Genon Mid-atlantic 10-Q 2011 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2011

OR

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

For the transition period from                      to                     

Commission File Number: 333-63240

GenOn Americas Generation, LLC

(Exact Name of Registrant as Specified in Its Charter)

51-0390520

(I.R.S. Employer

Identification No.)

Commission File Number: 333-61668

GenOn Mid-Atlantic, LLC

(Exact Name of Registrant as Specified in Its Charter)

58-2574140

(I.R.S. Employer

Identification No.)

Delaware

(State or Other Jurisdiction of

Incorporation or Organization)

1000 Main Street,

Houston, Texas

(Address of Principal Executive Offices)

77002

(Zip Code)

(832) 357-3000

(Registrant’s Telephone Number, Including Area Code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. (As a voluntary filer not subject to filing requirements, the registrant nevertheless filed all reports which would have been required to be filed by Section 15(d) of the Exchange Act during the preceding 12 months had the registrant been required to file reports pursuant to Section 15(d) of the Securities Exchange Act of 1934 solely as a result of having registered debt securities under the Securities Act of 1933.)

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

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

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

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

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

(Do not check if a smaller reporting company)

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

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

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

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

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

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

TABLE OF CONTENTS

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

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

i

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

ii

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

GenOn Energy Holdings	GenOn Energy Holdings, Inc. (formerly known as Mirant Corporation) and, except where the context indicates otherwise, its subsidiaries.
GenOn Energy Management	GenOn Energy Management, LLC (formerly known as Mirant Energy Trading, LLC).
GenOn Energy Services	GenOn Energy Services, LLC (formerly known as Mirant Services, LLC).
GenOn Kendall	GenOn Kendall, LLC (formerly known as Mirant Kendall, LLC).
GenOn Marsh Landing	GenOn Marsh Landing, LLC (formerly known as Mirant Marsh Landing, LLC).
GenOn Mid-Atlantic	GenOn Mid-Atlantic, LLC (formerly known as Mirant Mid-Atlantic, LLC) and, except where the context indicates otherwise, its subsidiaries.
GenOn North America	GenOn North America, LLC (formerly known as Mirant North America, LLC).
GenOn Potomac River	GenOn Potomac River, LLC (formerly known as Mirant Potomac River, LLC).
HAP	Hazardous Air Pollutant.
Hudson Valley Gas	Hudson Valley Gas Corporation.
intermediate generating units	Units designed to satisfy system requirements that are greater than baseload and less than peaking.
ISO	Independent system operator.
ISO-NE	Independent System Operator-New England.
LIBOR	London InterBank Offered Rate.
MDE	Maryland Department of the Environment.
Merger	The merger completed on December 3, 2010 pursuant to the Merger Agreement.
Merger Agreement	The agreement by and among Mirant Corporation, RRI Energy, Inc. and RRI Energy Holdings, Inc. dated as of April 11, 2010.
Mirant	GenOn Energy Holdings, Inc. (formerly known as Mirant Corporation) and, except where the context indicates otherwise, its subsidiaries.
MW	Megawatt.
MWh	Megawatt hour.
NAAQS	National Ambient Air Quality Standards.
net generating capacity	Net summer capacity.
NOV	Notice of violation.
NOx	Nitrogen oxides.
NPDES	National pollutant discharge elimination system.
NYISO	New York Independent System Operator.
NYMEX	New York Mercantile Exchange.
OTC	Over-the-counter.
peaking generating units	Units designed to satisfy demand requirements during the periods of greatest or peak load on the system.
PG&E	Pacific Gas & Electric Company.

iv

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.

v

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;

vi

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

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

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

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

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

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

• more stringent environmental laws and regulations (including the cumulative effect of many such regulations) that restrict our ability or render it uneconomic to operate our assets, including regulations related to air emissions;

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

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

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

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

• 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.

viii

PART I

FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

GENON AMERICAS GENERATION, LLC AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

		September 30,			September 30,			September 30,			September 30,
	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(in millions)
Operating revenues (including unrealized gains (losses) of $(12) million, $(231) million, $(107) million and $132 million, respectively)	$	715		$	244		$	1,253		$	1,124
Operating revenues—affiliate (including unrealized gains (losses) of $(2) million, $0, $8 million and $0, respectively)		2			—			13			—
Total operating revenues		717			244			1,266			1,124
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, $0, $0 and $0, respectively)		330			1			500			4
Total cost of fuel, electricity and other products		468			272			803			479
Gross Margin (excluding depreciation and amortization)		249			(28	)		463			645
Operating Expenses:
Operations and maintenance		118			93			197			182
Operations and maintenance—affiliate		59			72			119			142
Depreciation and amortization		42			50			82			99
(Gain) loss on sales of assets, net		1			(1	)		1			(3	)
Total operating expenses		220			214			399			420
Operating Income (Loss)		29			(242	)		64			225
Other Income (Expense), net:
Interest expense		(21	)		(49	)		(51	)		(99	)
Other, net		—			(1	)		(23	)		(2	)
Total other expense, net		(21	)		(50	)		(74	)		(101	)
Net Income (Loss)	$	8		$	(292	)	$	(10	)	$	124

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

1

GENON AMERICAS GENERATION, LLC AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

		September 30,			September 30,
	June 30, 2011			December 31, 2010
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents	$	279		$	514
Funds on deposit		349			949
Receivables		306			363
Receivables—affiliate		42			4
Notes receivable—affiliate		147			—
Derivative contract assets		777			1,288
Derivative contract assets—affiliate		39			5
Inventories		239			295
Prepaid expenses and other current assets		107			124
Total current assets		2,285			3,542
Property, plant and equipment, gross		3,976			3,946
Accumulated depreciation and amortization		(940	)		(869	)
Property, Plant and Equipment, net		3,036			3,077
Noncurrent Assets:
Intangible assets, net		98			101
Derivative contract assets		564			689
Derivative contract assets—affiliate		17			3
Prepaid rent		398			348
Debt issuance costs, net		6			12
Other		41			41
Total noncurrent assets		1,124			1,194
Total Assets	$	6,445		$	7,813
LIABILITIES AND MEMBER’S EQUITY
Current Liabilities
Current portion of long-term debt	$	4		$	1,389
Accounts payable and accrued liabilities		440			527
Payable—affiliate		282			54
Notes payable—affiliate		24			—
Derivative contract liabilities		662			1,130
Derivative contract liabilities—affiliate		24			3
Other		13			8
Total current liabilities		1,449			3,111
Noncurrent Liabilities:
Long-term debt, net of current portion		864			866
Derivative contract liabilities		87			173
Derivative contract liabilities—affiliate		16			—
Other		120			90
Total noncurrent liabilities		1,087			1,129
Commitments and Contingencies
Member’s Equity:
Member’s interest		3,909			3,573
Total member’s equity		3,909			3,573
Total Liabilities and Member’s Equity	$	6,445		$	7,813

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

2

GENON AMERICAS GENERATION, LLC AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY (UNAUDITED)

		September 30,
	Member’s Interest
	(in millions)
Balance, December 31, 2010	$	3,573
Net loss		(10	)
Distribution to member		(100	)
Capital contributions		446
Balance, June 30, 2011	$	3,909

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

3

GENON AMERICAS GENERATION, LLC AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

			September 30,			September 30,
		Six Months Ended June 30,
		2011			2010
		(in millions)
Cash Flows from Operating Activities:
Net income (loss)		$	(10	)	$	124
Adjustments to reconcile net income (loss) and changes in other operating assets and liabilities to net cash provided by operating activities:
Depreciation and amortization			82			104
(Gain) loss on sales of assets, net			1			(3	)
Net changes in derivative contracts			70			(12	)
Lower of cost or market inventory adjustments			1			20
Loss on early extinguishment of debt			23			—
Funds on deposit			(120	)		7
Changes in other operating assets and liabilities			218			(87	)
Total adjustments			275			29
Net cash provided by operating activities			265			153
Cash Flows from Investing Activities:
Capital expenditures			(47	)		(155	)
Proceeds from the sales of assets			4			3
Restricted funds on deposit, net			723			—
Issuance of notes receivable—affiliate			(147	)		—
Net cash provided by (used in) investing activities	��		533			(152	)
Cash Flows from Financing Activities:
Redemption of preferred stock			—			95
Repayments of long-term debt			(1,403	)		(69	)
Issuance of notes payable—affiliate			26			—
Distribution to member			(100	)		—
Capital contributions			444			—
Net cash provided by (used in) financing activities			(1,033	)		26
Net Increase (Decrease) in Cash and Cash Equivalents			(235	)		27
Cash and Cash Equivalents, beginning of period			514			404
Cash and Cash Equivalents, end of period		$	279		$	431
Supplemental Disclosures:
Cash paid for interest, net of amounts capitalized		$	59		$	92
Cash refunds received for income taxes		$	1		$	—
Supplemental Disclosure for Non-Cash Financing Activities:
Conversion to equity of notes payable to affiliate		$	2		$	—

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

4

GENON MID-ATLANTIC, LLC AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

		September 30,			September 30,			September 30,			September 30,
	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
	(in millions)
Operating revenues (including unrealized gains (losses) of $6 million, $(97) million, $(39) million and $103 million, respectively)	$	45		$	(39	)	$	44		$	219
Operating revenues—affiliate (including unrealized gains (losses) of $(33) million, $(108) million, $(39) million and $30 million, respectively)		235			209			534			690
Total operating revenues		280			170			578			909
Cost of fuel, electricity and other products (including unrealized (gains) losses of $0, $0, $0 and $0, respectively)		2			5			9			9
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
Total cost of fuel, electricity and other products		113			250			249			405
Gross Margin (excluding depreciation and amortization)		167			(80	)		329			504
Operating Expenses:
Operations and maintenance		101			70			163			135
Operations and maintenance—affiliate		42			47			82			95
Depreciation and amortization		30			36			59			69
Gain on sales of assets, net—affiliate		—			(1	)		—			(3	)
Total operating expenses		173			152			304			296
Operating Income (Loss)		(6	)		(232	)		25			208
Other Income (Expense), net:
Interest expense		(1	)		—			(1	)		(1	)
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

5

GENON MID-ATLANTIC, LLC AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

		September 30,			September 30,
	June 30, 2011			December 31, 2010
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents	$	53		$	202
Funds on deposit		147			2
Receivables		23			21
Receivables—affiliate		146			169
Derivative contract assets		155			162
Derivative contract assets—affiliate		136			245
Inventories		152			122
Prepaid rent		96			96
Other		3			11
Total current assets		911			1,030
Property, plant and equipment, gross		3,079			3,046
Accumulated depreciation and amortization		(567	)		(513	)
Property, Plant and Equipment, net		2,512			2,533
Noncurrent Assets:
Intangible assets, net		71			71
Derivative contract assets		474			516
Derivative contract assets—affiliate		44			97
Prepaid rent		398			348
Other		29			31
	��
Total noncurrent assets		1,016			1,063
Total Assets	$	4,439		$	4,626
LIABILITIES AND MEMBER’S EQUITY
Current Liabilities:
Current portion of long-term debt	$	4		$	4
Accounts payable and accrued liabilities		64			63
Payable—affiliate		129			114
Derivative contract liabilities		8			18
Derivative contract liabilities—affiliate		135			231
Contract retention liability		130			132
Other		15			8
Total current liabilities		485			570
Noncurrent Liabilities:
Long-term debt, net of current portion		16			18
Derivative contract liabilities—affiliate		41			94
Other		81			52
Total noncurrent liabilities		138			164
Commitments and Contingencies
Member’s Equity:
Member’s interest		3,816			3,892
Total member’s equity		3,816			3,892
Total Liabilities and Member’s Equity	$	4,439		$	4,626

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

6

GENON MID-ATLANTIC, LLC AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY (UNAUDITED)

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

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

7

GENON MID-ATLANTIC, LLC AND SUBSIDIARIES

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

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

		September 30,			September 30,
	Six Months Ended June 30,
	2011			2010
	(in millions)
Cash Flows from Operating Activities:
Net income	$	24		$	206
Adjustments to reconcile net income and changes in other operating assets and liabilities to net cash provided by operating activities:
Depreciation and amortization		59			69
Gain on sales of assets, net—affiliate		—			(3	)
Net changes in derivative contracts		51			(29	)
Lower of cost or market inventory adjustments		—			12
Changes in other operating assets and liabilities		5			(24	)
Total adjustments		115			25
Net cash provided by operating activities		139			231
Cash Flows from Investing Activities:
Capital expenditures		(43	)		(144	)
Proceeds from the sales of assets		—			4
Restricted funds on deposit, net		(143	)		—
Net cash used in investing activities		(186	)		(140	)
Cash Flows from Financing Activities:
Redemption of preferred stock		—			95
Repayment of long-term debt		(2	)		(2	)
Distribution to member		(100	)		(150	)
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	$	53		$	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

8

GENON AMERICAS GENERATION, LLC AND SUBSIDIARIES

GENON MID-ATLANTIC, LLC AND SUBSIDIARIES

COMBINED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1.      Description of Business and Accounting and Reporting Policies

Background

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

GenOn Mid-Atlantic operates and owns or leases 5,204 MW of net electric generating capacity in the Washington, D.C. area. GenOn Mid-Atlantic’s electric generating capacity is part of the 9,724 MW of net electric generating capacity of GenOn Americas Generation. GenOn Mid-Atlantic’s generating facilities serve the Eastern PJM markets. The PJM ISO operates the largest centrally dispatched control area in the United States.

We are Delaware limited liability companies and indirect wholly-owned subsidiaries of GenOn. GenOn Mid-Atlantic is a wholly-owned subsidiary of GenOn North America and an indirect wholly-owned subsidiary of GenOn Americas Generation. The chart below is a summary representation of our organizational structure and reportable segments and is not a complete organizational chart of GenOn.

(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.

9

Basis of Presentation

The consolidated interim financial statements and notes (interim financial statements) are unaudited, omit certain disclosures and should be read in conjunction with our audited consolidated financial statements and notes in our 2010 Annual Report on Form 10-K. These interim financial statements have been prepared in accordance with GAAP from records maintained by us. All significant intercompany accounts and transactions have been eliminated in consolidation. The interim financial statements reflect all normal recurring adjustments necessary, in management’s opinion, to present fairly our financial position and results of operations for the reported periods. Amounts reported for interim periods may not be indicative of a full year period because of seasonal fluctuations in demand for electricity and energy services, changes in commodity prices, and changes in regulations, timing of maintenance and other expenditures, dispositions, changes in interest expense and other factors.

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

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

• estimating the fair value of certain derivative contracts;

• estimating the useful lives of long-lived assets;

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

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

• estimating losses to be recorded for contingent liabilities.

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

10

Funds on Deposit

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

GenOn Americas Generation

		September 30,		September 30,
	June 30, 2011		December 31, 2010
	(in millions)
Cash collateral posted(1)	$	240	$	120
GenOn Mid-Atlantic restricted cash(2)		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		383		986
Less: Current funds on deposit		349		949
Total noncurrent funds on deposit	$	34	$	37

(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

		September 30,		September 30,
	June 30, 2011		December 31, 2010
	(in millions)
GenOn Mid-Atlantic restricted cash(1)	$	143	$	—
Cash collateral posted(2)		32		32
Total current and noncurrent funds on deposit		175		32
Less: Current funds on deposit		147		2
Total noncurrent funds on deposit	$	28	$	30

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

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

Inventories

Inventories were comprised of the following:

GenOn Americas Generation

		September 30,		September 30,
	June 30, 2011		December 31, 2010
	(in millions)
Fuel inventory:
Coal	$	79	$	52
Fuel oil		52		136
Other		4		1
Materials and supplies		73		72
Purchased emissions allowances		31		34
Total inventories	$	239	$	295

11

GenOn Mid-Atlantic

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

During the three months ended June 30, 2011 and 2010, GenOn Americas Generation recorded $1 million and $12 million, respectively, and during the six months ended June 30, 2011 and 2010, GenOn Americas Generation recorded $1 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:

		September 30,		September 30,			September 30,			September 30,
	Three Months Ended June 30,					Six Months Ended June 30,
	2011		2010			2011			2010
	(in millions)
Total interest costs	$	21	$	50		$	52		$	102
Capitalized and included in property, plant and equipment, net		—		(1	)		(1	)		(3	)
Interest expense	$	21	$	49		$	51		$	99

The amounts of capitalized interest above include interest accrued. During the three months ended June 30, 2011 and 2010, cash paid for interest was $60 million and $93 million, respectively, of which $1 million and $3 million, respectively, were capitalized. During the six months ended June 30, 2011 and 2010, cash paid for interest was $60 million 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:

12

• 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. 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.

13

GenOn Americas Generation

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

		September 30,		September 30,		September 30,			September 30,			September 30,
	Derivative Contract Assets				Derivative Contract Liabilities						Net Derivative Contract Assets (Liabilities)
	Current		Long-Term		Current			Long-Term
	(in millions)
June 30, 2011
Commodity Contracts:
Asset management	$	367	$	554	$	(221	)	$	(76	)	$	624
Trading activities		449		27		(465	)		(27	)		(16	)
Total derivatives	$	816	$	581	$	(686	)	$	(103	)	$	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:

		September 30,			September 30,			September 30,			September 30,
	Three 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	$	(25	)	$	15		$	(218	)	$	(109	)
Realized(1)(2)		63			(13	)		91			(11	)
Total asset management	$	38		$	2		$	(127	)	$	(120	)
Trading Commodity Contracts:
Unrealized	$	11		$	—		$	(13	)	$	—
Realized(1)(2)		(1	)		—			(21	)		—
Total trading	$	10		$	—		$	(34	)	$	—
Total derivatives	$	48		$	2		$	(161	)	$	(120	)

(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.

14

		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:

		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)		(19	)		(28	)		(47	)
Natural gas		(24	)		25			1
Fuel oil		2			(2	)		—
Coal		7			5			12

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

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

15

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:

		September 30,			September 30,		September 30,			September 30,
	Three 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	$	(27	)	$	15	$	(205	)	$	(112	)
Realized(1)(2)		61			—		86			(4	)
Total asset management	$	34			15		(119	)		(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.

		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	$	(78	)	$	27	$	133	$	(104	)
Realized(1)(2)		122			—		161		(4	)
Total asset management	$	44			27		294		(108	)

(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.

16

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.

17

Most of the fair value of our derivative contract assets and liabilities is based on observable quoted prices from exchanges and indicative quoted prices from independent brokers in active markets that regularly facilitate our transactions. An active market is considered to have transactions with sufficient frequency and volume to provide pricing information on an ongoing basis. We think that these prices represent the best available information for valuation purposes. In determining the fair value of derivative contract assets and liabilities, we use third-party market pricing where available. For transactions classified in Level 1 of the fair value hierarchy, we use the unadjusted published settled prices on the valuation date. For transactions classified in Level 2 of the fair value hierarchy, we value these transactions using indicative quoted prices from independent brokers or other widely-accepted valuation methodologies. Transactions are classified in Level 2 if substantially all (greater than 90%) of the fair value can be corroborated using observable market inputs such as transactable broker quotes. In accordance with the exit price objective under the fair value measurements accounting guidance, the fair value of our derivative contract assets and liabilities is determined based on the net underlying position of the recorded derivative contract assets and liabilities using bid prices for assets and ask prices for liabilities. The quotes that we obtain from brokers are non-binding in nature, but are from brokers that typically transact in the market being quoted and are based on their knowledge of market transactions on the valuation date. We typically obtain multiple broker quotes as of the valuation date that extend for the tenor of the underlying contracts for each delivery location. The number of quotes that we can obtain depends on the relative liquidity of the delivery location on the valuation date. If multiple broker quotes are received for a contract, we use an average of the quoted bid or ask prices. If only one broker quote is received for a delivery location and it cannot be validated through other external sources, we will assign the quote to a lower level within the fair value hierarchy. In some instances, we may combine broker quotes for a liquid delivery hub with broker quotes for the price spread between the liquid delivery hub and the delivery location under the contract. We also may apply interpolation techniques to value monthly strips if broker quotes are only available on a seasonal or annual basis. We perform validation procedures on the broker quotes at least monthly. The validation procedures include reviewing the quotes for accuracy and comparing them to our internal price curves. In certain instances, we may exclude from consideration a broker quote if it is a clear outlier and other quotes are obtained. At June 30, 2011, we obtained broker quotes for 100% of our delivery locations classified in Level 2 of the fair value hierarchy.

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

18

GenOn Americas Generation

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

		September 30,		September 30,		September 30,		September 30,
	June 30, 2011
	Level 1(1)		Level 2(1) (2)		Level 3		Total Fair Value
	(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.

19

		September 30,		September 30,		September 30,		September 30,
	December 31, 2010
	Level 1(1)		Level 2(1) (2)		Level 3		Total Fair Value
	(in millions)
Derivative contract assets:
Commodity Contracts
Asset Management:
Power	$	1	$	1,022	$	2	$	1,025
Fuel		4		3		33		40
Total Asset Management		5		1,025		35		1,065
Trading Activities		530		385		5		920
Total derivative contract assets	$	535	$	1,410	$	40	$	1,985
Derivative contract liabilities:
Commodity Contracts
Asset Management:
Power	$	12	$	248	$	4	$	264
Fuel		18		—		99		117
Total Asset Management		30		248		103		381
Trading Activities		533		389		3		925
Total derivative contract liabilities	$	563	$	637	$	106	$	1,306
Interest-bearing funds(3)	$	547	$	—	$	—	$	547

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

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

(3) Represents investments in money market funds and is included in cash and cash equivalents, funds on deposit and other noncurrent assets in the consolidated balance sheet. GenOn Americas Generation had $508 million of interest-bearing funds included in cash and cash equivalents, $2 million included in funds on deposit and $37 million included in other noncurrent assets.

20

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.

21

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	)

22

GenOn Mid-Atlantic

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

		September 30,		September 30,		September 30,		September 30,
	June 30, 2011
	Level 1(1)		Level 2(1) (2)		Level 3		Total Fair Value
	(in millions)
Derivative contract assets:
Commodity Contracts
Asset Management:
Power	$	1	$	774	$	4	$	779
Fuel		—		1		29		30
Total derivative contract assets	$	1	$	775	$	33	$	809
Derivative contract liabilities:
Commodity Contracts
Asset Management:
Power	$	11	$	103	$	—	$	114
Fuel		—		—		70		70
Total derivative contract liabilities	$	11	$	103	$	70	$	184
Interest-bearing funds(3)	$	223	$	—	$	—	$	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 six months ended June 30, 2011.

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

(3) Represents investments in money market funds and are included in cash and cash equivalents, funds on deposit and other noncurrent assets in the consolidated balance sheet. GenOn Mid-Atlantic had $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.

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

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

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

(1) 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.

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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	$	5	$	16	$	21	$	—	$	(113	)	$	(113	)
Gains (losses) included in income (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets still held at June 30	$	5	$	16	$	21	$	—	$	(113	)	$	(113	)

		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	)

Counterparty Credit Concentration Risk

We are exposed to the default risk of the counterparties with which we transact. We manage our credit risk by entering into master netting agreements and requiring counterparties to post cash collateral or other credit enhancements based on the net exposure and the credit standing of the counterparty. We also have non-collateralized power hedges entered into by GenOn Mid-Atlantic. These transactions are senior unsecured obligations of GenOn Mid-Atlantic and the counterparties and do not require either party to post cash collateral for initial margin or for securing exposure as a result of changes in power or natural gas prices. Our credit valuation adjustment on derivative contract assets was $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:

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GenOn Americas Generation

		September 30,		September 30,		September 30,		September 30,		September 30,
	June 30, 2011
Credit Rating Equivalent	Gross Exposure Before Collateral(1)		Net Exposure Before Collateral(2)		Collateral(3)		Exposure Net of Collateral		% of Net Exposure
	(dollars in millions)
Clearing and Exchange	$	536	$	1	$	1	$	—
Investment Grade:
Financial institutions		702		654		—		654		76	%
Energy companies		254		136		2		134		15	%
Non-investment Grade:
Energy companies		19		19		5		14		2	%
No External Ratings:
Internally-rated investment grade		38		38		—		38		4	%
Internally-rated non-investment grade		24		24		—		24		3	%
Total	$	1,573	$	872	$	8	$	864		100	%

		September 30,		September 30,		September 30,		September 30,		September 30,
	December 31, 2010
Credit Rating Equivalent	Gross Exposure Before Collateral(1)		Net Exposure Before Collateral(2)		Collateral(3)		Exposure Net of Collateral		% of Net Exposure
	(dollars in millions)
Clearing and Exchange	$	987	$	39	$	39	$	—
Investment Grade:
Financial institutions		806		707		—		707		78	%
Energy companies		337		130		2		128		14	%
Non-investment Grade:
Energy companies		15		15		—		15		2	%
No External Ratings:
Internally-rated investment grade		34		27		—		27		3	%
Internally-rated non-investment grade		26		26		—		26		3	%
Total	$	2,205	$	944	$	41	$	903		100	%

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

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

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

26

GenOn Mid-Atlantic

		September 30,		September 30,		September 30,		September 30,		September 30,
	June 30, 2011
Credit Rating Equivalent	Gross Exposure Before Collateral(1),(4)		Net Exposure Before Collateral(2)		Collateral(3)		Exposure Net of Collateral		% of Net Exposure
	(dollars in millions)
Investment Grade:
Financial institutions	$	656	$	645	$	—	$	645		95	%
Non-investment Grade:
Energy companies		12		12		—		12		2	%
No External Ratings:
Internally-rated non-investment grade		24		24		—		24		3	%
Total	$	692	$	681	$	—	$	681		100	%

		September 30,		September 30,		September 30,		September 30,		September 30,
	December 31, 2010
Credit Rating Equivalent	Gross Exposure Before Collateral(1),(4)		Net Exposure Before Collateral(2)		Collateral(3)		Exposure Net of Collateral		% of Net Exposure
	(dollars in millions)
Investment Grade:
Financial institutions	$	714	$	695	$	—	$	695		95	%
Non-investment Grade:
Energy companies		13		13		—		13		2	%
No External Ratings:
Internally-rated non-investment grade		25		25		—		25		3	%
Total	$	752	$	733	$	—	$	733		100	%

(1) 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.

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

27

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 did not have any financial instruments with credit-risk-related contingent features in a net liability position.

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

Fair Values of Other Financial Instruments (GenOn Americas Generation)

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

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

		September 30,		September 30,		September 30,		September 30,
	June 30, 2011				December 31, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Liabilities:
Long and short-term debt(1)	$	868	$	861	$	2,255	$	2,272

_________________

(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:

		September 30,			September 30,			September 30,		September 30,			September 30,			September 30,
	June 30, 2011								December 31, 2010
	Stated Interest Rate(1)			Long-term			Current		Stated Interest Rate(1)			Long-term			Current
	(in millions, except interest rates)
Bonds and Notes:
GenOn Americas Generation:
Senior unsecured notes, due 2011(2)		—		$	—		$	—		8.30	%	$	—		$	535
Senior unsecured notes, due 2021		8.50	%		450			—		8.50			450			—
Senior unsecured notes, due 2031		9.125			400			—		9.125			400			—
Unamortized debt discounts, net		—			(2	)		—		—			(2	)		—
GenOn North America:
Senior notes, due 2013(3)		—			—			—		7.375			—			850
GenOn Mid-Atlantic:
GenOn Chalk Point capital lease, due 2011 to 2015		8.19			16			4		8.19			18			4
Total				$	864		$	4				$	866		$	1,389

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

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

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

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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 generally conducts its business through various intermediate holding companies, including GenOn Americas Generation, and various operating subsidiaries, which enter into contracts as part of their business activities. In certain instances, the contractual obligations of such subsidiaries are guaranteed by, or otherwise supported by, GenOn or another of its subsidiaries, including by letters of credit issued under the GenOn credit facilities.

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

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

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

		September 30,		September 30,
	June 30, 2011		December 31, 2010
	(in millions)
Letters of credit—rent reserves(1)	$	98	$	101
Letters of credit—energy trading and marketing activities(1)		47		63
Letters of credit—other operating activities(1)		33		31
Surety bonds		8		7
Total	$	186	$	202

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

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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

		September 30,		September 30,		September 30,		September 30,
	Three Months Ended June  30,				Six Months Ended June  30,
	2011		2010		2011		2010
	(in millions)
Cost of fuel, electricity and other products—affiliate	$	3	$	1	$	5	$	4
Operations and maintenance expense—affiliate		35		40		67		80
Total	$	38	$	41	$	72	$	84

GenOn Mid-Atlantic

		September 30,		September 30,		September 30,		September 30,
	Three Months Ended June  30,				Six Months Ended June  30,
	2011		2010		2011		2010
	(in millions)
Cost of fuel, electricity and other products—affiliate	$	3	$	1	$	5	$	4
Operations and maintenance expense—affiliate		20		24		38		49
Total	$	23	$	25	$	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 June 30, 2011, GenOn Americas Generation recorded a reduction to operations and maintenance expense—affiliate of $8 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.

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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 unaudited condensed consolidated statements of operations. Amounts due to and from GenOn Energy Management under the Power Sale, Fuel Supply and Services Agreement are recorded as a net payable—affiliate or accounts receivable—affiliate, as appropriate. Substantially all energy marketing overhead expenses are allocated to GenOn’s operating subsidiaries. During the three months ended June 30, 2011 and 2010, GenOn Mid-Atlantic incurred $1 million and $3 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 June 30, 2011 and 2010, we incurred the following in costs under these arrangements, which are included in operations and maintenance expense—affiliate in our unaudited condensed consolidated statements of operations:

		September 30,		September 30,		September 30,		September 30,
	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
	(in millions)
GenOn Americas Generation	$	32	$	32	$	65	$	62
GenOn Mid-Atlantic	$	21	$	20	$	42	$	39

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

Notes Receivable from Affiliate and Notes Payable to Affiliate (GenOn Americas Generation)

In January 2011, GenOn Americas Generation and certain of its subsidiaries began participating in separate intercompany cash management programs whereby cash balances at GenOn Americas Generation and the respective participating subsidiaries were transferred to central concentration accounts to fund working capital and other needs of the respective participants. The balances under this program are reflected as notes receivable from affiliate and notes payable to affiliate. The notes are due on demand and accrue interest, which is payable quarterly, at the yield of a short term Treasury security fund. At June 30, 2011 GenOn Americas Generation had current notes receivable from GenOn Energy Holdings of $145 million related to its intercompany cash management program. During the three and six months ended June 30, 2011, GenOn Americas Generation earned an insignificant amount of interest income related to the notes receivable. At June 30, 2011 GenOn Americas Generation had current notes payable to GenOn Energy Holdings of $24 million related to its intercompany cash management program. During the three and six months ended June 30, 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 June 30, 2011 and 2010, were $14 million and $16 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.

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.

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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 $(8)��million and $(77) million during the three months ended June 30, 2011 and 2010, respectively, and $10 million 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 at June 30, 2011.

GenOn Mid-Atlantic

GenOn Mid-Atlantic and its subsidiaries are limited liability companies and are not subject to United States federal or state income taxes. As such, GenOn Mid-Atlantic is treated as though it were a branch or division of GenOn Americas Generation’s parent, GenOn Americas, for income tax purposes, and not as a separate taxpayer. GenOn Americas and GenOn are directly responsible for income taxes related to GenOn Mid-Atlantic’s operations. If GenOn Mid-Atlantic were to be allocated income taxes attributable to its operations, the pro forma income tax provision (benefit) attributable to income before taxes would be $(2) million and $(93) million during the three months ended June 30, 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 $212 million as of June 30, 2011.

7.      Segment Reporting (GenOn Americas Generation)

In conjunction with the Merger, GenOn Americas Generation began reporting in five segments in the fourth quarter of 2010: Eastern PJM, Northeast, California, Energy Marketing and Other Operations. Prior to the Merger, GenOn Americas Generation had four reportable segments: Mid-Atlantic, Northeast, California and Other Operations. Amounts for 2010 were reclassified to conform to the current segment presentation. The segments were determined based on how the business is managed and align with the information provided to the chief operating decision maker for purposes of assessing performance and allocating resources. Generally, GenOn Americas Generation’s segments are engaged in the sale of electricity, capacity, ancillary and other energy services from their generating facilities in hour-ahead, day-ahead and forward markets in bilateral and ISO markets. GenOn Americas Generation also engages in proprietary trading and fuel oil management. Operating revenues consist of (a) power generation revenues, (b) contracted and capacity revenues, (c) fuel sales and proprietary trading revenues and (d) power hedging revenues.

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,

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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

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

________________

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

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

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

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

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

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

(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.

(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.

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		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.

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	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.

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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. 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. 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. Currently, $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 July 2010 the opacity readings from the facility exceeded the applicable limits in several six minute intervals. In a third NOV, the Virginia DEQ asserted that GenOn Potomac River combusted used oils in the facility’s boilers without authority under its permit and received one shipment of coal that exceeded the maximum ash content allowed under its permit. In a fourth NOV, issued in February 2011, the Virginia DEQ asserted that in January 2011 GenOn Potomac River used a sorbent for the removal of SO₂ that was not permitted. We settled these alleged violations for $276,000 with the Virginia DEQ in May 2011.

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

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

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Maryland 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, but it has reached its capacity. We dispose of fly ash from our Morgantown and Chalk Point facilities at Brandywine. We dispose of fly ash from our Dickerson station at Westland. As described below, the MDE has sued us regarding Faulkner and Brandywine and threatened to sue regarding Westland. The MDE also has threatened not to renew the water discharge permits for all three facilities.

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.

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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. The FERC found that no party had violated the RPM provisions of PJM’s tariff and that the prices determined during the auctions were in accordance with the tariff’s provisions. The RPM Buyers filed a request for rehearing, which the FERC denied in June 2009. On a subsequent appeal, in February 2011, the United States Court of Appeals for the District of Columbia Circuit affirmed the FERC rulings. None of the RPM Buyers asked the D.C. Circuit to reconsider its decision and no party filed for a writ of certiorari. The deadlines for these procedures have passed.

9.      Subsequent Events

In July 2011, the EPA released its prepublication version of the regulations to replace the CAIR with the CSAPR starting in 2012. CSAPR will be finalized when published in the Federal Register, which we expect to occur in August 2011. The CSAPR will establish limitations on 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.

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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 June 30, 2011, our generating capacity was 54% in PJM, 26% in NYISO and ISO-NE and 20% in CAISO.

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

Merger of Mirant and RRI Energy

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

Hedging Activities

We hedge economically a substantial portion of our Eastern PJM coal-fired baseload generation and certain of our other generation. We generally do not hedge our intermediate and peaking units for tenors greater than 12 months. We hedge economically using products which we expect to be effective to mitigate the price risk of our generation. However, as a result of market liquidity limitations, our hedges often are not an exact match for the generation being hedged, and, we have some risks resulting from price differentials for different delivery points. In addition, we have risks for implied differences in heat rates when we hedge economically power using natural gas. Currently, a significant portion of our hedges are financial swap transactions between GenOn Mid-Atlantic and financial counterparties that are senior unsecured obligations of such parties and do not require either party to post cash collateral either for initial margin or for securing exposure as a result of changes in power or natural gas prices. At July 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		92	%		81	%		33	%		30	%		23	%
Fuel		93	%		71	%		47	%		—	%		—	%

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

The Dodd-Frank Act, which was enacted in July 2010 in response to the global financial crisis, increases the regulation of transactions involving OTC derivative financial instruments. The statute provides that standardized swap transactions between dealers and large market participants will have to be cleared and traded on an exchange or electronic platform. Although the provisions and legislative history of the Dodd-Frank Act provide strong evidence that market participants, such as GenOn Americas Generation, which utilize OTC derivative financial

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

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

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

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

Capital Expenditures and Capital Resources

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

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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

We decide to invest capital for environmental controls based on relatively certain regulations and the expected economic returns on the capital. Whether we elect to install additional controls as a result of the CSAPR, pending HAPs regulation or other regulations remains uncertain and depends on, among other things, the content and timing of regulations, the expected effect of regulations on wholesale power prices and allowance prices, as well as the cost of controls, profitability of our generating facilities, market conditions at the time and the likelihood of CO₂ regulation.

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

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

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

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Cross-State Air Pollution Rule. In 2005, the EPA promulgated the CAIR, which established SO₂ and NO_x cap-and-trade programs applicable directly to states and indirectly to generating facilities in the eastern United States. The NO_x cap-and-trade program has two components, an annual program and an Ozone Season program. The CAIR SO₂ cap-and-trade program builds off the existing acid rain cap-and-trade program but requires generating facilities to surrender twice as many allowances to cover emissions from 2010 through 2014 and approximately three times as many allowances starting in 2015. Florida, Illinois, Maryland, Mississippi, New Jersey, New York, Ohio, Pennsylvania and Virginia are subject to the CAIR’s SO₂ trading program and both its NO_x trading programs. Massachusetts is subject only to the CAIR’s Ozone Season NO_x trading program. These cap-and-trade programs were to be implemented in two phases, with the first phase going into effect in 2009 for NO_x and 2010 for SO₂ and more stringent caps going into effect in 2015. On July 11, 2008, the D.C. Circuit inState of North Carolina v. Environmental Protection Agency issued an opinion that would have vacated the CAIR. Various parties filed requests for rehearing with the D.C. Circuit and on December 23, 2008, the D.C. Circuit issued a second opinion in which it granted rehearing only to the extent that it remanded the case to the EPA without vacating the CAIR. Accordingly, the CAIR will remain effective until it is replaced by a rule consistent with the D.C. Circuit’s opinions, which as described below will take place in January 2012.

In 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

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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

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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.

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

Consolidated Financial Performance

We reported net income of $8 million and a net loss of $292 million during the three months ended June 30, 2011 and 2010, respectively. The change in net income/loss is detailed as follows:

		September 30,			September 30,			September 30,
	Three Months Ended June 30,						Increase/ (Decrease)
	2011			2010
	(in millions)
Gross margin:
Energy	$	80		$	96		$	(16	)
Contracted and capacity		105			138			(33	)
Realized value of hedges		63			78			(15	)
Total realized gross margin		248			312			(64	)
Unrealized gross margin		1			(340	)		341
Total gross margin (excluding depreciation and amortization)		249			(28	)		277
Operating expenses:
Operations and maintenance		118			93			25
Operations and maintenance—affiliate		59			72			(13	)
Depreciation and amortization		42			50			(8	)
(Gain) loss on sales of assets, net		1			(1	)		2
Total operating expenses		220			214			6
Operating income (loss)		29			(242	)		271
Other income (expense), net:
Interest expense, net		(21	)		(49	)		(28	)
Other, net		—			(1	)		(1	)
Total other expense, net		(21	)		(50	)		(29	)
Net income (loss)	$	8		$	(292	)	$	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

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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 gains of $1 million during the three months ended June 30, 2011, which included a $57 million net increase in the value of hedge and proprietary trading contracts for future periods, offset by $56 million associated with the reversal of previously recognized unrealized gains from power and fuel contracts that settled during the period; and

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

Operating Expenses.Our operating expenses increase of $6 million was principally a result of the following:

• an increase of $12 million in operations and maintenance expense primarily as a result of 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. 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 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; offset in part by

• a decrease of $8 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.

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

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Operating Statistics

The following table summarizes power generation volumes by segment:

		September 30,		September 30,		September 30,			September 30,
	Three Months Ended June 30,				Increase/ (Decrease)			Increase/ (Decrease)
	2011		2010
	(in gigawatt hours)
Eastern PJM:
Baseload		2,612		3,062		(450	)		(15	)%
Intermediate		242		277		(35	)		(13	)%
Peaking		29		64		(35	)		(55	)%
Total Eastern PJM		2,883		3,403		(520	)		(15	)%
Northeast:
Baseload		374		355		19			5	%
Intermediate		47		49		(2	)		(4	)%
Peaking		1		1		—			—	%
Total Northeast		422		405		17			4	%
California:
Intermediate		41		88		(47	)		(53	)%
Total California		41		88		(47	)		(53	)%
Total		3,346		3,896		(550	)		(14	)%

The total decrease in power generation volumes during the three 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 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.

Northeast.An increase in our Northeast baseload 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.

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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

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

• unrealized losses of $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.

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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
	(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.

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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.

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 June 30, 2011, GenOn Mid-Atlantic satisfied the restricted payments test. As a result of certain lien restrictions in its lease documentation, GenOn Mid-Atlantic has reserved $143 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.

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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-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 six months ended June 30, 2011, were $46 million. We estimate our capital expenditures, excluding capitalized interest, for the period July 1, 2011 through December 31, 2012 will be $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 June 30, 2011, we had $240 million of posted cash collateral and GenOn had $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 and regulation of energy contracts.

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

		September 30,		September 30,
	June 30, 2011		December 31, 2010
	(in millions)
Cash collateral posted—energy trading and marketing	$	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)		47		63
Letters of credit—other operating activities(1)		33		31
Surety bonds		8		7
Total	$	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

There have been no material changes outside the ordinary course of business to our debt obligations, off-balance sheet arrangements and contractual obligations from those disclosed in our 2010 Annual Report on Form 10-K and note 3 to our interim financial statements.

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Historical Cash Flows

Operating Activities. Our cash provided by operating activities is affected by seasonality, changes in energy prices and fluctuations in our working capital requirements. Net cash provided by operating activities increased $112 million for the six months ended June 30, 2011, compared to the same period in 2010, primarily as a result of the following:

• Inventories.A decrease in cash used of $145 million primarily related to changes in fuel oil inventory in 2011 compared to the same period in 2010;

• Net accounts receivables and accounts payables. An increase in cash provided of $121 million primarily as a result of an increase in payables to affiliates resulting from transactions initiated by GenOn Energy Management on behalf of affiliated companies. See note 5 to our interim financial statements;

• Interest Expense. A decrease in cash used of $43 million related to lower interest expense primarily resulting from the repayment of GenOn North America senior notes in December 2010 and the GenOn North America term loan in January 2011; and

• Other operating assets and liabilities. A decrease in cash used of $49 million related to changes in other operating assets and liabilities.

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

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

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

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

• Withdrawals from restricted funds on deposit. An increase in cash provided of $866 million primarily related to funds received from the GenOn debt financing on December 3, 2010, which were subsequently placed in restricted deposits at December 31, 2010. The withdrawal of cash was used to repay the GenOn North America long-term debt. See note 3 to our interim financial statements; and

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

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

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

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

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

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• 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.

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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 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		91	%		81	%		35	%		33	%		25	%
Fuel		93	%		73	%		50	%		—	%		—	%

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

The Dodd-Frank Act, which was enacted in July 2010 in response to the global financial crisis, increases the regulation of transactions involving OTC derivative financial instruments. The statute provides that standardized swap transactions between dealers and large market participants will have to be cleared and traded on an exchange or electronic platform. Although the provisions and legislative history of the Dodd-Frank Act provide strong evidence that market participants, such as GenOn Mid-Atlantic, which utilize OTC derivative financial instruments to hedge commercial risks are not to be subject to these clearing and exchange-trading requirements, it is uncertain what the final implementing regulations will provide. The effect of the Dodd-Frank Act on our business depends in large measure on pending rulemaking proceedings of the CFTC, the SEC and the federal banking regulators. Under the Dodd-Frank Act, entities defined as “swap dealers” and “major swap participants” (“SD/MSPs”) will face costly requirements for clearing and posting margin, as well as additional requirements for reporting and business conduct.

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

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

Moreover, the CFTC issued a proposal establishing recordkeeping and reporting requirements for swaps entered into before July 21, 2010, whose terms had not expired as of that date, and data relating to swaps entered into on or after July 21, 2010 and prior to the compliance date specified in the CFTC’s final swap data reporting rules. Whilst GenOn 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 six months ended June 30, 2011, we invested $43 million for capital expenditures, primarily related to maintenance capital expenditures. At June 30, 2011, we have invested $1.521 billion of the $1.674 billion that was budgeted for capital expenditures related to compliance with the Maryland Healthy Air Act. Provisions in the construction contracts for the scrubbers at three of our largest Maryland coal-fired units provide for certain payments to be made after final completion of the projects. The current budget of $1.674 billion continues to represent our best estimate of the total capital expenditures for compliance with the Maryland Healthy Air Act. See note 8 to our interim financial statements for further discussion of the scrubber contract litigation.

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The following table details the expected timing of payments for our estimated capital expenditures 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		—		10
Maintenance		15		36
Other construction		37		7
Total	$	205	$	53

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

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.

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

Consolidated Financial Performance

We reported net losses of $7 million and $233 million during the three months ended June 30, 2011 and 2010, respectively. The change in net income/loss is detailed as follows:

		September 30,			September 30,			September 30,
	Three Months Ended June 30,						Increase/ (Decrease)
	2011			2010
				(in millions)
Gross margin:
Energy	$	47		$	78		$	(31	)
Contracted and capacity		66			85			(19	)
Realized value of hedges		66			74			(8	)
Total realized gross margin		179			237			(58	)
Unrealized gross margin		(12	)		(317	)		305
Total gross margin (excluding depreciation and amortization)		167			(80	)		247
Operating expenses:
Operations and maintenance		101			70			31
Operations and maintenance—affiliate		42			47			(5	)
Depreciation and amortization		30			36			(6	)
Gain on sales of assets, net—affiliate		—			(1	)		1
Total operating expenses		173			152			21
Operating loss		(6	)		(232	)		226
Other income (expense), net:
Interest expense, net		(1	)		—			1
Other, net		—			(1	)		(1	)
Total other expense, net		(1	)		(1	)		—
Net loss	$	(7	)	$	(233	)	$	226

Realized Gross Margin.During the three months ended June 30, 2011, our realized gross margin decrease of $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;

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

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

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

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

• unrealized losses of $317 million during the three months ended June 30, 2010, which included a $203 million net decrease in the value of hedge contracts for future periods primarily related to increases in forward power prices and the recognition of many of our coal agreements at fair value beginning in the second quarter of 2010. The $317 million also included $114 million associated with the reversal of previously recognized unrealized gains from power and fuel contracts that settled during the period.

Operating Expenses.Our operating expenses increase of $21 million was principally a result of the following:

• an increase of $26 million in operations and maintenance expense primarily as a result of a $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. The increase in operations and maintenance expense was partially offset by a decrease of $12 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 and a decrease in allocated overhead costs as a result of a change in the allocation methodology as a result of the Merger; offset in part by

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

Operating Statistics

Our power generation volumes during the three months ended June 30, 2011 (in gigawatt hours) was 2,883 compared to 3,403 during the same period in 2010. See “Operating Statistics” in “Results of Operations—GenOn Americas Generation” above for additional details on power generation volumes.

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

• unrealized losses of $51 million during the six months ended June 30, 2011, which included $114 million associated with the reversal of previously recognized unrealized gains from power and fuel contracts that settled during the period, offset by a $63 million net increase in the value of hedge contracts for future periods. The increase in value was primarily related to decreases in forward power and natural gas prices and increases in forward coal prices; and

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• 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 June 30, 2011, except for amounts held in bank accounts to cover upcoming payables, all of our cash and cash equivalents were invested in AAA-rated United States Treasury money market funds.

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

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

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

Uses of Funds

Our requirements for liquidity and capital resources, other than for the day-to-day operation of our generating facilities, are significantly influenced by capital expenditures and payments under our operating leases.

Capital Expenditures. Our capital expenditures during the six months ended June 30, 2011, were $43 million. We estimate our capital expenditures for the period July 1, 2011 through December 31, 2012 will be $258 million. See “Capital Expenditures and Capital Resources” for further discussion of our capital expenditures.

Operating Leases.We lease 100% interests in both the Dickerson and Morgantown baseload units and associated property through 2029 and 2034, respectively, and have an option to extend the leases. Any extensions of the respective leases would be for less than 75% of the economic useful life of the facility, as measured from the beginning of the original lease term through the end of the proposed remaining lease term. We are accounting for these leases as operating leases. Although there is variability in the scheduled payment amounts over the lease term, we recognize rent expense for these leases on a straight-line basis in accordance with GAAP. Rent expense under our leases was $24 million and $48 million for both the three and six months ended June 30, 2011 and 2010, respectively.

Debt Obligations, Off-Balance Sheet Arrangements and Contractual Obligations

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

Historical Cash Flows

Operating Activities. Our cash provided by operating activities is affected by seasonality, changes in energy prices and fluctuations in our working capital requirements. Net cash provided by operating activities decreased $92 million for the six months ended June 30, 2011, compared to the same period in 2010, primarily as a result of the following:

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

• Inventories.An increase in cash used of $20 million primarily as a result of larger volumes of coal purchased at higher prices in 2011 as compared to 2010.

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

• Net accounts receivables and accounts payables.An increase in cash provided of $19 million primarily related to a decrease in power prices and generation volumes in 2011 compared to the same period in 2010; and

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

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Investing Activities.Net cash used in investing activities increased by $46 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:

• 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

• Proceeds from sale of assets. A decrease in cash provided of $4 million primarily related to the sale of emissions allowances in 2010; partially offset by

• Capital expenditures. A decrease in cash used of $101 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 $45 million for the six months ended June 30, 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 $150 million distributed in 2010.

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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.

ITEM 4. CONTROLS AND PROCEDURES

Effectiveness of Disclosure Controls and Procedures

As required by Exchange Act Rule 13a-15(b), our management, including our Principal Executive Officer and our Principal Financial Officer, conducted an assessment of the effectiveness of the design and operation of our disclosure controls and procedures (as defined by Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of June 30, 2011. Based upon this assessment, our management concluded that, as of June 30, 2011, the design and operation of these disclosure controls and procedures were effective.

Changes in Internal Control over Financial Reporting

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

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PART II

ITEM 1. LEGAL PROCEEDINGS

See note 8 to our interim unaudited condensed consolidated financial statements.

ITEM 6. EXHIBITS

GenOn Americas Generation

Exhibit No.	Exhibit Name
3.1	Certificate of Formation for Mirant Americas Generation, LLC, filed with the Delaware Secretary of State dated at November 1, 2001 (Incorporated herein by reference to Exhibit 3.1 to Registrant’s Quarterly Report on Form 10-Q filed November 9, 2001, File No. 333-63240)
3.2	Certificate of Amendment to Certificate of Formation of Mirant Americas Generation, LLC, filed with the Delaware Secretary of State dated at December 3, 2010 (Incorporated herein by reference to Exhibit 3.2A1 to Registrant’s Annual Report on Form 10-K filed March 1, 2011, File No. 333-63240)
3.2	Second Amended and Restated Limited Liability Agreement for GenOn Americas Generation, LLC dated December 3, 2010 (Incorporated herein by reference to Exhibit 3.3A1 to Registrant’s Annual Report on Form 10-K filed March 1, 2011, File No. 333-63240)

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Exhibit No.	Exhibit Name
4.1	GenOn Americas Generation agrees to furnish to the Securities and Exchange Commission, upon request, a copy of any instrument defining the rights of holders of long-term debt of GenOn Americas Generation and all of its consolidated subsidiaries for which financial statements are required to be filed with the Securities and Exchange Commission.
31.1A1*	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under Securities Exchange Act of 1934
31.2A3*	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under Securities Exchange Act of 1934
32.1A1*	Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(b))
32.2A3*	Certification of the Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(b))
101*	Interactive Data File

* Asterisk indicates exhibits filed herewith.

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GenOn Mid-Atlantic

Exhibit No.	Exhibit Name
3.1	Certificate of Formation of Southern Energy Mid-Atlantic, LLC, dated at July 12, 2000 (Incorporated herein by reference to Exhibit 3.1 to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)
3.2	Certificate of Amendment to Certificate of Formation of Mirant Mid-Atlantic, LLC, filed with the Delaware Secretary of State dated at January 20, 2011 (Incorporated herein by reference to Exhibit 3.2A2 to Registrant’s Annual Report on Form 10-K filed March 1, 2011, File No. 333-63240)
3.3	Second Amended and Restated Limited Liability Company Agreement of GenOn Mid-Atlantic, LLC, dated January 20, 2011 (Incorporated herein by reference to Exhibit 3.2A2 to Registrant’s Annual Report on Form 10-K filed March 1, 2011, File No. 333-63240)
4.1	GenOn Mid-Atlantic agrees to furnish to the Securities and Exchange Commission, upon request, a copy of any instrument defining the rights of holders of long-term debt of GenOn Mid-Atlantic.
31.1A2*	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under Securities Exchange Act of 1934
31.2A4*	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under Securities Exchange Act of 1934
32.1A2*	Certification of the Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(b))
32.2A4*	Certification of the Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(b))
101*	Interactive Data File

* Asterisk indicates exhibits filed herewith.

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SIGNATURES

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

	GENON AMERICAS GENERATION, LLC
Date: August 8, 2011	By:	/s/    THOMAS C. LIVENGOOD
		Thomas C. Livengood
		Senior Vice President and Controller (Duly Authorized Officer and Principal Accounting Officer)

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SIGNATURES

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

	GENON MID-ATLANTIC, LLC
Date: August 8, 2011	By:	/s/    THOMAS C. LIVENGOOD
		Thomas C. Livengood
		Senior Vice President and Controller (Duly Authorized Officer and Principal Accounting Officer)

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