Form 10-Q for GenOn Americas Generation: (a) cumulative decrease to member’s interest of $12 million in the consolidated balance sheet at December 31, 2010 and (b) cumulative increase to payable—affiliate and total current liabilities of $12 million in the consolidated balance sheet at December 31, 2010. To correct the misstatements, we recorded the following immaterial adjustments to the prior period financial statements presented in this Form 10-Q for GenOn Mid-Atlantic: (a) cumulative decrease to member’s interest of $8 million in the consolidated balance sheet at December 31, 2010 and (b) cumulative increase to payable—affiliate and total current liabilities of $8 million in the consolidated balance sheet at December 31, 2010.

~~6. Income~~Immaterial ~~Taxes~~Misstatement of Post-Employment Benefits in Prior Periods

To correct the misstatements, we recorded the following immaterial adjustments to the prior period financial statements presented in this Form 10-Q for GenOn Americas Generation: (a) cumulative decrease to member’s interest of $12 million in the consolidated balance sheet at December 31, 2010 and (b) cumulative increase to payables to affiliate and total current liabilities of $12 million in the consolidated balance sheet at December 31, 2010. To correct the misstatements, we recorded the following immaterial adjustments to the prior period financial statements presented in this Form 10-Q for GenOn Mid-Atlantic: (a) cumulative decrease to member’s interest of $8 million in the consolidated balance sheet at December 31, 2010 and (b) cumulative increase to payables to affiliate and total current liabilities of $8 million in the consolidated balance sheet at December 31, 2010.

7. Income Taxes

Income Tax Disclosures

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. Some of GenOn Americas Generation’s subsidiaries, Hudson Valley Gas and GenOn Special Procurement, Inc., exist as regarded corporate entities for income tax purposes. GenOn Kendall, which had previously existed as a regarded entity for income tax purposes, has been converted to a disregarded entity. For a subsidiary that continues to exist as a corporate regarded entity, 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 $(811) million and $~~(77)~~67 million during the three months ended ~~June~~September 30, 2011 and 2010, respectively, and $10(1) million and $1 68 million during the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010, respectively. The balance of GenOn Americas Generation’s pro forma ~~net~~ deferred income taxes is ~~zero~~$0 at ~~June~~September 30, 2011.

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 or division 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 $(233) million and $~~(93)~~127 million during the three months ended ~~June~~September 30, 2011 and 2010, respectively, and $10(23) million and $82209 million during the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010, respectively. The balance of GenOn Mid-Atlantic’s pro forma deferred income taxes would be a net deferred tax liability of $~~212~~189 million asat ~~of June~~September 30, 2011.

7. Segment Reporting (GenOn Americas Generation)

In conjunction with the Merger, GenOn Americas Generation began reporting in five segments in the fourth quarter of 2010: Eastern PJM, Northeast, California, Energy Marketing and Other Operations. Prior to the Merger, GenOn Americas Generation had four reportable segments: Mid-Atlantic, Northeast, California and Other Operations. Amounts for 2010 were reclassified to conform to the current segment presentation. The segments were 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, 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 and fuel oil management. Operating revenues consist of (a) power generation revenues, (b) contracted and capacity revenues, (c) fuel sales and proprietary trading revenues and (d) power hedging revenues.

~~which was shut down on February 28, 2011~~8. ~~The~~Segment ~~Energy~~Reporting ~~Marketing segment consists of proprietary trading and fuel oil management activities. Other Operations includes parent company adjustments for affiliate transactions of~~ (GenOn Americas Generation.)

The Eastern PJM segment consists of four generating facilities located in Maryland and Virginia with total net generating capacity of 5,204 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 of 362 MW, which was shut down on February 28, 2011. The Energy Marketing segment consists of proprietary trading and fuel oil management 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.

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.

GenOn Americas Generation Operating Segments

		September 30,			September 30,			September 30,			September 30,			September 30,			September 30,			September 30,
	Eastern PJM			Northeast			California			EnergyMarketing			OtherOperations			Eliminations			Total
	(in millions)
Three Months Ended June 30, 2011:
Operating revenues (1)	$	45		$	4		$	22		$	644		$	—		$	—		$	715
Operating revenues—affiliate(2)		235			45			—			73			—			(351	)		2
Total operating revenues		280			49			22			717			—			(351	)		717
Cost of fuel, electricity and other products (3)		2			2			(1	)		33			102			—			138
Cost of fuel, electricity and other products—affiliate(4)		111			25			(2	)		649			(102	)		(351	)		330
Total cost of fuel, electricity and other products		113			27			(3	)		682			—			(351	)		468
Gross margin (excluding depreciation and amortization)		167			22			25			35			—			—			249
Operating Expenses:
Operations and maintenance		101			11			6			—			—			—			118
Operations and maintenance—affiliate		42			10			9			(2	)		—			—			59
Depreciation and amortization		30			6			4			1			1			—			42
Gain on sales of assets, net		—			1			—			—			—			—			1
Total operating expenses, net		173			28			19			(1	)		1			—			220
Operating income (loss)	$	(6	)	$	(6	)	$	6		$	36		$	(1	)	$	—		$	29

________________

(1) Includes unrealized gains of $6 million for Eastern PJM and unrealized losses of $18 million for Energy Marketing.

(2) Includes unrealized gains of $30 million and $1 million for Energy Marketing and Northeast, respectively and unrealized losses of $33 million for Eastern PJM.

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

(4) Includes unrealized losses of $15 million for Energy Marketing and unrealized gains of $15 million for Eastern PJM.

	Eastern PJM		Northeast			California			EnergyMarketing		OtherOperations			Eliminations			Total
	(in millions)
Six Months Ended June 30, 2011:
Operating revenues (1)	$	44	$	9		$	50		$	1,150	$	—		$	—		$	1,253
Operating revenues—affiliate(2)		534		84			—			129		—			(734	)		13
Total operating revenues		578		93			50			1,279		—			(734	)		1,266
Cost of fuel, electricity and other products (3)		9		3			—			47		244			—			303
Cost of fuel, electricity and other products—affiliate(4)		240		52			(2	)		1,187		(243	)		(734	)		500
Total cost of fuel, electricity and other products		249		55			(2	)		1,234		1			(734	)		803
Gross margin (excluding depreciation and amortization)		329		38			52			45		(1	)		—			463
Operating Expenses:
Operations and maintenance		163		21			12			1		—			—			197
Operations and maintenance—affiliate		82		19			17			1		—			—			119
Depreciation and amortization		59		12			7			1		3			—			82
Gain on sales of assets, net		—		1			—			—		—			—			1
Total operating expenses, net		304		53			36			3		3			—			399
Operating income (loss)	$	25	$	(15	)	$	16		$	42	$	(4	)	$	—		$	64
Total assets at June 30, 2011	$	4,439	$	482		$	141		$	1,885	$	178		$	(680	)	$	6,445

GenOn Americas Generation Operating Segments

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

		September 30,			September 30,			September 30,			September 30,			September 30,			September 30,			September 30,
	Eastern PJM			Northeast			California			Energy Marketing			Other Operations			Eliminations			Total
	(in millions)
Three Months Ended September 30, 2011:

Operating revenues⁽¹⁾	$	41		$	2		$	22		$	864		$	—		$	—		$	929
Operating revenues—affiliate⁽²⁾		287			52			—			42			—			(397	)		(16	)

Total operating revenues		328			54			22			906			—			(397	)		913
Cost of fuel, electricity and other products⁽³⁾		4			1			—			72			133			—			210
Cost of fuel, electricity and other products—affiliate⁽⁴⁾		170			35			—			819			(133	)		(397	)		494

Total cost of fuel, electricity and other products		174			36			—			891			—			(397	)		704

Gross margin (excluding depreciation and amortization)		154			18			22			15			—			—			209

Operating Expenses:
Operations and maintenance		53			11			4			1			4			—			73
Operations and maintenance—affiliate		43			9			6			(1	)		(4	)		—			53
Depreciation and amortization		30			7			4			—			1			—			42
Impairment losses⁽⁵⁾		94			20			14			—			—			—			128
Gain on sales of assets, net		—			(1	)		(5	)		—			—			—			(6	)
Gain on sales of assets, net—affiliate		—			1			1			—			—			—			2

Total operating expenses		220		$	47		$	24		$	—		$	1		$	—		$	292

Operating income (loss)	$	(66	)	$	(29	)	$	(2	)	$	15		$	(1	)	$	—		$	(83	)

(21) Includes unrealized gains ~~of $57 million for Energy Marketing and unrealized~~ (losses) of $39(3) million and $1040 million for Eastern PJM and ~~Northeast~~Energy Marketing, respectively.

(32) Includes unrealized ~~gains~~losses of $29(2) million and $(25) million for Northeast and Energy Marketing, respectively.

(43) Includes unrealized losses of $2911 million for Energy Marketing ~~and unrealized gains of $27 million and $2 million for Eastern PJM and Northeast, respectively~~.

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

(5)	Represents impairment losses for the write off of excess NO_x and SO₂ emissions allowances as a result of the CSAPR. See note 2.

		September 30,			September 30,			September 30,			September 30,			September 30,			September 30,			September 30,
	Eastern PJM			Northeast			California			EnergyMarketing			OtherOperations			Eliminations			Total
	EasternPJM			Northeast			California			EnergyMarketing			OtherOperations			Eliminations			Total
	(in millions)
Three Months Ended June 30, 2010:
Nine Months Ended September 30, 2011:
Operating revenues(1)	$	(39	)		3		$	29		$	251		$	—		$	—		$	244
Operating revenues (1)	$	85		$	11		$	72		$	2,014		$	—		$	—		$	2,182
Operating revenues—affiliate(2)		~~209~~821			37136			4—			~~165~~171			—			(~~415~~1,131	)		—(3	)
Total operating revenues		~~170~~906			40147			3372			~~416~~2,185			—			(~~415~~1,131	)		~~244~~2,179
Cost of fuel, electricity and other products(3)		5			—			—			153			113			—			271
Cost of fuel, electricity and other products (3)		13			4			—			119			377			—			513
Cost of fuel, electricity and other products—affiliate(4)		~~245~~410			1887			4(2	)		~~262~~2,006			(~~113~~376	)		(~~415~~1,131	)		1994
Total cost of fuel, electricity and other products		~~250~~423			1891			4(2	)		~~415~~2,125			—1			(~~415~~1,131	)		~~272~~1,507
Gross margin (excluding depreciation and amortization)		~~(80~~483	)		2256			2974			160			—(1	)		—			~~(28~~672	)
Operating Expenses:
Operations and maintenance		70216			1332			716			12			—4			2—			93270
Operations and maintenance—affiliate		47125			1428			1123			2—			—(4	)		(2—	)		72172
Depreciation and amortization		3689			619			711			—1			14			—			50124
Gain on sales of assets, net		(1	)		—			—			—			—			—			(1	)
Impairment losses(5)		94			20			14			—			—			—			128
Total operating expenses, net		152			33			25			3			1			—			214
Gain on sales of assets, net		—			—			(5	)		—			—			—			(5	)
Operating income (loss)	$	(232	)	$	(11	)	$	4		$	(2	)	$	(1	)	$	—		$	(242	)
Gain on sales of assets, net—affiliate		—			1			1			—			—			—			2
Total operating expenses		524			100			60			3			4			—			691
Operating income (loss)	$	(41	)	$	(44	)	$	14		$	57		$	(5	)	$	—		$	(19	)
Total assets at September 30, 2011	$	4,213		$	435		$	129		$	1,389		$	177		$	(410	)	$	5,933

(1) Includes unrealized losses of $97(42) million and $~~134~~(28) million for Eastern PJM and Energy Marketing, respectively.

(2) Includes unrealized gains (losses) of $~~108~~(39) million, $(12) million and $1332 million for Eastern PJM, ~~and~~ Northeast, ~~respectively,~~ and ~~unrealized gains of $121 million for~~ Energy Marketing, respectively.

(3) Includes unrealized ~~losses~~gains of $~~109~~(18) million for Energy Marketing.

(4) Includes unrealized (gains) losses of $~~112~~(18) million, ~~for Eastern PJM and unrealized gains of~~ $3(1) million and $~~109~~18 million for Eastern PJM, Northeast and Energy Marketing, respectively.

(5)	Represents impairment losses for the write off of excess NO_x and SO₂ emissions allowances as a result of the CSAPR. See note 2.

	Eastern PJM			Northeast			California		EnergyMarketing(3)			OtherOperations(3)			Eliminations			Total
		September 30,			September 30,			September 30,		September 30,			September 30,			September 30,			September 30,
	EasternPJM			Northeast			California		EnergyMarketing			OtherOperations			Eliminations			Total
	(in millions)
Six Months Ended June 30, 2010:
Three Months Ended September 30, 2010:
Operating revenues(1)	$	~~219~~165		$	82		$	6128	$	~~836~~580		$	—		$	—		$	~~1,124~~775
Operating revenues—affiliate(2)		~~690~~488			~~104~~86			1013		4753			—			(~~851~~640	)		—
Total operating revenues		~~909~~653			~~112~~88			7141		~~883~~633			—			(~~851~~640	)		~~1,124~~775
Cost of fuel, electricity and other products(4)		9			—			—		199			267			—			475
Cost of fuel, electricity and other products (3)		4			—			—		78			163			—			245
Cost of fuel, electricity and other products—affiliate(5)		396			62			12		652			(267	)		(851	)		4
Cost of fuel, electricity and other products—affiliate(4)		178			59			9		559			(163	)		(640	)		2
Total cost of fuel, electricity and other products		~~405~~182			6259			129		~~851~~637			—			(~~851~~640	)		~~479~~247
Gross margin (excluding depreciation and amortization)		~~504~~471			5029			5932		32(4	)		—			—			~~645~~528
Operating Expenses:
Operations and maintenance		~~135~~65			2514			176		12			—1			4—			~~182~~88
Operations and maintenance—affiliate		9551			2614			219		41			—(1	)		(4—	)		~~142~~74
Depreciation and amortization		6936			125			158		—1			32			—			9952
Gain on sales of assets, net		(3—	)		—(1	)		—		—			—			—			(31	)
Total operating expenses, net		296			63			53		5			3			—			420
Total operating expenses		152			32			23		4			2			—			213
Operating income (loss)	$	~~208~~319		$	(133	)	$	69	$	27(8	)	$	(32	)	$	—		$	~~225~~315
Total assets at December 31, 2010	$	4,626		$	488		$	121	$	2,418		$	1,292		$	(1,132	)	$	7,813

(1) Includes unrealized gains of $~~103~~124 million and $2930 million for Eastern PJM and Energy Marketing, respectively.

(2) Includes unrealized gains (losses) of $3032 million, $8 million and $2(40) million for Eastern PJM, ~~and~~ Northeast, ~~respectively,~~ and ~~unrealized losses of $32 million for~~ Energy Marketing, respectively.

(3) ~~The~~Includes ~~2011~~unrealized ~~segment~~gains reporting footnote for GenOn Americas Generation presents certain parent company adjustments in Energy Marketing which were previously included in Other Operations. GenOn Americas Generation has reclassified the presentation of these adjustments for the three and six months ended June 30, 2010. The impact of the reclass for the three months ended March 31, 2011 to the Energy Marketing segment is a decrease in Cost of fuel, electricity and other products and an increase in Cost of fuel, electricity and other products—affiliate of $~~154~~13 million. ~~The impact of the reclass~~ for the three months ended March 31, 2011 to the Other Operations segment is an increase in Cost of fuel, electricity and other products and a decrease in Cost of fuel, electricity and other products—affiliate of $154 million. The reclass does not impact gross margin (excluding depreciation and amortization) or operating income of Energy Marketing ~~or Other Operations~~.

(4) Includes unrealized (gains) losses of $~~120~~(23) million, $10 million and $13 million for Eastern PJM, Northeast and Energy Marketing, respectively.

(5) Includes unrealized losses of $104 million and $16 million for Eastern PJM and Northeast, respectively, and unrealized gains of $120 million for Energy Marketing.

	Three Months EndedJune 30,						Six Months EndedJune 30,
	2011			2010			2011			2010
	(in millions)
Operating income (loss) for all segments	$	29		$	(242	)	$	64		$	225
Interest expense		(21	)		(49	)		(51	)		(99	)
Other, net		—			(1	)		(23	)		(2	)
Net income (loss)	$	8		$	(292	)	$	(10	)	$	124

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.

		September 30,			September 30,			September 30,		September 30,		September 30,			September 30,			September 30,
	Eastern PJM			Northeast			California		Energy Marketing		Other Operations			Eliminations			Total
	(in millions)
Nine Months Ended September 30, 2010:
Operating revenues⁽¹⁾	$	384		$	10		$	89	$	1,416	$	—		$	—		$	1,899
Operating revenues—affiliate⁽²⁾		1,178			190			23		100		—			(1,491	)		—

Total operating revenues		1,562			200			112		1,516		—			(1,491	)		1,899
Cost of fuel, electricity and other products⁽³⁾		13			—			—		277		430			—			720
Cost of fuel, electricity and other products—affiliate⁽⁴⁾		574			121			21		1,211		(430	)		(1,491	)		6

Total cost of fuel, electricity and other products		587			121			21		1,488		—			(1,491	)		726

Gross margin (excluding depreciation and amortization)		975			79			91		28		—			—			1,173

Operating Expenses:
Operations and maintenance		200			39			23		3		5			—			270
Operations and maintenance—affiliate		146			40			30		5		(5	)		—			216
Depreciation and amortization		105			17			23		1		5			—			151
Gain on sales of assets, net		(3	)		(1	)		—		—		—			—			(4	)

Total operating expenses		448			95			76		9		5			—			633

Operating income (loss)	$	527		$	(16	)	$	15	$	19	$	(5	)	$	—		$	540

Total assets at December 31, 2010	$	4,626		$	488		$	121	$	2,418	$	1,292		$	(1,132	)	$	7,813

(1)	Includes unrealized gains of $227 million and $59 million for Eastern PJM and Energy Marketing, respectively.

(2)	Includes unrealized gains (losses) of $62 million, $10 million and $(72) million for Eastern PJM, Northeast and Energy Marketing, respectively.

(3)	Includes unrealized losses of $107 million for Energy Marketing.

(4)	Includes unrealized (gains) losses of $81 million, $26 million and $(107) million for Eastern PJM, Northeast and Energy Marketing, respectively.

		September 30,			September 30,			September 30,			September 30,
	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
	(in millions)

Operating income (loss) for all segments	$	(83	)	$	315		$	(19	)	$	540
Interest expense		(19	)		(51	)		(70	)		(150	)
Interest expense—affiliate		(4	)		—			(4	)		—
Other, net		—			1			(23	)		(1	)

Income (loss) before income taxes	$	(106	)	$	265		$	(116	)	$	389

9. Litigation and Other Contingencies

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 in the United States District Court for the District of Maryland. Stone & Webster claims that it has not been paid in accordance with the terms of the EPC agreements for the scrubber projects and sought $143.1 million in liens against the properties. inIn March 2011, the ~~amounts~~court ofgranted ~~$43~~these liens.~~2 million~~ atIn ~~Chalk Point~~June 2011, ~~$46.8~~Stone ~~million~~& Webster filed a motion to amend its lien claims at ~~Dickerson~~these ~~and~~facilities by an additional $5390.15 million ~~at Morgantown~~. In ~~March~~ August 2011, the court granted these additional liens. ~~against~~In ~~the~~September ~~properties.~~2011, ~~The~~GenOn ~~liens~~Mid-Atlantic ~~are~~paid ~~interlocutory~~$68 ~~only~~million ~~and~~to ~~will~~Stone & ~~not~~Webster ~~become~~for ~~final~~achieving ~~unless~~substantial ~~and~~completion ~~until~~under the ~~Stone &~~EPC ~~Webster~~agreements, iswhich ~~successful~~reduced inthe ~~prosecuting~~outstanding ~~its~~liens ~~contractual~~amount ~~claims~~to $165.6 million. As a result of certain lien restrictions in its lease documentation, GenOn Mid-Atlantic has reserved $~~143~~165.6 million of cash (which is included in funds on deposit on the unaudited condensed consolidated balance sheet) in respect of such liens. InThe ~~June 2011,~~liens ~~Stone &~~are ~~Webster~~interlocutory ~~filed~~only ~~a motion~~and towill ~~amend~~not ~~its~~become ~~lien~~final ~~claims~~unless ~~at Chalk Point, Dickerson~~ and ~~Morgantown~~until ~~by an additional $90~~Stone ~~million.~~& InWebster ~~the~~is ~~event~~successful ~~that~~in ~~such~~prosecuting ~~liens~~its ~~are~~contractual ~~granted, GenOn Mid-Atlantic expects to reserve an additional $90 million of cash in respect thereof~~claims. We ~~dispute~~ dispute 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. Currently, $1.674 billion continues to to represent management’s best estimate of the total capital expenditures for compliance with the Maryland Healthy Air Act. However, if the costs incurred were to equal the amount claimed by Stone &Webster, the total capital expenditures ~~would~~ would exceed $1.674 billion by approximately 5%.

Environmental Matters

Potomac River NOVs. In 2010, the Virginia DEQ issued several NOVs related to the Potomac River facility. Virginia DEQ asserted that GenOn Potomac River failed to include required particulate matter data in compliance reports for certain periods in 2009, and that, when the data were later provided, they indicated that particulate matter emissions may have exceeded the permitted limit. GenOn Potomac River thinks that the data indicating exceedance of the limit are erroneous. In another NOV, the Virginia DEQ asserted that on one day in each of February 2010 and July 2010 the opacity readings from the facility exceeded the applicable limits in several six minute intervals. In a third NOV, the Virginia DEQ asserted that GenOn Potomac River combusted used oils in the facility’s boilers without authority under its permit and received one shipment of coal that exceeded the maximum ash content allowed under its permit. In a fourth NOV, issued in February 2011, the Virginia DEQ asserted that in January 2011 GenOn Potomac River used a sorbent for the removal of SO2 that was not permitted. We settled these alleged violations for $276,000 with the Virginia DEQ in May 2011.

Montgomery County Carbon Emissions Levy. The Dickerson facility is located in Montgomery County, Maryland, and in May 2010, Montgomery County imposed a levy on major emitters of CO2 in the county of $5 per ton of CO2 emitted. We estimated that the CO2 levy would have imposed $10 million to $15 million per year in levies owed to Montgomery County. In June 2010, GenOn Mid-Atlantic filed an action against Montgomery County in the United States District Court for the District of Maryland seeking a determination that the CO2 levy was unlawful. In its complaint, GenOn Mid-Atlantic contended that the CO2 levy violated its equal protection and due process rights, imposed an unconstitutional excessive fine, was an unconstitutional bill of attainder, constituted a prohibited special law under the Maryland Constitution, and was preempted by Maryland law and the RGGI, an interstate compact to which Maryland is a party. In July 2010, the District Court ruled that the CO2 levy was a tax rather than a fee and granted a motion filed by Montgomery County seeking dismissal of the suit under the federal Tax Injunction Act for lack of jurisdiction. GenOn Mid-Atlantic appealed that ruling to the United States Court of Appeals for the Fourth Circuit. In June 2011, the United States Court of Appeals for the Fourth Circuit overturned the dismissal and remanded the case to the district court. On July 19, 2011, Montgomery County repealed the carbon emissions levy. GenOn Mid-Atlantic has been refunded all amounts previously paid, with interest.

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.” In the past decade, 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~~Environmental ~~Fly~~Matters Ash Facilities. We have three fly ash facilities in Maryland: Faulkner, Westland and Brandywine. Until recently, we disposed of fly ash from our Morgantown station at Faulkner, but it has reached its capacity. We dispose of fly ash from our Morgantown and Chalk Point facilities at Brandywine. We dispose of fly ash from our Dickerson station at Westland. As described below, the MDE has sued us regarding Faulkner and Brandywine and threatened to sue regarding Westland. The MDE also has threatened not to renew the water discharge permits for all three facilities.

Montgomery County Carbon Emissions Levy. The Dickerson generating facility is located in Montgomery County, Maryland, and in May 2010, Montgomery County imposed a levy on major emitters of CO₂ in the county of $5 per ton of CO₂ emitted. We estimated that the CO₂ levy would have imposed $10 million to $15 million per year in levies owed to Montgomery County. In June 2010, GenOn Mid-Atlantic filed an action against Montgomery County in the United States District Court for the District of Maryland seeking a determination that the CO₂ levy was unlawful. In July 2010, the District Court ruled that the CO₂ levy was a tax rather than a fee and granted a motion filed by Montgomery County seeking dismissal of the suit under the federal Tax Injunction Act for lack of jurisdiction. GenOn Mid-Atlantic appealed that ruling to the United States Court of Appeals for the Fourth Circuit. In June 2011, the United States Court of Appeals for the Fourth Circuit overturned the dismissal and remanded the case to the District Court. In July 2011, following the decision of the Court of Appeals, Montgomery County repealed the carbon emissions levy. GenOn Mid-Atlantic has been refunded all amounts previously paid, with interest.

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.” In the past decade, 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.

Potomac River NOV. In August 2011, the Virginia DEQ issued an NOV related to the Potomac River generating facility. The Virginia DEQ asserted that (a) the facility is not equipped with all the appropriate fugitive dust controls, (b) we failed to correctly calculate NO_x emissions rates and (c) NO_x emissions exceeded the permitted limits on six days in June and July 2011. We contest the allegations.

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 has 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 of the Clean Water Act and Maryland’s Water Pollution Control Law at Faulkner. 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; (b) enjoin discharges that are not authorized by our existing permit; (c) require numerous technical studies; (d) impose civil penalties and (e) award them 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 of the Clean Water Act and Maryland’s Water Pollution Control Law at Brandywine. 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 them attorney’s 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 intends to sue us for alleged violations of Maryland’s water pollution laws at Westland. To date, MDE has not sued us regarding our ash disposal at Westland.

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 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 pursue 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 are discussing settlement. As a condition to obtaining the stay, we agreed in principle to pay a civil penalty of $1.9 million to the MDE if we reach a comprehensive settlement regarding all of the allegations related to the three Maryland ash facilities. Accordingly, we accrued $1.9 million atduring the three months ended June 30, 2011. We also ~~have~~ developed a technical solution, which included installing synthetic caps on portions of each of the ash facililties, that we ~~think~~thought ~~will~~would address the MDE’s concerns at the three ash facilities. WeDuring ~~have~~the three months ended June 30, 2011, we accrued $28 million for the estimated cost of the technical solution. In October 2011, the MDE informed us that our proposed technical solution was not adequate in the MDE’s view. 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. There are no assurances that we will be able to settle the three matters for the amounts that we have accrued and the ultimate resolution of these matters could be material to our results of operations, financial position and cash flows.

39Ash 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 ($10 million and $9 million at September 30, 2011 and December 31, 2010, respectively) associated with these environmental liabilities as part of its asset retirement obligations. GenOn Mid-Atlantic recorded the estimated discounted costs ($8 million and $7 million at September 30, 2011 and December 31, 2010, respectively) associated with these environmental liabilities as part of its asset retirement obligations. These amounts are exclusive of the $28 million accrual for the technical solution for three ash facilities in Maryland discussed above.

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 ($10 million and $9 million at June 30, 2011 and December 31, 2010, respectively) associated with these environmental liabilities as part of its asset retirement obligations. GenOn Mid-Atlantic recorded the estimated discounted costs ($7 million at June 30, 2011 and December 31, 2010) associated with these environmental liabilities as part of its asset retirement obligations.

Chapter 11 Proceedings

In July 2003, and various dates thereafter, GenOn Energy Holdings and certain of its subsidiaries, (collectively, the Mirant Debtors), including us, filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the Bankruptcy Court. 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 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.

~~Complaint~~41 ~~Challenging Capacity Rates Under the RPM Provisions of PJM’s Tariff~~

In May 2008, several parties, including the state public utility commissions of Maryland, Pennsylvania, New Jersey and Delaware, ratepayer advocates, certain electric cooperatives, various groups representing industrial electricity users, and federal agencies (the RPM Buyers), filed a complaint with the FERC asserting that capacity auctions held to determine capacity payments under the RPM provisions of PJM’s tariff had produced rates that were unjust and unreasonable. The FERC found that no party had violated the RPM provisions of PJM’s tariff and that the prices determined during the auctions were in accordance with the tariff’s provisions. The RPM Buyers filed a request for rehearing, which the FERC denied in June 2009. On a subsequent appeal, in February 2011, the United States Court of Appeals for the District of Columbia Circuit affirmed the FERC rulings. None of the RPM Buyers asked the D.C. Circuit to reconsider its decision and no party filed for a writ of certiorari. The deadlines for these procedures have passed.

9. Subsequent Events

In July 2011, the EPA released its prepublication version of the regulations to replace the CAIR with the CSAPR starting in 2012. CSAPR will be finalized when published in the Federal Register, which we expect to occur in August 2011. The CSAPR will establish limitations on NOx and/or SO2 emissions in states included in the program. The NOx allowances from the CAIR program will not be used in the CSAPR program and accordingly will have no value after 2011. The SO2 allowances used for compliance in the CAIR program are the Acid Rain Program allowances, which will have negligible value after 2011. The carrying value of NOx and SO2 emissions allowances included in GenOn Americas Generation’s property, plant and equipment and intangible assets at June 30, 2011 was $141 million. The carrying value of NOx and SO2 emissions allowances included in GenOn Mid-Atlantic’s property, plant and equipment and intangible assets at June 30, 2011 was $105 million. These are being evaluated for early retirement or impairment as a result of the CSAPR. It is likely that this evaluation will result in a substantial non-cash charge in the third quarter of 2011.

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

A. GenOn Americas Generation

This section is intended to provide the reader with information that will assist in understanding GenOn Americas Generation’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 interim financial statements and its 2010 Annual Report on Form 10-K. The results of operations by segment 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, see note 8 to our interim financial statements.

Overview

With approximately 9,724 MW of net electric generating capacity, we operate across various fuel (natural gas, coal and oil) and technology types, operating characteristics and regional power markets. At ~~June~~September 30, 2011, our generating capacity was 54% in PJM, 26% in NYISO and ISO-NE and 20% in CAISO.

We provide energy, capacity, ancillary and other energy services to wholesale customers in competitive energy markets in the United States, including ISOs and RTOs, power aggregators, retail providers, electric-cooperative utilities, other power generating companies and load serving entities. Our commercial operations consist primarily of dispatching electricity, hedging the generation and sale of electricity, procuring and managing fuel and providing logistical support for the operation of our facilities (e.g., by procuring transportation for coal and natural gas), as well as our proprietary trading operations.

Merger of Mirant and RRI Energy

On December 3, 2010, Mirant and RRI Energy completed their merger. See note 1 to our consolidated financial statements in our 2010 Annual Report on Form 10-K for further discussion of the Merger.

Hedging Activities

We hedge economically a substantial portion of our Eastern PJM coal-fired baseload generation and certain of our other 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 such parties and do not require either party to post cash collateral either for initial margin or for securing exposure as a result of changes in power or natural gas prices. At ~~July~~October 1231, 2011, our aggregate hedge levels increased in part based on expected reduced generation ~~without~~ considering the effects of the CSAPR ~~were~~and were as follows:

		September 30,			September 30,			September 30,			September 30,			September 30,
	2011(1)			2012			2013			2014			2015
	2012			2013			2014			2015			2016
Power		9285	%		8154	%		33	%		3025	%		2320	%
Fuel		9379	%		7153	%		475	%		—	%		—	%

(1) Percentages represent the period from August through December 2011.

instruments to hedge commercial risks are not to be subject to these clearing and exchange-trading requirements, it is uncertain what the final implementing regulations will provide. The effect of the Dodd-Frank Act on our business depends in large measure on pending rulemaking proceedings of the CFTC, the SEC and the federal banking regulators. Under the Dodd-Frank Act, entities defined as “swap dealers” and “major swap participants” (“SD/MSPs”) will face costly requirements for clearing and posting margin, as well as additional requirements for reporting and business conduct. The CFTC and SEC issued a proposed rulemaking to set final definitions for the terms “swap dealer” and “major swap participant” among others. Although we do not expect our hedging activity to result in our designation as an SD/MSP, as proposed, the “swap dealer” definition in particular is ambiguous, subjective and could be broad enough to encompass some energy companies. In addition, the CFTC and federal banking regulators, who will regulate bank SD/MSPs, separately issued proposed rules to establish capital and margin requirements for SD/MSPs and swap counterparties. While end-user counterparties who are using a swap to hedge or mitigate commercial risk would be generally exempt from mandatory margin requirements under the CFTC’s proposal applicable to non-bank SD/MSPs, they would have to post cash margin to bank SD/MSPs if they exceed exposure thresholds under the federal banking regulators’ proposal. The federal banking regulators’ rulemaking states that the credit support limit shall be determined by the bank SD/MSPs in accordance with their normal credit processes to set credit limits and to collect initial and variation margin. As proposed, the federal banking regulators’ rulemaking does not specify a procedure for determining such thresholds and a major question remains of the extent to which end-users and bank SD/MSPs will be free under the proposal to set their own thresholds to avoid the collection of margin from end-users. If applied to our hedging activity, such regulations could materially affect our ability to hedge economically our generation by significantly increasing the collateral costs associated with such activities. Furthermore, the CFTC and prudential regulators’ proposed capital requirements for SD/MSP’s recommend significant and cash-dependent capital requirements for SD/MSPs. The cost of complying with these requirements may be passed through to and imposed on commercial end users indirectly and increase the cost of our hedging activities.

The CFTC has also issued its proposed definition of “swap.” In further defining the term, the CFTC has left some ambiguity as to whether what are commonly understood as commodity options (which can settle physically) are to be generally considered swaps. With regard to electric power ISO/RTO products, including Financial Transmission Rights (FTRs), the CFTC has said only that it will consider granting exemptions to transactions where an instrument regulated by FERC is involved and such an exclusion would be in the public interest. If applied to our hedging activity, such regulations could considerably increase the transaction costs with respect to commodity options and FTR’s.

Moreover, the CFTC issued a proposal establishing recordkeeping and reporting requirements for swaps entered into before July 21, 2010, whose terms had not expired as of that date, and data relating to swaps entered into on or after July 21, 2010 and prior to the compliance date specified in the CFTC’s final swap data reporting rules. Whilst GenOn Americas Generation will have increased reporting and recordkeeping requirements, we do not expect the proposed requirements to have a material effect on our hedging activities.

In terms of the timing for the release and implementation of the rules established by Dodd-Frank, on July 14, 2011, the CFTC issued an Order clarifying the effective date of the provisions in the swap regulatory regime as the CFTC continues to implement rules. The Order provides temporary relief from certain provisions that would otherwise apply to swaps or swap dealers and that would have become effective as of July 16, 2011, until the CFTC completes the rulemakings specified in the Order. This Order is temporary, and it will expire upon the earlier of the effective date of final rules or December 31, 2011.

Capital Expenditures and Capital Resources

During the six months ended June 30, 2011, we invested $46 million for capital expenditures, excluding capitalized interest paid, primarily related to maintenance capital expenditures. At June 30, 2011, we have invested $1.521 billion of the $1.674 billion that was budgeted for capital expenditures related to compliance with the Maryland Healthy Air Act. Provisions in the construction contracts for the scrubbers at three of our largest Maryland coal-fired units provide for certain payments to be made after final completion of the projects. The

The Dodd-Frank Act, which was enacted in July 2010 in response to the global financial ~~current~~crisis, ~~budget~~increases the regulation of $1transactions involving OTC derivative financial instruments.~~674 billion~~ ~~continues~~The statute provides that standardized swap transactions between dealers and large market participants will have to ~~represent~~be cleared and traded on an exchange or electronic platform. Although the provisions and legislative history of the Dodd-Frank Act provide strong evidence that market participants, such as GenOn Americas Generation, which utilize OTC derivative financial instruments to hedge commercial risks are not to be subject to these clearing and exchange-trading requirements, it is uncertain what the final implementing regulations will provide. The effect of the Dodd-Frank Act on our ~~best~~business ~~estimate~~depends in large measure on pending rulemaking proceedings of the ~~total~~CFTC, the SEC and the federal banking regulators. Under the Dodd-Frank Act, entities defined as “swap dealers” and “major swap participants” (SD/MSPs) will face costly requirements for clearing and posting margin, as well as additional requirements for reporting and business conduct. The CFTC and SEC issued a proposed rulemaking to set final definitions for the terms “swap dealer” and “major swap participant” among others. Although we do not expect our hedging activity to result in our designation as an SD/MSP, as proposed, the “swap dealer” definition in particular is ambiguous, subjective and could be broad enough to encompass some energy companies. In addition, the CFTC and federal banking regulators, who will regulate bank SD/MSPs, separately issued proposed rules to establish capital ~~expenditures~~and margin requirements for ~~compliance~~SD/MSPs and swap counterparties. While end-user counterparties who are using a swap to hedge or mitigate commercial risk would be generally exempt from mandatory margin requirements under the CFTC’s proposal applicable to non-bank SD/MSPs, they would have to post cash margin to bank SD/MSPs if they exceed exposure thresholds under the federal banking regulators’ proposal. The federal banking regulators’ rulemaking states that the credit support limit shall be determined by the bank SD/MSPs in accordance with their normal credit processes to set credit limits and to collect initial and variation margin. As proposed, the ~~Maryland~~federal ~~Healthy~~banking ~~Air~~regulators’ ~~Act~~rulemaking does not specify a procedure for determining such thresholds and a major question remains of the extent to which end-users and bank SD/MSPs will be free under the proposal to set their own thresholds to avoid the collection of margin from end-users. ~~See~~If ~~note 8~~applied to our ~~interim~~hedging activity, such regulations could materially affect our ability to hedge economically our generation by significantly ~~financial~~increasing ~~statements~~the collateral costs associated with such activities. Furthermore, the CFTC and federal banking regulators’ proposed capital requirements for ~~further~~SD/MSPs ~~discussion~~recommend significant and cash-dependent capital requirements for SD/MSPs. The cost of complying with these requirements may be passed through to and imposed on commercial end users indirectly and increase the ~~scrubber~~cost ~~contract~~of ~~litigation~~our hedging activities.

The ~~following~~CFTC ~~table~~has ~~details~~also issued its proposed definition of “swap.” In further defining the ~~expected~~term, the CFTC has left some ambiguity as to whether what are commonly understood as commodity options (which ~~timing~~can ofsettle ~~payments~~physically) ~~for~~are ~~our~~to ~~estimated~~be ~~capital~~generally ~~expenditures~~considered swaps. With regard to electric power ISO/RTO products, ~~excluding~~including ~~capitalized~~Financial Transmission Rights (FTRs), the CFTC has said only that it will consider granting exemptions to transactions where an instrument regulated by FERC is involved and such an exclusion would be in the public interest. If applied to our hedging activity, ~~for~~such regulations could considerably increase the ~~remainder~~transaction ofcosts ~~2011~~with ~~and~~respect ~~2012:~~to commodity options and FTRs.

		September 30,		September 30,
	July 1, 2011throughDecember 31,2011		2012
	(in millions)
Maryland Healthy Air Act	$	153	$	—
Other environmental		2		13
Maintenance		17		44
Other construction		37		7
Total	$	209	$	64

Moreover, the CFTC issued a proposal establishing recordkeeping and reporting requirements for swaps entered into before July 21, 2010, whose terms had not expired as of that date, and data relating to swaps entered into on or after July 21, 2010 and prior to the compliance date specified in the CFTC’s final swap data reporting rules. Additionally, in July 2011, the CFTC adopted final large trader reporting rules for physical commodity swaps and swaptions. Although GenOn Americas Generation will have increased reporting and recordkeeping requirements under both proposals, we do not expect the proposed requirements to have a material effect on our hedging activities.

In terms of the timing for the release and implementation of the rules established by Dodd-Frank, in July 2011, the CFTC issued an order clarifying the effective date of the provisions in the swap regulatory regime as the CFTC continues to implement rules. The order provides temporary relief from certain provisions that would otherwise apply to swaps or swap dealers and that would have become effective as of July 16, 2011, until the CFTC completes the rulemakings specified in the order. This order is temporary, and it will expire upon the earlier of the effective date of final rules or December 31, 2011. In an open meeting in September 2011, Chairman Gensler indicated that the CFTC will not meet the extended deadline of December 31, 2011. The CFTC subsequently published an outline indicating that they may consider final rules in 2011 including entity and product definitions, position limits, the end-user exemption, and recording and reporting rules. The outline also indicated that the CFTC may consider final rules during the first quarter of 2012 including capital and margin requirements, client clearing documentation and risk management and internal business conduct rules. The CFTC indicated that the outline provided was subject to change and that the dates and order in which the CFTC finalizes its Dodd-Frank rulemaking could differ substantially from those provided in the outline. In the meantime, the CFTC has proposed an amendment extending the exemptive relief to July 16, 2012, or until a date the CFTC may otherwise determine with respect to a particular requirement under the Commodity Exchange Act.

In addition, in September 2011, the CFTC proposed swaps compliance and implementation schedules for mandatory clearing and trading, trading documentation and uncleared margin. The CFTC’s notice of proposed rulemaking would give the CFTC discretion to phase in implementation of any clearing mandate for 90, 180 or 270 days, depending on the types of entities that are party to the relevant swap. The trigger for the implementation phase-in period would be the issuance of a clearing mandate by the CFTC. The CFTC also issued a further notice of proposed rulemaking with respect to margin and documentation requirements that would establish implementation schedules of 90, 180 or 270 days, depending on the types of entities involved. The CFTC has proposed, but not yet adopted, regulations implementing both of these provisions. As the entity and product definitions have not been finalized, we cannot fully assess the impact of these proposals.

Capital Expenditures and Capital Resources

During the nine months ended September 30, 2011, we invested $129 million for capital expenditures, excluding capitalized interest paid. Capital expenditures for the period primarily relate to maintenance capital expenditures and include the $68 million payment to Stone & Webster for substantial completion of the scrubber projects. At September 30, 2011, we have invested $1.59 billion of the $1.674 billion that was budgeted for capital expenditures related to compliance with the Maryland Healthy Air Act. Provisions in the construction contracts for the scrubbers at three of our largest Maryland coal-fired units provide for certain payments to be made after final completion of the projects. The current budget of $1.674 billion continues to represent our best estimate of the total capital expenditures for compliance with the Maryland Healthy Air Act. See note 9 to our interim financial statements for further discussion of the scrubber contract litigation.

The following table details the expected timing of payments for our estimated capital expenditures, excluding capitalized interest, for the remainder of 2011, 2012 and 2013:

		September 30,		September 30,		September 30,
	October 1, 2011 through December 31, 2011		2012		2013
			(in millions)

Maryland Healthy Air Act	$	84	$	—	$	—
Other environmental		—		14		22
Maintenance		17		47		71
Other construction		21		8		—
Other		1		1		—

Total	$	123	$	70	$	93

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.

Environmental Matters

We decide to invest capital for environmental controls based on relatively certain regulations, an evaluation of various options for regulatory compliance, including different technologies and fuel modification, and the expected economic returns on the capital. Whether we elect to install additional controls as a result of ~~the~~existing ~~CSAPR,~~or pending ~~HAPs regulation or other~~ regulations remains uncertain and depends on, among other things, the content and timing of the full slate of regulations, the expected effect of regulations on wholesale power prices and allowance prices, as well as the cost of controls, profitability of our generating facilities, market conditions at the time and the likelihood of CO2 regulation.

~~The~~44 costs associated with more stringent environmental air and water quality requirements, including state-specific or regional regulatory initiatives, may result in coal-fired generating facilities, including some of ours, being retired. Implementation of a program putting a price on emissions of CO2 in addition to other emissions control requirements could increase the likelihood of retirements of coal-fired generating facilities.

We expect any such industry retirements to contribute to improving supply and demand fundamentals for the remaining generating facilities. Any resulting increased demand for natural gas could increase the spread between natural gas and coal prices, which would also benefit the remaining coal-fired generating facilities. Consequently, GenOn Americas Generation and GenOn Mid-Atlantic expect industry retirements to result in higher market power prices, which could result in GenOn Americas Generation investing approximately $345 million to $450 million, including $315 million to $415 million for GenOn Mid-Atlantic, over the next six years for SCRs and other environmental controls to meet certain air and water quality requirements, which we expect to fund from existing sources of liquidity. Under current and forecasted market conditions, we do not expect installations of scrubbers to be economic at most of our unscrubbed coal-fired facilities. If market prices are even higher than our current expectations, we might invest more for environmental controls.

Given the uncertainty related to these environmental matters, we cannot predict their actual outcome or ultimate effect on our business, and such matters could result in a material adverse effect on our results of operations, financial position and cash flows. See also our discussion under the caption “Environmental Matters” in note 8 to our interim financial statements, including the discussion regarding our Brandywine, Faulkner and Westland ash facilities.

~~Cross-State~~The ~~Air~~costs ~~Pollution~~associated ~~Rule.~~with ~~In 2005,~~more ~~the~~stringent ~~EPA~~environmental ~~promulgated the~~air ~~CAIR, which established SO2~~ and ~~NOx cap-and-trade programs applicable directly to states and indirectly to~~water ~~generating~~quality ~~facilities~~requirements, inincluding ~~the eastern United States. The NOx cap~~state-~~and-trade~~specific ~~program~~or ~~has~~regional ~~two~~regulatory ~~components~~initiatives, anmay ~~annual~~result ~~program~~in ~~and an Ozone Season program. The CAIR SO2 cap~~coal-~~and-trade~~fired ~~program builds off the existing acid rain cap-and-trade program but requires~~ generating facilities ~~to surrender twice as many allowances to cover emissions from 2010 through 2014 and approximately three times as many allowances starting in 2015. Florida~~, ~~Illinois,~~including ~~Maryland,~~some ~~Mississippi,~~of ~~New Jersey~~ours, ~~New~~being ~~York, Ohio, Pennsylvania and Virginia are subject to the CAIR’s SO2 trading program and both its NOx trading programs~~retired. ~~Massachusetts~~Implementation isof ~~subject~~a ~~only to the CAIR’s Ozone Season NOx trading~~ program. ~~These~~putting ~~cap-and-trade~~a ~~programs~~price ~~were to~~on beemissions ~~implemented in two phases, with the first phase going into effect in 2009 for NOx and 2010 for SO2 and more stringent caps going into effect in 2015. On July 11, 2008, the D.C. Circuit in State~~ of ~~North~~CO2 Carolina v. Environmental Protection Agency issued an opinion that would have vacated the CAIR. Various parties filed requests for rehearing with the D.C. Circuit and on December 23, 2008, the D.C. Circuit issued a second opinion in ~~which~~addition ~~it granted rehearing only~~ to ~~the~~other ~~extent~~emissions ~~that~~control itrequirements ~~remanded~~could ~~the~~increase ~~case to~~ the ~~EPA without vacating the CAIR. Accordingly, the CAIR will remain effective until it is replaced~~ bylikelihood aof ~~rule~~retirements ~~consistent~~of ~~with~~coal-fired ~~the~~generating Dfacilities.~~C. Circuit’s~~ ~~opinions,~~See ~~which~~discussion asunder ~~described~~– ~~below~~“HAPs ~~will~~Regulations” ~~take place in January 2012~~below.

InWe ~~July~~expect ~~2011,~~any ~~EPA~~such ~~released~~industry ~~its~~retirements ~~prepublication version of the regulations~~ to ~~replace~~contribute ~~the CAIR with the CSAPR. CSAPR will be finalized when published in the Federal Register, which we expect~~ to ~~occur~~improving ~~in August~~supply ~~2011. The CSAPR addresses interstate transport of emissions of NOx~~ and ~~SO2.~~demand ~~The CSAPR~~fundamentals ~~will~~for ~~establish~~the ~~limitations~~remaining ~~on NOx and/or SO2 emissions from electric~~ generating ~~units that are greater than~~ ~~25 megawatts~~facilities. ~~and~~Any ~~are~~resulting ~~located~~increased indemand ~~27 states~~for innatural ~~the~~gas ~~eastern~~could ~~half~~increase of the ~~United~~spread ~~States~~between ~~whose~~natural ~~NOx~~gas and~~/or~~ ~~SO2 emissions~~coal ~~are determined by the EPA to contribute significantly to nonattainment in other states~~prices, orwhich towould ~~interfere~~also ~~with~~benefit ~~maintenance in other states, of one or more of three NAAQS: (a)~~ the ~~annual~~remaining ~~NAAQS for fine particulate matter (PM2.5) promulgated in 1997; (b) the “24~~coal-~~hour”~~fired ~~NAAQS~~generating ~~for PM2~~facilities.5 ~~promulgated~~Consequently, inGenOn ~~2006~~Americas Generation and ~~(c) the ozone NAAQS~~GenOn ~~promulgated~~Mid-Atlantic inexpect ~~1997.~~industry ~~The~~retirements ~~CSAPR~~to ~~will~~result ~~create “emission budgets” for each of the covered states and allocates emissions allowances (denominated~~ in ~~tons~~higher ofmarket ~~emissions)~~power ~~to each of the 27 states regulated under the CSAPR. Under the EPA federal implementation plan~~prices, ~~for~~which ~~each~~we ofthink ~~2012~~will ~~and~~result ~~2013,~~in GenOn Americas Generation ~~will~~investing beapproximately ~~allocated~~$345 ~~9,642,~~million ~~4,311,~~to ~~and~~$450 19million,~~285~~ ~~allowances~~including ~~under~~$315 ~~the~~million ~~CSAPR~~to ~~for~~$415 ~~annual~~million ~~NOx,~~for ~~ozone-season NOx, and SO2, respectively. For each of 2012 and 2013,~~ GenOn Mid-Atlantic ~~will be allocated 9~~,~~476,~~ ~~4,194~~over ~~and~~the ~~18,925~~next ~~allowances~~six ~~under the~~years ~~CSAPR~~ for ~~annual~~SCRs ~~NOx, ozone-season NOx,~~ and ~~SO2,~~other ~~respectively.~~environmental ~~The~~controls ~~CSAPR~~to ~~contemplates~~meet ~~that~~certain ~~states~~air ~~after 2012 may allocate allowances in a different manner than allocated initially under the CSAPR. The CSAPR will limit each electric generating unit’s NOx~~ and ~~SO2 emissions~~water toquality ~~amounts~~requirements, ~~covered by the number of allowances held by that source in allowance accounts under the program (~~which ~~may~~we beexpect ~~purchased~~to orfund ~~otherwise acquired~~ from ~~other~~existing sources, ~~subject~~of ~~to certain limitations in the rule)~~liquidity. ~~The~~Current ~~NOx~~market ~~allowances~~prices ~~from~~do ~~the CAIR program will~~ not besupport ~~used~~this inlevel ~~the CSAPR program~~of ~~and accordingly will have no value after 2011~~investment. ~~The~~Under ~~SO2 allowances~~current ~~used~~and ~~for~~forecasted ~~compliance~~market ~~in the CAIR program are the Acid Rain Program allowances~~conditions, ~~which~~we ~~will~~do ~~have~~not ~~negligible~~expect ~~value~~installations ~~after 2011. The carrying value~~ of ~~NOx~~scrubbers ~~and~~to ~~SO2~~be ~~emissions~~economic ~~allowances~~at ~~included~~most inof ~~GenOn~~our ~~Americas~~unscrubbed ~~Generation’s~~coal-fired ~~property, plant and equipment and intangible assets at June 30, 2011 was $141 million~~facilities. ~~The~~If ~~carrying~~market ~~value~~power ~~of NOx~~prices ~~and~~rise ~~SO2~~even ~~emissions~~higher ~~allowances~~than ~~included~~our incurrent ~~GenOn~~expectations, ~~Mid-Atlantic’s~~we ~~property,~~might ~~plant~~invest ~~and~~more ~~equipment~~than ~~and intangible assets at June 30, 2011 was~~ $~~105~~450 million. ~~These are being evaluated~~ for ~~early~~environmental ~~retirement or impairment as a result of the CSAPR~~controls. ~~It is likely that this evaluation will result in a substantial non-cash charge in the third quarter of 2011.~~

Given the uncertainty related to these environmental matters and those discussed or referred to below, we cannot predict their actual outcome or ultimate effect on our business, and such matters could result in a material adverse effect on our results of operations, financial position and cash flows. See also our discussion under the caption “Environmental Matters” in note 9 to our interim financial statements, including the discussion regarding our Brandywine, Faulkner and Westland ash facilities.

Cross-State Air Pollution Rule. In 2005, the EPA promulgated the CAIR, which established SO₂ and NO_x cap-and-trade programs applicable directly to states and indirectly to generating facilities in the eastern United States. The NO_x cap-and-trade program has two components: an annual program and an ozone-season program. The CAIR SO₂ cap-and-trade program builds off the existing acid rain cap-and-trade program but requires generating facilities to surrender twice as many allowances to cover emissions from 2010 through 2014 and approximately three times as many allowances starting in 2015. Florida, Illinois, Maryland, Mississippi, New Jersey, New York, Ohio, Pennsylvania and Virginia are subject to the CAIR’s SO₂ trading program and both its NO_x trading programs. Massachusetts is subject only to the CAIR’s ozone-season NO_x trading program. These cap-and-trade programs were to be implemented in two phases, with the first phase going into effect in 2009 for NO_x and 2010 for SO₂ and more stringent caps going into effect in 2015. In July 2008, the D.C. Circuit in State of North Carolina v. Environmental Protection Agency issued an opinion that would have vacated the CAIR. Various parties filed requests for rehearing with the D.C. Circuit and in December 2008, the D.C. Circuit issued a second opinion in which it granted rehearing only to the extent that it remanded the case to the EPA without vacating the CAIR. Accordingly, the CAIR will remain effective until it is replaced by a rule consistent with the D.C. Circuit’s opinions, which as described below will take place in January 2012.

In August 2011, the EPA finalized the regulations to replace the CAIR with the CSAPR starting in 2012. The CSAPR addresses interstate transport of emissions of NO_x and SO₂. In September 2011, we (and others) asked the United States Court of Appeals for 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.

The CSAPR establishes limitations on NO_x and/or SO₂ emissions from electric generating units that are (i) greater than 25 megawatts and (ii) located in 27 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 (PM_2.5) promulgated in 1997; (b) the “24-hour” NAAQS for PM_2.5 promulgated in 2006 and (c) the ozone NAAQS promulgated in 1997. The CSAPR creates “emission budgets” for each of the covered states and allocates emissions allowances (denominated in tons of emissions) to each of the 27 states regulated under the CSAPR. Under the EPA federal implementation plan, for each of 2012 and 2013, GenOn Americas Generation was allocated 9,642, 4,311, and 19,285 allowances under the CSAPR for annual NO_x, ozone-season NO_x, and SO₂, respectively. For each of 2012 and 2013, GenOn Mid-Atlantic was allocated 9,476, 4,194, and 18,925 allowances under the CSAPR for annual NO_x, ozone-season NO_x, and SO₂, respectively. The federal implementation plan has also outlined EPA-determined allocations in the same amounts for 2013, although the CSAPR contemplates that states after 2012 may allocate allowances in a different manner than allocated initially under the CSAPR. In October 2011, the EPA proposed revisions to the final CSAPR that, if finalized, would provide GenOn Americas Generation with a small allowance increase in each compliance year. As a result, the expected CSAPR allowances for GenOn Americas Generation would be 9,683, 4,345 and 19,339 in 2012 and 2013, for annual NO_x, ozone-season NO_x and SO₂, respectively. The CSAPR limits each electric generating unit’s NO_x and SO₂ emissions to amounts covered by the number of allowances held by that source in allowance accounts under the program (which may be purchased or otherwise acquired from other sources, subject to certain limitations in the rule).

The NO_x allowances from the CAIR program will not be used in the CSAPR program and accordingly will have no value after 2011. The SO₂ allowances used for compliance in the CAIR program are the acid rain program allowances, which will have negligible value after 2011. As a result of the CSAPR, GenOn Americas Generation recorded impairment losses of $128 million and GenOn Mid-Atlantic recorded impairment losses of $94 million for the write-off of excess NO_x and SO₂ emissions allowances during the three months ended September 30, 2011. See note 2 to our interim financial statements for further discussion of the impairment losses.

We expect that the CSAPR will result in reduced generation volumes from uncontrolled coal-fired plants, increased generation from gas-fired plants, increased market power prices and increased emissions costs offset by allocated allowances. The effect of the CSAPR on our results of operations is dependent on the price of the emissions allowances, liquidity in the emissions allowances markets and whether we choose to monetize the allowances. Based on current market conditions, the CSAPR is expected to have a negative effect on our results of operations, which includes carrying excess CSAPR emissions allowances to future periods to optimize their value. Our long term results are dependent on market conditions and pending environmental regulations, including how states allocate the CSAPR allowances and finalization of HAPs-MACT. As currently proposed, HAPs-MACT is expected to mitigate the CSAPR effect starting in the second half of the decade. In addition to evaluating the effects of the CSAPR on our business and our ongoing evaluation of the wholesale energy market, our future decisions to mothball, retire or dispose of facilities could result in impairment charges related to our fixed assets.

The EPA also has stated that it may issue a subsequent, more stringent rule if it concludes that recent or planned revisions to the particulate matter and ozone NAAQS make necessary more stringent limits on SO₂ and NO_x emissions from electric generating facilities.

RGGI. The RGGI is a multi-state initiative in the Eastern PJM and Northeast outlining a cap-and-trade program to reduce CO₂ emissions from electric generating units with capacity of 25 MW or greater. The RGGI program calls for signatory states, which include Maryland, Massachusetts, New Jersey and New York, to stabilize CO₂ emissions to an established baseline from 2009 through 2014, followed by a 2.5% reduction each year from 2015 through 2018. In June 2011, New Jersey informed RGGI that it is withdrawing from the program effective December 31, 2011. The withdrawal by New Jersey is not expected to have a material effect on our operations.

HAPs Regulations. In May 2011, the EPA proposed emission standards for HAPs from coal- and oil-fired units. The EPA proposes to establish limits for mercury, non-mercury metals, certain organics and acid gases for compliance beginning in 2015. We do not expect these proposals to materially affect our operations. Our Maryland coal-fired units already are subject to SO2, NOx, and mercury limits under the Maryland Healthy Air Act. Accordingly, emissions from our Maryland coal-fired units already meet the EPA’s proposed HAPs standards as a result of the controls that have been installed. We expect that higher earnings from price increases resulting from industry retirements will be positive for us.

4446

AB 32. In California, emissions of greenhouse gases are governed by California’s Global Warming Solutions Act (AB 32), which requires that statewide greenhouse gas emissions be reduced to ~~SO2~~1990 levels by 2020. In December 2008, the CARB approved a Scoping Plan for implementing AB 32. The Scoping Plan ~~NOx~~requires that the CARB adopt a cap-and-trade regulation by January 2011 and that the cap-and-trade program begin in 2012. The CARB’s schedule for developing regulations to implement AB 32 is being coordinated with the schedule of the WCI for development of a regional cap-and-trade program for greenhouse gas emissions. Through the WCI, California is working with other western states and ~~mercury~~Canadian ~~limits~~provinces to coordinate and implement a regional cap-and-trade program. In October 2010, the CARB released its proposed cap-and-trade regulation for public comment, which the CARB approved in December 2010. In March 2011, a California superior court judge enjoined the implementation of the cap-and-trade program and related Scoping Plan measures until the CARB remedies various procedural flaws related to the CARB’s environmental review of the Scoping Plan under the ~~Maryland~~California ~~Healthy~~Environmental ~~Air~~Quality Act. The CARB appealed the decision. A state ~~Accordingly~~appellate court stayed the injunction, ~~emissions~~allowing ~~from~~the ~~our~~CARB ~~Maryland~~to ~~coal~~continue to develop the final cap-~~fired~~and-trade ~~units~~regulation. ~~already~~However, ~~meet~~the CARB indicated in June 2011 that while it still intends to initiate the ~~EPA’s~~cap-and-trade ~~proposed~~program ~~HAPs~~in ~~standards~~2012, ascompliance requirements aimposed ~~result~~by the rule will be delayed one year until 2013. In October 2011, the CARB adopted these final cap-and-trade regulations with an initial compliance period of 2013-2014 for electric utilities and large industrial facilities. Our California generating facilities will be required to comply with the ~~controls~~cap-and-trade ~~that~~regulations ~~have~~and ~~been~~related ~~installed~~rules when they go into effect. The recently adopted cap-and-trade regulation and any other plans, rules and programs approved to implement AB 32 could adversely affect the costs of operating the facilities. However, in accordance with our tolling agreements for the Northern California generating facilities, we would pass any applicable costs through to the counterparties.

~~AB 32~~Water Regulations. In ~~California~~April 2011, ~~emissions~~the ofEPA ~~greenhouse~~proposed ~~gases~~a ~~are governed by California’s Global Warming Solutions Act~~ 316(~~AB 32~~b), ~~which~~rule ~~requires~~ that ~~statewide~~would ~~greenhouse~~apply ~~gas~~to ~~emissions~~virtually beall ~~reduced~~existing ~~to 1990 levels by 2020. In December 2008~~facilities, ~~the~~including ~~CARB~~power ~~approved~~plants ~~a Scoping Plan for implementing AB 32. The Scoping Plan requires~~ that ~~the~~use ~~CARB~~cooling ~~adopt~~water aintake ~~cap-and-trade~~structures ~~regulation by January 2011 and that the cap-and-trade program begin in 2012. The CARB’s schedule for developing regulations~~ to ~~implement AB~~withdraw 32water isfrom ~~being~~waters ~~coordinated with the schedule~~ of the ~~WCI~~United ~~for~~States. ~~development~~That ofproposal awould ~~regional~~impose ~~cap-and-trade~~national ~~program~~standards for ~~greenhouse~~reducing ~~gas~~mortality ~~emissions.~~for ~~Through the WCI~~larger, ~~California is~~impingeable-sized ~~working~~organisms. ~~with~~It ~~other~~requires ~~western~~permit ~~states~~writers ~~and Canadian provinces~~ to ~~coordinate~~establish ~~and~~controls ~~implement~~for asmaller, ~~regional cap~~entrainable-~~and-trade~~sized ~~program.~~organisms Inon ~~October 2010,~~a ~~the CARB released its proposed cap~~site-~~and-trade~~specific ~~regulation for public comment~~basis, ~~which~~taking ~~the~~into ~~CARB~~account ~~approved~~a ~~in December 2010.~~variety Inof ~~March 2011~~factors, aincluding ~~California~~costs ~~superior court judge enjoined the implementation of the cap-~~and~~-trade~~ ~~program~~benefits. ~~and~~The ~~related~~final ~~Scoping~~rule ~~Plan~~may ~~measures~~differ ~~until~~from the ~~CARB~~proposal ~~remedies~~as ~~various procedural flaws related to the CARB’s~~a ~~environmental~~result ~~review~~ of the ~~Scoping~~public ~~Plan~~comment ~~under the California Environmental Quality Act~~process. ~~The~~Until ~~CARB appealed~~ the ~~decision.~~EPA Aissues ~~state appellate court stayed~~ the ~~injunction, allowing the CARB to continue to develop the~~ final ~~cap-and-trade regulation~~rule, ~~with adoption~~which ~~targeted for October 2011. However, CARB indicated in June 2011 that while~~ it ~~still~~has ~~intends~~committed to ~~initiate~~do ~~the~~by ~~cap-and-trade program in~~ July 2012, ~~compliance~~there ~~requirements~~is ~~imposed~~significant byuncertainty ~~the~~regarding ~~rule~~what ~~will~~technologies beor ~~delayed~~other ~~one~~measures ~~year until 2013. Our California generating facilities~~ will be ~~required~~needed to ~~comply~~satisfy ~~with the cap-and-trade~~ section 316(b) regulations ~~and related rules when they go into effect~~. ~~The recently adopted cap-and-trade regulation and any other plans, rules and programs approved to implement AB 32 could adversely affect the costs of operating the facilities.~~

Water Regulations. In April 2011, the EPA proposed a 316(b) rule that would apply to virtually all existing facilities, including power plants that use cooling water intake structures to withdraw water from waters of the United States. That proposal would impose national standards for reducing mortality for larger, impingeable-sized organisms. It requires permit writers to establish controls for smaller, entrainable-sized organisms on a site-specific basis, taking into account a variety of factors, including costs and benefits. In July 2011, the EPA extended the time in which it will accept public comment until August 18, 2011. The final rule may differ from the proposal as a result of the public comment process. Until the EPA issues the final rule, which it has committed to do by July 2012, there is significant uncertainty regarding what technologies or other measures will be needed to satisfy section 316(b) regulations.

Potrero Shutdown

On February 28, 2011, the Potrero generating facility was shut down. See note 3 to our consolidated financial statements in our 2010 Annual Report on Form 10-K for further discussion.

Potomac River Retirement

In August 2011, GenOn Mid-Atlantic entered into an agreement with the City of Alexandria, Virginia to remove permanently from service its Potomac River generating facility on October 1, 2012, subject to the receipt of all necessary consents and approvals. PJM has determined that the retirement of the facility will not affect reliability. GenOn Mid-Atlantic must now receive consent from PEPCO. If the PEPCO consent has not been received by July 3, 2012, the Potomac River generating facility will be retired within 90 days after the receipt thereof. Upon retirement of the Potomac River generating facility, all funds in a related account shall be distributed to GenOn Mid-Atlantic, provided that, if the retirement of the facility is after January 1, 2014, $750,000 of such funds shall be paid to the City of Alexandria. Currently, approximately $32 million is held in the escrow account. We do not expect any material diminution in the amount on deposit in the escrow account between now and disbursement of the funds to us. We do not expect the closing of the Potomac River generating facility to have a material effect on our business, results of operations, financial position or cash flows. See note 2 to our interim financial statements for further discussion of the retirement of the Potomac River generating facility and the impairment losses recognized in 2010.

Commodity Prices

The prices for power and natural gas remain 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.

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 are designated as hedges 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. However, these non-GAAP financial measures may not be comparable to similarly titled non-GAAP financial measures used by other companies. 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.

4548

~~gross~~Three ~~margin~~Months ~~(excluding~~Ended ~~depreciation and amortization) less unrealized gains and losses on derivative financial instruments. Conversely~~September 30, ~~unrealized~~2011 ~~gross~~Compared 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~~Three inMonths ~~value~~Ended ~~primarily because of changes in forward electricity and fuel prices. Realized gross margin~~September 30, ~~together with its components energy, contracted and capacity and~~2010 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. However, these non-GAAP financial measures may not be comparable to similarly titled non-GAAP financial measures used by other companies. 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.

Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010

Consolidated Financial Performance

We reported a net ~~income~~loss of $8106 million and a net ~~loss~~income of $~~292~~266 million during the three months ended ~~June~~September 30, 2011 and 2010, respectively. The change in net income/loss is detailed as follows:

		September 30,			September 30,			September 30,
	Three MonthsEndedJune 30,						Increase/(Decrease)
	Three MonthsEnded September 30,						Increase/
	2011			2010			(Decrease)
	(in millions)
Gross margin:
Energy	$	8071		$	96171		$	(16100	)
Contracted and capacity		~~105~~89			~~138~~135			(3346	)
Realized value of hedges		6349			7855			(156	)
Total realized gross margin		248			312			(64	)
Realized gross margin		209			361			(152	)
Unrealized gross margin		1—			~~(340~~167	)		~~341~~(167	)
Total gross margin (excluding depreciation and amortization)		~~249~~209			~~(28~~528	)		~~277~~(319	)
Operating expenses:
Operations and maintenance		~~118~~73			9388			25(15	)
Operations and maintenance—affiliate		5953			7274			(1321	)
Depreciation and amortization		42			5052			(810	)
(Gain) loss on sales of assets, net		1			(1	)		2
Impairment losses		128			—			128
Total operating expenses		220			214			6
Gain on sales of assets, net		(6	)		(1	)		(5	)
Operating income (loss)		29			(242	)		271
Loss on sales of assets, net—affiliate		2			—			2
Total operating expenses		292			213			79
Operating income (loss)		(83	)		315			(398	)
Other income (expense), net:
Interest expense, net		(2119	)		(4951	)		(2832	)
Other, net		—			(1	)		(1	)
Interest expense, net—affiliate		(4	)		—			4
Total other expense, net		(21	)		(50	)		(29	)
Other, net		—			1			1
Net income (loss)	$	8		$	(292	)	$	300
Total other expense, net		(23	)		(50	)		(27	)
Income (loss) before income taxes		(106	)		265			(371	)
Benefit for income taxes		—			(1	)		1
Net income (loss)	$	(106	)	$	266		$	(372	)

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, through RMR contracts (which we had at Potrero through February 28, 2011), through PPAs and tolling agreements and from 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.

46During the three months ended September 30, 2011, our realized gross margin decrease of $152 million was principally a result of the following:

•

a decrease of $100 million in energy primarily as a result of a decrease in generation volumes in Eastern PJM as a result of contracting dark spreads and spark spreads and a decrease in Energy Marketing primarily as a result of a decrease in fuel oil management activities, offset in part by an increase in proprietary trading;

~~contracts~~• ~~include~~a ~~sales~~decrease of ~~both~~$46 ~~power~~million ~~and~~in ~~natural~~contracted ~~gas~~and ~~used~~capacity toprimarily ~~hedge~~from ~~power~~lower capacity prices, asin ~~well~~Eastern asPJM ~~hedges~~and ~~to capture~~ the ~~incremental~~Northeast ~~value~~and ~~related~~the toshutdown of the ~~geographic~~Potrero ~~location~~generating offacility ~~our~~in ~~physical~~California; ~~assets.~~ and

~~During~~• ~~the~~a ~~three~~decrease ~~months~~of ~~ended~~$6 ~~June 30,~~million ~~2011,~~in ~~our~~ realized ~~gross~~value ~~margin decrease~~ of ~~$64 million~~hedges ~~was~~primarily ~~principally~~as a result of ~~the~~a ~~following:~~decrease in power hedges in Eastern PJM primarily resulting from prices and volumes hedged, partially offset by an increase in coal hedges in Eastern PJM resulting from prices.

• a decrease of $33 million in contracted and capacity primarily resulting from lower capacity prices in Eastern PJM and the Northeast and the shutdown of the Potrero generating facility in California;

• a decrease of $16 million in energy, primarily as a result of a decrease in generation volumes in Eastern PJM as a result of outages at certain of our coal-fired baseload units, an increase in production costs at our Dickerson generating facility as a result of the CO2 levy and contracting off-peak dark spreads, partially offset by an increase from our fuel oil management activities in Energy Marketing, primarily from the sales of fuel oil; and

• a decrease of $15 million in realized value of hedges primarily as a result of a decrease in power hedges in Eastern PJM and the Northeast primarily related to prices, offset by an increase in coal hedges in Eastern PJM related to 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 gains or losses of $10 ~~million~~ 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; and

• unrealized ~~losses~~gains of $~~340~~167 million during the three months ended ~~June~~September 30, 2010, which included a $~~205~~243 million net ~~decrease~~increase in the value of hedge and trading contracts for future periods primarily related to ~~increases~~decreases in forward power ~~prices~~ and ~~the~~natural ~~recognition~~gas ofprices ~~many~~and ofincreases ~~our~~in forward coal ~~agreements~~prices, atoffset ~~fair~~by ~~value~~unrealized ~~beginning~~losses ~~in the second quarter~~ of ~~2010. The~~ $~~340~~76 million ~~also included $135 million~~ associated with the reversal of previously recognized unrealized gains from power and fuel contracts that settled during the period.

Operating Expenses. Our operating expenses increase of $679 million was principally a result of the following:

• an increase of $12128 million in ~~operations~~impairment ~~and~~losses ~~maintenance~~for ~~expense~~the ~~primarily~~write-off ~~as a result~~ of aexcess ~~$30~~NOx ~~million~~and ~~accrual~~SO2 ~~for~~emissions ~~remediation~~allowances ~~costs~~included atin ~~our~~intangible ~~Maryland~~assets ~~ash facilities~~ (~~which includes a tentative~~ $~~1.9~~70 million ~~civil penalty~~), and anthe ~~increase~~write-off ~~in litigation costs for major project disputes, net~~ of ~~recoveries.~~excess ~~The~~NOx ~~increase in operations~~ and ~~maintenance~~SO2 ~~expense~~emissions ~~was~~allowances ~~partially~~previously ~~offset~~included ~~by a decrease~~ in ~~allocated~~property, ~~overhead~~plant ~~costs~~and asequipment a($58 ~~result~~million) ofduring ~~a change in~~ the ~~allocation~~three ~~methodology~~months asended aSeptember ~~result~~30, of2011 ~~the Merger and a decrease of $12 million~~ as a result of the ~~repeal~~CSAPR ofin ~~the~~Eastern ~~Montgomery County CO2 levy~~PJM, ~~including~~Northeast $8and ~~million related to the refund received in the third quarter of 2011 of CO2 levies paid in 2010~~California; partially offset ~~in part~~ by

• a decrease of $836 million in ~~depreciation~~operations and ~~amortization~~maintenance expense primarily as a result of (a) ~~reduction~~a change in the ~~carrying~~allocation ~~value~~methodology for overhead costs as a result of the ~~Dickerson~~Merger, ~~and~~(b) ~~Potomac~~a ~~River~~$6 ~~generating~~million ~~facilities~~decrease resulting from changes in asset retirement obligation assumptions in Eastern PJM, (c) $4 million as a result of ~~impairment~~the ~~losses~~repeal ~~taken~~of in the ~~fourth~~Montgomery ~~quarter~~County ofCO2 ~~2010,~~levy and ~~the~~(d) ~~shutdown~~other ofcost ~~the~~reductions ~~Potrero~~in ~~generating~~Eastern ~~facility~~PJM and Northeast. These decreases were partially offset by $5 million of major litigation costs, net of recoveries; and

•

a decrease of $10 million in depreciation and amortization expense primarily as a result of a reduction in the carrying value of the Dickerson and Potomac River generating facilities as a result of impairment losses in the fourth quarter of 2010, and the shutdown of the Potrero generating facility.

Interest Expense, Net. Interest expense, net decrease of $28 million reflects lower interest expense as a result of (a) repayment of the GenOn North America senior secured credit facilities and senior notes in December 2010 and January 2011, respectively, and (b) repayment of the GenOn Americas Generation senior unsecured notes in May 2011.

4750

Operating Statistics

The following table summarizes power generation volumes by segment:

		September 30,		September 30,			September 30,			September 30,
	Three Months EndedJune 30,					Increase/(Decrease)			Increase/(Decrease)
	Three MonthsEnded September 30,					Increase/(Decrease)			Increase/(Decrease)
	2011		2010
	(in gigawatt hours)
Eastern PJM:
Baseload		23,~~612~~024		34,~~062~~060			(~~450~~1,036	)		(1526	)%
Intermediate		~~242~~456		~~277~~733			(35277	)		(1338	)%
Peaking		2957		64121			(3564	)		(5553	)%
Total Eastern PJM		23,~~883~~537		34,~~403~~914			(~~520~~1,377	)		(1528	)%
Northeast:
Baseload		~~374~~301		~~355~~400			19(99	)		5(25	)%
Intermediate		47164		49324			(2160	)		(449	)%
Peaking		18		15			—3			—60	%
Total Northeast		~~422~~473		~~405~~729			17(256	)		4(35	)%
California:
Intermediate		4128		88255			(47227	)		(5389	)%
Total California		41		88			(47	)		(53	)%
Peaking (1)		—		(1	)		1			100	%
Total		3,346		3,896			(550	)		(14	)%
Total California		28		254			(226	)		(89	)%
Total		4,038		5,897			(1,859	)		(32	)%

~~The~~(1) ~~total~~Negative ~~decrease~~amounts indenote ~~power~~net ~~generation~~energy ~~volumes~~used ~~during~~by the ~~three~~generating ~~months ended June 30, 2011, as compared to the same period in 2010, was primarily the result of the following:~~ facility.

~~Eastern~~The ~~PJM.~~total A decrease in ~~our~~power generation volumes ~~primarily~~during asthe athree ~~result~~months ofended ~~increased~~September 30, ~~outages~~2011, atas ~~certain~~compared ofto ~~our~~the ~~coal-fired~~same ~~baseload~~period ~~units, an increase~~ in ~~production~~2010, ~~costs~~was atprimarily ~~our~~the ~~Dickerson generating facility as a~~ result of the ~~CO2~~following: ~~levy and contracting off-peak dark spreads.~~

~~Northeast~~Eastern PJM. AnThe ~~increase~~decrease in our ~~Northeast~~ baseload and intermediate generation volumes was primarily as a result of ~~higher~~contracting ~~average~~dark spreads ~~temperatures~~and spark spreads.

~~California~~Northeast. The decrease in our baseload and intermediate generation ~~volumes~~ was ~~primarily~~a ~~the~~ result of ~~the~~a ~~shutdown~~reduction ofin our ~~the~~available ~~Potrero~~capacity at our Bowline generating facility, an outage at one of our generating facilities and contracting spark spreads in New England.

48California. The decrease in our intermediate generation volumes was primarily as a result of the shutdown of the Potrero generating facility.

~~Six~~Nine Months Ended ~~June~~September 30, 2011 Compared to ~~Six~~Nine Months Ended ~~June~~September 30, 2010

Consolidated Financial Performance

We reported a net loss of $10116 million and net income of $~~124~~390 million during the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010, respectively. The change in net income/loss is detailed as follows:

		September 30,			September 30,			September 30,
	Six Months EndedJune 30,						Increase/
	Nine MonthsEnded September 30,						Increase/
	2011			2010			(Decrease)
	(in millions)
Gross margin:
Energy	$	~~177~~248		$	~~206~~377		$	(29129	)
Contracted and capacity		~~226~~315			~~280~~415			(54100	)
Realized value of hedges		~~130~~179			~~147~~202			(1723	)
Total realized gross margin		533			633			(100	)
Realized gross margin		742			994			(252	)
Unrealized gross margin		(70	)		12179			(82249	)
Total gross margin (excluding depreciation and amortization)		~~463~~672			~~645~~1,173			(~~182~~501	)
Operating expenses:
Operations and maintenance		~~197~~270			~~182~~270			15—
Operations and maintenance—affiliate		~~119~~172			~~142~~216			(2344	)
Depreciation and amortization		82124			99151			(1727	)
(Gain) loss on sales of assets, net		1			(3	)		4
Impairment losses		128			—			128
Total operating expenses		399			420			(21	)
Gain on sales of assets, net		(5	)		(4	)		(1	)
Operating income		64			225			(161	)
Loss on sales of assets, net—affiliate		2			—			2
Total operating expenses		691			633			58
Operating income		(19	)		540			(559	)
Other income (expense), net:
Interest expense, net		(5170	)		(99150	)		(4880	)
Other, net		(23	)		(2	)		21
Interest expense, net—affiliate		(4	)		—			4
Total other expense, net		(74	)		(101	)		(27	)
Other, net		(23	)		(1	)		22
Net income (loss)	$	(10	)	$	124		$	(134	)
Total other expense, net		(97	)		(151	)		(54	)
Income (loss) before income taxes		(116	)		389			(505	)
Benefit for income taxes		—			(1	)		1
Net income (loss)	$	(116	)	$	390		$	(506	)

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, through RMR contracts (which we had at Potrero through February 28, 2011), through PPAs and tolling agreements and from 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 ~~six~~nine months ended ~~June~~September 30, 2011, our realized gross margin decrease of $~~100~~252 million was principally a result of the following:

• a decrease of $54129 million in ~~contracted~~energy ~~and~~primarily ~~capacity~~as ~~primarily~~a ~~resulting~~result ~~from~~of ~~lower~~a ~~capacity~~decrease ~~prices~~in generation volumes in Eastern PJM ~~and~~as ~~the~~a ~~Northeast~~result of contracting dark spreads and ~~the~~spark ~~shutdown~~spreads ofpartially ~~the~~offset ~~Potrero~~by ~~generating~~an ~~facility~~increase in ~~California~~Energy Marketing as a result of an increase in proprietary trading and fuel oil management activities;

•52 a decrease of $29 million in energy, primarily as a result of a decrease in generation volumes in Eastern PJM as a result of contracting dark spreads and an increase in production costs at our Dickerson generating facility as a result of the CO2 levy, partially offset by an increase from our fuel oil management activities in Energy Marketing primarily from the sales of fuel oil and an increase in the Northeast resulting from an increase in power prices and generation volumes as a result of higher average temperatures; and

• a decrease of $17100 million in ~~realized~~contracted ~~value~~and ofcapacity ~~hedges~~ primarily asresulting afrom ~~result~~lower ofcapacity aprices ~~decrease~~ in ~~our power hedges in~~ Eastern PJM and the Northeast ~~primarily~~and ~~resulting~~the ~~from~~shutdown ~~prices,~~of ~~offset~~the inPotrero ~~part~~generating byfacility ~~an increase~~ in ~~our~~California; ~~coal hedges in Eastern PJM resulting from prices.~~and

•

a decrease of $23 million in realized value of hedges primarily as a result of a decrease in our power hedges in Eastern PJM and the Northeast primarily resulting from prices and volumes hedged and a decrease in crude oil hedges in the Northeast, offset in part by an increase in our coal hedges in Eastern PJM resulting from prices.

• 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; and

• unrealized gains of $12179 million during the ~~six~~nine months ended ~~June~~September 30, 2010, which included a $~~228~~471 million net increase in the value of hedge and trading contracts for future periods primarily related to decreases in forward power and natural gas prices ~~and~~offset ~~also~~in ~~included~~part by the recognition of many of our coal agreements at fair value beginning in the second quarter of 2010. The increase in value was ~~partially~~further offset by ~~$216~~unrealized ~~million~~losses ~~associated with the reversal~~ of ~~previously~~$292 ~~recognized~~million ~~unrealized gains~~ from power and fuel contracts that settled during the period for which net unrealized gains had been recorded in prior periods.

Operating Expenses. Our operating expenses ~~decrease~~increase of $2158 million was principally a result of the following:

• aan ~~decrease~~increase of $17128 million in ~~depreciation~~impairment ~~and~~losses ~~amortization~~for ~~expense~~the ~~primarily~~write-off asof aexcess ~~result~~NOx ofand aSO2 ~~reduction~~emissions allowances included in ~~the~~intangible ~~carrying~~assets ~~value~~($70 ofmillion) and the ~~Dickerson~~write-off of excess NOx and ~~Potomac~~SO2 ~~River~~emissions ~~generating~~allowances ~~facilities~~previously asincluded ain ~~result~~property, ofplant ~~impairment~~and ~~losses~~equipment ~~taken~~($58 inmillion) during the ~~fourth~~three ~~quarter~~months ofended ~~2010~~September 30, ~~and~~2011 ~~the~~as ~~shutdown~~a result of the ~~Potrero~~CSAPR ~~generating~~in ~~facility;~~Eastern PJM, Northeast and California; partially offset by

• a decrease of $844 million in operations and maintenance expense primarily as a result of (a) ~~decrease in allocated overhead costs as~~ a ~~result of a~~ change in the allocation methodology for overhead costs as a result of the Merger, (b) a decrease of $1014 million as a result of the repeal of the Montgomery County CO2 levy, including $8 million related to the refund received in the third quarter of 2011 of CO2 levies paid in 2010, (c) a ~~reduction~~$6 million decrease resulting from changes in ~~outage~~asset ~~expenses~~retirement obligation assumptions in ~~California~~Eastern PJM, (d) a reduction in variable operations and maintenance, and outage expenses in Eastern PJM, (e) the shutdown of the Potrero generating facility, ~~and~~(f) a decrease in property taxes in the Northeast and (g) other cost reductions in Northeast and California. The decrease in operations and maintenance expense was partially offset by a $30 million accrual for remediation costs at our Maryland ash facilities (which includes a tentative $1.9 million civil penalty) and ana $12 million increase in ~~litigation costs for~~ major ~~project~~litigation ~~disputes~~costs, net of recoveries; ~~partially offset by~~and

• a decrease of $4 27 million in ~~gain~~depreciation onand ~~sales~~amortization expense primarily as a result of ~~assets~~a ~~primarily~~reduction ~~related~~in tothe ~~emissions~~carrying ~~allowances~~value ~~sold~~of tothe ~~third~~Dickerson ~~parties~~and Potomac River generating facilities as a result of impairment losses in the fourth quarter of 2010, and the shutdown of the Potrero generating facility.

Interest Expense, Net. Interest expense, net decrease of $4876 million reflects lower interest expense as a result of (a) repayment of the GenOn North America senior secured credit facilities and senior notes in December 2010 and January 2011, respectively, and (b) repayment of the GenOn Americas Generation senior unsecured notes in May 2011.

~~Other,~~53 Net. Other, net change of $21 million was primarily a result of $23 million relating to the 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.

Other, Net. Other, net change of $22 million was primarily a result of $23 million relating to the 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.

Operating Statistics

The following table summarizes power generation volumes by segment:

		September 30,		September 30,			September 30,			September 30,
	Six Months EndedJune 30,					Increase/(Decrease)			Increase/(Decrease)
	Nine Months EndedSeptember 30,					Increase/			Increase/
	2011		2010			(Decrease)			(Decrease)
	(in gigawatt hours)
Eastern PJM:
Baseload		69,~~123~~147		711,~~034~~094			(~~911~~1,947	)		(1318	)%
Intermediate		~~263~~719		~~332~~1,065			(69346	)		(2132	)%
Peaking		43100		70191			(2791	)		(3948	)%
Total Eastern PJM		69,~~429~~966		712,~~436~~350			(12,~~007~~384	)		(1419	)%
Northeast:
Baseload		~~753~~1,054		~~720~~1,120			33(66	)		5(6	)%
Intermediate		67252		58382			9(130	)		16(34	)%
Peaking		19		16			—3			—50	%
Total Northeast		~~821~~1,315		~~779~~1,508			42(193	)		5(13	)%
California:
Intermediate		5280		~~211~~466			(~~159~~386	)		(7583	)%
Total California		52		211			(159	)		(75	)%
Peaking (1)		—		(1	)		1			100	%
Total		7,302		8,426			(1,124	)		(13	)%
Total California		80		465			(385	)		(83	)%
Total		11,361		14,323			(2,962	)		(21	)%

~~The~~(1) ~~total~~Negative ~~decrease~~amounts indenote ~~power~~net ~~generation~~energy ~~volumes~~used ~~during~~by the ~~six~~generating ~~months ended June 30, 2011, as compared to the same period in 2010, was primarily the result of the following:~~ facility.

~~Eastern~~The ~~PJM.~~total A decrease in ~~our~~power generation volumes ~~primarily~~during asthe anine ~~result~~months ofended ~~contracting~~September 30, ~~dark~~2011, ~~spreads~~as ~~and~~compared anto ~~increase~~the insame ~~production~~period ~~costs~~in at2010, ~~our~~was ~~Dickerson~~primarily ~~generating~~the ~~facility as a~~ result of the ~~CO2~~following: ~~levy.~~

~~California~~Northeast. The decrease in our baseload and intermediate generation ~~volumes~~ was ~~primarily~~a ~~the~~ result of ~~the~~a reduction ~~shutdown~~in ofour ~~the~~available ~~Potrero~~capacity at our Bowline generating facility, an outage at one of our generating facilities and contracting spark spreads in New England.

California. The decrease in our intermediate generation volumes was primarily as a result of the shutdown of the Potrero generating facility.

Financial Condition

Liquidity and Capital Resources

Management thinks that our liquidity position and cash flows from operations will be adequate to fund operating, maintenance and capital expenditures, to fund debt service and to meet other liquidity requirements. Management regularly monitors our ability to fund our operating, financing and investing activities. See note 34 to our interim financial statements for additional discussion of our debt.

~~Sources~~54 ~~of Funds and Capital Structure~~

The principal sources of our liquidity are expected to be: (a) existing cash on hand and expected cash flows from 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, additional capital contributions from GenOn.

~~The~~Sources ~~table below sets forth total cash and cash equivalents~~ of ~~GenOn~~Funds ~~Americas Generation~~ and ~~its~~ ~~subsidiaries~~Capital atStructure ~~June 30, 2011 (in millions):~~

		September 30,
Cash and Cash Equivalents:
GenOn Americas Generation (excluding GenOn Mid-Atlantic)	$	226
GenOn Mid-Atlantic		53
Total cash and cash equivalents	$	279

The principal sources of our liquidity are expected to be: (a) existing cash on hand and expected cash flows from the operations of our subsidiaries, (b) at its discretion, letters of credit issued by GenOn, and (c) at its discretion, additional capital contributions from GenOn.

WeOur ~~consider~~operating ~~all~~cash ~~short-term~~flows ~~investments~~may ~~with~~be anaffected ~~original~~by, ~~maturity~~among ofother ~~three~~things: ~~months~~(a) demand orfor ~~less~~electricity; (b) the difference between the cost of fuel used to begenerate ~~cash~~electricity and the market value of the ~~equivalents.~~electricity Atgenerated; ~~June~~(c) 30commodity prices (including prices for electricity, ~~2011~~emissions allowances, ~~except~~natural ~~for~~gas, ~~amounts~~coal ~~held~~and oil); (d) operations and maintenance expenses in ~~bank~~the ~~accounts~~ordinary tocourse; ~~cover~~(e) planned ~~upcoming~~and ~~payables,~~unplanned ~~all~~outages; (f) terms ofwith ~~our~~trade ~~cash~~creditors; and (g) cash ~~equivalents~~requirements ~~were~~for ~~invested~~capital inexpenditures ~~AAA-rated~~relating ~~United~~to ~~States~~certain ~~Treasury~~facilities ~~money~~(including ~~market~~those ~~funds~~necessary to comply with environmental regulations).

The table below sets forth total cash and cash equivalents of GenOn Americas Generation and its subsidiaries at September 30, 2011 (in millions):

		September 30,
Cash and Cash Equivalents:
GenOn Americas Generation (excluding GenOn Mid-Atlantic)	$	116
GenOn Mid-Atlantic		84

Total cash and cash equivalents	$	200

We consider all short-term investments with an original maturity of three months or less to be cash equivalents. At September 30, 2011, 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.

LOGO

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. InA ~~particular, a~~ substantial portion of cash from its operations is generated by GenOn 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 payment tests are not satisfied, GenOn Mid-Atlantic would not be able to distribute cash or make other restricted payments. At ~~June~~ September 30, 2011, GenOn Mid-Atlantic satisfied the restricted payments test. As a result of certain lien restrictions in its lease documentation, GenOn Mid-Atlantic has reserved $~~143~~165.6 million of cash (which is included in funds on deposit on the unaudited condensed consolidated balance sheet) in respect of such liens. InSee ~~June 2011,~~note ~~Stone &~~9 ~~Webster filed a motion~~ to ~~amend~~our ~~its~~interim ~~lien~~financial ~~claims at Chalk Point, Dickerson and Morgantown by an additional $90 million~~statements. ~~In the event that such liens are granted, GenOn Mid-Atlantic expects to reserve an additional $90 million of cash in respect thereof. See note 8.~~

~~Our~~55 ability to pay our obligations is dependent on the receipt of dividends from GenOn North America, capital contributions or intercompany loans from GenOn and our ability to refinance all or a portion of those obligations as they become due.

Our ability to pay our obligations is dependent on the receipt of dividends from GenOn North America, capital contributions or intercompany loans from GenOn and our 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, (b) debt service, (c) payments under the GenOn Mid-Atlantic operating leases, and (d) collateral required for our asset management and proprietary trading and fuel oil management activities.

Repayment of Debt. On January 3, 2011, part of the proceeds from the ~~Merger~~merger-related debt issuances was used to redeem $866 million (principal and 1.844% premium) of GenOn North America senior unsecured notes due 2013. On May 2, 2011, we repaid our $535 million of senior notes that came due. See note 34 to our interim financial statements.

Capital Expenditures. Our capital expenditures, excluding capitalized interest paid, during the ~~six~~nine months ended ~~June~~ September 30, 2011, were $46129 million. We estimate our capital expenditures, excluding capitalized interest, for the period ~~July~~October 1, 2011 through December 31, ~~2012~~2013 will be $~~273~~286 million. 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 cash collateral or letters of credit as 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, ~~and~~ 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 draw on a letter of credit or apply cash collateral held to satisfy the existing amounts outstanding under an open contract. At ~~June~~September 30, 2011, we had $~~240~~174 million of posted cash collateral and GenOn had $~~178~~138 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. Our liquidity requirements 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.

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

		September 30,		September 30,
	June 30,2011		December 31,2010
	September 30,2011		December 31,2010
	(in millions)
Cash collateral posted—energy trading and marketing	$	~~200~~135	$	80
Cash collateral posted—other operating activities		4039		40
Letters of credit—rent reserves(1)		9875		101
Letters of credit—energy trading and marketing(1)		4730		63
Letters of credit—other operating activities(1)		33		31
Surety bonds		82		7
Total	$	~~426~~314	$	322

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

“Cash collateral posted—energy trading and marketing” includes initial margin held by MF Global Inc., a futures contract merchant and broker/dealer entity, and one of three clearing brokers through which we held positions on The Chicago Mercantile Exchange, the Intercontinental Exchange and the Nodal Exchange. On October 31, 2011, the Securities Investor Protection Corporation announced that it initiated the liquidation of MF Global Inc. under the Securities Investor Protection Act. As of October 31, 2011, we had $12 million in our accounts with MF Global Inc., $9 million of which was being used to cover the initial margin requirements of our open positions. Recovery of the initial margin and excess funds from MF Global Inc. will be a function of the amounts available to satisfy the claims of customers and other creditors and the priority of claims. Generally, customers with “commodity contracts” receive priority treatment with respect to “customer property.” However, news reports indicate that there may be a significant shortfall in MF Global Inc.’s commodity customer funds. We are in the process of evaluating our claims and will be pursuing our rights to recover amounts owned.

Debt Obligations, Off-Balance Sheet Arrangements and Contractual Obligations

There have been no material changes outside the ordinary course of business to our debt obligations, off-balance sheet arrangements and contractual obligations from those disclosed in our 2010 Annual Report on Form 10-K and note 34 to our interim financial statements.

Historical Cash Flows

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 ~~increased~~decreased $~~112~~154 million for the ~~six~~nine months ended ~~June~~September 30, 2011, compared to the same period in 2010, primarily as a result of the following:

• ~~Inventories~~Realized gross margin. A decrease in cash ~~used~~provided of $~~145~~273 million ~~primarily~~in ~~related~~2011, compared to ~~changes~~the same period in ~~fuel~~2010, ~~oil~~excluding a decrease in non-cash lower of cost or market inventory adjustment of $21 million. See “Results of Operations” in Item 2 for additional discussion of our performance in 2011 compared to the same period in 2010;

• ~~Net~~Accounts ~~accounts~~payable, ~~receivables and accounts payables~~collateral. AnA ~~increase~~decrease in cash provided of $~~121~~41 million primarily as a result of anless ~~increase~~than in$1 ~~payables~~million toposted ~~affiliates resulting from transactions initiated~~ by ~~GenOn~~our ~~Energy~~counterparties ~~Management~~in on2011 ~~behalf~~compared ofto ~~affiliated~~$41 ~~companies.~~million ~~See~~posted ~~note~~by ~~5 to~~ our ~~interim~~counterparties ~~financial~~in ~~statements~~2010; and

• ~~Interest~~Funds ~~Expense~~on deposit. AAn ~~decrease~~increase in cash used of $4329 million ~~related~~primarily toas ~~lower~~a ~~interest~~result ~~expense~~of ~~primarily~~$54 ~~resulting~~million ~~from the repayment~~ of ~~GenOn~~additional ~~North~~collateral ~~America~~posted ~~senior~~with ~~notes~~our counterparties in ~~December~~2011 ~~2010~~compared ~~and~~to ~~the~~an ~~GenOn~~additional ~~North~~$25 ~~America~~million ~~term~~collateral ~~loan~~posted inwith ~~January~~our ~~2011;~~counterparties ~~and~~in 2010.

• Other operating assets and liabilities. AAn ~~decrease~~increase in cash used of $492 million related to changes in other operating assets and liabilities as compared to the same period in 2010.

~~The~~57 ~~increases in cash provided and decreases in cash used by operating activities were partially offset by the following:~~

• Funds on deposit. An increase in cash used of $127 million primarily as a result of $120 million of additional collateral posted with our counterparties in 2011 compared to an additional $7 million returned from our counterparties in 2010; and

• Realized gross margin. A decrease in cash provided of $119 million in 2011, compared to the same period in 2010, excluding a decrease in non-cash lower of cost or market inventory adjustment of $19 million. See “Results of Operations” in Item 2 for additional discussion of our performance in 2011 compared to the same period in 2010.

Investing Activities. Net cash provided by investing activities increased by $685 million for the six months ended June 30, 2011, compared to the same period in 2010. This difference was primarily a result of the following:

• Withdrawals from restricted funds on deposit. An increase 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. The withdrawal of cash was used to repay the GenOn North America long-term debt. See note 3 to our interim financial statements; and

• Capital expenditures. A decrease in cash used of $108 million primarily as a result of payments related to our Maryland scrubber projects in 2010.

The increase in cash provided by and decrease in cash used in investing activities were partially offset by the following:

• Intercompany debt. An increase in cash used of $147 million related to the repayment of intercompany debt.

• Payments into restricted funds on deposit. A decrease in cash provided of $143 million primarily related to funds placed in restricted deposits as a result of our scrubber contract litigation and related liens. See note 8 to our interim financial statements; and

Financing Activities. Net cash used in financing activities increased by $1.059 billion for the six months ended June 30, 2011, compared to the same period in 2010. This difference was primarily a result of the following:

•The ~~Repayment~~decreases ofin ~~long-term~~cash ~~debt.~~provided Anand ~~increase~~increases in cash used ofby ~~$1.334~~operating ~~billion~~activities ~~for~~were ~~repayment~~partially ofoffset ~~long-term~~by the ~~debt.~~following: ~~See note 3 to our interim financial statements;~~

• ~~Distribution to member~~Inventories. AnA ~~increase~~decrease in cash used of $~~100~~80 million primarily related to achanges ~~distribution~~in tofuel ~~our~~oil ~~member~~inventory ~~during~~in ~~the six months ended June 30,~~ 2011. ~~There~~compared ~~were~~to ~~no distributions for~~ the ~~six~~same ~~months~~period ~~ended~~in ~~June 30,~~ 2010; ~~and~~

• ~~Redemption~~Interest ~~of preferred stock~~Expense. A decrease in cash ~~provided~~used of $9567 million related to ~~the~~lower ~~redemption~~interest ofexpense ~~Series~~primarily Aresulting ~~preferred~~from ~~stock~~the ~~held~~repayment byof GenOn ~~Mid-Atlantic~~North inAmerica ~~2010.~~senior ~~There~~notes ~~were~~in noDecember ~~redemptions~~2010 ~~during~~and the ~~six~~GenOn ~~months~~North ~~ended~~America ~~June~~term ~~30,~~loan in January 2011.;

~~The increases~~• Operating expenses. A decrease in cash used related to lower operations and ~~decrease~~maintenance expense of $44 million. See “Results of Operations” in ~~cash~~Item ~~provided~~2 byfor ~~financing~~additional ~~activities~~discussion ~~were~~of ~~partially~~our ~~offset~~performance byin 2011 compared to the ~~following:~~same period in 2010; and

•Investing ~~Capital contributions~~Activities. AnNet ~~increase in~~ cash provided ofby investing activities increased by $~~444~~618 million ~~related~~for the nine months ended September 30, 2011, compared to ~~contributions~~the ~~made~~same byperiod ~~our~~in ~~member;~~2010. ~~and~~This difference was primarily a result of the following:

• ~~Intercompany~~Withdrawals ~~debt~~from restricted funds on deposit. An increase in cash provided of $26934 million primarily related to ~~proceeds~~(a) $866 million received from ~~intercompany~~the GenOn debt financing on December 3, 2010, which were subsequently placed in restricted deposits at December 31, 2010 and (b) $68 million primarily related to the withdrawal of cash used to reduce the outstanding lien amounts in accordance with our scrubber contract litigation. The withdrawal of cash of $866 million was used to repay the GenOn North America long-term debt. See note 4 to our interim financial statements;

55• Capital expenditures. A decrease in cash used of $77 million primarily as a result of payments related to our Maryland scrubber projects; and

•

Other investing activities. An increase in cash provided of $5 million related to changes in other investing activities as compared to the same period in 2010.

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

•

Intercompany debt. An increase in cash used of $164 million related to the repayment of intercompany debt; and

•

Payments into restricted funds on deposit. A decrease in cash provided of $234 million primarily related to funds placed in restricted deposits as a result of our scrubber contract litigation and related liens. See note 9 to our interim financial statements.

Financing Activities. Net cash used in financing activities increased by $911 million for the nine months ended September 30, 2011, compared to the same period in 2010. This difference was primarily a result of the following:

•

Repayment of long-term debt. An increase in cash used of $1.333 billion for repayment of long-term debt. See note 4 to our interim financial statements; and

•

Redemption of preferred stock. A decrease in cash provided of $95 million related to the redemption of Series A preferred stock held by GenOn Mid-Atlantic in 2010. There were no redemptions during the nine months ended September 30, 2011.

~~ITEM~~The 2.increase ~~MANAGEMENT’S~~in ~~DISCUSSION~~cash ~~AND~~used ~~ANALYSIS~~and OFdecrease ~~FINANCIAL~~in ~~CONDITION~~cash ~~AND~~provided ~~RESULTS~~by OFfinancing ~~OPERATIONS~~activities were partially offset by the following:

•

Capital contributions. An increase in cash provided of $474 million related to contributions made by our member;

•

Intercompany debt. An increase in cash provided of $34 million related to proceeds received from intercompany debt; and

•

Distributions to member. A decrease in cash used of $9 million related to distributions to our member.

Recently Adopted Accounting Guidance

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

ITEM 2.

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

B. GenOn Mid-Atlantic

This section is intended to provide the reader with information that will assist in understanding 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 Mid-Atlantic’s interim financial statements and its 2010 Annual Report on Form 10-K. 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.

Overview

With approximately 5,204 MW of net electric generating capacity in the PJM market, we operate across various fuel (natural gas, coal and oil) and technology types, and operating characteristics. We provide energy, capacity, ancillary and other energy services to wholesale customers in the PJM market. GenOn Americas Generation’s commercial operations provides us with services that consist primarily of dispatching electricity, hedging the generation and sale of electricity, procuring and managing fuel and providing logistical support for the operation of our facilities (e.g., by procuring transportation for coal and natural gas).

Merger of Mirant and RRI Energy

Refer to “Merger of Mirant and RRI Energy” above for GenOn Americas Generation.

Hedging Activities

We hedge economically a substantial portion of our PJM coal-fired baseload 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. Although some of our hedges are executed through our affiliate, GenOn Energy Management, a majority of our hedges are financial swap transactions with financial counterparties that are senior unsecured obligations of such parties and do not require either party to post cash collateral either for initial margin or for securing exposure as a result of changes in power or natural gas prices. At ~~July~~October 1231, 2011, our aggregate hedge levels increased in part based on expected reduced generation ~~without~~ considering the effects of the CSAPR and were as follows:

		September 30,			September 30,			September 30,			September 30,			September 30,
	2011(1)			2012			2013			2014			2015
	2012			2013			2014			2015			2016
Power		9187	%		8159	%		35	%		3327	%		2522	%
Fuel		9382	%		7357	%		505	%		—	%		—	%

~~(1)~~60 ~~Percentages represent the period from August through December 2011.~~

The Dodd-Frank Act, which was enacted in July 2010 in response to the global financial crisis, increases the regulation of transactions involving OTC derivative financial instruments. The statute provides that standardized swap transactions between dealers and large market participants will have to be cleared and traded on an exchange or electronic platform. Although the provisions and legislative history of the Dodd-Frank Act provide strong evidence that market participants, such as GenOn Mid-Atlantic, which utilize OTC derivative financial instruments to hedge commercial risks are not to be subject to these clearing and exchange-trading requirements, it is uncertain what the final implementing regulations will provide. The effect of the Dodd-Frank Act on our business depends in large measure on pending rulemaking proceedings of the CFTC, the SEC and the federal banking regulators. Under the Dodd-Frank Act, entities defined as “swap dealers” and “major swap participants” (SD/MSPs) will face costly requirements for clearing and posting margin, as well as additional requirements for reporting and business conduct. The CFTC and SEC issued a proposed rulemaking to set final definitions for the terms “swap dealer” and “major swap participant” among others. Although we do not expect our hedging activity to result in our designation as an SD/MSP, as proposed, the “swap dealer” definition in particular is ambiguous, subjective and could be broad enough to encompass some energy companies. In addition, the CFTC and federal banking regulators, who will regulate bank SD/MSPs, separately issued proposed rules to establish capital and margin requirements for SD/MSPs and swap counterparties. While end-user counterparties who are using a swap to hedge or mitigate commercial risk would be generally exempt from mandatory margin requirements under the CFTC’s proposal applicable to non-bank SD/MSPs, they would have to post cash margin to bank SD/MSPs if they exceed exposure thresholds under the federal banking regulators’ proposal. The federal banking regulators’ rulemaking states that the credit support limit shall be determined by the bank SD/MSPs in accordance with their normal credit processes to set credit limits and to collect initial and variation margin. As proposed, the federal banking regulators’ rulemaking does not specify a procedure for determining such thresholds and a major question remains of the extent to which end-users and bank SD/MSPs will be free under the proposal to set their own thresholds to avoid the collection of margin from end-users. If applied to our hedging activity, such regulations could materially affect our ability to hedge economically our generation by significantly increasing the collateral costs associated with such activities. Furthermore, the CFTC and ~~prudential~~federal banking regulators’ proposed capital requirements for SD/~~MSP’s~~MSPs recommend significant and cash-dependent capital requirements for SD/MSPs. The cost of complying with these requirements may be passed through to and imposed on commercial end users indirectly and increase the cost of our hedging activities.

Moreover, the CFTC issued a proposal establishing recordkeeping and reporting requirements for swaps entered into before July 21, 2010, whose terms had not expired as of that date, and data relating to swaps entered into on or after July 21, 2010 and prior to the compliance date specified in the CFTC’s final swap data reporting rules. ~~Whilst~~Additionally, ~~GenOn~~in July 2011, the CFTC adopted final large trader reporting rules for physical commodity swaps and swaptions. Although GenOn Mid-Atlantic will have increased reporting and recordkeeping requirements under both proposals, we do not expect the proposed requirements to have a material effect on our hedging activities.

In terms of the timing for the release and implementation of the rules established by Dodd-Frank, in July 2011, the CFTC ~~recently~~ issued an ~~Order~~order clarifying the effective date of the provisions in the swap regulatory regime as the CFTC continues to implement rules. The ~~Order~~order provides temporary relief from certain provisions that would otherwise apply to swaps or swap dealers and that would have become effective as of July 16, 2011, until the CFTC completes the rulemakings specified in the ~~Order~~order. This ~~Order~~order is temporary, and it will expire upon the earlier of the effective date of final rules or December 31, 2011. In an open meeting in September 2011, Chairman Gensler indicated that the CFTC will not meet the extended deadline of December 31, 2011. The CFTC subsequently published an outline indicating that they may consider final rules in 2011 including entity and product definitions, position limits, the end-user exemption, and recording and reporting rules. The outline also indicated that the CFTC may consider final rules during the first quarter of 2012 including capital and margin requirements, client clearing documentation and risk management and internal business conduct rules. The CFTC indicated that the outline provided was subject to change and that the dates and order in which the CFTC finalizes its Dodd-Frank rulemaking could differ substantially from those provided in the outline. In the meantime, the CFTC has proposed an amendment extending the exemptive relief to July 16, 2012, or until a date the CFTC may otherwise determine with respect to a particular requirement under the Commodity Exchange Act.

~~Capital~~61 ~~Expenditures and Capital Resources~~

During the six months ended June 30, 2011, we invested $43 million for capital expenditures, primarily related to maintenance capital expenditures. At June 30, 2011, we have invested $1.521 billion of the $1.674 billion that was budgeted for capital expenditures related to compliance with the Maryland Healthy Air Act. Provisions in the construction contracts for the scrubbers at three of our largest Maryland coal-fired units provide for certain payments to be made after final completion of the projects. The current budget of $1.674 billion continues to represent our best estimate of the total capital expenditures for compliance with the Maryland Healthy Air Act. See note 8 to our interim financial statements for further discussion of the scrubber contract litigation.

In addition, in September 2011, the CFTC proposed swaps compliance and implementation schedules for mandatory clearing and trading, trading documentation and uncleared margin. The ~~following~~CFTC’s ~~table~~notice ~~details~~of proposed rulemaking would give the ~~expected~~CFTC ~~timing~~discretion to phase in implementation of ~~payments~~any clearing mandate for ~~our~~90, ~~estimated~~180 ~~capital~~or 270 days, ~~expenditures~~depending on the types of entities that are party to the relevant swap. The trigger for the ~~remainder~~implementation phase-in period would be the issuance of ~~2011~~a clearing mandate by the CFTC. The CFTC also issued a further notice of proposed rulemaking with respect to margin and ~~2012:~~documentation requirements that would establish implementation schedules of 90, 180 or 270 days, depending on the types of entities involved. The CFTC has proposed, but not yet adopted, regulations implementing both of these provisions. As the entity and product definitions have not been finalized, we cannot fully assess the impact of these proposals.

		September 30,		September 30,
	July 1, 2011throughDecember 31, 2011		2012
	(in millions)
Maryland Healthy Air Act	$	153	$	—
Other environmental		—		10
Maintenance		15		36
Other construction		37		7
Total	$	205	$	53

Capital Expenditures and Capital Resources

During the nine months ended September 30, 2011, we invested $126 million for capital expenditures. Capital expenditures for the period primarily relate to maintenance capital expenditures and include the $68 million payment to Stone & Webster for substantial completion of the scrubber projects. At September 30, 2011, we have invested $1.59 billion of the $1.674 billion that was budgeted for capital expenditures related to compliance with the Maryland Healthy Air Act. Provisions in the construction contracts for the scrubbers at three of our largest Maryland coal-fired units provide for certain payments to be made after final completion of the projects. The current budget of $1.674 billion continues to represent our best estimate of the total capital expenditures for compliance with the Maryland Healthy Air Act. See note 9 to our interim financial statements for further discussion of the scrubber contract litigation.

The following table details the expected timing of payments for our estimated capital expenditures for the remainder of 2011, 2012 and 2013:

		September 30,		September 30,		September 30,
	October 1, 2011 through December 31, 2011		2012		2013
	(in millions)

Maryland Healthy Air Act	$	84	$	—	$	—
Other environmental		—		5		5
Maintenance		9		34		49
Other construction		21		8		—
Other		—		—		—

Total	$	114	$	47	$	54

Environmental Matters

Refer to “Environmental Matters” above for GenOn Americas Generation.

Potomac River Retirement

Refer to “Potomac River Retirement” above for GenOn Americas Generation.

Commodity Prices

Refer to “Commodity Prices” above for GenOn Americas Generation.

Results of Operations

Non-GAAP Performance Measures. Refer to “Non-GAAP Performance Measures” above for GenOn Americas Generation.

58Three Months Ended September 30, 2011 Compared to Three Months Ended September 30, 2010

Three Months Ended June 30, 2011 Compared to Three Months Ended June 30, 2010

Consolidated Financial Performance

We reported a net ~~losses~~loss of $769 million and net income of $~~233~~319 million during the three months ended ~~June~~September 30, 2011 and 2010, respectively. The change in net income/loss is detailed as follows:

		September 30,			September 30,			September 30,
	Three Months EndedJune 30,						Increase/(Decrease)
	Three Months EndedSeptember 30,						Increase/
	2011			2010			(Decrease)
	(in millions)			~~(in millions)~~
Gross margin:
Energy	$	4763		$	78151		$	(3188	)
Contracted and capacity		6654			8583			(1929	)
Realized value of hedges		6649			7458			(89	)
Total realized gross margin		179			237			(58	)
Realized gross margin		166			292			(126	)
Unrealized gross margin		(12	)		~~(317~~179	)		~~305~~(191	)
Total gross margin (excluding depreciation and amortization)		~~167~~154			~~(80~~471	)		~~247~~(317	)
Operating expenses:
Operations and maintenance		~~101~~53			7065			31(12	)
Operations and maintenance—affiliate		4243			4751			(58	)
Depreciation and amortization		30			36			(6	)
Gain on sales of assets, net—affiliate		—			(1	)		1
Impairment losses		94			—			94
Total operating expenses		~~173~~220			152			2168
Operating loss		(6	)		(232	)		226
Operating income (loss)		(66	)		319			(385	)
Other income (expense), net:
Interest expense, net		(1—	)		—(1	)		(1	)
Other, net		—			(1	)		(1	)
Interest expense, net—affiliate		(3	)		—			3
Total other expense, net		(13	)		(1	)		—2
Net loss	$	(7	)	$	(233	)	$	226
Income (loss) before income taxes		(69	)		318			(387	)
Benefit for income taxes		—			(1	)		1
Net income (loss)	$	(69	)	$	319		$	(388	)

Realized Gross Margin. ~~During~~Our ~~the~~realized ~~three~~gross ~~months~~margin ~~ended~~consists ~~June 30,~~of ~~2011~~energy, ~~our~~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 ~~decrease~~sold in the PJM market. Realized value of ~~$58~~hedges ~~million~~represents ~~was~~the ~~principally~~actual amargin ~~result~~upon the settlement of our power and fuel hedging contracts and the ~~following:~~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.

•63 a decrease of $31 million in energy, primarily as a result of a decrease in generation volumes as a result of increased outages at certain of our coal-fired baseload units, an increase in production costs at our Dickerson generating facility as a result of the CO2 levy and contracting off-peak dark spreads;

• a decrease of $19 million in contracted and capacity primarily as a result of a decrease in capacity prices, offset in part by an increase in capacity volumes; and

• a decrease of $8 million in realized value of hedges primarily as a result of a decrease in our power hedges resulting from prices, offset in part by an increase in our coal hedges primarily resulting from prices.

Realized Gross Margin. During the three months ended September 30, 2011, our realized gross margin decrease of $126 million was principally a result of the following:

•

a decrease of $88 million in energy, primarily as a result of a decrease in generation volumes as a result of contracting dark spreads and spark spreads;

•

a decrease of $29 million in contracted and capacity primarily as a result of a $24 million decrease from lower capacity prices and a $4 million decrease from ancillary services; and

•

a decrease of $9 million in realized value of hedges, primarily as a result of a $10 million decrease in power hedges resulting from prices and volumes hedged, partially offset by a $1 million increase in our coal hedges resulting from prices.

• unrealized losses of $12 million during the three months ended ~~June~~September 30, 2011, which included $6041 million associated with the reversal of previously recognized unrealized gains from power and fuel contracts that settled during the period, offset by a $4829 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 an increase in forward coal prices~~; and

• unrealized ~~losses~~gains of $~~317~~179 million during the three months ended ~~June~~September 30, 2010, which included a $~~203~~228 million net ~~decrease~~increase in the value of hedge contracts for future periods primarily related to ~~increases~~decreases in forward power ~~prices~~ and ~~the~~natural ~~recognition~~gas ofprices ~~many~~and ofincreases ~~our~~in forward coal ~~agreements~~prices, atpartially ~~fair~~offset ~~value~~by ~~beginning~~unrealized inlosses ~~the second quarter~~ of ~~2010. The~~ $~~317~~49 million ~~also included $114 million~~ associated with the reversal of previously recognized unrealized gains from power and fuel contracts that settled during the period.

Operating Expenses. Our operating expenses increase of $2168 million was principally a result of the following:

• an increase of $2694 million in ~~operations~~impairment ~~and~~losses ~~maintenance~~for ~~expense~~the ~~primarily~~write-off ~~as a result~~ of aexcess ~~$30~~NOx ~~million~~and ~~accrual~~SO2 ~~for~~emissions ~~remediation~~allowances ~~costs~~included atin ~~our~~intangible ~~Maryland~~assets ~~ash facilities~~ (~~which includes a tentative~~ $~~1.9~~57 million ~~civil penalty~~), ~~litigation~~and ~~costs~~the ~~for~~write-off ~~major project disputes, net~~ of ~~recoveries~~excess NOx and anSO2 ~~increase~~emissions inallowances ~~outage~~previously ~~expenses.~~included ~~The increase~~ in ~~operations~~property, plant and ~~maintenance~~equipment ~~expense was partially offset by a decrease of~~ ($1237 million) asduring ~~a result of~~ the ~~repeal~~three ofmonths ~~the~~ended ~~Montgomery~~September ~~County CO2 levy~~30, ~~including $8 million related to refund received in the third quarter of~~ 2011 ~~of CO2 levies paid in 2010 and a decrease in allocated overhead costs~~ as a result of ~~a change in~~ the ~~allocation methodology as a result of the Merger~~CSAPR; offset in part by

• a decrease of $620 million in ~~depreciation~~operations and ~~amortization~~maintenance expense ~~primarily~~was asprincipally a result of (a) ~~reduction~~a $6 million decrease resulting from changes in ~~the~~asset ~~carrying~~retirement ~~value~~obligation ofassumptions, ~~the~~(b) ~~Dickerson~~a ~~and~~change ~~Potomac~~in ~~River~~the ~~generating~~allocation ~~facilities~~methodology for overhead costs as a result of ~~impairment~~the ~~losses~~Merger, ~~taken~~(c) in$4 ~~the~~million ~~fourth~~as ~~quarter~~a result of ~~2010~~the repeal of the Montgomery County CO2 levy, and (d) other cost reductions. These decreases were partially offset by $5 million of major litigation costs, net of recoveries; and

•

a decrease of $6 million in depreciation and amortization expense primarily as a result of a reduction in the carrying value of the Dickerson and Potomac River generating facilities as a result of impairment losses in the fourth quarter of 2010.

Operating Statistics

Our power generation volumes during the three months ended ~~June~~September 30, 2011 (in gigawatt hours) was 23,~~883~~537 compared to 34,~~403~~914 during the same period in 2010. See “Operating Statistics” in “Results of Operations—GenOn Americas Generation” above for additional details on power generation volumes.

6064

~~Six~~Nine Months Ended ~~June~~September 30, 2011 Compared to ~~Six~~Nine Months Ended ~~June~~September 30, 2010

Consolidated Financial Performance

We reported a net ~~income~~loss of $2445 million and net income of $~~206~~525 million during the ~~six~~nine months ended ~~June~~September 30, 2011 and 2010, respectively. The change in net income/loss is detailed as follows:

		September 30,			September 30,			September 30,
	Six Months EndedJune 30,						Increase/(Decrease)
	Nine Months EndedSeptember 30,						Increase/(Decrease)
	2011			2010
	(in millions)
Gross margin:
Energy	$	~~108~~171		$	~~170~~321		$	(62150	)
Contracted and capacity		~~143~~197			~~174~~257			(3160	)
Realized value of hedges		~~129~~178			~~131~~189			(211	)
Total realized gross margin		380			475			(95	)
Realized gross margin		546			767			(221	)
Unrealized gross margin		(5163	)		29208			(80271	)
Total gross margin (excluding depreciation and amortization)		~~329~~483			~~504~~975			(~~175~~492	)
Operating expenses:
Operations and maintenance		~~163~~216			~~135~~200			2816
Operations and maintenance—affiliate		82125			95146			(1321	)
Depreciation and amortization		5989			69105			(1016	)
Impairment losses		94			—			94
Gain on sales of assets, net—affiliate		—			(3	)		3
Total operating expenses		~~304~~524			~~296~~448			876
Operating income		25			208			(183	)
Operating income (loss)		(41	)		527			(568	)
Other income (expense), net:
Interest expense, net		(1	)		(12	)		—(1	)
Interest expense, net—affiliate		(3	)		—			3
Other, net		—			(1	)		(1	)
Total other expense, net		(14	)		(23	)		(1	)
Net income	$	24		$	206		$	(182	)
Income (loss) before income taxes		(45	)		524			(569	)
Benefit for income taxes		—			(1	)		1
Net income (loss)	$	(45	)	$	525		$	(570	)

Realized Gross Margin. ~~During~~Our ~~the~~realized ~~six~~gross ~~months~~margin ~~ended~~consists ~~June 30,~~of ~~2011~~energy, ~~our~~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 ~~decrease~~sold in the PJM market. Realized value of ~~$95~~hedges ~~million~~represents ~~was~~the ~~principally~~actual amargin ~~result~~upon the settlement of our power and fuel hedging contracts and the ~~following:~~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.

•Realized aGross ~~decrease~~Margin. ofDuring ~~$62~~the ~~million~~nine inmonths ~~energy~~ended September 30, ~~primarily~~2011, asour arealized ~~result~~gross ofmargin a decrease ~~in generation volumes as a result~~ of ~~contracting~~$221 ~~dark~~million ~~spreads~~was ~~and~~principally ~~an increase in production costs at our Dickerson generating facility as~~ a result of the ~~CO2~~following: ~~levy;~~

• a decrease of $31150 million in ~~contracted~~energy ~~and capacity~~ primarily as a result of a decrease in ~~capacity~~generation ~~prices,~~volumes ~~offset~~as ina ~~part~~result byof ancontracting ~~increase~~dark inspreads ~~capacity~~and ~~volumes;~~spark ~~and~~spreads;

• a decrease of $260 million in ~~realized~~contracted ~~value~~and ofcapacity ~~hedges primarily~~ as a result of a ~~decrease~~$53 inmillion ~~our~~decrease ~~power~~from ~~hedges~~lower ~~resulting~~capacity ~~from~~ prices, ~~offset~~and ina ~~part~~$7 bymillion andecrease ~~increase~~from inancillary ~~our~~services; ~~coal hedges primarily resulting from prices.~~and

~~Unrealized~~65 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 $51 million during the six months ended June 30, 2011, which included $114 million associated with the reversal of previously recognized unrealized gains from power and fuel contracts that settled during the period, offset by a $63 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; and

• ~~unrealized~~a ~~gains~~decrease of $2911 million ~~during~~in ~~the~~realized ~~six~~value ~~months~~of ~~ended~~hedges, ~~June~~primarily ~~30,~~as ~~2010,~~a ~~which~~result ~~included~~of a $~~193~~45 million ~~net~~decrease ~~increase~~ in ~~the~~power ~~value~~hedges ~~of hedge contracts for future periods~~ primarily ~~related~~resulting tofrom ~~decreases in forward power and natural gas~~ prices, ~~and~~offset ~~also included the recognition of many of our coal agreements at fair value beginning~~ in ~~the~~part ~~second~~by ~~quarter~~a of$34 ~~2010.~~million ~~The~~ increase in ~~value~~our ~~was~~coal ~~partially~~hedges ~~offset~~resulting ~~by $164 million associated with the reversal of previously recognized unrealized gains~~ from ~~power and fuel contracts that settled during the period~~prices.

~~Operating~~Unrealized ~~Expenses~~Gross Margin. ~~Our~~Unrealized ~~operating~~gross ~~expenses~~margin ~~increase~~represents ofthe $8net ~~million~~unrealized ~~was~~gain ~~principally~~or aloss ~~result~~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:

• anunrealized ~~increase~~losses of $1563 million induring ~~operations~~the ~~and~~nine ~~maintenance~~months ~~expense~~ended ~~primarily~~September ~~as a result of a $~~30, ~~million~~2011, ~~accrual for remediation costs at our Maryland generating facilities (~~which ~~includes~~included ~~a tentative~~ $~~1.9~~155 million ~~civil~~associated ~~penalty)~~with ~~and~~the ~~litigation~~reversal ~~costs~~of ~~for~~previously ~~major~~recognized ~~project~~unrealized ~~disputes,~~gains ~~net~~from ofpower ~~recoveries.~~and ~~The~~fuel ~~increase~~contracts inthat ~~operations~~settled ~~and~~during ~~maintenance~~the ~~expense~~period, ~~is partially~~ offset by a ~~decrease of~~ $1092 million asnet aincrease ~~result~~in of the ~~repeal~~value of ~~the~~hedge ~~Montgomery~~contracts ~~County~~for ~~CO2~~future ~~levy,~~periods ~~including~~primarily ~~$8 million~~ related to ~~refund~~decreases ~~received~~ in ~~the~~forward ~~third~~power ~~quarter~~and ofnatural ~~2011~~gas ofprices ~~CO2 levies paid in 2010, a reduction in outage expense~~ and aincreases ~~decrease~~ in ~~allocated~~forward ~~overhead~~coal ~~costs as a result of a change in the allocation methodology as a result of the Merger~~prices; and

• aunrealized ~~decrease~~gains of $3208 million induring ~~gain~~the onnine ~~sales~~months ended September 30, 2010, which included a $421 million net increase in the value of ~~assets~~hedge contracts for future periods primarily related to ~~emissions~~decreases ~~allowances~~in ~~sold~~forward topower ~~third~~and ~~parties~~natural ingas ~~2010;~~prices offset in part by the recognition of many of our coal agreements at fair value beginning in the second quarter of 2010. The increase in value was further offset by $213 million associated with the reversal of previously recognized unrealized gains from power and fuel contracts that settled during the period.

•Operating aExpenses. ~~decrease~~Our ofoperating ~~$10~~expenses ~~million~~increase ~~in depreciation and amortization expense primarily as a result~~ of a$76 ~~reduction~~million inwas ~~the~~principally ~~carrying value of the Dickerson and Potomac River generating facilities as~~ a result of ~~impairment losses taken in~~ the ~~fourth~~following: ~~quarter of 2010.~~

•

an increase of $ 94 million in impairment losses for the write-off of excess NO_x and SO₂emissions allowances included in intangible assets ($57 million) and the write-off of excess NO_xand SO₂emissions allowances previously included in property, plant and equipment ($37 million) during the three months ended September 30, 2011 as a result of the CSAPR; offset in part by

•

a decrease of $16 million in depreciation and amortization expense primarily as a result of a reduction in the carrying value of the Dickerson and Potomac River generating facilities as a result of impairment losses in the fourth quarter of 2010; and

•

a decrease of $5 million in operations and maintenance expense primarily as a result of (a) $14 million as a result of the repeal of the Montgomery County CO₂ levy, including $8 million related to a refund received in the third quarter of 2011 of CO₂ levies paid in 2010, (b) a change in the allocation methodology for overhead costs as a result of the Merger, (c) a $6 million decrease resulting from changes in asset retirement obligation assumptions, (d) decreased variable operations and maintenance expense and (e) decreased outage expense. These decreases were partially offset by a $30 million accrual for remediation costs at our Maryland ash facilities (which includes a tentative $1.9 million civil penalty) and $12 million of major litigation costs, net of recoveries.

Operating Statistics

Our power generation volumes during the ~~six~~nine months ended ~~June~~September 30, 2011 (in gigawatt hours) was 69,~~429~~ 966 compared to 712,~~436~~350 during the same period in 2010. See “Operating Statistics” in “Results of Operations—GenOn Americas Generation” above for additional details on power generation volumes.

Financial Condition

Liquidity and Capital Resources

Management thinks that our liquidity position and cash flows from operations will be adequate to fund operating, maintenance and capital expenditures, and to service our operating leases and to meet other liquidity requirements. Management regularly monitors our ability to fund our operating, financing and investing activities.

~~Sources~~66 ~~of Funds~~

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, capital contributions or advances from GenOn North America and (c) at its discretion, letters of credit issued or borrowings made under GenOn’s senior secured revolving credit facility.

We consider all short-term investments with an original maturity of three months or less to be cash equivalents. At June 30, 2011, 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.

At June 30, 2011, we had $53 million of cash, which amount was available under the operating leases for distribution to GenOn North America.

~~the~~Sources ~~performance~~ of ~~our~~Funds ~~power generating facilities, including interruptions in operations or curtailment of operations to comply with environmental restrictions.~~

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, 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).

At September 30, 2011, we had $84 million of cash, which amount was available under the operating leases for distribution to GenOn North America.

Under the operating leases, we are subject to a covenant that restricts our right to make distributions. Our ability to satisfy the criteria set by that covenant in the future could be impaired by factors which negatively affect the performance of our power generating facilities, including interruptions in operations or curtailment of operations to comply with environmental restrictions.

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 capital expenditures and payments under our operating leases.

Capital Expenditures. Our capital expenditures during the ~~six~~nine months ended ~~June~~September 30, 2011, were $43126 million. We estimate our capital expenditures for the period ~~July~~October 1, 2011 through December 31, ~~2012~~2013 will be $~~258~~215 million. See “Capital Expenditures and Capital Resources” for further discussion of our capital expenditures.

Operating Leases. We lease 100% interests in both the Dickerson and Morgantown baseload units and associated property through 2029 and 2034, respectively, and have an option to extend the leases. Any extensions of the respective leases would be for less than 75% of the economic useful life of the facility, as measured from the beginning of the original lease term through the end of the proposed remaining lease term. We are accounting for these leases as operating leases. Although there is variability in the scheduled payment amounts over the lease term, we recognize rent expense for these leases on a straight-line basis in accordance with GAAP. Rent expense under our leases was $24 million and $4872 million for both the three and ~~six~~nine months ended ~~June~~September 30, 2011 and 2010, respectively.

MF Global Credit Risk. As noted above, GenOn Energy Management enters into hedge transactions for our benefit pursuant to intercompany arrangements, including transactions executed through MF Global Inc. See “Liquidity and Capital Resources—Cash Collateral and Letters of Credit” for GenOn Americas Generation above for a discussion of the pending liquidation of MF Global Inc. As of October 31, 2011, GenOn Energy Management had $2 million in its accounts with MF Global Inc. for our benefit. In the event that GenOn Energy Management is unable to recover cash collateral posted in connection with transactions for our benefit, we are required to reimburse GenOn Energy Management under the terms of our intercompany arrangements.

Debt Obligations, Off-Balance Sheet Arrangements and Contractual Obligations

Historical Cash Flows

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 decreased $92200 million for the ~~six~~nine months ended ~~June~~September 30, 2011, compared to the same period in 2010, primarily as a result of the following:

• Realized gross margin. A decrease in cash provided of $~~107~~233 million in 2011, compared to the same period in 2010, excluding a decrease in non-cash lower of cost or market fuel inventory adjustment of $12 million. See “Results of Operations” in Item 2 for additional discussion of our performance in 2011 as compared to the same period in 2010; and

• Inventories. An increase in cash used of $2032 million primarily as a result of larger volumes of coal purchased, atoffset ~~higher~~by lower average prices in 2011 as compared to 2010.

The decrease in cash provided and increase in cash used by operating activities was partially offset by the following:

• Net accounts receivables and accounts payables. An increase in cash provided of $1961 million primarily related to a decrease in power prices and generation volumes in 2011 compared to the same period in 2010; and

• Other operating assets and liabilities. A decrease in cash used of $156 million related to changes in other operating assets and liabilities compared to the same period in 2010.

63Investing Activities. Net cash used in investing activities increased by $101 million for the nine months ended September 30, 2011, compared to the same period in 2010. This difference was primarily a result of the following:

•

Restricted funds on deposit, net. A net decrease in cash provided of $166 million primarily related to $234 million placed in restricted deposits as a result of our scrubber contract litigation and related liens, partially offset by $68 million primarily related to the withdrawal of cash used to reduce the outstanding lien amounts in accordance with our scrubber contract litigation. See note 9 to our interim financial statements; and

•

Proceeds from sale of assets. A decrease in cash provided of $3 million primarily related to the sale of emissions allowances in 2010; partially offset by

•

Capital expenditures. A decrease in cash used of $68 million primarily as a result of payments related to our Maryland scrubber projects.

Financing Activities. Net cash used in financing activities decreased by $35 million for the nine months ended September 30, 2011, compared to the same period in 2010. This difference was primarily a result of the following:

•

Distributions to member. A decrease in cash used of $100 million related to distributions to our member. In 2011, we distributed $100 million compared to $200 million distributed in 2010; and

•

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Filing Compare · GENON MID-ATLANTIC, LLC