UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

 

 

Form 10-K

 

Commission file number: 1-16455

GenOn Energy, Inc.

(Exact Name of Registrant as Specified in Its Charter)

 

 

(832) 357-3000

(Registrant’s telephone number, including area code)

 

 

 

 

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

 

 

Securities registered pursuant to Section 12(g) of the Act: None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act.  Yes þ      No o

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ

 

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.  Yes þ     No o

 

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).  Yes þ     No o

 

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 registrant’s 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.  o

 

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. (Check one):

 

(Do not check if a smaller reporting company)

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  o Yes þ No

 

Aggregate market value of voting stock held by non-affiliates of the registrant was approximately $1,334,952,151 on June 30, 2010 (based on $3.79 per share, the closing price in the daily composite list for transactions on the New York Stock Exchange that day). Aggregate market value of voting stock held by non-affiliates of the registrant was approximately $2,918,449,213 on December 31, 2010 (based on $3.81 per share, the closing price in the daily composite list for transactions on the New York Stock Exchange that day).

 

As of February 18, 2011, there were 770,915,236 shares of the registrant’s Common Stock, $0.001 par value per share, outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the Registrant’s proxy statement for the 2011 Annual Meeting of Stockholders are incorporated by reference in Part III of this Form 10-K to the extent described herein.

 

 

TABLE OF CONTENTS

 

 

 

GLOSSARY OF CERTAIN DEFINED TERMS
(Continued)

 

 

 

GLOSSARY OF CERTAIN DEFINED TERMS
(Continued)

 

 

 

GLOSSARY OF CERTAIN DEFINED TERMS
(Continued)

 

 

 

GLOSSARY OF CERTAIN DEFINED TERMS
(Continued)

 

 

 

In addition to historical information, the information presented in this Form 10-K includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Exchange Act. These statements involve known and unknown risks and uncertainties and relate to our revenues, income, capital structure and other financial items, future events, our future financial performance or our projected business results and our view of economic and market conditions. In some cases, one can identify forward-looking statements by terminology such as “may,” “will,” “should,” “could,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “expect,” “intend,” “seek,” “plan,” “think,” “anticipate,” “estimate,” “predict,” “target,” “potential” or “continue” or the negative of these terms or other comparable terminology.

 

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

 

 

 

 

Many of these risks, uncertainties and assumptions are beyond our ability to control or predict. All forward-looking statements attributable to us or persons acting on our behalf 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.

 

Factors that Could Affect Future Performance

 

We undertake no obligation to update publicly or revise any forward-looking statements to reflect events or circumstances that may arise after the date of this report. Our filings and other important information are also available on our investor relations page at www.genon.com/investors.aspx.

 

In addition to the discussion of certain risks in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the accompanying notes to GenOn’s consolidated financial statements, other factors that could affect our future performance are set forth in Item 1A, “Risk Factors.”

 

Certain Terms

 

As used in this report, unless the context requires otherwise, “we,” “us,” “our” and “GenOn” refer to GenOn Energy, Inc. and its consolidated subsidiaries, after giving effect to the 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.

 

While RRI Energy was the legal acquirer, the Merger was accounted for as a reverse acquisition, and Mirant was deemed to have acquired RRI Energy for accounting purposes. As a consequence of the reverse acquisition accounting treatment, the historical financial statements and results of operations presented for periods prior to the Merger date are the historical statements of Mirant, except for stockholders’ equity which has been retroactively adjusted for the equivalent number of shares of the legal acquirer. The operations of the former RRI Energy businesses have been included in the financial statements from the date of the Merger. Specifically, the consolidated financial statements and financial and operational results of GenOn include the results of Mirant through December 2, 2010 and include the results of the combined entities from December 3, 2010, unless indicated otherwise.

 

Pursuant to the Plan for Mirant and certain of its subsidiaries, on January 3, 2006, Mirant emerged from bankruptcy and acquired substantially all of the assets of the old Mirant Corporation. The Plan provides that new Mirant (now named GenOn Energy Holdings) has no successor liability for any unassumed obligations of the old Mirant Corporation. The old corporation was then renamed and transferred to a trust, which is not affiliated with GenOn Energy Holdings. For further information about our corporate history, revenues, suppliers, business segments and Mirant’s bankruptcy, see notes 1, 14 and 16 to our consolidated financial statements and “Selected Financial Data” in Item 6 of this Form 10-K.

 

Overview

 

We provide energy, capacity, ancillary and other energy services to wholesale customers in competitive energy markets in the United States through ownership and operation of, and contracting for, power generation capacity. We are a wholesale generator with approximately 24,200 MW of net electric generating capacity in the PJM, MISO, Northeast and Southeast regions and California. We also operate integrated asset management and energy marketing organizations, including proprietary trading operations. Our customers are principally ISOs, RTOs and investor-owned utilities. Our generating portfolio is diversified across fossil fuel and technology types, operating characteristics and several regional power markets and serves customers primarily located near major metropolitan load centers.

 

At December 31, 2010, our generating capacity was 50% in PJM, 23% in CAISO, 10% in the Southeast, 7% in MISO and 10% in NYISO and ISO-NE. The net generating capacity of these facilities consisted of approximately 34% baseload, 46% intermediate and 20% peaking capacity. Our coal facilities generally dispatch as baseload, although some dispatch as intermediate capacity, and our gas, oil and dual fuel plants primarily dispatch as intermediate and/or peaking capacity.

 

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 cost savings targets.  We expect to achieve approximately $150 million in annual cost savings through reductions in corporate overhead and support costs. We expect cost savings to result from consolidations in several areas, including headquarters, IT systems and corporate functions such as accounting, human resources and finance. Starting in January 2012, we expect to achieve the full $150 million of annual cost savings. We have estimated the total merger-related costs at

approximately $215 million. These costs include $87 million of advisory and legal fees and $128 million of other merger-related costs, including costs to achieve the savings. These amounts include $25 million incurred by RRI Energy prior to the Merger. During 2010, the Company incurred $114 million. We expect to incur approximately $63 million, $10 million and $3 million during 2011, 2012 and 2013 and beyond, respectively. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this Form 10-K and note 3 to our consolidated financial statements.

 

Continued operating and commercial expertise.  We have substantial experience in the management, operation and optimization of a portfolio of diverse generating facilities. Drawing on the best practices of Mirant and RRI Energy, we intend to operate our generating facilities safely and 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 intend to 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 expect to continue to sell capacity either bilaterally or through periodic auction processes.

 

Investing capital prudently.  Our capital investment decisions are focused on achieving an appropriate return for our stockholders. Capital investments include participating in the development or acquisition of new facilities, the maintenance of our existing facilities for long-term availability and improved commercial availability, and investments in our existing facilities to improve their competitive position.

 

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.

 

Business Segments

 

We have five operating segments: Eastern PJM, Western PJM/MISO, California, Energy Marketing and Other Operations.

 

The Eastern PJM segment consists of eight generating facilities located in Maryland, New Jersey and Virginia. The Maryland and Virginia generating facilities are located near Washington, D.C.

 

The Western PJM/MISO segment consists of 23 generating facilities located in Illinois, Ohio and Pennsylvania.

 

The California segment consists of eight generating facilities and includes other business development efforts, including the Marsh Landing project.

 

The Energy Marketing segment consists of our proprietary trading, fuel oil management and natural gas transportation and storage activities.

 

The Other Operations segment consists of three generating facilities located in Massachusetts, one generating facility located in New York, three generating facilities located in Florida, one generating facility located in Mississippi and one generating facility located in Texas. For 2008, the Other Operations segment included the Lovett generating facility in New York, which was shut down on April 19, 2008 and demolished in 2009.

The table below summarizes selected financial information of our operations by business segment for 2010:

 

 

 

 

Eliminations for revenues and gross margin are primarily related to intercompany sales of emissions allowances. Eliminations for operating income/loss also include a $616 million impairment loss related to goodwill recorded at our GenOn Mid-Atlantic subsidiary on its standalone balance sheet. The goodwill impairment loss and related goodwill balance are eliminated upon consolidation at GenOn North America and are not reflected on the consolidated balance sheet of the Company. For selected financial information about our business segments, see note 16 to our consolidated financial statements.

 

Eastern PJM Segment

 

We own or lease eight generating facilities in the Eastern PJM segment with total net generating capacity of 6,336 MW. Our Eastern PJM segment had a combined 2010 net capacity factor of 33%. The following table presents the details of our Eastern PJM generating facilities:

 

 

 

 

We completed the installation of scrubbers at our Chalk Point, Dickerson and Morgantown coal-fired units in the fourth quarter of 2009. We previously 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. In addition, we installed selective non-catalytic reduction systems at the three Dickerson coal-fired units. These controls are capable of reducing emissions of SO₂, NO_x and mercury by approximately 98%, 90% and 80%, respectively, for three of our largest coal-fired units in Maryland.

 

We reviewed our Chalk Point, Dickerson, Morgantown and Potomac River generating facilities for impairment as a result of our annual assessment of the goodwill recorded at our GenOn Mid-Atlantic registrant on its standalone balance sheet, which is eliminated upon consolidation at GenOn North America. Upon completion of the assessment, we determined that none of the GenOn Mid-Atlantic generating facilities was impaired at October 31, 2010.

 

In December 2010, PJM published an updated load forecast, which depicted a decrease in the expected demand from prior projections because of lower economic growth expectations. As a result of the load forecast, our current expectation is that there will be a decrease in the clearing prices for future capacity auctions in certain years. The decrease in projected capacity revenue caused us to update our October 2010 impairment review of GenOn Mid-Atlantic’s long-lived assets. Upon completion of our assessment, which was based on the accounting guidance related to the impairment of long-lived assets, we determined that the Dickerson and Potomac River generating facilities were impaired at December 31, 2010, as the carrying value exceeded the updated December 2010 undiscounted cash flows. We recorded fourth quarter impairment losses of $523 million and $42 million on our 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 full impairment of the Potomac River generating facility, we recorded $32 million in operations and maintenance expense and corresponding liabilities associated with our commitment to reduce particulate emissions at our Potomac River generating facility as part of the agreement with the City of Alexandria, Virginia. The planned capital investment would not be recovered in future periods based on the current projected cash flows of the Potomac River generating facility. We also have $32 million included in funds on deposit and other noncurrent assets in the consolidated balance sheets, which represents the remaining balance placed in escrow as a result of the agreement with the City of Alexandria. See note 5(c) to our consolidated financial statements for further information related to our GenOn Mid-Atlantic impairment analyses.

 

Our generating facilities located in New Jersey may require further investment in environmental controls. See “Environmental Regulation” below for further information.

 

Western PJM/MISO Segment

 

We own or lease 23 generating facilities in the Western PJM/MISO segment with total net generating capacity of 7,483 MW. Our Western PJM/MISO segment had a combined 2010 net capacity factor of 36%. The following table presents the details of our Western PJM/MISO generating facilities:

 

 

 

 

We expect the Avon Lake, New Castle and Niles generating facilities to move from the MISO region to the PJM region in June 2011 as a result of the FERC’s approval of the transfer.

 

In 2009 and 2010, we installed scrubbers at the Keystone and Cheswick generating facilities to reduce the SO₂ emissions from these facilities. As a result, the number of SO₂ allowances we will need to purchase in the market to comply with current regulations is reduced. These scrubbers are capable of removing up to 98% of the SO₂ from the exhaust as well as reducing mercury emissions by up to 80%. The units had previously been retrofitted with SCRs to reduce NO_x emissions.

 

California Segment

 

We own eight generating facilities in California with total net generating capacity of 5,725 MW. Our California segment generating facilities had a combined 2010 net capacity factor of 2%. The following table presents the details of our California generating facilities:

 

 

 

In the third quarter of 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 is no longer needed for reliability, as determined by the CAISO. That settlement agreement became effective in November 2009. In December 2010, the CAISO provided GenOn Potrero with the requisite notice of termination of the RMR agreement. On January 19, 2011, at the request of GenOn Potrero, the FERC approved changes to GenOn Potrero’s RMR agreement to allow the CAISO to terminate the RMR agreement effective February 28, 2011. On February 28, 2011, the Potrero facility was shut down.

 

Our existing generating facilities in California depend almost entirely on payments they receive to operate in support of system and local reliability through the sale of resource adequacy capacity to load serving entities. The energy, capacity and ancillary services markets, as currently constituted, will not support the capital expenditures necessary to repower or reconstruct our facilities. In order to obtain the necessary capital support for repowering or reconstructing our facilities, we would need to obtain contracts with creditworthy buyers. Absent that, our existing generating facilities in California will be commercially viable only as long as they have contracts for their capacity.

 

Energy Marketing Segment

 

Our Energy Marketing segment includes our proprietary trading, fuel oil management and natural gas transportation and storage activities. This activity includes the purchase and sale of electricity, fuel and emissions allowances, sometimes through financial derivatives.

 

Using our fundamental understanding of the markets in which we operate, we support our commercial asset management activities as well as engage in proprietary trading when we identify opportunities. We engage in fuel oil management activities to hedge economically the fair value of our physical fuel oil inventories, optimize the approximately three million barrels of storage capacity that we own or lease, 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 our physical natural gas and 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 5% 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 and requires all incremental natural gas transportation and natural gas storage activities to be risk reducing. For 2010, our combined average daily VaR for proprietary trading and fuel oil management activities was $2 million.

 

Other Operations Segment

 

We own or lease four generating facilities in the Northeast region and five generating facilities in the Southeast region with total net generating capacity of 5,055 MW. Other Operations had a combined 2010 net capacity factor of 8%. Other Operations is comprised of our generating facilities located in Massachusetts,

New York, Florida, Mississippi and Texas. The following table presents the details of our Other Operations generating facilities:

 

 

 

 

During the second quarter of 2010, the NYISO issued its annual peak load and energy forecast in its Load and Capacity Data report (the Gold Book). The Gold Book reports projected electricity supply and demand for the New York control area for the next ten years. The most recent Gold Book projects a significant decrease in future electricity demand as a result of current economic conditions and the expected future effects of demand-side management programs in New York. The expected reduction in future demand as a result of demand-side management programs is being driven primarily by an energy efficiency program being instituted within the State of New York that will seek to achieve a 15% reduction from 2007 energy volumes by 2015. As a result of the projections in the Gold Book, we evaluated the Bowline generating facility for impairment in the second quarter of 2010. The sum of the probability weighted undiscounted cash flows for the Bowline generating facility exceeded the carrying value. As a result, we did not record an impairment loss for the Bowline generating facility during the second quarter of 2010.

 

GenOn Bowline has challenged its property tax assessment for the 2009 and 2010 tax years. Although the assessment for the 2010 tax year was reduced significantly from the assessment received in 2009, the assessment continues to exceed significantly the estimated fair value of the generating facility.

 

In the fourth quarter of 2010, we identified certain operational issues that reduced the available capacity of the Bowline generating facility. We are in the process of evaluating long-term solutions for the generating facility, but our current expectation is that the reduction in available capacity could extend through 2012. In the fourth quarter of 2010, we again evaluated the Bowline generating facility for impairment because of the expected extended reduction in available capacity together with the pending property tax litigation and the effect of supply and demand assumptions in the NYISO’s Gold Book. The sum of the probability weighted undiscounted cash flows for the Bowline generating facility exceeded the carrying value. As a result, we did not record an impairment loss for the Bowline generating facility during 2010. See note 5(c) to our

consolidated financial statements for further information related to our impairment analysis of the Bowline generating facility.

 

ISO-NE previously had determined that, at times, it was necessary for the Canal generating facility to operate to meet local reliability criteria for SEMA when it is not economic for the Canal generating facility to operate based upon prevailing market prices. When the Canal generating facility operates to meet local reliability criteria, we are compensated at the price we bid into the ISO-NE, pursuant to ISO-NE market rules, rather than at the market price. During 2009, NSTAR Electric Company completed planned upgrades to the SEMA transmission system. These upgrades have reduced the need for the Canal generating facility to operate and caused a reduction in energy gross margin compared to historical levels. The final phase of these transmission upgrades was completed in the third quarter of 2009 and as a result, the capacity factor for the Canal generating facility dropped as compared to 2008. With the completion of the transmission upgrades and because of the Canal generating facility’s high fuel costs relative to other generation in the northeast market, we expect that the future revenues of the Canal generating facility will be principally capacity revenue from the ISO-NE forward capacity market.

 

The Kendall generating facility, which is a cogeneration facility, has long-term agreements under which it sells steam.

 

Pursuant to a consent decree, we discontinued operation of units 4 and 5 at our Lovett generating facility in New York in May 2007 and April 2008, respectively. In addition, we discontinued operation of unit 3 at the Lovett generating facility in May 2007 because it was uneconomic to operate the unit. We completed the demolition of the Lovett generating facility in 2009.

 

Asset Management

 

We provide energy, capacity, ancillary and other energy services to wholesale customers in competitive energy markets in the United States, including ISOs and RTOs, power aggregators, retail providers, electric-cooperative utilities, other power generating companies and load serving entities. Our commercial operations consist primarily of dispatching electricity, hedging the generation and sale of electricity, 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).

 

Our strategy is to 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 Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this Form 10-K for our aggregate hedge levels based on expected generation for 2011 to 2015. In addition, see Item 1A, “Risk Factors—Risks Related to Economic and Financial Market Conditions—Greater regulation of energy contracts” for a discussion of 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.

 

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, MISO, 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. At January 31, 2011, total projected contracted capacity and PPA revenues for which prices have been set for 2011 through 2014 are $3.1 billion.

 

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.

 

Several of our California, Florida and Mississippi generating facilities typically operate under contracts for their capacity or energy. In California, GenOn Delta has entered into agreements with PG&E to provide electricity from our natural gas-fired units in service at Contra Costa and Pittsburg. With respect to Contra Costa units 6 and 7, GenOn Delta is providing 674 MW of capacity to PG&E for 2011 under a multi-year tolling agreement into which we entered in 2006. GenOn Delta entered into a new agreement with PG&E on September 2, 2009 for the 674 MW at Contra Costa units 6 and 7 for the period from November 2011 through April 2013. At the end of the agreement, and subject to any necessary regulatory approval, GenOn Delta has agreed to retire Contra Costa units 6 and 7, which began operations in 1964, in furtherance of state and federal policies to retire aging power plants that utilize once-through cooling technology. In addition, GenOn Delta entered into an agreement with PG&E on October 28, 2010 for 1,159 MW of capacity from Pittsburg units 5, 6 and 7 for three years commencing January 1, 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. On September 2, 2009, GenOn Marsh Landing entered into a ten-year PPA with PG&E for 760 MW of natural gas-fired peaking generation to be constructed adjacent to our Contra Costa generating facility near Antioch, California. Construction of the Marsh Landing generating facility is expected to be completed by mid-2013.

 

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 2013 and one that extends to 2020. See “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of this Form 10-K 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. To perform a portion of these functions, we lease natural gas transportation and storage capacity. We sell excess fuel supplies to third parties.

 

We receive coal at our generating facilities primarily by rail and truck. In addition, we can receive coal by barge at three of our plants: our Morgantown generating facility completed construction of a barge unloader in 2008 that enables us to receive coal from domestic and international sources; and our Cheswick and Elrama generating facilities also have barge unloading facilities, which are typically used to receive domestic coal. We have coal blending facilities at our Cheswick, Morgantown and Titus generating facilities that allow 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 and, despite occasional interruptions of planned deliveries, to date we have managed to avoid any significant detrimental effects on our operations. 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. Interruptions to planned or contracted deliveries can result from a variety of factors,

including operational issues of coal suppliers, lack of, or constraints in, coal transportation (including rail system and river system disruptions) and adverse weather conditions.

 

Emissions

 

Our commercial operations manage the acquisition and use of emissions allowances for our generating facilities. Our generating facilities in Maryland, Massachusetts, New Jersey and New York are subject to the RGGI, a multi-state cap-and-trade program to reduce CO₂ emissions from units of 25 MW or greater. The RGGI became effective on January 1, 2009. To comply, we are required to purchase allowances, either through periodic auctions or open market transactions, to offset our CO₂ emissions. In 2010 and 2009, we recognized approximately $34 million and $45 million, respectively, in cost of fuel, electricity and other products as a result of our compliance with the RGGI.

 

In May 2010, the Montgomery County Council imposed a levy on major emitters of CO₂ in Montgomery County, Maryland which we estimate will impose on the Dickerson generating facility of GenOn Mid-Atlantic an additional $10 million to $15 million per year in levies owed to Montgomery County. During 2010, we recognized $8 million in levies in operations and maintenance expense. See note 18 to our consolidated financial statements for further discussion of the action filed against Montgomery County in the United States District Court for the District of Maryland by GenOn Mid-Atlantic.

 

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 (although we do use ponds to dewater ash at some facilities). 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 constructing 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 commenced construction of the ash beneficiation facility in February 2011 and expect to complete it in 2012. Our disposal plan for gypsum includes disposing of it in approved landfills and selling it to third parties for use in the production of drywall. Currently, we expect to spend approximately $130 million over the next five years for ash landfill expansions, closures and for building an ash beneficiation facility.

 

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.

 

Competitive Environment

 

The power generating industry is capital intensive and highly competitive. 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 45%, 24%, 20% and 6%, respectively, of the electricity produced in the United States. Other energy sources account for the remaining 5% of electricity produced.

 

Wholesale power generation 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 competitive advantages include the following:

 

 

 

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 as a way to encourage construction of additional generation when market conditions warrant. Over the last several years, very little new generation has been constructed as a result of the economic downturn in recent years 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. Also, the costs to construct new generating facilities have been rising, and there is substantial environmental opposition to building either coal-fired or nuclear plants.

 

In some markets, state regulators have proposed initiatives to provide long-term contracts for new generating capacity. In December 2010, the Maryland Public Service Commission sought comments on a possible request for proposals for new generating facilities. The draft request for proposals would require any such new generation to bid into the capacity markets in a manner that would ensure clearing in the market. The draft request provides for project submittals on July 29, 2011. We filed comments on the draft request for proposals on January 28, 2011, noting there is no need for additional capacity at this time. If the request for proposals is issued as currently drafted, it could have a negative effect on capacity prices in PJM in future years.

 

On January 28, 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. If the New Jersey agreement for new capacity is implemented as required by the statute, it could have a negative effect on capacity prices in PJM in future years. On February 1, 2011, a group of which we are a member initiated a proceeding at the FERC seeking changes in the PJM tariff to prevent interference with the capacity markets from efforts such as the New Jersey legislation and the Maryland request for proposals. On February 9, 2011, we joined a group of companies that filed suit in the U.S. District Court for New Jersey asking the court to declare the New Jersey legislation unconstitutional.

 

In addition, as a result of initiatives at both the federal and state level, new construction of renewable resources, including solar and wind, has occurred or is planned.

 

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 additional generating capacity. To the extent that these upgrades are completed, prices for electricity and capacity could be lower in some of our markets than they might otherwise be.

 

The prices for power and natural gas remain 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 add economic hedges, including to maintain projected levels of cash flows from operations for

future periods to help support continued compliance with the covenants in our debt and lease agreements. We have implemented seasonal operating models at some of our facilities to address the effect of depressed power and commodity prices on the margins earned at these facilities.

 

Concern over climate change and air emissions have 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 “Environmental Regulation” later in the section for further discussion.

 

Seasonality

 

For information on the effect of seasonality on our business, see “Risk Factors” in Item 1A of this Form 10-K and note 17 to our consolidated financial statements.

 

Regulatory Environment

 

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, although our Potrero station sold its output under a cost-based RMR agreement through February 2011 for which separate rate authorization was granted by the FERC. The FERC could revoke or limit our market-based rate authority if it determined that we possess insufficiently mitigated market power in a regional electricity market. Under the Natural Gas Act, our subsidiaries that sell natural gas for resale are 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 subsidiaries with blanket certificate authority adhere to general rules against market manipulation as well as 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 or 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.

 

In 2006, the FERC certified the NERC as the national energy reliability organization. The NERC is now responsible for the development and enforcement of mandatory reliability 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. The 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 electricity at wholesale must comply with the reliability standards of the regional reliability council for the NERC region in which its sales occur.

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, Illinois, Maryland, Massachusetts, New Jersey, New York, Ohio, Pennsylvania and Virginia have joined the applicable ISO and RTO.

 

Our subsidiaries owning generating facilities have made such filings, and received such orders, as are necessary to obtain exempt wholesale generator status under the PUHCA 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 or reporting requirements that PUHCA imposes on “holding companies.”

 

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.

 

We hedge economically a substantial portion of our Eastern PJM coal-fired baseload generation and certain of our other generation. A significant portion of such 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. The Dodd-Frank Act, which was enacted in July 2010 in response to the global financial crisis, increases the regulation of transactions involving OTC derivative financial instruments. The statute provides that standardized swap transactions between dealers and large market participants will have to be cleared and traded on an exchange or electronic platform. Although the provisions and legislative history of the Dodd-Frank Act provide strong evidence that market participants, such as GenOn, which utilize OTC derivative financial instruments to hedge economically commercial risks are not to be subject to these clearing and exchange-trading requirements, it is uncertain what the final implementing regulations to be issued by the CFTC and SEC will provide. The effect of the Dodd-Frank Act on our business depends in large measure on pending CFTC and SEC rulemaking proceedings and, in particular, the final definitions for the key terms “Swap Dealer” and “Major Swap Participant” in the Dodd-Frank Act. The CFTC and SEC issued a proposed rulemaking to set final definitions for the terms “Swap Dealer” and “Major Swap Participant,” among others. 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. As proposed, the Swap Dealer definition in particular is ambiguous, subjective and could be broad enough to encompass some energy companies. Such regulations could materially affect our ability to hedge economically our generation by reducing liquidity in the energy and commodity markets and, if we were required to clear such transactions on exchanges or meet other requirements, by significantly increasing the collateral costs associated with such activities. See Item 1A, “Risk Factors—Risks Related to Economic and Financial Market Conditions—Greater regulation of energy contracts” for additional information.

 

Under the Dodd-Frank Act, the CFTC now has the authority to set position limits not only on contracts listed by designated contract markets but also for swap contracts that perform or affect a significant price discovery function. As a result of the significant amendments to the Commodity Exchange Act by the Dodd-Frank Act, the CFTC withdrew, in August 2010, the January 2010 notice of proposed rulemaking in which it proposed to adopt all-months-combined, single (non-spot) month and spot-month position limits for exchange-listed natural gas, crude oil, heating oil and gasoline futures and options contracts. The CFTC plans to issue a

notice of rulemaking proposing position limits for regulated exempt commodity contracts, including energy commodity contracts, in early 2011.

 

In addition to the upcoming position limit rulemakings under the Dodd-Frank Act, the CFTC has designated and put into effect position limits for certain electricity and natural gas contracts designated as significant price discovery contracts, including contracts based on CAISO and PJM West Hub locational marginal pricing that we trade on the Intercontinental Exchange, Inc. Designations put into effect to date have not had a material effect on our business. We continue to monitor the rulemaking proceeding on the remaining contracts.

 

PJM Region.  Our Eastern and Western 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 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 generating capacity. Our generating facilities located in the Eastern and Western 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 to meet the region’s demand requirements. PJM has conducted seven RPM capacity auctions and we began receiving payments in June 2007 as a result of the first auction. Certain market participants have challenged the results of the RPM auctions that set capacity payments under the RPM provisions of PJM’s tariff for the twelve month periods beginning June 1, 2008, June 1, 2009 and June 1, 2010. The FERC rejected those challenges and its orders were affirmed by the D.C. Circuit. See “Complaint Challenging Capacity Rates Under the RPM Provisions of PJM’s Tariff” in note 18 to our consolidated financial statements for a discussion of the challenges.

 

Since 2008, annual auctions have been conducted to procure capacity three years prior to each delivery period. The first annual auction took place in May 2008, for the provision of capacity from June 1, 2011 to May 31, 2012. 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 “Competitive Environment” for our involvement at the FERC.

 

MISO.  Our MISO generating facilities sell electricity into the markets operated by MISO. MISO manages the transmission system and provides open access to its transmission system and markets to all market participants on an equal basis. MISO operates physical and financial energy markets using a locational marginal pricing model, which calculates a price for every generator and load point within MISO similar to the model utilized by PJM. MISO operates day-ahead and real-time markets into which generators can offer to provide energy. MISO does not administer a centralized capacity market. MISO implemented the Ancillary Services Market (Regulation and Operating Reserves) on January 6, 2009 and implemented an enforceable Planning Reserve Margin for each planning year effective June 1, 2009. A feature of the Ancillary Services Market is the addition of scarcity pricing that, during supply shortages, can raise the combined price of energy and ancillary services significantly higher than the previous cap of $1,000/MWh.

 

California.  Our California generating facilities are located inside the CAISO’s control area. On April 1, 2009, the CAISO implemented its Market Redesign and Technology Update (MRTU). MRTU’s key components include locational marginal pricing of energy similar to the RTO/ISO markets in the east, a day-ahead market in addition to the existing real-time market, a more effective congestion management system and an increase in the existing bid caps. The CAISO also schedules transmission transactions and arranges for necessary ancillary services. Most sales in California are pursuant to bilateral contracts, but a significant

percentage of electrical energy is sold in the day-ahead and real-time market. The CAISO does not operate a wholesale capacity market.

 

Other Operations.  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.

 

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 similar to the model used in PJM, MISO and NYISO.

 

On March 6, 2006, a settlement proposal was filed with the FERC among ISO-NE and multiple market participants for the FCM under which annual capacity auctions would be conducted for supply three years in advance of provision. The settlement provided for a four-year transition period during which capacity suppliers receive a set price for their capacity commencing on December 1, 2006, with price escalators through May 31, 2010. Beginning December 1, 2006, our generating facilities began receiving capacity revenues under the FCM transition period. On June 1, 2010, our generating facilities began receiving capacity revenues based upon the auction results.

 

Our Choctaw, Sabine, Indian River and Osceola generating facilities located in the Southeast region do not operate in a market that is operated by an RTO or ISO. Opportunities to negotiate bilateral contracts and long-term transactions with investor owned utilities, municipalities and cooperatives exist within this region. In addition to entering into bilateral transactions, there is a limited opportunity to sell into the short-term market. Access to the transmission system in this region to which the generating facility is interconnected is governed by the FERC approved terms and conditions of the applicable transmission provider’s open access transmission tariff. In the Entergy sub-region, which the Choctaw facility can access, Southwest Power Pool has been designated as the Independent Coordinator of Transmission. In this capacity, the Independent Coordinator of Transmission provides oversight of the Entergy transmission system.

 

Environmental Regulation

 

Our business is subject to extensive environmental regulation by federal, state and local authorities. We must comply with applicable laws and regulations, and obtain and comply with the terms of government issued permits. These requirements relate to a broad range of our activities, including the discharge of materials into the air, water and soil; the proper handling of solid, hazardous and toxic materials and waste; noise and safety, and health standards applicable to the workplace. Some of these requirements are under revision or in dispute, and some new requirements are pending or under consideration. Our costs of complying with environmental laws and permits are substantial, including significant environmental capital expenditures. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Expenditures and Capital Resources” for additional information.

 

Air Emissions Regulations

 

The Clean Air Act and similar state laws impose significant environmental requirements on our generating facilities. The Clean Air Act mandates 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, NO_x 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. Such costs could be material. Significant air regulatory programs to which we are subject are described below.

 

Clean Air Interstate Rule.  In 2005, the EPA promulgated the CAIR, which established in the eastern United States SO₂ and NO_x cap-and-trade programs applicable directly to states and indirectly to generating facilities. The NO_x cap-and-trade program has two components, an annual program and an Ozone Season program. The CAIR SO₂ cap-and-trade program builds off the existing acid rain cap-and-trade program but requires generating facilities to surrender twice as many allowances to cover emissions from 2010 through 2014 and approximately three times as many allowances starting in 2015. Florida, Illinois, Maryland, Mississippi, New Jersey, New York, Ohio, Pennsylvania, Texas and Virginia are subject to the CAIR’s SO₂ trading program and both its NO_x trading programs. Massachusetts is subject only to the CAIR’s Ozone Season NO_x trading program. These cap-and-trade programs were to be implemented in two phases, with the first phase going into effect in 2009 for NO_x and 2010 for SO₂ and more stringent caps going into effect in 2015. Various parties challenged the EPA’s adoption of the CAIR, and on July 11, 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 on December 23, 2008, the D.C. Circuit issued a second opinion in which it granted rehearing only to the extent that it remanded the case to the EPA without vacating the CAIR. Accordingly, the CAIR will remain effective until it is replaced by a rule consistent with the D.C. Circuit’s opinions. The states in which we operate that are subject to CAIR (i.e., Florida, Illinois, Maryland, Massachusetts, Mississippi, New Jersey, New York, Ohio, Pennsylvania, Texas and Virginia) have promulgated regulations implementing the federal CAIR.

 

The EPA has stated that it expects to finalize the regulations to replace the CAIR in 2011, and on August 2, 2010, the EPA proposed a rule (the Transport Rule) to replace the CAIR. The EPA has sought comment on the proposed Transport Rule as well as several alternatives. If finalized, the CAIR replacement proposal and each of the alternatives would impose more stringent emission reductions than were required under the CAIR. The EPA’s proposed replacement rule would establish an emissions budget for each of thirty-one eastern and midwestern states and the District of Columbia, and would allow only limited interstate trading. For SO₂, generating facilities in a region comprised of Georgia, Illinois, Indiana, Iowa, Kentucky, Michigan, Missouri, New York, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and Wisconsin would be subject to a more stringent cap on SO₂ emissions than the other states subject to the rule, and would not be allowed to use emissions allowances from sources in a separate region comprised of Alabama, Connecticut, Delaware, the District of Columbia, Florida, Kansas, Louisiana, Maryland, Massachusetts, Minnesota, Nebraska, New Jersey and South Carolina. For both SO₂ and NO_x, interstate trading of emissions allowances would be allowed only to the extent that the total number of emissions allowances used within a particular state did not exceed the state’s budgeted allowances plus a “variability limit” intended to account for the variability of emissions because of changes in demand for electricity, timing of maintenance activities and unit outages. If total emissions allowances used within a state in a year exceed the annual budget plus the variability limit, then owners of generating facilities in that state that are deemed responsible for the state’s exceedance would be required to surrender additional allowances. The two alternatives on which the EPA sought comment would further restrict trading. Under the first alternative, only intrastate trading of allowances would be allowed. The second alternative would establish an emissions limit for each generating facility, with some averaging allowed. In January 2011, the EPA also sought comment on two additional methods of allocating allowances. Finally, the EPA has also stated that it may issue a subsequent, more stringent rule if it concludes that recent or planned revisions to the particulate matter and ozone NAAQS make

necessary more stringent limits on SO₂ and NO_x emissions from electric generating facilities. We continue to monitor developments related to the EPA’s proposed options to replace the existing CAIR.

 

The effect on our business of these pending regulations and whether we elect to install additional controls is uncertain and depends on the content and timing of the regulations, the expected effect of the regulations on wholesale power prices and allowance prices, as well as the cost of controls, profitability of our generating facilities, market conditions at the time and the likelihood of CO₂ regulation. We may choose to retire certain of our units rather than install additional controls.

 

The costs associated with more stringent environmental air quality requirements may result in coal-fired generating facilities, including some of ours, being retired. Although conditions may change, under current and forecasted market conditions, installations of additional scrubbers would not be economic at most of our unscrubbed coal-fired facilities. Any such retirements could contribute to improving supply and demand fundamentals for the remaining fleet. Any resulting increased demand for gas could increase the spread between gas and coal prices, which would also benefit the remaining coal-fired generating facilities.

 

Maryland Healthy Air Act.  The Maryland Healthy Air Act was enacted in April 2006 and requires reductions in SO₂, NO_x 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 NO_x 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.

 

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. These controls are capable of reducing emissions of SO₂, NO_x and mercury by approximately 98%, 90% and 80%, respectively, for three of our largest 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 had planned outages to complete the installation of the scrubbers. During those outages, we also performed significant maintenance activities. We expect to invest $1.674 billion in capital expenditures to comply with the requirements for SO₂, NO_x and mercury emissions under the Maryland Healthy Air Act. At December 31, 2010, we had invested $1.519 billion of the $1.674 billion. In July 2007, our subsidiaries GenOn Mid-Atlantic and GenOn Chalk Point entered into an agreement with Stone & Webster, Inc. 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 18 to our consolidated financial statements under “Scrubber Contract Litigation” for further discussion.

 

New Jersey.  In April 2009, the New Jersey Department of Environmental Protection finalized a regulation requiring a two-phase reduction in NO_X emissions from combustion turbines in New Jersey. Phase I requires reductions during high electricity demand days and runs from May 2009 through 2014. Under our compliance plan, we operate enhanced NO_x controls at our Shawville, Pennsylvania generating facility (upwind from New Jersey) on high energy demand days. Phase II requires the installation of emission controls on all but one of our New Jersey generating facilities (Gilbert, Glen Gardner, Sayreville and Werner) by May 1, 2015. The New Jersey Department of Environmental Protection is evaluating proposed changes to its high electricity demand days regulations and may defer for two years, in part or in whole, requirements for reduction in NO_x emissions from combustion turbines. If we elect to install these controls, we could incur capital expenditures of up to approximately $190 million primarily during 2014 to 2017 (assuming the two-year deferral described above). Our initial Phase II control plan was filed with the state of New Jersey and our decision on investments should occur by 2012.

HAPs Regulations.  In 2005, the EPA issued the CAMR, which would have limited total annual mercury emissions from coal-fired power plants across the United States through a two-phased cap-and-trade program. In February 2008, the D.C. Circuit vacated the CAMR and the EPA’s decision not to regulate coal- and oil-fired electric utility steam generating units under section 112 of the Clean Air Act, which requires the EPA to develop MACT standards for controlling emissions of all HAPs, including mercury. The EPA and a group representing electricity generators sought review of the D.C. Circuit’s decision by the United States Supreme Court. In February 2009, the EPA filed to withdraw its petition for review, stating that it intends to promulgate alternative regulations for electricity generators under section 112 of the Clean Air Act, and the United States Supreme Court subsequently denied the petition for review. As a result of the D.C. Circuit decision, coal-fired and oil-fired generating facilities are now subject to regulation under the section of the Clean Air Act that generally requires the EPA to develop MACT standards to control HAPs, including mercury, from each covered facility. Although the EPA has announced that it will develop MACT standards for mercury and other HAPs, it has not yet promulgated such standards. The MACT standards may require us to install and operate additional emissions control equipment at some of our facilities, the cost of which may be material. The EPA has collected emissions data, which will be used to develop such standards. Our Maryland coal-fired units already are subject to mercury limits under the Maryland Healthy Air Act, as described above. Many of our coal-fired units will emit less mercury as a result of the SO₂ and NO_x controls that have been installed. In the interim, a number of states, including Pennsylvania, pursued mercury regulations. In December 2009, the Pennsylvania Supreme Court upheld a lower court’s determination that the proposed Pennsylvania mercury rule was unlawful and unenforceable.

 

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 Avon Lake, Chalk Point, Cheswick, Conemaugh, Dickerson, Elrama, Keystone, Morgantown, New Castle, Niles, Portland, Potomac River, Shawville and Titus 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.

 

Regulation of Greenhouse Gases, including the RGGI.  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. One such effort is the RGGI, a multi-state initiative in the Eastern PJM and Northeast outlining a cap-and-trade program to reduce CO₂ emissions from electric generating units with capacity of 25 MW or greater. The RGGI program calls for signatory states, which include Maryland, Massachusetts, New Jersey and New York, to stabilize CO₂ emissions to an established baseline from 2009 through 2014, followed by a 2.5% reduction each year from 2015 through 2018. Each of these four states has 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.

 

During 2010, we produced approximately 17.3 million tons of CO₂ at our Maryland, Massachusetts, New Jersey and New York generating facilities for a total cost of $34 million under the RGGI (including all former Mirant generating facilities for 2010 and all former RRI Energy generating facilities for December 2010). In

2011, we expect to produce approximately 15.6 million tons of CO₂ at our Maryland, Massachusetts, New Jersey and New York 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.

 

The tenth auction of allowances by the RGGI states was held on December 1, 2010. The clearing price for the approximately 24.8 million allowances sold in the auction allocated for use beginning in the first control period (2009-2011) was $1.86 per ton. The clearing price for the approximately 1.2 million allowances sold in the auction allocated for use beginning in the second control period (2012-2014) was $1.86 per ton. The allowances sold in this auction may be used for compliance in any of the RGGI states. Further auctions will occur quarterly, with the next auction scheduled for March 2011.

 

In California, emissions of greenhouse gases are governed by California’s Global Warming Solutions Act (AB 32), which requires that statewide greenhouse gas emissions be reduced to 1990 levels by 2020. In December 2008, the CARB approved a Scoping Plan for implementing AB 32. The Scoping Plan requires that the CARB adopt a cap-and-trade regulation by January 2011 and that the cap and trade program begin in 2012. The CARB’s schedule for developing regulations to implement AB 32 is being coordinated with the schedule of the WCI for development of a regional cap-and-trade program for greenhouse gas emissions. Through the WCI, California is working with other western states and Canadian provinces to coordinate and implement a regional cap-and-trade program. In October 2010, the CARB released its proposed cap-and-trade regulation for public comment, which the CARB approved in December 2010. Our California generating facilities will be required to comply beginning in 2012. 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.

 

In July 2008, the Pennsylvania Climate Change Act was adopted. This legislation requires development of reports of the effects of climate change in Pennsylvania and potential economic opportunities resulting from mitigation strategies. It requires development of an annual state-level greenhouse gas emissions inventory and baseline, a voluntary registry, and establishment of cost-effective state-level strategies for reducing or offsetting greenhouse gases. The Climate Change Advisory Committee established by the Act published a Climate Change Action Plan in December 2009. The plan includes numerous recommendations to reduce 2020 greenhouse gas emissions in the state by 30 percent below year 2000 levels. Recommendations affecting fossil power generation are carbon capture and sequestration at selected coal-fired units and minimum efficiency improvements. The plans also recommend greenhouse gas performance standards for new power plants.

 

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 Change Act, the MAEEA is to establish statewide greenhouse gas emissions limits effective beginning in 2020 that will reduce such emissions from the 1990 levels by a range of 10% to 25% beginning in 2020, with the reduction increasing to 80% below 1990 levels 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 we operate our Massachusetts generating facilities and the costs of operating those facilities. On December 29, 2010, the MAEEA established a limit for 2020 that is 25% less than the 1990 level.

 

In April 2009, the Maryland General Assembly passed the Maryland Act, which became effective in October 2009. The Maryland Act requires a reduction in greenhouse gas emissions in Maryland by 25% from 2006 levels by 2020. However, this provision of the Maryland Act is only in effect through 2016 unless a

subsequent statutory enactment extends its effective period. The Maryland Act requires the MDE to develop a proposed implementation plan to achieve these reductions by the end of 2011 and to adopt a final plan by the end of 2012.

 

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 promulgated a rule that requires owners of facilities in many sectors of the economy, including power generation, to report annually to the EPA the quantity and source of greenhouse gas emissions released from those facilities. In addition to this reporting requirement, the EPA has promulgated several rules that address greenhouse gas emissions. In December 2009, under a portion of the Clean Air Act that regulates vehicles, the EPA determined that elevated concentrations of greenhouse gases in the atmosphere endanger the public’s health and welfare through their contribution to climate change (Endangerment Finding). In April 2010, the EPA finalized a rule to regulate greenhouse gases from vehicles beginning in model year 2012. In April 2010, the EPA also issued its “Reconsideration of Interpretation of Regulations that Determine Pollutants Covered by Clean Air Act Permitting Programs,” 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 will require such sources to use “best available control technology” to limit their greenhouse gases. We expect various parties to seek judicial review of these regulations and that the legal challenges to these regulations will not be resolved for several years. 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 expects to propose regulations by July 2011 and to finalize such regulations by May 2012.

 

In addition to the state and regional regulatory matters described above, various bills have been proposed in Congress to govern CO₂ emissions from generating facilities. Current proposals include 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 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. It is possible that Congress will take action to regulate greenhouse gas emissions within the next several years. 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 coal-fired generating facility retirements. During 2010, we produced approximately 20.7 million tons of CO₂ at our generating facilities (including all former Mirant generating facilities for 2010 and all former RRI Energy generating facilities for December 3 to December 31, 2010). Our former RRI Energy generating facilities produced approximately 20.4 million tons of CO₂ for January through December 2, 2010. We expect to produce approximately 40.3 million total tons of CO₂ at our generating facilities in 2011.

 

Water Regulations

 

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). A 2007 decision by the United States Court of Appeals for the Second Circuit (the Second Circuit) in Riverkeeper Inc. et al. v. EPA, in which the court remanded to the EPA for reconsideration numerous provisions of the EPA’s section 316(b) regulations for existing power plants, has created substantial uncertainty about exactly what technologies or other measures will be needed to satisfy section 316(b) requirements in the future and when any new requirements will be imposed. Following that ruling by the Second Circuit, the EPA in 2007 suspended its 316(b) regulations for existing power plants. Various parties sought review of the Second Circuit’s decision by the United States Supreme Court, and it granted those requests with respect to whether the EPA could permissibly weigh costs versus benefits in determining what requirements to impose. On April 1, 2009, the Supreme Court reversed the Second Circuit, ruling that the EPA had permissibly relied on cost-benefit analysis in setting standards for cooling water intake structures for existing power plants and authorizing site-specific variances. The Supreme Court’s ruling did not alter other aspects of the Second Circuit’s decision. Significant uncertainty remains regarding the effect of the Supreme Court’s decision on the EPA’s 316(b) regulations for existing power plants and 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.

 

At our Shawville, Pennsylvania facility, we could be required to install a cooling tower by late 2013 at one or more of its units in order to comply with our permit. If we decide to install one or more cooling towers, we could invest approximately $160 million, primarily during 2012 to 2014. Under current and forecasted market conditions, such capital expenditures may not be justified. We are continuing to evaluate alternatives and appealing the permit. See discussion below under “Shawville NPDES Permit Appeal.”

 

Once-Through Cooling.  In October 2010, the California State Water Resources Control Board’s (State Water Board’s) Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling (Once-Through Cooling Policy) became effective. Compliance options for our 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 our Pittsburg and Contra Costa generating facilities is December 31, 2017; and for our Mandalay and Ormond Beach generating facilities the date is December 31, 2020. We will shut down the Contra Costa generating facility in April 2013, subject to regulatory approval. We are analyzing compliance options for the remaining affected generating units, and for certain of our California generating facilities the Once-Through Cooling Policy could have a material adverse effect on how we operate those facilities and the costs of operating those facilities. In October 2010, we and several other companies jointly filed a lawsuit in California superior court challenging the State Water Board’s issuance of the Once-Through Cooling Policy on various procedural and substantive grounds. The lawsuit seeks a writ directing the State Water Board to vacate and set aside approval of the Once-Through Cooling Policy.

 

Endangered Species Acts.  GenOn Delta’s use of water from the Sacramento-San Joaquin Delta at its Contra Costa and Pittsburg generating facilities potentially affects certain fish species protected under the federal Endangered Species Act and the California Endangered Species Act. GenOn Delta therefore must maintain authorization under both statutes to engage in operations that could result in a take of (i.e., cause harm to) fish of the protected species. In January and February 2006, GenOn Delta received correspondence from the United States Fish and Wildlife Service and the U.S. Army Corps of Engineers expressing the view that the federal Endangered Species Act take authorization for the Contra Costa and Pittsburg generating facilities was no longer in effect as a result of changed circumstances. GenOn Delta disagreed with the agencies’ characterization of its take authorization as no longer being in effect. In October 2007, GenOn Delta received correspondence from the United States Fish and Wildlife Service, the National Marine Fisheries Service and the Army Corps of Engineers clarifying that GenOn Delta continued to be authorized to take four species of fish protected under the federal Endangered Species Act. The agencies have initiated a process that will review the environmental effects of GenOn Delta’s water usage, including effects on the protected species of fish. That process could lead to changes in the manner in which GenOn Delta can use river water for the

operation of the Contra Costa and Pittsburg generating facilities. As discussed further in note 5(c) to our consolidated financial statements, we plan to shut down the Contra Costa generating facility in April 2013.

 

By letter dated September 27, 2007, the Coalition for a Sustainable Delta, four water districts, and an individual (the Delta Noticing Parties) provided notice to us of their intent to file suit alleging that GenOn Delta has violated, and continues to violate, the federal Endangered Species Act through the operation of its Contra Costa and Pittsburg generating facilities. The Delta Noticing Parties contend that the facilities use of water drawn from the Sacramento-San Joaquin Delta for cooling purposes results in harm to four species of fish listed as endangered species. The Delta Noticing Parties assert that GenOn Delta’s authorizations to take (i.e., cause harm to) those species, a biological opinion and incidental take statement issued by the National Marine Fisheries Service on October 17, 2002, for three of the fish species and a biological opinion and incidental take statement issued by the United States Fish and Wildlife Service on November 4, 2002, for the fourth fish species, have been violated by GenOn Delta and no longer apply to permit the effects on the four fish species caused by the operation of the Contra Costa and Pittsburg generating facilities. Following receipt of these letters, GenOn Delta received in October 2007 the correspondence noted above from the United States Fish and Wildlife Service, the National Marine Fisheries Service and the United States Army Corps of Engineers (the Corps) clarifying GenOn Delta’s continuing right to take the four species of fish. In a subsequent letter, the Coalition for a Sustainable Delta also alleged violations of the National Environmental Policy Act and the California Endangered Species Act associated with the operation of GenOn Delta’s generating facilities. On May 14, 2009, the Coalition for a Sustainable Delta, Kern County Water Agency and an individual sent a new notice of intent to sue to the Corps alleging that the Corps had violated the federal Endangered Species Act by issuing permits related to the operation of GenOn Delta’s Contra Costa and Pittsburg generating facilities without ensuring that conservation measures would be implemented to minimize and mitigate the harm to the four endangered fish species and their habitat allegedly resulting from such operation. GenOn Delta disputes the allegations made by the Delta Noticing Parties and those made in the May 14, 2009 notice.

 

On February 11, 2010, GenOn Delta entered into a settlement agreement with the Delta Noticing Parties, the parties to the May 14, 2009 notice of intent to sue, and the Corps. The settlement agreement provides for the Delta Noticing Parties and the parties to the May 14, 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 GenOn Delta to seek approval from the Corps, the United States Fish and Wildlife Service, and the National Marine Fisheries Service to amend its plan then in effect for monitoring entrainment and impingement of aquatic species caused by the operation of its generating facilities to increase monitoring during periods the facilities are operating, and those approvals have been obtained. The settlement agreement requires the Corps 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 GenOn Delta’s water usage in a timely manner and allows the Delta Noticing Parties and the parties to the May 14, 2009 notice of intent to sue to issue new notices of intent to sue if such consultations are not completed by October 31, 2011.

 

In November 2009, GenOn Delta signed a second amendment to a Memorandum of Agreement with the California Department of Fish and Game. The amendment requires GenOn Delta to prepare a planning and feasibility study for potential habitat restoration projects and extends by 16 months to March 1, 2011, the deadline for submitting an application for a new permit authorizing GenOn Delta to take the protected fish species affected by the operation of its facilities. The amendment extends GenOn Delta’s existing authorization for take of fish species protected under the California Endangered Species Act until the California Department of Fish and Game completes its consideration of the application for the new permit.

 

Potrero National Pollution Discharge Elimination System Permit.  On June 8, 2006, Bayview-Hunters Point Community Advocates and Communities for a Better Environment filed a petition challenging the issuance of the NPDES permit for our Potrero generating facility. On February 8, 2007, Bayview-Hunters Point Community Advocates and Communities for a Better Environment filed another petition with a request to amend their initial petition. On March 21, 2007, the California State Water Resources Control Board notified the parties that petitioners requested that as of March 19, 2007, the two petitions be moved from active status to abeyance. Those petitions currently remain in abeyance. Additionally, on June 15, 2007,

Bayview-Hunters Point Community Advocates and Communities for a Better Environment and San Francisco Baykeeper filed a third petition requesting that the NPDES permits for Potrero and GenOn Delta’s Pittsburg generating facility be reopened. The State Water Resources Control Board denied that petition on November 27, 2007. As discussed further in notes 5 and 19 to our consolidated financial statements, the CAISO has determined that the Potrero generating facility is no longer needed for reliability and, accordingly, we shut it down on February 28, 2011.

 

Kendall NPDES and Surface Water Discharge Permit.  On September 26, 2006, the EPA issued to GenOn Kendall an NPDES renewal permit for the Kendall cogeneration facility. The same permit was concurrently 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. GenOn Kendall 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. On March 6, 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 to install a mechanism to sweep organisms away from the intake structure through an induced water flow. On May 1, 2008, GenOn Kendall submitted comments on the draft permit modification objecting to the new requirements. On December 19, 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 on February 2, 2009, GenOn Kendall filed an appeal of those modifications.

 

In October 2010, GenOn Kendall 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 among GenOn Kendall, the EPA and MADEP as part of a settlement of the permit renewal proceedings pending before EPA and MADEP. The settlement contemplates that an additional steam pipeline will be installed across the Charles River under the Longfellow Bridge to allow GenOn Kendall to make additional steam sales to Trigen-Boston Energy Corporation in Boston and that GenOn Kendall 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 GenOn Kendall to reduce significantly its use of water from the Charles River. On October 25, 2010, EPA and MADEP issued the proposed revised permits (the 2010 Kendall Permits) as draft permit modifications for public comment. On December 17, 2010, the EPA and MADEP issued final permits that became effective on February 1, 2011. The 2010 Kendall Permits will limit GenOn Kendall 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. The 2010 Kendall Permits do not require the installation of barrier nets or modifications to the intake structure at the facility. Because river water will no longer be used for once-through cooling under normal operations once the new pipeline and equipment have been installed, GenOn Kendall expects 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 its settlement with the EPA and MADEP, the EPA and MADEP issued administrative orders that defer application of 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 not expected to occur until 2015.

 

Canal NPDES and SWD Permit.  On August 1, 2008, the EPA issued to GenOn Canal 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 GenOn Canal 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. GenOn Canal 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. On December 4, 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. GenOn Canal filed comments on January 29, 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.

 

Conemaugh NPDES Permit.  In April 2007, two environmental groups sued GenOn Northeast Management Company in the United States District Court for the Western District of Pennsylvania alleging the inappropriate discharge of five metals to the Conemaugh River from the Conemaugh generating facility. We think that an administrative consent order and agreement signed in 2004 precludes this lawsuit and the two plaintiffs do not have standing. In October 2010, the court denied our motion to dismiss on these two grounds. A trial has been scheduled for June 2011.

 

Seward NPDES Permit Appeal.  The PADEP issued the Seward generating facility a renewed NPDES permit on July 19, 2010. On September 7, 2010, PennEnvironment, Defenders of Wildlife and the Sierra Club challenged this permit. These environmental groups assert that there was insufficient public notice of the final permit. They also assert that PADEP failed to (a) undertake a “case-by-case” analysis to set technology-based effluent limitations, (b) require sufficient monitoring of temperature changes or a compliance schedule or to otherwise address certain alleged violations, (c) address the discharge of “underground seeps to groundwater” and (d) properly consider the need for additional water quality-based effluent limitations. We disagree with these allegations and think that all of the issues raised have been adequately and appropriately addressed.

 

Shawville NPDES Permit Appeal.  The PADEP issued the Shawville generating facility a renewed NPDES Permit on August 9, 2010. That permit requires installation of cooling towers or reduction in plant operation by September 1, 2013 to reduce thermal effects on the West Branch of the Susquehanna River, which the Shawville generating facility uses for cooling water. We have appealed the permit because the deadlines for installation of cooling towers are both unachievable and inconsistent with the timeframe for making investment decisions regarding anticipated air quality regulations—the Transport Rule, which is expected to replace the CAIR, and the MACT Rule, which is expected to regulate emissions of mercury and other hazardous air pollutants. In addition, the Pennsylvania Fish & Boat Commission appealed the permit, alleging that the schedule for and form of thermal limits on the plant are not sufficiently stringent.

 

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.

 

Our Contra Costa, Pittsburg and Potrero generating facilities 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 those facilities were purchased in 1999 by our subsidiaries. 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 our 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 2008, we 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. We do not yet know what, if any, remediation will be required for the Lovett property.

 

We are responsible for environmental costs related to site contamination investigations and remediation requirements at four generating facilities in New Jersey. We recorded the estimated long-term liability for the remediation costs of $7 million at December 31, 2010.

 

Other.  As a result of their age, many of our plants contain significant amounts of asbestos insulation, other asbestos containing materials, as well as lead-based paint. We think we properly manage and dispose of such materials in compliance with state and federal rules. See note 5(d) to our consolidated financial statements.

 

Additionally, CERCLA, also known as the Superfund law, establishes a federal framework for dealing with the cleanup of contaminated sites. Many states have enacted similar state superfund statutes as well as other laws imposing obligations to investigate and clean up contamination. We do not think we have any material liabilities or obligations under CERCLA or similar state laws. These laws impose clean up and restoration liability on owners and operators of plants from or at which there has been a release or threatened release of hazardous substances, together with those who have transported or arranged for the disposal of those substances.

Employees

 

At February 11, 2011, we employed 3,487 people, which included approximately 2,621 employees at our generating facilities, 415 employees at our regional offices and 451 employees at our corporate headquarters in Houston, Texas. The following details the employees subject to collective bargaining agreements:

 

 

 

 

To mitigate and reduce the risk of disruption during labor negotiations, we engage in contingency planning for operation of our generating facilities to the extent possible during an adverse collective action by one or more of our unions.

Available Information

 

Our principal offices are at 1000 Main Street, Houston, Texas 77002 (832-357-7000). The following information is available free of charge on our website (http://www.genon.com):

 

 

You can request a free copy of these documents by contacting our investor relations department. It is our intention to disclose amendments to, or waivers from, our code of ethics and business conduct on our website. No information on our website is incorporated by reference into this Form 10-K. In addition, our annual, quarterly and current reports are available on the SEC’s website at (http://www.sec.gov) or at its public reference room: 100 F Street, NE, Room 1580, Washington, D.C. 20549 (1-800-SEC-0330).

 

 

We are subject to the following factors that could affect our future performance and results of operations. Also, see “Cautionary Statement Regarding Forward-Looking Information” on page vii, “Business” in Item 1 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this Form 10-K.

 

Risks Related to the Operation of our Business

 

The merger that created GenOn may not achieve its intended results, and we may be unable to integrate successfully Mirant’s and RRI Energy’s operations.

 

Achieving the anticipated benefits of the merger that created GenOn depends on whether the businesses of RRI Energy and Mirant can be integrated in an efficient and effective manner. Integration of the two companies could take longer than anticipated and could result in the loss of valuable employees, the disruption of our ongoing businesses, processes and systems or inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements, any of which could adversely affect our ability to achieve the anticipated benefits of the merger. We may have difficulty addressing possible differences in corporate cultures and management philosophies. Many of our employees are in new positions following the merger and are required to comply with policies that are new to them, including policies related to risk management. The integration process is subject to a number of uncertainties, and no assurance can be given that the anticipated benefits will be realized or, if realized, the timing of their realization. Failure to achieve these anticipated benefits could result in increased costs or decreases in the amount of expected revenues and could adversely affect our future business, financial condition, operating results and prospects.

 

Our revenues 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 into competitive power markets either on a short-term fixed price basis or through power sales agreements. 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, our competitors’ marginal and long-term costs of production, 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, which may limit our ability to recover costs and an adequate return

on our investment. 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 and results of operations are influenced by factors that are beyond our control, including:

 

 

Some of our existing generating facilities may have a limited life unless we make significant capital expenditures to increase their commercial and environmental performance which may not be justified under current market rules and conditions.

 

Most of our existing generating facilities in California depend almost entirely on payments in support of system reliability. The energy market, as currently constituted, will not justify the capital expenditures necessary to repower or reconstruct these facilities to make them commercially viable in a merchant market and to meet future environmental requirements. If a commercially reasonable capacity market were to be instituted by the CAISO or we could obtain a contract with a creditworthy buyer, it is possible that we could justify investing the necessary capital to repower or reconstruct these facilities. Absent that, most of our existing generating facilities in California will be commercially viable only as long as they are necessary for reliability. As discussed further in note 5(c) to our consolidated financial statements, we plan to shut down the Contra Costa generating facility in April 2013 and we shut down the Potrero generating facility on February 28, 2011.

 

Our generating facilities face lower levels of profitability under current and forecasted market conditions and some of our generating facilities may not justify the capital expenditures to make them commercially viable and/or to meet possible environmental requirements.

 

Changes in the wholesale energy market or in our facility operations could result in impairments.

 

If our outlook for the wholesale energy market changes negatively, or if our ongoing evaluation of our business results in decisions to mothball, retire or dispose of facilities, we could have impairment charges related to our fixed assets, including the assets of RRI Energy that were recorded at provisional fair values in conjunction with the Merger. 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. Furthermore, increasing environmental regulatory requirements could result in facilities being removed from service or derated. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Business Overview” in Item 7 of this Form 10-K and note 5 to our consolidated financial statements.

 

Our Marsh Landing development project is subject to construction risks and, if we are unsuccessful in addressing those risks, we may not recover our investment in the project or our return on the project may be lower than expected.

 

Under its long-term PPA with PG&E, GenOn Marsh Landing bears the risk of completing the construction of the generating facility by the required completion date under the PPA. GenOn Marsh Landing has posted a letter of credit of $80 million to PG&E to secure its contingent obligations for delay damages or termination payments under the PPA, which amounts were $16 million at December 31, 2010, and escalate over the construction period. GenOn Marsh Landing has also posted a letter of credit and provided a guaranty of GenOn Energy Holdings to the contractor at December 31, 2010 of $26 million and $43 million, respectively, to secure its obligations under the EPC agreement for the Marsh Landing project. GenOn Marsh Landing has also posted surety bonds totaling $4 million to PG&E to secure obligations related to transmission system upgrades and interconnection services. If GenOn Marsh Landing does not complete the construction of the Marsh Landing generating facility by the required completion date under the PPA, our return on the project may be lower than expected. Should the facility fail to be operational by the required date under the PPA or not perform as required under the terms of the PPA, PG&E may have the right to terminate the PPA. As there is currently no wholesale capacity market in California, if PG&E were to terminate the PPA, our return on the project might be materially lower than expected.

We are exposed to the risk of fuel and fuel transportation cost increases and volatility and interruption in fuel supply because our generating facilities generally do not have long-term agreements for the supply of natural gas, coal and oil and rely on other parties for transportation.

 

Although we purchase fuel based on our expected fuel requirements, we still face the risks of supply interruptions and fuel price volatility. 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 it. 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. This may have a material adverse effect on our financial performance. The volatility of fuel prices could adversely affect our financial results and operations.

 

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 2013 and one that extends to 2020. There is risk that our coal suppliers may not provide the contractual quantities on the dates specified within the agreements, or the deliveries may be carried over to future periods. If our coal suppliers do not perform in accordance with the agreements, we may have to procure coal in the market to meet our needs, or 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. Non-performance or default risk by our coal suppliers could have a material adverse effect on our future results of operations, financial condition and cash flows. For a discussion of our coal supplier concentration risk, see note 1 to our consolidated financial statements in this Form 10-K.

 

For our oil-fired generating facilities, we typically purchase fuel from a limited number of suppliers under contracts with terms of varying lengths. If our oil suppliers do not perform in accordance with the agreements, we may have to procure oil in the market to meet our needs, or 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 may have a material adverse effect on our cash flows and results of operations.

 

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

 

 

 

A decrease in, or the elimination of, the revenues generated by our facilities or an increase in the costs of operating them could materially affect our cash flows and results of operations, including cash flows available to us to make payments on our debt or our other obligations.

 

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.

 

We are exposed to possible losses 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 represent 42% of our net notional power position at December 31, 2010. 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 our counterparties and any resulting failure to pay amounts owed to us or to perform obligations or services owed to us beyond collateral posted could have a negative effect on our business and financial condition.

 

We are subject to adverse developments in the regions in which we operate, especially the PJM market.

 

At December 31, 2010, our generating capacity was 50% in PJM, 23% in CAISO, 10% in the Southeast, 7% in MISO and 10% in NYISO and ISO-NE. Adverse developments in these regions, especially in the PJM market (where most of our revenues are derived), may adversely affect our results of operations or financial condition. The effect of such adverse regional developments may be greater on us than on our more diversified competitors.

 

Our income tax NOL carry forwards could be substantially limited if we experience an ownership change as defined in the IRC.

 

We have approximately $1.9 billion of federal NOL carry forwards, which we are able to use to offset taxable income in future years. If, however, an “ownership change,” as defined in IRC Section (IRC §) 382, occurs, the amount of NOLs that could be used in any one year following such ownership change would be substantially limited. In general, an “ownership change” would occur when there is a greater than 50-percentage point increase in ownership of a company’s stock by stockholders each of which owns (or is deemed to own under IRC § 382) 5% or more of such company’s stock. Given IRC § 382’s broad definition, an ownership change could be the unintended consequence of otherwise normal market trading in our stock that is outside our control. Moreover, while we have a stockholder rights plan in place in an effort to preserve our NOLs, the stockholder rights plan can only deter, not prevent, an ownership change that would result in the loss of our NOLs. See notes 7 and 13 to our consolidated financial statements.

 

Competition in wholesale power markets may have a material adverse effect on our financial condition, results of operations and cash flows.

 

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 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. The competitive advantages

of such participants could adversely affect our ability to compete effectively and could have an adverse effect on the revenues generated by our facilities.

 

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 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, which could have a material adverse effect on our results of operations.

 

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. If we are required to make material expenditures to decommission or remediate one or more of our facilities, such obligations will affect our cash flows and may adversely affect our ability to make payments on our obligations.

 

Terrorist attacks, future wars or risk of war may adversely affect our results of operations, our ability to raise capital or our future growth.

 

As a power generator, we face heightened risk of an act of terrorism, either a direct act against one of our generating facilities or an act against the transmission and distribution infrastructure that is used to transport our power, which would cause an inability to operate as a result of systemic damage. Further, 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. If such an attack or security breach were to occur, our business, results of operations and financial condition could be materially adversely affected. In addition, such an attack could affect our ability to service our indebtedness, our ability to raise capital and our future growth opportunities.

 

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. 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 maintain an amount of insurance protection that we consider adequate, but 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. A hazard or liability for which we are not fully insured could have a material adverse effect on our financial results and our financial condition.

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 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 and could have a material adverse effect on our results of operations. 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, which could adversely affect our financial condition, results of operations or cash flows. See notes 7, 18 and 19 to our consolidated financial statements.

 

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

 

The failure of the lenders under our undrawn credit facilities to perform could have a material adverse effect on our liquidity and results of operations. We are exposed to systemic risk of the financial markets and institutions and the risk of non-performance of the individual lenders under our 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, we maintain a revolving credit facility to manage our expected liquidity needs and contingencies as described in more detail in this Form 10-K. The failure of our lenders to perform under our revolving credit facility could have a material adverse effect on our results of operations. In the event that financial institutions are unwilling or unable to renew our existing revolving credit facility or enter into new revolving credit facilities, our ability to hedge economically our assets or engage in proprietary trading could also be impaired. A significant portion of the Marsh Landing project costs are expected to be funded through drawings under the GenOn Marsh Landing credit facility. The failure of the lenders to perform under that credit facility and related interest rate swaps could have a material adverse effect on the ability to complete construction of the Marsh Landing facility or on the expected return on that investment.

 

As financial institutions consolidate and operate under more restrictive capital constraints and regulations, there could be less liquidity in the energy and commodity markets, which could have a negative effect on our ability to hedge economically and transact with 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. In recent years, global financial institutions have been active participants in these energy and commodity markets. As such financial institutions consolidate and operate under more restrictive capital constraints and regulations, there could be less liquidity in the energy and

commodity markets, which could have a negative 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 affect our ability to hedge economically our generation.

 

The Dodd-Frank Act, which was enacted in July 2010 in response to the global financial crisis, increases the regulation of transactions involving OTC derivative financial instruments. The statute provides that standardized swap transactions between dealers and large market participants will have to be cleared and traded on an exchange or electronic platform. Although the provisions and legislative history of the Dodd-Frank Act provide strong evidence that market participants, such as the Company, 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 to be issued by the CFTC and SEC will provide. The effect of the Dodd-Frank Act on our business depends in large measure on pending CFTC and SEC rulemaking proceedings and, in particular, the final definitions for the key terms “Swap Dealer” and “Major Swap Participant” in the Dodd-Frank Act. The CFTC and SEC issued a proposed rulemaking to set final definitions for the terms “Swap Dealer” and “Major Swap Participant,” among others. 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. As proposed, the Swap Dealer definition in particular is ambiguous, subjective and could be broad enough to encompass some energy companies. If applied to our hedging activity, such regulations could materially affect our ability to hedge economically our generation by 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.

 

Changes in commodity prices may negatively affect our financial results by increasing the cost of producing power or lowering 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 asset management activities will not fully protect us from fluctuations in commodity prices.

 

We engage in asset management activities related to sales of electricity and purchases of fuel. 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. 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 asset management 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 4 to our consolidated financial statements and “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of this Form 10-K.

Additionally, we expect to have an open position in the market, within our established guidelines, resulting from our 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 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 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.

 

The accounting treatment of our asset management, proprietary trading and fuel oil management activities may increase the volatility of our quarterly and annual financial results.

 

We engage in asset management activities to hedge economically our exposure to market risk with respect to: (a) electricity sales from our generating facilities, (b) fuel used by those facilities and (c) emissions allowances. We generally attempt to balance our fixed-price purchases and sales commitments in terms of contract volumes and the timing of performance and delivery obligations through the use of financial and physical derivative financial instruments. We also use derivative financial instruments with respect to our limited proprietary trading and fuel oil management activities, through which we attempt to achieve incremental returns by transacting where we have specific market expertise. Derivatives from our asset management, 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. Other than interest rate swaps into which we entered to manage our interest rate risk associated with our GenOn Marsh Landing project financing, which were designated as cash flow hedges, none of our other derivatives recorded at fair value is 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 note 4 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. 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. 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.

We are required to surrender emission 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.

 

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 emission allowances if allowances are a part of the final regulatory framework. See “Business—Environmental Matters” in Item 1, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Business Overview” in Item 7 of this Form 10-K and note 18 to our consolidated financial statements.

 

Certain environmental laws, including the Comprehensive Environmental Response, Compensation and Liability Act of 1980 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 with known soil and/or groundwater contamination. Releases of hazardous substances at our generating facilities, or at locations where we dispose of (or in the past disposed of) hazardous substances and other waste, could require us to spend significant sums to remediate contamination, regardless of whether we caused such contamination. The discovery of significant contamination at our generating facilities, at disposal sites we currently use or have used, or at other locations for which we may be liable, or the failure or inability of parties contractually responsible to us for contamination to respond when claims or obligations regarding such contamination arise, could have a material adverse effect on our financial performance and condition.

 

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. For most of our ash disposal, we use our own ash management facilities, which are all dry landfills to dispose of the ash; however, 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 have a plan to develop new ash management facilities and also commenced construction in February 2011 of a facility that is designed to prepare our ash from certain of our Maryland facilities for beneficial uses. However, the costs associated with purchasing new land and permitting the land to allow for ash disposal could be material, and the amount of time needed to obtain permits for the land could extend beyond the expected timeline. Likewise, the ongoing construction of a facility to prepare our ash for beneficial use may be delayed, cost more than expected or 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, 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. The EPA expects to finalize this rule in late 2011.

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.

 

We are subject to regulation by the FERC regarding the rates, terms and conditions of wholesale sales of electric capacity, energy and ancillary services and other matters, including mergers and acquisitions, the disposition of facilities under the FERC’s jurisdiction and the issuance of securities, as well as by state agencies regarding physical aspects of our generating 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. If we cannot comply with all applicable regulations, our business, results of operations and financial condition could be adversely affected.

 

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 and results of operations.

 

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.

 

We have a substantial amount of indebtedness. At December 31, 2010, our consolidated indebtedness was $6.1 billion. In addition, the present values of lease payments under the respective GenOn Mid-Atlantic and REMA operating leases were approximately $927 million and $488 million, respectively (assuming a 10% and 9.4% discount rate, respectively) and the termination value of the respective GenOn Mid-Atlantic and REMA operating leases was $1.4 billion and $752 million.

Our substantial 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:

 

 

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

 

We and certain of our subsidiaries, including GenOn Americas Generation, are holding companies and, as a result, are dependent upon dividends, distributions and other payments from our operating subsidiaries to generate the funds necessary to meet our obligations. In particular, a substantial portion of the cash from our operations is generated by GenOn Mid-Atlantic. The ability of certain of our subsidiaries to pay dividends and make distributions is restricted under the terms of their debt or other agreements, including the operating leases of GenOn Mid-Atlantic and REMA. Under their respective operating leases, GenOn Mid-Atlantic and REMA are not permitted to make any distributions and other restricted payments unless: (a) they satisfy the fixed charge coverage ratio for the most recently ended period of four fiscal quarters; (b) they are 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 respective operating leases or if the respective restricted payment tests are not satisfied, GenOn Mid-Atlantic and REMA would not be able to distribute cash. At December 31, 2010, GenOn Mid-Atlantic and REMA satisfied the respective restricted payments tests.

 

We may be unable to generate sufficient cash to service our debt and to post required amounts of cash collateral necessary to hedge economically market risk.

 

Our ability to pay principal and interest on our debt depends on our future operating performance. If our cash flows and capital resources are insufficient to allow us to make scheduled payments on our debt, we may have to reduce or delay capital expenditures, sell assets, seek additional capital, restructure or refinance. There can be no assurance that the terms of our debt will allow these alternative measures, that the financial markets will be available to us on acceptable terms or that such measures would satisfy our scheduled debt service obligations. If we do not comply with the payment and other material covenants under our debt agreements, we could be required to repay our debt immediately and, in the case of our revolving credit facilities, the commitment to lend us money could terminate.

We seek to manage the risks associated with the volatility in the price at which we sell power produced by our generating facilities and in the prices of fuel, emissions allowances and other inputs required to produce such power by entering into hedging transactions. These asset management activities may require us to post collateral either in the form of cash or letters of credit. At December 31, 2010, we had approximately $265 million of posted cash collateral and $267 million of letters of credit outstanding under our revolving credit facility primarily to support our asset management activities, trading activities, rent reserve requirements and other commercial arrangements. See note 6 to our consolidated financial statements for further information on our posted cash collateral and letters of credit. Although we seek to structure transactions in a way that reduces our potential liquidity needs for collateral, we may be unable to execute our hedging strategy successfully if we are unable to post the amount of collateral required to enter into and support hedging contracts.

 

We are an active participant in energy exchange and clearing markets. These markets require a per-contract initial margin to be posted, regardless of the credit quality of the participant. The initial margins are determined by the exchanges through the use of proprietary models that rely on a variety of inputs and factors, including market conditions. We have limited notice of any changes to the margin rates. Consequently, we are exposed to changes in the per unit margin rates required by the exchanges and could be required to post additional collateral on short notice.

 

The terms of our credit facilities restrict our current and future operations, particularly our ability to respond to changes or take certain actions.

 

Our credit facilities contain a number of restrictive covenants that impose significant operating and financial restrictions on us and may limit our ability to engage in acts that may be in our long-term best interest, including restrictions on our ability to:

 

 

In addition, the restrictive covenants in our credit facilities require us to maintain a ratio of consolidated secured debt (net of up to $500 million in cash) to EBITDA of not more than 3.50 to 1.00, which will be tested at the end of each fiscal quarter and, in the case of EBITDA, will be calculated on a rolling four fiscal quarter basis ending on the last day of such fiscal quarter. Our ability to meet that financial ratio can be affected by events beyond our control. Our failure to comply with the covenants in our credit facilities could result in an event of default under our credit facilities and any other debt to which a cross-default or cross-acceleration provision applies.

 

 

None.

 

 

Our generating facilities are described under “Business—Business Segments” in Item 1 of this Form 10-K. We own or lease oil and gas pipelines that serve our generating facilities. Our principal executive offices at

1000 Main Street, Houston, Texas 77002 are leased through 2018, subject to two five-year renewal options. We also lease offices, including a trading floor, at 1155 Perimeter Center West, Suite 100, Atlanta, GA 30338 and various other office spaces. We think that our properties are adequate for our present needs. Except for the Conemaugh, Keystone and Sabine facilities, our interest at December 31, 2010 is 100% for each property. We have satisfactory title, rights and possession to our owned facilities, subject to exceptions, which, in our opinion, would not have a material adverse effect on the use or value of the facilities.

 

 

See note 18 to our consolidated financial statements for discussion of the material legal proceedings to which we are a party.

 

 

 

The common stock data included in this Item 5 refers to GenOn’s common stock from December 3, 2010 through December 31, 2010 and to RRI Energy, Inc.’s common stock (ticker symbol “RRI”) for all other periods presented.

 

Common Stock.  Our common stock trades on the NYSE under the ticker symbol “GEN.” On February 18, 2011, we had 88,158 stockholders of record. The closing price of our common stock on December 31, 2010 was $3.81. We have never paid dividends. Some of our debt agreements restrict the payment of dividends. See note 6 to our consolidated financial statements.

 

We are authorized to issue 2 billion shares of common stock having a par value of $.001 per share and 125 million shares of preferred stock having a par value of $.001 per share. In addition, we reserved shares for unresolved claims related to the Mirant bankruptcy, of which approximately 1.3 million shares had not yet been distributed at December 31, 2010.

 

The following table sets forth the high and low prices for our common stock as reported by the NYSE for the periods indicated.

 

 

Securities Authorized for Issuance under Equity Compensation Plans.  See Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for information related to securities authorized for issuance under equity compensation plans.

 

Stock Performance Graph.  The performance graph below is being provided as furnished and not filed, as permitted by 17 Code of Federal Regulations 229.201(e), in this Form 10-K and compares the cumulative total stockholder return on our common stock (GenOn or RRI Energy) with the Standard & Poor’s 500 Index and a group of our peer companies in our industry comprised of Allegheny Energy, Inc., Calpine Corporation, Constellation Energy Group, Inc., Dynegy Inc., Mirant, NRG Energy, Inc. and PPL Corporation. In 2010, we added Constellation Energy Group, Inc. to our peer group of companies because of the Merger. The graph assumes that $100 was invested on December 31, 2005, in our common stock (GenOn or RRI Energy) and each of the above indices (except that Calpine Corporation is only included in the peer group since its emergence from bankruptcy in January 2008 and Mirant is only included since its emergence from bankruptcy in January 2006 through the Merger close on December 3, 2010) and that all dividends were reinvested.

GenOn Energy, Inc

 

 

 

 

Source: SNL Financial LC, Charlottesville, VA

 

The following discussion should be read in conjunction with our consolidated financial statements and the notes thereto, which are in this Form 10-K. The following tables present our selected consolidated financial information, which is derived from our consolidated financial statements.

 

Upon completion of the Merger, Mirant stockholders had a majority of the voting interest in the combined company. Although RRI Energy issued shares of RRI Energy common stock to Mirant stockholders to effect the Merger, the Merger is accounted for as a reverse acquisition under the acquisition method of accounting. Under the acquisition method of accounting, Mirant is treated as the accounting acquirer and RRI Energy is treated as the acquired company for financial reporting purposes. As such, the consolidated financial statements and results below of GenOn include the results of Mirant, from January 1, 2006 through December 2, 2010, and include the results of the combined entities for the period from December 3, 2010 through December 31, 2010. The EPS data has been retroactively adjusted to give effect to the Exchange Ratio. The consolidated financial statements presented herein for periods ended prior to the closing of the Merger (and any other financial information presented herein with respect to such pre-merger dates, unless otherwise specified) are the consolidated financial statements and other financial information of Mirant.

 

 

Our Statement of Operations Data for each year reflects the volatility caused by unrealized gains and losses related to derivative financial instruments used to hedge economically electricity and fuel. Changes in the fair value and settlements of derivative financial instruments used to hedge economically electricity are reflected in operating revenue and changes in the fair value and settlements of derivative financial instruments used to hedge economically fuel 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 proprietary trading and fuel oil management activities are recorded on a net basis as operating revenue in the consolidated statements of operations. See note 4 to our consolidated financial statements.

 

 

For 2010, net loss reflects the following before taxes:

 

 

For 2009, net income reflects the following before taxes:

 

 

For 2007, net income reflects the following before taxes:

 

 

For 2006, net income reflects the following before taxes:

 

 

The consolidated Balance Sheet Data at December 31, 2006 segregates pre-petition liabilities subject to compromise from those liabilities that were not subject to compromise.

 

 

The amounts for 2010 reflect the assets acquired and the debt transactions entered into related to the Merger. For additional information on the Merger and related debt transactions, see notes 2 and 6 to our consolidated financial statements.

 

In 2010, we reclassified the principal balance of the GenOn Americas Generation senior notes due in May 2011 from long-term debt to current portion of long-term debt.

 

On January 1, 2010, we adopted revised accounting guidance related to accounting for variable interest entities. As a result, MC Asset Recovery, LLC was deconsolidated from our financial results. The total assets at December 31, 2009 in the table above have been adjusted from amounts previously presented to reflect a $39 million reduction as a result of the deconsolidation of MC Asset Recovery, LLC. The adoption of this accounting guidance did not affect any of the other periods presented. For additional information, see note 15 to our consolidated financial statements.

 

In 2005, we recorded the effects of the Plan. As a result, liabilities subject to compromise at December 31, 2006, only reflect the liabilities of our New York entities that remained in bankruptcy at that time. Total assets for all periods reflect our election in 2008 to discontinue the net presentation of assets subject to master netting agreements upon adoption of the accounting guidance for offsetting amounts related to certain contracts.

 

This section is intended to provide the reader with information that will assist in understanding our 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 our consolidated financial statements and the notes accompanying those financial statements.

 

Merger of Mirant and RRI Energy

 

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.

 

Although RRI Energy was the legal acquirer, the Merger was accounted for as a reverse acquisition, and Mirant was deemed to have acquired RRI Energy for accounting purposes. As a consequence of the reverse acquisition accounting treatment, the historical financial statements presented for periods prior to the Merger date are the historical statements of Mirant, except for stockholders’ equity which has been retroactively adjusted for the equivalent number of shares of the legal acquirer. The operations of the former RRI Energy businesses have been included in the financial statements from the date of the Merger. For a discussion of our strategy, see Item 1, “Business—Strategy” in this Form 10-K.

 

Our Business

 

With approximately 24,200 MW of electric generating capacity, we operate across various fuel (natural gas, coal and oil) and technology types, operating characteristics and regional power markets. At December 31, 2010, our generating capacity was 50% in PJM, 23% in CAISO, 10% in the Southeast, 7% in MISO and 10% in NYISO and ISO-NE.

 

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

 

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 the markets in which we operate, we have entered into forward sales of natural gas to hedge economically exposure to changes in the price of electricity. We procure 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.

 

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 31, 2011, total projected contracted capacity and PPA revenues for which prices have been set for 2011 through 2014 are $3.1 billion.

 

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 three million barrels of storage capacity that we own or lease, 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 our physical natural gas and 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 5% 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. For 2010, the combined average daily VaR for proprietary trading and fuel oil management activities was $2 million.

 

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 then have some risks resulting from price differentials for different delivery points and 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 31, 2011, our aggregate hedge levels based on expected generation for each year were as follows:

 

 

 

 

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

 

 

Capital Expenditures and Capital Resources

 

For 2010, we invested $298 million for capital expenditures, excluding capitalized interest, of which $114 million related to compliance with the Maryland Healthy Air Act. At December 31, 2010, we have invested $1.519 billion of the $1.674 billion that was budgeted for capital expenditures related to compliance with the Maryland Healthy Air Act. As the final part of our compliance with the Maryland Healthy Air Act,

we placed four scrubbers in service at our Maryland facilities in the fourth quarter of 2009. Provisions in the construction contracts for the scrubbers provide for certain payments to be made after final completion of the project. The current budget of $1.674 billion continues to represent our best estimate of the total capital expenditures for compliance with the Maryland Healthy Air Act. See note 18 to our consolidated financial statements for further discussion of scrubber contract litigation.

 

For 2010, our capitalized interest was $6 million compared to $72 million for 2009. The decrease in capitalized interest from 2009 is a result of placing our scrubbers in service at our Maryland facilities in the fourth quarter of 2009.

 

The following table details the expected timing of payments for our estimated capital expenditures, excluding capitalized interest not related to the Marsh Landing generating facility, for 2011 and 2012:

 

 

We expect that available cash and future cash flows from operations will be sufficient to fund these capital expenditures. However, we plan to fund a substantial portion of the capital expenditures for the Marsh Landing generating facility with approximately $500 million of project financing debt into which we entered on October 8, 2010. See “California Development Activities” below for additional information on the Marsh Landing generating facility. 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 make decisions to invest capital for environmental controls based on relatively certain regulations and the expected economic returns on the capital. As discussed in Part 1 of this Form 10-K under “Business—Regulatory Environment—Environmental Regulation,” the effect on our business of pending EPA regulations to replace the CAIR and whether we elect to install additional controls are uncertain and depend on the content and timing of the regulations, the expected effect of the regulations on wholesale power prices and allowance prices, as well as the cost of controls, profitability of our generating facilities, market conditions at the time and the likelihood of CO₂ regulation. The EPA has stated that it expects to finalize the regulations to replace the CAIR in 2011. We may choose to retire certain of our units rather than install additional controls.

 

The costs associated with more stringent environmental air quality requirements may result in coal-fired generating facilities, including some of ours, being retired. Although conditions may change, under current and forecasted market conditions, installations of additional scrubbers would not be economic at most of our unscrubbed coal-fired facilities. Any such retirements could contribute to improving supply and demand fundamentals for the remaining fleet. Any resulting increased demand for gas could increase the spread between gas and coal prices, which would also benefit the remaining coal-fired generating facilities.

 

Furthermore, federal, state-specific or regional regulatory initiatives to stimulate CO₂ emission reductions in our industry are being considered. The effect on our business of these matters is uncertain and depends on the form and content of resulting regulations, if any, including their effect on (a) wholesale electricity and emissions allowance prices and (b) other existing regulations such as the RGGI.

 

If CO₂ regulation becomes more stringent, we expect that the demand for 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 resulting costs, 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. It is possible that Congress will take action to regulate greenhouse gas emissions within the next several years. The form and timing of any final legislation will be influenced by political and economic factors and are uncertain at this time. Implementation of a CO₂ cap-and-trade program in addition to other emission control requirements could increase the likelihood of coal-fired generating facility retirements.

 

Given the uncertainty related to these environmental matters, we cannot predict their actual outcome or ultimate effect on our business, and such matters could result in a material adverse effect on our results of operations, financial position and cash flows. See “Business—Regulatory Environment—Environmental Regulation” and “Risk Factors—Risks Related to Governmental Regulation and Laws” in Items 1 and 1A, respectively, of this Form 10-K and note 18 to our consolidated financial statements for further discussion.

 

Commodity Prices

 

The prices for power and natural gas remain low compared to several years ago. The energy gross margin from our 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 add economic hedges, including to maintain projected levels of cash flows from operations for future periods to help support continued compliance with the covenants in our debt and lease agreements.

 

California Development Activities

 

GenOn Marsh Landing

 

On September 2, 2009, GenOn Marsh Landing entered into a ten-year PPA with PG&E for 760 MW of natural gas-fired peaking generation to be constructed adjacent to our Contra Costa generating facility near Antioch, California.

 

During the ten-year term of the PPA, GenOn Marsh Landing will receive fixed monthly capacity payments and variable operating payments. The contract provides PG&E with the entire output of the 760 MW generating facility, which is expected to be capable of producing 719 MW during peak July conditions.

 

On May 6, 2010, GenOn Marsh Landing entered into an EPC agreement with Kiewit Power Constructors Co. (Kiewit) for the construction of the Marsh Landing generating facility. Under the EPC agreement, Kiewit is to design and construct the Marsh Landing generating facility on a turnkey basis, including all engineering, procurement, construction, commissioning, training, start-up and testing. The lump sum cost of the EPC agreement is $499 million (including the $212 million total cost under the Siemens Turbine Generator Supply and Services Agreement which was assigned to Kiewit in connection with the execution of the EPC agreement), plus the reimbursement of California sales and use taxes. See “Debt Obligations, Off-Balance Sheet Arrangements and Contractual Obligations” in “Liquidity and Capital Resources” for additional information on the EPC agreement with Kiewit.

 

On October 8, 2010, GenOn Marsh Landing entered into a credit agreement for up to $650 million of commitments to finance the Marsh Landing generating facility. See note 6 to our consolidated financial statements for further discussion.

 

GenOn Marsh Landing has received all permits necessary to begin construction and, on October 8, 2010, directed Kiewit to commence engineering and procurement for the Marsh Landing generating facility. Construction of the Marsh Landing generating facility is expected to be completed by mid-2013.

 

Contra Costa Toll Extension

 

On September 2, 2009, GenOn Delta entered into an agreement with PG&E for the 674 MW of Contra Costa units 6 and 7 for the period from November 2011 through April 2013. At the end of the agreement, and

subject to any necessary regulatory approval, GenOn Delta has agreed to retire Contra Costa units 6 and 7, which began operations in 1964, in furtherance of state and federal policies to retire aging power plants that utilize once-through cooling technology.

 

Pittsburg Toll Extension

 

On October 28, 2010, GenOn Delta entered into an agreement with PG&E for 1,159 MW of capacity from Pittsburg units 5, 6 and 7 for three years commencing January 1, 2011, with options for PG&E to extend the agreement for each of 2014 and 2015. Under the agreement, GenOn Delta will receive monthly capacity payments with bonuses and/or penalties based on heat rate and availability.

 

Potrero Settlement

 

On August 13, 2009, GenOn Potrero entered into a settlement agreement (Potrero Settlement) with the City and County of San Francisco. Among other things, the Potrero Settlement obligates GenOn Potrero to close permanently each of the remaining units of the Potrero generating facility at the end of the year in which the CAISO determines that such unit is no longer needed to maintain the reliable operation of the electricity system. In December 2010, the CAISO provided GenOn Potrero with the requisite notice of termination of the RMR agreement. On January 19, 2011, at the request of GenOn Potrero, the FERC approved changes to GenOn Potrero’s RMR agreement to allow the CAISO to terminate the RMR agreement effective February 28, 2011. On February 28, 2011, the Potrero facility was shut down. See note 19 to our consolidated financial statements for further discussion of the Potrero Settlement.

 

IBEW Local 1900 Collective Bargaining Agreement

 

During the second quarter of 2010, we entered into a new collective bargaining agreement with our employees represented by IBEW Local 1900 (located in Maryland and Virginia). The previous collective bargaining agreement expired on June 1, 2010. The new agreement has a five-year term expiring on June 1, 2015. As part of the new agreement, we are required to provide additional retirement contributions through the defined contribution plan, increases in pay and other benefits. In addition, the agreement provides for a change to the postretirement healthcare benefit plan covering IBEW Local 1900 union employees to eliminate employer-provided healthcare subsidies through a gradual phase-out. We recorded the effects of the plan curtailment during the second quarter of 2010 and recognized a reduction in other postretirement liabilities of $48 million and a decrease in accumulated other comprehensive loss of $11 million on the consolidated balance sheet and a gain of $37 million reflected as a reduction in operations and maintenance expense on the consolidated statement of operations. In addition, we recognized an increase of $3 million in our pension liability and in accumulated other comprehensive loss as a result of planned salary increases under the new collective bargaining agreement. See note 8 to our consolidated financial statements for additional information on the postretirement healthcare benefit curtailment.

 

Results of Operations

 

Upon completion of the Merger, Mirant stockholders had a majority of the voting interest in the combined company. Although RRI Energy issued shares of RRI Energy common stock to Mirant stockholders to effect the Merger, the Merger is accounted for as a reverse acquisition under the acquisition method of accounting. Under the acquisition method of accounting, Mirant is treated as the accounting acquirer and RRI Energy is treated as the acquired company for financial reporting purposes. As such, the consolidated financial statements and results below of GenOn include the results of Mirant, from January 1, 2008 through December 2, 2010, and include the results of the combined entities for the period from December 3, 2010 through December 31, 2010. The consolidated financial statements presented herein for periods ended prior to the closing of the Merger (and any other financial information presented herein with respect to such pre-merger dates, unless otherwise specified) are the consolidated financial statements and other financial information of Mirant.

Non-GAAP Performance Measures.  The following discussion includes the non-GAAP financial measures realized gross margin and unrealized gross margin to reflect how we manage our business. In our discussion of the results of our reportable segments, we include the components of realized gross margin, which are energy, contracted and capacity, and realized value of hedges. Management generally evaluates our operating results excluding the impact of unrealized gains and losses. When viewed with our GAAP financial results, these non-GAAP financial measures may provide a more complete understanding of factors and trends affecting our business. Realized gross margin represents our gross margin (excluding depreciation and amortization) less unrealized gains and losses on derivative financial instruments. Conversely, unrealized gross margin represents our unrealized gains and losses on derivative financial instruments. None of our derivative financial instruments recorded at fair value is designated as a hedge (other than our interest rate swaps) and changes in their fair values are recognized currently in income as unrealized gains or losses. As a result, our financial results are, at times, volatile and subject to fluctuations in value primarily because of changes in forward electricity and fuel prices. Realized gross margin, together with its components energy, contracted and capacity, and realized value of hedges, provide a measure of performance that eliminates the volatility reflected in unrealized gross margin, which is created by significant shifts in market values between periods. We also disclose the non-GAAP financial measures adjusted income from continuing operations and adjusted EBITDA as consolidated performance measures, which exclude unrealized gross margin. As mentioned above, management generally evaluates our operating results excluding the effect of unrealized gains and losses. Adjusted income from continuing operations and adjusted EBITDA also exclude items related to the Merger and the former Mirant bankruptcy, as well as impairment charges and net lower of cost or market adjustments to our commodity inventories and certain other items. We adjust for the subsequent benefit created by commodity inventory utilized in operations that were subject to prior period lower of cost or market adjustments. We exclude or adjust for these items to provide a more meaningful representation of our ongoing results of operations. However, these non-GAAP financial measures may not be comparable to similarly titled non-GAAP financial measures used by other companies.

 

We use these non-GAAP financial measures in communications with investors, analysts, rating agencies, banks and other parties. Adjusted EBITDA is a key performance metric in our employee short-term incentive structure for annual bonuses. We think these non-GAAP financial measures provide meaningful representations of our consolidated operating performance and are useful to us and others in facilitating the analysis of our results of operations from one period to another. We view adjusted EBITDA as providing a measure of operating results unaffected by differences in capital structures, capital investment cycles and ages of related assets among otherwise comparable companies. We encourage our investors to review our consolidated financial statements and other publicly filed reports in their entirety and not to rely on a single financial measure.

2010 Compared to 2009

 

Consolidated Financial Performance

 

We reported net loss of $50 million and net income of $494 million for 2010 and 2009, respectively. The change in net income/loss is detailed as follows:

 

 

Realized Gross Margin.  For 2010, our realized gross margin decrease of $203 million was principally a result of the following:

 

 

Unrealized Gross Margin.  Our unrealized gross margin for both periods reflects the following:

 

 

 

Operating Expenses.  Our operating expenses increase of $674 million was primarily a result of the following:

 

 

 

 

 

Gain on Bargain Purchase.  We reported a gain on bargain purchase of $518 million during 2010. Because the fair value of the net assets acquired in the Merger exceeds the purchase price, the Merger is being accounted for as a bargain purchase in accordance with acquisition accounting guidance. The estimated gain on the bargain purchase is primarily a result of differences between the long-term fundamental value of the generating facilities and the effect of the near-term view of the equity markets on the price of Mirant common stock at the close of the Merger, specifically as a result of the following: