UNITED STATES ~~SECURITIES~~ ~~AND EXCHANGE COMMISSION~~

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 ~~March~~June 3130, 2011

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

For the transition period from to

Commission File Number: 333-63240

GenOn Americas Generation, LLC

(Exact Name of Registrant as Specified in Its Charter)

51-0390520 ~~(I.R.S.~~ ~~Employer Identification No.)~~

(I.R.S. Employer

Identification No.)

Commission File Number: 333-61668

GenOn Mid-Atlantic, LLC

(Exact Name of Registrant as Specified in Its Charter)

Delaware (State or Other Jurisdiction of Incorporation or Organization)		58-2574140 (I.R.S. Employer Identification No.)
1000 Main Street,		77002
Houston, Texas (Address of Principal Executive Offices)		(Zip Code)

58-2574140

(~~832) 357-3000 (Registrant’s~~I.R.S. ~~Telephone~~Employer ~~Number, Including Area Code)~~

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 o¨ Yes o¨ No GenOn Mid-Atlantic, LLC o¨ Yes o¨ No

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

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

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

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

	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	¨

(Do not check if a smaller reporting company)

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

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

	Page
Glossary of Certain Defined Terms		ii
Cautionary Statement Regarding Forward-Looking Information	v
PART I FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS:
GenOn Americas Generation, LLC
Condensed Consolidated Statements of Operations (Unaudited) Three Months Ended March 31, 2011 and 2010		1
Condensed Consolidated Balance Sheets March 31, 2011 (Unaudited) and December 31, 2010		2
Condensed Consolidated Statements of Member’s Equity (Unaudited) Three Months Ended March 31, 2011		3
Condensed Consolidated Statements of Cash Flows (Unaudited) Three Months Ended March 31, 2011 and 2010		4
GenOn Mid-Atlantic, LLC
Condensed Consolidated Statements of Operations (Unaudited) Three Months Ended March 31, 2011 and 2010		5
Condensed Consolidated Balance Sheets March 31, 2011 (Unaudited) and December 31, 2010		6
Condensed Consolidated Statements of Member’s Equity (Unaudited) Three Months Ended March 31, 2011		7
Condensed Consolidated Statements of Cash Flows (Unaudited) Three Months Ended March 31, 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:
GenOn Americas Generation, LLC
Overview		37
Merger of Mirant and RRI Energy		37
Hedging Activities		37
Capital Expenditures and Capital Resources		38
Environmental Matters		39
Potrero Shutdown		40
Commodity Prices		40
Results of Operations		40
Operating Statistics		43
Financial Condition		44
Historical Cash Flows		46
GenOn Mid-Atlantic, LLC
Overview		48
Merger of Mirant and RRI Energy		48
Hedging Activities		48
Capital Expenditures and Capital Resources		49
Environmental Matters		49
Commodity Prices		50
Results of Operations		50
Operating Statistics		51
Financial Condition		51
Historical Cash Flows		52
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		54
Item 4. CONTROLS AND PROCEDURES		54
PART II
Item 1. LEGAL PROCEEDINGS		55
Item 1A. RISK FACTORS		55
Item 6. EXHIBITS:
GenOn Americas Generation, LLC		55
GenOn Mid-Atlantic, LLC		56
Exhibit 31.1A1
Exhibit 31.1A2
Exhibit 31.2A3
Exhibit 31.2A4
Exhibit 32.1A1
Exhibit 32.1A2
Exhibit 32.2A3
Exhibit 32.2A4


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

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

Glossary of Certain Defined Terms


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

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.
Clean Water Act		Federal Water Pollution Control Act.
CO2		Carbon dioxide.
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.
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 MD Ash Management		GenOn MD Ash Management, LLC (formerly known as Mirant MD Ash Management, 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.
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.
PJM		PJM Interconnection, LLC.

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.

iii

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 Holdings		GenOn Energy Holdings, Inc. (formerly known as Mirant Corporation) and, except where the context indicates otherwise, its subsidiaries.
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.
GenOn Energy Management		GenOn Energy Management, LLC (formerly known as Mirant Energy Trading, LLC).
PPA		Power purchase agreement.
GenOn Energy Services		GenOn Energy Services, LLC (formerly known as Mirant Services, LLC).
RGGI		Regional Greenhouse Gas Initiative.
GenOn Kendall		GenOn Kendall, LLC (formerly known as Mirant Kendall, LLC).
RMR		Reliability-must-run.
GenOn Marsh Landing		GenOn Marsh Landing, LLC (formerly known as Mirant Marsh Landing, LLC).
RPM		Model utilized by PJM to meet load serving entities’ forecasted capacity obligations through a forward-looking commitment of capacity resources.
GenOn Mid-Atlantic		GenOn Mid-Atlantic, LLC (formerly known as Mirant Mid-Atlantic, LLC) and, except where the context indicates otherwise, its subsidiaries.
RRI Energy		RRI Energy, Inc., which changed its name to GenOn Energy, Inc. in connection with the Merger.
GenOn North America		GenOn North America, LLC (formerly known as Mirant North America, LLC).
RTO		Regional Transmission Organization.
GenOn Potomac River		GenOn Potomac River, LLC (formerly known as Mirant Potomac River, LLC).
scrubbers		Flue gas desulfurization emissions controls.
HAP		Hazardous Air Pollutant.
SEC		United States Securities and Exchange Commission.
Hudson Valley Gas		Hudson Valley Gas Corporation.
Securities Act		Securities Act of 1933, as amended.
intermediate generating units		Units designed to satisfy system requirements that are greater than baseload and less than peaking.
SO2		Sulfur dioxide.
ISO		Independent system operator.
Stone & Webster		Stone & Webster, Inc.
ISO-NE		Independent System Operator-New England.
Transport Rule		The EPA’s Proposed Federal Implementation Plan To Reduce Interstate Transport of Fine Particulate Matter and Ozone, which would replace the CAIR.
LIBOR		London InterBank Offered Rate.
Virginia DEQ		Virginia Department of Environmental Quality.
MDE		Maryland Department of the Environment.
WCI		Western Climate Initiative.
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.



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.

RPM		Model utilized by PJM to meet load serving entities’ forecasted capacity obligations through a forward-looking commitment of capacity resources.

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.

Stone & Webster		Stone & Webster, Inc.

Virginia DEQ		Virginia Department of Environmental Quality.

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 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;

•

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 ~~our~~changes ~~accounting~~in ~~for~~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;

•

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 and Analysis of Financial Condition and Results of Operations” 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 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.

~~vii~~viii

PART I ~~FINANCIAL~~ ~~INFORMATION~~

FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

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

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

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

	Three Months
		September 30,			September 30,			September 30,			September 30,
	Ended March 31,
	Three Months EndedJune 30,						Six Months EndedJune 30,
	2011			2010			2011			2010
	(in millions)
Operating revenues—nonaffiliate (including unrealized gains (losses) of $(95) million and $363 million, respectively)	$	538		$	880
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—affiliate (including unrealized gains of $10 million and $0, respectively)		11			—
Operating revenues—affiliate (including unrealized gains (losses) of $(2) million, $0, $8 million and $0, respectively)		2			—			13			—
Total operating revenues		~~549~~717			~~880~~244			1,266			1,124
Cost of fuel, electricity and other products—nonaffiliate (including unrealized (gains) losses of $(14) million and $11 million, respectively)		165			204
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—affiliate (including unrealized (gains) losses of $0 and $0, respectively)		170			3
Cost of fuel, electricity and other products—affiliate (including unrealized (gains) losses of $0, $0, $0 and $0, respectively)		330			1			500			4
Total cost of fuel, electricity and other products		~~335~~468			~~207~~272			803			479
Gross Margin (excluding depreciation and amortization)		~~214~~249			~~673~~(28	)		463			645
Operating Expenses:
Operations and maintenance—nonaffiliate		79			89
Operations and maintenance		118			93			197			182
Operations and maintenance—affiliate		6059			7072			119			142
Depreciation and amortization		4042			4950			82			99
Gain on sales of assets, net		—			(2	)
(Gain) loss on sales of assets, net		1			(1	)		1			(3	)
Total operating expenses		~~179~~220			~~206~~214			399			420
Operating Income		35			467
Operating Income (Loss)		29			(242	)		64			225
Other Income (Expense), net:
Interest expense		(3021	)		(5049	)		(51	)		(99	)
Other, net		~~(23~~—	)		(1	)		(23	)		(2	)
Total other expense, net		(5321	)		(5150	)		(74	)		(101	)
Net Income (Loss)	$	~~(18~~8	)	$	~~416~~(292	)	$	(10	)	$	124

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.)~~

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

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	March 31,			December 31,
		September 30,			September 30,
	2011			2010
	June 30, 2011			December 31, 2010
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents	$	~~402~~279		$	514
Funds on deposit		~~259~~349			949
Receivables—nonaffiliate		222			363
Receivables		306			363
Receivables—affiliate		8542			4
Notes receivable—affiliate		~~122~~147			—
Derivative contract assets—nonaffiliate		915			1,288
Derivative contract assets		777			1,288
Derivative contract assets—affiliate		2039			5
Inventories		~~235~~239			295
Prepaid expenses and other current assets		~~113~~107			124
Total current assets		2,~~373~~285			3,542
Property, plant and equipment, gross		3,~~957~~976			3,946
Accumulated depreciation and amortization		(~~905~~940	)		(869	)
Property, Plant and Equipment, net		3,~~052~~036			3,077
Noncurrent Assets:
Intangible assets, net		9998			101
Derivative contract assets—nonaffiliate		593			689
Derivative contract assets		564			689
Derivative contract assets—affiliate		17			3
Prepaid rent		~~324~~398			348
Debt issuance costs, net		56			12
Other		4241			41
Total noncurrent assets		1,~~080~~124			1,194
Total Assets	$	6,~~505~~445		$	7,813
LIABILITIES AND MEMBER’S EQUITY
Current Liabilities:
Current Liabilities
Current portion of long-term debt	$	~~539~~4		$	1,389
Accounts payable and accrued liabilities		~~377~~440			527
Payable—affiliate		~~188~~282			4254
Notes payable—affiliate		824			—
Derivative contract liabilities—nonaffiliate		793			1,130
Derivative contract liabilities		662			1,130
Derivative contract liabilities—affiliate		1024			3
Other		13			8
Total current liabilities		1,~~928~~449			3,~~099~~111
Noncurrent Liabilities:
Long-term debt, net of current portion		~~865~~864			866
Derivative contract liabilities—nonaffiliate		128			173
Derivative contract liabilities		87			173
Derivative contract liabilities—affiliate		716			—
Other		91120			90
Total noncurrent liabilities		1,~~091~~087			1,129
Commitments and Contingencies
Member’s Equity:
Member’s interest		3,~~486~~909			3,~~585~~573
Total member’s equity		3,~~486~~909			3,~~585~~573
Total Liabilities and Member’s Equity	$	6,~~505~~445		$	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.)~~

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

CONDENSED CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY (UNAUDITED)

	Member’s
		September 30,
	Interest
	Member’sInterest
	(in millions)
Balance, December 31, 2010	$	3,~~585~~573
Net loss		(1810	)
Distribution to member		(100	)
Capital contributions		19446
Balance, March 31, 2011	$	3,486
Balance, June 30, 2011	$	3,909

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.)~~

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

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Three Months
		September 30,			September 30,
	Ended March 31,
	Six Months Ended June 30,
	2011			2010
	(in millions)
Cash Flows from Operating Activities:
Net income (loss)	$	(1810	)	$	~~416~~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		4182			51104
Gain on sales of assets, net		—			(2	)
(Gain) loss on sales of assets, net		1			(3	)
Net changes in derivative contracts		7170			(~~352~~12	)
Lower of cost or market inventory adjustments		—1			820
Loss on extinguishment of debt		23			—
Loss on early extinguishment of debt		23			—
Funds on deposit		(32120	)		~~(14~~7	)
Changes in other operating assets and liabilities		~~159~~218			~~210~~(87	)
Total adjustments		~~262~~275			~~(99~~29	)
Net cash provided by operating activities		~~244~~265			~~317~~153
Cash Flows from Investing Activities:
Capital expenditures		(2147	)		(83155	)
Proceeds from the sales of assets		4			23
Restricted funds on deposit, net		723			—
Issuance of notes receivable—affiliate		(~~122~~147	)		—
Net cash provided by (used in) investing activities		~~584~~533			(81152	)
Cash Flows from Financing Activities:
Repayments of long-term debt		(867	)		(67	)
Redemption of preferred stock		—			95
Issuance of notes payable—affiliate		8			—
Repayments of long-term debt		(1,403	)		(69	)
Issuance of notes payable—affiliate		26			—
Distribution to member		(100	)		—
Capital contributions		19444			—
Net cash used in financing activities		(940	)		(67	)
Net cash provided by (used in) financing activities		(1,033	)		26
Net Increase (Decrease) in Cash and Cash Equivalents		(~~112~~235	)		~~169~~27
Cash and Cash Equivalents, beginning of period		514			404
Cash and Cash Equivalents, end of period	$	~~402~~279		$	~~573~~431
Supplemental Disclosures:
Cash paid for interest, net of amounts capitalized	$	—59		$	292
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.)~~

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

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

	Three Months Ended March 31,
		September 30,			September 30,			September 30,			September 30,
	2011			2010
	Three Months EndedJune 30,						Six Months EndedJune 30,
	(in millions)
	2011			2010			2011			2010
Operating revenues—nonaffiliate (including unrealized gains (losses) of $(45) million and $200 million, respectively)	$	(1	)	$	258
	(in millions)
Operating revenues—affiliate (including unrealized gains (losses) of $(6) million and $138 million, respectively)		299			481
Operating revenues (including unrealized gains (losses) of $6 million, $(97) million, $(39) million and $103 million, respectively)	$	45		$	(39	)	$	44		$	219
Total operating revenues		298			739
Operating revenues—affiliate (including unrealized gains (losses) of $(33) million, $(108) million, $(39) million and $30 million, respectively)		235			209			534			690
Cost of fuel, electricity and other products—nonaffiliate (including unrealized (gains) losses of $0 and $0, respectively)		7			4
Total operating revenues		280			170			578			909
Cost of fuel, electricity and other products—affiliate (including unrealized gains of $(12) million and $(8) million, respectively)		129			151
Cost of fuel, electricity and other products (including unrealized (gains) losses of $0, $0, $0 and $0, respectively)		2			5			9			9
Total cost of fuel, electricity and other products		136			155
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
Gross Margin (excluding depreciation and amortization)		162			584
Total cost of fuel, electricity and other products		113			250			249			405
Operating Expenses:
Gross Margin (excluding depreciation and amortization)		167			(80	)		329			504
Operations and maintenance—nonaffiliate		62			65
Operating Expenses:
Operations and maintenance—affiliate		40			48
Operations and maintenance		101			70			163			135
Depreciation and amortization		29			33
Operations and maintenance—affiliate		42			47			82			95
Gain on sales of assets, net—affiliate		—			(2	)
Depreciation and amortization		30			36			59			69
Total operating expenses		131			144
Gain on sales of assets, net—affiliate		—			(1	)		—			(3	)
Operating Income		31			440
Total operating expenses		173			152			304			296
Other Income (Expense), net:
Operating Income (Loss)		(6	)		(232	)		25			208
Interest expense		—			(1	)
Other Income (Expense), net:
Total other expense, net		—			(1	)
Interest expense		(1	)		—			(1	)		(1	)
Net Income	$	31		$	439
Other, net		—			(1	)		—			(1	)
Total other expense, net		(1	)		(1	)		(1	)		(2	)
Net Income (Loss)	$	(7	)	$	(233	)	$	24		$	206

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.)~~

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

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

	March 31,			December 31,
		September 30,			September 30,
	2011			2010
	June 30,2011			December 31,2010
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents	$	~~131~~53		$	202
Funds on deposit		~~146~~147			2
Receivables—nonaffiliate		19			21
Receivables		23			21
Receivables—affiliate		~~140~~146			169
Derivative contract assets—nonaffiliate		158			162
Derivative contract assets		155			162
Derivative contract assets—affiliate		~~212~~136			245
Inventories		~~132~~152			122
Prepaid rent		96			96
Other		63			11
Total current assets		~~1,040~~911			1,030
Property, plant and equipment, gross		3,~~059~~079			3,046
Accumulated depreciation and amortization		(~~541~~567	)		(513	)
Property, Plant and Equipment, net		2,~~518~~512			2,533
Noncurrent Assets:
Intangible assets, net		71			71
Derivative contract assets—nonaffiliate		472			516
Derivative contract assets		474			516
Derivative contract assets—affiliate		6744			97
Prepaid rent		~~324~~398			348
Other		3029			31
Total noncurrent assets		~~964~~1,016			1,063
Total Assets	$	4,~~522~~439		$	4,626
LIABILITIES AND MEMBER’S EQUITY
Current Liabilities:
Current portion of long-term debt	$	4		$	4
Accounts payable and accrued liabilities		5664			63
Payable—affiliate		~~149~~129			~~106~~114
Derivative contract liabilities—nonaffiliate		15			18
Derivative contract liabilities		8			18
Derivative contract liabilities—affiliate		~~197~~135			231
Contract retention liability		130			132
Other		1215			8
Total current liabilities		~~563~~485			~~562~~570
Noncurrent Liabilities:
Long-term debt, net of current portion		1716			18
Derivative contract liabilities—affiliate		5941			94
Other		5281			52
Total noncurrent liabilities		~~128~~138			164
Commitments and Contingencies
Member’s Equity:
Member’s interest		3,~~831~~816			3,~~900~~892
Total member’s equity		3,~~831~~816			3,~~900~~892
Total Liabilities and Member’s Equity	$	4,~~522~~439		$	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.)~~

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

CONDENSED CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY (UNAUDITED)

	Member’s
		September 30,
	Interest
	Member’sInterest
	(in millions)
Balance, December 31, 2010	$	3,~~900~~892
Net income		3124
Distribution to member		(100	)
Balance, March 31, 2011	$	3,831
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.)~~

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

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Three Months
		September 30,			September 30,
	Ended March 31,
	Six Months Ended June 30,
	2011			2010
	(in millions)
Cash Flows from Operating Activities:
Net income	$	3124		$	~~439~~206
Adjustments to reconcile net income and changes in other operating assets and liabilities to net cash provided by operating activities:
Depreciation and amortization		2959			3369
Gain on sales of assets, net—affiliate		—			(23	)
Net changes in derivative contracts		3951			(~~346~~29	)
Lower of cost or market inventory adjustments		—			812
Changes in other operating assets and liabilities		935			92(24	)
Total adjustments		~~161~~115			~~(215~~25	)
Net cash provided by operating activities		~~192~~139			~~224~~231
Cash Flows from Investing Activities:
Capital expenditures		(1943	)		(79144	)
Proceeds from the sales of assets		—			34
Restricted funds on deposit, net		(143	)		—
Net cash used in investing activities		(~~162~~186	)		(76140	)
Cash Flows from Financing Activities:
Repayment of long-term debt		(1	)		(1	)
Redemption of preferred stock		—			95
Distribution to member		(100	)		(75	)
Repayment of long-term debt		(2	)		(2	)
Net cash used in financing activities		(101	)		(76	)
Distribution to member		(100	)		(150	)
Net Increase (Decrease) in Cash and Cash Equivalents		(71	)		72
Net cash used in financing activities		(102	)		(57	)
Net Increase (Decrease) in Cash and Cash Equivalents		(149	)		34
Cash and Cash Equivalents, beginning of period		202			125
Cash and Cash Equivalents, end of period	$	~~131~~53		$	~~197~~159
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~~

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 5 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 ~~March~~ June 3130, 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:

• ~~determining~~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.

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

	March 31,		December 31,
		September 30,		September 30,
	2011		2010
	June 30,2011		December 31,2010
	(in millions)
Funds deposited with the trustee to discharge the GenOn North America senior notes, due 2013(1)	$	—	$	866
Cash collateral posted(1)	$	240	$	120
Cash collateral posted(2)		152		120
GenOn Mid-Atlantic restricted cash(2)		143		—
GenOn Mid-Atlantic restricted cash(3)		143		—
Funds deposited with the trustee to discharge the GenOn North America senior notes, due 2013(3)		—		866
Total current and noncurrent funds on deposit		~~295~~383		986
Less: Current funds on deposit		~~259~~349		949
Total noncurrent funds on deposit	$	3634	$	37

(1)		See note 3 for discussion of the related debt.
(2)		Represents 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).
(3)		Represents cash reserved in respect of interlocutory liens related to the scrubber contract litigation. See note 8.

(1)	Represents 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).

(2)	Represents cash reserved in respect of interlocutory liens related to the scrubber contract litigation. See note 8.

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

GenOn Mid-Atlantic

	March 31,		December 31,
		September 30,		September 30,
	2011		2010
	June 30,2011		December 31,2010
	(in millions)
Cash collateral posted(1)	$	32	$	32
GenOn Mid-Atlantic restricted cash(1)	$	143	$	—
GenOn Mid-Atlantic restricted cash(2)		143		—
Cash collateral posted(2)		32		32
Total current and noncurrent funds on deposit		175		32
Less: Current funds on deposit		~~146~~147		2
Total noncurrent funds on deposit	$	2928	$	30

(1)		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.
(2)		Represents cash reserved in respect of interlocutory liens related to the scrubber contract litigation. See note 8.

(1)	Represents cash reserved in respect of interlocutory liens related to the scrubber contract litigation. See note 8.

11 (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

	March 31,		December 31,
		September 30,		September 30,
	2011		2010
	June 30,2011		December 31,2010
	(in millions)
Fuel inventory:
Fuel oil	$	72	$	136
Coal	$	79	$	52
Coal		58		52
Fuel oil		52		136
Other		24		1
Materials and supplies		73		72
Purchased emissions allowances		3031		34
Total inventories	$	~~235~~239	$	295

GenOn Mid-Atlantic

	March 31,		December 31,
		September 30,		September 30,
	2011		2010
	June 30,2011		December 31,2010
	(in millions)
Fuel inventory:
Fuel oil	$	22	$	20
Coal	$	79	$	52
Coal		58		52
Fuel oil		21		20
Other		2		1
Materials and supplies		50		49
Total inventories	$	~~132~~152	$	122

During the three months ended ~~March~~June 3130, 2011 and 2010, weGenOn Americas Generation recorded $1 million and $012 million, respectively, and during the six months ended June 30, 2011 and 2010, GenOn Americas Generation recorded $81 million and $20 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 30, 2011 and 2010, GenOn Mid-Atlantic recorded $0 and $4 million, respectively, and during the six months ended June 30, 2011 and 2010, GenOn Mid-Atlantic recorded $0 and $12 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:

	Three Months Ended
		September 30,			September 30,			September 30,			September 30,
	March 31,
	Three Months EndedJune 30,						Six Months EndedJune 30,
	2011			2010			2011			2010
	(in millions)
Total interest costs	$	3121		$	5250		$	52		$	102
Capitalized and included in property, plant and equipment, net		(1—	)		(21	)		(1	)		(3	)
Interest expense	$	3021		$	5049		$	51		$	99

The amounts of capitalized interest above include interest accrued. During the three months ~~ended~~ ~~March~~ended June 3130, 2011 and 2010, cash paid for interest was $060 million and $293 million, respectively, of which $1 million and ~~we did~~$3 million, ~~not~~respectively, ~~capitalize~~were ~~any~~capitalized. During the six months ended June 30, 2011 and 2010, cash paid for interest inwas ~~either~~$60 million ~~period~~and $95 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 2 for additional information on fair value measurements.

New Accounting Guidance Not Yet Adopted at June 30, 2011

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:

•

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

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. We ~~through~~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:

											Net Derivative
		September 30,		September 30,		September 30,			September 30,			September 30,
	Derivative Contract Assets				Derivative Contract Liabilities						~~Contract~~Net DerivativeContractAssets (Liabilities)
	Current		Long-Term		Current			Long-Term			~~Assets (Liabilities)~~
	(in millions)
March 31, 2011
June 30, 2011
Commodity Contracts:
Asset management	$	~~415~~367	$	~~567~~554	$	(~~260~~221	)	$	(8776	)	$	~~635~~624
Trading activities		~~520~~449		4327		(~~543~~465	)		(4827	)		(2816	)
Total derivatives	$	~~935~~816	$	~~610~~581	$	(~~803~~686	)	$	(~~135~~103	)	$	~~607~~608
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:

	Three Months Ended March 31,
		September 30,			September 30,			September 30,			September 30,
	Three Months Ended June 30,
	2011						2010
				Cost of Fuel,						Cost of Fuel,
Derivatives Not Designated as Hedging Instruments	OperatingRevenues			Cost of Fuel,Electricity andOther Products			OperatingRevenues			Cost of Fuel,Electricity andOther Products
	Operating			Electricity and			Operating			Electricity and
Derivatives Not Designated as Hedging Instruments	Revenues			Other Products			Revenues			Other Products
	(in millions)
Asset Management Commodity Contracts:
Unrealized	$	(6225	)	$	1415		$	~~353~~(218	)	$	(11109	)
Realized(1)(2)		6863			(1113	)		8591			(1511	)
Total asset management	$	638		$	32		$	~~438~~(127	)	$	(26120	)
Trading Commodity Contracts:
Unrealized	$	~~(23~~11	)	$	—		$	10(13	)	$	—
Realized(1)(2)		6(1	)		—			19(21	)		—
Total trading	$	~~(17~~10	)	$	—		$	29(34	)	$	—
Total derivatives	$	~~(11~~48	)	$	32		$	~~467~~(161	)	$	(26120	)

(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.

(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,
	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	$	(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:

	Notional Volumes at March 31, 2011
		September 30,			September 30,			September 30,
	Derivative			Derivative			Net
	Notional Volumes at June 30, 2011
	Contract			Contract			Derivative
Derivative Instruments	DerivativeContractAssets			DerivativeContractLiabilities			NetDerivativeContracts
Derivative Instruments	Assets			Liabilities			Contracts
	(in millions)
Commodity Contracts (in equivalent MWh):
Power(1)		(2019	)		(2028	)		(4047	)
Natural gas		(1324	)		1425			1
Fuel oil		2			(2	)		—
Coal		7			65			1312

		September 30,			September 30,			September 30,
	Notional Volumes at December 31, 2010
	Derivative			Derivative			Net
Derivative Instruments	DerivativeContractAssets			DerivativeContractLiabilities			NetDerivativeContracts
	Contract			Contract			Derivative
Derivative Instruments	Assets			Liabilities			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:

											Net Derivative
	Derivative Contract Assets				Derivative Contract Liabilities						Contract
	Current		Long-Term		Current			Long-Term			Assets (Liabilities)
	(in millions)
March 31, 2011
Commodity Contracts:
Asset management—nonaffiliate	$	158	$	472	$	(15	)	$	—		$	615
Asset management—affiliate		212		67		(197	)		(59	)		23
Total derivatives	$	370	$	539	$	(212	)	$	(59	)	$	638
December 31, 2010
Commodity Contracts:
Asset management—nonaffiliate	$	162	$	516	$	(18	)	$	—		$	660
Asset management—affiliate		245		97		(231	)		(94	)		17
Total derivatives	$	407	$	613	$	(249	)	$	(94	)	$	677

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 Derivative Contract Assets (Liabilities)
	Current		Long-Term		Current			Long-Term
	(in millions)
June 30, 2011
Commodity Contracts:
Asset management	$	155	$	474	$	(8	)	$	—		$	621
Asset management—affiliate		136		44		(135	)		(41	)		4

Total derivatives	$	291	$	518	$	(143	)	$	(41	)	$	625

December 31, 2010
Commodity Contracts:
Asset management	$	162	$	516	$	(18	)	$	—		$	660
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:

	Three Months Ended March 31,
		September 30,			September 30,		September 30,			September 30,
	Three Months Ended June 30,
	2011					2010
				Cost of Fuel,					Cost of Fuel,
Derivatives Not Designated as Hedging Instruments	OperatingRevenues			Cost of Fuel,Electricity andOther Products		OperatingRevenues			Cost of Fuel,Electricity andOther Products
	Operating			Electricity and		Operating			Electricity and
Derivatives Not Designated as Hedging Instruments	Revenues			Other Products		Revenues			Other Products
	(in millions)
Asset Management Commodity Contracts:
Unrealized	$	(5127	)	$	1215	$	~~338~~(205	)	$	8(112	)
Realized(1)(2)		61			—		7586			—(4	)
Total asset management	$	1034		$	1215	$	~~413~~(119	)	$	8(116	)

(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.

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

~~The~~(2) ~~following~~Effective ~~tables~~January ~~present~~1, ~~the~~2011, ~~notional~~excludes ~~quantity~~settlement onvalue ~~long~~of ~~(short) positions~~fuel ~~for derivative~~contracts ~~financial~~classified ~~instruments:~~ as inventory.

	Notional Volumes at March 31, 2011
		September 30,			September 30,		September 30,			September 30,
	Derivative			Derivative		Net
	Six Months Ended June 30,
	Contract			Contract		Derivative
	2011					2010
Derivative Instruments	Assets			Liabilities		Contracts
Derivatives Not Designated as Hedging Instruments	OperatingRevenues			Cost of Fuel,Electricity andOther Products		OperatingRevenues			Cost of Fuel,Electricity andOther Products
	(in millions)
Commodity Contracts (in equivalent MWh):
Asset Management Commodity Contracts:
Power(1)		(37	)		3		(34	)
Unrealized	$	(78	)	$	27	$	133		$	(104	)
Coal		5			9		14
Realized(1)(2)		122			—		161			(4	)
Total asset management	$	44			27		294			(108	)

Notional Volumes at December 31, 2010

Derivative

Net

Contract

Derivative

Derivative Instruments

Assets

Liabilities

Contracts

(in millions)

Commodity Contracts (in equivalent MWh):

Power(1)

(40

)

(36

)

Coal

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

(12) ~~Includes~~Effective ~~MWh~~January ~~equivalent~~1, of2011, ~~natural~~excludes ~~gas~~settlement ~~transactions~~value ~~used~~of tofuel ~~hedge~~contracts ~~power~~classified ~~economically~~as inventory.

Fair Value Measurements.

Fair Value Hierarchy and Valuation Techniques. We apply recurring fair value measurements to our financial assets and liabilities. In determining 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.

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
Derivative Instruments	Derivative Contract Assets			Derivative Contract Liabilities			Net Derivative Contracts
	(in millions)
Commodity Contracts (in equivalent MWh):
Power⁽¹⁾		(29	)		(6	)		(35	)
Coal		5			8			13

	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.

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.

The fair value of our derivative contract assets and liabilities is based largely 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. As of March 31, 2011, we obtained broker quotes for 100% of our delivery locations classified in Level 2 of the fair value hierarchy.

~~Inactive~~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 ~~are~~that regularly facilitate our transactions. An active market is considered to behave ~~those~~transactions ~~markets~~ with ~~few~~sufficient ~~transactions,~~frequency ~~noncurrent~~and ~~pricing~~volume to orprovide ~~prices~~pricing information on an ongoing basis. We think that ~~vary~~these ~~over~~prices ~~time~~represent orthe ~~among~~best available information for valuation purposes. In determining the fair value of derivative contract assets and liabilities, we use third-party market pricing ~~makers~~where available. ~~Our~~For transactions classified in Level 31 of the fair value hierarchy, ~~may~~we ~~involve~~use ~~transactions~~the ~~whereby~~unadjusted ~~observable~~published ~~market~~settled ~~data,~~prices ~~such~~on asthe ~~broker~~valuation ~~quotes,~~date. ~~are not~~For ~~available~~transactions ~~for~~classified ~~substantially~~in ~~all~~Level 2 of the ~~tenor~~fair ofvalue ~~the~~hierarchy, ~~contract~~we value these transactions using indicative quoted prices from independent brokers or weother widely-accepted valuation methodologies. Transactions are ~~only~~classified ~~able~~in toLevel 2 ~~obtain indicative~~if ~~broker~~substantially ~~quotes~~all ~~that~~(greater ~~cannot~~than 90%) of the fair value can be corroborated by using observable market ~~data~~inputs such as transactable broker quotes. In ~~such~~accordance ~~cases,~~with ~~we may~~the ~~apply~~exit ~~valuation~~price ~~techniques~~objective ~~such~~under asthe ~~extrapolation~~fair ~~and~~value ~~other~~measurements ~~quantitative~~accounting ~~methods to~~guidance, ~~determine~~the fair value. ~~Proprietary~~of ~~models~~our ~~may~~derivative ~~also~~contract beassets ~~used~~and toliabilities ~~determine~~is determined based on the ~~fair~~net ~~value~~underlying position of the recorded derivative contract assets and liabilities ~~that~~using ~~may~~bid beprices ~~structured~~for orassets ~~otherwise~~and ~~tailored.~~ask ~~Our techniques~~prices for ~~fair~~liabilities. ~~value~~The ~~estimation~~quotes ~~include~~that ~~assumptions~~we ~~for~~obtain ~~market~~from ~~prices~~brokers are non-binding in nature, ~~correlation~~but ~~and~~are from brokers that typically ~~volatility~~transact in the market being quoted and are based on their knowledge of market transactions on the valuation date. ~~The~~We ~~degree~~typically obtain multiple broker quotes as of ~~estimation~~the ~~increases~~valuation date that extend for ~~longer~~the ~~duration~~tenor ~~contracts,~~of the underlying contracts ~~with~~for each ~~multiple~~delivery ~~pricing~~location. ~~features,~~The ~~option~~number ~~contracts~~of ~~and~~quotes ~~off-hub~~that we can obtain depends on the relative liquidity of the delivery ~~points~~location on the valuation date. AtIf ~~March 31,~~multiple ~~2011~~broker quotes are received for a contract, ~~GenOn~~we use an average of the quoted bid or ask prices. If ~~Americas~~only ~~Generation’s~~one ~~assets~~broker quote is received for a delivery location and ~~liabilities~~it ~~classified~~cannot asbe ~~Level~~validated 3through inother 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 ~~represented~~liquid ~~approximately~~delivery 3%hub ofwith ~~its~~broker ~~total~~quotes ~~assets~~for the price spread between the liquid delivery hub and ~~10%~~the ofdelivery ~~its~~location ~~total~~under ~~liabilities~~the ~~measured~~contract. atWe ~~fair~~ also may apply interpolation techniques to value monthly strips if broker quotes are only available on a seasonal or annual basis. AtWe ~~March 31,~~perform ~~2011,~~validation ~~GenOn~~procedures ~~Mid-Atlantic’s~~on ~~assets~~the ~~and~~broker ~~liabilities~~quotes ~~classified~~at asleast ~~Level~~monthly. 3The invalidation procedures include reviewing the quotes for accuracy and comparing them to our internal price curves. In certain instances, we may ~~fair~~exclude ~~value~~from ~~hierarchy~~consideration ~~represented~~a ~~approximately~~broker 3%quote ofif ~~its~~it ~~total~~is ~~assets~~a clear outlier and 31other quotes are obtained. At June 30, 2011, we obtained broker quotes for 100% of ~~its~~our ~~total liabilities~~delivery ~~measured~~locations atclassified in Level 2 of the fair value hierarchy.

Inactive markets are considered to be those markets with few transactions, noncurrent pricing or prices that vary over time or among market makers. Our transactions in Level 3 of the fair value hierarchy may involve transactions whereby observable market data, such as broker quotes, are not available for substantially all of the tenor of the contract or we are only able to obtain indicative broker quotes that cannot be corroborated by observable market data. In such cases, we may apply valuation techniques such as extrapolation and other quantitative methods to determine fair value. 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:

	March 31, 2011
							Total
	Level 1(1)		Level 2(1) (2)		Level 3		Fair Value
	(in millions)
Derivative contract assets:
Commodity Contracts
Asset Management:
Power	$	6	$	934	$	7	$	947
Fuel		2		2		31		35
Total Asset Management		8		936		38		982
Trading Activities		257		298		8		563
Total derivative contract assets	$	265	$	1,234	$	46	$	1,545
Derivative contract liabilities:
Commodity Contracts
Asset Management:
Power	$	12	$	229	$	8	$	249
Fuel		13		—		85		98
Total Asset Management		25		229		93		347
Trading Activities		262		325		4		591
Total derivative contract liabilities	$	287	$	554	$	97	$	938
Interest-bearing funds(3)	$	575	$	—	$	—	$	575

(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 three months ended March 31, 2011.

(2)		Option contracts comprised approximately 2% of GenOn Americas Generation’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 Americas Generation had $393 million of interest-bearing funds included in cash and cash equivalents, $146 million included in funds on deposit and $36 million included in other noncurrent assets.

GenOn Americas Generation

	December 31, 2010
							Total
	Level 1(1)		Level 2(1) (2)		Level 3		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

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:

(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.
		September 30,		September 30,		September 30,		September 30,
(2)	Option contracts comprised approximately 1% of GenOn Americas Generation’s net derivative contract assets.
	June 30, 2011
(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 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.
	Level 1(1)		Level 2(1) (2)		Level 3		Total FairValue
	(in millions)
Derivative contract assets:
Commodity Contracts
Asset Management:
Power	$	10	$	855	$	14	$	879
Fuel		2		8		32		42
Total Asset Management		12		863		46		921
Trading Activities		214		253		9		476
Total derivative contract assets	$	226	$	1,116	$	55	$	1,397
Derivative contract liabilities:
Commodity Contracts
Asset Management:
Power	$	19	$	179	$	8	$	206
Fuel		14		6		71		91
Total Asset Management		33		185		79		297
Trading Activities		223		264		5		492
Total derivative contract liabilities	$	256	$	449	$	84	$	789
Interest-bearing funds(3)	$	454	$	—	$	—	$	454

(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 months ended June 30, 2011.

(2)	Option contracts comprised approximately 2% 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 million of interest-bearing funds included in cash and cash equivalents, $147 million included in funds on deposit and $34 million included in other noncurrent assets.

The following is a reconciliation of changes in fair value of net commodity derivative contract assets and liabilities classified as Level 3 during the three months ended March 31, 2011 and 2010, respectively:

		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

	Net Derivatives Contracts (Level 3)
	Asset			Trading
	Management			Activities		Total
	(in millions)
Balance, January 1, 2011 (net asset (liability))	$	(68	)	$	2	$	(66	)
Total gains (losses) realized/unrealized:
Included in earnings (1)		15			2		17
Purchases(2)		—			—		—
Issuances(2)		—			—		—
Settlements (3)		(2	)		—		(2	)
Transfers in and out of Level 3(4)		—			—		—
Balance, March 31, 2011 (net asset (liability))	$	(55	)	$	4	$	(51	)
Balance, January 1, 2010 (net asset (liability))	$	19		$	13	$	32
Total gains (losses) realized/unrealized:
Included in earnings (1)		(11	)		21		10
Purchases(2)		—			—		—
Issuances(2)		—			—		—
Settlements (5)		(13	)		10		(3	)
Transfers in and out of Level 3(4)		37			—		37
Balance, March 31, 2010 (net asset (liability))	$	32		$	44	$	76

(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.

(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.

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

~~The~~(3) ~~following~~Represents ~~table~~investments ~~presents~~in ~~the~~money ~~amounts~~market funds and is included in ~~income~~cash ~~related~~and tocash ~~derivative contract~~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 ~~liabilities~~cash ~~classified~~equivalents, as$2 ~~Level~~million 3: included in funds on deposit and $37 million included in other noncurrent assets.

	Three Months Ended March 31,
	2011						2010
			Cost of Fuel,						Cost of Fuel,
			Electricity						Electricity
	Operating		and Other				Operating		and Other
	Revenues		Products		Total		Revenues		Products		Total
	(in millions)
Gains (losses) included in income	$	3	$	12	$	15	$	38	$	6	$	44
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 March 31	$	3	$	13	$	16	$	38	$	6	$	44

The 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,			September 30,			September 30,
	Net Derivatives Contracts (Level 3)
	Asset Management			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			4			33
Purchases⁽²⁾		—			—			—
Issuances⁽²⁾		—			—			—
Settlements⁽³⁾		6			(2	)		4
Transfers into Level 3⁽⁴⁾		—			—			—
Transfers out of Level 3⁽⁴⁾		—			—			—

Balance, June 30, 2011 (net asset (liability))	$	(33	)	$	4		$	(29	)

Balance, January 1, 2010 (net asset (liability))	$	19		$	13		$	32
Total gains (losses) realized/unrealized:
Included in earnings⁽¹⁾		(133	)		(16	)		(149	)
Purchases⁽²⁾		—			—			—
Issuances⁽²⁾		—			—			—
Settlements⁽⁵⁾		(16	)		22			6
Transfers in and out of Level 3⁽⁴⁾		38			—			38

Balance, June 30, 2010 (net asset (liability))	$	(92	)	$	19		$	(73	)

(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,
	2011						2010
	Operating Revenues		Cost of Fuel, Electricity and Other Products		Total		Operating Revenues			Cost of Fuel, Electricity and Other Products			Total
	(in millions)
Gains (losses) included in income	$	7	$	15	$	22	$	(36	)	$	(113	)	$	(149	)
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	)

		September 30,		September 30,		September 30,		September 30,		September 30,			September 30,
	Six Months Ended June 30,
	2011						2010
	Operating Revenues		Cost of Fuel, Electricity and Other Products		Total		Operating Revenues		Cost of Fuel, Electricity and Other Products			Total
	(in millions)
Gains (losses) included in income	$	10	$	27	$	37	$	2	$	(107	)	$	(105	)
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	)

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:

	March 31, 2011
		September 30,		September 30,		September 30,		September 30,
							Total
	June 30, 2011
	Level 1(1)		Level 2(1) (2)		Level 3		~~Fair~~TotalFair Value
	(in millions)
Derivative contract assets:
Commodity Contracts
Asset Management:
Power	$	51	$	~~874~~774	$	—4	$	~~879~~779
Fuel		—		21		2829		30
Total derivative contract assets	$	51	$	~~876~~775	$	2833	$	~~909~~809
Derivative contract liabilities:
Commodity Contracts
Asset Management:
Power	$	911	$	~~177~~103	$	—	$	~~186~~114
Fuel		—		—		8570		8570
Total derivative contract liabilities	$	911	$	~~177~~103	$	8570	$	~~271~~184
Interest-bearing funds(3)	$	~~304~~223	$	—	$	—	$	~~304~~223

(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 three months ended March 31, 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 $129 million of interest-bearing funds included in cash and cash equivalents, $146 million included in funds on deposit and $29 million included in other noncurrent assets.

(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 months ended June 30, 2011.

	December 31, 2010
							Total
	Level 1(1)		Level 2(1)(2)		Level 3		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

(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 $48 million of interest-bearing funds included in cash and cash equivalents, $147 million included in funds on deposit and $28 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.

21 23

(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.

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

~~The~~(3) ~~following~~Represents isinvestments ain ~~reconciliation~~money ofmarket ~~changes~~funds and are included in ~~fair~~cash ~~value~~and ofcash ~~net~~equivalents, ~~commodity~~funds ~~derivative contract~~on ~~assets~~deposit and ~~liabilities~~other ~~classified~~noncurrent asassets ~~Level~~in 3the ~~during~~consolidated ~~the~~balance ~~three~~sheet. ~~months~~GenOn ~~ended~~Mid-Atlantic ~~March 31,~~had ~~2011~~ $202 million of interest-bearing funds included in cash and ~~2010~~cash equivalents, ~~respectively:~~ $2 million included in funds on deposit and $30 million included in other noncurrent assets.

	Asset
	Management
	(in millions)
Balance, January 1, 2011 (net asset (liability))	$	(69	)
Total gains (losses) realized/unrealized:
Included in earnings(1)		14
Purchases(2)		—
Issuances(2)		—
Settlements(3)		(2	)
Transfers in and out of Level 3(4)		—
Balance, March 31, 2011 (net asset (liability))	$	(57	)
Balance, January 1, 2010 (net asset (liability))	$	13
Total gains (losses) realized/unrealized:
Included in earnings(1)		(36	)
Purchases(2)		—
Issuances(2)		—
Settlements(5)		—
Transfers in and out of Level 3(4)		37
Balance, March 31, 2010 (net asset (liability))	$	14

(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.
		September 30,
(2)	Contracts entered into during each quarterly reporting period are reported with other changes in fair value.
	AssetManagement
(3)	Effective January 1, 2011, represents the reversal of previously recognized unrealized gains and losses from settlement of contracts during each quarterly reporting period.
	(in millions)
(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.
Balance, January 1, 2011 (net asset (liability))	$	(69	)
(5)	Represents the total cash settlements of contracts during each quarterly reporting period that existed at the beginning of each quarterly reporting period.
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	)

22 (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)

(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:

	Three Months Ended March 31,
		September 30,		September 30,		September 30,		September 30,			September 30,			September 30,
	Three Months Ended June 30,
	2011						2010
			Cost of Fuel,							Cost of Fuel,
	OperatingRevenues		Cost of Fuel,Electricity andOther Products		Total		OperatingRevenues			Cost of Fuel,Electricity andOther Products			Total
			Electricity							Electricity
	Operating		and Other				Operating			and Other
	Revenues		Products		Total		Revenues			Products			Total
	(in millions)
Gains (losses) included in income	$	—5	$	1216	$	1221	$	(6—	)	$	7(113	)	$	1(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 March 31	$	—	$	12	$	12	$	(6	)	$	7		$	1
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	)

Counterparty Credit Concentration Risk.

		September 30,		September 30,		September 30,		September 30,			September 30,			September 30,
	Six Months Ended June 30,
	2011						2010
	Operating Revenues		Cost of Fuel, Electricity and Other Products		Total		Operating Revenues			Cost of Fuel, Electricity and Other Products			Total
	(in millions)
Gains (losses) included in income	$	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 June 30	$	5	$	28	$	33	$	(6	)	$	(106	)	$	(112	)

WeCounterparty ~~are~~Credit ~~exposed~~Concentration toRisk 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 credit reserve on derivative contract assets was $13 million and $19 million at March 31, 2011 and December 31, 2010, respectively.

AtWe ~~March 31,~~are ~~2011~~exposed to the default risk of the counterparties with which we transact. We manage our credit risk by entering into master netting agreements and ~~December 31,~~requiring ~~2010,~~counterparties ~~$2 million~~to post cash collateral or other credit enhancements based on the net exposure and ~~$3 million,~~the ~~respectively,~~credit standing of ~~cash~~the counterparty. We also have non-collateralized power hedges entered into by GenOn ~~collateral~~Mid-Atlantic. ~~posted~~These totransactions are senior unsecured obligations of GenOn ~~Americas~~Mid-Atlantic ~~Generation~~and bythe counterparties ~~under~~and ~~master~~do ~~netting~~not ~~agreements were~~require ~~included~~either party to post cash collateral for initial margin or for securing exposure as a result of changes in ~~accounts~~power ~~payable~~or natural ~~and~~gas ~~accrued~~prices. ~~liabilities~~Our credit valuation adjustment on ~~GenOn~~derivative ~~Americas~~contract ~~Generation’s consolidated~~assets ~~balance~~was ~~sheets~~$15 million and $19 million at June 30, 2011 and December 31, 2010, respectively.

At June 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 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:

23 25

GenOn Americas Generation

	March 31, 2011
		September 30,		September 30,		September 30,		September 30,		September 30,
	Gross		Net
	June 30, 2011
	Exposure		Exposure				Exposure
Credit Rating Equivalent	GrossExposureBeforeCollateral(1)		NetExposureBeforeCollateral(2)		Collateral(3)		ExposureNet ofCollateral		% of NetExposure
	Before		Before				Net of		% of Net
Credit Rating Equivalent	Collateral(1)		Collateral(2)		Collateral(3)		Collateral		Exposure
	(dollars in millions)
Clearing and Exchange	$	~~624~~536	$	121	$	121	$	—		—
Investment Grade:
Financial institutions		~~732~~702		~~655~~654		—		~~655~~654		8076	%
Energy companies		~~248~~254		97136		82		89134		1115	%
Other		1		1		—		1		—
Non-investment Grade:
Energy companies		1219		1219		—5		1214		2	%
No External Ratings:
Internally-rated investment grade		3638		3538		—		3538		4	%
Internally-rated non-investment grade		2624		2624		—		2624		3	%
Total	$	1,~~679~~573	$	~~838~~872	$	208	$	~~818~~864		100	%

		September 30,		September 30,		September 30,		September 30,		September 30,
	December 31, 2010
	Gross		Net
Credit Rating Equivalent	GrossExposureBeforeCollateral(1)		NetExposureBeforeCollateral(2)		Collateral(3)		ExposureNet ofCollateral		% of NetExposure
	Exposure		Exposure				Exposure
	Before		Before				Net of		% of Net
Credit Rating Equivalent	Collateral(1)		Collateral(2)		Collateral(3)		Collateral		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.

(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.

24 (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

March 31, 2011

September 30,

Gross

Net

June 30, 2011

Exposure

Credit Rating Equivalent

GrossExposureBeforeCollateral(1),(4)

NetExposureBeforeCollateral(2)

Collateral(3)

ExposureNet ofCollateral

% of NetExposure

Before

Net of

% of Net

Credit Rating Equivalent

Collateral(1),(4)

Collateral(2)

Collateral(3)

Collateral

Exposure

(dollars in millions)

Investment Grade:

Financial institutions

~~659~~656

~~641~~645

—

~~641~~645

Non-investment Grade:

Energy companies

1112

—

1112

No External Ratings:

Internally-rated non-investment grade

2524

—

2524

Total

~~695~~692

~~677~~681

—

~~677~~681

100

		September 30,		September 30,		September 30,		September 30,		September 30,
	December 31, 2010
	Gross		Net
Credit Rating Equivalent	GrossExposureBeforeCollateral(1),(4)		NetExposureBeforeCollateral(2)		Collateral(3)		ExposureNet ofCollateral		% of NetExposure
	Exposure		Exposure				Exposure
	Before		Before				Net of		% of Net
Credit Rating Equivalent	Collateral(1),(4)		Collateral(2)		Collateral(3)		Collateral		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)		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.
(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.

(1)

~~GenOn~~(2) ~~Americas~~Net ~~Generation had credit~~ exposure tobefore ~~two~~collateral ~~investment~~represents ~~grade~~the ~~counterparties~~credit ~~at March 31~~exposure, ~~2011~~including both realized and ~~December 31,~~unrealized ~~2010~~transactions, ~~respectively,~~after ~~each~~applying ~~representing~~the anterms ~~exposure~~ of ~~more~~master ~~than~~netting ~~10% of~~agreements ~~total~~with ~~credit~~counterparties ~~exposure,~~and ~~net~~netting of ~~collateral~~transactions ~~and~~with ~~totaling~~clearing ~~$536 million~~brokers and ~~$568 million at March 31, 2011 and December 31, 2010, respectively~~exchanges.

~~GenOn~~(3) ~~Mid-Atlantic~~Collateral ~~had~~includes ~~credit~~cash ~~exposure to three investment grade counterparties at March 31, 2011~~ and ~~December 31,~~letters ~~2010, respectively, each representing an exposure~~ of ~~more than 10% of total~~ credit ~~exposure,~~received ~~net~~from ~~of collateral and totaling $603 million and $653 million at March 31, 2011 and December 31, 2010, respectively~~counterparties.

25 (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 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 million and $568 million at June 30, 2011 and December 31, 2010, respectively.

GenOn Mid-Atlantic had credit exposure to two investment grade counterparties at June 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 million and $653 million at June 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 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 in nature that could require us to post additional cash collateral or letters of credit as a result of a credit event, including

a downgrade. However, as a result of our current credit rating, we are typically required to post collateral in the normal course of business to offset either substantially or completely the net liability positions, after applying the terms of master netting agreements. At June 30, 2011, the fair value of GenOn Americas Generation’s financial instruments with credit-risk-related contingent features in a net liability position was $21 million for which GenOn Americas Generation had posted collateral of $19 million, including cash and letters of credit. At June 30, 2011, GenOn Mid-Atlantic ~~Credit~~did ~~Risk.~~not have any financial instruments with credit-risk-related contingent features in a net liability position.

~~Our~~At standard industry contracts contain credit-risk-related contingent features such as ratings-related thresholds whereby we would be required to post additional cash collateral or letters of credit as a result of a credit eventJune 30, ~~including~~2011 aand downgrade. Additionally, some of our contracts contain language, which is generally subjective in nature that could require us to post additional cash collateral or letters of credit as a result of a credit event, including a downgrade. However, as a result of our current credit rating, we are typically required to post collateral in the normal course of business to offset either substantially or completely the net liability positions, after applying the terms of master netting agreements. At MarchDecember 31, ~~2011~~2010, ~~the fair value of~~ GenOn Americas ~~Generation’s~~ ~~financial instruments with credit-risk-related contingent features in a net liability~~Generation ~~position~~had ~~was~~ $770 million ~~for~~and ~~which GenOn Americas Generation had posted collateral of~~ $6 1 million, ~~including~~ ~~cash~~respectively, ~~and letters~~ of ~~credit.~~cash Atcollateral ~~March 31,~~posted ~~2011,~~with ~~GenOn~~counterparties ~~Mid-Atlantic~~under ~~did~~master ~~not~~netting ~~have~~agreements ~~any financial~~that ~~instruments~~was ~~with~~included ~~credit-risk-related~~in ~~contingent~~funds ~~features~~on indeposit aon ~~net~~the ~~liability~~consolidated ~~position~~balance sheets.

AtFair ~~March 31,~~Values ~~2011~~of ~~and~~Other ~~December 31,~~Financial ~~2010,~~Instruments (GenOn Americas Generation) ~~had $7 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:

March 31, 2011

December 31, 2010

September 30,

Carrying

June 30, 2011

December 31, 2010

Amount

Fair Value

Amount

Fair Value

CarryingAmount

Fair Value

CarryingAmount

Fair Value

(in millions)

Liabilities:

Long and short-term debt(1)

~~1,404~~868

~~1,435~~861

2,255

2,272

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

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

3. Long-Term Debt

Outstanding debt was as follows:

	March 31, 2011								December 31, 2010
		September 30,			September 30,			September 30,		September 30,			September 30,			September 30,
	Stated								Stated
	June 30, 2011								December 31, 2010
	Interest								Interest
	StatedInterestRate(1)			Long-term			Current		StatedInterestRate(1)			Long-term			Current
	Rate(1)			Long-term			Current		Rate(1)			Long-term			Current
	(in millions, except interest rates)
Bonds and Notes:
GenOn Americas Generation:
Senior unsecured notes, due 2011		8.30	%	$	—		$	535		8.30	%	$	—		$	535
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(2)		—			—			—		7.375			—			850
Senior notes, due 2013(3)		—			—			—		7.375			—			850
GenOn Mid-Atlantic:
GenOn Chalk Point capital lease, due 2011 to 2015		8.19			1716			4		8.19			18			4
Total				$	~~865~~864		$	~~539~~4				$	866		$	1,389

(1)		The stated interest rates are at March 31, 2011 and December 31, 2010.
(2)		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.

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

26 (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 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 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.

4. Guarantees and Letters of Credit ~~(GenOn Americas Generation)~~

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~~ construction agreements and agreements with vendors. Although the primary obligation ~~of GenOn Americas Generation or a subsidiary~~ under such contracts is to pay money or render performance, such contracts may include obligations to indemnify the counterparty for damages arising from the breach thereof and, in certain instances, other existing or potential liabilities. In many cases GenOn Americas Generation’s maximum potential liability cannot be estimated because some of the underlying agreements contain no limits on potential liability.

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, asand ~~well as~~ 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:

	March 31,		December 31,
		September 30,		September 30,
	2011		2010
	June 30,2011		December 31,2010
	(in millions)
Letters of credit—rent reserves(1)	$	98	$	101
Letters of credit—energy trading and marketing activities(1)		3847		63
Letters of credit—other operating activities(1)		3633		31
Surety bonds		8		7
Total	$	~~180~~186	$	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.

5. 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

	Three Months Ended
		September 30,		September 30,		September 30,		September 30,
	March 31,
	Three Months EndedJune 30,				Six Months EndedJune 30,
	2011		2010		2011		2010
	(in millions)
Cost of fuel, electricity and other products—affiliate	$	23	$	31	$	5	$	4
Operations and maintenance expense—affiliate		3235		40		67		80
Total	$	3438	$	4341	$	72	$	84

GenOn Mid-Atlantic

	Three Months Ended
		September 30,		September 30,		September 30,		September 30,
	March 31,
	Three Months EndedJune 30,				Six Months EndedJune 30,
	2011		2010		2011		2010
	(in millions)
Cost of fuel, electricity and other products—affiliate	$	23	$	21	$	5	$	4
Operations and maintenance expense—affiliate		1820		2524		38		49
Total	$	2023	$	2725	$	43	$	53

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 months ended ~~March~~June 3130, 2011, GenOn Americas Generation recorded a reduction to operations and maintenance expense—affiliate of ~~approximately~~ $58 million and $13 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 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~~ 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 ~~March~~June 3130, 2011 and 2010, GenOn Mid-Atlantic incurred $1 million and $43 million, respectively, of energy marketing overhead expenses. During the six months ended June 30, 2011 and 2010, GenOn Mid-Atlantic incurred $2 million and $7 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 months ended ~~March~~June 3130, 2011 and 2010, we incurred the following in costs under these arrangements, which are included in operations and maintenance ~~expense~~ expense—affiliate in our unaudited condensed consolidated statements of operations:

	Three Months
		September 30,		September 30,		September 30,		September 30,
	Ended March 31,
	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
	(in millions)
GenOn Americas Generation	$	3332	$	3032	$	65	$	62
GenOn Mid-Atlantic	$	21	$	1920	$	42	$	39

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 ~~March~~June 3130, 2011 GenOn Americas Generation had current notes receivable from GenOn Energy Holdings of $~~122~~145 million related to its intercompany cash management program. During the three and six months ended ~~March~~June 3130, 2011, GenOn Americas Generation earned an insignificant amount of interest income related to the notes receivable. At ~~March~~June 3130, 2011 GenOn Americas Generation had current notes payable to GenOn Energy Holdings of $824 million related to its intercompany cash management program. During the three and six months ended ~~March~~June 3130, 2011, GenOn Americas Generation paid 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 30, 2011 and 2010, were $6 million and $7 million, respectively, and in the six months ended ~~March~~June 3130, 2011 and 2010, were $814 million and $916 million, respectively, and are recorded in cost of fuel, electricity and other products—affiliate in GenOn Mid-Atlantic’s unaudited condensed consolidated statements of operations.

30 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 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 $18(8) million and $78 (77) million during the three months ended ~~March~~June 3130, 2011 and 2010, respectively., ~~The~~and ~~pro~~$10 million ~~forma~~and $1 million during the six months ended June 30, 2011 and 2010, respectively. The balance of GenOn Americas Generation’s pro forma net deferred income taxes is zero asat ~~of March~~June 3130, 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 $12(2) million and $~~175~~(93) million during the three months ended ~~March~~June 3130, 2011 and 2010, respectively, and $10 million and $82 million during the six months ended June 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 $~~200~~212 million as of ~~March~~June 3130, 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.

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.

~~GenOn~~33 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 sales of emissions allowances, intercompany revenues and intercompany cost of fuel.

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.

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

	Eastern									Energy			Other
		September 30,			September 30,			September 30,			September 30,			September 30,			September 30,			September 30,
	PJM			Northeast			California			Marketing			Operations			Eliminations			Total
	Eastern PJM			Northeast			California			EnergyMarketing			OtherOperations			Eliminations			Total
	(in millions)
Three Months Ended March 31, 2011:
Three Months Ended June 30, 2011:
Operating revenues—nonaffiliate(1)	$	(1	)	$	5		$	28		$	506		$	—		$	—		$	538
Operating revenues (1)	$	45		$	4		$	22		$	644		$	—		$	—		$	715
Operating revenues—affiliate(2)		~~299~~235			3945			—			5673			—			(~~383~~351	)		112
Total operating revenues		~~298~~280			4449			2822			~~562~~717			—			(~~383~~351	)		~~549~~717
Cost of fuel, electricity and other products—nonaffiliate(3)		7			1			1			14			142			—			165
Cost of fuel, electricity and other products (3)		2			2			(1	)		33			102			—			138
Cost of fuel, electricity and other products—affiliate(4)		~~129~~111			2725			—(2	)		~~538~~649			(~~141~~102	)		(~~383~~351	)		~~170~~330
Total cost of fuel, electricity and other products		~~136~~113			2827			1(3	)		~~552~~682			1—			(~~383~~351	)		~~335~~468
Gross margin (excluding depreciation and amortization)		~~162~~167			1622			2725			1035			(1—	)		—			~~214~~249
Operating Expenses:
Operations and maintenance—nonaffiliate		62			10			6			1			—			—			79
Operations and maintenance		101			11			6			—			—			—			118
Operations and maintenance—affiliate		4042			910			89			3(2	)		—			—			6059
Depreciation and amortization		2930			6			34			—1			21			—			4042
Total operating expenses, net		131			25			17			4			2			—			179
Gain on sales of assets, net		—			1			—			—			—			—			1
Operating income (loss)	$	31		$	(9	)	$	10		$	6		$	(3	)	$	—		$	35
Total operating expenses, net		173			28			19			(1	)		1			—			220
Total assets at March 31, 2011	$	4,522		$	497		$	144		$	1,885		$	333		$	(876	)	$	6,505
Operating income (loss)	$	(6	)	$	(6	)	$	6		$	36		$	(1	)	$	—		$	29

(1)		Includes unrealized losses of $45 million and $50 million for Eastern PJM and Energy Marketing, respectively.
(2)		Includes unrealized gains of $27 million for Energy Marketing and unrealized losses of $6 million and $11 million for Eastern PJM and Northeast, respectively.
(3)		Includes unrealized gains of $14 million for Energy Marketing.
(4)		Includes unrealized losses of $14 million for Energy Marketing and unrealized gains of $12 million and $2 million for Eastern PJM and Northeast, respectively.

________________

32 (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									Energy			Other
	Eastern PJM			Northeast			California			EnergyMarketing			OtherOperations			Eliminations			Total
	PJM			Northeast			California			Marketing			Operations			Eliminations			Total
	(in millions)
Three Months Ended March 31, 2010:
Six Months Ended June 30, 2011:
Operating revenues—nonaffiliate(1)	$	258		$	5		$	32		$	585		$	—		$	—		$	880
Operating revenues (1)	$	44		$	9		$	50		$	1,150		$	—		$	—		$	1,253
Operating revenues—affiliate(2)		~~481~~534			6784			6—			~~(118~~129	)		—			(~~436~~734	)		—13
Total operating revenues		~~739~~578			7293			3850			~~467~~1,279			—			(~~436~~734	)		~~880~~1,266
Cost of fuel, electricity and other products—nonaffiliate(3)		4			—			—			200			—			—			204
Cost of fuel, electricity and other products (3)		9			3			—			47			244			—			303
Cost of fuel, electricity and other products—affiliate(4)		~~151~~240			4452			8(2	)		~~236~~1,187			—(243	)		(~~436~~734	)		3500
Total cost of fuel, electricity and other products		~~155~~249			4455			8(2	)		~~436~~1,234			—1			(~~436~~734	)		~~207~~803
Gross margin (excluding depreciation and amortization)		~~584~~329			2838			3052			3145			—(1	)		—			~~673~~463
Operating Expenses:
Operations and maintenance—nonaffiliate		65			12			10			—			—			2			89
Operations and maintenance		163			21			12			1			—			—			197
Operations and maintenance—affiliate		4882			1219			1017			21			—			(2—	)		70119
Depreciation and amortization		3359			612			87			—1			23			—			4982
Gain on sales of assets, net		(2—	)		—1			—			—			—			—			(21	)
Total operating expenses, net		~~144~~304			3053			2836			23			23			—			~~206~~399
Operating income (loss)	$	~~440~~25		$	(215	)	$	216		$	2942		$	(24	)	$	—		$	~~467~~64
Total assets at December 31, 2010	$	4,626		$	488		$	121		$	2,418		$	1,292		$	(1,132	)	$	7,813
Total assets at June 30, 2011	$	4,439		$	482		$	141		$	1,885		$	178		$	(680	)	$	6,445

(1)		Includes unrealized gains of $200 million and $163 million for Eastern PJM and Energy Marketing, respectively.
(2)		Includes unrealized gains of $138 million and $15 million for Eastern PJM and Northeast, respectively and unrealized losses of $153 million for Energy Marketing.
(3)		Includes unrealized losses of $11 million for Energy Marketing.
(4)		Includes unrealized losses of $19 million for Northeast and unrealized gains of $8 million and $11 million for Eastern PJM and Energy Marketing, respectively.

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

	Three Months
	Ended March 31,
	2011			2010
	(in millions)
Operating income for all segments	$	35		$	467
Interest expense		(30	)		(50	)
Other, net		(23	)		(1	)
Net income (loss)	$	(18	)	$	416

(2)	Includes unrealized gains of $57 million for Energy Marketing and unrealized losses of $39 million and $10 million for Eastern PJM and Northeast, respectively.

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

(4)	Includes unrealized losses of $29 million for Energy Marketing and unrealized gains of $27 million and $2 million for Eastern PJM and Northeast, 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 June 30, 2010:

Operating revenues⁽¹⁾	$	(39	)		3		$	29	$	251		$	—		$	—		$	244
Operating revenues—affiliate⁽²⁾		209			37			4		165			—			(415	)		—

Total operating revenues		170			40			33		416			—			(415	)		244
Cost of fuel, electricity and other products⁽³⁾		5			—			—		153			113			—			271
Cost of fuel, electricity and other products—affiliate⁽⁴⁾		245			18			4		262			(113	)		(415	)		1

Total cost of fuel, electricity and other products		250			18			4		415			—			(415	)		272

Gross margin (excluding depreciation and amortization)		(80	)		22			29		1			—			—			(28	)

Operating Expenses:
Operations and maintenance		70			13			7		1			—			2			93
Operations and maintenance—affiliate		47			14			11		2			—			(2	)		72
Depreciation and amortization		36			6			7		—			1			—			50
Gain on sales of assets, net		(1	)		—			—		—			—			—			(1	)

Total operating expenses, net		152			33			25		3			1			—			214

Operating income (loss)	$	(232	)	$	(11	)	$	4	$	(2	)	$	(1	)	$	—		$	(242	)

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

(2)	Includes unrealized losses of $108 million and $13 million for Eastern PJM and Northeast, respectively, and unrealized gains of $121 million for Energy Marketing.

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

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


	Eastern PJM			Northeast			California		Energy Marketing⁽³⁾		Other Operations⁽³⁾			Eliminations			Total
	(in millions)
Six Months Ended June 30, 2010:

Operating revenues⁽¹⁾	$	219		$	8		$	61	$	836	$	—		$	—		$	1,124
Operating revenues—affiliate⁽²⁾		690			104			10		47		—			(851	)		—

Total operating revenues		909			112			71		883		—			(851	)		1,124
Cost of fuel, electricity and other products⁽⁴⁾		9			—			—		199		267			—			475
Cost of fuel, electricity and other products—affiliate⁽⁵⁾		396			62			12		652		(267	)		(851	)		4

Total cost of fuel, electricity and other products		405			62			12		851		—			(851	)		479

Gross margin (excluding depreciation and amortization)		504			50			59		32		—			—			645

Operating Expenses:
Operations and maintenance		135			25			17		1		—			4			182
Operations and maintenance—affiliate		95			26			21		4		—			(4	)		142
Depreciation and amortization		69			12			15		—		3			—			99
Gain on sales of assets, net		(3	)		—			—		—		—			—			(3	)

Total operating expenses, net		296			63			53		5		3			—			420

Operating income (loss)	$	208		$	(13	)	$	6	$	27	$	(3	)	$	—		$	225

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

(1)	Includes unrealized gains of $103 million and $29 million for Eastern PJM and Energy Marketing, respectively.

(2)	Includes unrealized gains of $30 million and $2 million for Eastern PJM and Northeast, respectively, and unrealized losses of $32 million for Energy Marketing.

(3)

The 2011 segment 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 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 losses of $120 million for Energy Marketing.

(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 Ended June 30,						Six Months Ended June 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.

Scrubber Contract Litigation

In January 2011, Stone & Webster, the EPC contractor for the scrubber projects at the Chalk Point, Dickerson and Morgantown 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 liens against the properties in the amounts of $43.2 million at Chalk Point, $46.8 million at Dickerson and $53.1 million at Morgantown. In March 2011, the court granted liens against the properties. The liens are interlocutory only and will not become final unless and until Stone & Webster is successful in prosecuting its contractual claims. As a result of certain lien restrictions in its lease documentation, GenOn Mid-Atlantic has reserved $143 million of cash (which is included in funds on deposit on the unaudited condensed consolidated balance sheet) in respect of such liens. WeIn ~~dispute~~June 2011, Stone & Webster filed a motion to amend its lien claims at Chalk Point, Dickerson and Morgantown by an additional $90 million. In the event that such liens are granted, GenOn Mid-Atlantic expects to reserve an additional $90 million of cash in respect thereof. We 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. ~~The~~Currently, ~~current budget of~~ $1.674 billion continues 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 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~~ 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 ~~early~~ May 2011.

Montgomery County Carbon Emissions Levy. The Dickerson facility is located in Montgomery County, Maryland, and ~~effective~~ in May 2010, Montgomery County imposed a levy on major emitters of CO2 in the county of $5 per ton of CO2 emitted. We ~~estimate~~estimated that the CO2 levy ~~will~~would ~~impose~~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 iswas unlawful. In its complaint, GenOn Mid-Atlantic ~~contends~~contended that the CO2 levy ~~violates~~ violated its equal protection and due process rights, ~~imposes~~imposed an unconstitutional excessive fine, is was an unconstitutional bill of attainder, ~~constitutes~~constituted a prohibited special law under the Maryland Constitution, and iswas preempted by Maryland law and the RGGI, an interstate compact to which Maryland is a party. In July 2010, the ~~district~~District ~~court~~Court ruled that the CO2 levy was is 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 ~~has~~ 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~~38 Fly 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. We currently dispose of fly ash from our Morgantown and Chalk Point facilities at Brandywine. We currently dispose of fly ash from our Dickerson station at Westland.

In May 2008, the MDE filed a complaint against GenOn Mid-Atlantic and GenOn MD Ash Management in the Circuit Court for Charles County, Maryland alleging violations of Maryland’s water pollution laws at Faulkner. The MDE contended that the operation of Faulkner had resulted in the discharge of pollutants that exceeded Maryland’s water quality criteria and without the appropriate NPDES permit. The MDE also alleged that 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, GenOn MD Ash Management and GenOn Mid-Atlantic filed a motion to dismiss the complaint, arguing that the discharges are permitted by a December 2000 Consent Order. In January 2011, MDE dismissed without prejudice its complaint and informed GenOn that it intended to file a similar lawsuit in federal court. In May 2011, the MDE filed a complaint against GenOn Mid-Atlantic and GenOn MD Ash Management in the 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 landfill 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.

In January 2011, the MDE informed us that it intends to file a complaint related to alleged violations of Maryland’s water pollution laws at Westland.

In April 2010, the MDE filed a complaint against GenOn Mid-Atlantic and GenOn MD Ash Management 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. GenOn MD Ash Management and GenOn Mid-Atlantic dispute the allegations. In September 2010, four environmental advocacy groups became intervening parties in the proceeding. In March 2011, the MDE tentatively determined to deny GenOn MD Ash Management’s and GenOn Mid-Atlantic’s 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 has indicated that it is planning also 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.

We have initiated discussions with the MDE to seek to resolve the dispute related to Brandywine along with the disputes related to Faulkner and Westland described above. We are examining a range of possible alternatives to address the MDE’s concerns. If an alternative acceptable to the MDE is developed, we expect that the MDE would issue renewed, more-stringent (but yet to be developed) permits that would require us to take actions at these three facilities to achieve the more stringent standards. We cannot estimate the costs of the possible actions as they are still being developed but they likely would result in material expenditures (some of which could be capitalized), including possible penalties. There are no assurances that we will be able to resolve these three disputes with the MDE.

~~Ash~~Maryland ~~Disposal~~Fly ~~Facility~~Ash ~~Closures~~Facilities. We ~~are~~have ~~responsible~~three ~~for~~fly ~~environmental~~ash facilities ~~costs~~in ~~related~~Maryland: toFaulkner, ~~the future~~Westland ~~closures~~and Brandywine. Until recently, we disposed of ~~several~~fly ash ~~disposal~~from ~~facilities.~~our ~~GenOn~~Morgantown ~~Americas~~station ~~Generation~~at Faulkner, but it has ~~accrued~~reached ~~the estimated~~its ~~discounted~~capacity. ~~costs~~We ~~($10 million~~dispose ~~and~~of ~~$9 million~~fly atash ~~March 31,~~from ~~2011~~our Morgantown and ~~December 31,~~Chalk ~~2010,~~Point facilities at ~~respectively)~~Brandywine. ~~associated~~We ~~with~~dispose ~~these~~of ~~environmental~~fly ~~liabilities~~ash asfrom ~~part~~our ofDickerson ~~its~~station ~~asset~~at ~~retirement obligations~~Westland. ~~GenOn~~As ~~Mid-Atlantic~~described ~~recorded~~below, the ~~estimated~~MDE ~~discounted~~has ~~costs~~sued ~~($8 million~~us ~~and~~regarding ~~$7 million at~~Faulkner ~~March 31,~~and ~~2011~~Brandywine and ~~December 31,~~threatened ~~2010,~~to ~~respectively)~~sue ~~associated~~regarding ~~with~~Westland. ~~these~~The ~~environmental liabilities~~MDE asalso ~~part~~has ofthreatened ~~its~~not ~~asset~~to ~~retirement~~renew ~~obligations.~~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 at June 30, 2011. We also have developed a technical solution that we think will address the MDE’s concerns at the three ash facilities. We have accrued $28 million for the estimated cost of the technical solution. 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.

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.

Complaint 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. PJM conducted the capacity auctions that are the subject of the complaint to set the capacity payments in effect under the RPM provisions of its tariff for twelve month periods beginning June 1, 2008, June 1, 2009, and June 1, 2010. The RPM Buyers allege that (a) the times between when the auctions were held and the periods that the resulting capacity rates would be in effect were too short to allow competition from new resources in the auctions, (b) the administrative process established under the RPM provisions of PJM’s tariff was inadequate to restrain the exercise of market power by the withholding of capacity to increase prices, and (c) the locational pricing established under the RPM provisions of PJM’s tariff created opportunities for sellers to raise prices while serving no legitimate function. The RPM Buyers asked the FERC ~~to reduce significantly the capacity rates established by the capacity auctions and to set June 1, 2008, as the date beginning on which any rates~~ found by the FERC to be excessive would be subject to refund. If the FERC were to reduce the capacity payments set through the capacity auctions to the rates proposed by the RPM Buyers, the capacity revenue we have received or expect to receive for the period June 1, 2008 through May 31, 2011, would be reduced by approximately $600 million. In September 2008, the FERC issued an order dismissing the complaint. 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. ~~Certain~~ ofOn ~~the~~a ~~RPM~~subsequent ~~Buyers have appealed the orders entered by the FERC to the United States Court of Appeals for the Fourth Circuit. That~~ appeal, ~~was~~in ~~transferred~~February 2011, to the United States Court of ~~Appeal~~Appeals for the District of Columbia Circuit. ~~On February 8, 2011, the D.C. Circuit~~ affirmed the FERC rulings. None of the RPM Buyers asked the D.C. Circuit to reconsider its decision. ~~The deadline~~and ~~for~~no ~~any~~ party tofiled ~~file~~ for a writ of certiorari. ~~with~~The ~~the~~deadlines ~~Supreme~~for ~~Court~~these isprocedures ~~May 9,~~have ~~2011~~passed.

36 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 NO_x and/or SO₂ emissions in states included in the program. 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 SO₂allowances used for compliance in the CAIR program are the Acid Rain Program allowances, which will have negligible value after 2011. The carrying value of NO_x 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 NO_x 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 AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

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 ~~March~~June 3130, 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~~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 ~~April~~July 12, 2011, our aggregate hedge levels based on expected generation without considering the effects of CSAPR were as follows:

		September 30,			September 30,			September 30,			September 30,			September 30,
	2011(1)			2012			2013			2014			2015
Power		8492	%		8381	%		3633	%		3330	%		923	%
Fuel		9193	%		7671	%		4947	%		—	%		—	%

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

37The 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 Americas Generation, which utilize OTC derivative financial

~~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 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 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~~ 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 ~~three~~six months ended ~~March~~June 3130, 2011, we invested $2146 million for capital expenditures, excluding capitalized interest paid, primarily related to maintenance capital expenditures. At ~~March~~June 3130, 2011, we have invested $1.52521 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 ~~project~~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.

~~The~~42 ~~following table details the expected timing of payments for our estimated capital expenditures, excluding capitalized interest, for the remainder of 2011 and 2012:~~

	April 1, 2011
	through
	December 31,
	2011		2012
	(in millions)
Maryland Healthy Air Act	$	154	$	—
Other environmental		6		9
Maintenance		35		40
Other construction		45		7
Total	$	240	$	56

We expect that available cash and future cash flows from operations will be sufficient to fund these capital expenditures.

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.

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

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

Total	$	209	$	64

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

~~Several~~We ~~proposed~~decide ~~environmental~~to ~~regulations~~invest ~~are~~capital ~~pending.~~for ~~The~~environmental ~~dates~~controls ofbased ~~final~~on relatively certain regulations and ~~implementation~~ ~~deadlines~~the ~~are~~expected economic ~~difficult~~returns toon ~~predict~~the capital. ~~The~~Whether ~~following~~we ~~summarizes~~elect ~~material~~to ~~first~~install ~~quarter 2011~~additional ~~environmental~~controls ~~regulatory~~as ~~developments.~~a ~~See~~result ~~also~~of ~~our~~the ~~discussion~~CSAPR, ~~under~~pending ~~the~~HAPs ~~caption “Environmental~~regulation ~~Matters”~~or inother ~~note~~regulations 8remains touncertain ~~our~~and ~~interim~~depends ~~financial statements~~on, ~~including~~among ~~the~~other ~~discussion~~things, of the ~~process~~content ~~for~~and ~~obtaining~~timing ~~renewals~~of ~~from~~regulations, the expected ~~MDE~~effect of ~~water~~regulations ~~discharge~~on ~~permits~~wholesale ~~for~~power ~~our~~prices ~~Brandywine~~and allowance prices, ~~Faulkner~~ ~~and~~as ~~Westland~~well ~~ash~~as ~~facilities.~~the ~~Our~~cost ~~2010~~of ~~Annual~~controls, ~~Report~~profitability onof ~~Form~~our ~~10-K~~generating ~~contains~~facilities, ~~discussion~~market ~~of other~~conditions ~~pending~~at ~~environmental~~the ~~matters,~~time ~~including~~and the ~~proposed~~likelihood ~~Transport~~of ~~Rule~~CO2 regulation.

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 1990 levels by 2020. In December 2008, the CARB approved a Scoping Plan for implementing AB 32. The ~~Scoping~~costs ~~Plan~~associated ~~requires~~with ~~that~~more ~~the~~stringent ~~CARB~~environmental ~~adopt~~air ~~a cap-~~and~~-trade~~ ~~regulation~~water byquality ~~January 2011~~requirements, ~~and~~including ~~that the cap~~state-~~and-trade program begin in 2012. The CARB’s schedule for developing regulations to~~specific ~~implement~~or ~~AB 32 is being coordinated with the schedule of the WCI for development of a~~ regional ~~cap-and-trade~~ ~~program~~regulatory ~~for greenhouse gas emissions. Through the WCI~~initiatives, ~~California~~may isresult ~~working~~in ~~with other western states and Canadian provinces to coordinate and implement a regional cap~~coal-~~and-trade program.~~fired Ingenerating ~~October 2010~~facilities, ~~the~~including ~~CARB~~some ~~released~~of ~~its proposed cap-and-trade regulation for public comment~~ours, ~~which~~being ~~the CARB approved in December 2010~~retired. InImplementation ~~March 2011,~~of a ~~California superior court judge enjoined the implementation of the cap-and-trade~~ program ~~and~~putting ~~related~~a ~~Scoping~~price ~~Plan~~on ~~measures until~~emissions ~~CARB remedies various procedural flaws related to CARB’s environmental review~~ of ~~the~~CO2 ~~Scoping Plan~~in ~~under~~addition ~~the California Environmental Quality Act, possibly delaying the scheduled January 2012 implementation date. Our California generating facilities will be required~~ to ~~comply with the cap-and-trade regulations and related rules when they go into effect. The recently adopted cap-and-trade regulation and any~~ other ~~plans,~~emissions ~~rules~~control ~~and~~requirements ~~programs approved to implement AB 32~~ could ~~adversely~~ ~~affect~~increase the ~~costs~~likelihood of ~~operating~~retirements ~~the~~of coal-fired generating facilities.

~~Water Regulations.~~ We ~~are~~expect ~~required~~any ~~under~~such ~~the~~industry ~~Clean~~retirements ~~Water~~to ~~Act~~contribute to ~~comply~~improving ~~with~~supply ~~intake~~ and ~~discharge~~ ~~requirements,~~demand ~~requirements~~fundamentals for ~~technological controls and operating practices. To discharge water, we generally need permits required by~~ the ~~Clean Water Act. Such permits typically~~ ~~are~~remaining ~~subject~~generating ~~to review every five years~~facilities. AsAny ~~with~~resulting ~~air~~increased ~~quality~~demand ~~regulations,~~for ~~federal~~natural ~~and~~gas ~~state~~could ~~water regulations~~increase ~~are~~the ~~expected~~spread tobetween ~~impose~~natural ~~additional~~gas and ~~more~~coal ~~stringent requirements or limitations in the future. This is particularly the case for regulatory requirements governing cooling water intake structures~~prices, which ~~are~~would ~~subject~~also tobenefit ~~regulation under section 316(b) of~~ the ~~Clean~~remaining ~~Water~~coal-fired ~~Act~~generating ~~(the 316(b) regulations)~~facilities. ~~A 2007 decision by the United States Court of Appeals for the Second Circuit (the Second Circuit) in Riverkeeper Inc. et al. v. EPA~~Consequently, inGenOn ~~which the court remanded to the EPA for~~Americas ~~reconsideration~~Generation ~~numerous~~and ~~provisions~~GenOn ofMid-Atlantic ~~the~~expect ~~EPA’s~~industry ~~section~~retirements ~~316(b) regulations for existing power plants, has created substantial uncertainty about exactly what technologies or other measures will be needed~~ to ~~satisfy~~result ~~section 316(b) requirements~~ in ~~the~~higher ~~future~~market ~~and when any new requirements will be imposed. Following that ruling by the Second Circuit, the EPA in 2007 suspended its 316(b) regulations for existing~~ power ~~plants. Various parties sought review of the Second Circuit’s decision by the United States Supreme Court~~prices, ~~and~~which ~~it granted those requests with respect to whether the EPA~~ could ~~permissibly~~result ~~weigh~~in ~~costs~~GenOn ~~versus~~Americas ~~benefits~~Generation ininvesting ~~determining~~approximately ~~what~~$345 ~~requirements~~million to ~~impose. On~~$450 ~~April 1~~million, ~~2009,~~including ~~the~~$315 ~~Supreme~~million ~~Court~~to ~~reversed~~$415 ~~the~~million ~~Second~~for GenOn ~~Circuit~~Mid-Atlantic, ~~ruling~~over ~~that~~ the ~~EPA~~next ~~had permissibly~~six ~~relied~~years ~~on cost-benefit analysis in setting standards~~ for ~~cooling~~SCRs ~~water intake structures for existing power plants~~ and ~~authorizing site-specific variances. The Supreme Court’s ruling did not alter~~ other ~~aspects~~environmental ofcontrols ~~the~~to ~~Second~~meet ~~Circuit’s~~certain ~~decision.~~air Inand ~~April 2011,~~water ~~the~~quality ~~EPA proposed a 316(b) rule that would apply to virtually all existing facilities~~requirements, ~~including~~which ~~power plants~~we ~~that~~expect ~~use cooling water intake structures~~ to ~~withdraw~~fund ~~water~~ from ~~waters~~existing sources of ~~the United States~~liquidity. ~~That~~ ~~proposal~~Under ~~would~~current ~~impose~~and ~~national~~forecasted ~~standards~~market ~~for reducing mortality for larger~~conditions, ~~impingeable-sized~~we ~~organisms.~~do Itnot ~~requires~~expect ~~permit~~installations ~~writers~~of scrubbers to ~~establish~~be ~~controls~~economic ~~for~~at ~~smaller,~~most ~~entrainable-sized organisms~~of onour aunscrubbed ~~site~~coal-~~specific~~fired ~~basis, taking into account a variety of factors, including costs and benefits~~facilities. ~~The~~If ~~EPA~~market ~~will~~prices ~~accept~~are ~~public~~even ~~comment~~higher onthan ~~its~~our ~~proposal~~current ~~until July 19~~expectations, ~~2011,~~we ~~and~~might ~~the~~invest ~~final rule~~more ~~may~~for ~~differ~~environmental ~~from the proposal as a result of that process~~controls. 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.

39Given 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.

~~HAPs~~Cross-State ~~Regulations~~Air Pollution Rule. In ~~May~~ ~~2011~~2005, the EPA ~~proposed~~promulgated the ~~emission~~CAIR, ~~standards~~which ~~for~~established ~~HAPs~~SO2 ~~from~~and ~~coal~~NOx cap-and-trade programs applicable directly to states and indirectly to ~~oil-fired~~generating ~~units~~facilities in the eastern United States. The ~~EPA~~NOx cap-and-trade ~~proposes~~program tohas ~~establish~~two ~~limits~~components, ~~for~~an ~~mercury,~~annual ~~non-mercury~~program ~~metals~~and an Ozone Season program. The CAIR SO2 cap-and-trade program builds off the existing acid ~~gases.~~ Werain docap-and-trade ~~not~~program ~~expect these~~but ~~proposals~~requires generating facilities to ~~materially~~surrender ~~affect~~twice ~~our~~as ~~operations~~many allowances to cover emissions from 2010 through 2014 and approximately three times as many allowances starting in 2015. ~~Our~~Florida, Illinois, Maryland, ~~coal-fired~~Mississippi, ~~units~~New ~~already~~ Jersey, New York, Ohio, Pennsylvania and Virginia are subject to the CAIR’s SO2, ~~NOx,~~trading program and ~~mercury~~both ~~limits~~its ~~under~~NOx trading programs. Massachusetts is subject only to the ~~Maryland~~CAIR’s ~~Healthy~~Ozone Season ~~Air~~NOx ~~Act~~trading program. ~~Accordingly~~These cap-and-trade programs were to be implemented in two phases, with the first phase going into effect in 2009 for NOx and 2010 for ~~emissions~~SO2 ~~from~~and ~~our~~more ~~Maryland~~stringent ~~coal-fired~~caps ~~units~~going ~~already~~into ~~meet~~effect in 2015. On July 11, 2008, the ~~EPA’s~~D.C. Circuit ~~proposed~~in ~~HAPs~~State ~~standards~~of asNorth aCarolina 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 ~~result~~December 23, of2008, the ~~controls~~D.C. Circuit issued a second opinion in which it granted rehearing only to the extent that ~~have~~it ~~been~~remanded ~~installed~~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 July 2011, EPA released its prepublication version of the regulations to replace the CAIR with the CSAPR. CSAPR will be finalized when published in the Federal Register, which we expect to occur in August 2011. The CSAPR addresses interstate transport of emissions of NO_x and SO₂. The CSAPR will establish limitations on NO_x and/or SO₂ emissions from electric generating units that are greater than 25 megawatts and are located in 27 states in the eastern half of the United States whose NO_x and/or SO₂ emissions are determined by the EPA to 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 will create “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 will be 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 will be allocated 9,476, 4,194 and 18,925 allowances under the CSAPR for annual NO_x, ozone-season NO_x, and SO₂, respectively. The CSAPR contemplates that states after 2012 may allocate allowances in a different manner than allocated initially under the CSAPR. The CSAPR will limit 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. The carrying value of NO_x 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 NO_x 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.

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. We do not expect these proposals to materially affect our operations. Our Maryland coal-fired units already are subject

to SO₂, NO_x, 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.

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 1990 levels by 2020. In December 2008, the CARB approved a Scoping Plan for implementing AB 32. The Scoping Plan 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 Canadian 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 California Environmental Quality Act. The CARB appealed the decision. A state appellate court stayed the injunction, allowing the CARB to continue to develop the final cap-and-trade regulation, with adoption targeted for October 2011. However, CARB indicated in June 2011 that while it still intends to initiate the cap-and-trade program in 2012, compliance requirements imposed by the rule will be delayed one year until 2013. Our California generating facilities will be required to comply with the cap-and-trade 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 facility was shut down. See note 3 to our consolidated financial statements in our 2010 Annual Report on Form 10-K for further discussion.

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 is designated as a hedge and changes in their fair values are recognized currently in income as unrealized gains or losses. As a result, our financial results are, at times, volatile and subject to fluctuations in value primarily because of changes in forward electricity and fuel prices. Realized gross margin, together with its components energy, contracted and capacity and realized value of hedges, provide a measure of performance that eliminates the volatility reflected in unrealized gross margin, which is created by significant shifts in market values between periods. 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.

40 45

~~Three~~ gross ~~Months~~margin ~~Ended~~(excluding ~~March 31~~depreciation and amortization) less unrealized gains and losses on derivative financial instruments. Conversely, ~~2011~~unrealized ~~Compared~~gross margin represents our unrealized gains and losses on derivative financial instruments. None of our derivative financial instruments recorded at fair value is designated as a hedge and changes in their fair values are recognized currently in income as unrealized gains or losses. As a result, our financial results are, at times, volatile and subject to ~~Three~~fluctuations ~~Months~~in ~~Ended~~value ~~March 31~~primarily because of changes in forward electricity and fuel prices. Realized gross margin, ~~2010~~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.

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

Consolidated Financial Performance

We reported net ~~loss~~income of $18 8 million and a net ~~income~~loss of $~~416~~292 million during the three months ended ~~March~~June 3130, 2011 and 2010, respectively. The change in net income/loss is detailed as follows:

	Three Months
		September 30,			September 30,			September 30,
	Ended March 31,						Increase/
	Three MonthsEndedJune 30,						Increase/(Decrease)
	2011			2010			~~(Decrease)~~
	(in millions)
Gross margin:
Energy	$	9780		$	~~110~~96		$	(1316	)
Contracted and capacity		~~121~~105			~~142~~138			(2133	)
Realized value of hedges		6763			6978			(215	)
Total realized gross margin		~~285~~248			~~321~~312			(3664	)
Unrealized gross margin		~~(71~~1	)		~~352~~(340	)		~~(423~~341	)
Total gross margin (excluding depreciation and amortization)		~~214~~249			~~673~~(28	)		~~(459~~277	)
Operating expenses:
Operations and maintenance—nonaffiliate		79			89			(10	)
Operations and maintenance		118			93			25
Operations and maintenance—affiliate		6059			7072			(1013	)
Depreciation and amortization		4042			4950			(98	)
Gain on sales of assets, net		—			(2	)		2
(Gain) loss on sales of assets, net		1			(1	)		2
Total operating expenses		~~179~~220			~~206~~214			~~(27~~6	)
Operating income		35			467			(432	)
Operating income (loss)		29			(242	)		271
Other income (expense), net:
Interest expense, net		(3021	)		(5049	)		20(28	)
Other, net		~~(23~~—	)		(1	)		(221	)
Total other expense, net		(5321	)		(5150	)		(229	)
Net income (loss)	$	~~(18~~8	)	$	~~416~~(292	)	$	~~(434~~300	)

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~~46 ~~the three months ended March 31, 2011, our realized gross margin decrease of $36 million was principally a result of the following:~~

• a decrease of $21 million in contracted and capacity primarily resulting from lower capacity prices in Eastern PJM and the Northeast;

• a decrease of $13 million in energy, primarily as a result of a decrease in generation volumes in Eastern PJM as a result of contracting 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 $2 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, offset in part by an increase in our coal hedges in Eastern PJM resulting from prices.

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 three months ended June 30, 2011, our realized gross margin decrease of $64 million was principally a result of the following:

•

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 ~~losses~~gains of $711 million during the three months ended ~~March~~June 3130, 2011, which included ~~$67 million associated with the reversal of previously recognized unrealized gains from power and fuel contracts that settled during the period and~~ a $457 million net ~~decrease~~increase in the value of hedge and proprietary trading contracts for future periods., ~~The~~offset ~~decrease~~by in$56 ~~value~~million ~~was~~associated ~~primarily~~with ~~related~~the toreversal ~~increases~~of inpreviously ~~oil~~recognized ~~prices,~~unrealized ~~offset~~gains byfrom ~~decreases~~power inand ~~forward~~fuel ~~power~~contracts ~~and~~that ~~natural~~settled ~~gas~~during ~~prices~~the period; and

• unrealized ~~gains~~losses of $~~352~~340 million during the three months ended ~~March~~June 3130, 2010, which included a $~~433~~205 million net ~~increase~~decrease in the value of hedge and trading contracts for future periods primarily related to ~~decreases~~increases in forward power prices and ~~natural~~the ~~gas~~recognition ~~prices,~~of ~~partially~~many ~~offset~~of byour coal agreements at fair value beginning in the second quarter of 2010. The $81340 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 ~~decrease~~increase of $276 million was principally a result of the following:

• aan ~~decrease~~increase of $2012 million in operations and maintenance expense primarily as a result of a ~~decrease~~$30 inmillion ~~outage~~accrual ~~expenses~~for inremediation ~~Eastern~~costs ~~PJM~~at ~~incurred~~our ~~during~~Maryland ~~the~~ash ~~three~~facilities ~~months~~(which ~~ended~~includes ~~March~~a ~~31,~~tentative ~~2011~~$1.9 ~~compared~~million tocivil ~~the~~penalty), ~~same~~and ~~period~~an increase in ~~2010~~litigation costs for major project disputes, net of recoveries. The increase in operations and maintenance expense was partially offset by a decrease in allocated overhead costs as a result of a change in the allocation methodology as a result of the Merger and a decrease of $12 million as a result of the ~~shutdown~~repeal of the ~~Potrero~~Montgomery ~~generating~~County ~~facility~~CO2 levy, including $8 million related to the refund received in the third quarter of 2011 of CO2 levies paid in 2010; ~~and~~offset in part by

• a decrease of $98 million in depreciation and amortization expense primarily as a result of a ~~decrease~~reduction in the carrying value of the Dickerson and Potomac River generating facilities as a result of impairment losses taken in the fourth quarter of 2010, and the shutdown of the Potrero generating facility~~; offset in part by~~.

•Interest aExpense, Net. Interest expense, net decrease of $2 28 million inreflects ~~gain~~lower oninterest ~~sales~~expense as a result of (a) repayment ~~assets~~of ~~primarily~~the ~~related~~GenOn toNorth ~~emissions~~America ~~allowances~~senior ~~sold~~secured tocredit ~~third~~facilities ~~parties~~and senior notes in December 2010 and January 2011, respectively, and (b) repayment of the GenOn Americas Generation senior unsecured notes in May 2011.

~~Interest~~47 Expense, Net. Interest expense, net decrease of $20 million reflects lower interest expense as a result of repayment of the GenOn North America senior secured credit facilities and senior notes in December 2010 and January 2011, respectively.

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

	Three Months
		September 30,		September 30,		September 30,			September 30,
	Ended March 31,				Increase/			Increase/
	Three Months EndedJune 30,				Increase/(Decrease)			Increase/(Decrease)
	2011		2010		~~(Decrease)~~			~~(Decrease)~~
	(in gigawatt hours)
Eastern PJM:
Baseload		32,~~511~~612		3,~~972~~062		(~~461~~450	)		(1215	)%
Intermediate		21242		55277		(3435	)		(6213	)%
Peaking		1429		664		8(35	)		~~133~~(55	)%
Total Eastern PJM		32,~~546~~883		43,~~033~~403		(~~487~~520	)		(1215	)%
Northeast:
Baseload		~~379~~374		~~365~~355		1419			45	%
Intermediate		2047		949		11(2	)		~~122~~(4	)%
Total Northeast		399		374		25			7	%
Peaking		1		1		—			—	%
Total Northeast		422		405		17			4	%
California:
Intermediate		1141		~~123~~88		(~~112~~47	)		(9153	)%
Total California		1141		~~123~~88		(~~112~~47	)		(9153	)%
Total		3,~~956~~346		43,~~530~~896		(~~574~~550	)		(1314	)%

The total decrease in power generation volumes during the three months ended ~~March~~June 3130, 2011, as as compared to the same period in 2010, iswas primarily the result of the following:

Eastern PJM. A decrease in our ~~baseload and intermediate~~ generation volumes primarily as a result of ~~contracting~~increased ~~dark~~outages ~~spreads,~~at ~~partially~~certain ~~offset~~of byour coal-fired baseload units, an increase in production costs at our ~~peaking~~Dickerson ~~generation~~generating facility as a result of the CO2 levy and contracting off-peak dark spreads.

Northeast. An increase in our Northeast baseload ~~and intermediate~~ generation as a result of ~~lower~~ higher average temperatures.

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

43 48

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

Consolidated Financial Performance

We reported a net loss of $10 million and net income of $124 million during the six months ended June 30, 2011 and 2010, respectively. The change in net income/loss is detailed as follows:

		September 30,			September 30,			September 30,
	Six Months Ended June 30,						Increase/
	2011			2010			(Decrease)
	(in millions)
Gross margin:
Energy	$	177		$	206		$	(29	)
Contracted and capacity		226			280			(54	)
Realized value of hedges		130			147			(17	)

Total realized gross margin		533			633			(100	)
Unrealized gross margin		(70	)		12			(82	)

Total gross margin (excluding depreciation and amortization)		463			645			(182	)
Operating expenses:
Operations and maintenance		197			182			15
Operations and maintenance—affiliate		119			142			(23	)
Depreciation and amortization		82			99			(17	)
(Gain) loss on sales of assets, net		1			(3	)		4

Total operating expenses		399			420			(21	)

Operating income		64			225			(161	)

Other income (expense), net:
Interest expense, net		(51	)		(99	)		(48	)
Other, net		(23	)		(2	)		21

Total other expense, net		(74	)		(101	)		(27	)

Net income (loss)	$	(10	)	$	124		$	(134	)

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 months ended June 30, 2011, our realized gross margin decrease of $100 million was principally a result of the following:

•

a decrease of $54 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 $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 $17 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, offset in part by an increase in our coal hedges in Eastern PJM resulting from prices.

•

unrealized losses of $70 million during the six months ended June 30, 2011, which included $123 million associated with the reversal of previously recognized unrealized gains from power and fuel contracts that settled during the period offset by a $53 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 $12 million during the six months ended June 30, 2010, which included a $228 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 also included the recognition of many of our coal agreements at fair value beginning in the second quarter of 2010. The increase in value was partially offset by $216 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 decrease of $21 million was principally a result of the following:

•

a decrease of $17 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 taken in the fourth quarter of 2010, and the shutdown of the Potrero generating facility; and

•

a decrease of $8 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 as a result of the Merger, a decrease of $10 million as a result of the repeal of the Montgomery County CO₂levy, including $8 million related to the refund received in the third quarter of 2011 of CO₂levies paid in 2010, a reduction in outage expenses in California and Eastern PJM, the shutdown of the Potrero generating facility and a decrease in property taxes in the Northeast. 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 an increase in litigation costs for major project disputes, net of recoveries; partially offset by

•

a decrease of $4 million in gain on sales of assets primarily related to emissions allowances sold to third parties in 2010.

Interest Expense, Net. Interest expense, net decrease of $48 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, 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.

Operating Statistics

The following table summarizes power generation volumes by segment:

		September 30,		September 30,		September 30,			September 30,
	Six Months Ended June 30,				Increase/ (Decrease)			Increase/ (Decrease)
	2011		2010		Increase/ (Decrease)			Increase/ (Decrease)
	(in gigawatt hours)
Eastern PJM:
Baseload		6,123		7,034		(911	)		(13	)%
Intermediate		263		332		(69	)		(21	)%
Peaking		43		70		(27	)		(39	)%

Total Eastern PJM		6,429		7,436		(1,007	)		(14	)%

Northeast:
Baseload		753		720		33			5	%
Intermediate		67		58		9			16	%
Peaking		1		1		—			—	%

Total Northeast		821		779		42			5	%

California:
Intermediate		52		211		(159	)		(75	)%

Total California		52		211		(159	)		(75	)%

Total		7,302		8,426		(1,124	)		(13	)%

The total decrease in power generation volumes during the six months ended June 30, 2011, as compared to the same period in 2010, was primarily the result of the following:

Eastern PJM. A decrease in our generation volumes primarily 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.

Northeast. An increase in our Northeast baseload and intermediate generation as a result of higher average temperatures.

California. The decrease in our intermediate generation volumes was primarily the 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 3 to our interim financial statements for additional discussion of our debt.

Sources 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~~51 ~~table below sets forth total cash and cash equivalents of GenOn Americas Generation and its subsidiaries at March 31, 2011 (in millions):~~

Cash and Cash Equivalents:
GenOn Americas Generation (excluding GenOn Mid-Atlantic)	$	271
GenOn Mid-Atlantic		131
Total cash and cash equivalents	$	402

We consider all short-term investments with an original maturity of three months or less to be cash equivalents. At March 31, 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.

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

The table below sets forth total cash and cash equivalents of GenOn Americas Generation and its subsidiaries at 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

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.

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. In 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. At ~~March~~June 3130, 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 million of cash (which is included in funds on deposit on the unaudited condensed consolidated balance sheet) in respect of such liens. In June 2011, Stone & Webster filed a motion to amend its lien claims at Chalk Point, Dickerson and Morgantown by an additional $90 million. 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 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 3 to our interim financial statements.

Capital Expenditures. Our capital expenditures, excluding capitalized interest paid, during the ~~three~~six months ended ~~March~~June 3130, 2011, were $2146 million. We estimate our capital expenditures, excluding capitalized interest, for the period ~~April~~July 1, 2011 through December 31, 2012 will be $~~296~~ 273 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 ~~March~~June 3130, 2011, we had ~~$152~~ $240 million of posted cash collateral and GenOn had $~~172~~178 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~~ 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:

	March 31,		December 31,
		September 30,		September 30,
	2011		2010
	June 30,2011		December 31,2010
	(in millions)
Cash collateral posted—energy trading and marketing	$	~~112~~200	$	80
Cash collateral posted—other operating activities		40		40
Letters of credit—rent reserves(1)		98		101
Letters of credit—energy trading and marketing(1)		3847		63
Letters of credit—other operating activities(1)		3633		31
Surety bonds		8		7
Total	$	~~332~~426	$	322

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

Debt Obligations, Off-Balance Sheet Arrangements and Contractual Obligations

~~Other~~There ~~than~~have ~~the~~been ~~repayment~~no ofmaterial ~~the~~changes ~~GenOn~~outside ~~North America senior notes on January 3, 2011 and~~ the ~~GenOn~~ ~~Americas~~ordinary ~~Generation~~course ~~senior~~of ~~unsecured~~business ~~notes on May 2, 2011, there have been no significant changes~~ to our debt obligations, off-balance sheet arrangements and contractual obligations from those ~~presented~~disclosed in our 2010 Annual Report on Form 10-K and note 3 to our interim financial statements.

~~Historical~~53 ~~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 from continuing operations decreased $73 million for the three months ended March 31, 2011, compared to the same period in 2010, primarily as a result of the following:

• Accounts payable, collateral. A decrease in cash provided of $78 million primarily as a result of $1 million returned to our counterparties in 2011 compared to $77 million posted by our counterparties in 2010;

• Net accounts receivables and accounts payables. A decrease in cash provided of $52 million primarily as a result of decreases in the settlement prices of our power hedges; and

• Realized gross margin. A decrease in cash provided of $44 million in 2011 compared to the same period in 2010 (excluding lower of cost or market inventory adjustments of $8 million in 2010). See “Results of Operations” in Item 2 for additional discussion of our performance in 2011 as compared to the same period in 2010; and

• Funds on deposit. A decrease in cash provided of $18 million primarily as a result of $32 million of additional collateral posted with our counterparties in 2011 compared to $14 million of additional collateral posted in 2010.

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

•Operating ~~Inventory~~Activities. AOur ~~decrease~~cash provided by operating activities is affected by seasonality, changes in energy prices and fluctuations in our working capital requirements. Net cash ~~used~~provided ofby operating activities increased $75112 million ~~primarily~~for ~~related~~the six months ended June 30, 2011, compared to the ~~changes~~same period in ~~fuel~~2010, ~~oil~~primarily ~~inventory;~~as a result of the following:

• ~~Other operating assets and liabilities~~Inventories. A decrease in cash used of $24145 million primarily related to changes in ~~other~~fuel ~~operating~~oil ~~assets~~inventory ~~and~~in ~~liabilities;~~2011 ~~and~~compared to the same period in 2010;

• ~~Operating~~Net ~~expenses~~accounts receivables and accounts payables. AAn ~~decrease~~increase in cash ~~used~~provided ~~related~~of to$121 ~~lower~~million ~~operations~~primarily ~~and~~as ~~maintenance~~a ~~expense~~result of ~~$20~~an ~~million.~~increase ~~See~~in ~~“Results~~payables ofto ~~Operations”~~affiliates inresulting ~~Item~~from 2transactions ~~for~~initiated ~~additional~~by ~~discussion~~GenOn Energy Management on behalf of ~~our~~affiliated ~~performance~~companies. inSee ~~2011~~note ~~compared~~5 to ~~the~~our ~~same~~interim ~~period~~financial ~~in 2010.~~statements;

~~Investing~~• ~~Activities~~Interest Expense. ~~Net~~A ~~cash~~decrease ~~provided~~in bycash ~~investing~~used ~~activities~~of ~~increased by~~ $~~665~~ 43 million ~~for the~~related ~~three~~to ~~months~~lower ~~ended~~interest ~~March 31,~~expense ~~2011,~~primarily ~~compared~~resulting tofrom the ~~same~~repayment ~~period~~of GenOn North America senior notes in December 2010. ~~This~~and ~~difference~~the ~~was primarily~~GenOn aNorth ~~result~~America ofterm ~~the~~loan ~~following:~~ in January 2011; and

• ~~Withdrawals~~Other ~~from~~operating ~~restricted~~assets ~~funds~~and ~~on deposit~~liabilities. AnA ~~increase~~decrease in cash ~~provided~~used of $~~866~~49 million ~~primarily~~ related to ~~funds~~changes ~~received from the GenOn debt financing on December 3, 2010, which were subsequently placed~~ in ~~restricted~~other ~~deposits~~operating atassets ~~December~~and ~~31, 2010~~liabilities. ~~The withdrawal of cash was used to repay long-term debt. See note 3 to our interim financial statements; and~~

•The ~~Capital~~increases ~~expenditures. A decrease~~ in cash ~~used~~provided ofand ~~$62~~decreases ~~million~~in ~~primarily~~cash asused aby ~~result~~operating ofactivities ~~payments~~were ~~related~~partially tooffset ~~our~~by the ~~Maryland~~following: ~~scrubber projects in 2010.~~

•

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 ~~Intercompany debt~~Activities. AnNet ~~increase~~cash used in ~~cash~~financing ~~used~~activities ofincreased by $~~122~~1.059 ~~million~~billion ~~related~~for the six months ended June 30, 2011, compared to the ~~repayment~~same ofperiod ~~intercompany~~in ~~debt~~2010. This difference was primarily a result of the following:

~~Financing~~54 Activities. Net cash used in financing activities increased by $873 million for the three months ended March 31, 2011, compared to the same period in 2010. This difference was primarily a result of the repayment of long-term debt. See note 3 to our interim financial statements. In addition, $100 million was distributed to our member in 2011. We made no distribution in 2010.

•

Repayment of long-term debt. An increase in cash used of $1.334 billion for repayment of long-term debt. See note 3 to our interim financial statements;

•

Distribution to member. An increase in cash used of $100 million related to a distribution to our member during the six months ended June 30, 2011. There were no distributions for the six months ended June 30, 2010; 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 six months ended June 30, 2011.

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

•

Capital contributions. An increase in cash provided of $444 million related to contributions made by our member; and

•

Intercompany debt. An increase in cash provided of $26 million related to proceeds received from intercompany debt.

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

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 ~~April~~July 12, 2011, our aggregate hedge levels based on expected generation without considering the effects of CSAPR were as follows:

		September 30,			September 30,			September 30,			September 30,			September 30,
	2011(1)			2012			2013			2014			2015
Power		8391	%		8481	%		3835	%		3633	%		1025	%
Fuel		9193	%		7873	%		5350	%		—	%		—	%

(1) Percentages represent the period from ~~May~~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.

48 56

~~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.

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 Mid-Atlantic 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, the CFTC recently 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 ~~three~~six months ended ~~March~~June 3130, 2011, we invested $1943 million for capital expenditures, primarily related to maintenance capital expenditures. At ~~March~~June 3130, 2011, we have invested $1.52521 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 ~~project~~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.

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

	April 1, 2011
		September 30,		September 30,
	through
	July 1, 2011throughDecember 31, 2011		2012
	December 31,
	2011		2012
	(in millions)
Maryland Healthy Air Act	$	~~154~~153	$	—
Other environmental		6—		510
Maintenance		3015		3436
Other construction		4437		7
Total	$	~~234~~205	$	4653

Environmental Matters

Refer to “Environmental Matters” 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.

~~Three~~58 ~~Months Ended March 31, 2011 Compared to Three Months Ended March 31, 2010~~

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

Consolidated Financial Performance

We reported net ~~income~~losses of $317 million and $~~439~~233 million during the three months ended ~~March~~June 3130, 2011 and 2010, respectively. The change in net income/loss is detailed as follows:

	Three Months Ended
		September 30,			September 30,			September 30,
	March 31,						Increase/
	Three Months EndedJune 30,						Increase/(Decrease)
	2011			2010			~~(Decrease)~~
	~~(in millions)~~			(in millions)
Gross margin:
Energy	$	6147		$	9278		$	(31	)
Contracted and capacity		7766			8985			(1219	)
Realized value of hedges		6366			5774			6(8	)
Total realized gross margin		~~201~~179			~~238~~237			(3758	)
Unrealized gross margin		(3912	)		~~346~~(317	)		~~(385~~305	)
Total gross margin (excluding depreciation and amortization)		~~162~~167			~~584~~(80	)		~~(422~~247	)
Operating expenses:
Operations and maintenance—nonaffiliate		62			65			(3	)
Operations and maintenance		101			70			31
Operations and maintenance—affiliate		4042			4847			(85	)
Depreciation and amortization		2930			3336			(46	)
Gain on sales of assets, net—affiliate		—			(21	)		21
Total operating expenses		~~131~~173			~~144~~152			~~(13~~21	)
Operating income		31			440			(409	)
Operating loss		(6	)		(232	)		226
Other income (expense), net:
Interest expense, net		—(1	)		(1—	)		1
Total other expense, net		—			(1	)		1
Other, net		—			(1	)		(1	)
Net income	$	31		$	439		$	(408	)
Total other expense, net		(1	)		(1	)		—
Net loss	$	(7	)	$	(233	)	$	226

Realized Gross Margin. During the three months ended ~~March~~June 3130, 2011, our realized gross margin decrease of $37 58 million was principally a result of the following:

• 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; ~~and~~

• a decrease of $1219 million in contracted and capacity primarily as a result of a decrease in capacity prices;, ~~partially~~ offset in part by an increase in capacity volumes; and

• ana ~~increase~~decrease of $68 million in realized value of hedges primarily as a result of ana ~~increase~~decrease in our ~~coal~~power hedges resulting from prices, offset in part by aan ~~decrease~~increase in our ~~power~~coal hedges primarily resulting from prices.

50 59

• unrealized losses of $3912 million during the three months ended ~~March~~June 3130, 2011, which included $5460 million associated with the reversal of previously recognized unrealized gains from power and fuel contracts that settled during the period, ~~partially~~ offset by a $1548 million net increase in the value of hedge contracts for future periods. The increase in value primarily related to decreases in forward power and natural gas prices and ~~increases~~an increase in forward coal prices; and

• unrealized ~~gains~~losses of $~~346~~317 million during the three months ended ~~March~~June 3130, 2010, which included a $~~396~~203 million net ~~increase~~decrease in the value of hedge contracts for future periods primarily related to ~~decreases~~increases in forward power prices and ~~natural~~the ~~gas~~recognition ~~prices,~~of ~~partially~~many ~~offset~~of byour coal agreements at fair value beginning in the second quarter of 2010. The $50317 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 ~~decrease~~increase of $13 21 million was principally a result of the following:

• aan ~~decrease~~increase of $1126 million in operations and maintenance expense primarily as a result of a ~~decrease~~$30 million accrual for remediation costs at our Maryland ash facilities (which includes a tentative $1.9 million civil penalty), litigation costs for major project disputes, net of recoveries and an increase in outage expenses. ~~incurred~~The ~~during~~increase in operations and maintenance expense was partially offset by a decrease of $12 million as a result of the ~~three~~repeal ~~months~~of ~~ended~~the ~~March~~Montgomery 31County CO2 levy, ~~2011~~including ~~compared~~$8 million related to refund received in the ~~same~~third ~~period~~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; ~~and~~offset in part by

• a decrease of $46 million in depreciation and amortization expense primarily as a result of a ~~decrease~~reduction in the carrying value of the Dickerson and Potomac River generating facilities as a result of impairment losses taken in the fourth quarter of 2010~~; offset in part by~~.

• a decrease of $2 million in gain on sales of assets primarily related to emissions allowances sold to third parties in 2010.

Operating Statistics

Our power generation volumes during the three months ended ~~March~~June 3130, 2011 (in gigawatt hours) ~~was~~ 3was 2,~~546~~ 883 compared to 43,~~033~~403 during the same period in 2010. See “Operating Statistics” in “Results of Operations—GenOn Americas Generation” above for additional details on power generation volumes.

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

Consolidated Financial Performance

We reported net income of $24 million and $206 million during the six months ended June 30, 2011 and 2010, respectively. The change in net income is detailed as follows:

		September 30,			September 30,			September 30,
	Six Months Ended June 30,						Increase/ (Decrease)
	2011			2010			Increase/ (Decrease)
	(in millions)
Gross margin:
Energy	$	108		$	170		$	(62	)
Contracted and capacity		143			174			(31	)
Realized value of hedges		129			131			(2	)

Total realized gross margin		380			475			(95	)
Unrealized gross margin		(51	)		29			(80	)

Total gross margin (excluding depreciation and amortization)		329			504			(175	)

Operating expenses:
Operations and maintenance		163			135			28
Operations and maintenance—affiliate		82			95			(13	)
Depreciation and amortization		59			69			(10	)
Gain on sales of assets, net—affiliate		—			(3	)		3

Total operating expenses		304			296			8

Operating income		25			208			(183	)

Other income (expense), net:
Interest expense, net		(1	)		(1	)		—
Other, net		—			(1	)		(1	)

Total other expense, net		(1	)		(2	)		(1	)

Net income	$	24		$	206		$	(182	)

Realized Gross Margin. During the six months ended June 30, 2011, our realized gross margin decrease of $95 million was principally a result of the following:

•

a decrease of $62 million in energy, primarily as a result of a decrease in generation volumes 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;

•

a decrease of $31 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 $2 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.

•

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 gains of $29 million during the six months ended June 30, 2010, which included a $193 million net increase in the value of hedge contracts for future periods primarily related to decreases in forward power and natural gas prices and also included the recognition of many of our coal agreements at fair value beginning in the second quarter of 2010. The increase in value was partially offset by $164 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 $8 million was principally a result of the following:

•

an increase of $15 million in operations and maintenance expense primarily as a result of a $30 million accrual for remediation costs at our Maryland generating facilities (which includes a tentative $1.9 million civil penalty) and litigation costs for major project disputes, net of recoveries. The increase in operations and maintenance expense is partially offset by a decrease of $10 million as a result of the repeal of the Montgomery County CO₂ levy, including $8 million related to refund received in the third quarter of 2011 of CO₂ levies paid in 2010, a reduction in outage expense and a decrease in allocated overhead costs as a result of a change in the allocation methodology as a result of the Merger; and

•

a decrease of $3 million in gain on sales of assets primarily related to emissions allowances sold to third parties in 2010; offset in part by

•

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 taken in the fourth quarter of 2010.

Operating Statistics

Our power generation volumes during the six months ended June 30, 2011 (in gigawatt hours) was 6,429 compared to 7,436 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 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 ~~March~~ June 3130, 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.

51At June 30, 2011, we had $53 million of cash, which amount was available under the operating leases for distribution to GenOn North America.

At the ~~March 31,~~performance ~~2011,~~of weour ~~had~~power ~~$131 million~~generating ~~of cash~~facilities, ~~which~~including ~~amount~~interruptions ~~was~~in ~~available~~operations ~~under~~or ~~the~~curtailment ~~operating leases~~of ~~for~~operations ~~distribution~~ to ~~GenOn~~comply ~~North~~with ~~America~~environmental restrictions.

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 ~~three~~six months ended ~~March~~June 3130, 2011, were $1943 million. We estimate our capital expenditures for the period ~~April~~July 1, 2011 through December 31, 2012 will be $~~280~~ 258 million. See “Capital Expenditures and Capital Resources” for further discussion of our capital expenditures.

Operating Leases. We lease 100% ~~interest~~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 ~~during~~and $48 million for both the three and six months ended ~~March~~June 3130, 2011 and 2010, respectively.

Debt Obligations, Off-Balance Sheet Arrangements and Contractual Obligations

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

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 ~~from continuing operations~~ decreased $3292 million for the ~~three~~six months ended ~~March~~ June 3130, 2011, compared to the same period in 2010, primarily as a result of the following:

• Realized gross margin. A decrease in cash provided of $45107 million in 2011, compared to the same period in 2010, (excluding a decrease in non-cash lower of cost or market fuel inventory ~~adjustments~~adjustment of $812 million ~~in 2010)~~. See “Results of Operations” in Item 2 for additional discussion of our performance in 2011 as compared to the same period in 2010; and

~~The~~• ~~decrease~~Inventories. An increase in cash ~~provided~~used byof ~~operating~~$20 ~~activities~~million ~~was~~primarily ~~partially~~as ~~offset~~a byresult ~~the~~of ~~following:~~ larger volumes of coal purchased at higher prices in 2011 as compared to 2010.

•The ~~Operating expenses. A~~ decrease in cash ~~used~~provided ~~related to lower operations~~ and ~~maintenance~~increase ~~expense of $9 million. See “Results of Operations”~~ in ~~Item~~cash 2used ~~for~~by ~~additional~~operating ~~discussion~~activities ofwas partially ~~our~~offset ~~performance~~by ~~in 2011 compared to~~ the ~~same~~following: ~~period in 2010; and~~

• ~~Other~~Net ~~operating~~accounts ~~assets~~receivables and ~~liabilities~~accounts payables. AAn ~~decrease~~increase in cash ~~used~~provided of $419 million primarily related to ~~changes~~a decrease in ~~other~~power ~~operating~~prices ~~assets~~ and ~~liabilities.~~generation volumes in 2011 compared to the same period in 2010; and

52 • Other operating assets and liabilities. A decrease in cash used of $15 million related to changes in other operating assets and liabilities.

Investing Activities. Net cash used in investing activities increased by $8646 million for the ~~three~~ six months ended ~~March~~June 3130, 2011, compared to the same period in 2010. This difference was primarily a result of the following:

•

• Proceeds from sale of assets. A decrease in cash provided of $34 million primarily related to the sale of ~~emission~~emissions ~~credits~~allowances in 2010; partially offset by

• Capital expenditures. A decrease in cash used of $60101 million primarily as a result of payments related to our Maryland scrubber projects in 2010.

Financing Activities. Net cash used in financing activities increased by $2545 million for the ~~three~~ six months ended ~~March~~June 3130, 2011, compared to the same period in 2010. This difference was primarily a result of $95 million received from the redemption of Series A preferred stock held by GenOn Mid-Atlantic in 2010 offset by $100 million distributed to our member in 2011 compared to $75150 million distributed in 2010.

53 64

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

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

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Filing Compare · GENON MID-ATLANTIC, LLC