UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2011

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

For the transition period from to

GenOn Americas Generation, LLC

(Exact Name of Registrant as Specified in Its Charter)

Commission File Number: 333-63240

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

GenOn Mid-Atlantic, LLC

(Exact Name of Registrant as Specified in Its Charter)

Commission File Number: 333-61668

58-2574140 (I.R.S. Employer Identification No.)

Delaware

(State or Other Jurisdiction of Incorporation or Organization of All Registrants)

1000 Main Street,
Houston, Texas 77002

(Address of Principal Executive Offices, Including Zip Code, of All Registrants)

(832) 357-3000

(Registrant’s telephone number, including area code)

None

Securities registered pursuant to Section 12(b) of the Act

None

Securities registered pursuant to Section 12(g) of the Act

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act.

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

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

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

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

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

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

GenOn Americas Generation, LLC		x
GenOn Mid-Atlantic, LLC		x

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

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

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

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

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

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

This combined Form 10-K is separately filed by GenOn Americas Generation, LLC and GenOn Mid-Atlantic, LLC. Information contained in this combined Form 10-K 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.

We have not incorporated by reference any information into this Form 10-K from any annual report to securities holders, proxy statement or prospectus filed pursuant to 424(b) or (c) of the Securities Act.

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

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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.

baseload generating units		units designed to satisfy minimum baseload requirements of the system and produce electricity at an essentially constant rate and run continuously.

CAIR		Clean Air Interstate Rule.

CAISO		California Independent System Operator.

capacity		amount of energy that could have been generated at continuous full-power operation during the period.

CARB		California Air Resources Board.

CenterPoint		CenterPoint Energy, Inc. and its subsidiaries, on and after August 31, 2002, and Reliant Energy, Incorporated and its subsidiaries, prior to August 31, 2002.

CERCLA		Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980.

CFTC		Commodity Futures Trading Commission.

Clean Air Act		Federal Clean Air Act.

Clean Water Act		Federal Water Pollution Control Act.

Climate Protection Act		Massachusetts’ Global Warming Solutions Act.

CO2		carbon dioxide.

CPUC		California Public Utility Commission.

CSAPR		Cross-State Air Pollution Rule.

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

Companies		GenOn Americas Generation, LLC, GenOn Mid-Atlantic, LLC and their subsidiaries.

D.C. Circuit		the United States Court of Appeals for the District of Columbia Circuit.

Delta Noticing Parties		the Coalition for a Sustainable Delta, four water districts, and an individual.

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.

Exchange Ratio		right of Mirant Corporation stockholders to receive 2.835 shares of common stock of RRI Energy, Inc. in the Merger.

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FASB		Financial Accounting Standards Board.

FCM		forward capacity market administered by ISO-NE to procure capacity resources to meet forecasted demand and reserve requirements.

FERC		Federal Energy Regulatory Commission.

FGD		flue gas desulfurization emissions controls.

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.

GenOn Americas Generation		GenOn Americas Generation, LLC.

GenOn California North		GenOn California North, LLC.

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

GenOn Delta		GenOn Delta, LLC.

GenOn Energy Holdings		GenOn Energy Holdings, Inc. (formerly known as Mirant Corporation) and, except where the context indicates otherwise, its subsidiaries.

GenOn Energy Management		GenOn Energy Management, LLC.

GenOn Energy Services		GenOn Energy Services, LLC.

GenOn Kendall		GenOn Kendall, LLC.

GenOn Marsh Landing		GenOn Marsh Landing, LLC.

GenOn Mid-Atlantic		GenOn Mid-Atlantic, LLC and its subsidiaries, which include the baseload units at two generating facilities under operating leases.

GenOn North America		GenOn North America, LLC.

GenOn Potrero		GenOn Potrero, LLC.

HAPs		hazardous air pollutants.

IBEW		International Brotherhood of Electrical Workers.

intermediate generating units		units designed to satisfy system requirements that are greater than baseload and less than peaking.

IRC		Internal Revenue Code of 1986, as amended.

IRC §		IRC section.

ISO		independent system operator.

ISO-NE		Independent System Operator-New England.

LIBOR		London InterBank Offered Rate.

LTPP		Long Term Procurement Planning process by the CPUC.

MACT		maximum achievable control technology.

MADEP		Massachusetts’ Department of Environmental Protection.

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MAEEA		Massachusetts’ Executive Office of Energy and Environmental Affairs.

Maryland Greenhouse Gas Act		Greenhouse Gas Reduction Act of 2009.

MATS		Mercury and Air Toxics Standards.

MDE		Maryland Department of the Environment.

Merger		the merger completed on December 3, 2010 pursuant to 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.

NERC		North American Electric Reliability Council.

net generating capacity		net summer capacity.

NOL		net operating loss.

NOx		nitrogen oxides.

NPCC		Northeast Power Coordinating Council.

NPDES		national pollutant discharge elimination system.

NYISO		New York Independent System Operator.

NYMEX		New York Mercantile Exchange.

OTC		over-the-counter.

Ozone Season		the period between May 1 and September 30 of each year.

peaking generating units		units designed to satisfy demand requirements during the periods of greatest or peak load on the system.

PEPCO		Potomac Electric Power Company.

PG&E		Pacific Gas & Electric Company.

PJM		PJM Interconnection, LLC.

Plan		the plan of reorganization that was approved in conjunction with Mirant Corporation’s and our 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.

RFC		Reliability First Corporation.

RFP		request for proposal.

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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.

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

Stone & Webster		Stone & Webster, Inc.

SWD		surface water discharge.

VaR		value at risk.

Virginia DEQ		Virginia Department of Environmental Quality.

WECC		Western Electric Coordinating Council.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

In addition to historical information, the information presented in this combined Form 10-K includes forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. These statements involve known and unknown risks and uncertainties and relate to our revenues, income, capital structure and other financial items, future events, our future financial performance or our projected business results and our view of economic and market conditions. In some cases, one can identify forward-looking statements by words such as “may,” “will,” “should,” “could,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “expect,” “intend,” “seek,” “plan,” “think,” “anticipate,” “estimate,” “predict,” “target,” “potential” or “continue” or the negative of these terms or comparable words.

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

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

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

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

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

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

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

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

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

· strikes, union activity or labor unrest;

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

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

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

· hazards customary to the power generation industry, including those listed in this cautionary statement and elsewhere in this Form 10-K, and the possibility that we may not have adequate insurance to cover losses resulting from such hazards or the inability of our insurers to provide agreed upon coverage;

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

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

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

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

· the cost and availability of emissions allowances;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

· our 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.

In addition to the discussion of certain risks in Item 7, “Management’s Narrative Analysis of the Results of Operations and Financial Condition” and the accompanying combined notes to GenOn Americas Generation, LLC’s and GenOn Mid-Atlantic, LLC’s consolidated financial statements, other factors that could affect our future performance are set forth in Item 1A, “Risk Factors.” Our filings and other important information are also available on our investor relations page at www.genon.com/investors.aspx.

Certain Terms

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

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Merger

On December 3, 2010, Mirant and RRI Energy completed their Merger. Mirant merged with a wholly-owned subsidiary of RRI Energy, with Mirant surviving the Merger as a wholly-owned subsidiary of RRI Energy. In connection with the all-stock, tax-free Merger, RRI Energy changed its name to GenOn Energy, Inc., Mirant stockholders received a fixed ratio of 2.835 shares of GenOn common stock for each share of Mirant common stock, and Mirant changed its name to GenOn Energy Holdings.

Strategy

Our goal is to create long-term stockholder value across a broad range of commodity price environments. We intend to achieve this goal by:

Successfully integrating the companies and achieving annual cost savings targets. In connection with the Merger, GenOn announced an initial annual cost savings target of $150 million through reductions in corporate overhead and support costs. GenOn has achieved $160 million in such annual cost savings.

Leveraging operating and commercial expertise. We have substantial experience in the management, operation and optimization of a portfolio of diverse generating facilities. We operate our generating facilities safely, efficiently, and in an environmentally responsible manner to achieve optimal availability and performance to maximize cash flow.

Transacting to reduce variability in realized gross margin. We develop and execute appropriate hedging strategies to manage risks associated with the volatility in the price at which we sell power and in the prices of fuel, emissions allowances and other inputs required to produce such power. This includes hedging over multiple years to reduce the variability in realized gross margin from our expected generation. In addition, we will continue to sell capacity either bilaterally or through periodic auction processes, which provides a predictable and relatively stable stream of realized gross margin and cash flow.

Maintaining appropriate liquidity and capital structure. Through disciplined balance sheet management and maintaining adequate liquidity, we expect to be able to operate across a broad range of commodity price environments. At December 31, 2011, GenOn Americas Generation had approximately $267 million in total available cash and cash equivalents. See “Management’s Narrative Analysis of the Results of Operations and Financial Condition — Liquidity and Capital Resources” in Item 7 for information on our liquidity.

Investing capital prudently. Our capital investment decisions are focused on achieving an appropriate return on investment. Capital investments are evaluated independently and include:

· Participating in the development or acquisition of new facilities, such as our investment in the Marsh Landing generating facility;

· Maintaining our existing generating facilities for near and long-term availability; and

· Investing in our existing facilities to improve their competitive position, including capital investments for environmental controls.

Commercial Operations

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-cooperatives, other power generating companies and other load serving entities. Our commercial operations consist primarily of dispatching electricity, hedging the price of electricity we expect to generate, selling capacity, procuring and managing fuel and providing logistical support for the operation of our facilities (for example, by procuring transportation for coal and natural gas) as well as GenOn Americas Generation’s proprietary trading operations.

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We sell capacity either bilaterally or through periodic auction processes in each ISO and RTO market in which we participate. Our capacity sales primarily occur through the PJM RPM and ISO-NE FCM auctions, but also in CAISO, NYISO and other markets where we enter into agreements with counterparties. We expect that a substantial portion of our PJM capacity will continue to be sold in PJM up to three years in advance. Revenue from these capacity sales is determined by market rules designed to ensure regional reliability, encourage competition and reduce energy price volatility. These capacity sales provide an important source of predictable revenues for us over the contracted periods. For GenOn Americas Generation, at January 24, 2012, total projected contracted capacity and PPA revenues for which prices have been set for 2012 through 2015 are $1.2 billion. For GenOn Mid-Atlantic, at January 24, 2012, total projected contracted capacity and PPA revenues for which prices have been set for 2012 through 2015 are $855 million. Failure to meet our capacity commitments may result in a reduction to our capacity payments through penalties or charges.

As part of our strategy, we enter into economic hedges—forward sales of electricity and forward purchases of fuel and emissions allowances—to manage the risks associated with volatility in prices for electricity, fuel and emissions allowances and to achieve more predictable financial results. In addition, given the high correlation between natural gas prices and electricity prices in many of the markets in which we operate, we enter into forward sales of natural gas to hedge economically our exposure to changes in the price of electricity. We procure our hedges in OTC transactions or on exchanges where electricity, fuel and emissions allowances are broadly traded, or through specific transactions with buyers and sellers, using futures, forwards, swaps and options. Our hedges cover various periods, including several years.

See “Management’s Narrative Analysis of the Results of Operations and Financial Condition” in Item 7 of this Form 10-K for our aggregate hedge levels based on expected generation for 2012 to 2016. In addition, see Item 1A, “Risk Factors—Risks Related to Economic and Financial Market Conditions” for a discussion of the risks associated with implementation of the Dodd-Frank Act on our ability to hedge economically our generation, including potentially reducing liquidity in the energy and commodity markets and, if we are required to clear such transactions on exchanges or meet other requirements, by significantly increasing the collateral costs associated with such activities.

Power

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. 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.

Although standard industry OTC transactions make up a substantial portion of our economic hedge portfolio, at times we sell non-standard, structured products to customers, primarily financial institutions. These products include fixed load shapes, load following arrangements, heat rate options and financial or physical tolls.

GenOn Americas Generation’s California generating facilities typically operate under contracts for their capacity or energy. GenOn Delta has entered into agreements with PG&E to provide electricity from its natural gas-fired units in service at Contra Costa and Pittsburg. GenOn Delta entered into an agreement with PG&E in September 2009 for 674 MW at Contra Costa for the period from November 2011 through April 2013. At the end of the agreement, and subject to any necessary regulatory approvals, GenOn Delta has agreed to retire the Contra Costa facility. In addition, GenOn Delta entered into an agreement with PG&E in October 2010 for 1,159 MW at Pittsburg for three years commencing January 2011, with options for PG&E to extend the agreement for each of 2014 and 2015. Under the respective agreements, GenOn Delta will receive monthly capacity payments with bonuses and/or penalties based on heat rate and availability.

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Fuel

We enter into contracts of varying terms to secure appropriate quantities of fuel that meet the varying specifications of our generating facilities. For our coal-fired generating facilities, we purchase most of our coal from a small number of suppliers under contracts with terms of varying lengths, some of which extend to 2014. See note 1 to our consolidated financial statements for discussion of our coal agreement risk. For our oil-fired units, we typically purchase fuel from a small number of suppliers either in the spot market or under contracts with terms of varying lengths. For our natural gas-fired facilities, in addition to purchasing natural gas, we arrange for and schedule its transportation through pipelines. We sell excess fuel supplies to third parties.

We receive coal at our generating facilities primarily by rail. In addition, we can receive coal by barge at our Morgantown generating facility. We have a coal blending facility at our Morgantown generating facility that allows for greater flexibility of coal supply by allowing various coal qualities to be blended while also meeting emissions targets. We monitor coal supply and delivery logistics carefully but there are occasional interruptions of planned deliveries caused by weather, operational or transportation issues. Because of the risk of disruptions in our coal supply, we strive to maintain adequate targeted levels of coal inventories at our coal-fired facilities.

Emissions

Our commercial operations manage the acquisition and use of emissions allowances for our generating facilities. GenOn Americas Generation trades emissions allowances for SO2, NOx and CO2 and manages the risk surrounding emissions exposure in federal, state and regional compliance programs applicable to its generating facilities. Because of our investments in environmental controls made over the past 12 years to our existing generation fleet, GenOn Americas Generation’s NOx emissions have been reduced by approximately 89% and SO2 emissions have been reduced by approximately 95% from the 1990 levels. GenOn Mid-Atlantic’s NOx emissions have been reduced by approximately 86% and SO2 emissions have been reduced by approximately 94% from the 1990 levels. See “—Regulatory Environment—Environmental Regulation” for a discussion of major environmental controls investments we expect to make over the next ten years.

Coal Combustion Byproducts

Existing state and federal rules require the proper management and disposal of wastes and other materials. We produce byproducts from our coal-fired generating units, including ash and gypsum. We actively manage the current and planned disposition of each of these byproducts. All of our ash disposal facilities are dry landfills. Our disposal plan for ash includes land filling at our existing ash management facilities, purchasing and permitting additional disposal sites, using third parties to handle and dispose of the ash, and construction of an ash beneficiation facility at our Morgantown site to make the ash more suitable for sale to third parties for the production of concrete as well as other beneficial uses. We have constructed the ash beneficiation facility and expect the facility to begin commercial operations during the first half of 2012. Our disposal plan for gypsum includes selling it to third parties for use in the production of drywall and disposing of it in approved landfills. Currently, we expect to invest approximately $10 million in capital expenditures over the next five years for ash landfill modifications and expansions.

There is increased focus on the regulation of coal combustion products and, if the manner in which they are regulated changes, we may be required to change our management practices for these byproducts and/or incur additional costs. See note 9 to our consolidated financial statements for information regarding litigation and other contingencies with respect to our Maryland fly ash facilities.

Energy Marketing Segment

See “Management’s Narrative Analysis of the Results of Operations and Financial Condition—Our Business” for a discussion of the business of GenOn Americas Generation’s energy marketing segment.

The Dodd-Frank Act

The Dodd-Frank Act, which was enacted in July 2010, increases the regulation of transactions involving OTC derivative financial instruments. The statute provides that standardized swap transactions between dealers and large

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market participants will have to be cleared and traded on an exchange or electronic platform. Although the provisions and legislative history of the Dodd-Frank Act provide strong evidence that market participants, such as GenOn Americas Generation, which utilize OTC derivative financial instruments to hedge commercial risks are not to be subject to these clearing and exchange-trading requirements, it is uncertain what the final implementing regulations will provide. The effect of the Dodd-Frank Act on our business depends in large measure on pending rulemaking proceedings of the CFTC, the SEC and the federal banking regulators. Under the Dodd-Frank Act, entities defined as “swap dealers” and “major swap participants” (SD/MSPs) will face costly requirements for clearing and posting margin, as well as additional requirements for reporting and business conduct. The CFTC and SEC issued a proposed rulemaking to set final definitions for the terms “swap dealer” and “major swap participant” among others. Although we do not expect our commercial 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. It is possible that the final rule will not offer much clarity and the designation as an SD/MSP could be decided by facts and circumstance tests. We expect the final rule to be released in the first quarter of 2012.

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 federal banking regulators’ proposed capital requirements for SD/MSPs recommend significant and cash-dependent capital requirements for SD/MSPs. The cost of complying with these requirements may be passed through to and imposed on commercial end users indirectly and increase the cost of our hedging activities.

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, 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. Several ISO’s, including PJM, CAISO, ISO-NE and the NYISO, have recently filed the exemption application with the CFTC. If applied to our hedging activity, such regulations could considerably increase the transaction costs with respect to commodity options and Financial Transmission Rights.

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

Lastly, in October 2011, the CFTC adopted final rules on speculative position limits that will apply to 28 futures contracts and any economically equivalent futures, options and swaps. The rules also establish new reporting

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requirements for persons holding or controlling positions in certain referenced contracts in excess of particular limits and amend the scope of the bona fide hedging exemption. At this time, we do not expect the position limits to have a material effect on GenOn Americas Generation’s commercial activities.

Competitive Environment

The power generating industry is capital intensive and highly competitive. In addition, the wholesale power generation industry is highly fragmented compared to other commodity industries. There is wide variation in terms of the capabilities, resources, nature and identity of the companies with which we compete. Our competitors include regulated utilities, merchant energy companies, financial institutions and other companies. For a discussion of competitive factors see Item 1A, “Risk Factors.” Coal-fired, natural gas-fired, nuclear and hydroelectric generation currently account for approximately 43%, 25%, 19% and 8%, respectively, of the electricity produced in the United States. Other energy sources account for the remaining 5% of electricity produced.

Our large coal generating fleet is exposed to the relationship between the cost of production and the price of the power produced. This relationship, commonly referred to as the dark spread, fluctuates with the cost of coal and the price of power. We hedge economically a substantial portion of our Eastern PJM coal-fired baseload generation and certain of our other generation. We seek to hedge economically our output at varying levels several years in advance because the price of electricity is volatile. In addition, we enter into contracts to hedge economically our future needs of coal, which is our primary fuel. The prices for power and natural gas are low compared to several years ago. The energy gross margin from our generating facilities is negatively affected by these price levels. For that portion of the volumes of generation that we have hedged, we are generally economically neutral to subsequent changes in commodity prices because our realized gross margin will reflect the contractual prices of our power and fuel contracts. We continue to seek to add economic hedges to maintain projected levels of cash flows from operations for future periods and to help support continued compliance with the covenants in our debt and lease agreements.

Given the substantial time required to permit and construct new power plants, the process to add generating capacity must begin years in advance of anticipated growth in demand. A number of ISOs and RTOs, including those in markets in which we operate, have implemented capacity markets designed to provide forward prices for capacity that ensure that adequate resources are in place to meet the region’s demand. Over the last several years, very little new generation has been constructed as a result of the economic downturn and programs to reduce the demand for electricity which have resulted in a decrease in the rate at which the long-term demand for electricity is forecasted to grow. See “Regulatory Environment” later in this section for further discussion.

The costs to construct new generating facilities have been rising, and there is substantial environmental opposition to building either coal-fired or nuclear plants. We have sufficient room and infrastructure at many of our existing sites to increase significantly our generating capacity when market rules, prices and conditions warrant. In addition to reduced costs for developing new generation at existing sites because of our ownership of the land and our ownership of and/or access to infrastructure, regulators frequently prefer that new generation be added at existing sites (brownfield development) rather than at new sites (greenfield development). We continue to consider these and other investment opportunities.

Many of our generating facilities are located in or near metropolitan areas, including Boston, New York City, San Francisco and Washington, D.C. The supply-demand balance in some of these markets is forecasted to become constrained and increasingly dependent on power imported from other regions to sustain reliability. However, there are proposed upgrades to the transmission systems in some of the markets in which we operate that could mitigate the need for existing marginal generating capacity and for new generating capacity. Additionally, new facilities have been proposed or developed in some of these markets that will increase or have increased available sources of supply. To the extent that these upgrades are completed and new facilities are built, prices for electricity and capacity could be lower in some of our markets than they might otherwise be. Furthermore, the prices for power and natural gas remain at historically low levels. See “Commercial Operations.”

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Concern over the environmental impacts of climate change and fossil-fueled generating station air emissions has led to significant legislative and regulatory efforts at the state and federal level. The costs of compliance with such efforts could affect our ability to compete in the markets in which we operate, especially with our coal-fired generating facilities. See “Regulatory Environment” and “Environmental Regulation” for further discussion.

Seasonality

For information on the effect of seasonality on our business, see “Risk Factors” in Item 1A in this Form 10-K.

Regulatory Environment

Federal, State and Local Regulations

FERC. The electricity industry is regulated extensively at the federal, state and local levels. At the federal level, the FERC has exclusive jurisdiction under the Federal Power Act over sales of electricity at wholesale and the transmission of electricity in interstate commerce. Each of our subsidiaries that owns or leases a generating facility selling at wholesale or that markets electricity at wholesale is a “public utility” subject to the FERC’s jurisdiction under the Federal Power Act. These subsidiaries must comply with certain FERC reporting requirements and FERC-approved market rules and they are subject to FERC oversight of mergers and acquisitions, the disposition of facilities under the FERC’s jurisdiction and the issuance of securities.

The FERC has authorized our subsidiaries that are public utilities under the Federal Power Act to sell wholesale energy, capacity and certain ancillary services at market-based rates. The majority of the output of the generating facilities owned by our subsidiaries is sold pursuant to this market-based rate authorization. The FERC could revoke or limit our market-based rate authority if it were to determine that we possess insufficiently mitigated market power in a regional electricity market. Under the Natural Gas Act, GenOn Americas Generation’s subsidiary, GenOn Energy Management, that sells natural gas for resale is deemed by the FERC to have blanket certificate authority to undertake these sales at market-based rates.

The FERC requires that our public utility subsidiaries with market-based rate authority and our subsidiary with blanket certificate authority adhere to general rules against market manipulation as well as to certain market behavior rules and codes of conduct. If any of our subsidiaries were found to have engaged in market manipulation, the FERC has the authority to impose a civil penalty of up to $1 million per day per violation. In addition to the civil penalties, if any of our subsidiaries were to engage in market manipulation or violate the market behavior rules or codes of conduct, the FERC could require a disgorgement of profits related to the improper activity or could revoke the subsidiary’s market-based rate authority or blanket certificate authority. If the FERC were to revoke market-based rate authority, our affected public utility subsidiary would have to file a cost-based rate schedule for all or some of its sales of electricity at wholesale.

Our subsidiaries owning generating facilities have made such filings, and received such orders, as are necessary to obtain exempt wholesale generator status under the Public Utility Holding Company Act of 2005 and the FERC’s regulations thereunder. Provided all of our subsidiaries owning or leasing generating facilities continue to be exempt wholesale generators, or are qualifying facilities under the Public Utility Regulatory Policies Act of 1978, we and our intermediate holding companies owning direct or indirect interests in those subsidiaries will remain exempt from the accounting, record retention and reporting requirements that the Public Utility Holding Company Act of 2005 imposes on “holding companies.”

NERC. In 2006, the FERC certified NERC as the national energy reliability organization. NERC is responsible for the development and enforcement of mandatory reliability standards, including cyber-security standards, for the electric power system. Each of our subsidiaries selling electricity at wholesale is responsible for complying with the reliability standards in the region in which it operates. Assets that have been determined to be critical physical or cyber-security assets are not accessible via the internet. NERC has the ability to assess financial penalties for non-compliance with the reliability standards, which penalties can, depending on the nature of the non-compliance, be significant. In addition to complying with the NERC standards, each of our entities selling

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electricity at wholesale must comply with the reliability standards of the regional reliability council for the NERC region in which its sales occur.

State and Local. State and local regulatory authorities historically have overseen the distribution and sale of electricity at retail to the ultimate end user, as well as the siting, permitting and construction of generating and transmission facilities. Our existing generating facilities are subject to a variety of state and local regulations, including regulations regarding the environment, health and safety and maintenance and expansion of the facilities.

In some markets, state regulators have proposed initiatives to provide long-term contracts for new generating capacity in order, among other things, to reduce future capacity prices in PJM. In January 2011, New Jersey enacted legislation which requires the Board of Public Utilities to implement a Long Term Capacity Agreement Pilot Program providing for new generating capacity in the state. The new generating capacity would be required to participate and be accepted as a capacity resource in the PJM capacity market. The New Jersey Board of Public Utilities awarded three contracts for new generating capacity as required by the statute. Because the law could have a negative effect on capacity prices in PJM in future years, a group of companies in February 2011 filed suit in the U.S. District Court for New Jersey asking the court to declare the New Jersey legislation unconstitutional. That proceeding continues.

In September 2011, the Maryland Public Service Commission issued an RFP for up to 1,500 MWs of new natural gas-fired generating capacity to be located in the Southwestern Mid-Atlantic Area Council zone of PJM. The RFP requires any such new generating capacity to bid into the capacity markets in a manner consistent with the PJM tariff. The order provided for project submittals in January 2012 and a Maryland Public Service Commission hearing, later in January 2012, to determine whether new generating capacity is needed to meet the long-term anticipated demand in Maryland. We filed comments with the Maryland Public Service Commission stating there is no need for additional capacity at this time. The Maryland Public Service Commission has not issued a final decision on whether it will require the electric distribution utilities in the state to enter into contracts for new generating capacity. Such contracts could have a negative effect on capacity prices and energy prices in PJM in future years.

In April 2011, the FERC ordered changes in the PJM tariff to prevent interference with the capacity markets by efforts such as the New Jersey legislation and the Maryland RFPs.

Because of the interest of these two states in building new generating capacity within their respective states and the possibility of future RFPs for new generating capacity, we have filed an interconnection request for new generating capacity at our Dickerson generating facility in Maryland to begin the process of reviewing the suitability of this site on the transmission grid. We have not decided to build new generating capacity at the facility.

ISOs and RTOs. The vast majority of our facilities operate in markets administered by ISOs and RTOs. In areas where ISOs or RTOs control the regional transmission systems, market participants have access to broader geographic markets than in regions without ISOs and RTOs. ISOs and RTOs operate day-ahead and real-time energy and ancillary services markets, typically governed by FERC-approved tariffs and market rules. Some ISOs and RTOs also operate capacity markets. Changes to the applicable tariffs and market rules may be requested by the ISO or RTO, or by other interested persons, including market participants and state regulatory agencies, and such proposed changes, if approved by the FERC, could have a significant effect on our operations and financial results. Although participation in ISOs and RTOs by public utilities that own transmission has been, and is expected to continue to be, voluntary, the majority of such public utilities in California, Maryland, Massachusetts, New York, and Virginia have joined the applicable ISO and RTO.

PJM. Our Eastern PJM generating facilities sell electricity into the markets operated by PJM. We have access to the PJM transmission system pursuant to PJM’s Open Access Transmission Tariff. PJM operates the PJM Interchange Energy Market, which is the region’s spot market for wholesale electricity, provides ancillary services for its transmission customers, performs transmission planning for the region and economically dispatches generating facilities. PJM administers day-ahead and real-time single clearing price markets and calculates

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electricity prices based on a locational marginal pricing model. A locational marginal pricing model determines a price for energy at each node in a particular zone taking into account the limitations and losses on transmission of electricity into the zone, resulting in a higher zonal price when less expensive energy cannot be imported from another zone. Generation owners in PJM are subject to mitigation, which limits the prices that they may receive under certain specified conditions.

Load-serving entities within PJM are required to have adequate sources of capacity. Our generating facilities located in the Eastern PJM region that sell electricity into the PJM market participate in the RPM forward capacity market. The PJM RPM capacity auctions are designed to provide forward prices for capacity that ensure that adequate resources are in place in the correct location to meet the region’s demand requirements. PJM has conducted numerous capacity auctions since RPM’s inception in 2007 with the next annual auction scheduled to take place in May 2012 for the provision of capacity from June 2015 to May 2016. PJM continues to revise elements of the RPM provisions of its tariff, both pursuant to those provisions and on its own volition or at the request of its stakeholders. These revisions must be filed with and approved by the FERC, and we, either individually or as part of a group, are actively involved at the FERC to protect our interests. See previous discussion under “FERC” for our involvement at the FERC.

California (GenOn Americas Generation). Our California generating facilities are located inside the CAISO’s control area. The CAISO operates wholesale electricity markets whose key components include locational marginal pricing of energy that is similar to the locational marginal pricing in the RTO/ISO markets in the east, day-ahead and real-time markets and a transmission congestion management system. The CAISO also schedules transmission transactions and arranges for necessary ancillary services. Most sales of electricity in California are made pursuant to bilateral contracts, but a significant percentage of electrical energy is sold in the day-ahead and real-time markets operated by the CAISO.

Although the CAISO does not operate a centralized capacity market, the CPUC has adopted resource adequacy requirements for load-servicing entities that require those load-serving entities to procure capacity on a forward basis in an amount deemed appropriate to ensure reliable operation. This resource adequacy obligation creates an opportunity for our California generating facilities to generate revenue through a capacity service offering.

In the absence of a centralized capacity market, California relies on the CPUC’s biannual LTPP process to identify the need for new generating capacity in the service areas of the three major electrical utilities that the CPUC regulates. We continue to monitor the CPUC’s LTPP proceedings to identify potential opportunities for new generating facilities.

Northeast Region (GenOn Americas Generation). Our Bowline generating facility participates in a market administered by the NYISO. The NYISO provides statewide transmission service under a single tariff and interfaces with neighboring market control areas. To account for transmission congestion and losses, the NYISO calculates energy prices using a locational marginal pricing model. The NYISO also administers a spot market for energy, as well as markets for installed capacity and services that are ancillary to transmission service. The NYISO’s locational capacity market utilizes a demand curve mechanism to determine monthly capacity prices to be paid to suppliers for three capacity zones: New York City, Long Island and Rest of State. Our facility is located in the Rest of State capacity zone. In September 2011, the FERC directed the NYISO to submit changes to its market rules to include criteria for the creation of new capacity zones in the NYISO’s capacity market. If the FERC accepts the NYISO’s November 2011 filing of the criteria for creating new capacity zones, it is possible that a new Lower Hudson Valley capacity zone could be created in time for the May 2014 monthly capacity auction. Our facility likely would be located in the new Lower Hudson Valley capacity zone.

In the fourth quarter of 2010, we identified potential risks associated with some equipment that reduced the available capacity of one of the units at the Bowline generating facility. We are in the process of evaluating long-term solutions for the generating facility, but we expect that the reduction in available capacity will extend through 2014. Unrelated to the reduction in available capacity, we are repairing the facility’s transmission and gas supply

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lines which were damaged by Hurricane Irene in August 2011. Until these repairs are completed, the facility cannot be dispatched. We expect to complete these repairs in May 2012.

Our Canal, Kendall and Martha’s Vineyard generating facilities participate in a market administered by ISO-NE. GenOn Energy Management is a member of the New England Power Pool, which is a voluntary association of electric utilities and other market participants in Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont, and which functions as an advisory organization to ISO-NE. As the RTO for the New England region, ISO-NE is responsible for the operation of transmission systems and for the administration and settlement of the wholesale electric energy, capacity and ancillary services markets. ISO-NE utilizes a locational marginal pricing model for electric energy similar to the model used in PJM and NYISO. Our generating facilities located in ISO-NE also participate in the FCM. The FCM is designed to provide forward prices for capacity that ensure that adequate resources are in place to meet the region’s demand. ISO-NE has conducted numerous FCMs and we began receiving payments in June 2010 as a result of the first auction.

Environmental Regulation

We are subject to extensive environmental regulation by federal, state and local authorities under a variety of statutes, regulations and permits that address the discharge of materials into the air, water and soil; the proper handling of solid, hazardous and toxic materials and waste; and noise, safety and health standards applicable to the workplace. Complying with these environmental requirements involves significant capital and operating expenses. We decide to invest capital for environmental controls based on relatively certain regulations, an evaluation of various options for regulatory compliance, including different technologies and fuel modification, and the expected economic returns on the capital. We expect industry retirements to contribute to a tightening of supply and demand fundamentals and higher prices for the remaining generating facilities. Consequently, we expect the resulting higher market prices to provide adequate returns on investment in environmental controls necessary to meet promulgated and anticipated requirements. Accordingly, we expect to invest approximately $347 million to $453 million, including $315 million to $418 million for GenOn Mid-Atlantic, over the next ten years for SCRs and other major environmental controls to meet certain NAAQS and various water quality requirements. See Item 7, “Management’s Narrative Analysis of the Results of Operations and Financial Condition—Capital Expenditures and Capital Resources” and “Environmental Matters” for additional information. Some of these requirements are under revision and/or in dispute, and some new requirements are pending or under consideration.

Air Emissions Regulations

The Clean Air Act and the resulting regulations (as well as similar state and local requirements) have been and will continue to be a focal point for us because they mandate a broad range of requirements concerning air quality, air emissions, operating practices and pollution control equipment. Under the Clean Air Act, the EPA sets NAAQS for pollutants thought to be harmful to public health and the environment, including SO2, ozone, and fine particulate matter (PM2.5). Most of our facilities are located in or near areas that are classified by the EPA as not achieving certain NAAQS (non-attainment areas). The relevant NAAQS have become more stringent and we expect that trend to continue. As a result of such classification and the manner in which regulators seek to achieve the NAAQS, our operations generally are subject to more stringent air pollution requirements than those applicable to facilities located elsewhere. The states are generally free to impose requirements that are more stringent than those imposed by the federal government. We expect increased regulation at both the federal and state levels of our air emissions. We maintain a comprehensive compliance strategy to address these continuing and new requirements. Complying with increasingly stringent NAAQS may require us to install and operate additional emissions control equipment at some of our facilities if we decide to continue to operate such facilities. Subject to market prices, and based on anticipated more stringent NAAQS for ozone and PM2.5, we expect to invest between $315 million and $418 million in capital expenditures during 2018 to 2021 at our Chalk Point and Dickerson generating facilities. Significant air regulatory programs to which we are subject are described below.

Cross-State Air Pollution Rule. In 2005, the EPA promulgated the CAIR, which established SO2 and NOx cap-and-trade programs applicable directly to states and indirectly to generating facilities in the eastern United States.

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The NOx 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. Maryland, New York and Virginia are subject to the CAIR’s SO2 trading program and both its NOx trading programs. Massachusetts is subject only to the CAIR’s ozone-season NOx trading program. These cap-and-trade programs were to be implemented in two phases, with the first phase going into effect in 2009 for NOx and 2010 for SO2 and more stringent caps going into effect in 2015. In July 2008, the D.C. Circuit in State of North Carolina v. Environmental Protection Agency issued an opinion that would have vacated the CAIR. Various parties filed requests for rehearing with the D.C. Circuit and in December 2008, the D.C. Circuit issued a second opinion in which it granted rehearing only to the extent that it remanded the case to the EPA without vacating the CAIR.

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

Under the CSAPR program, the EPA established new allowances for all of the new CSAPR programs and did not permit any carryover of Acid Rain Program or CAIR allowances into the CSAPR trading programs. As a result, the NOx allowances from the CAIR program would not have been used. Accordingly, we thought that the CAIR NOx allowances would have no value after 2011. Similarly, the SO2 allowances used for compliance in the CAIR program (which used the already existing Acid Rain Program allowances that would have continued to be useable for compliance with the Acid Rain Program) would not have been usable for compliance with the CSAPR SO2 program and we thought they would have negligible value after 2011. As a result of the CSAPR, GenOn Americas Generation recorded impairment losses during 2011 of $128 million and GenOn Mid-Atlantic recorded impairment losses of $94 million for the write-off of excess NOx and SO2 emissions allowances. See note 3 to our consolidated financial statements.

We expect that if the CSAPR stay is lifted it will result in reduced generation volumes from uncontrolled coal-fired plants, increased generation from gas-fired plants, increased market power prices and increased emissions costs offset by allocated allowances. The effect of the CSAPR on our results of operations depends on the price of the emissions allowances, liquidity in the emissions allowances markets and whether we choose to monetize the allowances.

Maryland Healthy Air Act. The Maryland Healthy Air Act was enacted in 2006 and required reductions in SO2, NOx and mercury emissions from large coal-fired power facilities. The state law also required Maryland to join the RGGI, which is discussed below. The Maryland Healthy Air Act and the regulations adopted by MDE to implement that act impose limits for (a) emissions of NOx in 2009 with further reductions in 2012 (including sublimits during the Ozone Season) and (b) emissions of SO2 in 2010 with further reductions in 2013. The Maryland Healthy Air Act also imposes restrictions on emissions of mercury beginning in 2010 with further reductions in 2013. The Maryland Healthy Air Act imposes fixed limits and owners of power facilities may not exceed these fixed limits by purchasing emissions allowances to comply.

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We installed scrubbers at our Chalk Point, Dickerson and Morgantown coal-fired units. In addition, we installed SCR systems at the Morgantown coal-fired units and one of the Chalk Point coal-fired units and a selective auto catalytic reduction system at the other Chalk Point coal-fired unit. We also installed selective non-catalytic reduction systems at the three Dickerson coal-fired units. The control equipment we have installed allows our Maryland generating facilities to comply with (a) the first phase of the CAIR without having to purchase emissions allowances and (b) all of the requirements of the Maryland Healthy Air Act.

In 2009, we completed installation of the scrubbers. We expect to invest approximately $1.674 billion in capital expenditures, of which $1.591 billion had been invested at December 31, 2011, to comply with the requirements for SO2, NOx and mercury emissions under the Maryland Healthy Air Act. In July 2007, GenOn Mid-Atlantic and its subsidiary, GenOn Chalk Point, LLC, entered into an agreement with Stone & Webster for EPC services relating to the installation of the scrubbers described above. The cost under the agreement was approximately $1.1 billion and is a part of the $1.674 billion described above. See note 9 to our consolidated financial statements.

MATS. In February 2012, the EPA promulgated emission standards for HAPs from coal- and oil-fired units. The EPA established limits for mercury, non-mercury metals, certain organics and acid gases, which limits must be met beginning in April 2015. These limits are referred to as the MACT standards, which will result in the shutdown or retirement of some coal-fired facilities. However, our coal-fired units covered by this rule already have the emissions control equipment necessary to comply.

New Source Review Enforcement Initiative. The EPA and various states are investigating compliance of coal-fired 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 for our Chalk Point, Dickerson, Morgantown and Potomac River generating facilities. We are corresponding or have corresponded with the EPA regarding all of these requests. If a violation is determined to have occurred at any of the facilities, our subsidiary owning or leasing the facilities may be responsible for the cost of purchasing and installing emissions control equipment, the cost of which may be material. Several of our generating facilities already have installed a variety of emissions control equipment. If such a violation is determined to have occurred after our subsidiaries acquired or leased the facilities or, if occurring prior to the acquisition or lease, is determined to constitute a continuing violation, our subsidiary owning or leasing the facility at issue could also be subject to fines and penalties by the state or federal government for the period after its acquisition or lease of the facility, the cost of which may be material, although applicable bankruptcy law may bar such liability for the Chalk Point, Dickerson, Morgantown and Potomac River generating facilities for periods prior to January 3, 2006, when the Plan became effective. See note 9 to our consolidated financial statements.

Regulation of Greenhouse Gases. Concern over climate change has led to significant legislative and regulatory efforts at the state and federal level to limit greenhouse gas emissions, especially CO2.

RGGI. 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 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. Each of those states promulgated regulations implementing the RGGI.

Complying with the RGGI could have a material adverse effect upon our operations and our operating costs, depending upon the availability and cost of emissions allowances and the extent to which such costs may be offset by higher market prices to recover increases in operating costs caused by the RGGI. As contemplated in a memorandum of understanding among the participating states, Regional Greenhouse Gas Initiative, Inc. is comprehensively reviewing the program, which may cause the participating states to change the manner in which the program is administered and may increase our cost to comply.

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During 2011, GenOn Americas Generation produced approximately 13.6 million tons of CO2 at its Maryland, Massachusetts and New York generating facilities for a total cost of $25 million under the RGGI, including 12.8 million tons of CO2 (for a total cost of $26 million) at GenOn Mid-Atlantic’s Maryland generating facilities. In 2012, GenOn Americas Generation expects to produce approximately 12.4 million tons of CO2 at its Maryland, Massachusetts and New York generating facilities, including approximately 11.5 million tons at GenOn Mid-Atlantic’s Maryland generating facilities. The RGGI regulations required those facilities to obtain allowances to emit CO2 beginning in 2009. Annual allowances generally were not granted to existing sources of such emissions. Instead, allowances have been made available for such facilities by purchase through periodic auctions conducted quarterly or through subsequent purchase from a party that holds allowances sold through a quarterly auction.

AB 32. In California, emissions of greenhouse gases are governed by 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. 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. A state appellate court stayed the injunction, allowing the CARB to continue to develop the final cap-and-trade regulation. In October 2011, the CARB adopted these final cap-and-trade regulations with an initial compliance period of 2013-2014 for electric utilities and large industrial facilities. In December 2011, the superior court judge affirmed that the CARB remedied the flaws in its environmental review of the Scoping Plan. GenOn Americas Generation’s 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. However, in accordance with our tolling agreements for the Northern California generating facilities, we would pass any applicable costs through to the counterparties.

Massachusetts Climate Protection Act. In August 2008, Massachusetts adopted the Climate Protection Act, which establishes a program to reduce greenhouse gas emissions significantly over the next 40 years. Under the Climate Protection Act, the MADEP has established a reporting and verification system for statewide greenhouse gas emissions, including emissions from generating facilities producing all electricity consumed in Massachusetts, and determined the state’s greenhouse gas emissions level in 1990. Under the Climate Protection Act, the MAEEA is to establish statewide greenhouse gas emissions limits effective beginning in 2020 that will reduce such emissions from the 1990 level by a range of 10% to 25% beginning in 2020, with the reduction increasing to 80% below the 1990 level by 2050. In setting these limits, the MAEEA is to consider the potential costs and benefits of various reduction measures, including emissions limits for electric generating facilities, and may consider the use of market-based compliance mechanisms. A violation of the emissions limits established under the Climate Protection Act may result in a civil penalty of up to $25,000 per day. Implementation of the Climate Protection Act could have a material adverse effect on how GenOn Americas Generation operates its Massachusetts generating facilities and the costs of operating those facilities. In December 2010, the MAEEA established a limit for 2020 that is 25% less than the 1990 level.

Maryland Greenhouse Gas Act. In April 2009, the Maryland General Assembly passed the Maryland Greenhouse Gas Act, which became effective in October 2009. The Maryland Greenhouse Gas Act requires a reduction in greenhouse gas emissions in Maryland by 25% from 2006 levels by 2020. However, this provision of the Maryland Greenhouse Gas Act is only in effect through 2016 unless a subsequent statutory enactment extends its effective period. Under the Maryland Greenhouse Gas Act, the MDE plans to complete its proposed implementation plan in early 2012 to achieve these reductions and to adopt a final plan by the end of 2012.

Federal Rules Regarding CO2. In light of the United States Supreme Court ruling in Massachusetts v. EPA that greenhouse gases fit within the Clean Air Act’s definition of “air pollutant,” the EPA has proposed and promulgated regulations regarding the emission of greenhouse gases. In September 2009, the EPA issued a rule that

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requires owners of facilities in many sectors of the economy, including power generation, to report annually to the EPA the quantity and source of greenhouse gas emissions released from those facilities. In addition to this reporting requirement, the EPA has promulgated several rules that address greenhouse gas emissions. In December 2009, under a portion of the Clean Air Act that regulates vehicles, the EPA determined that elevated concentrations of greenhouse gases in the atmosphere endanger the public’s health and welfare through their contribution to climate change (Endangerment Finding). In April 2010, the EPA finalized a rule to regulate greenhouse gases from vehicles beginning in model year 2012 (Vehicle Rule). In April 2010, the EPA also issued its “Reconsideration of Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs” (Tailoring Rule), which addresses the scope of pollutants subject to certain permitting requirements under the Clean Air Act as well as when such requirements become effective. The EPA has stated that, because of the vehicle rule, emissions of greenhouse gases from new stationary sources such as power plants and from major modifications to such sources are subject to certain Clean Air Act permitting requirements as of January 2011. These permitting requirements require such sources to use “best available control technology” to limit their greenhouse gases. Legal challenges to the Endangerment Finding, the Vehicle Rule and the Tailoring Rule have been consolidated and are pending review. The additional substantive requirements under the Clean Air Act that may apply or may come to apply to stationary sources such as power plants are not clear at this time.

In December 2010, the EPA announced that it was starting the process of developing regulations under the New Source Performance Standard section of the Clean Air Act that would affect new and existing fossil-fueled generating facilities. The EPA intends to propose regulations regarding new units in early 2012 and expects to finalize such regulations by late 2012.

In addition to the state and regional regulatory matters described above, over the last several years various bills have been proposed in Congress to govern CO2 emissions from generating facilities, including the creation of a cap-and-trade system that would require us to purchase allowances for some or all of the CO2 emitted by our generating facilities. If CO2 regulation becomes more stringent, we expect the demand for natural gas and/or renewable sources of electricity will increase over time. Although we expect that market prices for electricity would increase following such regulation and would allow us to recover a portion of the cost of these allowances, we cannot predict with any certainty the actual increases in costs such regulation could impose upon us or our ability to recover such cost increases through higher market rates for electricity, and such regulation could have a material adverse effect on our consolidated statements of operations, financial position and cash flows. Although it is possible that Congress will take action to regulate greenhouse gas emissions, we do not think this is likely to occur in the near term. The form and timing of any final legislation will be influenced by political and economic factors and is uncertain at this time. Implementation of a CO2 cap-and-trade program in addition to other emission control requirements could increase the likelihood of retirements of coal-fired generating facilities. During 2011, GenOn Americas Generation produced approximately 14.1 million tons of CO2 at its generating facilities, including approximately 13.2 million tons at GenOn Mid-Atlantic’s generating facilities. GenOn Americas Generation expects to produce approximately 12.7 million total tons of CO2 at its generating facilities, including approximately 11.8 million total tons at GenOn Mid-Atlantic’s generating facilities, in 2012.

Water Regulations

Clean Water Act. We are required under the Clean Water Act to comply with intake and discharge requirements, requirements for technological controls and operating practices. To discharge water, we generally need permits required by the Clean Water Act. Such permits typically are subject to review every five years. As with air quality regulations, federal and state water regulations are expected to impose additional and more stringent requirements or limitations in the future. This is particularly the case for regulatory requirements governing cooling water intake structures, which are subject to regulation under section 316(b) of the Clean Water Act (the 316(b) 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 would require 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. The final rule may differ from the proposal as

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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.

The EPA also is in the process of updating its technology-based regulations regarding discharges from power plants. The EPA has collected information from numerous power plants to inform this rulemaking. The new standards have not yet been proposed. Accordingly, we cannot predict their effect on our business.

Once-Through Cooling (GenOn Americas Generation). In October 2010, the California State Water Resources Control Board’s Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling (Once-Through Cooling Policy) became effective. Compliance options for GenOn Americas Generation’s affected generating units include transitioning to a closed-cycle cooling system, retiring, or submitting an alternative plan that meets equivalent mitigation criteria. The specified compliance date for GenOn Americas Generation’s Pittsburg and Contra Costa generating facilities is December 31, 2017. We will retire the Contra Costa generating facility in May 2013, subject to regulatory approvals. We will continue to analyze compliance options for GenOn Americas Generation’s Pittsburg generating facility. The Once-Through Cooling Policy could have a material adverse effect on how GenOn Americas Generation operates the Pittsburg generating facility and the costs of operating the facility. In October 2010, GenOn Americas Generation and several other companies jointly filed a lawsuit in California superior court challenging the California State Water Resources Control Board’s issuance of the Once-Through Cooling Policy on various procedural and substantive grounds. The lawsuit seeks a writ directing the California State Water Resources Control Board to vacate and set aside approval of the Once-Through Cooling Policy. A hearing on the merits is scheduled for March 2012.

Endangered Species Act (GenOn Americas Generation). Our use of water from the Sacramento-San Joaquin Delta at the Contra Costa and Pittsburg generating facilities potentially affects certain fish species protected under the federal Endangered Species Act. We therefore must maintain authorization to engage in operations that could result in a take of (i.e., cause harm to) fish of the protected species. In September 2007, the Delta Noticing Parties notified us of their intent to sue alleging that we violated, and continue to violate, the federal Endangered Species Act because we operate the Contra Costa and Pittsburg generating facilities. In October 2007, the United States Fish and Wildlife Service, the National Marine Fisheries Service and the Army Corps of Engineers initiated a process that reviewed the environmental effects of our water usage, including effects on the protected species of fish. They also clarified that we continued to be authorized to take four species of fish protected under the federal Endangered Species Act. In May 2009, the Coalition for a Sustainable Delta, Kern County Water Agency and an individual sent a new notice of intent to sue to the Army Corps of Engineers alleging that the Army Corps of Engineers had violated the federal Endangered Species Act by issuing permits related to the operation of the Contra Costa and Pittsburg generating facilities. We dispute the allegations made by the Delta Noticing Parties and those made in the May 2009 notice.

In February 2010, we entered into a settlement agreement with the Delta Noticing Parties, the parties to the May 2009 notice of intent to sue, and the Army Corps of Engineers. The settlement agreement provides for the Delta Noticing Parties and the parties to the May 2009 notice of intent to sue to withdraw the two notices of intent to sue and to release all claims described in those notices. The settlement agreement obligated us to monitor entrainment and impingement of aquatic species caused by the operation of our generating facilities. We have completed the monitoring activities. The settlement agreement requires the Army Corps of Engineers to use its best efforts to conclude ongoing consultations with the United States Fish and Wildlife Service and the National Marine Fisheries Service regarding the environmental effects of our water usage in a timely manner and allows the Delta Noticing Parties and the parties to the May 2009 notice of intent to sue to issue new notices of intent to sue if such consultations were not completed by October 31, 2011. The National Marine Fisheries Service completed its consultation in February 2012, and consultation with the United States Fish and Wildlife Service is pending. We have apprised the Delta Noticing Parties of the status of such consultations.

Kendall NPDES and Surface Water Discharge Permit (GenOn Americas Generation). In September 2006, the EPA issued an NPDES renewal permit for the Kendall cogeneration facility. The same permit was concurrently

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issued by the MADEP as a state SWD permit, and was accompanied by MADEP’s earlier issued water quality certificate under section 401 of the Clean Water Act. These permits sought to impose new temperature limits at various points in the Charles River, an extensive temperature, water quality and biological monitoring program and a requirement to develop and install a barrier net system to reduce fish impingement and entrainment. The provisions regulating the thermal discharge could have caused substantial curtailments of the operations of the Kendall generating facility. We appealed the permits in three proceedings: (a) appeal of the NPDES permit to the EPA’s Environmental Appeals Board; (b) appeal of the SWD permit to the MADEP; and (c) appeal of the water quality certification to the MADEP. The effect of the permits was stayed pending the outcome of these appeals. In March 2008, the EPA and the MADEP issued a draft permit modification to address the 316(b) provisions of the permit that would have required modifications to the intake structure for the Kendall generating facility to add fine and coarse mesh barrier exclusion technologies and a mechanism to sweep organisms away from the intake structure through an induced water flow. In May 2008, we submitted comments on the draft permit modification objecting to the new requirements. In December 2008, the EPA and the MADEP issued final permit modifications to address the 316(b) regulations. Those final permit modifications did not substantially modify the requirements proposed in the draft modifications, and in February 2009, we filed an appeal of those modifications.

In October 2010, we submitted a permit modification request to the EPA and MADEP that requested modification of the 2006 permits (as previously modified in 2008) to reflect revised permit terms agreed upon by us, the EPA and MADEP as part of a settlement of the permit renewal proceedings pending before the EPA and MADEP. The settlement contemplates that an additional steam pipeline will be installed across the Charles River to allow us to make additional steam sales to Trigen-Boston Energy Corporation in Boston and that we will install a back pressure steam turbine and air-cooled condenser at the Kendall generating facility. This new pipeline and equipment once operational, would allow us to reduce significantly our use of water from the Charles River. In October 2010, the EPA and MADEP issued the proposed revised permits (the 2010 Kendall Permits) as draft permit modifications for public comment. In December 2010, the EPA and MADEP issued final permits that became effective in February 2011. The 2010 Kendall Permits will limit us to drawing no more than 3.2 million gallons of water per day from the river under normal operations, impose temperature limits similar to the 2006 permits, and require monitoring of temperatures at various points in the river when the Kendall generating facility is discharging water to the river. Because river water will no longer be used for once-through cooling under normal operations once the new pipeline and equipment have been installed, we expect the 2010 Kendall Permits to impose significantly less risk that operations of the facility would have to be curtailed to maintain compliance with the temperature limits. As part of our settlement with the EPA and MADEP, the EPA and MADEP issued administrative orders that provide deadlines for achieving certain milestones associated with the installation of the back pressure steam turbine, air-cooled condenser and the new steam pipeline. The administrative orders allow us to defer the new limit on the amount of river water used by the Kendall cogenerating facility and the new temperature limits imposed by the 2010 Kendall Permits until installation has been completed of the new pipeline, the back pressure steam turbine, and the air-cooled condenser, which is expected to occur in 2014. Capital expenditures for this project are expected to be between $32 million and $35 million primarily during 2012 to 2014.

Canal NPDES and SWD Permit (GenOn Americas Generation). In August 2008, the EPA issued an NPDES renewal permit for the Canal generating facility. The same permit was concurrently issued by MADEP as a state SWD permit, and was accompanied by MADEP’s earlier water quality certificate under section 401 of the Clean Water Act. The new permit imposes a requirement on us to install closed cycle cooling or an alternative technology that will reduce the entrainment of marine organisms by the Canal generating facility to levels equivalent to what would be achieved by closed cycle cooling. We appealed the NPDES permit to the EPA’s Environmental Appeals Board and appealed the surface water discharge and the water quality certificate to the MADEP. In December 2008, the EPA requested a stay to the appeal proceedings and withdrew provisions related to the closed cycle cooling requirements. The EPA has re-noticed these provisions as draft conditions for additional public comment. We filed comments in January 2009, stating that installing closed cycle cooling at the Canal generating facility was not justified and that without some cost-recovery mechanism the cost would make continued operation of the facility uneconomic. While the appeals of the renewal permit are pending, the effect of any contested permit provisions is stayed and the Canal generating facility will continue to operate under its current NPDES permit. We are unable to predict the outcome of this proceeding.

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NPDES and State Pollutant Discharge Elimination System Permit Renewals. In addition to the various NPDES proceedings described above, proceedings are currently pending for renewal of the NPDES or state pollutant discharge elimination system permits at many of our generating facilities and ash disposal sites. In general, the EPA and the state agencies responsible for implementing the provisions of the Clean Water Act applicable to the intake of water and discharge of effluent by electric generating facilities have been making the requirements imposed upon such facilities more stringent over time. With respect to each of these permit renewal proceedings, the permit renewal proceeding could take years to resolve and the agency or agencies involved could impose requirements upon the entity owning the facility that require significant capital expenditures, limit the times at which the facility can operate, or increase operations and maintenance costs materially.

Byproducts, Wastes, Hazardous Materials and Contamination

Our facilities are subject to laws and regulations governing waste management. The federal Resource Conservation and Recovery Act of 1976 (and many analogous state laws) contains comprehensive requirements for the handling of solid and hazardous wastes. The generation of electricity produces non-hazardous and hazardous materials, and we incur substantial costs to store and dispose of waste materials. The EPA and the states in which we operate coal-fired units may develop new regulations that impose additional requirements on facilities that store or dispose of materials remaining after the combustion of fossil fuels, including coal ash. If so, we may be required to change our current waste management practices at some facilities and incur additional costs.

In June 2010, the EPA proposed two alternatives for regulating byproducts of coal combustion (e.g., ash and gypsum) under the federal Resource Conservation and Recovery Act of 1976. Under the first proposal, these byproducts would be regulated as solid wastes. Under the second proposal, these byproducts would be regulated as “special wastes” in a manner similar to the regulation of hazardous waste with an exception for beneficial reuse of these byproducts. The second alternative would impose significantly more stringent requirements on and increase materially the cost of disposal of coal combustion byproducts.

GenOn Americas Generation acquired its Contra Costa, Pittsburg and Potrero generating facilities from PG&E. All three have areas of soil and groundwater contamination. In 1998, prior to our acquisition of those facilities from PG&E, consultants for PG&E conducted soil and groundwater investigations at those facilities which revealed contamination. The consultants conducting the investigation estimated the aggregate cleanup costs at those facilities could be as much as $60 million. Pursuant to the terms of the Purchase and Sale Agreement with PG&E, PG&E has responsibility for the containment or capping of all soil and groundwater contamination and the disposition of up to 60,000 cubic yards of contaminated soil from the Potrero generating facility and the remediation of any groundwater or solid contamination identified by PG&E’s consultants in 1998 at the Contra Costa and Pittsburg generating facilities, before we purchased those facilities in 1999. Pursuant to our requests, PG&E has disposed of 807 cubic yards of contaminated soil from the Potrero generating facility. We are not aware of soil or groundwater conditions at the Contra Costa, Pittsburg and Potrero generating facilities for which we expect remediation costs to be material that are not the responsibility of other parties.

In January 2011, at our request, the FERC approved changes to the RMR agreement for our Potrero facility in San Francisco, California to allow the CAISO to terminate the RMR agreement effective February 2011. In February 2011, the Potrero facility was shut down in compliance with our November 2009 settlement agreement with the City and County of San Francisco.

In 2008, GenOn Americas Generation closed and then demolished the Lovett generating facility in New York. Pursuant to an agreement with the New York State Department of Environmental Conservation in 2009, we assessed the environmental condition of the property. During late 2011, the New York State Department of Environmental Conservation indicated the site characterization work was acceptable and requested we engage in an assessment of remedial alternatives for issues identified at the site. We are in the process determining these alternatives; however, we have not completed this process.

See note 9 to our consolidated financial statements regarding discussion of storm damage and remediation at our Brandywine ash disposal site.

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Item 1A. Risk Factors.

We are subject to the following factors that could have a material adverse effect on our future performance, results of operations, financial condition and cash flows. In addition, such factors could affect our ability to service our indebtedness and other obligations, our ability to raise capital and our future growth opportunities. Also, see “Cautionary Statement Regarding Forward-Looking Information” on page vi, “Business” in Item 1 and “Management’s Narrative Analysis of the Results of Operations and Financial Condition” in Item 7 of this Form 10-K.

Risks Related to the Operation of our Business

Our financial results are unpredictable because most of our generating facilities operate without long-term power sales agreements, and our revenues and results of operations depend on market and competitive forces that are beyond our control.

We provide energy, capacity, ancillary and other energy services from our generating facilities in a variety of markets and to bi-lateral counterparties, including participating in wholesale energy markets, entering into tolling agreements, sales of resource adequacy and participation in capacity auctions. Our revenues from selling capacity are a significant part of our overall revenues. We are not guaranteed recovery of our costs or any return on our capital investments through mandated rates.

The market for wholesale electric energy and energy services reflects various market conditions beyond our control, including the balance of supply and demand, transmission congestion, our competitors’ marginal and long-term costs of production, the price of fuel, and the effect of market regulation. The price at which we can sell our output may fluctuate on a day-to-day basis, and our ability to transact may be affected by the overall liquidity in the markets in which we operate. These markets remain subject to regulations that limit our ability to raise prices during periods of shortage to the degree that would occur in a fully deregulated market. In addition, unlike most other commodities, electric energy can be stored only on a very limited basis and generally must be produced at the time of use. As a result, the wholesale power markets are subject to substantial price fluctuations over relatively short periods of time and can be unpredictable. For further discussion, see “Business—Competitive Environment.”

Our revenues, results of operations and cash flows are influenced by factors that are beyond our control, including those set forth above, as well as:

· the failure of market regulators to develop and maintain efficient mechanisms to compensate merchant generators for the value of providing capacity needed to meet demand;

· actions by regulators, ISOs, RTOs and other bodies that may artificially modify supply and demand levels and prevent capacity and energy prices from rising to the level necessary for recovery of our costs, our investment and an adequate return on our investment;

· legal and political challenges to or changes in the rules used to calculate capacity payments in the markets in which we operate or the establishment of bifurcated markets, incentives, other market design changes or bidding requirements that give preferential treatment to new generating facilities over existing generating facilities or otherwise reduce capacity payments to existing generating facilities;

· the ability of wholesale purchasers of power to make timely payment for energy or capacity, which may be adversely affected by factors such as retail rate caps, refusals by regulators to allow utilities to recover fully their wholesale power costs and investments through rates, catastrophic losses and losses from investments by utilities in unregulated businesses;

· increases in prevailing market prices for fuel oil, coal, natural gas and emissions allowances that may not be reflected in prices we receive for sales of energy;

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· increases in electricity supply as a result of actions of our current competitors or new market entrants, including the development of new generating facilities or alternative energy sources that may be able to produce electricity less expensively than our generating facilities and improvements in transmission that allow additional supply to reach our markets;

· increases in 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 future OTC regulations adopted pursuant to the Dodd-Frank Act;

· decreases in energy consumption resulting from demand-side management programs such as automated demand response, which may alter the amount and timing of consumer energy use;

· the competitive advantages of certain competitors, including continued operation of older power facilities in strategic locations after recovery of historic capital costs from ratepayers;

· existing or future regulation of our markets by the FERC, ISOs and RTOs, including any price limitations and other mechanisms to address some of the price volatility or illiquidity in these markets or the physical stability of the system;

· our obligation under any default sharing mechanisms in RTO and ISO markets, such mechanisms exist to spread the risk of defaults by transmission owning companies or other RTO members across all market participants;

· regulatory policies of state agencies that affect the willingness of our customers to enter into long-term contracts generally, and contracts for capacity in particular;

· access to contractors and equipment;

· changes in the rate of growth in electricity usage as a result of such factors as national and regional economic conditions and implementation of conservation programs;

· seasonal variations in energy and natural gas prices, and capacity payments; and

· seasonal fluctuations in weather, in particular abnormal weather conditions.

We expect higher earnings from price increases resulting from industry retirements. However, as discussed above, the market for wholesale electric energy and energy services reflects various market conditions beyond our control, including the balance of supply and demand, our competitors’ marginal and long-term costs of production, and the effect of market regulation. We cannot ensure that higher earnings or price increases will result from industry retirements of coal-fired generating facilities.

Changes in the wholesale energy markets or in our generating facility operations as a result of increased environmental requirements could result in impairments or other charges.

If our ongoing evaluation of our business results in decisions to mothball, retire or dispose of additional facilities, we could have impairments or other charges. These evaluations involve significant judgments about the future. Actual future market prices, project costs and other factors could be materially different from our current estimates.

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We are exposed to the risk of fuel cost volatility because we must pre-purchase coal and oil.

Most of our fuel contracts are at fixed prices with terms of two years or less. Although we purchase coal and oil based on our expected requirements, we still face the risks of fuel price volatility if we require more fuel than we expected.

Our cost of fuel may not reflect changes in energy and fuel prices in part because we must pre-purchase inventories of coal and oil for reliability and dispatch requirements, and thus the price of fuel may have been determined at an earlier date than the price of energy generated from the fuel. Similarly, the price we can obtain from the sale of energy may not rise at the same rate, or may not rise at all, to match a rise in fuel costs.

We are exposed to the risk of our fuel providers and fuel transportation providers failing to perform.

For our coal-fired generating facilities, we purchase most of our coal from a limited number of suppliers. Because of a variety of operational issues, our coal suppliers may not provide the contractual quantities on the dates specified within our agreements, or the deliveries may be carried over to future periods. Also, interruptions to planned or contracted deliveries to our generating facilities can result from a lack of, or constraints in, coal transportation because of rail, river or road system disruptions, adverse weather conditions and other factors.

If our coal suppliers do not perform in accordance with the agreements, we may have to procure higher priced coal in the market to meet our needs, or higher priced power in the market to meet our obligations. In addition, generally our coal suppliers do not have investment grade credit ratings nor do they post collateral with us and, accordingly, we may have limited ability to collect damages in the event of default by such suppliers. For a discussion of our coal supplier concentration risk, see note 1 to our consolidated financial statements.

For our oil-fired generating facilities, we typically purchase fuel from a limited number of suppliers. If our oil suppliers do not perform in accordance with the agreements, we may have to procure higher priced oil in the market to meet our needs, or higher priced power in the market to meet our obligations. For our gas-fired generating facilities, any curtailments or interruptions on transporting pipelines could result in curtailment of our operations or increased fuel supply costs.

Operation of our generating facilities involves risks that could result in disruption, curtailment or inefficiencies in our operations.

The operation of our generating facilities involves various operating risks, including, but not limited to:

· the output and efficiency levels at which those generating facilities perform;

· interruptions in fuel supply and quality of available fuel;

· disruptions in the delivery of electricity;

· adverse zoning;

· breakdowns or equipment failures (whether a result of age or otherwise);

· violations of our permit requirements or changes in the terms of, or revocation of, permits;

· releases of pollutants and hazardous substances to air, soil, surface water or groundwater;

· ability to transport and dispose of coal ash at reasonable prices;

· curtailments or other interruptions in natural gas supply;

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· shortages of equipment or spare parts;

· labor disputes, including strikes, work stoppages and slowdowns;

· the aging workforce at many of our facilities;

· operator errors;

· curtailment of operations because of transmission constraints;

· failures in the electricity transmission system which may cause large energy blackouts;

· implementation of unproven technologies in connection with environmental improvements; and

· catastrophic events such as fires, explosions, floods, earthquakes, hurricanes or other similar occurrences.

These factors could result in a material decrease, or the elimination of, the revenues generated by our facilities or a material increase in our costs of operations.

We operate in a limited number of markets and a significant portion of our revenues are derived from the PJM market. The effect of adverse developments in our markets, especially the PJM market, may be greater on us than on our more geographically diversified competitors.

Our generating capacity is 54% in PJM, 20% in CAISO, and 26% in NYISO and ISO-NE. All of GenOn Mid-Atlantic’s generating facilities serve the PJM market. Adverse developments in these regions, especially in the PJM market, may adversely affect us. Further, the effect of such adverse regional developments may be greater on us than on our more geographically diversified competitors.

We are exposed to possible losses that may occur from the failure of a counterparty to perform according to the terms of a contractual arrangement with us, particularly in connection with our non-collateralized power hedges between GenOn Mid-Atlantic and financial institutions.

Non collateralized power hedges with financial institutions represent 58% of the net notional power position for GenOn Americas Generation and 57% of the net notional power position for GenOn Mid-Atlantic at December 31, 2011. Such hedges 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. Deterioration in the financial condition of such counterparties could result in their failure to pay amounts owed to us or to perform obligations or services owed to us beyond collateral posted.

Regulated utilities have competitive advantages in wholesale power markets.

We compete with non-utility generators, regulated utilities, and other energy service companies in the sale of our products and services, as well as in the procurement of fuel, fuel transportation and transmission services. We compete primarily on the basis of price and service. Regulated utilities in the wholesale markets generally enjoy a lower cost of capital than we do and often are able to recover fixed costs through regulated retail rates, including, in many cases, the costs of generation, allowing them to build, buy and upgrade generating facilities without relying exclusively on market-clearing prices to recover their investments.

Changes in technology may significantly affect our generating business by making our generating facilities less competitive.

We generate electricity using fossil fuels at large central facilities. This method results in economies of scale and lower costs than newer technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells. It

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is possible that advances in those technologies, or governmental incentives for renewable energies, will reduce their costs to levels that are equal to or below that of most central station electricity production.

The expected decommissioning and/or site remediation obligations of certain of our generating facilities may negatively affect our cash flows.

Some of our generating facilities and related properties are subject to decommissioning and/or site remediation obligations that may require material expenditures. Furthermore, laws and regulations may change to impose material additional decommissioning and remediation obligations on us in the future.

Terrorist attacks and/or cyber-attacks may result in our inability to operate and fulfill our obligations, and could result in material repair costs.

As a power generator, we face heightened risk of terrorism, including cyber terrorism, either by a direct act against one or more of our generating facilities or an act against the transmission and distribution infrastructure that is used to transport our power. Although our entire industry is exposed to these risks, our generating facilities and the transmission and distribution infrastructure located in the PJM market are particularly at risk because of the proximity to major population centers, including governmental and commerce centers.

We rely on information technology networks and systems to operate our generating facilities, engage in asset management activities, and process, transmit and store electronic information. Security breaches of this information technology infrastructure, including cyber-attacks and cyber terrorism, could lead to system disruptions, generating facility shutdowns or unauthorized disclosure of confidential information related to our employees, vendors and counterparties. Confidential information includes banking, vendor, counterparty and personal identity information.

Systemic damage to one or more of our generating facilities and/or to the transmission and distribution infrastructure could result in our inability to operate in one or all of the markets we serve for an extended period of time. If our generating facilities are shut down, we would be unable to respond to the ISOs and RTOs or fulfill our obligations under various energy and/or capacity arrangements, resulting in lost revenues and potential fines, penalties and other liabilities. Pervasive cyber-attacks across our industry could affect the ability of ISOs and RTOs to function in some regions. The cost to restore our generating facilities after such an occurrence could be material.

Our operations are subject to hazards customary to the power generating industry. We may not have adequate insurance to cover all of these hazards.

Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of high-speed rotating equipment and delivering electricity to transmission and distribution systems. In addition to natural risks (such as earthquake, flood, storm surge, lightning, hurricane, tornado and wind), hazards (such as fire, explosion, collapse and machinery failure) are inherent risks in our operations. We are also susceptible to terrorist attacks, including cyber-attacks, against our generating facilities or the transmission and distribution infrastructure that is used to transport our power. These hazards can cause significant injury to personnel or loss of life, severe damage to and destruction of property, plant and equipment, contamination of, or damage to, the environment and suspension of operations. The occurrence of any one of these events may result in our being named as a defendant in lawsuits asserting claims for substantial damages, environmental cleanup costs, personal injury and fines and/or penalties. We do not maintain specialized insurance for possible liability resulting from a cyber-attack on our systems that may shut down all or part of the transmission and distribution system. However, we maintain an amount of insurance protection that we consider adequate and customary for merchant power producers. We cannot assure that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject.

Lawsuits, regulatory proceedings and tax proceedings could adversely affect our future financial results.

From time to time, we are named as a party to, or our property is the subject of, lawsuits, regulatory proceedings or tax proceedings. We are currently involved in various proceedings which involve highly subjective

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matters with complex factual and legal questions. Their outcome is uncertain. Any claim that is successfully asserted against us could require significant expenditures by us. Even if we prevail, any proceedings could be costly and time-consuming, could divert the attention of our management and key personnel from our business operations and could result in adverse changes in our insurance costs. See notes 5 and 9 to our consolidated financial statements.

We depend on the skills, experience and efforts of our people.

The successful execution of our business strategy is dependent on the skills, experience and efforts of our people. The loss of one or more members of our senior management or employees with critical skills could adversely affect our future business, financial condition, and operating results if we were unable to secure the talent that we feel is needed.

If we acquire or develop additional facilities, dispose of existing facilities or combine with other businesses, we may incur additional costs and risks.

We may seek to purchase or develop additional facilities, dispose of existing facilities, or combine with other businesses. There is no assurance that these efforts will be successful. In addition, these activities involve risks and challenges, including identifying suitable opportunities, obtaining required regulatory and other approvals, integrating acquired or combined operations with our own, and increasing expenses and working capital requirements. Furthermore, in any sale, we may be required to indemnify a purchaser against liabilities. To finance future acquisitions, we may be required to issue additional equity securities or incur additional debt. Obtaining such additional financing is dependent on numerous factors, including general economic and capital market conditions, credit availability from financial institutions, the covenants in our debt agreements, and our financial performance, cash flow and credit ratings. We cannot make any assurances that we would be able to obtain such additional financing on commercially reasonable terms or at all.

Risks Related to Economic and Financial Market Conditions

We are exposed to systemic risk of the financial markets and institutions and the risk of non-performance of the individual lenders under GenOn’s undrawn credit facilities.

Maintaining sufficient liquidity in our business for maintenance and operating expenditures, capital expenditures and collateral is crucial in order to mitigate the risk of future financial distress to us. Accordingly, GenOn maintains a revolving credit facility to manage its expected liquidity needs and contingencies. In the event that financial institutions are unwilling or unable to renew GenOn’s existing revolving credit facility or enter into new revolving credit facilities, our ability to hedge economically our assets or GenOn Americas Generation’s ability to engage in proprietary trading could also be impaired.

A negative market perception of our value could impair our ability to refinance debt.

A substantial downturn in general economic conditions, including low power and commodity prices, could result in a perceived weakness in our overall financial health. A negative market perception of our value could result in our inability to obtain and maintain an appropriate credit rating. In this event, we may be unable to access debt markets or refinance future debt maturities, or we may be required to post additional collateral to operate our business.

As financial institutions consolidate and operate under more restrictive capital constraints and regulations, including the Dodd-Frank Act, there could be less liquidity in the energy and commodity markets for hedge transactions and fewer creditworthy counterparties.

We hedge economically a substantial portion of our Eastern PJM coal-fired baseload generation and certain of our other generation. 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. Global financial institutions have been active participants in these energy and commodity

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markets. As global financial institutions consolidate and operate under more restrictive capital constraints and regulations, including the Dodd-Frank Act, there could be less liquidity in the energy and commodity markets, which could have a material adverse effect on our ability to hedge economically and transact with creditworthy counterparties.

The Dodd-Frank Act could materially affect our business, including greater regulation of energy contracts and OTC derivative financial instruments, which could materially and adversely affect our ability to hedge economically our generation and engage in proprietary trading.

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 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” will face costly requirements for clearing and posting margin, as well as additional requirements for reporting and business conduct. Although we do not expect our commercial 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. It is possible that the final rule will not offer much clarity and the designation as an SD/MSP could be decided by facts and circumstance tests. The impact of the final regulations, or the uncertainty as to the scope thereof, could have a material adverse effect on our commercial activities and our ability to hedge economically, including decreasing liquidity in the forward commodity markets.

Many of the factors that cause changes in commodity prices are outside our control and may materially increase our cost of producing power or lower the price at which we are able to sell our power.

Our generating business is subject to changes in power prices and fuel and emissions costs, and these commodity prices are influenced by many factors outside our control, including weather, seasonal variation in supply and demand, market liquidity, transmission and transportation inefficiencies, availability of competitively priced alternative energy sources, demand for energy commodities, production of natural gas, coal and crude oil, natural disasters, wars, embargoes and other catastrophic events, and federal, state and environmental regulation and legislation. In addition, significant fluctuations in the price of natural gas may cause significant fluctuations in the price of electricity. Significant fluctuations in commodity prices may affect our financial results and financial position by increasing the cost of producing power and decreasing the amounts we receive from the sale of power.

Our hedging activities will not fully protect us from fluctuations in commodity prices.

We engage in hedging activities related to sales of electricity and purchases of fuel and emissions allowances. The income and losses from these activities are recorded as operating revenues and fuel costs. We may use forward contracts and other derivative financial instruments to manage market risk and exposure to volatility in prices of electricity, coal, natural gas, emissions and oil. The effectiveness of these hedges is dependent upon the correlation between the forward contracts and the other derivative financial instruments used as a hedge and the market risk of the asset or assets being hedged. We cannot provide assurance that these strategies will be successful in managing our price risks, or that they will not result in net losses to us as a result of future volatility in electricity, fuel and emissions markets. Actual power prices and fuel costs may differ from our expectations.

Our hedging activities include natural gas derivative financial instruments that we use to hedge economically power prices for our baseload generation. The effectiveness of these hedges is dependent upon the correlation between power and natural gas prices in the markets where we operate. If those prices are not sufficiently correlated, our financial results and financial position could be adversely affected. See note 2 to our consolidated financial statements.

Additionally, GenOn Americas Generation expects to have an open position in the market, within its established guidelines, resulting from its proprietary trading and fuel oil management activities. To the extent open positions exist, fluctuating commodity prices can affect our financial results and financial position, either favorably or unfavorably. As a result of these and other factors, we cannot predict the outcome that risk management

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decisions may have on our business, operating results or financial position. Although management devotes considerable attention to these issues, their outcome is uncertain.

Our policies and procedures cannot eliminate the risks associated with our hedging and GenOn Americas Generation’s proprietary trading activity.

The risk management procedures we have in place may not always be followed or may not always work as planned. If any of our employees were able to violate our system of internal controls, including our risk management policy, and engage in unauthorized hedging and related activities, it could result in significant penalties and financial losses. In addition, risk management tools and metrics such as value at risk, gross margin at risk, and stress testing are partially based on historic price movements. If price movements significantly or persistently deviate from historical behavior, risk limits may not fully protect us from significant losses.

Our hedging and GenOn Americas Generation’s proprietary trading and fuel oil management activities may increase the volatility of the GAAP financial results.

Derivatives from our hedging and GenOn Americas Generation’s proprietary trading and fuel oil management activities are recorded on our balance sheet at fair value pursuant to the accounting guidance for derivative financial instruments. None of our derivatives recorded at fair value are designated as a hedge under this guidance, and changes in their fair values currently are recognized in earnings as unrealized gains or losses. As a result, our GAAP financial results—including gross margin, operating income and balance sheet ratios—will, at times, be volatile and subject to fluctuations in value primarily because of changes in forward electricity and fuel prices. See notes 1 and 2 to our consolidated financial statements.

Risks Related to Governmental Regulation and Laws

Our costs of compliance with environmental laws are significant and can affect our future operations and financial results.

We are subject to extensive and evolving environmental regulations, particularly in regard to our coal- and oil-fired facilities. Environmental laws, particularly with respect to air emissions, disposal of ash, wastewater discharge and cooling water systems, are generally becoming more stringent, which may require us to make additional facility upgrades or restrict our operations. Failure to comply with environmental requirements could require us to shut down or reduce production at our facilities or create liabilities. We incur significant costs in complying with these regulations and, if we fail to comply, could incur significant penalties. Our cost estimates for environmental compliance are based on existing regulations or our view of reasonably likely regulations, and our assessment of the costs of labor and materials and the state of evolving technologies. Our decision to make these investments is often subject to future market conditions. Changes to the preceding factors, new or revised environmental regulations, litigation and new legislation and/or regulations, as well as other factors, could cause our actual costs to vary outside the range of our estimates, further constrain our operations, increase our environmental compliance costs and/or make it uneconomical to operate some of our facilities.

Federal, state and regional initiatives to regulate greenhouse gas emissions could have a material impact on our financial performance and condition. The actual impact will depend on a number of factors, including the overall level of greenhouse gas reductions required under any such regulations, the final form of the regulations or legislation, and the price and availability of emissions allowances if allowances are a part of any final regulatory framework.

We are required to surrender emissions allowances equal to emissions of specific substances to operate our facilities. Surrender requirements may require purchase of allowances, which may be unavailable or only available at costs that would make it uneconomical to operate our facilities.

Certain environmental laws, including CERCLA and comparable state laws, impose strict and, in many circumstances, joint and several liability for costs of remediating contamination. Some of our facilities have areas

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with known soil and/or groundwater contamination. We could be required to spend significant sums to remediate contamination, regardless of whether we caused such contamination, (a) if there are releases or discoveries of hazardous substances at our generating facilities, at disposal sites we currently use or have used, or at other locations for which we may be liable, or (b) if parties contractually responsible to us for contamination fail to or are unable to respond when claims or obligations regarding such contamination arise.

Our coal-fired generating units produce certain byproducts that involve extensive handling and disposal costs and are subject to government regulation. Changes in these regulations, or their administration, by legislatures, state and federal regulatory agencies, or other bodies may affect the costs of handling and disposing of these byproducts.

As a result of the coal combustion process, we produce significant quantities of ash at our coal-fired generating units that must be disposed of at sites permitted to handle ash. One of our landfills in Maryland has reached design capacity and we expect that another one of our sites in Maryland may reach full capacity in the next few years. As a result, we are developing new ash management facilities and have constructed a facility to prepare ash from certain of our Maryland facilities for beneficial uses. However, the costs associated with developing new ash management facilities could be material, and the amount of time to complete such developments could extend beyond the time when new facilities are needed. Likewise, the new facility for preparing ash for beneficial uses may not operate as expected; or the ash may not be marketed and sold as expected. Additionally, costs associated with third-party ash handling and disposal are material and could have an adverse effect on our financial performance and condition.

We also produce gypsum as a byproduct of the SO2 scrubbing process at our coal-fired generating facilities, most of which is sold to third parties for use in drywall production. Should our ability to sell such gypsum to third parties be restricted as a result of the lack of demand or otherwise, our gypsum disposal costs could rise materially.

The EPA has proposed two alternatives for regulating byproducts such as ash and gypsum. One of these alternatives would regulate these byproducts as “special wastes” in a manner similar to the regulation of hazardous wastes. If these byproducts are regulated as special wastes, the cost of disposing of these byproducts would increase materially and may limit our ability to recycle them for beneficial use.

Our business is subject to complex government regulations. Changes in these regulations, or their administration, by legislatures, state and federal regulatory agencies, or other bodies may affect the prices at which we are able to sell the electricity we produce, the costs of operating our generating facilities or our ability to operate our facilities.

The majority of our generation is sold at market prices under market-based rate authority granted by the FERC. If certain conditions are not met, the FERC has the authority to withhold or rescind market-based rate authority and require sales to be made based on cost-of-service rates. A loss of our market-based rate authority could have a materially negative impact on our generating business.

Even when market-based rate authority has been granted, the FERC may impose various forms of market mitigation measures, including price caps and operating restrictions, when it determines that potential market power might exist and that the public interest requires such potential market power to be mitigated. In addition to direct regulation by the FERC, most of our facilities are subject to rules and terms of participation imposed and administered by various ISOs and RTOs. Although these entities are themselves ultimately regulated by the FERC, they can impose rules, restrictions and terms of service that are quasi-regulatory in nature and can have a material adverse impact on our business. For example, ISOs and RTOs may impose bidding and scheduling rules, both to curb the potential exercise of market power and to ensure market functions. Such actions may materially affect our ability to sell and the price we receive for our energy, capacity and ancillary services.

To conduct our business, we must obtain and periodically renew licenses, permits and approvals for our facilities. These licenses, permits and approvals can be in addition to any required environmental permits. No assurance can be provided that we will be able to obtain and comply with all necessary licenses, permits and approvals for these facilities.

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Conflicts may occur between reliability needs and environmental rules, particularly with increasingly stringent environmental restrictions. Without a consent decree or adjustments to permit requirements, which require long lead times to obtain, we remain subject to environmental penalties or liabilities that may occur as a result of operating in compliance with reliability requirements. Further, we could be subject to citizen suits in these types of circumstances, even if we have received a consent decree or permit adjustment exempting us from environmental requirements.

We cannot predict whether the federal or state legislatures will adopt legislation relating to the restructuring of the energy industry. There are proposals in many jurisdictions that would either roll back or advance the movement toward competitive markets for the supply of electricity, at both the wholesale and retail levels. In addition, any future legislation favoring large, vertically integrated utilities and a concentration of ownership of such utilities could affect our ability to compete successfully, and our business and results of operations could be adversely affected. Similarly, any regulations or laws that favor new generation over existing generation could adversely affect our business.

Risks Related to Level of Indebtedness

Our substantial indebtedness and operating lease obligations could adversely affect our ability to raise additional capital to fund our operations, limit our ability to react to changes in the economy or our industry and prevent us from meeting or refinancing our obligations.

At December 31, 2011, GenOn Americas Generation’s consolidated indebtedness was $866 million and GenOn Mid-Atlantic’s consolidated debt was $18 million. In addition, the present value of lease payments under the GenOn Mid-Atlantic operating leases was approximately $881 million (assuming a 10% discount rate) and the termination value of the GenOn Mid-Atlantic operating leases was $1.3 billion.

Our indebtedness and operating lease obligations could have important consequences for our liquidity, results of operations, financial position and prospects, including our ability to grow in accordance with our strategy. These consequences include the following:

· they may limit our ability to obtain additional debt or equity financing for working capital, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes;

· a substantial portion of our cash flows from operations must be dedicated to the payment of rent and principal and interest on our indebtedness and will not be available for other purposes, including for working capital, capital expenditures and other general corporate purposes;

· the debt service requirements of our indebtedness and our lease obligations could make it difficult for us to satisfy or refinance our financial obligations;

· they may limit our flexibility in planning for and reacting to changes in our industry;

· they may place us at a competitive disadvantage compared to other, less leveraged competitors; and

· we may be more vulnerable in a downturn in general economic conditions or in our business and we may be unable to carry out capital expenditures that are important to our long-term growth or necessary to comply with environmental regulations.

GenOn Americas Generation and its subsidiaries that are holding companies may not have access to sufficient cash to meet their obligations if their subsidiaries, in particular GenOn Mid-Atlantic, are unable to make distributions.

GenOn Americas Generation and certain of its subsidiaries are holding companies and, as a result, GenOn Americas Generation is dependent upon dividends, distributions and other payments from its operating subsidiaries

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Item 2. Properties.

The properties below were owned or leased as of December 31, 2011. Our leasehold or ownership interest is 100% for each property.

Facility

Net
Generating
Capacity
(MW)(1)

Holding

In Service
Date(2)

Primary Fuel
Type(3)

SO2 and/or NOx
Control
Technology(4)

Dispatch
Type (5)

Location

NERC
Region

Eastern PJM:

Chalk Point

2,401

Own

1964-1991

Coal/Dual/Oil

FGD;SCR(6);SACR(7)

B/I/P

Maryland(8)

RFC

Dickerson (9)

849

Own/Lease

1959-1993

Coal/Dual/Oil

FGD;SNCR

B/P

Maryland(8)

RFC

Morgantown (9)

1,477

Own/Lease

1970-1973

Coal/Oil

FGD;SCR

B/P

Maryland(8)

RFC

Potomac River(10)

482

Own

1949-1957

Coal

DSI

B/I

Virginia(8)

RFC

Total Eastern PJM(11)

5,209

Northeast Region:

Bowline

1,139

Own

1972-1974

Dual

N/A

New York

NPCC

Canal

1,126

Own

1968-1976

Dual/Oil

N/A

Massachusetts

NPCC

Kendall

256

Own

1949-2002

Natural Gas/Oil/Dual

N/A

B/P

Massachusetts

NPCC

Martha’s Vineyard

Own

1968-1972

Oil

N/A

Massachusetts

NPCC

Total Northeast

2,535

California:

Contra Costa(12)

674

Own

1964

Natural Gas

N/A

California

WECC

Pittsburg

1,311

Own

1960-1972

Natural Gas

N/A

California

WECC

Total California

1,985

Total GenOn Americas Generation

9,729

(1)	Total MW amounts reflect net summer capacity.
(2)	Represents the year of commercial operation or range of years if units became operational in different years.
(3)	Dual means natural gas and oil.
(4)	SO2 controls include FGD and DSI (dry sorbent injection). NOx controls include SCR, SACR (selective auto-catalytic reduction) and SNCR (selective non-catalytic reduction). In addition, substantially all of our coal units and many of our other units are equipped with combustion controls to reduce NOx (i.e., low NOx burners, overfire air systems and/or water injection).
(5)	B is baseload. I is intermediate. P is peaking.
(6)	For Chalk Point unit 1.
(7)	For Chalk Point unit 2.
(8)	These generating facilities are located near Washington, D.C.
(9)	We lease 100% interests in the Dickerson and Morgantown baseload units through facility lease agreements expiring in 2029 and 2034, respectively. We own 307 MW and 248 MW of peaking capacity at the Dickerson and Morgantown generating facilities, respectively. We operate the Dickerson and Morgantown facilities.
(10)	We expect to retire the Potomac River generating facility in October 2012.
(11)	GenOn Mid-Atlantic’s generating facilities are these four facilities.
(12)	We expect to retire the Contra Costa generating facility in May 2013.

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Item 7. Management’s Narrative Analysis of the Results of Operations and Financial Condition.

A. GenOn Americas Generation

This section is intended to provide the reader with information that will assist in understanding GenOn Americas Generation’s financial statements, the changes in those financial statements from year to year and the primary factors contributing to those changes. The following discussion should be read in conjunction with GenOn Americas Generation’s consolidated financial statements and the notes accompanying those financial statements.

Merger of Mirant and RRI Energy

Our Business

We are a wholesale generator with approximately 9,729 MW of net electric generating capacity located, in many cases, near major metropolitan load centers in the Eastern PJM and Northeast regions and northern California. We also operate integrated asset management and proprietary trading operations. Our customers are principally ISOs, RTOs and investor-owned utilities.

In connection with the retirement of the Potomac River and Contra Costa generating facilities, we expect to incur some charges beginning in the first quarter of 2012. We are currently determining the appropriate amounts for these charges, which include write-offs for excess materials and supplies inventory, severance and other plant closure costs.

Our commercial operations consist primarily of dispatching electricity, hedging the price of electricity we expect to generate, selling capacity, procuring and managing fuel and providing logistical support for the operation of our facilities (for example, by procuring transportation for coal and natural gas), as well as GenOn Americas Generation’s proprietary trading operations.

We typically sell the electricity we produce into the wholesale market at prices in effect at the time we produce it (spot price). We use dispatch models to assist in making daily bidding decisions regarding the quantity and price of the power we offer to generate from our facilities and sell into the markets. We bid the energy from our generating facilities into the hour-ahead or day-ahead energy market and sell ancillary services through the ISO and RTO markets. We work with the ISOs and RTOs in real time to ensure that our generating facilities are dispatched economically to meet the reliability needs of the market.

Spot prices for electricity are volatile, as are prices for fuel and emissions allowances. In order to reduce the risk of price volatility and achieve more predictable financial results, we have historically entered into economic hedges—forward sales of electricity and forward purchases of fuel and emissions allowances to permit us to produce and sell the electricity—to manage the risks associated with such volatility. In addition, given the high correlation between natural gas prices and electricity prices in many of the markets in which we operate, we have entered into forward sales of natural gas to hedge economically our exposure to changes in the price of electricity. We procure our hedges in OTC transactions or on exchanges where electricity, fuel and emissions allowances are broadly traded, or through specific transactions with buyers and sellers, using futures, forwards, swaps and options. Our hedges cover various periods, including several years.

We sell capacity either bilaterally or through periodic auctions in each ISO and RTO market in which we participate. These capacity sales provide an important source of predictable revenues for us over the contracted period. At January 24, 2012, total projected contracted capacity and PPA revenues for which prices have been set

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for 2012 through 2015 are $1.2 billion. Failure to meet our capacity commitments may result in a reduction to our capacity payments through penalties or charges.

In addition to the activities described above, we buy and sell some electricity, fuel and emissions allowances, sometimes through financial derivatives, as part of our proprietary trading, fuel oil management and natural gas transportation and storage activities. We engage in proprietary trading to gain information about the markets in which we operate to support our asset management and to take advantage of selected opportunities that we identify. We enter into fuel oil management activities to hedge economically the fair value of our physical fuel oil inventories, optimize the approximately two million barrels of storage capacity that we own, as well as attempt to profit from market opportunities related to timing and/or differences in the pricing of various products. We engage in natural gas transportation and storage activities to optimize GenOn’s physical natural gas storage positions and manage the physical gas requirements for a portion of our assets. Proprietary trading, fuel oil management and natural gas transportation and storage activities together will typically comprise less than 10% of our realized gross margin. All of our commercial activities are governed by a comprehensive risk management policy, which includes limits on the size of volumetric positions and VaR for our proprietary trading and fuel oil management activities.

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 January 24, 2012, our aggregate hedge levels based on expected generation for each year were as follows:

	2012(1)		2013		2014		2015		2016

Power	93	%	76	%	38	%	29	%	27	%
Fuel	81	%	64	%	9	%	—	%	—	%

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

See Item 1A, “Risk Factors—Risks Related to Economic and Financial Market Conditions” for a discussion of:

· the risks of consolidation of financial institutions and more restrictive capital constraints and regulation, which could have a negative effect on our ability to hedge economically with creditworthy counterparties; and

· the risks of implementation of the Dodd-Frank Act on our ability to hedge economically our generation, including potentially reducing liquidity in the energy and commodity markets and, if we are required to clear such transactions on exchanges or meet other requirements, by significantly increasing the collateral costs associated with such activities.

Capital Expenditures and Capital Resources

For 2011, we invested $156 million for capital expenditures, excluding capitalized interest paid. Capital expenditures for 2011 primarily relate to maintenance capital expenditures, the construction of an ash beneficiation facility and include the $68 million payment to Stone & Webster for substantial completion of the Maryland scrubber projects. At December 31, 2011, we have invested $1.591 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

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contracts for the scrubbers at our Maryland coal-fired units provide for certain payments to be made after final completion of the projects. Assuming we are successful in pursuing our claims in the New York proceeding, the total estimated capital expenditures for compliance with the Maryland Healthy Air Act would not exceed the $1.674 billion we currently have recorded. However, if the costs were to equal the amount claimed by Stone & Webster in the litigation, the total capital expenditures would exceed $1.674 billion by approximately 5%. See note 9 to our consolidated financial statements for further discussion involving the scrubber contract litigation.

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

	2012		2013
	(in millions)

Maryland Healthy Air Act	$	83	$	—
Other environmental	13		21
Maintenance	56		66
Other construction	13		—
Total	$	165	$	87

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

Environmental Matters

We decide to invest capital for environmental controls based on relatively certain regulations, an evaluation of various options for regulatory compliance, including different technologies and fuel modification, and the expected economic returns on the capital. We expect other industry participants to retire coal-fired generating facilities because of the costs associated with more stringent environmental air and water quality requirements, some of which have already been announced.

We expect industry retirements of coal-fired generating facilities to contribute to a tightening of supply and demand fundamentals and higher prices for the remaining generating facilities. Consequently, we expect the resulting higher market prices to provide adequate returns on some investment in environmental controls necessary to meet promulgated and anticipated requirements. Accordingly, we expect to invest approximately $347 million to $453 million, including $315 million to $418 million for Chalk Point unit 2 and Dickerson at GenOn Mid-Atlantic and $32 million to $35 million at Kendall, over the next ten years for SCRs and other major environmental controls to meet certain air and water quality requirements, which we expect to fund from existing sources of liquidity.

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2011 Compared to 2010

Consolidated Financial Performance

We reported net income of $16 million and net loss $396 million for 2011 and 2010, respectively. The change in net income/loss is detailed as follows:

	2011			2010			Increase/ (Decrease)
	(in millions)

Gross margin:
Energy	$	234		$	435		$	(201	)
Contracted and capacity	398			541			(143		)
Realized value of hedges	271			292			(21		)
Realized gross margin	903			1,268			(365		)
Unrealized gross margin	138			(17		)	155
Total gross margin (excluding depreciation and amortization)	1,041			1,251			(210		)
Operating expenses:
Operations and maintenance	378			390			(12		)
Operations and maintenance—affiliate	228			293			(65		)
Depreciation and amortization	177			199			(22		)
Impairment losses	128			565			(437		)
Gain on sales of assets, net	(5		)	(4		)	(1		)
Loss on sales of assets, net—affiliate	2			(5		)	7
Total operating expenses	908			1,438			(530		)
Operating income (loss)	133			(187		)	320
Other expense, net:
Interest expense, net	(88		)	(200		)	(112		)
Interest expense, net—affiliate	(5		)	—			5
Other, net	(24		)	(9		)	15
Total other expense, net	(117		)	(209		)	(92		)
Net income (loss)	$	16		$	(396	)	$	412

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.

For 2011, our realized gross margin decrease of $365 million was principally a result of the following:

· a decrease of $201 million in energy primarily as a result of a decrease in generation volumes in Eastern PJM as a result of contracting dark spreads and spark spreads partially offset by an increase in Energy Marketing as a result of an increase in proprietary trading and fuel oil management activities;

· a decrease of $143 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; and

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· a decrease of $21 million in realized value of hedges primarily as a result of a decrease in our power hedges in Eastern PJM and the Northeast primarily resulting from prices and volumes hedged and a decrease in crude oil hedges in the Northeast, offset in part by an increase in our coal hedges in Eastern PJM resulting from prices.

Unrealized 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 $138 million in 2011, which included a $354 million net increase in the value of hedge and proprietary trading contracts for future periods primarily related to decreases in forward power and natural gas prices, offset by $216 million associated with the reversal of previously recognized unrealized gains from power and fuel contracts that settled during the period; and

· unrealized losses of $17 million in 2010, which included $387 million associated with the reversal of previously recognized unrealized gains from power and fuel contracts that settled during the period, substantially offset by a $370 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, offset in part by the recognition of many of our coal agreements at fair value beginning in the second quarter of 2010.

Operating Expenses. Our operating expenses decrease of $530 million was principally a result of the following:

· a decrease of $437 million in impairment losses. In 2011, we recognized $128 million in impairment losses for the write-off of excess NOx and SO2 emissions allowances as a result of the CSAPR. In 2010, we recognized $565 million in impairment losses related to our Dickerson and Potomac River generating facilities. See note 3 to our consolidated financial statements;

· a decrease of $77 million in operations and maintenance expense primarily related to the following:

· a decrease of $43 million resulting from a change in the allocation methodology for overhead costs and a larger number of generating facilities to which the allocated costs are distributed, both as a result of the Merger;

· $32 million recognized in 2010 related to a liability associated with our commitment to reduce particulate emissions at our Potomac River generating facility as a part of the agreement with the City of Alexandria, Virginia. See note 3 to our consolidated financial statements;

· a decrease of $20 million resulting from decreases of variable operations and maintenance, outage expenses and some labor costs in Eastern PJM;

· a decrease of $17 million as a result of the repeal of the Montgomery County CO2 levy, including $8 million related to a refund received during 2011 of CO2 levies paid in 2010;

· a decrease of $16 million resulting from other cost reductions in Northeast and California;

· a decrease of $8 million resulting from the shutdown of the Potrero generating facility; and

· a decrease of $6 million resulting from changes in asset retirement obligation assumptions in Eastern PJM, partially offset by

· a $49 million accrual for remediation costs at our Maryland ash facilities (which includes a tentative $1.9 million civil penalty);

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· $15 million recognized in 2011for major litigation costs, net of recoveries; and

· a $10 million accrual for the Brandywine storm damage and remediation; and

· a decrease of $22 million in depreciation and amortization expense primarily as a result of reductions in the carrying values of the Dickerson and Potomac River generating facilities as a result of impairment losses in 2010, and the shutdown of the Potrero generating facility.

Interest Expense, Net. Interest expense, net decrease of $107 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 $15 million was primarily a result of the following:

· $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.

· $9 million write-off of unamortized debt issuance costs related to the GenOn North America senior secured term loan that was repaid in 2010.

Operating Statistics

The following table summarizes power generation volumes by segment:

	2011	2010		Increase/ (Decrease)		Increase/ (Decrease)
	(in gigawatt hours)

Eastern PJM:
Baseload	11,462	14,271		(2,809	)	(20	)%
Intermediate	705	1,120		(415	)	(37	)%
Peaking	100	218		(118	)	(54	)%
Total Eastern PJM	12,267	15,609		(3,342	)	(21	)%

Northeast:
Baseload	1,053	1,485		(432	)	(29	)%
Intermediate	242	395		(153	)	(39	)%
Peaking	9	7		2		29	%
Total Northeast	1,304	1,887		(583	)	(31	)%

California:
Intermediate	115	519		(404	)	(78	)%
Peaking(1)	—	(1	)	1		100	%
Total California	115	518		(403	)	(78	)%

Total	13,686	18,014		(4,328	)	(24	)%

(1) Negative amounts denote net energy used by the generating facility.

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

Eastern PJM. The decrease in our baseload and intermediate generation volumes was primarily as a result of contracting dark spreads and spark spreads.

Northeast. The decrease in our baseload and intermediate generation was primarily a reduction in our available capacity at our Bowline and Kendall generating facilities.

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

Financial Condition

Liquidity and Capital Resources

Management thinks that our liquidity position and cash flows from operations will be adequate to fund operating, maintenance and capital expenditures, to fund debt service and to meet other liquidity requirements. Management regularly monitors our ability to fund our operating, financing and investing activities. See note 4 to our consolidated financial statements for additional discussion of our debt.

Sources of Funds and Capital Structure

Maintaining sufficient liquidity in our business is crucial in order to mitigate the risk of future financial distress to us. Accordingly, we plan on a prospective basis for the expected liquidity requirements of our business considering the factors listed below:

· expected expenditures with respect to maintenance activities and capital improvements, and related outages;

· expected collateral postings in support of our business;

· effects of market price volatility on the amount of collateral postings for hedge transactions and risk management transactions;

· effects of market price volatility on fuel pre-payment requirements;

· seasonal and intra-month working capital requirements;

· debt service obligations; and

· costs associated with litigation, regulatory and tax proceedings.

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.

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

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The table below sets forth total cash and cash equivalents of GenOn Americas Generation and its subsidiaries at December 31, 2011 (in millions):

Cash and Cash Equivalents:
GenOn Americas Generation (excluding GenOn Mid-Atlantic)	$	199
GenOn Mid-Atlantic	68
Total cash and cash equivalents	$	267

We consider all short-term investments with an original maturity of three months or less to be cash equivalents. At December 31, 2011, except for amounts held in bank accounts to cover current payables, all of our cash and cash equivalents were invested in AAA-rated United States Treasury money market funds.

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

(1)	At December 31, 2011, the present value of lease payments under the GenOn Mid-Atlantic operating leases was approximately $881 million (assuming a 10% discount rate) and the termination value of the GenOn Mid-Atlantic operating leases was $1.3 billion.

Except for existing cash on hand, GenOn Americas Generation is a holding company that is dependent on the distributions and dividends of its subsidiaries for liquidity and, at its discretion, additional capital contributions from GenOn. 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 December 31, 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 $165.6 million of cash (which is included in funds on deposit on the unaudited consolidated balance sheet) in respect of such liens. See note 7 to our consolidated financial statements.

Pursuant to the terms of its lease documents, GenOn Mid-Atlantic is restricted from, among other actions, (a) encumbering assets, (b) entering into business combinations or divesting assets, (c) entering into transactions with affiliates on other than an arm’s length basis or (d) materially changing its business. Therefore, at

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December 31, 2011, all of GenOn Mid-Atlantic’s net assets (excluding cash) were deemed restricted for purposes of Rule 4-08(e)(3)(ii) of Regulation S-X.

The amounts of the deemed restricted net assets were as follows:

	December 31,
	2011		2010
	(in millions)

GenOn Mid-Atlantic	$	3,859	$	3,690

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

Uses of Funds

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

Capital Expenditures. Our capital expenditures, excluding capitalized interest, during 2011, were $156 million. Our estimated capital expenditures, excluding capitalized interest, for 2012 and 2013 are $165 million and $87 million, respectively. See above under, “Capital Expenditures and Capital Resources” for further discussion of our capital expenditures.

Debt Service. At December 31, 2011, we had $866 million of long-term debt ($4 million of which was classified as current) with expected interest payments of $76 million for 2012. See note 4 to our consolidated financial statements.

GenOn Mid-Atlantic Operating Leases. GenOn Mid-Atlantic leases a 100% interest in both the Dickerson and Morgantown baseload units and associated property through 2029 and 2034, respectively. GenOn Mid-Atlantic has 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 the GenOn Mid-Atlantic leases was $96 million for each of 2011, 2010 and 2009. The scheduled payment amounts for the GenOn Mid-Atlantic leases are $132 million and $138 million for 2012 and 2013, respectively. At December 31, 2011, the total notional minimum lease payments for the remaining term of the leases aggregated $1.6 billion and the aggregate termination value for the leases was approximately $1.3 billion and generally decreases over time. In addition, the present value of lease payments at December 31, 2011 was approximately $881 million (assuming a 10% discount rate). GenOn provides letters of credit in support of GenOn Mid-Atlantic’s lease obligations to post rent reserves in an aggregate amount equal to the greatest of the next six months scheduled rent payments, 50% of the next 12 months scheduled rent payments or $75 million.

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

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power pools, rent reserves, power purchases and sales, fuel and emissions 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 December 31, 2011, we had $156 million of posted cash collateral and GenOn had $171 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. See Item 1, “Business” for our discussion on the Dodd-Frank Act. See note 1 to our consolidated financial statements.

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

	December 31,
	2011		2010
	(in millions)

Cash collateral posted—energy trading and marketing	$	118	$	80
Cash collateral posted—other operating activities	38		40
Letters of credit—energy trading and marketing(1)	39		63
Letters of credit—rent reserves(1)	101		101
Letters of credit—other operating activities(1)	31		31
Surety bonds	6		7
Total	$	333	$	322

(1) At December 31, 2011, represents letters of credit posted by GenOn for the benefit of GenOn Americas Generation.

Historical Cash Flows

2011 Compared to 2010

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 by $80 million during 2011, compared to 2010, primarily as a result of the following:

· Realized gross margin. A decrease in cash provided of $378 million in 2011, compared to 2010, excluding a decrease in non-cash lower of cost or market inventory adjustment of $14 million. See “Results of Operations” in this Item 7 for additional discussion of our performance in 2011 compared to 2010; and

· Funds on deposit. An increase in cash used of $125 million primarily as a result of $38 million of additional collateral posted with our counterparties in 2011 compared to an additional $87 million collateral returned by our counterparties in 2010.

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

· Accounts payable, collateral. An increase in cash provided of $144 million primarily as a result of $122 million posted by our counterparties in 2011 compared to $22 million returned to our counterparties in 2010;

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· Inventories. A decrease in cash used of $106 million primarily related to changes in fuel oil inventory in 2011 compared to 2010;

· Interest Expense. A decrease in cash used of $97 million related to lower interest expense primarily resulting from the repayment of the GenOn North America senior notes in December 2010, the repayment of the GenOn North America term loan in January 2011 and the repayment of the GenOn Americas Generation senior unsecured notes in May 2011;

· Operating expenses. A decrease in cash used related to lower operations and maintenance expense of $45 million. See “Results of Operations” in this Item 7 for additional discussion of our performance in 2011 compared to 2010; and

· Other operating assets and liabilities. An increase in cash provided of $31 million related to changes in other operating assets and liabilities as compared to 2010.

Investing Activities. Net cash provided by investing activities increased by $1.481 billion during 2011 compared to 2010. This difference was primarily a result of the following:

· Withdrawals from restricted funds on deposit. An increase in cash provided of $866 million related to the withdrawal of cash used to redeem the GenOn North America senior notes. See note 4 to our consolidated financial statements;

· Payments into restricted funds on deposit. An increase in cash provided of $702 million primarily related to $866 million of funds deposited with the Trustee in 2010 for the GenOn North America senior notes, which were redeemed on January 3, 2011, partially offset by $166 million placed in restricted deposits as a result of our scrubber contract litigation and related liens. See notes 4 and 9 to our consolidated financial statements; and

· Capital expenditures. A decrease in cash used of $93 million primarily as a result of payments related to our Maryland scrubber projects; partially offset by

· Intercompany debt. An increase in cash used of $181 million related to the repayment of intercompany debt.

Financing Activities. Net cash used in financing activities increased by $1.758 billion during 2011 compared to 2010. This difference was primarily a result of the following:

· Repayment of long-term debt. An increase in cash used of $1.029 billion for repayment of long-term debt. See note 4 to our consolidated financial statements;

· Capital contributions. A decrease in cash provided of $605 million related to contributions made by our member; and

· Redemption of preferred stock. A decrease in cash provided of $295 million related to the redemption of Series A preferred stock held by GenOn Mid-Atlantic in 2010. There were no redemptions during 2011.

The increase in cash used and decreases in cash provided by financing activities were partially offset by the following:

· Distributions to member. A decrease in cash used of $122 million related to distributions to our member. In 2011, we distributed $100 million compared to $222 million distributed in 2010; and

· Intercompany debt. An increase in cash provided of $49 million related to proceeds received from intercompany debt.

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Item 7. Management’s Narrative Analysis of the Results of Operations and Financial Condition.

B. GenOn Mid-Atlantic

This section is intended to provide the reader with information that will assist in understanding GenOn Mid-Atlantic’s financial statements, the changes in those financial statements from year to year and the primary factors contributing to those changes. The following discussion should be read in conjunction with GenOn Mid-Atlantic’s consolidated financial statements and the notes accompanying those financial statements.

Merger of Mirant and RRI Energy

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

Our Business

We are a wholesale generator with approximately 5,209 MW of net electric generating capacity located near major metropolitan load centers in the PJM market. GenOn Americas Generation provides us with services that consist primarily of dispatching electricity, hedging the price of electricity we expect to generate, selling capacity and procuring and managing fuel and providing logistical support for the operation of the facilities (for example, by procuring transportation for coal and natural gas).

At January 24, 2012, total projected contracted capacity and PPA revenues for which prices have been set for 2012 through 2015 are $855 million.

In connection with the retirement of the Potomac River generating facility, we expect to incur some charges beginning in the first quarter of 2012. We are currently determining the appropriate amounts for these charges, which include write-offs for excess materials and supplies inventory, severance and other plant closure costs.

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 January 24, 2012, our aggregate hedge levels based on expected generation for each year were as follows:

	2012(1)		2013		2014		2015		2016

Power	98	%	84	%	42	%	32	%	30	%
Fuel	86	%	70	%	10	%	—	%	—	%

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

See Item 1A, “Risk Factors—Risks Related to Economic and Financial Market Conditions” for a discussion of:

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such transactions on exchanges or meet other requirements, by significantly increasing the collateral costs associated with such activities.

Capital Expenditures and Capital Resources

For 2011, we invested $147 million for capital expenditures. Capital expenditures for the period primarily relate to maintenance capital expenditures, the construction of an ash beneficiation facility and include the $68 million payment to Stone & Webster for substantial completion of the Maryland scrubber projects. At December 31, 2011, we have invested $1.591 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 our Maryland coal-fired units provide for certain payments to be made after final completion of the projects. Assuming we are successful in pursuing our claims in the New York proceeding, the total estimated capital expenditures for compliance with the Maryland Healthy Air Act would not exceed the $1.674 billion we currently have recorded. However, if the costs were to equal the amount claimed by Stone & Webster in the litigation, the total capital expenditures would exceed $1.674 billion by approximately 5%. See note 9 to our consolidated financial statements for further discussion involving the scrubber contract litigation.

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

	2012		2013
	(in millions)

Maryland Healthy Air Act	$	83	$	—
Other environmental	5		4
Maintenance	34		49
Other construction	12		—
Total	$	134	$	53

Environmental Matters

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

Commodity Prices

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

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Results of Operations

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

2011 Compared to 2010

Consolidated Financial Performance

We reported net income of $105 million and net loss of $781 million for 2011 and 2010, respectively. The change in net income/loss is detailed as follows:

	2011			2010			Increase/ (Decrease)
	(in millions)

Gross margin:
Energy	$	163		$	384		$	(221	)
Contracted and capacity	245			335			(90		)
Realized value of hedges	274			280			(6		)
Realized gross margin	682			999			(317		)
Unrealized gross margin	120			7			113
Total gross margin (excluding depreciation and amortization)	802			1,006			(204		)
Operating expenses:
Operations and maintenance	301			299			2
Operations and maintenance—affiliate	166			194			(28		)
Depreciation and amortization	131			141			(10		)
Impairment losses	94			1,153			(1,059		)
Gain on sales of assets, net—affiliate	—			(3		)	3
Total operating expenses, net	692			1,784			(1,092		)
Operating income (loss)	110			(778		)	888
Other expense, net:
Interest expense, net	(1		)	(3		)	(2		)
Interest expense, net—affiliate	(4		)	—			4
Other, net	—			(1		)	(1		)
Total other income (expense), net	(5		)	(4		)	1
Income (loss) before income taxes	105			(782		)	887
Benefit for income taxes	—			(1		)	1
Net income (loss)	$	105		$	(781	)	$	886

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

Realized Gross Margin. The decrease of $317 million in realized gross margin was principally a result of the following:

· a decrease of $221 million in energy primarily as a result of a decrease in generation volumes as a result of contracting dark spreads and spark spreads;

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· a decrease of $90 million in contracted and capacity as a result of a $81 million decrease from lower capacity prices and volume and a $9 million decrease from ancillary services; and

· a decrease of $6 million in realized value of hedges, primarily as a result of a $37 million decrease in power hedges primarily resulting from prices, offset in part by a $28 million increase in our coal hedges resulting from prices.

· unrealized gains of $120 million in 2011, which included a $338 million net increase in the value of hedge contracts for future periods primarily related to decreases in forward power and natural gas prices, offset by $218 million associated with the reversal of previously recognized unrealized gains from power and fuel contracts that settled during the period; and

· unrealized gains of $7 million in 2010, which included a $326 million net increase in the value of hedge contracts for future periods primarily related to decreases in forward power and natural gas prices, offset in part by the recognition of many of our coal agreements at fair value beginning in the second quarter of 2010. The increase in value was substantially offset by $319 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 $1.1 billion was principally a result of the following:

· a decrease of $1.1 billion in impairment losses. In 2011, we recognized $94 million in impairment losses for the write-off of excess NOx and SO2 emissions allowances as a result of the CSAPR. In 2010, we recognized $1.2 billion in impairment losses, including $616 million related to the write-off of goodwill and $537 million related to our Dickerson and Potomac River generating facilities. See note 3 to our consolidated financial statements.

· a decrease of $26 million in operations and maintenance expense primarily related to the following

· a decrease of $22 million resulting from a change in the allocation methodology for overhead costs and a larger number of generating facilities to which the allocated costs are distributed, both as a result of the Merger;

· a decrease of $20 million resulting from decreases of variable operations and maintenance, outage expenses and some labor costs;

· a decrease of $17 million as a result of the repeal of the Montgomery County CO2 levy, including $8 million related to a refund received in 2011 of CO2 levies paid in 2010; and

· a decrease of $6 million resulting from changes in asset retirement obligation assumptions, partially offset by

· a $49 million accrual for remediation costs at our Maryland ash facilities (which includes a tentative $1.9 million civil penalty);

· $15 million recognized in 2011for major litigation costs, net of recoveries; and

· a $10 million accrual for the Brandywine storm damage and remediation; and

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· a decrease of $10 million in depreciation and amortization expense primarily as a result of reductions in the carrying values of the Dickerson and Potomac River generating facilities as a result of impairment losses in 2010.

Operating Statistics

Our power generation volumes during 2011 (in gigawatt hours) were 12,267 compared to 15,609 during 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

· expected expenditures with respect to maintenance activities and capital improvements, and related outages;

· expected collateral postings in support of our business;

· effects of market price volatility on the amount of collateral postings for hedge transactions and risk management transactions;

· effects of market price volatility on fuel pre-payment requirements; and

· seasonal and intra-month working capital requirements.

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 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 December 31, 2011, except for amounts held in bank accounts to cover upcoming payables, all of our cash and cash equivalents were invested in AAA-rated United States Treasury money market funds.

At December 31, 2011, we had $68 million of cash, which amount was available under the operating leases for distribution to GenOn North America.

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

Uses of Funds

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

Capital Expenditures. Our capital expenditures during 2011 were $147 million. We estimate our capital expenditures for 2012 and 2013 are $134 million and $53 million, respectively. See above under, “Capital Expenditures and Capital Resources” for further discussion of our capital expenditures.

Operating Leases. We lease 100% interest 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 $96 million for each of 2011, 2010 and 2009. The scheduled payment amounts for our leases are $132 million and $138 million for 2012 and 2013, respectively. At December 31, 2011, the total notional minimum lease payments for the remaining term of the leases aggregated $1.6 billion and the aggregate termination value for the leases was approximately $1.3 billion and generally decreases over time. In addition, the present value of lease payments at December 31, 2011 was approximately $881 million (assuming a 10% discount rate). GenOn provides letters of credit in support of our lease obligations in an aggregate amount equal to the greatest of the next six months scheduled rent payments, 50% of the next 12 months scheduled rent payments or $75 million.

2011 Compared to 2010

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 $261 million during 2011, compared to 2010, primarily as a result of the following:

· Realized gross margin. A decrease in cash provided of $322 million in 2011, compared to 2010, excluding a decrease in non-cash lower of cost or market fuel inventory adjustment of $5 million. See “Results of Operations” in this Item 7 for additional discussion of our performance in 2011 as compared to 2010; and

· Inventories. An increase in cash used of $35 million primarily as a result of larger volumes of coal purchased at higher average prices in 2011 as compared to 2010.

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

· Net accounts receivables and accounts payables. An increase in cash provided of $65 million primarily related to a decrease in power prices and generation volumes in 2011 compared to 2010; and

· Other operating assets and liabilities. A decrease in cash used of $31 million related to changes in other operating assets and liabilities compared to 2010.

Investing Activities. Net cash used in investing activities increased by $84 million during 2011, compared to 2010. This difference was primarily a result of the following:

· Restricted funds on deposit, net. A net decrease in cash provided of $167 million primarily related to $234 million placed in restricted deposits as a result of our scrubber contract litigation and related liens, partially offset by $68 million related to the withdrawal of cash used to reduce the outstanding lien

Table of Contents

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

Item 11. Executive Compensation.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

Item 13. Certain Relationships and Related Transactions and Director Independence.

Each of Items 10 through 13 has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

Item 14. Principal Accountant Fees and Services.

KPMG LLP conducts an integrated audit of GenOn and its subsidiaries. As such, GenOn Americas Generation and GenOn Mid-Atlantic do not separately arrange for audit services. A significant portion of the fees for professional audit services and other services rendered by KPMG LLP were allocated to us through the Administrative Services Agreement with GenOn Energy Services as described in note 6 to our consolidated financial statements. Prior to the Merger, the Mirant Audit Committee pre-approved all audit services and permissible non-audit services provided by the independent auditor. As provided in the GenOn Audit Committee Charter, the GenOn Audit Committee pre-approved all audit services and permissible non-audit services provided by the independent auditor from the time of the Merger and for the remainder of fiscal year 2010 and for fiscal year 2011.

The following table shows the aggregate fees related to the audit and other services provided by KPMG LLP for fiscal years 2011 and 2010. Amounts in the table for periods prior to the consummation of the Merger on December 3, 2010 reflect amounts paid by Mirant to KPMG LLP.

	2011		2010
	(in thousands)

Audit Fees(1)	$	5,390	$	5,867
Audit-Related Fees(2)	25		754
Tax Fees(3)	—		—
All Other Fees(4)	—		—
Total	$	5,415	$	6,621

(1) Includes fees and expenses related to the audit of GenOn’s consolidated financial statements and the effectiveness of GenOn’s internal controls over financial reporting. This category also includes the review of financial statements included in GenOn’s Quarterly Reports on Form 10-Q, the audits of various subsidiary financial statements required by statute or regulation, and services that are normally provided by the independent auditors in connection with regulatory filings or engagements, consultations provided on audit and accounting matters that arose during, or as a result of, the audits or the reviews of interim financial statements, and the preparation of any written communications on internal control matters.

(2) Consists of accounting consulting, assurance and related services that are reasonably related to the performance of the audit or review of our financial statements, which during 2011 and 2010 related to the Merger, and are not reported above under “Audit Fees.”

(3) Consists of professional services rendered for general tax consulting services.

(4) Consists of fees for services provided by KPMG LLP, other than fees for the services listed in the other categories.

Table of Contents

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

CONSOLIDATED STATEMENTS OF OPERATIONS

	2011			2010			2009
	(in millions)

Operating revenues (including unrealized gains (losses) of $252, $69 and $(2), respectively)	$	3,015		$	2,102		$	2,309
Operating revenues—affiliate (including unrealized gains (losses) of $(112), $3 and $0, respectively)	(77		)	3			—
Total operating revenues	2,938			2,105			2,309
Cost of fuel, electricity and other products (including unrealized (gains) losses of $7, $89 and $(49), respectively)	677			846			701
Cost of fuel, electricity and other products—affiliate (including unrealized (gains) losses of $(5), $0 and $0, respectively)	1,220			8			9
Total cost of fuel, electricity and other products	1,897			854			710
Gross Margin (excluding depreciation and amortization)	1,041			1,251			1,599
Operating Expenses:
Operations and maintenance	378			390			355
Operations and maintenance—affiliate	228			293			291
Depreciation and amortization	177			199			142
Impairment losses	128			565			221
Gain on sales of assets, net	(5		)	(4		)	(22		)
(Gain) loss on sales of assets, net—affiliate	2			(5		)	—
Total operating expenses	908			1,438			987

Operating Income (Loss)	133			(187		)	612

Other Income (Expense), net:
Interest expense	(88		)	(200		)	(137		)
Interest expense—affiliate	(5		)	—			—
Interest income	—			—			1
Other, net	(24		)	(9		)	(1		)
Total other expense, net	(117		)	(209		)	(137		)
Net Income (Loss)	$	16		$	(396	)	$	475

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

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

CONSOLIDATED BALANCE SHEETS

	December 31,
	2011		2010
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents	$	267	$	514
Funds on deposit	316		949
Receivables, net	288		363
Receivables, net—affiliate	22		4
Note receivable—affiliate	181		—
Derivative contract assets	977		1,288
Derivative contract assets— affiliate	44		5
Inventories	257		295
Prepaid rent and other expenses	113		124
Total current assets	2,465		3,542
Property, Plant and Equipment, net	2,934		3,077
Noncurrent Assets:
Intangible assets, net	28		101
Derivative contract assets	731		689
Derivative contract assets—affiliate	29		3
Prepaid rent	386		348
Debt issuance costs, net	6		12
Other	10		41
Total noncurrent assets	1,190		1,194
Total Assets	$	6,589	$	7,813

LIABILITIES AND MEMBER’S EQUITY
Current Liabilities:
Current portion of long-term debt	$	4	$	1,389
Accounts payable and accrued liabilities	509		527
Payables, net—affiliate	93		54
Notes payable—affiliate	47		—
Derivative contract liabilities	700		1,130
Derivative contract liabilities—affiliate	76		3
Other	25		8
Total current liabilities	1,454		3,111
Noncurrent Liabilities:
Long-term debt, net of current portion	862		866
Derivative contract liabilities	100		173
Derivative contract liabilities—affiliate	89		—
Other	119		90
Total noncurrent liabilities	1,170		1,129
Commitments and Contingencies
Member’s Equity:
Member’s interest	3,965		3,573
Total member’s equity	3,965		3,573
Total Liabilities and Member’s Equity	$	6,589	$	7,813

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

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

CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY

	Member’s Interest			Preferred Stock in Affiliate			Total Member’s Equity
	(in millions)

Balance, December 31, 2008	$	2,718		$	(345	)	$	2,373
Net income	475			—			475
Amortization of discount on preferred stock in affiliate	19			(19		)	—
Redemption of preferred stock in affiliate	—			84			84
Distributions to member	(115		)	—			(115		)
Balance, December 31, 2009	3,097			(280		)	2,817
Net loss	(396		)	—			(396		)
Amortization of discount on preferred stock in affiliate	15			(15		)	—
Redemption of preferred stock in affiliate	—			295			295
Distributions to member	(222		)	—			(222		)
Capital contributions	1,079			—			1,079
Balance, December 31, 2010	3,573			—			3,573
Net income	16			—			16
Distributions to member	(100		)	—			(100		)
Capital contributions	476			—			476
Balance, December 31, 2011	$	3,965		$	—		$	3,965

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

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

CONSOLIDATED STATEMENTS OF CASH FLOWS

	2011			2010			2009
	(in millions)
Cash Flows from Operating Activities:
Net income (loss)	$	16		$	(396	)	$	475
Adjustments to reconcile net income (loss) and changes in operating assets and liabilities to net cash provided by operating activities:
Depreciation and amortization	176			207			152
Impairment losses	128			565			221
Gain on sales of assets, net	(3		)	(9		)	(22		)
Net changes in derivative contracts	(138		)	17			(47		)
Lower of cost or market inventory adjustments	8			22			32
Loss on early extinguishment of debt	23			—			—
Potomac River settlement obligation	—			32			—
Other, net	—			10			—
Changes in operating assets and liabilities:
Receivables, net	75			38			342
Receivables, net—affiliate	(20		)	(2		)	—
Funds on deposit	(38		)	87			26
Prepaid rent	(38		)	(44		)	(46		)
Inventories	30			(76		)	(35		)
Other assets	12			5			(10		)
Accounts payable and accrued liabilities	48			(18		)	(326		)
Payables, net—affiliate	39			—			8
Taxes accrued	16			5			(7		)
Other liabilities	30			1			3
Total adjustments	348			840			291
Net cash provided by operating activities	364			444			766
Cash Flows from Investing Activities:
Capital expenditures	(159		)	(252		)	(666		)
Proceeds from the sales of assets	9			8			25
Restricted funds on deposit, net	702			(866		)	1
Issuance of notes receivables—affiliate	(181		)	—			—
Net cash provided by (used in) investing activities	371			(1,110		)	(640		)
Cash Flows from Financing Activities:
Redemption of preferred stock in affiliate	—			295			84
Repayment of long-term debt	(1,405		)	(376		)	(45		)
Issuance of notes payable—affiliate	49			—			—
Capital contributions	474			1,079			—
Distributions to member	(100		)	(222		)	(115		)
Net cash provided by (used in) financing activities	(982		)	776			(76		)
Net Increase (Decrease) in Cash and Cash Equivalents	(247		)	110			50
Cash and Cash Equivalents, beginning of year	514			404			354
Cash and Cash Equivalents, end of year	$	267		$	514		$	404

Supplemental Cash Flow Disclosures:
Cash paid for interest, net of amounts capitalized	$	94		$	185		$	124
Cash refunds received for income taxes	$	1		$	—		$	—
Supplemental Disclosures for Non-Cash Financing Activities:
Conversion to equity of notes payable to affiliate	$	2		$	—		$	—

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

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

CONSOLIDATED STATEMENTS OF OPERATIONS

	2011			2010			2009
	(in millions)
Operating revenues (including unrealized gains of $74, $123 and $137, respectively)	$	260		$	347		$	401
Operating revenues—affiliate (including unrealized gains (losses) of $45, $(43) and $(1), respectively)	1,087			1,357			1,377
Total operating revenues	1,347			1,704			1,778
Cost of fuel, electricity and other products (including unrealized (gains) losses of $0, $0 and $0, respectively)	18			18			17
Cost of fuel, electricity and other products—affiliate (including unrealized (gains) losses of $(1), $73 and $(8), respectively)	527			680			510
Total cost of fuel, electricity and other products	545			698			527

Gross Margin (excluding depreciation and amortization)	802			1,006			1,251
Operating Expenses:
Operations and maintenance	301			299			245
Operations and maintenance—affiliate	166			194			189
Depreciation and amortization	131			141			98
Impairment losses	94			1,153			385
Gain on sales of assets, net—affiliate	—			(3		)	(14		)
Total operating expenses	692			1,784			903

Operating Income (Loss)	110			(778		)	348
Other Income (Expense), net:

Interest expense	(1		)	(3		)	(3		)
Interest expense—affiliate	(4		)	—			—
Other, net	—			(1		)	(1		)
Total other income (expense), net	(5		)	(4		)	(4		)

Income (Loss) Before Income Taxes	105			(782		)	344
Benefit for income taxes	—			(1		)	—
Net Income (Loss)	$	105		$	(781	)	$	344

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

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

CONSOLIDATED BALANCE SHEETS

	December 31,
	2011		2010
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents	$	68	$	202
Funds on deposit	198		2
Receivables, net	25		21
Receivables, net—affiliate	44		169
Derivative contract assets	208		162
Derivative contract assets—affiliate	191		245
Inventories	167		122
Prepaid rent	96		96
Other	4		11
Total current assets	1,001		1,030
Property, Plant and Equipment, net	2,444		2,533
Noncurrent Assets:
Intangible assets, net	16		71
Derivative contract assets	526		516
Derivative contract assets—affiliate	105		97
Prepaid rent	386		348
Other	—		31
Total noncurrent assets	1,033		1,063
Total Assets	$	4,478	$	4,626

LIABILITIES AND MEMBER’S EQUITY
Current Liabilities:
Current portion of long-term debt	$	4	$	4
Accounts payable and accrued liabilities	82		63
Payables, net—affiliate	44		114
Derivative contract liabilities	—		18
Derivative contract liabilities—affiliate	168		231
Contract retention liability	69		132
Other	24		8
Total current liabilities	391		570
Noncurrent Liabilities:
Long-term debt, net of current portion	14		18
Derivative contract liabilities—affiliate	68		94
Other	78		52
Total noncurrent liabilities	160		164
Commitments and Contingencies
Member’s Equity:
Member’s interest	3,927		3,892
Total member’s equity	3,927		3,892
Total Liabilities and Member’s Equity	$	4,478	$	4,626

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

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

CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY

	Member’s Interest			Preferred Stock in Affiliate			Total Member’s Equity
	(in millions)

Balance, December 31, 2008	$	4,786		$	(211	)	$	4,575
Net income	344			—			344
Amortization of discount on preferred stock in affiliate	11			(11		)	—
Redemption of preferred stock in affiliate	—			84			84
Distributions to member	(125		)	—			(125		)
Balance, December 31, 2009	5,016			(138		)	4,878
Net loss	(781		)	—			(781		)
Amortization of discount on preferred stock in affiliate	7			(7		)	—
Redemption of preferred stock in affiliate	—			145			145
Distributions to member	(350		)	—			(350		)
Balance, December 31, 2010		3,892			—			3,892
Net income	105			—			105
Distributions to member	(100		)	—			(100		)
Capital contributions	30			—			30
Balance, December 31, 2011	$	3,927		$	—		$	3,927

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

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

CONSOLIDATED STATEMENTS OF CASH FLOWS

	2011			2010			2009
	(in millions)
Cash Flows from Operating Activities:
Net income (loss)	$	105		$	(781	)	$	344
Adjustments to reconcile net income (loss) and changes in operating assets and liabilities to net cash provided by operating activities:
Depreciation and amortization	131			141			98
Impairment losses	94			1,153			385
Gain on sales of assets, net	—			(3		)	(14		)
Net changes in derivative contracts	(120		)	(7		)	(144		)
Lower of cost or market inventory adjustments	8			13			29
Potomac River settlement obligation	—			32			—
Changes in operating assets and liabilities:
Receivables, net	(4		)	6			(11		)
Receivables, net—affiliate	125			18			24
Prepaid rent	(38		)	(44		)	(46		)
Inventories	(53		)	(18		)	(17		)
Other assets	5			6			(9		)
Accounts payable and accrued liabilities	27			6			—
Payables, net—affiliate	(70		)	(17		)	(19		)
Taxes accrued	16			6			(7		)
Other liabilities	26			2			(6		)
Total adjustments	147			1,294			263
Net cash provided by operating activities	252			513			607
Cash Flows from Investing Activities:
Capital expenditures	(147		)	(233		)	(578		)
Proceeds from the sales of assets	1			4			14
Restricted deposit payments and other	(166		)	1			1
Net cash used in investing activities	(312		)	(228		)	(563		)
Cash Flows from Financing Activities:
Redemption of preferred stock in affiliate	—			145			84
Repayment of long-term debt	(4		)	(3		)	(3		)
Capital contributions	30			—			—
Distributions to member	(100		)	(350		)	(125		)
Net cash used in financing activities	(74		)	(208		)	(44		)
Net Increase (Decrease) in Cash and Cash Equivalents	(134		)	77			—
Cash and Cash Equivalents, beginning of year	202			125			125
Cash and Cash Equivalents, end of year	$	68		$	202		$	125

Supplemental Cash Flow Disclosures:
Cash paid for interest	$	—		$	2		$	2
Cash refund received for income taxes	$	1		$	—		$	—

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

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GenOn was formed as a Delaware corporation in August 2000 by CenterPoint (then known as Reliant Energy, Incorporated) in connection with the planned separation of its regulated and unregulated operations. CenterPoint transferred substantially all of its unregulated businesses, including the name Reliant Energy, to the company now named GenOn Energy, Inc. In May 2001, Reliant Energy (then known as Reliant Resources, Inc.) became a publicly traded company and in September 2002, CenterPoint distributed its remaining ownership of Reliant Energy’s common stock to its stockholders. RRI Energy changed its name from Reliant Energy, Inc. effective May 2, 2009 in connection with the sale of its retail business. GenOn changed its name from RRI Energy, Inc. effective December 3, 2010 in connection with the Merger. “We,” “us,” and “our” refer to GenOn Americas Generation, LLC and GenOn Mid-Atlantic, LLC, and, except where the context indicates otherwise, its subsidiaries.

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 6.

Merger of Mirant and RRI Energy

On December 3, 2010, Mirant and RRI Energy completed the Merger. Upon completion of the Merger, RRI Energy Holdings, Inc., a direct and wholly-owned subsidiary of RRI Energy merged with and into Mirant, with Mirant continuing as the surviving corporation and a wholly-owned subsidiary of RRI Energy. Each of Mirant and RRI Energy received legal opinions that the Merger qualified as a tax-free reorganization under the IRC. Upon the closing of the Merger, each issued and outstanding share of Mirant common stock, including grants of restricted common stock, automatically converted into 2.835 shares of common stock of RRI Energy based on the Exchange Ratio. Approximately 417 million shares of RRI Energy common stock were issued. Additionally, upon the closing of the Merger, RRI Energy was renamed GenOn. Mirant stock options and other equity awards converted upon completion of the Merger into stock options and equity awards with respect to GenOn common stock, after giving effect to the Exchange Ratio. See note 4 for additional information on the related debt transactions.

Basis of Presentation

The consolidated financial statements have been prepared in accordance wit h GAAP from records maintained by us and our subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.

At December 31, 2011 and 2010, substantially all of our subsidiaries are wholly-owned and located in the United States. We did not consolidate two power generating facilities, which are under operating leases (see note 7).

Use of Estimates

The preparation of consolidated 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 consolidated 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.

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We evaluate events that occur after the balance sheet date and through the date 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.

Revenue Recognition

GenOn Americas Generation

GenOn Americas Generation recognizes revenue when earned and collection is probable. GenOn Americas Generation earns revenue from the following sources: (a) power generation revenues, (b) contracted and capacity revenues, (c) power hedging revenues and (d) fuel sales and proprietary trading revenues.

Power Generation Revenues. GenOn Americas Generation recognizes revenue from the sale of electricity from its generating facilities. Sales of energy primarily are based on economic dispatch, or “as-ordered” by an ISO or RTO, based on member participation agreements, but without an underlying contractual commitment. ISO and RTO revenues and revenues from sales of energy based on economic-dispatch are recorded on the basis of MWh delivered, at the relevant day-ahead or real-time prices. Additionally, GenOn Americas Generation includes revenue from the sale of steam in power generation revenues.

Contracted and Capacity Revenues. GenOn Americas Generation recognizes revenue received from providing ancillary services and revenue received from an ISO or RTO based on auction results or negotiated contract prices for making installed generation capacity available to meet system reliability requirements. In addition, when a long-term electric power agreement conveys to the buyer of the electric power the right to control the generating capacity of GenOn Americas Generation’s facility, that agreement is evaluated to determine if it is a lease of the generating facility rather than a sale of electric power. Operating lease revenue for GenOn Americas Generation’s generating facilities is normally recorded as capacity revenue.

Power Hedging Revenues. GenOn Americas Generation recognizes revenue from contracts for the sale of both power and natural gas used to hedge power prices as well as for hedges to capture the incremental value related to the geographic location of its physical assets.

Fuel Sales and Proprietary Trading Revenues. GenOn Americas Generation recognizes revenue from the sale of fuel oil and natural gas and revenues associated with fuel oil management and proprietary trading activities.

The following table reflects GenOn Americas Generation’s revenues by type:

	2011		2010		2009
	(in millions)

Power generation revenues	$	1,677	$	1,122	$	805
Contracted and capacity revenues	796		560		592
Power hedging revenues	410		394		845
Fuel sales and proprietary trading revenues	55		29		67
Total operating revenues	$	2,938	$	2,105	$	2,309

In accordance with accounting guidance related to derivative financial instruments, physical transactions, or revenues from the sale of generated electricity to ISOs and RTOs are recorded on a gross basis in the consolidated statements of operations. Financial transactions, or the buying and selling of energy for trading purposes, are recorded on a net basis in the consolidated statements of operations.

GenOn Mid-Atlantic

GenOn Mid-Atlantic recognizes revenue from the sale of energy when earned and collection is probable. GenOn Mid-Atlantic recognizes revenue when electric power is delivered to an affiliate or to a customer pursuant to

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contractual commitments that specify volume, price and delivery requirements. GenOn Mid-Atlantic earns revenue from the following sources: (a) power generation revenues, (b) power hedging revenues and (c) contracted and capacity revenues, as defined above.

The following table reflects GenOn Mid-Atlantic’s revenues by type:

	2011		2010		2009
	(in millions)

Power generation revenues	$	719	$	990	$	659
Power hedging revenues	383		379		770
Contracted and capacity revenues	245		335		349
Total operating revenues	$	1,347	$	1,704	$	1,778

Cost of Fuel, Electricity and Other Products

Cost of fuel, electricity and other products on our consolidated statements of operations includes the costs of goods produced and sold through the combustion process, including the costs associated with handling and disposal of ash, natural gas transportation and services rendered during a reporting period. Cost of fuel, electricity and other products also includes purchased emissions allowances for CO2, SO2 and NOx and the settlements of and changes in fair value of derivative financial instruments used to hedge fuel economically. Additionally, cost of fuel, electricity and other products includes lower of cost or market inventory adjustments. Cost of fuel, electricity and other products excludes depreciation and amortization. Gross margin is total operating revenues less cost of fuel, electricity and other products.

Derivatives and Hedging Activities

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

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.

If certain criteria are met, a derivative financial instrument may be designated as a fair value hedge or cash flow hedge. We did not have any derivative financial instruments that were designated as fair value or cash flow hedges for accounting purposes during 2011, 2010, or 2009.

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

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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 revenues 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. See note 2.

Concentration of Revenues

During 2011, GenOn Americas Generation had $1.3 billion in revenues from PJM, which represented 44% of consolidated revenues. The revenues generated from this counterparty in 2011 are included in the Eastern PJM and Energy Marketing segments. During 2010, GenOn Americas Generation had $1.3 billion in revenues from PJM, which represented 63% of consolidated revenues. The revenues generated from this counterparty in 2010 are included in the Eastern PJM and Energy Marketing segments. During 2009, GenOn Americas Generation had $1.0 billion in revenues from PJM, which represented 43% of consolidated revenues. The revenues generated from this counterparty in 2009 are primarily included in the Eastern PJM segment. Additionally, during 2009, GenOn Americas Generation had $332 million in revenues from another counterparty, which represented 14% of consolidated revenues. The revenues generated from this counterparty in 2009 are included in the Eastern PJM, Energy Marketing and Other Operations segments.

During 2011, GenOn Mid-Atlantic had $963 million in revenues from PJM, which represented 72% of consolidated revenues. During 2010, GenOn Mid-Atlantic had $1.3 billion in revenues from PJM, which represented 78% of consolidated revenues. During 2009, GenOn Mid-Atlantic had $1.0 billion in revenues from PJM, which represented 56% of consolidated revenues. Additionally, during 2009 GenOn Mid-Atlantic had $191 million in revenues from another counterparty, which represented 11% of consolidated revenues.

Coal Supplier Concentration Risk

Our coal supply comes primarily from the Northern Appalachian and Central Appalachian coal regions. GenOn Americas Generation enters into contracts of varying tenors on behalf of GenOn Mid-Atlantic to secure appropriate quantities of fuel that meet the varying specifications of GenOn Mid-Atlantic’s generating facilities. For the coal-fired generating facilities, GenOn Americas Generation purchases most of its coal from a small number of suppliers under contracts with terms of varying lengths, some of which extend to 2014. We had exposure to three counterparties at December 31, 2011, and exposure to two counterparties at December 31, 2010, that each represented an exposure of more than 10% of our total coal commitments, by volume, for the respective succeeding year, and in aggregate represented approximately 62% and 60% of our total coal commitments at December 31, 2011 and 2010, respectively. At December 31, 2011 and 2010, the single largest counterparty represented an exposure of 38% and 39%, respectively, of these total coal commitments, by volume.

Coal Transportation Concentration Risk

The coal to operate our coal-fired facilities (all of which are owned or leased by GenOn Mid-Atlantic) is delivered primarily by train and we have a limited number of railroads transporting such coal. For 2011, one railroad represented 93% of our coal transportation costs.

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Concentration of Labor Subject to Collective Bargaining Agreements

GenOn Energy Services, an indirect wholly-owned subsidiary of GenOn, provides our personnel under a services agreement. At December 31, 2011, 70% of GenOn Americas Generation’s total employees are subject to collective bargaining agreements. Of those employees subject to collective bargaining agreements, 73% are represented by IBEW Local 1900 in the Eastern PJM segment. At December 31, 2011, 70% of GenOn Mid-Atlantic’s total employees are subject to collective bargaining agreements and are represented by IBEW Local 1900. No employees are subject to a collective bargaining agreement that will expire in 2012.

Cash and Cash Equivalents

GenOn Americas Generation and GenOn Mid-Atlantic consider all short-term investments with an original maturity of three months or less to be cash equivalents. At December 31, 2011 and 2010, except for amounts held in bank accounts to cover current payables, all of our cash and cash equivalents were invested in AAA-rated United States Treasury money market funds.

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

	December 31,
	2011		2010
	(in millions)

Cash collateral posted — energy trading and marketing	$	118	$	80
Cash collateral posted — other operating activities(1)	38		40
GenOn Mid-Atlantic restricted cash(2)	166		—
Funds deposited with the trustee to discharge the GenOn North America senior notes, due 2013(3)	—		866
Total current and noncurrent funds on deposit	322		986
Less: Current funds on deposit	316		949
Total noncurrent funds on deposit	$	6	$	37

(1) Includes $32 million related to the Potomac River settlement. See note 3.

(2) Represents cash reserved in respect of interlocutory liens related to the scrubber contract litigation. See note 9.

(3) See note 4 for discussion of the related debt.

GenOn Mid-Atlantic

	December 31,
	2011		2010
	(in millions)

GenOn Mid-Atlantic restricted cash(1)	$	166	$	—
Cash collateral posted(2)	32		32
Total current and noncurrent funds on deposit	198		32
Less: Current funds on deposit	198		2
Total noncurrent funds on deposit	$	—	$	30

(1) Represents cash reserved in respect of interlocutory liens related to the scrubber contract litigation. See note 9.

(2) Represents amount related to the Potomac River settlement. See note 3.

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Inventories

Inventories consist primarily of materials and supplies, fuel oil, coal and purchased emissions allowances. Inventory is generally stated at the lower of cost or market value and is expensed on a weighted average cost basis. Fuel inventory is removed from the inventory account as it is used in the generation of electricity or sold to third parties, including sales related to GenOn Americas Generation’s fuel oil management activities. Materials and supplies are removed from the inventory account when they are used for repairs, maintenance or capital projects. Purchased emissions allowances are removed from inventory and charged to cost of fuel, electricity and other products in the consolidated statements of operations as they are utilized for emissions volumes.

Inventories were comprised of the following:

GenOn Americas Generation

	December 31,
	2011		2010
	(in millions)
Fuel inventory:
Coal	$	92	$	52
Fuel oil	68		136
Natural gas	1		—
Other	3		1
Materials and supplies	74		72
Purchased emissions allowances	19		34
Total inventories	$	257	$	295

GenOn Mid-Atlantic

	December 31,
	2011		2010
	(in millions)

Fuel inventory:
Coal	$	92	$	52
Fuel oil	20		20
Other	3		1
Materials and supplies	52		49
Total inventories	$	167	$	122

During 2011, 2010 and 2009, GenOn Americas Generation recorded $8 million, $22 million and $32 million, respectively, for lower of average cost or market valuation adjustments in cost of fuel, electricity and other products.

During 2011, 2010 and 2009, GenOn Mid-Atlantic recorded $8 million, $13 million and $29 million, respectively, for lower of average cost or market valuation adjustments in cost of fuel, electricity and other products.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost, which includes materials, labor, associated payroll-related and overhead costs and the cost of financing construction. The cost of routine maintenance and repairs, such as inspections and corrosion removal, and the replacement of minor items of property are charged to expense as incurred. Certain expenditures incurred during a major maintenance outage of a generating facility are capitalized, including the replacement of major component parts and labor and overhead incurred to install the parts. Depreciation of the recorded cost of depreciable property, plant and equipment is determined using primarily

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composite rates. Leasehold improvements are depreciated over the shorter of the expected life of the related equipment or the lease term. Upon the retirement or sale of property, plant and equipment, the cost of such assets and the related accumulated depreciation are removed from the consolidated balance sheets. No gain or loss is recognized for ordinary retirements in the normal course of business since the composite depreciation rates used by us take into account the effect of interim retirements.

Impairment of Long-Lived Assets

GenOn Americas Generation and GenOn Mid-Atlantic evaluate long-lived assets, such as property, plant and equipment and purchased intangible assets subject to amortization, for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Such evaluations are performed in accordance with the accounting guidance related to evaluating long-lived assets for impairment. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated undiscounted future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future net cash flows, an impairment charge is recognized as the amount by which the carrying amount of the asset exceeds its fair value. See note 3.

Capitalization of Interest Cost (GenOn Americas Generation)

GenOn Americas Generation capitalizes interest on projects during their construction period. GenOn Americas Generation determines which debt instruments represent a reasonable measure of the cost of financing construction in terms of interest costs incurred that otherwise could have been avoided. These debt instruments and associated interest costs are included in the calculation of the weighted average interest rate used for determining the capitalization rate. Once a project is placed in service, capitalized interest, as a component of the total cost of the construction, is depreciated over the estimated useful life of the asset constructed.

During 2011, 2010 and 2009, GenOn Americas Generation incurred the following interest costs:

	2011			2010			2009
	(in millions)

Total interest costs	$	96		$	205		$	209
Capitalized and included in property, plant and equipment, net	(3		)	(5		)	(72		)
Interest expense	$	93		$	200		$	137

The amounts of capitalized interest above include interest accrued. During 2011, 2010 and 2009, cash paid for interest was $97 million, $190 million and $192 million, respectively, of which $3 million, $5 million and $68 million, respectively, were capitalized.

Environmental Costs

We expense environmental expenditures related to existing conditions that do not have future economic benefit. We capitalize environmental expenditures for which there is a future economic benefit. We record liabilities for expected future costs, on an undiscounted basis, related to environmental assessments and /or remediation when they are probable and can be reasonably estimated. In determining the liabilities, we refer to currently available information, including relevant past experience, remedial objectives, available technologies and applicable laws and regulations. We record reimbursements or recoveries of environmental remediation costs in income when received, or when receipt of recovery is highly probable.

Operating Leases

We lease various assets under non-cancelable leasing arrangements, including generating facilities, office space and other equipment. The rent expense associated with leases that qualify as operating leases is recognized on

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a straight-line basis over the lease term within operations and maintenance expense in the consolidated statements of operations. Our most significant operating leases are GenOn Mid-Atlantic’s leases of a 100% interest in the Dickerson and Morgantown baseload units. See note 7.

Intangible Assets

Intangible assets relate primarily to trading rights, development rights and granted emissions allowances. Intangible assets with definite useful lives are amortized on a straight-line basis to their estimated residual values over their respective useful lives ranging up to 30 years. See note 3.

Debt Issuance Costs (GenOn Americas Generation)

Debt issuance costs are capitalized and amortized as interest expense under the effective interest method over the term of the related debt. Changes in debt issuance costs are as follows:

	2011			2010			2009
	(in millions)

Balance, January 1	$	12		$	29		$	38
Amortized	—			(8		)	(9		)
Accelerated amortization/write-offs(1)(2)	(7		)	(9		)	—
Balance, December 31	$	5		$	12		$	29

(1) See note 4.

(2) Amounts are considered a portion of the net carrying value of the related debt and are expensed when accelerated as a component of debt extinguishments.

Income Taxes and Deferred Tax Asset Valuation Allowance

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

Deferred tax assets and liabilities are recognized for the regarded corporate entities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. When necessary, deferred tax assets are reduced by a valuation allowance to reflect the amount that is estimated to be recoverable. In assessing the recoverability of the deferred tax assets, GenOn Americas Generation considers whether it is likely that some portion or all of the deferred tax assets will be realized. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

The determination of a valuation allowance requires significant judgment as to the generation of taxable income during future periods in which those temporary differences are deductible. In making this determination,

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New Accounting Guidance Not Yet Adopted at December 31, 2011

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

· 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.

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

2. Financial Instruments

(a) Derivatives and Hedging Activities.

GenOn Americas Generation

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

	Derivative Contract Assets				Derivative Contract Liabilities						Net Derivative Contract
	Current		Long-Term		Current			Long-Term			Assets (Liabilities)
	(in millions)

December 31, 2011
Commodity Contracts:
Asset management	$	562	$	757	$	(314	)	$	(186	)	$	819
Trading activities	459		3		(462		)	(3		)	(3		)
Total derivatives	$	1,021	$	760	$	(776	)	$	(189	)	$	816
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

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

	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	$	138		$	(2	)	$	77		$	(89	)
Realized(1)(2)	284			(47		)	318			(168		)
Total asset management	$	422		$	(49	)	$	395		$	(257	)

Trading Commodity Contracts:
Unrealized	$	2		$	—		$	(5	)	$	—
Realized(1)(2)	(22		)	—			(23		)	—
Total trading	$	(20	)	$	—		$	(28	)	$	—

Total derivatives	$	402		$	(49	)	$	367		$	(257	)

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

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

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

	Notional Volumes at December 31, 2011
Derivative Instruments	Derivative Contract Assets		Derivative Contract Liabilities	Net Derivative Contracts
			(in millions)

Commodity Contracts (in equivalent MWh):
Power(1)	(97	)	61	(36	)
Natural gas	(9	)	10	1
Coal	3		8	11

	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.

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GenOn Mid-Atlantic

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

	Derivative Contract Assets				Derivative Contract Liabilities						Net Derivative Contract
	Current		Long-Term		Current			Long-Term			Assets (Liabilities)
					(in millions)
December 31, 2011
Commodity Contracts:
Asset management	$	208	$	526	$	—		$	—		$	734
Asset management—affiliate	191		105		(168		)	(68		)	60
Total derivatives	$	399	$	631	$	(168	)	$	(68	)	$	794
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 (including amounts with affiliates) recognized in income in the consolidated statements of operations:

	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	$	119	$	1		$	80	$	(73	)
Realized(1)(2)	268		(1		)	300		(128		)
Total asset management	$	387	$	—		$	380	$	(201	)

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

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

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

	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.

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(b) 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: Represents 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.

A significant amount of the fair value of our derivative contract assets and liabilities is based on observable quoted prices from exchanges and indicative quoted prices from independent brokers in active markets that regularly facilitate our transactions. An active market is considered to have transactions with sufficient frequency and volume to provide pricing information on an ongoing basis. We think these prices represent the best available information for valuation purposes. In determining the fair value of derivative contract assets and liabilities, we use third-party market pricing where available. For transactions classified in Level 1 of the fair value hierarchy, we use the unadjusted published settled prices on the valuation date. For transactions classified in Level 2 of the fair value hierarchy, we value these transactions using indicative quoted prices from independent brokers or other widely-accepted valuation methodologies. Transactions are classified in Level 2 if substantially all (greater than 90%) of the fair value can be corroborated using observable market inputs such as transactable broker quotes. In accordance with the exit price objective under the fair value measurements accounting guidance, the fair value of our derivative contract assets and liabilities is determined based on the net underlying position of the recorded derivative contract assets and liabilities using bid prices for assets and ask prices for liabilities. The quotes we obtain from brokers are non-binding in nature, but are from brokers that typically transact in the market being quoted and are based on their knowledge of market transactions on the valuation date. We typically obtain multiple broker quotes as of the valuation date that extend for the tenor of the underlying contracts for each delivery location. The number of quotes 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

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GenOn Americas Generation

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

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

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

Interest-bearing funds(3)	$	421	$	—		$	—	$	421

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

(2) Option contracts comprised 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 $249 million of interest-bearing funds included in cash and cash equivalents, $166 million included in funds on deposit and $6 million included in other noncurrent assets.

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	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.

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The following is a reconciliation of changes (comprised of the sum of the quarterly changes) in fair value of net commodity derivative contract assets and liabilities (including amounts with affiliates) classified as Level 3 during 2011 and 2010:

	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)	(18		)	28			10
Purchases(2)	—			—			—
Issuances(2)	—			—			—
Settlements(3)	20			(8		)	12
Transfers into Level 3(4)	—			—			—
Transfers out of Level 3(4)	12			—			12
Balance, December 31, 2011 (net asset (liability))	$	(54	)	$	22		$	(32	)

Balance, January 1, 2010 (net asset (liability))	$	19		$	13		$	32
Total gains (losses) realized/unrealized:
Included in earnings(1)	17			(49		)	(32		)
Purchases(2)	—			—			—
Issuances(2)	—			—			—
Settlements(5)	(142		)	39			(103		)
Transfers in and out of Level 3(4)	38			(1		)	37
Balance, December 31, 2010 (net asset (liability))	$	(68	)	$	2		$	(66	)

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

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

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

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

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

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

	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	$	30	$	4	$	34	$	(24	)	$	(74	)	$	(98	)
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 December 31	$	32	$	6	$	38	$	(1	)	$	(67	)	$	(68	)

GenOn Mid-Atlantic

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

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

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

Interest-bearing funds(3)	$	230	$	—	$	—	$	230

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

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

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

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	December 31, 2010
	Level 1(1)		Level 2(1)(2)		Level 3		Total Fair Value
	(in millions)
Derivative contract assets:
Commodity Contracts
Asset Management:
Power	$	1	$	986	$	—	$	987
Fuel	—		2		31		33
Total derivative contract assets	$	1	$	988	$	31	$	1,020

Derivative contract liabilities:
Commodity Contracts
Asset Management:
Power	$	12	$	231	$	1	$	244
Fuel	—		—		99		99
Total derivative contract liabilities	$	12	$	231	$	100	$	343

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

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

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

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

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	Asset Management
	(in millions)

Balance, January 1, 2011 (net asset (liability))	$	(69	)
Total gains (losses) realized/unrealized:
Included in earnings(1)	(31		)
Purchases (2)	—
Issuances (2)	—
Settlements (3)	24
Transfers into Level 3(4)	—
Transfers out of Level 3(4)	12
Balance, December 31, 2011 (net asset (liability))	$	(64	)

Balance, January 1, 2010 (net asset (liability))	$	13
Total gains (losses) realized/unrealized:
Included in earnings (1)	6
Purchases (2)	—
Issuances (2)	—
Settlements (5)	(126		)
Transfers in and out of Level 3(4)	38
Balance, December 31, 2010 (net asset (liability))	$	(69	)

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

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

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

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

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

	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	$	5	$	(7	)	$	(75	)	$	(82	)
Gains (losses) included in income (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets still held at December 31	$	(2	)	$	6	$	4	$	(7	)	$	(68	)	$	(75	)

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(c) 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. GenOn Americas Generation and GenOn Mid-Atlantic credit valuation adjustments on derivative contract assets were $47 million and $19 million at December 31, 2011 and 2010, respectively.

At December 31, 2011 and 2010, $4 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 monitor counterparty credit concentration risk on both an individual basis and a group counterparty basis. The following tables highlight the credit quality and the balance sheet settlement exposures related to these activities:

GenOn Americas Generation

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

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

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	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 and the netting of transactions with clearing brokers and exchanges.

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

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GenOn Mid-Atlantic

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

Investment Grade:
Financial institutions	$	805	$	802	$	—	$	802	98	%
Non-investment Grade:
Energy companies	1		1		—		1		—
No External Ratings:
Internally-rated non-investment grade	13		13		—		13		2	%
Total	$	819	$	816	$	—	$	816	100	%

	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)

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	%

(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 December 31, 2011 and December 31, 2010, respectively, each representing an exposure of more than 10% of total credit exposure, net of collateral and totaling $664 million and $568 million at December 31, 2011 and 2010, respectively.

GenOn Mid-Atlantic had credit exposure to two investment grade counterparties at December 31, 2011 and three investment grade counterparties at December 31, 2010, each representing an exposure of more than 10% of total credit exposure, net of collateral and totaling $664 million and $653 million at December 31, 2011 and 2010, respectively.

(d) GenOn Americas Generation and GenOn Mid-Atlantic Credit Risk.

Our standard industry contracts contain credit-risk-related contingent features such as ratings-related thresholds whereby we would be required to post additional cash collateral or letters of credit as a result of a credit event, including a downgrade. Additionally, some of our contracts contain adequate assurance language, which is

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generally subjective in nature but could require us to post additional cash collateral or letters of credit as a result of a credit event, including a downgrade. However, as a result of our current credit rating, we are typically required to post collateral in the normal course of business to offset either substantially or completely the net liability positions, after applying the terms of master netting agreements. At December 31, 2011, the fair value of GenOn Americas Generation’s financial instruments with credit-risk-related contingent features in a net liability position was $2 million for which GenOn Americas Generation had posted collateral of $2 million, including cash and letters of credit. At December 31, 2011, GenOn Mid-Atlantic did not have any financial instruments with credit-risk-related contingent features in a net liability position.

At December 31, 2011 and 2010, GenOn Americas Generation had $64 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.

(e) 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 debt are as follows:

	December 31,
	2011				2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Liabilities:
Long and short-term debt(1)	$	866	$	797	$	2,255	$	2,273

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

3. Long-Lived Assets

(a) Property, Plant and Equipment, Net.

Property, plant and equipment, net consisted of the following:

GenOn Americas Generation

	December 31,						Depreciable
	2011			2010			Lives (years)
	(in millions)

Production	$	2,608		$	2,695		11 to 33
Leasehold improvements on leased generating facilities	1,121			1,056			5 to 34
Construction work in progress	76			65			—
Other	89			129			2 to 12
Total	3,894			3,945
Accumulated depreciation and amortization	(960		)	(868		)
Total property, plant and equipment, net	$	2,934		$	3,077

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GenOn Mid-Atlantic

	December 31,						Depreciable
	2011			2010			Lives (years)
	(in millions)

Production	$	1,832		$	1,885		31 to 33
Leasehold improvements on leased generating facilities	1,121			1,056			5 to 34
Construction work in progress	64			56			—
Other	37			49			2 to 12
Total	3,054			3,046
Accumulated depreciation and amortization	(610		)	(513		)
Total property, plant and equipment, net	$	2,444		$	2,533

Depreciation of the recorded cost of property, plant and equipment is recognized on a straight-line basis over the estimated useful lives of the assets. Emissions allowances purchased in acquisitions prior to the Merger related to owned facilities were included in production assets above and are depreciated on a straight-line basis over the average life of the related generating facilities. See below for discussion of impairment of excess emissions allowances in 2011.

Depreciation expense was as follows:

GenOn Americas Generation

	2011		2010		2009
	(in millions)

Depreciation expense	$	168	$	190	$	134

GenOn Mid-Atlantic

	2011		2010		2009
	(in millions)

Depreciation expense	$	126	$	135	$	92

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(b) Intangible Assets, Net.

GenOn Americas Generation

The following is a summary of intangible assets:

		December 31, 2011					December 31, 2010
	Weighted Average Amortization Lives	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
		(in millions)

Trading rights	16 years	$	15	$	(8	)	$	15	$	(6	)
Development rights	30 years	13		(3		)	13		(2		)
Emissions allowances	24 years	11		(3		)	107		(28		)
Other intangibles	30 years	5		(2		)	4		(2		)
Total intangible assets		$	44	$	(16	)	$	139	$	(38	)

GenOn Mid-Atlantic

The following is a summary of intangible assets:

		December 31, 2011					December 31, 2010
	Weighted Average Amortization Lives	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
		(in millions)

Emissions allowances	26 years	$	10	$	(2	)	$	89	$	(26	)
Development rights	30 years	6		—			6		—
Other intangibles	30 years	4		(2		)	4		(2		)
Total intangible assets		$	20	$	(4	)	$	99	$	(28	)

Trading rights are intangible assets recognized in connection with asset purchases that represent GenOn Americas Generation’s ability to generate additional cash flows by incorporating GenOn Americas Generation’s trading activities with the acquired generating facilities. See below for information on the 2009 impairment of the trading rights related to the Potrero and Contra Costa generating facilities.

Development rights represent the right to expand capacity at certain acquired generating facilities. The existing infrastructure, including storage facilities, transmission interconnections and fuel delivery systems and contractual rights acquired, provide the opportunity to expand or repower certain generating facilities. See below for information on the 2010 impairment of the development rights related to the Dickerson generating facility and the 2009 impairment of the development rights related to the Potrero generating facility.

Emissions allowances primarily represent allowances granted for the leasehold baseload units at the Dickerson and Morgantown generating facilities. See below for discussion of impairment of excess emissions allowances in 2011 and for information on the 2010 impairment of emissions allowances related to the Dickerson generating facility.

GenOn Americas Generation

Amortization expense was as follows:

	2011		2010		2009
	(in millions)

Amortization expense	$	9	$	9	$	8

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GenOn Mid-Atlantic

Amortization expense was as follows:

	2011		2010		2009
	(in millions)

Amortization expense	$	5	$	6	$	6

GenOn Americas Generation

Assuming no future acquisitions, dispositions or impairments of intangible assets, amortization expense is estimated to be approximately the following for each of the next five years (in millions):

2012	$	3
2013	3
2014	3
2015	1
2016	1

GenOn Mid-Atlantic

Assuming no future acquisitions, dispositions or impairments of intangible assets, amortization expense is estimated to be approximately the following for each of the next five years (in millions):

2012	$	1
2013	1
2014	1
2015	1
2016	1

(c) Impairments on Assets Held and Used.

2011

Granted Emissions Credits

In August 2011, the EPA finalized the CSAPR, which was intended to replace the CAIR starting in 2012. In September 2011, we and others asked the D.C. Circuit to stay and vacate the CSAPR. In December 2011, the court ordered the EPA to stay implementation of the CSAPR and to keep CAIR in place until the court rules on the legal deficiencies alleged with respect to the CSAPR. The CSAPR addresses interstate transport of emissions of NOx and SO2. The CSAPR establishes limitations on NOx and/or SO2 emissions from electric generating units that are (i) greater than 25 megawatts and (ii) located in 28 states (in the eastern half of the United States) that the EPA determined contribute significantly to nonattainment in other states, or to interfere with maintenance in other states, of one or more of three NAAQS: (a) the annual NAAQS for fine particulate matter (PM2.5) promulgated in 1997; (b) the “24-hour” NAAQS for PM2.5 promulgated in 2006 and (c) the ozone NAAQS promulgated in 1997. The CSAPR creates “emission budgets” for each of the covered states and allocates emissions allowances (denominated in tons of emissions) to each of the 28 states regulated under the CSAPR.

Under the CSAPR program, the EPA established new allowances for all of the new CSAPR programs and did not permit any carryover Acid Rain Program or CAIR allowances into the CSAPR trading programs. As a result, the NOx allowances from the CAIR program would not have been used. Accordingly, we thought that the CAIR NOx allowances would have no value after 2011. Similarly, the SO2 allowances used for compliance in the CAIR

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program (which used the already existing Acid Rain Program allowances that would have continued to be usable for compliance with the Acid Rain Program) would not have been usable for compliance with the CSAPR SO2 program and we thought they would have negligible value after 2011. As a result of the CSAPR, GenOn Americas Generation recorded impairment losses of $128 million for (a) the write-off of excess NOx and SO2 emissions allowances previously included in intangible assets ($70 million) and (b) the write-off of excess NOx and SO2 emissions allowances previously included in property, plant and equipment ($58 million) during 2011. As a result of the CSAPR, GenOn Mid-Atlantic recorded impairment losses of $94 million for (a) the write-off of excess NOx and SO2 emissions allowances previously included in intangible assets ($56 million) and (b) the write-off of excess NOx and SO2 emissions allowances previously included in property, plant and equipment ($38 million) during 2011. The emissions allowances within property, plant and equipment and intangible assets had previously been included with a generating facility asset group for purposes of impairment testing. Because we thought (a) there would be no future use of the NOx emissions allowances and (b) the SO2 emissions allowances would have negligible value after 2011 under the CSAPR and their price had fallen sharply, we evaluated, in conjunction with preparing our third quarter interim financial statements, these emissions allowances for impairment separately from the generating facility asset group and determined that impairments existed.

As GenOn Americas Generation thought that CAIR NOx emissions allowances of $43 million would have no value after 2011, they were fully impaired. The excess Acid Rain Program SO2 emissions allowances of $86 million were impaired to their estimated fair value of $1 million based on their current market prices obtained from brokers. The excess Acid Rain Program SO2 emissions allowances were categorized in Level 3 in the fair value hierarchy.

As GenOn Mid-Atlantic thought that CAIR NOx emissions allowances of $43 million would have no value after 2011, they were fully impaired. The excess Acid Rain Program SO2 emissions allowances of $52 million were impaired to their estimated fair value of $1 million based on their current market prices obtained from brokers. The excess Acid Rain Program SO2 emissions allowances were categorized in Level 3 in the fair value hierarchy.

Potomac River Generating Facility

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

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

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2010

GenOn Mid-Atlantic Generating Facilities

In December 2010, PJM published an updated load forecast, which depicted a decrease in the expected demand because of lower economic growth expectations. As a result of the load forecast, our expectation was that there would be a decrease in the clearing prices for future capacity auctions in certain years. As a result of the decrease in projected capacity revenue, we evaluated GenOn Mid-Atlantic long-lived assets for impairment. Each of the GenOn Mid-Atlantic generating facilities was viewed as an individual asset group.

Our assumptions related to future electricity and fuel prices were based on observable market prices to the extent available and long-term prices derived from proprietary fundamental market modeling. The assumptions regarding electricity demand were based on forecasts from PJM and assumptions for generating capacity additions and retirements included publicly-announced projects, which take into account renewable sources of electricity.

GenOn Americas Generation recorded impairment losses of $523 million and $42 million on the consolidated statement of operations to reduce the carrying values of the Dickerson and Potomac River generating facilities, respectively, to their estimated fair values. GenOn Mid-Atlantic recorded impairment losses of $497 million and $40 million on the consolidated statement of operations to reduce the carrying values of the Dickerson and Potomac River generating facilities, respectively, to their estimated fair values. In addition, as a result of the impairment of the Potomac River generating facility, we recorded $32 million in operations and maintenance expense and corresponding liabilities associated with GenOn Mid-Atlantic’s commitment at the time to reduce particulate emissions as part of the agreement with the City of Alexandria, Virginia. The planned capital investment would not have been recovered in future periods based on the projected cash flows of the Potomac River generating facility.

The following table sets forth by level within the fair value hierarchy assets that were accounted for at fair value on a non-recurring basis. All assets that were measured at fair value as a result of impairment losses recorded during 2010 were categorized in Level 3 at December 31, 2010:

GenOn Americas Generation

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total		Loss Included in Earnings
	(in millions)

Dickerson generating facility	$	—	$	—	$	91	$	91	$	462
Dickerson intangible assets	—		—		8		8		61
Potomac River generating facility(1)	—		—		1		1		42
Total	$	—	$	—	$	100	$	100	$	565

(1) The remaining carrying value represents the fair value of the related SO2 and NOx emissions allowances included in property, plant and equipment, net.

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GenOn Mid-Atlantic

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total		Loss Included in Earnings
	(in millions)

Dickerson generating facility	$	—	$	—	$	86	$	86	$	437
Dickerson intangible assets	—		—		8		8		60
Potomac River generating facility(1)	—		—		1		1		40
Total	$	—	$	—	$	95	$	95	$	537

(1) The remaining carrying value represents the fair value of the related SO2 and NOx emissions allowances included in property, plant and equipment, net.

2009

Potrero Generating Facility (GenOn Americas Generation)

During 2009, GenOn Potrero executed a settlement agreement with the City and County of San Francisco in which it agreed to shut down the Potrero generating facility when it was no longer needed for reliability, as determined by the CAISO. As a result of the settlement agreement, GenOn Americas Generation evaluated the Potrero generating facility for impairment during the third quarter of 2009. All of the units at GenOn Potrero were viewed as a single asset group. Additionally, the asset group included intangible assets recorded at GenOn California North for trading and development rights related to GenOn Potrero.

GenOn Americas Generation determined that the tangible assets for the Potrero generating facility were not impaired because the weighted average sum of the undiscounted cash flows exceeded the carrying value of the tangible assets in the third quarter of 2009.

As a result of certain terms included in the settlement agreement, GenOn Americas Generation separately evaluated the trading and development rights associated with the Potrero generating facility for impairment and determined that both of these intangible assets were fully impaired at September 30, 2009. Accordingly, GenOn Americas Generation recognized an impairment loss of $9 million on the consolidated statement of operations to write off the carrying value of the intangible assets related to the Potrero generating facility. This impairment loss is included in the results of GenOn Americas Generation’s California segment for 2009.

Contra Costa Generating Facility (GenOn Americas Generation)

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

GenOn Americas Generation evaluated the intangible asset of trading rights related to its Contra Costa generating facility for impairment during the third quarter of 2009 as a result of the shutdown provisions in the tolling agreement. Because the Contra Costa generating facility is under contract with PG&E through its expected retirement date of May 2013, GenOn Americas Generation determined the intangible asset was fully impaired as of September 30, 2009. GenOn Americas Generation recorded an impairment loss of $5 million on the consolidated statement of operations to write off the carrying value of the trading rights related to the Contra Costa generating facility. This impairment loss is included in the results of GenOn Americas Generation’s California segment for 2009.

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GenOn Mid-Atlantic Generating Facilities

During 2009, the continued decline in average natural gas prices caused power prices to decline in the Eastern PJM region. Additionally, weak economic conditions and various demand-response programs at the time resulted in a decrease in the forecasted gross margin of the GenOn Mid-Atlantic generating facilities.

We determined that the Potomac River generating facility was impaired, as the carrying value exceeded the undiscounted cash flows. As a result of the assessment, GenOn Americas Generation recorded an impairment loss of $207 million in the fourth quarter of 2009 to reduce the carrying value of the Potomac River generating facility to its estimated fair value. GenOn Mid-Atlantic recorded an impairment loss of $202 million to reduce the carrying value of the Potomac River generating facility to its estimated fair value.

The following tables set forth by level within the fair value hierarchy our assets and GenOn Americas Generation’s intangible assets that were accounted for at fair value on a non-recurring basis. All of our assets and GenOn Americas Generation’s intangible assets that were measured at fair value as a result of impairment losses recorded during 2009 were categorized in Level 3 at December 31, 2009:

GenOn Americas Generation

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total		Loss Included in Earnings
	(in millions)

Potomac River generating facility	$	—	$	—	$	37	$	37	$	207
Potrero intangible assets	—		—		—		—		9
Contra Costa intangible assets	—		—		—		—		5
Total	$	—	$	—	$	37	$	37	$	221

GenOn Mid-Atlantic

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total		Loss Included in Earnings
	(in millions)

Potomac River generating facility	$	—	$	—	$	37	$	37	$	202
Total	$	—	$	—	$	37	$	37	$	202

(d) Goodwill, Net (GenOn Mid-Atlantic).

GenOn Mid-Atlantic performed its annual test for goodwill impairment effective October 31, 2010 and 2009, based upon GenOn Mid-Atlantic’s most recent business plan and market data from independent sources available at the respective testing dates. GenOn Mid-Atlantic utilized multiple valuation approaches in arriving at a fair value of GenOn Mid-Atlantic’s reporting unit for purposes of the test, including an income approach involving discounted cash flows and a market approach involving trading multiples of peer companies. The annual evaluations of goodwill for 2010 and 2009 indicated that the carrying value of the reporting unit exceeded the fair value, requiring the second step of the goodwill analysis to be performed.

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GenOn Mid-Atlantic then performed the second step of the goodwill impairment test, which required an allocation of the fair value as the purchase price in a hypothetical acquisition of the reporting unit. The fair value of the reporting unit was compared to the fair value of the tangible and intangible assets and the remaining value was the implied goodwill. For 2010, as a result of this analysis, GenOn Mid-Atlantic recorded an impairment loss of $616 million on its consolidated statement of operations to reduce the carrying value of goodwill to its implied fair value, which was zero. For 2009, GenOn Mid-Atlantic recorded an impairment loss of $183 million on its consolidated statement of operations to reduce the carrying value of goodwill to its implied fair value.

GenOn Mid-Atlantic’s assumptions related to future electricity and fuel prices were based on observable market prices to the extent available and long-term prices derived from proprietary fundamental market modeling. The assumptions regarding electricity demand were based on forecasts from PJM and assumptions for generating capacity additions and retirements included publicly-announced projects, which take into account renewable sources of electricity.

GenOn Mid-Atlantic’s estimates of future cash flows did not include contracts entered into to hedge economically the expected generation of Mid-Atlantic generating facilities. The cash flows related to these contracts were excluded because they were not directly attributable to the generating facilities.

The following summarizes the changes in the carrying amount of goodwill during 2011, 2010 and 2009, respectively (in millions):

Balance, January 1, 2009	$	799
Impairment loss	(183		)
Balance, December 31, 2009	616
Impairment loss	(616		)
Balance, December 31, 2010	$	—

The following table sets forth by level within the fair value hierarchy GenOn Mid-Atlantic’s goodwill that was accounted for at fair value on a non-recurring basis. GenOn Mid-Atlantic’s goodwill that was measured at fair value as a result of an impairment during the current period was categorized in Level 3 at December 31, 2010:

GenOn Mid-Atlantic

	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total		Loss Included in Earnings
	(in millions)

GenOn Mid-Atlantic goodwill	$	—	$	—	$	—	$	—	$	616
Total	$	—	$	—	$	—	$	—	$	616

(e) Asset Retirement Obligations.

Upon initial recognition of a liability for an asset retirement obligation or a conditional asset retirement obligation, an entity shall capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Retirement obligations associated with long-lived assets included within the scope of accounting guidance are those for which a legal obligation exists under enacted laws, statutes and written or oral contracts, including obligations arising under the doctrine of promissory estoppel.

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We identified certain asset retirement obligations within our power generating facilities. These asset retirement obligations are primarily related to asbestos abatement in facilities on owned or leased property and other environmental obligations related to ash disposal sites. In addition, the asset retirement obligations also relate to environmental obligations for fuel storage facilities, wastewater treatment facilities and pipelines. See note 9.

Asbestos abatement is the most significant type of asset retirement obligation identified for recognition in connection with our policy related to accounting for conditional asset retirements. The EPA has regulations in place governing the removal of asbestos. Because of the nature of asbestos, it can be difficult to ascertain the extent of contamination in older facilities unless substantial renovation or demolition takes place. Therefore, we incorporated certain assumptions based on the relative age and size of our facilities to estimate the current cost for asbestos abatement. The actual abatement cost could differ from the estimates used to measure the asset retirement obligation. As a result, these amounts will be subject to revision when actual abatement activities are undertaken.

The following tables set forth the balances of the asset retirement obligations and the additions, revisions in estimated cash flows and accretion of the asset retirement obligations. The asset retirement obligations are included in other noncurrent liabilities in the consolidated balance sheets:

GenOn Americas Generation

	2011			2010
	(in millions)

Beginning balance January 1	$	54		$	43
Revisions in estimated cash flows	(2		)(1)	7
Accretion expense	5			4
Ending balance December 31	$	57		$	54

GenOn Mid-Atlantic

	2011			2010
	(in millions)

Beginning balance January 1	$	18		$	13
Revisions in estimated cash flows	(2		)(1)	4
Accretion expense	2			1
Ending balance December 31	$	18		$	18

(1) Includes $6 million of income recorded in the consolidated statement of operations as a result of changes in asset retirement obligations assumptions.

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4. Long-Term Debt

(a) Overview.

Outstanding debt was as follows:

	December 31, 2011							December 31, 2010
	Weighted Average Stated Interest Rate (1)		Long-term			Current		Weighted Average Stated Interest Rate (1)		Long-term			Current
	(in millions, except interest rates)
Facilities, 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	—		(2		)	—		—		(2		)	—
GenOn North America:
Senior notes, due 2013(3)	—		—			—		7.375		—			850
GenOn Mid-Atlantic:
GenOn Chalk Point, LLC capital lease, due 2012 to 2015	8.19		14			4		8.19		18			4
Total			$	862		$	4			$	866		$	1,389

(1)		The weighted average stated interest rates are at December 31, 2011 and 2010, respectively.
(2)		These notes were repaid on May 2, 2011.
(3)		These notes were discharged at the closing of the Merger on December 3, 2010 and were redeemed on January 3, 2011 at a call price of 101.844% of the principal amount.

GenOn Americas Generation

Debt maturities for the principal amounts at December 31, 2011 are (in millions):

2012	$	4
2013	4
2014	5
2015	5
2016	—
2017 and thereafter	850
Total	$	868

GenOn Americas Generation

Senior Unsecured Notes. The senior notes due 2021 and 2031 are senior unsecured obligations of GenOn Americas Generation having no recourse to any subsidiary or affiliate of GenOn Americas Generation. In May 2011, GenOn Americas Generation repaid at maturity $535 million of its senior notes due 2011.

GenOn North America

Senior Notes Due 2013. Upon closing of the Merger, the senior notes due 2013 of GenOn North America 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

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December 31, 2010 and was recorded as restricted cash, included in funds on deposit on the consolidated balance sheet.

In January 2011, the senior 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 in 2011, which includes a $16 million premium and $7 million of unamortized debt issuance costs.

Senior Secured Credit Facilities. Upon closing of the Merger, GenOn North America repaid the outstanding senior secured credit facility of $305 million plus accrued and unpaid interest through the date of repayment. The total payment was $305 million and a $9 million loss on extinguishment of debt was recognized in other, net in the consolidated statement of operations during 2010.

Other

Capital Lease. This is a capital lease at our Chalk Point generating facility for an 84 MW peaking unit. The amount outstanding under the capital lease at December 31, 2011, which matures in 2015, is $18 million with an 8.19% annual interest rate. Depreciation expense related to this lease was $2 million during 2011, 2010 and 2009. The annual principal payments under this lease are $4 million during 2012 and 2013 and $5 million in 2014 and 2015. The gross amount of assets under the capital lease, recorded in property, plant and equipment, net, was $24 million at December 31, 2011 and 2010. The related accumulated depreciation was $18 million and $16 million at December 31, 2011 and 2010, respectively.

(b) GenOn Credit Facilities.

The GenOn credit facilities, and the subsidiary guarantees thereof, are the senior secured obligations of GenOn and certain of its existing and future direct and indirect subsidiaries, excluding GenOn Americas Generation; provided, however, that certain of GenOn Americas Generation’s subsidiaries (other than GenOn Mid-Atlantic and GenOn Energy Management and their subsidiaries) guarantee the GenOn credit facilities to the extent permitted under the indenture for the senior notes of GenOn Americas Generation.

(c) Sources of Funds.

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

GenOn Americas Generation and certain of its subsidiaries are holding companies and, as a result, GenOn Americas Generation and such subsidiaries are dependent upon dividends, distributions and other payments from their respective subsidiaries to generate the funds necessary to meet their obligations. In particular, a substantial portion of the cash from GenOn Americas Generation’s 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 December 31, 2011, GenOn Mid-Atlantic satisfied the restricted payments tests. GenOn Mid-Atlantic has reserved $165.6 million of cash (which is included in funds on deposit on the consolidated balance sheet) in respect of such liens. See note 9.

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Pursuant to the terms of its leases, GenOn Mid-Atlantic is restricted from, among other actions, (a) encumbering assets, (b) entering into business combinations or divesting assets, (c) incurring additional debt, (d) entering into transactions with affiliates on other than an arm’s length basis or (e) materially changing their business. Therefore, at December 31, 2011 and 2010, all of GenOn Mid-Atlantic’s net assets (excluding cash) were deemed restricted for purposes of Rule 4-08(e)(3)(iii) of Regulation S-X.

The amounts of restricted net assets were as follows:

	December 31,
	2011		2010
	(in millions)

GenOn Mid-Atlantic	$	3,859	$	3,690

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

5. 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 Corporation and GenOn Special Procurement, Inc., exist as regarded corporate entities for income tax purposes. GenOn Kendall, which had previously existed as a regarded entity, was converted to a disregarded entity effective January 1, 2011. For these subsidiaries that continue to exist as corporate regarded entities, GenOn Americas Generation allocates current and deferred income taxes to each corporate regarded entity as if such entity were a single taxpayer utilizing the asset and liability method to account for income taxes. To the extent GenOn Americas Generation provides tax expense or benefit, any related tax payable or receivable to GenOn is reclassified to equity in the same period because GenOn Americas Generation does not have a tax sharing agreement with GenOn.

At the Merger, each of Mirant and RRI Energy separately determined whether or not each had experienced an ownership change as defined in the IRC. IRC § 382 provides, in general, that an ownership change occurs when there is a greater than 50-percentage point increase in ownership of a company’s stock held by new or existing stockholders who own (or are deemed to own under IRC § 382) 5% or more of the loss company’s stock over a three year testing period. IRC § 382 limits the amount of pre-Merger NOLs that can be used during any post-ownership change year to offset taxable income. Mirant experienced an “ownership change” within the meaning of IRC § 382. The annual limitation on the amount of taxable income that can be offset by Mirant’s pre-Merger NOLs has been redetermined as of the date of the Merger. GenOn Americas Generation’s annual limitation on the amount of taxable income that can be offset by its pre-Merger NOLs has also been redetermined as a consequence of the Mirant ownership change that resulted from the Merger. GenOn Americas Generation has reduced the amount of its pre-Merger NOLs available to offset post-Merger taxable income based on the expected limits determined in accordance with IRC § 382.

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Details of GenOn Americas Generation’s income tax provision (benefit) are as follows:

	2011		2010			2009
	(in millions)
Current benefit:
Federal	$	—	$	—		$	—
State	—		(1		)	—
Deferred provision:
Federal	—		1			—
State	—		—			—
Total provision (benefit) for income taxes	$	—	$	—		$	—

A reconciliation of GenOn Americas Generation’s expected federal statutory income tax provision to the effective income tax provision adjusted for permanent and other items during 2011, 2010 and 2009, is as follows:

	2011			2010			2009
	(in millions)
United States federal statutory income tax provision (benefit)	$	5		$	(139	)	$	167
State and local income taxes, net of federal income taxes	5			12			1
LLC income not subject to federal taxation	(10		)	136			(166		)
Change in deferred tax asset valuation allowance	—			(105		)	(2		)
Conversion of GenOn Kendall to disregarded entity	—			58			—
Merger related write off of NOLs	—			38			—
Tax provision	$	—		$	—		$	—

In 2011, 2010 and 2009, GenOn Americas Generation recognized changes in its valuation allowance of $0, $(105) million and $(2) million, respectively, related to its net deferred tax assets. At December 31, 2011and 2010, no valuation allowance is recorded.

GenOn Kendall, which had previously existed as a taxable entity, was converted to a disregarded entity and is treated as a branch of GenOn Americas for income tax purposes. As a result of the conversion, GenOn Kendall’s net deferred tax assets of $58 million and corresponding valuation allowance were written off in 2010.

The tax effects of GenOn Americas Generation’s temporary differences between the carrying amounts of assets and liabilities in the consolidated financial statements and its tax bases which give rise to deferred tax assets and liabilities for continuing operations are as follows:

	2011			2010
	(in millions)
Deferred Tax Assets:
Loss carry forwards	$	2		$	2
Net deferred tax assets	2			2
Deferred Tax Liabilities:
Property and intangible assets	(2		)	(3		)
Net deferred tax liabilities	(2		)	(3		)
Net deferred taxes	$	—		$	(1	)

At December 31, 2011, GenOn Americas Generation had $6 million of NOL carry forwards for federal income tax purposes expiring from 2023 to 2031 and $1 million of NOL carry forwards for state income tax purposes. The federal NOL carry forward is generally available to offset future federal income tax.

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Tax Uncertainties

The recognition of contingent losses for tax uncertainties requires management to make significant assumptions about the expected outcomes of certain tax contingencies. Under the accounting guidance, we must reflect in our income tax provision the full benefit of all positions that will be taken in our income tax returns, except to the extent that such positions are uncertain and fall below the benefit recognition requirements. In the event that we determine that a tax position meets the uncertainty criteria, an additional liability or an adjustment to our NOLs, determined under the measurement criteria, will result. We periodically reassess the tax positions in our tax returns for open years based on the latest information available and determine whether any portion of the tax benefits reflected should be treated as unrecognized.

Both the federal and state NOL carry forwards from any closed year are subject to examination until the year that such NOL carry forwards are utilized and that utilization year is closed for audit. For 2009, our tax provision includes an insignificant amount related to the accrual for any penalties and interest related to the uncertain tax benefits. Subsequent to the Merger, GenOn Americas Generation has not recorded any uncertain tax benefits.

Pro Forma Income Tax Disclosures

GenOn Americas Generation

GenOn Americas Generation is not subject to income taxes except for those subsidiaries of GenOn Americas Generation that are separate taxpayers. GenOn Americas and GenOn are otherwise directly responsible for income taxes related to GenOn Americas Generation’s operations.

The following reflects a pro forma disclosure of the income tax provision that would be reported if GenOn Americas Generation were to be allocated income taxes attributable to its operations. Pro forma income tax provision attributable to income before tax would consist of the following:

	2011		2010		2009
	(in millions)
Current income tax provision:
Federal	$	—	$	7	$	10
State	—		2		5
Provision for income taxes	$	—	$	9	$	15

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The following table presents the pro forma reconciliation of GenOn Americas Generation’s federal statutory income tax provision for continuing operations adjusted for reorganization items to the pro forma effective tax provision:

	2011			2010			2009
	(in millions)

United States federal statutory income tax provision (benefit)	$	5		$	(139	)	$	167
State and local income taxes, net of federal income taxes	5			42			26
Change in deferred tax asset valuation allowance	(74		)	55			(167		)
Merger related write off of NOLs	83			61			—
Tax settlement(1)	(23		)	—			—
Excess tax deductions related to bankruptcy transactions	—			—			(3		)
Other, net	4			(10		)	(8		)
Tax provision	$	—		$	9		$	15

(1) Settlement of tax disputes increased our tax basis in depreciable assets that previously had been written off as a result of Mirant’s emergence from bankruptcy in 2006.

The tax effects of temporary differences between the carrying amounts of assets and liabilities in the consolidated balance sheets and their respective tax bases which give rise to the pro forma deferred tax assets and liabilities would be as follows:

	December 31,
	2011			2010
	(in millions)
Deferred Tax Assets:
Reserves	$	41		$	14
Loss carry forwards	220			228
Property and intangible assets	237			238
Other, net	5			42
Subtotal	503			522
Valuation allowance	(179		)	(253		)
Net deferred tax assets	324			269
Deferred Tax Liabilities:
Derivative contract assets and liabilities	(321		)	(268		)
Other, net	(3		)	(1		)
Net deferred tax liabilities	(324		)	(269		)
Net deferred taxes	$	—		$	—

At December 31, 2011 and 2010, a portion of GenOn Americas Generation’s pro forma NOLs (approximately $0 and $11 million, respectively) is attributable to excess tax deductions primarily related to bankruptcy transactions. The recognition of pro forma tax benefit of these excess tax deductions, either through realization or reduction of the pro forma valuation allowance, would be an increase to pro forma member’s interest.

The guidance related to accounting for income taxes requires that a valuation allowance be established when it is more-likely-than-not that all or a portion of a deferred tax asset will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences are deductible. In making this determination, management considers all available positive and negative evidence affecting specific deferred tax assets, including GenOn Americas Generation’s past and

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anticipated future performance, the reversal of deferred tax liabilities and the implementation of tax planning strategies.

Objective positive evidence is necessary to support a conclusion that a valuation allowance is not needed for all or a portion of deferred tax assets when significant negative evidence exists. GenOn Americas Generation evaluates this position quarterly and makes its judgment based on the facts and circumstances at that time.

As of the Merger, each of Mirant and RRI Energy had separately determined whether or not it had experienced an ownership change as defined in the IRC. IRC § 382 provides, in general, that an ownership change occurs when there is a greater than 50-percentage point increase in ownership of a company’s stock by new or existing stockholders who own (or are deemed to own under IRC § 382) 5% or more of the loss company’s stock over a three year testing period. IRC § 382 limits the amount of pre-Merger NOLs that can be used during any post-ownership change year to offset taxable income. Mirant experienced an “ownership change” within the meaning of IRC § 382. The annual limitation on the amount of taxable income that can be offset by Mirant’s pre-Merger NOLs was redetermined as of the date of the Merger. GenOn Americas Generation’s annual limitation on the amount of taxable income that can be offset by its pre-Merger NOLs was redetermined as a consequence of the Mirant ownership change as a result of the Merger. GenOn Americas Generation has reduced the amount of pro forma NOLs available to offset post-Merger taxable income based on the expected limits determined in accordance with IRC § 382.

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.

The following reflects a pro forma disclosure of the income tax provision that would be reported if GenOn Mid-Atlantic was to be allocated income taxes attributable to its operations. Pro forma income tax provision attributable to income before tax would consist of the following:

	2011		2010			2009
	(in millions)
Current provision:
Federal	$	3	$	108		$	182
State	1		21			40
Deferred provision (benefit):
Federal	21		(159		)	(9		)
State	5		(39		)	(7		)
Total income taxes provision (benefit)	$	30	$	(69	)	$	206

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The following table presents the pro forma reconciliation of GenOn Mid-Atlantic’s federal statutory income tax provision for continuing operations adjusted for reorganization items to the pro forma effective tax provision:

	2011			2010			2009
	(in millions)
United States federal statutory income tax provision (benefit)	$	37		$	(274	)	$	121
State and local income taxes, net	4			(11		)	21
Tax settlement(1)	(11		)	—			—
Impairment of non-deductible goodwill	—			216			64
Tax provision (benefit)	$	30		$	(69	)	$	206

(1) Settlement of tax disputes increased our tax basis in depreciable assets that previously had been written off as a result of Mirant’s emergence from bankruptcy in 2006.

	December 31,
	2011			2010
	(in millions)
Deferred Tax Assets:
Property and intangible assets	$	27		$	26
Other, net	39			21
Net deferred tax assets	66			47
Deferred Tax Liabilities:
Derivative contracts	(313		)	(266		)
Other, net	(1		)	—
Net deferred tax liabilities	(314		)	(266		)
Net deferred taxes	$	(248	)	$	(219	)

Pro Forma Tax Uncertainties

For 2009, our tax provision includes an insignificant amount related to the accrual for any penalties and interest related to the uncertain tax benefits. Subsequent to the Merger, we have not recorded any uncertain tax benefits.

6. 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.

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

GenOn Americas Generation

	2011		2010		2009
	(in millions)

Cost of fuel, electricity and other products—affiliate	$	8	$	8	$	9
Operations and maintenance expense—affiliate	129		163		155
Total	$	137	$	171	$	164

GenOn Mid-Atlantic

	2011		2010		2009
	(in millions)

Cost of fuel, electricity and other products—affiliate	$	8	$	8	$	8
Operations and maintenance expense—affiliate	75		92		84
Total	$	83	$	100	$	92

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 consolidated statements of operations. Amounts due from and to GenOn’s indirect operating subsidiaries are recorded as receivables, net—affiliate or payables, net—affiliate, as appropriate. Substantially all energy marketing overhead expenses are allocated to GenOn’s operating subsidiaries. During 2011, GenOn Americas Generation recorded a reduction to operations and maintenance expense—affiliate of $25 million, related to the allocations of energy marketing overhead expenses to affiliates that are not included in the GenOn Americas Generation consolidated statements of operations.

GenOn Mid-Atlantic

GenOn Mid-Atlantic receives services from GenOn Energy Management which include the bidding and dispatch of the generating units, procurement of fuel and other products and the execution of contracts, including economic hedges, to reduce price risk. These transactions are recorded as operating revenues—affiliate, cost of fuel, electricity and other products—affiliate and operations and maintenance expense—affiliate, as appropriate, in the consolidated statements of operations. Amounts due to and from GenOn Energy Management under the Power Sale, Fuel Supply and Services Agreement are recorded as payables, net—affiliate or receivables, net—affiliate, as appropriate. Substantially all energy marketing overhead expenses are allocated to GenOn’s operating subsidiaries. During, 2011, 2010 and 2009, GenOn Mid-Atlantic incurred $4 million, $13 million and $14 million, respectively, of energy marketing overhead expense. These costs are included in operations and maintenance expense—affiliate in GenOn Mid-Atlantic’s 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

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Management for power and capacity sales are recorded as payables, net—affiliate or receivables, net—affiliate in GenOn Mid-Atlantic’s 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 2011, 2010 and 2009, we incurred the following in costs under these arrangements, which are included in operations and maintenance expense —affiliate in our consolidated statements of operations:

	2011		2010		2009
	(in millions)

GenOn Americas Generation	$	124	$	130	$	135
GenOn Mid-Atlantic	$	81	$	83	$	91

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

Sales Agreements with GenOn Marsh Landing (GenOn Americas Generation)

In October 2010, GenOn Delta entered into an agreement for the sale of the land for the Marsh Landing planned generating facility site to GenOn Marsh Landing for consideration of approximately $3 million based on a third-party appraisal. In December 2010, GenOn Marsh Landing and GenOn Delta closed on the transfer of the site. In connection with the transaction, GenOn Delta recognized a gain of $3 million, which is included in gain on sales of assets, net—affiliate in GenOn Americas Generation’s consolidated statement of operations.

In October 2010, GenOn California North entered into an agreement for the sale of certain emission reduction credits to GenOn Marsh Landing. In connection with the transaction, GenOn California North recognized a gain of $2 million, which is included in gain on sales of assets, net—affiliate in GenOn Americas Generation’s consolidated statement of operations.

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

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(a) Commitments.

In addition to debt and other obligations in the consolidated balance sheets, we have the following annual commitments under various agreements at December 31, 2011, related to our operations:

GenOn Americas Generation

	Off-Balance Sheet Arrangements and Contractual Obligations by Year
	Total		2012		2013		2014		2015		2016		>5 Years
	(in millions)

GenOn Mid-Atlantic operating leases	$	1,596	$	132	$	138	$	131	$	110	$	150	$	935
Other operating leases	33		3		4		4		3		3		16
Fuel commitments	629		362		249		18		—		—		—
Commodity transportation commitments	55		30		5		5		5		5		5
LTSA commitments	49		7		2		2		2		1		35
Maryland Healthy Air Act	83		83		—		—		—		—		—
Other	287		114		11		12		12		13		125
Total commitments	$	2,732	$	731	$	409	$	172	$	132	$	172	$	1,116

GenOn Mid-Atlantic

	Off-Balance Sheet Arrangements and Contractual Obligations by Year
	Total		2012		2013		2014		2015		2016		>5 Years
	(in millions)

GenOn Mid-Atlantic operating leases	$	1,596	$	132	$	138	$	131	$	110	$	150	$	935
Other operating leases	33		3		4		4		3		3		16
Fuel commitments	629		362		249		18		—		—		—
Commodity transportation commitments	45		29		4		4		4		4		—
Maryland Healthy Air Act	83		83		—		—		—		—		—
Other	273		100		11		12		12		13		125
Total commitments	$	2,659	$	709	$	406	$	169	$	129	$	170	$	1,076

Our contractual obligations tables do not include the derivative obligations reported at fair value (other than fuel supply commitments), which are discussed in note 2 and the asset retirement obligations, which are discussed in note 3.

GenOn Mid-Atlantic Operating Leases

GenOn Mid-Atlantic leases a 100% interest in both the Dickerson and Morgantown baseload units and associated property through 2029 and 2034, respectively. GenOn Mid-Atlantic has 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 and recognize rent expense on a straight-line basis. Rent expense totaled $96 million during 2011, 2010 and 2009, and is included in operations and maintenance expense in the consolidated statements of operations. At December 31, 2011 and 2010, we have paid $482 million and $444 million, respectively, of lease payments in excess of rent expense recognized, which is recorded in prepaid rent on the consolidated balance sheets. Of these amounts, $96 million is included in prepaid rent on our consolidated balance sheets at December 31, 2011 and 2010.

At December 31, 2011, the total notional minimum lease payments for the remaining terms of the leases aggregated $1.6 billion and the aggregate termination value for the leases was $1.3 billion, which generally decreases over time. GenOn Mid-Atlantic leases the Dickerson and the Morgantown baseload units from third party owner lessors. These owner lessors each own undivided interests in these baseload generating facilities. The

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subsidiaries of the institutional investors who hold the membership interests in the owner lessors are called owner participants. Equity funding by the owner participants plus transaction expenses paid by the owner participants totaled $299 million. The issuance and sale of pass through certificates raised the remaining $1.2 billion needed for the owner lessors to acquire the undivided interests.

The pass through certificates are not direct obligations of GenOn Mid-Atlantic. Each pass through certificate represents a fractional undivided interest in one of three pass through trusts formed pursuant to three separate pass through trust agreements between GenOn Mid-Atlantic and United States Bank National Association (as successor in interest to State Street Bank and Trust Company of Connecticut, National Association), as pass through trustee. The property of the pass through trusts consists of lessor notes. The lessor notes issued by an owner lessor are secured by that owner lessor’s undivided interest in the lease facilities and its rights under the related lease and other financing documents. For restrictions under these leases, see note 7.

Other Operating Leases

We have commitments under other operating leases with various terms and expiration dates. GenOn Americas Generation’s rent expense totaled $7 million, $6 million and $6 million during 2011, 2010 and 2009, respectively, related to these operating leases. GenOn Mid-Atlantic’s rent expense totaled $7 million, $6 million and $5 million during 2011, 2010 and 2009, respectively, related to these operating leases.

Fuel and Commodity Transportation Commitments

We have commitments under coal agreements and commodity transportation contracts, primarily related to natural gas and coal, of various quantities and durations. At December 31, 2011, the maximum remaining term under any individual fuel supply contract is three years and any transportation contract is 13 years.

LTSA Commitments

LTSA commitments relates to GenOn Americas Generation’s long term service agreements associated with the maintenance of a turbine at its Kendall generating facility.

Maryland Healthy Air Act

Maryland Healthy Air Act commitments reflect the remaining expected payments for capital expenditures to comply with the limitations for SO2, NOx and mercury emissions under the Maryland Healthy Air Act. We completed the installation of the remaining pollution control equipment related to compliance with the Maryland Healthy Air Act in the fourth quarter of 2009. However, provisions in our construction contracts provide that certain payments be made after final completion of the project. See note 9.

Other

Other primarily represents miscellaneous liabilities and open purchase orders less invoices received related to general procurement of products and services purchased in the ordinary course of business. These include construction, maintenance and labor activities at our generating facilities.

(b) Cash Collateral.

In order to sell power and purchase fuel in the forward markets and perform other energy trading and marketing activities, GenOn Americas Generation is often required to provide trade credit support to its counterparties or make deposits with brokers. In addition, GenOn Americas Generation is often required to provide cash collateral for access to the transmission grid to participate in power pools and for other operating activities. In the event of default, the counterparty can apply cash collateral held to satisfy the existing amounts outstanding under an open contract.

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The following is a summary of cash collateral posted with counterparties:

	December 31,
	2011		2010
	(in millions)

Cash collateral posted—energy trading and marketing	$	118	$	80
Cash collateral posted—other operating activities	38		40
Total	$	156	$	120

(c) Guarantees (GenOn Americas Generation).

GenOn generally conducts its business through various intermediate holding companies, including GenOn Americas Generation, and various operating subsidiaries, which enter into contracts as a routine 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 of GenOn Americas Generation or a subsidiary under such contracts is to pay money or render performance, such contracts may include obligations to indemnify the counterparty for damages arising from the breach thereof and, in certain instances, other existing or potential liabilities. In many cases GenOn Americas Generation’s maximum potential liability cannot be estimated because some of the underlying agreements contain no limits on potential liability.

Upon issuance or modification of a guarantee, GenOn Americas Generation determines if the obligation is subject to initial recognition and measurement of a liability and/or disclosure of the nature and terms of the guarantee. Generally, guarantees of the performance of a third party are subject to the recognition and measurement, as well as the disclosure provisions, of the accounting guidance related to guarantees. Such guarantees must initially be recorded at fair value, as determined in accordance with the accounting guidance. GenOn Americas Generation did not have any third party guarantees at December 31, 2011, that met the recognition requirements of the accounting guidance.

Guarantees between and on behalf of entities under common control are subject only to the disclosure provisions of the accounting guidance related to guarantors’ accounting and disclosure requirements for guarantees. GenOn Americas Generation must disclose information as to the term of the guarantee and the maximum potential amount of future gross payments (undiscounted) under the guarantee, even if the likelihood of a claim is remote.

Letters of Credit and Surety Bonds

In December 2010, the GenOn North America letters of credit issued under the senior secured revolving credit facility were transferred to GenOn upon completion of the Merger. GenOn has issued letters of credit in support of our obligations to perform under commodity agreements, financing or lease arrangements and other commercial agreements.

At December 31, 2011 and 2010, GenOn Americas Generation had obligations outstanding under surety bonds of $6 million and $7 million, respectively.

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

	December 31,
	2011		2010
	(in millions)

Letters of credit—rent reserves(1)	$	101	$	101
Letters of credit—energy trading and marketing(1)	39		63
Letters of credit—other operating activities(1)	31		31
Surety bonds	6		7
Total	$	177	$	202

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

Commercial Purchase and Sales Arrangements

In connection with the purchase and sale of fuel, emissions allowances and energy to and from third parties with respect to the operation of our generating facilities, we may be required to guarantee a portion of the obligations of certain of our subsidiaries. These obligations may include liquidated damages payments or other unscheduled payments. At December 31, 2011, a GenOn Americas Generation subsidiary is contingently obligated for a total of $24 million under such arrangements. In addition, GenOn is contingently obligated for a total of $77 million under such guarantees issued on behalf of GenOn Americas Generation subsidiaries. GenOn Americas Generation does not expect that it will be required to make any material payments under these guarantees.

Other Guarantees and Indemnifications

Our debt agreements typically indemnify against liabilities that arise from the preparation, entry into, administration or enforcement of the agreement.

We have issued guarantees in conjunction with certain performance agreements and commodity and derivative contracts and other contracts that provide financial assurance to third parties on behalf of a subsidiary or an unconsolidated third party. The guarantees on behalf of subsidiaries are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the relevant subsidiary’s intended commercial purposes.

At December 31, 2011, a GenOn Americas Generation subsidiary has issued $63 million of guarantees of obligations that its subsidiaries may incur in connection with construction agreements. In addition, GenOn Energy Holdings has issued $18 million of guarantees on behalf of a GenOn Americas Generation subsidiary related to settlement agreement obligations. We do not expect that we will be required to make any material payments under these guarantees.

GenOn Americas Generation, through its subsidiaries, participates in several power pools with RTOs. The rules of these RTOs require that each participant indemnify the pool for defaults by other members. Usually, the amount indemnified is based upon the activity of the participant relative to the total activity of the pool and the amount of the default. Consequently, the amount of such indemnification cannot be quantified.

On a routine basis in the ordinary course of business, we indemnify financing parties and consultants or other vendors who provide services to us. We do not expect that we will be required to make any material payments under these indemnity provisions.

Because some of the guarantees and indemnities we issue to third parties do not limit the amount or duration of our obligations to perform under them, there exists a risk that we may have obligations in excess of the amounts described above. For those guarantees and indemnities that do not limit our liability exposure, we may not be able to estimate our potential liability until a claim is made for payment or performance, because of the contingent nature of these contracts.

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GenOn Americas Generation Operating Segments

	Eastern PJM		Northeast			California			Energy Marketing			Other Operations			Eliminations			Total
	(in millions)
2011:
Operating revenues(1)	$	260	$	11		$	94		$	2,650		$	—		$	—		$	3,015
Operating revenues—affiliate(2)	1,087		157			—			12			—			(1,333		)	(77		)
Total operating revenues	1,347		168			94			2,662			—			(1,333		)	2,938
Cost of fuel, electricity and other products(3)	18		2			1			181			475			—			677
Cost of fuel, electricity and other products—affiliate(4)	527		96			(3		)	2,407			(474		)	(1,333		)	1,220
Total cost of fuel, electricity and other products	545		98			(2		)	2,588			1			(1,333		)	1,897
Gross margin (excluding depreciation and amortization)	802		70			96			74			(1		)	—			1,041
Operating Expenses:
Operations and maintenance	301		45			23			3			6			—			378
Operations and maintenance—affiliate	166		38			31			(1		)	(6		)	—			228
Depreciation and amortization	131		24			15			2			5			—			177
Impairment losses(5)	94		20			14			—			—			—			128
Loss (gain) on sales of assets, net	—		—			(5		)	—			—			—			(5		)
Loss (gain) on sales of assets, net—affiliate	—		1			1			—			—			—			2
Total operating expenses	692		128			79			4			5			—			908
Operating income	$	110	$	(58	)	$	17		$	70		$	(6	)	$	—		$	133
Total assets	$	4,478	$	454		$	135		$	2,012		$	177		$	(667	)	$	6,589
Capital expenditures	$	147	$	8		$	1		$	—		$	3		$	—		$	159

(1) Includes unrealized gains of $74 million and $178 million for Eastern PJM and Energy Marketing, respectively.

(2) Includes unrealized gains (losses) of $45 million, $(5) million and $(152) million for Eastern PJM, Northeast and Energy Marketing, respectively.

(3) Includes unrealized losses of $7 million for Energy Marketing.

(4) Includes unrealized (gains) losses of $(1) million, $2 million and $(6) million for Eastern PJM, Northeast and Energy Marketing, respectively.

(5) Represents impairment losses for the write off of excess NOx and SO2 emissions allowances as a result of the CSAPR. See note 3.

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GenOn Americas Generation Operating Segments

	Eastern PJM			Northeast			California			Energy Marketing(1)		Other Operations(1)			Eliminations			Total
	(in millions)
2010:
Operating revenues(2)	$	347		$	15		$	118		$	1,622	$	—		$	—		$	2,102
Operating revenues—affiliate(3)	1,357			219			26			246		—			(1,845		)	3
Total operating revenues	1,704			234			144			1,868		—			(1,845		)	2,105
Cost of fuel, electricity and other products(4)	18			2			—			284		542			—			846
Cost of fuel, electricity and other products—affiliate(5)	680			135			23			1,557		(542		)	(1,845		)	8
Total cost of fuel, electricity and other products	698			137			23			1,841		—			(1,845		)	854
Gross margin (excluding depreciation and amortization)	1,006			97			121			27		—			—			1,251
Operating Expenses:
Operations and maintenance	299			53			29			3		6			—			390
Operations and maintenance—affiliate	194			55			43			7		(6		)	—			293
Depreciation and amortization	141			23			28			1		6			—			199
Impairment losses(6)	1,153			—			—			—		28			(616		)	565
Gain on sales of assets, net	(3		)	(1		)	(5		)	—		—			—			(9		)
Total operating expenses	1,784			130			95			11		34			(616		)	1,438
Operating income (loss)	$	(778	)	$	(33	)	$	26		$	16	$	(34	)	$	616		$	(187	)

Total assets	$	4,626		$	488		$	121		$	2,418	$	1,292		$	(1,132	)	$	7,813
Capital expenditures	$	233		$	11		$	2		$	1	$	5		$	—		$	252

(1) Includes reclassifications for adjustments previously included in Energy Marketing.

(2) Includes unrealized gains (losses) of $123 million and $(54) million for Eastern PJM and Energy Marketing, respectively.

(3) Includes unrealized gains (losses) of $(43) million, $(3) million and $49 million for Eastern PJM, Northeast and Energy Marketing, respectively.

(4) Includes unrealized losses of $89 million for Energy Marketing.

(5) Includes unrealized (gains) losses of $73 million, $16 million and $(89) million for Eastern PJM, Northeast and Energy Marketing, respectively.

(6) Includes impairment loss of goodwill of $616 million recorded at GenOn Mid-Atlantic on its standalone balance sheet. The goodwill does not exist at GenOn Americas Generation’s consolidated balance sheet. As such, the goodwill impairment loss is eliminated upon consolidation.

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GenOn Americas Generation Operating Segments

	Eastern PJM			Northeast			California			Energy Marketing(1)		Other Operations(1)			Eliminations			Total
	(in millions)
2009:
Operating revenues(2)	$	401		$	15		$	109		$	1,787	$	—		$	(3	)	$	2,309
Operating revenues—affiliate(3)	1,377			303			45			213		—			(1,938		)	—
Total operating revenues	1,778			318			154			2,000		—			(1,941		)	2,309
Cost of fuel, electricity and other products(4)	17			(1		)	(1		)	145		541			—			701
Cost of fuel, electricity and other products—affiliate(5)	510			144			33			1,801		(541		)	(1,938		)	9
Total cost of fuel, electricity and other products	527			143			32			1,946		—			(1,938		)	710
Gross margin (excluding depreciation and amortization)	1,251			175			122			54		—			(3		)	1,599
Operating Expenses:
Operations and maintenance	245			73			34			3		—			—			355
Operations and maintenance—affiliate	189			53			41			8		—			—			291
Depreciation and amortization	98			18			22			1		3			—			142
Impairment losses(6)	385			—			14			—		5			(183		)	221
Gain on sales of assets, net	(14		)	(4		)	—			—		—			(4		)	(22		)
Total operating expenses	903			140			111			12		8			(187		)	987
Operating income (loss)	$	348		$	35		$	11		$	42	$	(8	)	$	184		$	612

Total assets	$	5,807		$	616		$	139		$	2,782	$	407		$	(2,234	)	$	7,517

Capital expenditures	$	578		$	16		$	2		$	2	$	68		$	—		$	666

(1) Includes reclassifications for adjustments previously included in Energy Marketing.

(2) Includes unrealized gains (losses) of $137 million and $(139) million for Eastern PJM and Energy Marketing, respectively.

(3) Includes unrealized gains (losses) of $(1) million, $(25) million and $26 million for Eastern PJM, Northeast and Energy Marketing, respectively.

(4) Includes unrealized gains of $49 million for Energy Marketing.

(5) Includes unrealized (gains) losses of $(8) million, $(41) million and $49 million for Eastern PJM, Northeast and Energy Marketing, respectively.

(6) Includes $183 million impairment loss of goodwill recorded at GenOn Mid-Atlantic on its standalone balance sheet. The goodwill does not exist at GenOn Americas Generation’s consolidated balance sheet. As such, the goodwill impairment loss is eliminated upon consolidation.

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9. Litigation and Other Contingencies

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

Scrubber Contract Litigation

In January 2011, Stone & Webster, the EPC contractor for the scrubber projects at the Chalk Point, Dickerson and Morgantown generating facilities, filed two suits against GenOn Mid-Atlantic and one suit against GenOn Chalk Point, LLC in the United States District Court for the District of Maryland. Stone & Webster claims that it has not been paid in accordance with the terms of the EPC agreements for the scrubber projects and sought $143.1 million in liens against the properties. In March 2011, the court granted these liens. In June 2011, Stone & Webster filed a motion to amend its lien claims at these facilities by an additional $90.5 million. In August 2011, the court granted these additional liens. In September 2011, GenOn Mid-Atlantic paid $68 million to Stone & Webster for achieving substantial completion under the EPC agreements, which reduced the outstanding liens amount to $165.6 million. As a result of certain lien restrictions in its lease documentation, GenOn Mid-Atlantic has reserved $165.6 million of cash (which is included in funds on deposit on the unaudited condensed consolidated balance sheet) in respect of such liens. The liens are interlocutory only and will not become final unless and until Stone & Webster is successful in prosecuting its contractual claims. We dispute Stone & Webster’s allegations and in February 2011 filed a related action against Stone &Webster in the United States District Court for the Southern District of New York. The proceedings in Maryland have been stayed pending resolution of the proceeding in New York. Assuming we are successful in pursuing our claims in the New York proceeding, the total estimated capital expenditures for compliance with the Maryland Healthy Air Act would not exceed the $1.674 billion we currently have recorded. However, if the costs were to equal the amount claimed by Stone &Webster in the litigation, the total capital expenditures would exceed $1.674 billion by approximately 5%.

Bowline Property Tax Dispute

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

Environmental Matters

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

Potomac River Notice of Violation. In August 2011, the Virginia DEQ issued a notice of violation related to the Potomac River generating facility. The Virginia DEQ asserted that (a) the facility is not equipped with all appropriate fugitive dust controls, (b) we failed to correctly calculate NOx emissions rates and (c) NOx emissions exceeded the permitted limits on six days in June and July 2011. In February 2012, we settled this matter with the Virginia DEQ by agreeing to pay a civil penalty of $280,700.

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Maryland Fly Ash Facilities. We have three fly ash facilities in Maryland: Faulkner, Westland and Brandywine. We dispose of fly ash from our Morgantown and Chalk Point generating facilities at Brandywine. We dispose of fly ash from our Dickerson generating facility at Westland. We no longer dispose of fly ash at the Faulkner facility. As described below, the MDE has sued us regarding Faulkner and Brandywine and threatened to sue regarding Westland. The MDE also has threatened not to renew the water discharge permits for all three facilities.

Faulkner Litigation. In May 2008, the MDE sued us in the Circuit Court for Charles County, Maryland alleging violations of Maryland’s water pollution laws at Faulkner. The MDE contended that the operation of Faulkner had resulted in the discharge of pollutants that exceeded Maryland’s water quality criteria and without the appropriate NPDES permit. The MDE also alleged that we failed to perform certain sampling and reporting required under an applicable NPDES permit. The MDE complaint requested that the court (a) prohibit continuation of the alleged unpermitted discharges, (b) require us to cease from further disposal of any coal combustion byproducts at Faulkner and close and cap the existing disposal cells and (c) assess civil penalties. In July 2008, we filed a motion to dismiss the complaint, arguing that the discharges are permitted by a December 2000 Consent Order. In January 2011, the MDE dismissed without prejudice its complaint and informed us that it intended to file a similar lawsuit in federal court. In May 2011, the MDE filed a complaint against us in the United States District Court for the District of Maryland alleging violations of the Clean Water Act and Maryland’s Water Pollution Control Law at Faulkner. The MDE contends that (a) certain of our water discharges are not authorized by our existing permit and (b) operation of the Faulkner facility has resulted in discharges of pollutants that violate water quality criteria. The complaint asks the court to, among other things, (a) enjoin further disposal of coal ash; (b) enjoin discharges that are not authorized by our existing permit; (c) require numerous technical studies; (d) impose civil penalties and (e) award them attorneys’ fees. We dispute the allegations.

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

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

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

Stay and Settlement Discussions. In June 2011, the MDE agreed to stay the litigation related to Faulkner and Brandywine while we pursue settlement of allegations related to the three Maryland ash facilities. MDE also agreed not to pursue its tentative denial of our application to renew our water discharge permit at Brandywine and agreed not to act on our renewal applications for Faulkner or Westland while we are discussing settlement. As a condition to obtaining the stay, we agreed in principle to pay a civil penalty of $1.9 million to the MDE if we reach a comprehensive settlement regarding all of the allegations related to the three Maryland ash facilities. Accordingly, we accrued $1.9 million during 2011. We also developed a technical solution, which includes installing synthetic caps on the closed cells of each of the three ash facilities. During 2011, we accrued $47 million for the estimated cost of the technical solution. We continue to negotiate with the MDE. At this time, we cannot reasonably estimate the upper range of our obligations for remediating the sites for the following reasons: (a) we have not finished

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Schedule I

GENON AMERICAS GENERATION, LLC (PARENT)

CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF OPERATIONS

	2011			2010			2009
	(in millions)

Operating income	$	—		$	—		$	—
Other Income (Expense), net:
Equity in income (loss) of affiliates	102			(276		)	596
Interest expense	(86		)	(120		)	(121		)
Other, net	—			1			—
Total other income (expense), net	16			(395		)	475
Income (loss) before income taxes	16			(395		)	475
Provision for income taxes	—			1			—
Net income (loss)	$	16		$	(396	)	$	475

The accompanying notes are an integral part of the registrant’s condensed financial information.

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Schedule I

GENON AMERICAS GENERATION, LLC (PARENT)

CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED BALANCE SHEETS

	December 31,
	2011		2010
	(in millions)
ASSETS
Current Assets:
Cash and cash equivalents	$	—	$	150
Total current assets	—		150
Property, Plant and Equipment, net	8		—
Noncurrent Assets:
Investments in affiliates	4,827		4,834
Debt issuance costs, net	6		5
Total noncurrent assets	4,833		4,839
Total Assets	$	4,841	$	4,989

LIABILITIES AND MEMBER’S EQUITY
Current Liabilities:
Current portion of long-term debt	$	—	$	535
Accounts payable and accrued liabilities	16		23
Payables, net—affiliate	12		9
Total current liabilities	28		567
Noncurrent Liabilities:
Long-term debt, net of current portion	848		848
Other	—		1
Total noncurrent liabilities	848		849
Commitments and Contingencies
Member’s Equity:
Member’s interest	3,965		3,573
Total member’s equity	3,965		3,573
Total Liabilities and Member’s Equity	$	4,841	$	4,989

The accompanying notes are an integral part of the registrant’s condensed financial information.

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Schedule I

GENON AMERICAS GENERATION, LLC (PARENT)

CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CONDENSED STATEMENTS OF CASH FLOWS

	2011			2010			2009
	(in millions)

Cash Flows from Operating Activities:
Net cash provided by operating activities	$	32		$	221		$	116
Cash Flows from Investing Activities:
Capitalized interest	(3		)	—			—
Capital contributions	(30		)	(1,079		)	—
Net cash used in investing activities	(33		)	(1,079		)	—
Cash Flows from Financing Activities:
Redemption of preferred stock in affiliate	—			150			—
Repayment of long-term debt	(535		)	—			—
Issuance of notes payable—affiliate	12			—			—
Capital contributions	474			1,079			—
Distributions to member	(100		)	(222		)	(115		)
Net cash provided by (used in) financing activities	(149		)	1,007			(115		)
Net Increase (Decrease) in Cash and Cash Equivalents	(150		)	149			1
Cash and Cash Equivalents, beginning of year	150			1			—
Cash and Cash Equivalents, end of year	$	—		$	150		$	1

Supplemental Disclosures:
Cash paid for interest, net of amounts capitalized	$	94		$	119		$	119

Supplemental Disclosures for Non-Cash Investing and Financing Activities:
Conversion to equity of notes payable to affiliate	$	2		$	93		$	—

The accompanying notes are an integral part of the registrant’s condensed financial information.

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Schedule I

GENON AMERICAS GENERATION, LLC (PARENT)

CONDENSED FINANCIAL INFORMATION OF REGISTRANT

NOTES TO REGISTRANTS’ CONDENSED FINANCIAL STATEMENTS

December 31, 2011, 2010 and 2009

1. Background and Basis of Presentation

Background

The condensed parent company financial statements have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X, as the restricted net assets of GenOn Americas Generation, LLC’s subsidiaries exceed 25 percent of the consolidated net assets of GenOn Americas Generation, LLC’s. These statements should be read in conjunction with the consolidated statements and notes thereto of GenOn Americas Generation.

GenOn Americas Generation, LLC is a Delaware limited liability company and indirect wholly-owned subsidiary of GenOn.

GenOn, a Delaware corporation, was formed in August 2000 by CenterPoint (then known as Reliant Energy, Incorporated) in connection with the planned separation of its regulated and unregulated operations. CenterPoint transferred substantially all of its unregulated businesses, including the name Reliant Energy to the company now named GenOn Energy, Inc. In May 2001, Reliant Energy (then known as Reliant Resources, Inc.) became a publicly traded company and in September 2002, CenterPoint distributed its remaining ownership of Reliant Energy’s common stock to its stockholders. RRI Energy changed its name from Reliant Energy, Inc. effective May 2, 2009 in connection with the sale of its retail business. GenOn changed its name from RRI Energy, Inc. effective December 3, 2010.

Merger of Mirant and RRI Energy

Basis of Presentation

The condensed financial statements presented herein are the condensed financial statements and other financial information of GenOn Americas Generation, LLC.

Equity in income/loss of affiliates consists of earnings of direct subsidiaries of GenOn Americas Generation, LLC (parent).

During 2011, 2010 and 2009, GenOn Americas Generation, LLC received cash dividends from its subsidiaries of $137 million, $341 million and $235 million, respectively.

Immaterial Misstatement of Post-Employment Benefits in Prior Periods

During 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 2010, 2009, 2008 and 2007, our equity

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Schedule II

VALUATION AND QUALIFYING ACCOUNTS

GenOn Americas Generation

	December 31, 2011, 2010 and 2009
			Additions
Description	Balance at Beginning of Period		Charged to Income		Charged to Other Accounts		Deductions(1)			Balance at End of Period
	(in millions)

Provision for uncollectible accounts (current)
2011	$	4	$	11	$	—	$	(3	)	$	12
2010	3		6		—		(5		)	4
2009	12		9		—		(18		)	3
Provision for uncollectible accounts (noncurrent)
2011	$	15	$	32	$	—	$	(11	)	$	36
2010	11		18		—		(14		)	15
2009	42		13		—		(44		)	11

(1) Deductions in 2011, 2010 and 2009 consisted primarily of reversals of credit reserves for derivative contract assets.

GenOn Mid-Atlantic

	December 31, 2011, 2010 and 2009
			Additions
Description	Balance at Beginning of Period		Charged to Income		Charged to Other Accounts		Deductions(1)			Balance at End of Period
	(in millions)

Provision for uncollectible accounts (current)
2011	$	4	$	11	$	—	$	(3	)	$	12
2010	2		6		—		(4		)	4
2009	9		8		—		(15		)	2
Provision for uncollectible accounts (noncurrent)
2011	$	15	$	33	$	—	$	(12	)	$	36
2010	11		18		—		(14		)	15
2009	42		13		—		(44		)	11

(1) Deductions in 2011, 2010 and 2009 consisted primarily of reversals of credit reserves for derivative contract assets.

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3. Exhibit Index

GenOn Americas Generation

Exhibit No.		Exhibit Name

1.1		Purchase Agreement, dated at October 2, 2001, among Mirant Americas Generation, Inc. and Salomon Smith Barney Inc., Banc of America Securities LLC, Blaylock & Partners, L.P., Scotia Capital (USA) Inc., TD Securities (USA) Inc. and Tokyo-Mitsubishi International plc, as Initial Purchaser (Incorporated herein by reference to Exhibit 1.1 to Registrant’s Registration Statement on Form S-4/A Amendment No. 1, Registration No. 333-85124)

2.1		Purchase and Sale Agreement by and between Mirant Americas, Inc. and LS Power Acquisition Co. I, LLC, dated at January 15, 2007 (Incorporated herein by reference to Exhibit 2.1 to the Mirant Corporation Current Report on Form 8-K filed January 18, 2007)

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

3.3		Second Amended and Restated Limited Liability Agreement for GenOn Americas Generation, LLC dated December 3, 2010

4.1		Indenture between Mirant Americas Generation, Inc. and Bankers Trust Company, as trustee, relating to Senior Notes, dated at May 1, 2001 (Incorporated herein by reference to Exhibit 4.1 to the Registrant’s Registration Statement on Form S-4, Registration No. 333-63240)

4.2		Second Supplemental Indenture relating to Senior Notes 8.300% due 2011, dated at May 1, 2001 (Incorporated herein by reference to Exhibit 4.3 to Registrant’s Registration Statement on Form S-4, Registration No. 333-63240)

4.3		Third Supplemental Indenture from Mirant Americas Generation, Inc. to Bankers Trust Company, relating to 9.125 % Senior Notes due 2031, dated at May 1, 2001 (Incorporated herein by reference to Exhibit 4.4 to Registrant’s Registration Statement on Form S-4, Registration No. 333-63240)

4.4		Fifth Supplemental Indenture from Mirant Americas Generation, Inc. to Bankers Trust Company, dated at October 9, 2001 (Incorporated herein by reference to Exhibit 4.6 to Registrant’s Registration Statement on Form S-4/A Amendment No. 1, Registration No. 333-85124)

4.5		Form of Sixth Supplemental Indenture from Mirant Americas Generation LLC to Bankers Trust Company, dated at November 1, 2001 (Incorporated herein by reference to Exhibit 4.6 to the Mirant Corporation Annual Report on Form 10-K filed February 27, 2009)

4.6		Form of Seventh Supplemental Indenture from Mirant Americas Generation LLC to Wells Fargo Bank National Association, dated at January 3, 2006 (Incorporated herein by reference to Exhibit 4.1 to Registrant’s Quarterly Report on Form 10-Q filed May 14, 2007)

4.7		Senior Note Indenture between Mirant North America, LLC, Mirant North America Escrow, LLC, MNA Finance Corp. and Law Debenture Trust Company of New York, as trustee (Incorporated herein by reference to Exhibit 4.2 to Registrant’s Annual Report on Form 10-K filed March 14, 2006)

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Exhibit No.		Exhibit Name

4.8		Registration Rights Agreement, dated at October 9, 2001, among Mirant Americas Generation, Inc., Salomon Smith Barney Inc. and Banc of America Securities LLC, Blaylock & Partners, L.P., Scotia Capital (USA) Inc., TD Securities (USA) Inc. and Tokyo-Mitsubishi International plc, as Initial Purchasers (Incorporated herein by reference to Exhibit 4.8 to Registrant’s Registration Statement on Form S-4/A Amendment No. 1, Registration No. 333-85124)

10.1†		Engineering, Procurement and Construction Agreement, dated at July 30, 2007, between Mirant Mid-Atlantic, LLC, Mirant Chalk Point, LLC and Stone & Webster, Inc. (Incorporated herein by reference to Exhibit 10.1 to the Mirant Corporation Quarterly Report on Form 10-Q filed November 6, 2009)

10.2		Membership Interest Purchase and Sale Agreement, dated at January 31, 2007, between Mirant New York, Inc. and Alliance Energy Renewables, LLC (Incorporated herein by reference to Exhibit 10.1 to Registrant’s Quarterly Report on Form 10-Q filed May 14, 2007)

10.3		Settlement and Release of Claims Agreement, by and among the Mirant Parties, the California Parties and OMOI, dated at January 13, 2005 (Incorporated herein by reference to Exhibit 10.39 to the Mirant Corporation Annual Report on Form 10-K filed March 14, 2005, File No. 001-16107)

10.4		Credit Agreement among Mirant North America, LLC, JPMorgan Chase Bank, N.A as administrative agent and Deutsche Bank Securities Inc. and Goldman Sachs Credit Partners L.P., as co-syndication agents, dated at January 3, 2006 (Incorporated herein by reference to Exhibit 10.2 to the Mirant Corporation Quarterly Report on Form 10-Q filed November 6, 2009)

10.5		Administrative Services Agreement dated at January 3, 2006 by and between Mirant Americas Generation, LLC and Mirant Services, LLC (Incorporated herein by reference to Exhibit 10.5 to Registrant’s Annual Report on Form 10-K filed March 31, 2006)

10.6		Power Sale, Fuel Supply and Services Agreement dated at January 3, 2006 among Mirant Americas Energy Marketing, LP, Mirant Bowline, LLC, Mirant Lovett, LLC, and Mirant NY-Gen, LLC (Incorporated herein by reference to Exhibit 10.6 to Registrant’s Annual Report on Form 10-K filed March 31, 2006)

10.7		Power Sale, Fuel Supply and Services Agreement dated at January 3, 2006 among Mirant Americas Energy Marketing, LP, Mirant Canal, LLC, and Mirant Kendall, LLC (Incorporated herein by reference to Exhibit 10.7 to Registrant’s Annual Report on Form 10-K filed March 31, 2006)

10.8		Power Sale, Fuel Supply and Services Agreement dated at January 3, 2006 by and between Mirant Americas Energy Marketing, LP and Mirant Chalk Point, LLC (Incorporated herein by reference to Exhibit 10.8 to Registrant’s Annual Report on Form 10-K filed March 31, 2006)

10.9		Power Sale, Fuel Supply and Services Agreement dated at January 3, 2006 by and between Mirant Americas Energy Marketing, LP and Mirant Mid-Atlantic, LLC (Incorporated herein by reference to Exhibit 10.9 to Registrant’s Annual Report on Form 10-K filed March 31, 2006)

10.10		Power Sale, Fuel Supply and Services Agreement dated at January 3, 2006 by and between Mirant Americas Energy Marketing, LP and Mirant Potomac River, LLC (Incorporated herein by reference to Exhibit 10.10 to Registrant’s Annual Report on Form 10-K filed March 31, 2006)

10.11		Power Sale, Fuel Supply and Services Agreement dated at January 3, 2006 among Mirant Americas Energy Marketing, LP, Mirant Delta, LLC, and Mirant Potrero, LLC (Incorporated herein by reference to Exhibit 10.12 to Registrant’s Annual Report on Form 10-K filed March 31, 2006)

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Exhibit No.		Exhibit Name

10.12		Power Sale, Fuel Supply and Services Agreement dated at January 3, 2006 by and between Mirant Americas Energy Marketing, LP and Mirant Zeeland, LLC (Incorporated herein by reference to Exhibit 10.13 to Registrant’s Annual Report on Form 10-K filed March 31, 2006)

10.13		Mirant Corporation 2005 Omnibus Incentive Compensation Plan, effective December 2005 (Incorporated herein by reference to Exhibit 10.1 to the Mirant Corporation Current Report on Form 8-K filed January 3, 2006, File No. 001-16107)

12.1		Statement of Ratio Earnings to Fixed Charges (Incorporated herein by reference to Exhibit 12.1 to Registrant’s Registration Statement on Form S-4/A Amendment No. 1, Registration No. 333-85124)

21.1*		Subsidiaries of GenOn Americas Generation, LLC

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.

† The Registrant has requested confidential treatment for certain portions of this Exhibit pursuant to Rule 24b-2 under the Securities Exchange Act of 1934, as amended.

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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

3.3		Second Amended and Restated Limited Liability Company Agreement of GenOn Mid-Atlantic, LLC dated January 20, 2011

4.1		Form of 8.625% Series A Pass Through Certificate (Incorporated herein by reference to Exhibit 4.1 to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

4.2		Form of 9.125% Series B Pass Through Certificate (Incorporated herein by reference to Exhibit 4.2 to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

4.3		Form of 10.060% Series C Pass Through Certificate (Incorporated herein by reference to Exhibit 4.3 to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

4.4(a)		Pass Through Trust Agreement A between Southern Energy Mid-Atlantic, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, dated at December 18, 2000 (Incorporated herein by reference to Exhibit 4.4(a) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

4.4(b)		Schedule identifying substantially identical agreement to Pass Through Trust Agreement A constituting Exhibit 4.4(a) (Incorporated herein by reference to Exhibit 4.4(b) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

4.5(a)		Participation Agreement (L1) among Southern Energy Mid-Atlantic, LLC, as Lessee, Dickerson OL1 LLC, as Owner Lessor, Wilmington Trust Company, as Owner Manager, SEMA OP3 LLC, as Owner Participant and State Street Bank and Trust Company of Connecticut, National Association, as Lease Indenture Trustee and as Pass Through Trustee, dated at December 18, 2000 (Incorporated herein by reference to Exhibit 4.5(a) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

4.5(b)		Schedule identifying substantially identical agreements to Participation Agreement constituting Exhibit 4.5(a) (Incorporated herein by reference to Exhibit 4.5(b) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

4.6(a)		Participation Agreement (Morgantown L1) among Southern Energy Mid-Atlantic, LLC, as Lessee, Morgantown OL1 LLC, as Owner Lessor, Wilmington Trust Company, as Owner Manager, SEMA OP1, as Owner Participant and State Street Bank and Trust Company of Connecticut, National Association, as Lease Indenture Trustee and as Pass Through Trustee, dated at December 18, 2000 (Incorporated herein by reference to Exhibit 4.6(a) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

4.6(b)		Schedule identifying substantially identical agreements to Participation Agreement constituting Exhibit 4.6(a) hereto (Incorporated herein by reference to Exhibit 4.6(b) to Registrant’s Form S-4 in Registration No. 333-61668)

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Exhibit No.		Exhibit Name

4.7(a)		Facility Lease Agreement (L1) between Southern Energy Mid-Atlantic, LLC, as Facility Lessee, and Dickerson OL1 LLC, as Owner Lessor, dated at December 19, 2000 (Incorporated herein by reference to Exhibit 4.7(a) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

4.7(b)		Schedule identifying substantially identical agreement to Facility Lease Agreement constituting Exhibit 4.7(a) (Incorporated herein by reference to Exhibit 4.7(b) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

4.8(a)		Facility Lease Agreement (L1) between Southern Energy Mid-Atlantic, LLC, as Facility Lessee, and Morgantown OL1 LLC, as Owner Lessor, dated at December 19, 2000 (Incorporated herein by reference to Exhibit 4.8(a) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

4.8(b)		Schedule identifying substantially identical agreement to Facility Lease Agreement constituting Exhibit 4.8(a) (Incorporated herein by reference to Exhibit 4.8(b) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

4.9(a)		Indenture of Trust, Mortgage and Security Agreement (L1) between Dickerson OL1 LLC, as Lessor, and State Street Bank and Trust Company of Connecticut, National Association, as Lease Indenture Trustee, dated at December 19, 2000 (Incorporated herein by reference to Exhibit 4.9(a) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

4.9(b)		Schedule identifying substantially identical agreement to Indenture of Trust, Mortgage and Security Agreement constituting Exhibit 4.9(a) (Incorporated herein by reference to Exhibit 4.9(b) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

4.10(a)		Indenture of Trust, Mortgage and Security Agreement (L1) between Morgantown OL1 LLC, as Lessor, and State Street Bank and Trust Company of Connecticut, National Association, as Lease Indenture Trustee, dated at December 19, 2000 (Incorporated herein by reference to Exhibit 4.10(a) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

4.10(b)		Schedule identifying substantially identical agreement to Indenture of Trust, Mortgage and Security Agreement constituting Exhibit 4.10(a) (Incorporated herein by reference to Exhibit 4.10(b) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

4.11(a)		Series A Lessor Note Due June 20, 2012 for Dickerson OL1 LLC, dated at December 19, 2000 (Incorporated herein by reference to Exhibit 4.11(a) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

4.11(b)		Schedule identifying substantially identical Lessor Notes constituting Exhibit 4.11(a) (Incorporated herein by reference to Exhibit 4.11(b) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

4.12(a)		Series A Lessor Note Due June 30, 2008, for Morgantown OL1 LLC, dated at December 19, 2000 (Incorporated herein by reference to Exhibit 4.12(a) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

4.12(b)		Schedule identifying substantially Series A Lessor Notes constituting Exhibit 4.12(a) (Incorporated herein by reference to Exhibit 4.12(b) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

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Exhibit No.		Exhibit Name

4.13(a)		Series B Lessor Note Due June 30, 2015, for Dickerson OL1 LLC, dated at December 19, 2000 (Incorporated herein by reference to Exhibit 4.13(a) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

4.13(b)		Schedule identifying substantially Lessor Note constituting Exhibit 4.13(a) (Incorporated herein by reference to Exhibit 4.13(b) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

4.14(a)		Series B Lessor Note Due June 30, 2017, for Morgantown OL1 LLC, dated at December 19, 2000 (Incorporated herein by reference to Exhibit 4.14(a) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

4.14(b)		Schedule identifying substantially identical Lessor Notes constituting Exhibit 4.14(a) (Incorporated herein by reference to Exhibit 4.14(b) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

4.15(a)		Series C Lessor Note Due June 30, 2020, for Morgantown OL1 LLC, dated at December 19, 2000 (Incorporated herein by reference to Exhibit 4.15(a) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

4.15(b)		Schedule identifying substantially identical Lessor Notes constituting Exhibit 4.15(a) (Incorporated herein by reference to Exhibit 4.15(b) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

4.16		Registration Rights Agreement, between Southern Energy Mid-Atlantic, LLC and Credit Suisse First Boston, acting for itself on behalf of the Purchasers, dated at December 18, 2000 (Incorporated herein by reference to Exhibit 4.16 to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

4.17(a)		Supplemental Pass Through Trust Agreement A between Mirant Mid-Atlantic, LLC, and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, dated at June 29, 2001 (Incorporated herein by reference to Exhibit 4.17(a) to Registrant’s Registration Statement on Form S-4/A Registration No. 333-61668)

4.17(b)		Schedule identifying substantially identical agreements to Supplemental Pass Through Trust Agreement for Supplemental Pass Through Trust Agreement B between Mirant Mid-Atlantic, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, dated at June 29, 2001, and Supplemental Pass Through Trust Agreement C between Mirant Mid-Atlantic, LLC and State Street Bank and Trust Company of Connecticut, National Association, as Pass Through Trustee, dated at June 29, 2001 constituting Exhibit 4.17(a) (Incorporated herein by reference to Exhibit 4.17(b) to Registrant’s Registration Statement on Form S-4/A, Registration No. 333-61668)

10.1†		Engineering, Procurement and Construction Agreement, dated at July 30, 2007, between Mirant Mid-Atlantic, LLC, Mirant Chalk Point, LLC and Stone & Webster, Inc. (Incorporated herein by reference to Exhibit 10.1 to the Mirant Corporation Quarterly Report on Form 10-Q filed November 6, 2009)

10.2		Power Sale, Fuel Supply and Services Agreement dated at January 3, 2006 by and between Mirant Americas Energy Marketing, LP and Mirant Mid-Atlantic, LLC (Incorporated herein by reference to Exhibit 10.17 to Registrant’s Annual Report on Form 10-K filed March 3, 2006)

10.3		Power Sale, Fuel Supply and Services Agreement dated at January 3, 2006 by and between Mirant Americas Energy Marketing, LP and Mirant Chalk Point, LLC (Incorporated herein by reference to Exhibit 10.18 to Registrant’s Annual Report on Form 10-K filed March 3, 2006)

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Exhibit No.		Exhibit Name

10.4		Power Sale, Fuel Supply and Services Agreement dated at January 3, 2006 by and between Mirant Americas Energy Marketing, LP and Mirant Potomac River, LLC (Incorporated herein by reference to Exhibit 10.19 to Registrant’s Annual Report on Form 10-K filed March 3, 2006)

10.5		Administrative Services Agreement dated at January 3, 2006 by and between Mirant Mid-Atlantic, LLC and Mirant Services, LLC (Incorporated herein by reference to Exhibit 10.20 to Registrant’s Annual Report on Form 10-K filed March 3, 2006)

10.6(a)		Asset Purchase and Sale Agreement for Generating Plants and Related Assets by and between Potomac Electric Power Company and Southern Energy, Inc. dated at June 7, 2000 (Incorporated herein by reference to Exhibit 10.1(a) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.6(b)		Amendment No. 1 to Asset Purchase and Sale Agreement by and between Potomac Electric Power Company and Southern Energy, Inc. dated at September 18, 2000 (Incorporated herein by reference to Exhibit 10.1(b) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.6(c)		Amendment No. 2 to Asset Purchase and Sale Agreement by and between Potomac Electric Power Company and Southern Energy, Inc. dated at December 19, 2000 (Incorporated herein by reference to Exhibit 10.1(c) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.7(a)		Interconnection Agreement (Dickerson) by and between Potomac Electric Power Company and Southern Energy Mid-Atlantic, LLC dated at December 19, 2000 (Incorporated herein by reference to Exhibit 10.2(a) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.7(b)		Schedule identifying substantially identical agreements to Interconnection Agreement constituting Exhibit 10.7(a) hereto (Incorporated herein by reference to Exhibit 10.2(b) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.8(a)		Easement, License and Attachment Agreement (Dickerson Station) by and between Potomac Electric Power Company, Southern Energy Mid-Atlantic, LLC and Southern Energy MD Ash Management, LLC dated at December 19, 2000 (Incorporated herein by reference to Exhibit 10.3(a) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.8(b)		Schedule identifying substantially identical agreements to Easement, License and Attachment Agreement constituting Exhibit 10.8(a) (Incorporated herein by reference to Exhibit 10.3(b) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.9(a)		Bill of Sale (SEMA: Dickerson; Morgantown; RR Spur; Production Service Center) by Potomac Electric Power Company, for the benefit of Southern Energy Mid-Atlantic, LLC dated at December 19, 2000 (Incorporated herein by reference to Exhibit 10.4(a) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.9(b)		Schedule identifying substantially identical documents to Bill of Sale constituting Exhibit 10.9(a) hereto (Incorporated herein by reference to Exhibit 10.4b to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.10(a)		Facility Site Lease Agreement and Easement Agreement (L1) between Southern Energy Mid-Atlantic, LLC, Dickerson OL1 LLC and Southern Energy MD Ash Management, LLC, dated at December 19, 2000 (Incorporated herein by reference to Exhibit 10.5(a) Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

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Exhibit No.		Exhibit Name

10.10(b)		Schedule identifying substantially identical agreements to Facility Site Lease Agreement constituting Exhibit 10.10(a) (Incorporated herein by reference to Exhibit 10.5(b) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.11(a)		Facility Site Lease Agreement (L1) between Southern Energy Mid-Atlantic, LLC, Morgantown OL1 LLC and Southern Energy MD Ash Management, LLC, dated at December 19, 2000 (Incorporated herein by reference to Exhibit 10.6(a) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.11(b)		Schedule identifying substantially identical agreements to Facility Site Lease Agreement constituting Exhibit 10.11(a) (Incorporated herein by reference to Exhibit 10.6(b) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.12(a)		Facility Site Sublease Agreement (L1) between Southern Energy Mid-Atlantic, LLC, Dickerson OL1 LLC, dated at December 19, 2000 (Incorporated herein by reference to Exhibit 10.7(a) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.12(b)		Schedule identifying substantially identical agreements to Facility Site Sublease Agreement constituting Exhibit 10.12(a) (Incorporated herein by reference to Exhibit 10.7b to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.13(a)		Facility Site Sublease Agreement (L1) between Southern Energy Mid-Atlantic, LLC, Morgantown OL1 LLC, dated at December 19, 2000 (Incorporated herein by reference to Exhibit 10.8a to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.13(b)		Schedule identifying substantially identical agreements to Facility Site Sublease Agreement constituting Exhibit 10.13(a) (Incorporated herein by reference to Exhibit 10.8(b) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.14		Capital Contribution Agreement by and between Southern Energy, Inc. and Southern Energy Mid-Atlantic, LLC dated at December 19, 2000 (Incorporated herein by reference to Exhibit 10.12 to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.15		Promissory Note between Southern Energy Mid-Atlantic, LLC and Southern Energy Peaker, LLC in the original principal amount of $71,110,000 dated at December 19, 2000 (Incorporated herein by reference to Exhibit 10.13 to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.16		Promissory Note between Southern Energy Mid-Atlantic, LLC and Southern Energy Potomac River, LLC in the original principal amount of $152,165,000 dated at December 19, 2000 (Incorporated herein by reference to Exhibit 10.14 to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.17(a)		Shared Facilities Agreement between Southern Energy Mid-Atlantic, LLC, Dickerson OL1 LLC, Dickerson OL2 LLC, Dickerson OL3 LLC, and Dickerson OL4 LLC, dated at December 18, 2000 (Incorporated herein by reference to Exhibit 10.15(a) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.17(b)		Shared Facilities Agreement between Southern Energy Mid-Atlantic, LLC, Morgantown OL1 LLC, Morgantown OL2 LLC, Morgantown OL3 LLC, Morgantown OL4 LLC, Morgantown OL5 LLC, Morgantown OL6 LLC, and Morgantown OL7 LLC, dated at December 18, 2000 constituting Exhibit 10.17(a) (Incorporated herein by reference to Exhibit 10.15(b) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

F-84

Table of Contents

Exhibit No.		Exhibit Name

10.18(a)		Assignment and Assumption Agreement between Southern Energy Mid-Atlantic, LLC, Dickerson OL1 LLC, Dickerson OL2 LLC, Dickerson OL3 LLC, and Dickerson OL4 LLC, dated at December 19, 2000 (Incorporated herein by reference to Exhibit 10.16(a) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.18(b)		Assignment and Assumption Agreement between Southern Energy Mid-Atlantic, LLC, Morgantown OL1 LLC, Morgantown OL2 LLC, Morgantown OL3 LLC, Morgantown OL4 LLC, Morgantown OL5 LLC, Morgantown OL6 LLC, and Morgantown OL7 LLC, dated at December 19, 2000 constituting Exhibit 10.18(a) (Incorporated herein by reference to Exhibit 10.16(b) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.19(a)		Ownership and Operation Agreement between Dickerson OL1 LLC, Dickerson OL2 LLC, Dickerson OL3 LLC, Dickerson OL4 LLC, and Southern Energy Mid-Atlantic, LLC, dated at December 19, 2000 (Incorporated herein by reference to Exhibit 10.17(a) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.19(b)		Ownership and Operation Agreement between Morgantown OL1 LLC, Morgantown OL2 LLC, Morgantown OL3 LLC, Morgantown OL4 LLC, Morgantown OL5 LLC, Morgantown OL6 LLC, Morgantown OL7 LLC, and Southern Energy Mid-Atlantic, LLC, dated at December 18, 2000 constituting Exhibit 10.19(a) (Incorporated herein by reference to Exhibit 10.17(b) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.20(a)		Guaranty Agreement (Dickerson L1) between Southern Energy, Inc. and Dickerson OL1 LLC, dated at December 19, 2000 (Incorporated herein by reference to Exhibit 10.21(a) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.20(b)		Schedule identifying substantially identical agreements to Guaranty Agreement constituting Exhibit 10.20(a) (Incorporated herein by reference to Exhibit 10.21(b) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.21(a)		Guaranty Agreement (Morgantown L1) between Southern Energy, Inc. and Morgantown OL1 LLC, dated at December 19, 2000 (Incorporated herein by reference to Exhibit 10.22(a) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.21(b)		Schedule identifying substantially identical agreements to Guaranty Agreement constituting Exhibit 10.21(a) (Incorporated herein by reference to Exhibit 10.22(b) to Registrant’s Registration Statement on Form S-4, Registration No. 333-61668)

10.22		Credit Agreement among Mirant North America, LLC, JPMorgan Chase Bank, N.A. as administrative agent and Deutsche Bank Securities Inc. and Goldman Sachs Credit Partners L.P., as co-syndication agents, dated at January 3, 2006 (Incorporated herein by reference to Exhibit 10.2 to the Mirant Corporation Quarterly Report on Form 10-Q filed November 6, 2009)

21.1*		Subsidiaries of GenOn Mid-Atlantic, LLC

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))

F-85

Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	GenOn Americas Generation, LLC


Date: February 29, 2012	By:	/s/ EDWARD R. MULLER
		Edward R. Muller
		President and Chief Executive Officer
		(Principal Executive Officer)

GENON AMERICAS GENERATION, LLC

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signatures		Title


/s/ EDWARD R. MULLER		President and Chief Executive Officer and Manager
Edward R. Muller		of GenOn Americas Generation, LLC (Principal
Date: February 29, 2012		Executive Officer)


/s/ J. WILLIAM HOLDEN, III		Executive Vice President and Chief Financial Officer
J. William Holden III		and Manager of GenOn Americas Generation, LLC
Date: February 29, 2012		(Principal Financial Officer)


/s/ MICHAEL L. JINES		Executive Vice President, General Counsel,
Michael L. Jines		Secretary and Chief Compliance Officer and Manager
Date: February 29, 2012		of GenOn Americas Generation, LLC


/s/ THOMAS C. LIVENGOOD		Senior Vice President and Controller
Thomas C. Livengood		of GenOn Americas Generation, LLC
Date: February 29, 2012		(Principal Accounting Officer)

Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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: February 29, 2012	By:	/s/ EDWARD R. MULLER
		Edward R. Muller
		President and Chief Executive Officer
		(Principal Executive Officer)

GENON MID-ATLANTIC, LLC

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signatures		Title


/s/ EDWARD R. MULLER		President and Chief Executive Officer and Manager
Edward R. Muller		of GenOn Mid-Atlantic, LLC (Principal Executive
Date: February 29, 2012		Officer)


/s/ J. WILLIAM HOLDEN, III		Executive Vice President and Chief Financial Officer
J. William Holden III		and Manager of GenOn Mid-Atlantic, LLC
Date: February 29, 2012		(Principal Financial Officer)


/s/ MICHAEL L. JINES		Executive Vice President, General Counsel,
Michael L. Jines		Secretary and Chief Compliance Officer and Manager
Date: February 29, 2012		of GenOn Mid-Atlantic, LLC


/s/ THOMAS C. LIVENGOOD		Senior Vice President and Controller
Thomas C. Livengood		of GenOn Mid-Atlantic, LLC
Date: February 29, 2012		(Principal Accounting Officer)

Report of Independent Registered Public Accounting Firm	F-69
GenOn Americas Generation, LLC
Schedule I — Condensed Statements of Operations (Parent)	F-71
Schedule I — Condensed Balance Sheets (Parent)	F-72
Schedule I — Condensed Statements of Cash Flows (Parent)	F-73
Schedule I — Notes to Registrant’s Condensed Financial Statements (Parent)	F-74
Schedule II— Valuation and Qualifying Accounts	F-76

		Page

Glossary of Certain Defined Terms		ii

Cautionary Statement Regarding Forward-Looking Information		vi

PART I

Item 1.	Business	1
Item 1A.	Risk Factors	19
Item 1B.	Unresolved Staff Comments	29
Item 2.	Properties	30
Item 3.	Legal Proceedings	31
Item 4.	Mine Safety Disclosures	31

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	31
Item 6.	Selected Financial Data	31
Item 7.	Management’s Narrative Analysis of the Results of Operations and Financial Condition	32
	GenOn Americas Generation	32
	GenOn Mid-Atlantic	44
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	50
Item 8.	Financial Statements and Supplementary Data	50
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	50
Item 9A.	Controls and Procedures	50
Item 9B.	Other Information	51

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	52
Item 11.	Executive Compensation	52
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	52
Item 13.	Certain Relationships and Related Transactions and Director Independence	52
Item 14.	Principal Accountant Fees and Services	52
Item 15.	Exhibits and Financial Statement Schedules	53

Report of Independent Registered Public Accounting Firm	F-1
GenOn Americas Generation, LLC
Consolidated Statements of Operations	F-3
Consolidated Balance Sheets	F-4
Consolidated Statements of Member’s Equity	F-5
Consolidated Statements of Cash Flows	F-6
GenOn Mid-Atlantic, LLC
Consolidated Statements of Operations	F-7
Consolidated Balance Sheets	F-8
Consolidated Statements of Member’s Equity	F-9
Consolidated Statements of Cash Flows	F-10
Combined Notes to the Consolidated Financial Statements	F-11

Exhibits
GenOn Americas Generation, LLC	F-77
GenOn Mid-Atlantic, LLC	F-80

Exhibit No.		Exhibit Name

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