UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

Form 10-K

 

 

 

 

 

Commission file number 1-16455

 

RRI Energy, Inc.
(Exact Name of Registrant as Specified in Its Charter)

 

 

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 in 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 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.  þ

 

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 definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

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

 

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was $1,751,959,756 (computed by reference to the closing sale price of the registrant’s common stock on the New York Stock Exchange on June 30, 2009, the last business day of the registrant’s most recently completed second fiscal quarter).

 

As of February 11, 2010, the registrant had 353,270,519 shares of common stock outstanding and no shares of common stock were held by the registrant as treasury stock.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the registrant’s definitive proxy statement for its 2010 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2009, are incorporated by reference into Part III of this Form 10-K.

 

 

TABLE OF CONTENTS

 

 

This report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements are statements that contain projections, assumptions or estimates about our revenues, income, capital structure and other financial items, our plans and objectives for future operations or about our future economic performance, possible transactions, dispositions, financings or offerings, and our view of economic and market conditions. In many cases, you can identify forward-looking statements by terminology such as “anticipate,” “estimate,” “believe,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “should,” “will,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and other similar words. However, the absence of these words does not mean that the statements are not forward-looking.

 

Actual results may differ materially from those expressed or implied by the forward-looking statements as a result of many factors or events, including, but not limited to, the following:

 

 

Other factors that could cause our actual results to differ from our projected results are discussed or referred to in Item 1A of this report. Each forward-looking statement speaks only as of the date of the particular statement and we undertake no obligation to update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. Our filings and other important information are also available on our investor page at www.rrienergy.com.

 

 

GLOSSARY OF TERMS
(Continued)

 

 

 

 

We provide energy, capacity, ancillary and other energy services to wholesale customers in competitive energy markets in the United States through our ownership and operation of and contracting for power generation capacity. Our business consists of four reportable segments: East Coal, East Gas, West and Other. We are a well-capitalized, wholesale generator with more than 14,000 megawatts of power generation plants.

 

The power generation industry is deeply cyclical and capital intensive. There is the possibility for significant future changes in environmental laws and regulations related to emissions. Competitive power markets are still relatively new and we believe scale and diversity will be important long term.

 

Over the past 18 months, natural gas and other commodity prices have declined, the spread between gas and coal prices has compressed and the downturn in the economy has reduced demand for electricity. Turmoil in the financial markets has increased the cost of capital and limited its availability. In 2009, we completed the sale of our former retail business, eliminating risk related to collateral posting and contingent capital related to that business. We are focused on managing the risks of operating in the current environment.

 

While we cannot control commodity prices, cyclicality of the industry or political outcomes, we can position ourselves for the longer term market recovery and industry consolidation that is likely over time. We strive for operating excellence to achieve maximum value from our plants.

 

For further information about our corporate history, business segments and disposition activities, see notes 1, 20, 21, 22 and 23 to our consolidated financial statements and “Selected Financial Data” in Item 6 of this Form 10-K.

 

We focus on operations excellence and continually improving our efficiency and effectiveness. We are implementing a flexible, plant-specific approach to how we operate and invest to maximize the value of our assets. Our objective is to invest for higher performance levels at higher-margin plants, while maintaining performance at lower-margin plants for the expected longer term market recovery. For further discussion, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Business Overview—Flexible Plant-Specific Operating Model” in Item 7 of this Form 10-K.

 

As of December 31, 2009, we owned, had an interest in, leased or contracted for power from 37 electric power plants with an aggregate net generating capacity of 14,581 MW in five regions of the United States. As of December 31, 2009, the net generating capacity of our plants by reportable segment consisted of approximately 32% East Coal, 28% East Gas, 23% West (gas) and 17% Other. Our coal plants generally dispatch as base-load, and our gas, oil and dual fuel plants primarily dispatch as intermediate and/or peaking capacity. We believe coal-fired plants will play an integral role in meeting the United States energy needs for the foreseeable future. Reduced demand for some coal-fired plants could occur depending on the outcome of various pending environmental laws and regulations. Efficient, well located coal-fired plants with emission controls should have a long-term future in the industry.

The following table describes our plants as of December 31, 2009:

 

 

 

 

 

The following table reflects operational and financial data for each of our four reportable segments. For further information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Consolidated Results of Operations” in Item 7 of this Form 10-K.

 

 

 

 

The following table reflects operational data for each significant plant with impacts on open energy gross margin in our reportable segments. Thus, this table excludes plants that primarily operated under power purchase agreements during the majority of these years as the financial results from those plants are included in other margin. For further information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Consolidated Results of Operations” in Item 7 of this Form 10-K.

 

 

 

 

 

 

 

The following table reflects revenues by type for each of our reportable segments. For further information, see “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Consolidated Results of Operations” in Item 7 of this Form 10-K.

 

 

 

 

Markets

 

In addition to purchasing energy, our customers will, for reliability and to comply with regulations, purchase rights to capacity from our plants. We also provide ancillary services to support transmission grid operations. Our products and services may be provided individually or in combination to investor-owned utilities, municipalities, cooperatives and other companies that serve end users or purchase power at wholesale for resale. We obtain transmission services from various RTOs, ISOs, utilities and municipalities.

 

We sell energy, ancillary and other energy services in the spot market on an hour-ahead or day-ahead basis, as well as in forward markets for various time periods. We sell our plants’ capacity in forward markets. A significant portion of our revenues comes from energy sold in the spot market and forward sales of capacity. Most of these energy sales occur in our East Coal segment, primarily in the PJM Market. Our capacity sales

primarily occur through the PJM Market’s reliability pricing model (RPM) auctions, but also in MISO, Cal ISO and other markets where we enter into agreements with counterparties.

 

Through the RPM auctions, we have committed approximately 5,500 MW of capacity (3,000 MW for coal plants and 2,500 MW for natural gas plants) through May 2013. We expect that a substantial portion of our PJM capacity will continue to be sold in the PJM Market 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. The California Public Utility Commission and Cal ISO are considering possible enhancements to existing resource adequacy requirements, including alternatives similar to capacity markets designed in New England and PJM.

 

Most of our plants operate in regions administered by PJM, Cal ISO and MISO and none of our plants is subject to traditional cost-based regulation. We can generally sell at market-determined prices. However, these regional jurisdictions operate under FERC-approved market rules. The market rules include price limits or caps applicable to all electric generators and numerous other FERC-approved requirements relating to the manner in which we must operate our plants, including reliability standards. A number of our subsidiaries are public utilities under the Federal Power Act and are subject to FERC rules and oversight regulations. Each of these subsidiaries has been granted market-based rate authority, although a limited amount of services sold by some of them is sold at cost-based rates.

 

The following table reflects estimated capacity revenues for 2010 and 2011:

 

 

 

 

Fuel Supply

 

To ensure adequate fuel supplies, we contract for natural gas, coal and fuel oil for our plants. For our natural gas-fired plants, we also arrange for, schedule and balance natural gas from our suppliers and through transporting pipelines. To perform these functions, we lease natural gas transportation and storage capacity. Our coal supply strategy has been to contract for our expected delivery needs at least one year in advance with prices generally fixed one year in advance. This has caused volatility in our financial results since our energy sales primarily occur in the spot market. Our modest financial hedging program has mitigated some of our fixed-price coal risk. Going forward, we expect to reduce the levels of our physical coal inventory and will continue to evaluate ways to address volatile coal prices. Under some of our agreements, the counterparties are required to provide fuel supply. We sell excess fuel supplies to third parties. See note 2(c) to our consolidated financial statements and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Consolidated Results of Operations” in Item 7 of this Form 10-K.

 

Hedging

 

We may hedge to (a) seek potential value greater than what is available in the spot or day-ahead markets, (b) address operational requirements or (c) seek a specific financial objective. Our coal procurement strategy is an example of hedging for an operational requirement. We have implemented a modest hedging program for a financial objective. Some of our coal plants’ 2010 and 2011 generation is hedged so that in the event of a sustained depressed commodity environment, we expect to deliver some minimal level of free cash flow. The rest of our fleet is largely unhedged to benefit from the expected longer term market recovery. For further

discussions, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in Item 7 of this Form 10-K, “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A of this Form 10-K and notes 2(e) and 6 to our consolidated financial statements.

 

Other

 

For further discussion of our business strategy, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Business Overview” in Item 7 of this Form 10-K. See “Risk Factors” in Item 1A of this Form 10-K for further discussion on factors that could have an adverse effect on our business.

 

The wholesale power generation industry is intensely competitive. Each of our business segments, East Coal, East Gas, West and Other, faces competitors that include other non-utility generators, regulated utilities and other energy service companies, including those owned by investment banking firms, hedge funds and private equity funds. For additional information on the effect of competition, see “Risk Factors” in Item 1A of this Form 10-K.

 

A large portion of our margins has historically been realized during our third quarter because most of our plants are located in markets where the greatest demand for power occurs during the summer months. For additional information on the effect of seasonality on our business, see “Risk Factors” in Item 1A of this Form 10-K and note 19 to our consolidated financial statements.

 

We are subject to numerous federal, state and local requirements relating to the protection of the environment and the safety and health of personnel and the public. These requirements relate to a broad range of our activities, including the discharge of compounds 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.

 

We make decisions to invest in environmental capital projects based on relatively certain regulations and the expected economic returns on the capital. Based on existing regulations and our current market outlook and assessment of the costs of labor and materials and the state of evolving technologies, we estimate that we will invest approximately $34 million in 2010, $20 million in 2011 and $34 million in later years primarily on wastewater treatment, coal combustion product management and environmental maintenance capital projects. The 2010 estimate also includes approximately $14 million to complete SO₂ controls at our Cheswick plant. As discussed further below, for years beyond 2011, the amount of environmental investments could significantly increase subject to the form of final regulations and future market conditions, particularly in regard to NO_x, SO₂ and CO₂ emissions. Although we cannot predict the actual outcome or ultimate effect on our business of environmental laws and regulations that are pending, under consideration or revision, or in dispute, we expect them generally to become more stringent in the future. For additional information on how environmental matters may impact our business, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Business Overview” in Item 7 of this Form 10-K, note 16(b) to our consolidated financial statements and “Risk Factors” in Item 1A of this Form 10-K.

 

Air Quality

 

Under the Clean Air Act, the EPA sets national ambient air quality standards for pollutants considered harmful to public health and the environment, including NO_x, SO₂, ozone and fine particulate matter (PM_2.5). Emissions of NO_x and SO₂ affect the standards for NO_x and SO₂, are precursors to the formation of ozone and

PM_2.5, and contribute to reduced visibility. The EPA and states use local and regional controls to attain and maintain the national ambient air quality standards and to control visibility. The EPA also has authority under the Clean Air Act to control mercury and other hazardous air pollutants from major sources of emissions to the air. In addition, the EPA has been taking steps to regulate greenhouse gas emissions.

 

National Ambient Air Quality Standards

 

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 plant (upwind from New Jersey) on high energy demand days. Phase II requires the installation of emission controls on all of our New Jersey plants (Gilbert, Glen Gardner, Sayreville and Werner) by May 1, 2015. If we elect to install these controls, we could incur capital expenditures of up to approximately $190 million primarily during 2013 to 2015. Our initial Phase II control plan must be filed with the state of New Jersey by May 1, 2010, and our decision on investments should occur by 2012.

 

In March 2005, the EPA finalized the Clean Air Interstate Rule (CAIR) to reduce emissions of NO_x and SO₂ in the Eastern United States in two phases in order to assist with the attainment of both ozone and PM_2.5 standards. The first phase, which took effect in 2009 for NO_x and takes effect in 2010 for SO₂, requires overall reductions within the area of approximately 50% in NO_x and SO₂ emissions on an annual basis. The second phase, which takes effect in 2015, requires additional reductions of approximately 10% for a 60% total reduction in NO_x and approximately 15% for a 65% total reduction in SO₂. CAIR is a cap-and-trade program which requires us to provide an emission allowance for each ton of NO_x and SO₂ that we emit. We maintain or have contracts to purchase emission allowances that at a minimum correspond with forward power sales. In general, we do not have emission allowances for all of our generation. We purchase emission allowances, as needed, to correspond with our power generation.

 

In July 2008, the United States Circuit Court of Appeals for the D.C. Circuit ruled that CAIR was legally flawed, vacated CAIR in its entirety and remanded CAIR to the EPA for revision consistent with the Court’s opinion. On rehearing, in December 2008, the Court decided that CAIR will remain in effect until the EPA issues a new rule to replace CAIR in accordance with the July 2008 decision. The EPA has stated that it expects to finalize the new rule in 2011. We may install emission controls at our Conemaugh plant for up to $70 million over several years, expected to begin no sooner than 2012.

 

Eight of our plants are located in geographic areas that are not in compliance with the existing ozone national ambient air quality standards (nonattainment areas). Following finalization of CAIR, it is possible that additional NO_x emission control measures (in addition to the measures required by CAIR) may be necessary at plants in or near nonattainment areas to meet current or revised ozone standards. These control measures may be part of regional or state implementation plans.

 

Ten of our eleven coal-fired plants are located in nonattainment areas for PM_2.5. States must develop emission reduction plans by April 2012 that bring nonattainment areas into compliance by 2014. These plans may be state-specific or regional in scope. The EPA has estimated that the power generation sector SO₂ and NO_x emissions reductions required by CAIR would allow many of the nonattainment areas to achieve compliance with the revised PM_2.5 standard.

 

The EPA’s primary focus for achieving compliance with visibility standards is on emissions of NO_x and SO₂, particularly from the power sector. The EPA has asserted that the NO_x and SO₂ reductions to be achieved through CAIR should be adequate to provide the improvements in visibility required by 2013.

 

States are not precluded from developing plans that would require additional reductions in NO_x and SO₂ emissions to meet ozone, PM_2.5 or visibility improvement goals. In addition, a delay in finalizing the CAIR replacement rule could make additional NO_x and SO₂ reductions necessary.

Hazardous Air Pollutants

 

In 2000, the EPA found that regulation of hazardous air pollutants, including mercury, from coal and oil-fired power plants was “appropriate and necessary,” triggering the requirement to regulate such emissions using the Maximum Achievable Control Technology (MACT) standard of the Clean Air Act. In February 2009, the EPA stated its intent to proceed with rulemaking under the MACT standard. This approach considers the most effective control technologies in operation, without regard to cost effectiveness. The EPA has stated it expects to issue rules late in 2011. 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.

 

Greenhouse Gas Emissions

 

There is an increased global focus over the direction of climate change policy. There are currently no federal CO₂ emission regulations with which our plants must comply. However, the United States Congress is considering legislation that would impose mandatory limitation of CO₂ and other greenhouse gas emissions for the domestic power generation sector. In addition, several states in the northeast, midwest and west are increasingly active in developing state-specific or regional regulatory initiatives to stimulate CO₂ emission reductions in the electric power generation industry and other industries.

 

Ten northeastern states, including New Jersey and Maryland, formed the Regional Greenhouse Gas Initiative, or RGGI, which requires power generators to reduce CO₂ emissions by 10% by 2019, beginning in 2009. California adopted legislation designed to reduce greenhouse gas emissions to 25% below 1990 levels by 2020, beginning in 2012. In July 2008, the Pennsylvania Climate Change Act was adopted. This legislation requires development of reports of the impacts of climate change in Pennsylvania and potential economic opportunities resulting from mitigation strategies. It also requires development of an annual state-level greenhouse gas emissions inventory and establishment of cost-effective state-level strategies for reducing or offsetting greenhouse gases.

 

In addition, the EPA issued two regulatory findings in December 2009 that are preliminary steps to establishing regulations limiting greenhouse gas emissions. Assuming the EPA finalizes these regulations, New Source Review requirements may apply if a permit is sought for new construction or a major modification to an existing plant, including application to CO₂ emissions of a yet to be defined best available control technology standard. Individual states may also begin to take into account CO₂ emissions when considering permits to construct or modify significant sources of emissions. In 2009, our plants emitted approximately 20.8 million metric tons of CO₂, approximately 90% of which was from our East Coal segment. The amount of CO₂ emissions from our plants will depend on their dispatch time during the period.

 

In September 2007, we joined the Chicago Climate Exchange, a voluntary greenhouse gas registry, reduction and trading system. By joining the exchange, we have committed to reduce our annual greenhouse gas emissions to six percent below the average of our 1998-2001 levels by 2010 (no more than 28.6 million metric tons in 2010). We continue to satisfy our reduction targets through previously implemented plant retirements and capacity factor reductions, ongoing heat rate improvement efforts and transacting on the exchange.

 

Water Regulations

 

In July 2007, the EPA suspended its 2004 regulations relating to cooling water intake structures at large existing power plants pending further rulemaking. This action was in response to the Second Circuit Court of Appeals’ January 2007 remand of several provisions in the 2004 regulations. In April 2009, the U.S. Supreme Court overturned the Second Circuit on one issue, ruling that the Clean Water Act does not prohibit using cost-benefit analysis in determining appropriate control requirements for cooling water intake structures. The EPA has stated it plans to issue a proposed rule in mid-2010 and has retained interim requirements that plant intakes employ best technology available controls as determined on a plant-by-plant, best professional judgment basis.

To comply with existing federal rules and subject to market conditions, we may install a cooling tower at one or more of our Shawville, Pennsylvania units for up to $80 million over several years, expected to begin no sooner than 2012.

 

In September 2009, the EPA announced its intent to revise effluent limitation guidelines for the power generation industry, which are anticipated to result in more stringent regulation. These regulations are applicable to the majority of our plants.

 

The California State Water Resources Control Board is considering a policy that could result in phasing out the use of coastal water for once-through cooling. If regulations follow this policy, affected plants could be required to install cooling towers or be removed from service. This regulation could impact our Mandalay and Ormond Beach plants.

 

Coal Combustion Products

 

Existing state and federal rules require the proper management and disposal of potentially hazardous wastes and other materials. The EPA currently classifies coal combustion products such as fly ash as non-hazardous waste products. Currently, we expect to spend approximately $50 million for ash landfill expansions including approximately $7 million in each of 2010 and 2011 and the remaining amount over several later years. There is increased focus on the regulation of coal combustion products and, if their classifications change, we may be required to change our waste management practices or incur additional costs.

 

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 believe we properly manage and dispose of such materials in compliance with state and federal rules. See note 16(b) to our consolidated financial statements.

 

We do not believe we have any material liabilities or obligations under the Comprehensive Environmental Response Corporation and Liability Act of 1980 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.

 

As of December 31, 2009, we had 2,239 full-time and part-time employees. Of these employees, 1,017 are covered by collective bargaining agreements, which expire on various dates from March 31, 2010 through September 30, 2014. The following table sets forth the number of our employees as of December 31, 2009:

 

 

 

 

 

Mark M. Jacobs has served as our President and Chief Executive Officer since May 2007. Prior to that, he served as our Executive Vice President and Chief Financial Officer from July 2002 to October 2007.

 

David D. Brast has served as our Senior Vice President, Commercial Operations and Origination since May 2009. Prior to that, he served as Vice President, Commercial Operations and Origination from June 2003 to May 2009.

 

Rick J. Dobson has served as our Executive Vice President and Chief Financial Officer since October 2007. Prior to that, he served as Senior Vice President and Chief Financial Officer of Novelis Inc., an international aluminum rolling and recycling company, from July 2006 to August 2007 and Senior Vice President and Chief Financial Officer of Aquila, Inc., an electric and natural gas distribution company that also owns and operates generation assets, from October 2002 to July 2006.

 

David S. Freysinger has served as our Senior Vice President, Generation Operations since January 2004.

 

D. Rogers Herndon has served as our Executive Vice President, Strategic Planning and Business Development since June 2009. He served as our Senior Vice President, Strategic Planning and Business Development from November 2007 to June 2009. He was Senior Vice President, Commercial Operations and Origination from May 2006 to November 2007. Prior to that, he was a Managing Director for PSEG Energy Resources and Trade from April 2003 to December 2005.

 

Michael L. Jines has served as our Executive Vice President, General Counsel and Corporate Secretary and Chief Compliance Officer since June 2009. He served as our Senior Vice President, General Counsel and Corporate Secretary from May 2003 to June 2009.

 

Thomas C. Livengood has served as our Senior Vice President and Controller since May 2005. Prior to that, he served as our Vice President and Controller from August 2002 to May 2005.

 

Albert H. Myres has served as our Senior Vice President, Government and Public Affairs since December 2007. He served as Shell Oil Corporation’s Chief of Staff and Senior Advisor to the President and Country Chairman from August 2005 to December 2007 and Senior Advisor, Government Affairs from June 2002 to August 2005.

 

Karen D. Taylor has served as our Senior Vice President, Human Resources since December 2003. In November 2005, she was appointed as our Chief Diversity Officer.

 

Our principal offices are at 1000 Main, Houston, Texas 77002 (832-357-7000). The following information is available free of charge on our website (http://www.rrienergy.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 business ethics policy on our website. No information on our website is incorporated by reference into this Form 10-K. In addition, certain of these materials 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 will timely provide the annual certification of our Chief Executive Officer to the New York Stock Exchange. We filed last year’s certification in July 2009. In addition, our Chief Executive Officer and Chief Financial Officer each have signed and filed the certifications under Section 302 of the Sarbanes-Oxley Act of 2002 with this Form 10-K.

 

 

We are subject to the following factors that could affect our future performance and results of operations. Also, see “Forward-Looking Statements” on page iii, “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.

 

Our financial results are subject to market factors beyond our control. We are exposed to the risk of loss if third parties fail to perform their contractual obligations.

 

Our results of operations, financial condition and cash flows are significantly impacted by the prevailing demand and market prices for electricity, capacity, fuel and emission allowances over which we have no control. Demand or market prices can fluctuate dramatically in response to many factors, including seasonal and weather conditions; changes in the prices of related commodities; changes in law and regulation; regulatory intervention (including the imposition of price limitations, bidding rules or similar mechanisms); market illiquidity; transmission constraints; environmental limitations; generation unit outages; fuel supply issues; economic conditions; and other events.

 

Current economic conditions may result in ongoing reduced demand for electricity, commodity price volatility, increased risk of third-party default, changes in law or regulation and other events. We depend on fuel sources and fuel supply facilities owned and operated by third parties to supply our plants. We depend on power transmission facilities owned and operated by third parties to deliver electricity to our customers. We may incur losses if third parties default on their contractual obligations, such as obligations to buy or sell electricity, capacity, fuel or emission allowances; or provide us with fuel and related transportation services or power transmission services. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Credit Risk” in Item 7 of this Form 10-K and note 2(c) to our consolidated financial statements.

We operate in relatively immature markets that are characterized by elements of both competitive and regulated markets. Changes in the regulatory environment in which we operate could adversely affect our ability to sell at market rates, or the cost, manner or feasibility of conducting our business.

 

We operate in a regulatory environment that is undergoing varying restructuring initiatives. In many instances, the regulatory structures governing the electricity markets are still evolving, creating gaps in the regulatory framework and associated uncertainty. In addition, existing regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to our plants or our commercial activities. We cannot predict the future direction of these initiatives or the ultimate effect that this changing regulatory environment will have on our business. However, future regulatory restrictions, regulatory or political intervention or changes in laws and regulations, may constrain our ability to sell at market prices or otherwise have an adverse effect on our business.

 

The majority of our generation is sold at market prices under market-based rate authority granted by the FERC. Even where market-based rate authority has been granted, the FERC can impose various forms of market mitigation measures, including price caps and operating restrictions. If we lost our market-based rate authority, we may incur additional costs and risks. We also participate in regional power pools, reliability councils, transmission organizations and capacity auctions. Changes in the rules governing such auctions or groups and/or in the composition of such groups may have an adverse effect on our business. Participation in RTOs is voluntary, and transmission owning companies or other RTO members may exit an RTO so long as they do so in compliance with the applicable FERC tariffs and agreements and FERC approval. See “Business—Markets” in Item 1 of this Form 10-K.

 

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 plants. Failure to comply with environmental requirements could require us to shut down or reduce production at our plants or could create liability exposure. 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 plants. We also may be subject to claims for the environmental liabilities associated with plants even if a prior owner caused the liabilities.

 

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

 

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 16(b) to our consolidated financial statements.

 

The operation of plants involves significant risks that could limit, interrupt or shut down operations and increase our costs.

 

We are exposed to risks relating to the breakdown of our plant equipment or processes; performance below expected levels of output or efficiency; fuel supply or transportation failures or interruptions;

maintenance or construction delays or cost overruns; shortages of or delays in obtaining equipment, material and labor; operational restrictions resulting from environmental limitations and governmental interventions; as well as other risks that could increase our cost of doing business or could cause extended and/or unplanned outages of our plants. If a plant fails or is unavailable, we may have to purchase replacement power from third parties at higher prices and/or we may be subject to contractual or other penalties. In addition, many of our plants are old and require significant maintenance expenditures.

 

We are party to collective bargaining agreements with labor unions at several of our plants. If our workers were to engage in a strike, work stoppage or other slowdown, other employees were to become unionized or the terms and conditions in future labor agreements were renegotiated, we could experience a significant disruption in our operations and higher ongoing labor costs. Similarly, we have an aging workforce at a number of our plants creating potential knowledge and expertise gaps as those workers retire.

 

To operate our plants, we must obtain and maintain various permits, licenses, approvals and certificates from governmental agencies. Our failure to obtain or maintain any necessary governmental permits or licenses or to satisfy these legal requirements, including environmental compliance provisions, could limit our ability to operate our plants.

 

We have insurance, subject to limits and deductibles, covering some types of physical damage and business interruption related to our plants. However, this insurance may not always be available on commercially reasonable terms. In addition, there is no assurance that insurance proceeds will be sufficient to cover all losses, insurance payments will be timely made or the policies themselves will be free of substantial deductibles.

 

Competition and alternative technologies 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. Our competitors may have greater access to capital and lower cost structures and/or more efficient power generation facilities. In addition, aggregate demand for power may be met by generation capacity based on competing technologies, as well as power generation facilities fueled by alternative or renewable energy sources. Regulatory initiatives designed to enhance renewable generation could increase competition from these types of facilities.

 

Our largely unhedged position may cause volatile financial results and any hedging may be ineffective.

 

We are largely unhedged based on our views of the market. Our uncontracted generation is generally sold on the spot market at current market prices; however, we must maintain coal supply to operate. Therefore, fluctuating commodity prices can affect our financial results and financial position, either favorably or unfavorably. To the extent we hedge, our hedges may not be effective as a result of basis price differences, transmission issues, price correlation, volume variations, margins being compressed as a result of market prices behaving differently than expected or other factors. See note 2(e) to our consolidated financial statements and “Quantitative and Qualitative Disclosures About Market Risk” in Item 7A of this Form 10-K.

 

Changes in the wholesale energy market or in our plant 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 plants, we could have impairment charges related to our fixed assets. 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 plants 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 4 to our consolidated financial statements.

Significant events beyond our control, such as weather-related problems or acts of terrorism, could have a material adverse effect on our business.

 

The uncertainty associated with events beyond our control, such as significant weather events, including unseasonable conditions and possible effects from climate change, if any, and the risk of future terrorist activity, may affect our results of operations and financial condition in unpredictable ways. These events could result in a decrease in the demand for power, adverse changes in the insurance markets, disruptions of power and fuel markets or hedging transactions becoming ineffective. In addition, significant weather events or terrorist actions could damage or shut down our plants or the fuel and fuel supply facilities or the power transmission facilities upon which our plants are dependent. These events could also adversely affect the United States economy, create instability in the financial markets and, as a result, have an adverse effect on our ability to access capital on terms and conditions acceptable to us. We are also highly dependent on our specialized computer and communications systems, the operation of which could be interrupted by fire, flood, power loss, computer viruses or similar disruptions. There is no guarantee that our backup systems and disaster recovery plans will be effective. Our business interruption insurance may be limited, as discussed above under “—The operation of plants involves significant risks that could limit, interrupt or shut down operations and increase our costs.”

 

Our borrowing levels, debt service obligations and restrictive covenants may adversely affect our business. We may be vulnerable to reductions in our cash flow.

 

As of December 31, 2009, we had total debt of $2.4 billion and off-balance sheet RRI Energy Mid-Atlantic Power Holdings, LLC (REMA) leases of $423 million (collectively referred to below as debt or debt service).

 

 

If we were unable to generate sufficient cash flows, access funds from operations or raise cash from other sources, we would not be able to meet our debt service and other obligations. These situations could result from adverse developments in the economy or in the power, fuel or capital markets, a disruption in our operations or those of third parties, or other events adversely affecting our cash flows and financial performance.

 

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. These proceedings involve highly subjective matters with complex factual and legal questions. Their outcome is uncertain. Any claim that is successfully asserted against us could result in significant damage claims and other losses. 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 14, 16 and 17 to our consolidated financial statements.

 

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

 

We may seek to purchase or develop additional plants, dispose of existing plants, 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.

 

 

None.

 

 

Our principal executive offices are leased through 2018, subject to two five-year renewal options. Our plants are described under “Business—Operations” in Item 1 of this Form 10-K. We believe that our properties are adequate for our present needs. 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.

 

 

For a description of our material pending legal and regulatory proceedings and settlements, see notes 16 and 17 to our consolidated financial statements.

 

 

None.

 

 

Our common stock trades on the New York Stock Exchange under the ticker symbol “RRI.” On February 11, 2010, we had 33,948 stockholders of record. The closing price of our common stock on December 31, 2009 was $5.72. We have never paid dividends. Some of our debt agreements restrict the payment of dividends. See note 7 to our consolidated financial statements.

 

 

The following line graph compares the yearly percentage change in our cumulative total stockholder return on common stock with cumulative total return of a broad equity market index (Standard & Poor’s 500 Stock Index), the cumulative total return of a group of our peer companies comprised of Allegheny Energy, Inc., Calpine Corporation, Dynegy Inc., Mirant Corporation, NRG Energy, Inc. and PPL Corporation, and the cumulative total return of a group of peer companies we used for 2008, comprised of Calpine Corporation, Constellation Energy Group, Inc., Dominion Resources, Inc., Dynegy Inc., Exelon Corporation, Mirant Corporation, NRG Energy, Inc., Sempra Energy and TXU Corp. In 2009, we changed our group of peer companies following the sale of our former retail business. This stock price performance graph is furnished in this Form 10-K and is not filed, as permitted by 17 CFR 229.201(e).

 

 

 

 

 

Business Overview

 

Strategy.  We provide energy, capacity, ancillary and other energy services to wholesale customers in competitive power generation markets in the United States. Our objective is to be the best performing, best positioned generator in competitive electricity markets.

 

The power generation industry is deeply cyclical and capital intensive. Given the nature of the industry, we believe scale and diversity are important long term. Given these beliefs, our strategy is to:

 

 

 

The current market environment is challenging given the uncertainty in the financial markets, possible legislative and regulatory environmental matters and the pace of economic and power demand recovery. Additionally, current commodity prices and spreads are depressed relative to historical levels. While we believe these conditions will improve, the timing is uncertain. Our primary focus is on managing the risks of operating in this current environment.

 

We have taken a number of actions to navigate the current market challenges, capture the value of our existing assets and position us for the longer term market recovery, while maximizing cash flow and building ample liquidity. Some of these actions include:

 

 

We are regularly assessing the impact on our business of a wide variety of economic and commodity price scenarios, and believe we have the ability to operate through an extended downturn, if that should occur.

 

Key Earnings Drivers.  Our financial results are significantly impacted by supply and demand fundamentals in the regions in which we operate as well as the spread between gas and coal prices. Plants with lower costs dispatch ahead of higher cost plants to meet demand, with the price of electricity being set by the last plant dispatched.

 

The specific factors that drive our margins include the prices of power, capacity, natural gas, coal and fuel oil, the cost of emission allowances and transmission, as well as weather and economic factors, many of which are volatile. Our ability to control these factors is limited, and in most instances, the factors are beyond our control. We have the most control over the percentage of time that our plants are available to run when it is economical for them to do so (commercial capacity factor). Our key earnings drivers and various factors that affect these earnings drivers include:

 

Economic generation (amount of time our plants are economical to operate)

 

 

Commercial capacity factor (generation as a percentage of economic generation)

 

 

Unit margin

 

 

Other margin (primarily capacity sales)

 

Costs

 

 

Hedges

 

 

Flexible Plant-Specific Operating Model.  We have different operating approaches for our plants. These operating approaches are determined by each plant’s condition, environmental controls, profitability, market rules, upside potential and value drivers. We have separated our plants into four groups for the purpose of developing an operating model.

 

 

As described above, the plants comprising each of these four groups are similarly situated particularly with regard to profitability, upside potential and our expectation of future environmental investment based on current market conditions. Therefore, we believe that presenting the amount of open gross margin for each group provides an additional way of viewing our operations and facilitates understanding of the factors and trends affecting our business. The above amounts exclude open gross margin relating to (a) our previously-owned Bighorn plant and Channelview plant ($49 million during 2007), (b) selective commercial strategies not designated to a specific plant but related more to a geographical region ($(3) million, $35 million and $39 million during 2009, 2008 and 2007, respectively) and (c) other insignificant items ($1 million, $1 million and $(2) million during 2009, 2008 and 2007, respectively). See “—Consolidated Results of Operations” for the reconciliations of open gross margin to loss from continuing operations.

 

Pending Environmental Matters.  We make decisions to invest in environmental capital projects based on relatively certain regulations and the expected economic returns on the capital. As discussed above, we expect future environmental investments would most likely be considered in our near-term profit/controls group of plants.

 

The EPA has stated that it expects to finalize a new rule to replace CAIR in 2011. Various agencies, including the EPA, are considering other regulations related to national ambient air quality standards and hazardous air pollutants. The following table lists the coal plants in our near-term profit/controls group that may be impacted by this new rule and preliminary estimates, stated in 2009 dollars, of additional investments that we could consider as a result. We expect these estimates will change as more information becomes available regarding the nature and timing of the potential investments.

 

 

The impact on our business of these pending regulations and whether we make any of the potential investments is uncertain and depends on the form (whether cap-and-trade or MACT), content and timing of the regulations, the effect of the regulations on wholesale power prices and allowance prices, as well as the cost of controls, profitability of our plants, market conditions at the time and the likelihood of CO₂ regulation. We may choose to not make any of the potential investments listed above.

 

The costs associated with more stringent environmental air quality requirements may result in coal plants, including some of ours, being retired sooner than currently contemplated. However, 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 fleet.

 

Furthermore, the United States Congress is considering legislation that would impose mandatory limitation of CO₂ and other greenhouse gas emissions for the domestic power generation sector. State-specific or regional regulatory initiatives to stimulate CO₂ emission reductions in our industry are increasingly active. The impact on our business of these matters are uncertain and depends on the form and content of resulting regulations, including whether and to what extent allowances are allocated to us, the timing of resulting regulations and their effect on wholesale power prices and allowance prices, the profitability of our plants and market conditions at the time, as well as whether and to what extent there are cost effective control technologies or energy efficiency measures available to reduce emissions at our plants.

 

If CO₂ legislation or regulation transpires, we expect that the demand for gas and/or renewable sources of energy will increase over time. This could decrease economic generation at coal plants. Implementation of a CO₂ cap-and-trade program in addition to other emission control requirements could increase the likelihood of coal plant retirements.

Given the uncertainty related to these pending environmental matters, we cannot predict the actual outcome or ultimate impact of these matters on our business. See “—Liquidity and Capital Resources” below, “Business—Environmental Matters” in Item 1A of this Form 10-K and note 16(b) to our consolidated financial statements for further discussion.

 

Effectiveness and Efficiency Measures for 2010.  Consistent with our flexible plant-specific operating model, our objective is to operate each plant to capture the maximum value at the lowest economical cost over time. We plan to use total margin capture factor to measure our effectiveness of achieving this objective. Total margin capture factor is calculated by dividing open gross margin generated by the plants by the total available open gross margin assuming 100% availability. We plan to measure our efficiency of capturing margin utilizing total cost per MWh generated and total cost per MW of generation capacity. These costs metrics will include operation and maintenance expense (excluding the REMA lease expense) and general and administrative expense as well as maintenance capital expenditures.

 

Impairments of Long-Lived Assets.  In December 2009, we evaluated each of our plants including the related intangible assets for potential impairments. We determined that two plants’ (New Castle and Indian River) undiscounted cash flows did not exceed the carrying value of the net property, plant and equipment and related intangible assets. Thus, we estimated each plant’s fair value and determined we incurred pre-tax impairment charges of $211 million. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—New Accounting Pronouncements, Significant Accounting Policies and Critical Accounting Estimates” in Item 7 of this Form 10-K and note 4 to our consolidated financial statements for further discussion.

 

Exit of Retail Business.  In December 2008, we sold our Northeast retail commercial, industrial and governmental/institutional (C&I) contracts. In May 2009, we sold our Texas retail business. In December 2009, we sold our Illinois retail C&I contracts. The sale of the retail business achieved the following important strategic objectives for us:

 

 

2009 Compared to 2008 and 2008 Compared to 2007

 

Following the sale of our Texas retail business and commencing in the third quarter of 2009, we have four reportable segments: East Coal, East Gas, West and Other. We have presented the segment information in this report on a consistent basis for 2009, 2008 and 2007. See note 20 to our consolidated financial statements.

 

Our income/loss from continuing operations before income taxes for 2009 compared to 2008 changed by $630 million (income in 2008 of $26 million compared to loss in 2009 of $604 million) primarily due to (a) open gross margin, which decreased by $430 million due to open energy unit margins declining $16/MWh driven by weak commodity prices, weak economic conditions and mild summer and early winter weather and (b) hedges and other items, which changed by $385 million primarily due to out-of-the money coal hedges in 2009 compared to in-the-money coal hedges in 2008. These items were partially offset by (a) the difference between the goodwill impairment of $305 million in 2008 and the long-lived assets impairments of $211 million in 2009 and (b) $45 million of lower operation and maintenance expense primarily attributable to the use of our plant-specific operating model.

 

Our income/loss from continuing operations before income taxes for 2008 compared to 2007 changed by $388 million (loss in 2007 of $362 million compared to income in 2008 of $26 million) primarily due to (a) hedges and other items, which changed by $337 million primarily due to in-the-money coal hedges in 2008 and lower losses on our closed power hedges, (b) debt extinguishments losses decreased by $112 million, (c) $110 million decrease in interest expense and operation and maintenance expense and (d) $85 million

decrease in depreciation and amortization. These items were partially offset by the goodwill impairment in 2008 of $305 million.