Item 1. Business
Overview
We are a competitive energy company that produces and sells electricity. We own or lease 10,280 MW of electric generating capacity located in markets in the Mid-Atlantic (5,244 MW) and Northeast regions (2,689 MW) and in California (2,347 MW). We also operate an integrated asset management and energy marketing organization based in Atlanta, Georgia. Our customers are ISOs, investor-owned utilities, municipal systems, aggregators, electric cooperative utilities, producers, generators, marketers and large industrial customers. Our generating portfolio is diversified across fuel types, power markets and dispatch types and serves customers located near many major metropolitan load centers. Our total net generating capacity is approximately 31% baseload, 57% intermediate and 12% peaking.
Mirant North America is a Delaware limited liability company, a wholly-owned subsidiary of Mirant Americas Generation and an indirect wholly-owned subsidiary of Mirant. Mirant Corporation was incorporated in Delaware on September 23, 2005. Pursuant to the Plan for Mirant and certain of its subsidiaries, on January 3, 2006, New Mirant emerged from bankruptcy and acquired substantially all of the assets of Old Mirant, a corporation that was formed in Delaware on April 3, 1993, and that had been named Mirant Corporation prior to January 3, 2006.
In the third quarter of 2006, Mirant commenced auction processes to sell six U.S. natural gas-fired facilities including the Zeeland and Bosque facilities. On May 1, 2007, we completed the sale of the Zeeland and Bosque natural gas-fired facilities. In addition, on May 7, 2007, we completed the sale of Mirant NY-Gen, an indirect wholly-owned subsidiary. In accordance with our debt covenants, approximately $524 million of the proceeds from the sale of the Zeeland and Bosque facilities are being reinvested in the business. At December 31, 2007, $273 million of such proceeds have been reinvested in the business. See Note 10 to our consolidated and combined financial statements contained elsewhere in this report for additional information regarding the accounting for these facilities as discontinued operations.
On April 9, 2007, Mirant announced that its Board of Directors had decided to explore strategic alternatives to enhance stockholder value. In the exploration process, the Board of Directors considered whether the interests of stockholders would be best served by returning excess cash from the sale proceeds to stockholders, with Mirant continuing to operate its retained businesses or, alternatively, whether greater stockholder value would be achieved by entering into a transaction with another company, including a sale of Mirant in its entirety. On November 9, 2007, Mirant announced the conclusion of the strategic review process. Mirant plans to return a total of $4.6 billion of excess cash to its stockholders.
The accompanying consolidated financial statements include the accounts of Mirant North America and reflect the effects of the Plan as of December 31, 2005, including:
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The contribution by Mirant of its interest in Mirant Potomac River and Mirant Peaker to our indirect wholly-owned subsidiary, Mirant Mid-Atlantic, and its interest in Mirant Zeeland and in Mirant Americas Energy Marketing, Mirant Americas Development, Inc., Mirant Americas Production Company, Mirant Americas Energy Capital, LLC, Mirant Americas Energy Capital Assets, LLC, Mirant Americas Development Capital, LLC, Mirant Americas Retail Energy Marketing, LP, and Mirant Americas Gas Marketing I-XV, LLCs (collectively, the “Trading Debtors”) to us. All of the contributed subsidiaries were under the common control of Mirant and are collectively referred to as the “Contributed Subsidiaries.”
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The transfer of the trading and marketing business of the Trading Debtors to Mirant Energy Trading, a wholly-owned subsidiary of Mirant North America. After these transfers took place on January 31, 2006, the Trading Debtors were transferred to a trust created under the Plan that is not affiliated with us.
The accompanying 2005 combined financial statements present our results of operations and cash flows based on the assets, liabilities and operations of the predecessor Contributed Subsidiaries.
The annual, quarterly and current reports, and any amendments to those reports, that we file with or furnish to the SEC, are available free of charge on Mirant’s website at www.mirant.com as soon as reasonably practicable after they are electronically filed with or furnished to the SEC. Information contained on this website is not incorporated into this Form 10-K.
Business Segments
We have four operating segments: Mid-Atlantic, Northeast, California and Other Operations. The Mid-Atlantic segment consists of four generating facilities located in Maryland and Virginia. The Northeast segment consists of five generating facilities located in Massachusetts and New York. The California segment consists of three generating facilities located in or near the City of San Francisco. Other Operations includes proprietary trading, fuel oil management and, for periods prior to 2006, includes gains and losses related to a long-term PPA with Pepco (the “Back-to-Back Agreement”) and the transition power agreement with Pepco that expired in January 2005. See Note 15 to our consolidated and combined financial statements contained elsewhere in this report for further discussion of the Back-to-Back Agreement. Other Operations also includes interest on our debt and interest income on our invested cash balances.
The table below presents our power generating performance metrics for the year ended December 31, 2007:
The table below summarizes selected financial information of our continuing operations by business segment for the year ended December 31, 2007 (dollars in millions):
Eliminations are primarily related to intercompany sales of emissions allowances and interest on intercompany notes receivable and notes payable. For selected financial information about our business segments, see Note 13 to our consolidated and combined financial statements contained elsewhere in this report. See Item 2. Properties for a complete list of our operating plants.
Commercial Operations
Our commercial operations consist primarily of procuring fuel, dispatching electricity, hedging the production and sale of electricity by our generating facilities, managing fuel oil and providing logistical support for the operation of our facilities (for example, by procuring transportation for coal). We typically sell the electricity we produce into the wholesale market at prices in effect at the time we produce it (the “spot price”). Spot prices for electricity are volatile, as are prices for fuel and emissions allowances, and in order to reduce the risk of that volatility and achieve more predictable financial results, it is our strategy to enter into hedges-forward sales of electricity into the wholesale market and forward purchases of fuel and emissions allowances to allow us to produce and sell the electricity-for various time periods. In addition, given the high correlation between natural gas prices and electricity prices, we enter into forward sales of natural gas to hedge 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. We also sell capacity and ancillary services where there are markets for such products and when it is economic to do so. In addition to selling the electricity we produce and buying the fuel and emissions allowances we need to produce electricity (“asset management”), we buy and sell some electricity, fuel and emissions allowances as part of our proprietary trading and fuel oil management activities. Proprietary trading is a small part of our commercial operations. We engage in proprietary trading to gain information about the markets to support our asset management and to take advantage of selected opportunities that we identify from time to time. All of our commercial activities are governed by a comprehensive Risk Management Policy, which requires that our hedging activities with respect to our assets be risk-reducing and sets limits on the size of positions and VaR in our proprietary trading and fuel oil management activities.
We use dispatch models to assist us in making daily decisions regarding the quantity and price of the power our facilities will generate and sell into the markets. We bid the energy from our generating facilities into the day-ahead energy market and sell ancillary services through the ISO markets. We sell capacity either bilaterally or through auction processes in each ISO in which we participate. 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.
We economically hedge a substantial portion of our Mid-Atlantic coal-fired baseload generation and certain of our Northeast coal, gas and oil-fired generation through OTC transactions. A significant portion of our hedges are financial swap transactions that are senior unsecured obligations of Mirant Mid-Atlantic and do not require the posting of cash collateral either for initial margin or for securing exposure as a result of changes in power or natural gas prices. However, we generally do not hedge our intermediate and peaking units for tenors greater than 12 months. At February 25, 2008, we were economically hedged as follows:
Our commercial operations manage the acquisition and utilization of emissions allowances for our generating facilities. Primarily as a result of the pollution control equipment we are installing to comply with the requirements of the Maryland Healthy Air Act, we anticipate that we will have significant excess emissions allowances in future periods. We plan to continue to maintain some emissions allowances in excess of expected generation in case our actual generation exceeds our current forecasts for future periods and for possible future additions of generating capacity. During the fourth quarter of 2007, we began a program to sell excess emissions allowances, dependent upon market conditions. We sold approximately $24 million of excess emissions allowances and recognized a gain of $22 million, which is included in gain on sales of assets in the consolidated statement of operations for the year ended December 31, 2007. At December 31, 2007, the estimated fair value of our excess emissions allowances exceeded the carrying value recorded on our consolidated balance sheet by approximately $200 million.
While OTC transactions make up a substantial portion of our economic hedge portfolio, at times we sell non-standard, structured products to customers. Additionally, our California facilities operate under long-term contracted capacity and RMR contracts.
We enter into contracts of varying terms to secure appropriate quantities of fuel to meet the varying specifications of our generating facilities. For our coal-fired generating facilities, we purchase coal from a variety of suppliers under contracts with terms of varying lengths, some of which extend to 2012. Our hedged percentages for fuel include transactions for which commercial terms have been negotiated but for which contracts have not yet been executed. Individual transactions may or may not be binding prior to execution of a contract. For our gas-fired units, we typically purchase fuel under short-term contracts with a variety of suppliers on a day-ahead or monthly basis.
Our coal supply comes primarily from the Central Appalachian and Northern Appalachian coal regions. All of our coal is delivered by rail; however, we are in the process of constructing a barge unloading facility at our Morgantown station that is expected to become operational in the third quarter of 2008. The barge unloader will enable us to receive coal from international locations as well. We monitor coal supply and delivery logistics carefully and, despite occasional interruptions of scheduled deliveries, to date we have managed to avoid any significant effects on our operations. We maintain an inventory of coal at our coal-fired facilities for this purpose. Interruptions of scheduled deliveries can result from a variety of disruptions, including strikes, rail system disruptions or severe weather.
Mid-Atlantic Region
We own or lease four generating facilities in the Mid-Atlantic region with total net generating capacity of 5,244 MW. Our Mid-Atlantic region had a combined 2007 net capacity factor of 37%.
Power generated by our Mid-Atlantic facilities is sold into the PJM market. For a discussion of the PJM market, see “Regulatory Environment” below. We have participated in standard offer service auctions in Maryland and Washington, D.C. Power sales, either directly through these auctions or indirectly through subsequent market transactions that are a result of the auction process, serve as economic hedges for the Mid-Atlantic facilities.
The following table presents the details of our Mid-Atlantic generating facilities:
The Chalk Point facility is our largest generating facility. It consists of two coal-fired baseload units, two dual-fueled (oil and gas) intermediate units and two oil-fired and five dual-fueled (oil and gas) peaking units. Our next largest facility is the Morgantown facility. It consists of two dual-fueled (coal and oil) baseload units and six oil-fired peaking units. The Dickerson facility has three coal-fired baseload units, and one oil-fired and two dual-fueled (oil and gas) peaking units. The Potomac River station has three coal-fired baseload units and two coal-fired intermediate units.
On May 23, 2007, the Virginia State Air Pollution Control Board directed the Virginia DEQ to issue a state operating permit (the “Permit”) for the Potomac River facility that significantly restricted the facility's operations by imposing stringent limits on its SO2 emissions and constraining unit operations so that no more than three of the facility’s five units can operate at one time. We think these limits and constraints are unreasonable and arbitrary. The Virginia DEQ issued the Permit as directed on June 1, 2007. In June 2007, Mirant Potomac River filed a petition for appeal in the Circuit Court of the City of Richmond, Virginia, seeking to set aside the Virginia State Air Pollution Control Board’s directive of May 23, 2007, and the Permit issued by the Virginia DEQ on June 1, 2007. The Virginia State Air Pollution Control Board stated that the Permit is intended to be supplanted by a more comprehensive permit that it expects to issue. On October 19, 2007, the Virginia DEQ published a draft of this more comprehensive permit to solicit comments from the public. If adopted as proposed, this comprehensive permit would also impose stringent limits on SO2 emissions that would continue to limit Mirant Potomac River to operating no more than three of the five units of the Potomac River generating facility at any one time. On November 30, 2007, the Virginia State Air Pollution Control Board directed the Virginia DEQ to develop an alternative state operating permit that would require completion of a proposed project to merge the stacks of certain of the units at the Potomac River facility, set a single SO2 emissions limit for the facility and allow for greater operating flexibility. On December 21, 2007, the Virginia DEQ published a draft of this alternative state operating permit for public comment. If approved as currently drafted with some minor modifications, this alternative state operating permit would enable Mirant Potomac River to operate all five units of the facility at one time. We anticipate that the Virginia State Air Pollution Control Board will consider the proposed permit in March 2008.
Northeast Region
We own generating facilities in the Northeast region with total net generating capacity of 2,689 MW. Our Northeast region had a combined 2007 net capacity factor of 22%. The Northeast region is comprised of our facilities located in New York and New England. Generation is sold from our Northeast facilities through a combination of bilateral contracts, spot market transactions and structured transactions.
The following table presents the details of our facilities in the Northeast Region:
New York. The capacity, energy and ancillary services from our New York generating facilities are sold into the bilateral markets and into the markets administered by the NYISO. For a discussion of NYISO, see “Regulatory Environment” below.
The New York generating facilities consist of the Bowline and Lovett facilities. The Bowline facility is a dual-fueled (natural gas and oil) facility comprised of two intermediate/peaking units. The Lovett facility consists of one baseload unit capable of burning coal and gas.
Significant developments related to these generating facilities in 2007 were as follows:
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On January 26, 2007, Mirant New York, Mirant Bowline (which owns the Bowline facility) and Hudson Valley Gas (collectively the “Emerging New York Entities”) filed their Supplemental Joint Chapter 11 Plan of Reorganization with the Bankruptcy Court and subsequently filed amendments to that plan (as subsequently amended, the “Supplemental Plan”). The Supplemental Plan was confirmed by the Bankruptcy Court on March 23, 2007, and became effective on April 16, 2007.
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In the second quarter of 2007, we shut down units 3 and 4 at the Lovett facility. On October 20, 2007, Mirant Lovett submitted notices of its intent to discontinue operation of unit 5 at the Lovett generating facility as of midnight on April 19, 2008, to the New York Public Service Commission, the NYISO, Orange and Rockland and several other potentially affected transmission and distribution companies in New York.
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On July 13, 2007, Mirant Lovett (which owns the Lovett facility) filed a plan of reorganization (the “Mirant Lovett Plan”) with the Bankruptcy Court. The Mirant Lovett Plan was confirmed by the Bankruptcy Court on September 19, 2007, and became effective on October 2, 2007. As a result of Mirant Lovett’s emergence from bankruptcy, we do not have any subsidiaries remaining in bankruptcy. See Note 11 to our consolidated and combined financial statements contained elsewhere in this report for additional information regarding the emergence from bankruptcy of Mirant Lovett and the Emerging New York Entities.
New England. The Canal facility consists of one oil-fired intermediate unit and one dual-fueled (oil and gas) intermediate unit. The Kendall facility consists of one combined cycle dual-fueled (oil and gas) baseload unit, two 1,300 pound steam boilers and one simple cycle jet engine peaking unit. The Martha’s Vineyard facility consists of five diesel peaking units.
The capacity, energy and ancillary services from our New England generating units are sold into the NEPOOL bilateral markets and into the markets administered by the ISO-NE. For a discussion of the NEPOOL and the ISO-NE, see “Regulatory Environment” below.
California
We own three generating facilities in California with total net generating capacity of 2,347 MW. Our California facilities had a combined 2007 net capacity factor of 4%. The following table presents the details of our California facilities:
The Pittsburg and Contra Costa facilities are located in Contra Costa County and the Potrero facility is located in the City of San Francisco. Through the end of 2006, the majority of our California units were subject to RMR arrangements with the CAISO. These agreements are described further under “Regulatory Environment” below. Pittsburg unit 7 and Contra Costa unit 6 were not subject to an RMR arrangement, and thus functioned solely as merchant facilities in the CAISO. In 2006, we either sold the output of Pittsburg unit 7 and Contra Costa unit 6 into the market through bilateral transactions with utilities and other merchant generators, or dispatched the units in the CAISO clearing markets.
On July 28, 2006, we signed two tolling agreements with PG&E to provide electricity from all our natural gas-fired units in service at Pittsburg and Contra Costa, including Pittsburg unit 7 and Contra Costa unit 6. The agreements are for 100% of the capacity from these units. The contracts have varying tenors for each unit covering from one to five years, and include capacity of 1,985 MW for 2008 and 2009, 1,303 MW for 2010 and 674 MW for 2011. The contracted capacity for 2007 was 1,985 MW. We receive monthly capacity payments with bonuses and/or penalties based on guaranteed heat rate and availability tolerances. As a result of these contracts, the Pittsburg and Contra Costa units are no longer subject to the RMR agreements. All of our Potrero units continue to be subject to RMR arrangements that continue through 2008 and are then renewable annually.
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, including companies owned by hedge funds and private equity funds. For a discussion of competitive factors and the effects of seasonality on our business see Item 1A.
Item 1A. Risk Factors
The following are factors that could affect our future performance:
Our revenues are unpredictable because most of our 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 sell capacity, energy and ancillary services from most of our generating facilities into competitive power markets on a short-term fixed price basis or through power sales agreements. Since mid-2007, our revenues from selling capacity have become 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, the marginal and long run costs incurred by our competitors and the effect of market regulation. Being concentrated in a few geographic markets results in concentrated exposure to those markets, especially PJM. The price for which we can sell our output may fluctuate on a day-to-day basis. The markets in which we compete remain subject to one or more forms of regulation that limit our ability to raise prices during periods of shortage to the degree that would occur in a fully deregulated market and may thereby limit our ability to recover costs and an adequate return on our investment. Our revenues and results of operations are influenced by factors that are beyond our control, including:
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the failure of market regulators to develop and maintain efficient mechanisms to compensate merchant generators for the value of providing capacity needed to meet demand;
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actions by regulators, ISOs, RTOs and other bodies that may prevent capacity and energy prices from rising to the level necessary for recovery of our costs, our investment and an adequate return on our investment;
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legal and political challenges to the rules used to calculate capacity payments in the markets in which we operate;
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the possibility that appellate courts considering the pending appeals of the FERC’s rulings that approved the RPM and FCM tariffs do not affirm the FERC’s approval of those tariffs, resulting in modifications to the capacity payments made under those tariffs in the future and possibly refunds for past periods;
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the ability of wholesale purchasers of power to make timely payment for energy or capacity, which may be adversely affected by factors such as retail rate caps, refusals by regulators to allow utilities to recover fully their wholesale power costs and investments through rates, catastrophic losses and losses from investments by utilities in unregulated businesses;
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the fact that increases in prevailing market prices for fuel oil, coal, natural gas and emissions allowances may not be reflected in prices we receive for sales of energy;
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increases in supplies due to actions of our current competitors or new market entrants, including the development of new generating facilities or alternative energy sources that may be able to produce electricity less expensively than our generating facilities and improvements in transmission that allow additional supply to reach our markets;
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decreases in energy consumption resulting from demand-side management programs such as automated demand response, which may alter the amount and timing of consumer energy use;
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the competitive advantages of certain competitors including continued operation of older power plants in strategic locations after recovery of historic capital costs from ratepayers;
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existing or future regulation of our markets by the FERC, ISOs and RTOs, including any price limitations and other mechanisms to address some of the price volatility or illiquidity in these markets or the physical stability of the system;
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regulatory policies of state agencies that affect the willingness of our customers to enter into long-term contracts generally, and contracts for capacity in particular;
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weather conditions that depress demand or increase the supply of hydro power; and
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changes in the rate of growth in electricity usage as a result of such factors as national and regional economic conditions and implementation of conservation programs.
In addition, unlike most other commodities, electric energy can only be stored 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.
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 costs, and these commodity prices are influenced by many factors outside of our control, including weather, market liquidity, transmission and transportation inefficiencies, availability of competitively priced alternative energy sources, demand for energy commodities, production of natural gas, crude oil and coal, natural disasters, wars, embargoes and other catastrophic events, and federal, state and environmental regulation and legislation. 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 use of derivative contracts in our asset management activities will not fully protect us from fluctuations in commodity prices and our risk management policy cannot eliminate the risks associated with these activities.
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 instruments that we use to hedge 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.
Additionally, we expect to have an open position in the market, within our established guidelines, resulting from the management of our portfolio. To the extent open positions exist, fluctuating commodity prices can affect our financial results and financial position, either favorably or unfavorably. Furthermore, the risk management procedures we have in place may not always be followed or may not always work as planned. Unauthorized hedging and related activities by our employees could result in significant penalties and financial losses. As a result of these and other factors, we cannot predict the outcome that risk management decisions may have on our businesses, operating results or financial position. Although management devotes a considerable amount of attention to these issues, their outcome is uncertain.
We are exposed to the risk of fuel and fuel transportation cost increases and volatility and interruption in fuel supply because our facilities generally do not have long-term agreements for the supply of natural gas, coal and oil.
Although we attempt to 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.
Our asset management and proprietary trading 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: (1) electricity sales from our generating facilities; (2) fuel used by those facilities; and (3) 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 contracts. We also use derivative contracts 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 and proprietary trading activities are recorded on our balance sheet at fair value pursuant to SFAS 133. None of our derivatives recorded at fair value are designated as hedges under SFAS 133 and changes in their fair values are therefore recognized currently in earnings as unrealized gains or losses. As a result, our financial results-including gross margin, operating income and balance sheet ratios-will, at times, be volatile and subject to fluctuations in value primarily due to changes in forward electricity and fuel prices. For a more detailed discussion of the accounting treatment of our asset management and proprietary trading activities, see Note 4 to our consolidated and combined financial statements contained elsewhere in this report.
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:
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the output and efficiency levels at which those generating facilities perform;
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interruptions in fuel supply;
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disruptions in the delivery of electricity;
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adverse zoning;
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breakdowns or equipment failures (whether due to age or otherwise);
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restrictions on emissions;
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violations of our permit requirements or changes in the terms of or revocation of permits;
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releases of pollutants and hazardous substances to air, soil, surface water or groundwater;
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shortages of equipment or spare parts;
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labor disputes;
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operator errors;
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curtailment of operations due to transmission constraints;
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failures in the electricity transmission system which may cause large energy blackouts;
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implementation of unproven technologies in connection with environmental improvements; and
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catastrophic events such as fires, explosions, floods, earthquakes, hurricanes or other similar occurrences.
A decrease in, or the elimination of, the revenues generated by our facilities or an increase in the costs of operating such facilities 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.
Our operating results are subject to quarterly and seasonal fluctuations.
Our operating results have fluctuated in the past and may continue to do so in the future as a result of a number of factors, including seasonal variations in demand and fuel prices.
We compete to sell energy and capacity in the wholesale power markets against some competitors that enjoy competitive advantages, including the ability to recover fixed costs through rate base mechanisms and a lower cost of capital.
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 impact on the revenues generated by our facilities.
Our business and activities are subject to extensive environmental requirements and could be adversely affected by such requirements, including future changes to them.
Our business is subject to extensive environmental regulations promulgated by federal, state and local authorities, which, among other things, restrict the discharge of pollutants into the air, water and soil, and also govern the use of water from adjacent waterways. Such laws and regulations frequently require us to obtain operating permits and remain in continuous compliance with the conditions established by those operating permits. To comply with these legal requirements and the terms of our operating permits, we must spend significant sums on environmental monitoring, pollution control equipment and emissions allowances. If we were to fail to comply with these requirements, we could be subject to civil or criminal liability and the imposition of liens or fines. We may be required to shut down facilities if we are unable to comply with the requirements, or if we determine the expenditures required to comply are uneconomic.
From time to time we may not be able to obtain necessary environmental regulatory approvals. Such approvals could be delayed or subject to onerous conditions. If there is a delay in obtaining environmental regulatory approval or if onerous conditions are imposed, the operation of our generating facilities or the sale of electricity to third parties could be prevented or become subject to additional costs. Such delays or onerous conditions could have a material adverse effect on our financial performance and condition.
In addition, environmental laws, particularly with respect to air emissions, wastewater discharge and cooling water systems, are generally becoming more stringent, which may require us to make expensive facility upgrades or restrict our operations. With the trend toward stricter standards, greater regulation and more extensive permitting requirements, we expect our environmental expenditures to be substantial in the future. Although we have budgeted for significant expenditures to comply with these requirements, actual expenditures may be greater than budgeted amounts. We may have underestimated the cost of the environmental work we are planning or the air emissions allowances we anticipate buying. In addition, new environmental laws may be enacted, new or revised regulations under those laws may be issued, the interpretation of such laws and regulations by regulatory authorities or the courts may change, or additional information concerning the way in which such requirements apply to us may be identified. For example, in April 2006, Maryland enacted the Healthy Air Act, which requires more significant reductions in emissions of NOx, SO2 and mercury than the CAIR. This legislation affects our coal-fired units at Chalk Point, Dickerson and Morgantown. We anticipate that the total capital expenditures to achieve compliance for SO2 and NOx emissions at these facilities will be approximately $1.6 billion through the first quarter of 2010.
Increased public concern and growing political pressure related to global warming has resulted in significant increases in the regulation of greenhouse gases, including CO2 at the state level. Future local, state and federal regulation of greenhouse gases are likely to create substantial environmental costs for us in the form of taxes or
purchases of emissions allowances. Many of the states where we own generating facilities, including California, Maryland, Massachusetts and New York, have recently committed to mandatory reductions in statewide CO2 emissions through a regional cap-and-trade program. Some of these programs include proposals that would not allocate emissions allowances to existing sources of emissions and instead require all allowances to be purchased initially through an auction process. This could decrease the amount of available allowances and substantially increase their prices. Because our generating facilities emit CO2, these regulations and similar future laws may significantly increase our operating costs.
Certain environmental laws, including CERCLA and comparable state laws, impose strict and, in many circumstances, joint and several liability for costs of remediating contamination in soil, groundwater and elsewhere. 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.
Major environmental construction projects planned by 2010 at our Mid-Atlantic coal facilities may not meet their anticipated schedule, which would restrict these units from running at their maximum economic levels. In the event that the operating constraints were sufficiently severe, Mirant Mid-Atlantic may not have sufficient cash flow to permit it to make distributions or, if more severe, to meet its obligations.
Under the Maryland Healthy Air Act, we are required to reduce annual emissions below certain levels by January 2010. The levels established do not allow for the use of emissions allowances to meet the mandated levels. To meet these requirements, we are installing pollution control equipment on all of our Maryland coal facilities. We may not meet this construction schedule by January 2010 due to a number of factors, including:
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failure or delays in obtaining necessary permits and approvals;
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adverse weather conditions;
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unanticipated cost increases;
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engineering problems;
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shortages of equipment, materials or skilled labor;
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unscheduled delays in delivery of materials and equipment; and
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work stoppages.
Any of these factors may significantly increase the estimated costs of our environmental construction projects or result in a loss of cash flows from operations due to reduced unit operations.
The expected decommissioning and/or site remediation obligations of certain of our generating facilities may negatively affect our cash flows.
We expect that certain of our generating facilities and related properties will become subject to decommissioning and/or site remediation obligations that may require material expenditures. For example, we may start decommissioning the Lovett facility if the final operating unit ceases operation on April 19, 2008. We expect the decommissioning of the Lovett facility to cost approximately $20 million. The exact amount and timing of such expenditures is not presently known. 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.
Our consolidated indebtedness 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.
As of December 31, 2007, our consolidated indebtedness was $1.435 billion. In addition, the present value of lease payments under the Mirant Mid-Atlantic leveraged leases is approximately $1 billion (assuming a 10% discount rate) and the termination value of the Mirant Mid-Atlantic leveraged leases is $1.4 billion. Our leverage could have important consequences, including the following: (1) it may limit our ability to obtain additional debt or equity financing for working capital, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; (2) a substantial portion of our cash flows from operations must be dedicated to the payment of principal and interest on our indebtedness and will not be available for other purposes, including our operations, capital expenditures and future business opportunities; (3) the debt service requirements of our indebtedness could make it more difficult for us to satisfy or refinance our financial obligations; (4) borrowings under our senior secured credit facilities are at variable rates of interest, exposing us to the risk of increased interest rates; (5) it may limit our ability to adjust to changing market conditions and place us at a competitive disadvantage compared with our competitors that have less debt; and (6) we may be more vulnerable in a downturn in general economic conditions or in our business and we may be unable to carry out capital expenditures that are important to our long-term growth or necessary to comply with environmental regulations.
The sale by our indirect parent, Mirant of the six U.S. natural gas-fired facilities and its Philippine and Caribbean businesses, and its decision to return a total of $4.6 billion in excess cash to its stockholders, could adversely limit its ability to make capital contributions to or otherwise support us and our subsidiaries.
We are a holding company and we may not have access to sufficient cash to meet our obligations if our subsidiary Mirant Mid-Atlantic is unable to make distributions.
We are a holding company and, as a result, we are dependent upon dividends, distributions and other payments from our operating subsidiaries to generate the funds necessary to meet our obligations. In particular, a significant portion of cash from our operations is generated by the power generating facilities of Mirant Mid-Atlantic. Under the Mirant Mid-Atlantic leveraged leases, Mirant Mid-Atlantic is subject to a covenant that restricts its right to make distributions to us. Mirant Mid-Atlantic’s ability to satisfy the criteria set forth by that covenant in the future could be impaired by factors which negatively affect the performance of its power generating facilities, including interruptions in operation or curtailment of operations to comply with environmental restrictions.
Our obligations, including our indebtedness, are effectively subordinated to the obligations or indebtedness of our subsidiaries, except to the extent that such obligations or indebtedness are assumed or guaranteed by a subsidiary.
We may be unable to generate sufficient liquidity to service our debt and to post required amounts of cash collateral necessary to hedge market risk effectively.
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.
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. As of December 31, 2007, we had approximately $108 million of
posted cash collateral and $290 million of letters of credit outstanding primarily to support our asset management activities, debt service reserve requirements and other commercial arrangements. See Note 9 to our consolidated and combined financial statements contained elsewhere in this report for further information on our posted cash collateral and letters of credit. While 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.
If our facilities experience unplanned outages, we may be required to procure replacement power in the open market to satisfy contractual commitments. Without adequate liquidity to post margin and collateral requirements, we may be exposed to significant losses and may miss significant opportunities, and we may have increased exposure to the volatility of spot markets.
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 costs of operating our facilities or our ability to operate our facilities. Such cost impacts, in turn, may negatively affect our financial condition and results of operations.
We are subject to regulation by the FERC regarding the terms and conditions of wholesale service and rates, 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 where market based rate authority has been granted, the FERC may impose various forms of market mitigation measures, including price caps and operating restrictions, where 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 RTOs and ISOs. 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 and capacity.
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.
On August 8, 2005, the EPAct 2005 was enacted. Among other things, the EPAct 2005 provides incentives for various forms of electric generating technologies, which will subsidize certain of our competitors. Regulations that could be issued pursuant to the EPAct 2005 may have an adverse impact on our business.
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 both to advance and to roll back 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. We cannot provide assurance that the introductions of new laws, or other future regulatory developments, will not have a material adverse impact on our business, operations or financial condition.
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 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.
Terrorist attacks, future war or risk of war may adversely affect our results of operations, our ability to raise capital or our future growth.
As power generators, we face heightened risk of an act of terrorism, either a direct act against one of our generating facilities or an inability to operate as a result of systemic damage resulting from an act against the transmission and distribution infrastructure that we use to transport our power. If such an attack were to occur, our business, financial condition and results of operations 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.
Our operations are subject to many hazards associated with the power generating industry, which may expose us to significant liabilities for which we may not have adequate insurance coverage. Power generation involves hazardous activities, including acquiring, transporting and unloading fuel, operating large pieces of rotating equipment and delivering electricity to transmission and distribution systems. In addition to natural risks, such as earthquake, flood, lightning, hurricane 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 successful claim for which we are not fully insured could have a material adverse effect on our financial results and our financial condition.
We are currently involved in significant litigation that, if decided adversely to us, could materially adversely affect our results of operations and profitability.
We are currently involved in various litigation matters, which are described in more detail in this Form 10-K. We intend to defend vigorously against those claims that we are unable to settle, but the results of this litigation cannot be determined. Adverse outcomes for us in this litigation could require significant expenditures by us and could have a material adverse effect on our results of operations and profitability.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
The properties below were owned or leased as of December 31, 2007. Our leasehold or ownership interest is 100% for each property.
(1) Total MW amounts reflect nominal net dependable capacity.
(2) Net capacity factor is the average production as a percentage of the potential net dependable capacity used over a year.
We also own an oil pipeline, which is approximately 51.5 miles long and serves the Chalk Point and Morgantown generating facilities.
Item 3.
Item 3. Legal Proceedings-See Note 14 to our consolidated and combined financial statements contained elsewhere in this report for discussion of the material legal proceedings to which we are a party.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
None.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
We are an indirect wholly-owned subsidiary of Mirant. Our membership interests are not publicly traded and all of our membership interests are held by our parent, Mirant Americas Generation. For the years ended December 31, 2007 and 2006, we made cash distributions to Mirant Americas Generation of $695 million and $381 million, respectively. In addition, in 2006, we settled $1.773 billion of Mirant Americas Generation’s obligations pursuant to the Plan. We have no equity compensation plans under which we issue our membership interests.
Item 6.
Item 6. Selected Financial Data
The following discussion should be read in conjunction with our consolidated and combined financial statements and the notes thereto, which are included elsewhere in this Form 10-K. The following tables present our selected financial information, which is derived from our consolidated and combined financial statements.
During our bankruptcy proceedings, our consolidated and combined financial statements were prepared in accordance with SOP 90-7. Our Statements of Operations Data for the years ended December 31, 2004 and 2003, do not include interest expense on debt that was subject to compromise subsequent to the Petition Date. Our Statement of Operations Data for the year ended December 31, 2005, reflects the effects of accounting for the Plan confirmed on December 9, 2005.
The consolidated Balance Sheet Data for years 2006, 2005, 2004 and 2003, segregates pre-petition liabilities subject to compromise from those liabilities that were not subject to compromise.
In 2005, we recorded the effects of the Plan. As a result, liabilities subject to compromise at December 31, 2005 and 2006, only reflect the liabilities of our New York entities that remained in bankruptcy at that time.
Item 7.
Item 7. Management’s Discussion and Analysis of Results of Operations and Financial Condition
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 and combined financial statements and the notes accompanying those financial statements.
Overview
We are a competitive energy company that produces and sells electricity. We are a direct wholly-owned subsidiary of Mirant Americas Generation and an indirect wholly-owned subsidiary of Mirant. We own or lease 10,280 MW of electric generating capacity located in markets in the Mid-Atlantic and Northeast regions and in California. We also operate an integrated asset management and energy marketing organization based in Atlanta, Georgia.
Dispositions
In the third quarter of 2006, Mirant commenced auction processes to sell six U.S. natural gas-fired facilities including our indirectly owned Zeeland and Bosque facilities. On May 1, 2007, we completed the sale of the Zeeland and Bosque natural gas-fired facilities. In addition, on May 7, 2007, we completed the sale of Mirant NY-Gen, an indirect wholly-owned subsidiary. In accordance with our debt covenants, approximately $524 million of the proceeds from the sale of the Zeeland and Bosque facilities are being reinvested in the business. At December 31, 2007, $273 million of such proceeds have been reinvested in the business. See Note 10 to our consolidated and combined financial statements contained elsewhere in this report for additional information regarding the accounting for these facilities as discontinued operations.
Exploration of Strategic Alternatives and Share Repurchases
On April 9, 2007, Mirant announced that its Board of Directors had decided to explore strategic alternatives to enhance stockholder value. In the exploration process, the Board of Directors considered whether the interests of stockholders would be best served by returning excess cash from the sale proceeds to stockholders, with Mirant continuing to operate its retained businesses or, alternatively, whether greater stockholder value would be achieved by entering into a transaction with another company, including a sale of Mirant in its entirety. On November 9, 2007, Mirant announced the conclusion of the strategic review process. Mirant plans to return a total of $4.6 billion of excess cash to its stockholders.
Hedging Activities
We economically hedge a substantial portion of our Mid-Atlantic coal-fired baseload generation and certain of our Northeast coal, gas and oil-fired generation through OTC transactions. A significant portion of our hedges are financial swap transactions that are senior unsecured obligations of Mirant Mid-Atlantic and do not require the posting of cash collateral either for initial margin or for securing exposure as a result of changes in power prices. However, we generally do not hedge our intermediate and peaking units for tenors greater than 12 months. At February 25, 2008, we were economically hedged as follows:
Capital Expenditures and Capital Resources
For the year ended December 31, 2007, we paid $553 million of capital expenditures, primarily related to the Maryland Healthy Air Act. The following table details our estimated capital expenditures, excluding capitalized interest, for 2008 through 2010 (in millions):
Through December 31, 2007, we paid approximately $500 million for capital expenditures related to the Maryland Healthy Air Act. We will have extended planned outages during the installation of equipment and, during those outages, we will perform other routine maintenance activities. We expect that available cash and future cash flows from operations will be sufficient to fund these capital expenditures.
Consolidated Financial Performance
We reported net income of $90 million and $1.348 billion for the years ended December 31, 2007 and 2006, respectively, and a net loss of $779 million for the year ended December 31, 2005. The change in net income (loss) is detailed as follows (in millions):
Results of Operations
The following discussion of our performance is organized by reportable operating segment, which is consistent with the way we manage our business. In 2007, we completed the sale of the Zeeland and Bosque facilities and Mirant NY-Gen. The sales have resulted in the reclassification of the revenues and expenses of these facilities to discontinued operations and the reclassification of the related assets and liabilities to assets held for sale for all periods presented through their respective dates of sale.
In the tables below, the Mid-Atlantic region includes our Chalk Point, Morgantown, Dickerson and Potomac River facilities. The Northeast region includes our Bowline, Canal, Lovett, Kendall and Martha’s Vineyard facilities. The California region includes our Pittsburg, Contra Costa and Potrero facilities. Other Operations
includes proprietary trading, fuel oil management and, for periods prior to 2006, includes gains and losses related to a long-term PPA with Pepco (the “Back-to-Back Agreement”) and the transition power agreement with Pepco that expired in January 2005. See Note 15 to our consolidated and combined financial statements contained elsewhere in this report for further discussion of the Back-to-Back Agreement. Other Operations also includes interest on our debt and interest income on our invested cash balances.
Operating Statistics
The following table summarizes net capacity factor by region for the years ended December 31, 2007, 2006 and 2005:
The following table summarizes power generation volumes by region for the years ended December 31, 2007, 2006 and 2005 (in gigawatt hours):
2007 versus 2006
Gross Margin Overview
The following table details realized and unrealized gross margin by operating segment (in millions):
Gross margin for the years ended December 31, 2007 and 2006, is further detailed as follows (in millions):
Energy represents gross margin from the generation of electricity, sales and purchases of emissions allowances, fuel sales, purchases and handling of fuel, steam sales and our proprietary trading and fuel oil management activities.
Contracted and capacity represents gross margin received from capacity sold in ISO administered capacity markets, through RMR contracts and ancillary services.
Incremental realized value of hedges represents the actual margin upon the settlement of our power and fuel hedging contracts.
Unrealized gross margin represents the net unrealized gain or loss on our derivative contracts.
Our gross margin for the year ended December 31, 2007, was $1.002 billion as compared to $1.949 billion for the same period in 2006. The decrease in gross margin, which includes net unrealized gains and losses from our hedging activities, was principally a result of the following:
A decrease of $1.233 billion in unrealized gross margin was comprised of the following:
•
unrealized losses of $624 million in 2007, which include $442 million from the settlement of power and fuel contracts during the period for which net unrealized gains had been recorded in prior periods and a $182 million net decrease in the value of hedge contracts for future periods primarily related to increases in forward power prices in 2007; and
•
unrealized gains of $609 million in 2006, which include a $440 million net increase in the value of hedge contracts for future periods primarily related to decreases in forward power prices in 2006 and $169 million from the settlement of power and fuel contracts during the period for which net unrealized losses had been recorded in prior periods.
An increase of $286 million in realized gross margin primarily attributable to: (1) an increase in contracted and capacity of $231 million principally related to the PJM RPM and the FCM in New England; (2) an increase in energy of $173 million as a result of an increase in power prices, a decrease in emissions prices, slightly higher
generation volumes and the settlement of favorable fuel oil management positions; partially offset by (3) a decrease of $118 million in incremental realized value of hedges.
Mid-Atlantic
Our Mid-Atlantic segment, which accounts for approximately half of our net generating capacity, includes four generating facilities with total net generating capacity of 5,244 MW. The following tables summarize our Mid-Atlantic segment (in millions):
Gross Margin
The increase of $250 million in realized gross margin was principally a result of the following:
•
an increase of $154 million in energy, primarily because of an increase in power prices, a decrease in emissions prices and slightly higher generation volumes;
•
an increase of $157 million in contracted and capacity related to higher capacity revenues from the PJM RPM, which became effective in June 2007. See Item 1. “Regulatory Environment” for further discussion of RPM; and
•
a decrease of $61 million in incremental realized value of hedges of our generation output primarily as a result of a decrease in the amount by which the settlement value of power contracts exceeded market prices.
The decrease of $963 million in unrealized gross margin was comprised of the following:
•
unrealized losses of $479 million in 2007, which include $270 million from the settlement of power and fuel contracts during the period for which net unrealized gains had been recorded in prior periods and a $209 million net decrease in the value of hedge contracts for future periods primarily related to increases in forward power prices in 2007; and
•
unrealized gains of $484 million in 2006, which include a $312 million net increase in the value of hedge contracts for future periods primarily as a result of decreases in forward power prices in 2006 and $172 million from the settlement of power and fuel contracts during the year for which net unrealized losses had been recorded in prior periods, particularly during the high energy prices of late 2005.
Operating Expenses
Operating expenses increased $41 million primarily as a result of the following:
•
an increase of $27 million in operations and maintenance expense, of which $18 million was related to higher maintenance performed in conjunction with planned outages for the installation of pollution control equipment and $8 million related to increased corporate overhead allocations as a result of the dispositions in 2007;
•
an increase of $7 million in depreciation and amortization expense primarily related to expenditures on equipment to improve environmental performance; and
•
a decrease of $7 million in gain on sales of assets, net primarily related to a gain of $6 million on the sale of a building in 2006.
Northeast
Our Northeast segment is comprised of our facilities located in New York and New England with total net generating capacity of 2,689 MW. The following tables summarize the operations of our Northeast segment (in millions):
Gross Margin
The decrease of $6 million in realized gross margin was principally a result of the following:
•
a decrease of $60 million in incremental realized value of hedges of our generation output, primarily as a result of a decrease in the amount by which the settlement value of power contracts exceeded market prices;
•
an increase of $43 million in contracted and capacity from the implementation of the new FCM in New England. See Item 1. “Regulatory Environment” for further information on the implementation of the new FCM; and
•
an increase of $11 million in energy, primarily because of an increase in power prices and higher generation volumes.
The decrease of $104 million in unrealized gross margin was comprised of the following:
•
unrealized losses of $43 million in 2007, which include $57 million from the settlement of power and fuel contracts during the period for which unrealized gains had been recorded in prior periods, partially offset by a $14 million net increase in the value of hedge contracts for future periods primarily related to decreases in forward power prices in 2007; and
•
unrealized gains of $61 million in 2006, which include a $50 million net increase in the value of hedge contracts for future periods primarily related to decreases in forward power prices in 2006 and $11 million from the settlement of power and fuel contracts during the year for which unrealized losses had been recorded in prior periods, particularly during the high energy prices of late 2005.
Operating Expenses
Operating expenses increased $117 million primarily as a result of the following:
•
an increase of $63 million in operations and maintenance which included:
•
an increase of $71 million in 2007, which represents that portion of the 2006 New York property tax settlement that reduced operating expenses for 2006, but which related to prior periods. See Note 15 to our consolidated financial statements contained elsewhere in this report for further discussion; and
•
a decrease of $6 million related to a decrease in maintenance costs primarily as a result of the shutdown of Lovett units 3 and 4 in 2007 and repairs on Lovett unit 5 in 2006.
•
an increase of $57 million in impairment losses. In 2007, we recorded an impairment loss of $175 million on our Lovett facility. In 2006, we recorded an impairment loss of $118 million on the Bowline unit 3 suspended construction project. See Note 5 to our consolidated financial statements contained elsewhere in this report for additional information related to these impairments; and
•
an increase of $3 million in gain on sales of assets, net which includes a $14 million gain on the sale of certain ancillary equipment that was included in the sale of the six U.S. natural gas-fired facilities in
the second quarter of 2007. This amount was partially offset by a decrease of $11 million in sales of emissions allowances. In 2007, gain on the sales of emissions allowances was $33 million and included a gain of $22 million on the sales of excess emissions allowances to third parties and $11 million related to the sales of emissions allowances to affiliates. In 2006, gain on the sales of emissions allowances to affiliates was $44 million. The affiliate gains are eliminated in the consolidated and combined statements of operations.
California
Our California segment consists of the Pittsburg, Contra Costa and Potrero facilities with total net generating capacity of 2,347 MW. The following tables summarize our California segment (in millions):
Gross Margin
The increase in our contracted and capacity gross margin and decrease in our energy gross margin were primarily a result of the commencement of a new tolling agreement in the first quarter of 2007 at our Contra Costa and Pittsburg facilities. See Item 1. “Business Segments” for additional information regarding the tolling agreement.
Operating Expenses
The increase of $9 million in operating expenses includes an increase of $11 million in operations and maintenance expense in 2007, resulting from higher maintenance costs related to outages and a $5 million property tax settlement in 2006.
Other Expense (Income), Net
The decrease of $29 million in other expense (income), net is primarily a result of a gain of $26 million in 2006 related to the transfer of Contra Costa unit 8 to PG&E. See “California Settlement” in Note 15 to our consolidated and combined financial statements contained elsewhere in this report for further discussion.
Other Operations
Other Operations includes proprietary trading, fuel oil management, interest on our debt and interest income on our invested cash balances. The following tables summarize our Other Operations segment (in millions):
Gross Margin
The decrease of $163 million in unrealized gross margin was comprised of the following:
•
in 2007, unrealized losses on proprietary trading and fuel oil management activities of $102 million, which include $115 million from the settlement of power and fuel contracts during the period for which unrealized gains had been recorded in prior periods and a $13 million net increase in value associated with contracts for future periods; and
•
unrealized gains on proprietary trading and fuel oil management activities of $61 million in 2006.
The increase of $39 million in realized gross margin was principally a result of an increase in energy related to our proprietary trading and fuel oil management activities as favorable positions entered into prior to 2007 were settled in the current period.
Operating Expenses
Operating expenses decreased $14 million primarily as a result of the following:
•
a decrease of $9 million in depreciation expense as a result of fully depreciated computer equipment; and
•
a decrease of $6 million in operations and maintenance expense, primarily resulting from a reduction in allocated expenses as a result of the dispositions completed in 2007.
Other Expense (Income), Net
Other expense (income), net increased $27 million primarily as a result of the following:
•
a decrease of $46 million related to increased interest income resulting from increased cash balances as a result of the receipts of proceeds from dispositions completed in 2007 and lower interest expense on our debt; offset by
•
a decrease in gain on sales of investments, which included a gain of $54 million in 2006 from the sale of a portion of our investment in InterContinental Exchange and $19 million on the sale of our two New York Mercantile Exchange seats and shares.
Other Significant Consolidated Statements of Operations Comparison
Discontinued Operations
For the year ended December 31, 2007 and 2006, income from discontinued operations was $8 million and $3 million, respectively, and included the results of operations of Mirant Zeeland, Mirant Texas and Mirant NY-Gen. See Note 10 to our consolidated and combined financial statements contained elsewhere in this report for additional information related to discontinued operations.
Reorganization Items, net
Reorganization items, net for the years ended December 31, 2007 and 2006, are comprised of the following (in millions):
Under the terms of the New York property tax settlement, in February 2007 we received refunds totaling approximately $163 million for 1995 through 2003 and paid unpaid but accrued taxes of approximately $115 million for 2003 through 2006. See Note 15 to our consolidated and combined financial statements contained elsewhere in this report for additional information.
2006 versus 2005
Gross Margin
The following table details gross margin by realized and unrealized margin for the year ended December 31, 2006 and 2005 (in millions):
Mid-Atlantic
The following table summarizes the operations of our Mid-Atlantic segment for the years ended December 31, 2006 and 2005 (in millions):
Gross Margin
Gross margin increased by $863 million for the year ended December 31, 2006, compared to the same period for 2005 and is detailed as follows (in millions):
Energy represents gross margin from the generation of electricity, sales and purchases of emissions allowances, fuel sales, purchases and handling of fuel, steam sales and our proprietary trading and fuel oil management activities.
Contracted and capacity represents gross margin received from capacity sold in ISO administered capacity markets, through RMR contracts, ancillary services and from the Back-to-Back Agreement, which was terminated on August 10, 2007.
Incremental realized value of hedges represents the actual margin upon the settlement of our power and fuel hedging contracts.
Unrealized gross margin represents the unrealized gain or loss on our derivative contracts.
The significant increase in the gross margin for our Mid-Atlantic operations is primarily due to the following:
•
an increase of $581 million related to unrealized gross margin from hedging activities. In 2006, unrealized gains of $484 million are primarily due to $312 million from increased value associated with forward power contracts for future periods as a result of decreases in forward power prices in 2006 and $172 million due to the settlement of power and fuel contracts during the year for which net unrealized losses had been recorded in prior periods, particularly during the high energy prices of late 2005. In 2005, unrealized losses of $97 million were primarily due to increases in power prices as a result of increases in gas prices;
•
an increase of $545 million in incremental realized value of hedges of our generation output. In 2006, the incremental realized value of our hedges contributed $263 million to our gross margin as our power contracts settled at prices higher than market prices for the year. In 2005, our opportunity cost of hedging was $282 million primarily due to the impact of rising energy prices in the latter part of 2005 that resulted in the settlement of power contracts at prices lower than market prices for that year; and
•
a decrease of $238 million in energy primarily related to lower power prices and lower generation volumes on our oil-fired units. Power prices were lower due to significantly lower gas prices in 2006 compared to 2005. Our baseload coal units’ generation decreased slightly and our 9% total decrease in generation volumes was driven by significantly lower volumes generated by our oil-fired units. A sharp decrease in power prices combined with average oil prices that were somewhat higher than in 2005 resulted in our oil-fired units not being able to dispatch economically for much of the year.
Northeast
The following table summarizes the operations of our Northeast segment for the years ended December 31, 2006 and 2005 (in millions):
Gross Margin
Gross margin increased by $152 million for the year ended December 31, 2006, compared to the same period for 2005 and is detailed as follows (in millions):
The increase in gross margin is primarily due to the following:
•
an increase of $72 million related to unrealized gross margin from hedging activities. In 2006, unrealized gains of $61 million are primarily due to $50 million from increased value associated with forward power and fuel contracts for future periods mainly as a result of decreases in forward power prices in 2006 and $11 million due to the settlement of power and fuel contracts during the year for which unrealized losses had been recorded in prior periods, particularly during the high energy prices of late 2005. In 2005, unrealized losses of $11 million were primarily due to increases in power prices as a result of increased gas prices and the settlement of contracts during the year for which unrealized losses had been recorded in prior periods, partially offset by an increase in the value of fuel hedges due to higher fuel prices;
•
an increase of $168 million in incremental realized value of hedges of our generation output. In 2006, the incremental realized value of our hedges contributed $125 million to our gross margin as our power contracts settled at prices higher than market prices for the year, partially offset by hedged fuel costs
that were higher than the market. In 2005, our opportunity cost of hedging was $43 million primarily due to the impact of rising energy prices in the latter part of 2005 that resulted in the settlement of power contracts at prices lower than market prices for that year, partially offset by the favorable impact of hedged fuel costs that were generally lower than the market as fuel prices increased in 2005; and
•
a decrease of $97 million in energy primarily related to lower generation volumes. Our decrease in generation volumes was driven by significantly lower volumes generated by our oil-fired units. A decrease in power prices combined with average oil prices that were higher than in 2005 resulted in our oil-fired units not being able to dispatch economically for most of the period.
Operating Expenses
The decrease of $20 million in operating expenses is primarily due to a decrease of $94 million in operations and maintenance, which relates to the New York property tax settlement. Of this amount, $71 million relates to periods prior to 2006. The remaining decrease in property tax expense represents the difference in the 2006 expense under the settlement compared to the 2005 expense that was accrued based on the property tax assessments. Gains on sales of assets increased $36 million due to an increase of $37 million in gains on sales of emissions allowances to affiliates that are eliminated in the consolidated statement of operations. Impairment losses in 2006 represent the impairment of the Bowline unit 3 suspended construction project.
California
The following table summarizes the operations of our California segment for the years ended December 31, 2006 and 2005 (in millions):
Gross Margin
Gross margin increased by $2 million for the year ended December 31, 2006, compared to the same period for 2005 and is detailed as follows (in millions):
The increase in our energy gross margin is primarily due to several days of extreme heat in July 2006, which allowed us to earn incremental gross margin on units that were under a tolling agreement for the same period in 2005. The expiration of this tolling agreement is the primary reason for the decrease in our contracted and capacity margin.
Other Expense (Income), net
The decrease of $35 million in other expense (income), net is primarily due to a gain of $26 million in 2006 related to the transfer of Contra Costa unit 8 to PG&E and an increase of $6 million in interest income. See “California Settlement” in Note 15 to our consolidated and combined financial statements contained elsewhere in this report for further discussion.
Other Operations
Other Operations includes proprietary trading, fuel oil management and for periods prior to 2006, gains and losses related to the Back-to-Back Agreement and the transition power agreement with Pepco that expired in January 2005. See “Pepco Litigation” in Note 15 to our consolidated and combined financial statements contained elsewhere in this report for further discussion of the Back-to-Back Agreement. The following table summarizes the operations of our Other Operations segment for the years ended December 31, 2006 and 2005 (in millions):
Gross Margin
Gross margin increased by $85 million for the year ended December 31, 2006, compared to the same period for 2005 and is detailed as follows (in millions):
The increase in gross margin is primarily due to the following:
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an increase of $31 million in energy, primarily related to our proprietary trading and fuel oil management activities net of cost or market adjustments on our oil inventory during the third and fourth quarters of 2006;
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an increase of $78 million in contracted and capacity due to a decrease in realized losses on the Back-to-Back Agreement and the hedges related to this contract, primarily due to the expiration of one of Pepco’s PPAs covered by that agreement; and
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a decrease of $24 million in unrealized gross margin, which includes an increase of $73 million in unrealized gains on our proprietary trading and fuel oil management activities, offset by a decrease of $97 million in unrealized gains on the Back-to-Back Agreement and the related hedges. In 2006, the Back-to-Back agreement was transferred to Mirant Power Purchase.
Operating Expenses
Operating expenses decreased by $9 million primarily due to a decrease in operations and maintenance of $5 million and a decrease in depreciation of $3 million.
Other Expense, net
The decrease in other expense, net of $703 million is primarily due to the following:
•
interest expense, net decreased by $677 million. In 2005, we recognized $746 million of interest on liabilities subject to compromise for the period from the 2003 petition date through December 2005; and
•
gains on sales of investments increased $30 million. In 2006, we recognized a gain of $54 million related to sales of our investment in InterContinental Exchange and a gain of $19 million on the sale of our two New York Mercantile Exchange seats and shares. In 2005, we recognized a gain of $44 million related to the sale of a portion of our investment in InterContinental Exchange.
Other Significant Consolidated Statements of Operations Comparison
Reorganization Items, net
Reorganization items, net for the years ended December 31, 2006 and 2005, are comprised of the following (in millions):
Reorganization items, net decreased by $249 million for the year ended December 31, 2006, compared to 2005, primarily related to the settlement of the New York State property tax disputes. Under the terms of the settlement, in February 2007 we received refunds totaling approximately $163 million for 1995 through 2003 and
paid unpaid but accrued taxes of approximately $115 million for 2003 through 2006. For the year ended December 31, 2005, reorganization items, net represent amounts that were recorded in the financial statements as a result of the bankruptcy proceedings.
Estimated claims and losses on rejected and amended contracts relate primarily to rejected energy contracts, such as tolling agreements, gas transportation contracts and electric transmission contracts.
Discontinued Operations
During the third quarter of 2006, Mirant commenced auction processes to sell six U.S. natural gas-fired facilities, including the Zeeland and Bosque facilities. Accordingly, the results of operations related to the planned sales were reclassified to income (loss) from discontinued operations in our consolidated and combined statements of operations for all periods presented.
For the year ended December 31, 2006, we reported net income from discontinued operations of $3 million, which includes an impairment loss to write-down the Zeeland and Bosque facilities to fair value. For the year ended December 31, 2005, we reported a net loss of $9 million. See Note 10 to our consolidated and combined financial statements contained elsewhere in this report for additional information related to discontinued operations.
Liquidity and Capital Resources
Sources of Funds and Capital Structure
The principal sources of liquidity for our future operations and capital expenditures are expected to be: (1) existing cash on hand and cash flows from the operations of our subsidiaries; (2) letters of credit issued or borrowings made under our $800 million senior secured revolving credit facility; (3) $200 million of letter of credit capacity available under our senior secured term loan; and (4) redemptions of preferred shares in Mirant Americas.
The table below sets forth total cash, cash equivalents and availability of credit facilities of Mirant North America and its subsidiaries at December 31, 2007 and 2006 (in millions):
We consider all short-term investments with an original maturity of three months or less to be cash equivalents. At December 31, 2007, except for amounts held in bank accounts to cover upcoming payables, all of our cash and cash equivalents were invested in AAA-rated U.S. Treasury money market funds.
Except for existing cash on hand, letters of credit and borrowings under our senior credit facilities and our ability to access capital, we are dependent on the distributions and dividends of our subsidiaries, in particular Mirant Mid-Atlantic, for liquidity.
We are a holding company and, as a result, we are dependent upon dividends, distributions and other payments from our subsidiaries to generate the funds necessary to meet our obligations. The chart below is a summary representation of our capital structure and is not a complete organizational chart.
A significant portion of cash from our operations is generated by the power generation facilities of Mirant Mid-Atlantic. Under the Mirant Mid-Atlantic leveraged leases, Mirant Mid-Atlantic is subject to a covenant that restricts its right to make distributions to us. Mirant Mid-Atlantic’s ability to satisfy the criteria set by that covenant in the future could be impaired by factors which negatively affect the performance of its power generation facilities, including interruptions in operation or curtailment of operations to comply with environmental restrictions.
We are an intermediate holding company and the sole subsidiary of, and source of distribution to, Mirant Americas Generation. Mirant Americas Generation relies on distributions from us to fund the debt service on its $1.661 million senior notes. We incurred certain indebtedness pursuant to our senior notes and senior secured credit facilities secured by our assets and the assets of our subsidiaries (other than Mirant Mid-Atlantic and its subsidiaries and Mirant Energy Trading). Our indebtedness includes certain covenants typical in such notes and credit facilities, including restrictions on dividends, distributions and other restricted payments. Further, the notes and senior secured credit facilities include financial covenants that will exclude from the calculation the financial results of any subsidiary that is unable to make distributions or dividends at the time of such calculation. Thus, the ability of Mirant Mid-Atlantic to make distributions to us under the leveraged lease transaction could have a material effect on the calculation of the financial covenants under our senior notes and senior secured credit facilities and on our ability to make distributions to Mirant Americas Generation.
At December 31, 2007, we had distributed to Mirant Americas Generation, all available cash that was permitted to be distributed under the terms of our debt agreements, leaving us and our subsidiaries with $697 million. Of this amount, $242 million was held by Mirant Mid-Atlantic which, as of December 31, 2007, met the ratio tests under the leveraged lease documents for distribution of the entire amount to us. After taking into account our financial results for the year ended December 31, 2007, we expect to be able to distribute approximately $65 million to Mirant Americas Generation in March 2008.
Maintaining sufficient liquidity in our business is crucial in order to mitigate the risk of future financial distress to us. Accordingly, we plan on a prospective basis for the expected liquidity requirements of our business considering the factors listed below:
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expected expenditures with respect to maintenance activities and capital improvements, and related outages;
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expected collateral posted in support of our business;
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effects of market price volatility on the amount of collateral posted for economic hedge transactions and risk management transactions;
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effects of market price volatility on fuel pre-payment requirements;
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seasonal and intra-month working capital requirements; and
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debt service obligations.
Our operating cash flows may be affected by, among other things: (1) demand for electricity; (2) the difference between the cost of fuel used to generate electricity and the market value of the electricity generated; (3) commodity prices (including prices for electricity, emissions allowances, natural gas, coal and oil); (4) the cost of ordinary course operations and maintenance expenses; (5) planned and unplanned outages; (6) terms with trade creditors; and (7) cash requirements for capital expenditures relating to certain facilities (including those necessary to comply with environmental regulations).
Uses of Funds
Our requirements for liquidity and capital resources, other than for the day-to-day operation of our generating facilities, are significantly influenced by the following activities: (1) capital expenditures required to keep our power generating facilities in operation; (2) debt service; (3) our asset management and proprietary trading activities; and (4) the Mirant Mid-Atlantic operating leases.
Capital Expenditures. Capital expenditures excluding capitalized interest for our continuing operations were $553 million, $127 million and $96 million for the years ended December 31, 2007, 2006 and 2005, respectively. Our capital expenditures for 2008, 2009 and 2010 are expected to be approximately $964 million, $516 million and $274 million, respectively. This forecast does not assume any construction of new generating units during the forecast period. Instead, the current capital expenditure program, which is expected to be funded by cash on hand and operating cash flow, focuses on efficiency, safety, reliability and compliance with existing environmental laws and contract obligations, including capital expenditures made to comply with the limitations for SO2 and NOx emissions under the Maryland Healthy Air Act. For a more detailed discussion of environmental expenditures we expect to incur in the future, see Item 1. Business.
Debt Service. At December 31, 2007, we had $1.435 billion of long-term debt with expected interest expense of approximately $94 million for 2008. Under the terms of our senior secured term facility, we are required to use 50% of our free cash flow for each fiscal year (less amounts paid to Mirant Americas Generation for the purpose of paying interest on the Mirant Americas Generation senior notes) to pay down our senior secured term loan, in addition to our scheduled amortization of $7 million per year. The percentage of free cash flow that we are required to use to pay down our senior secured term loan may be reduced to 25% upon our achievement of a net debt to EBITDA ratio of less than 2:1. At December 31, 2007, our net debt to EBITDA was less than 2:1. As such, we were required to use 25% of our free cash flow to pay down our senior secured term loan. We estimate this prepayment, which will be made during the first quarter of 2008, to be $132 million.
Mirant Mid-Atlantic Operating Leases. Mirant Mid-Atlantic leases the Morgantown and Dickerson baseload units and associated property through 2034 and 2029, respectively. Mirant Mid-Atlantic has an option to extend the leases. Any extensions of the respective leases would be limited to 75% of the economic useful life of the facility, as measured from the beginning of the original lease term through the end of the proposed remaining lease term. We are accounting for these leases as operating leases. While there is variability in the scheduled payment amounts over the lease term, we recognize rent expense for these leases on a straight-line basis. As of December 31, 2007, the total notional minimum lease payments for the remaining term of the leases aggregated approximately $2.1 billion and the aggregate termination value for the leases was approximately $1.4 billion and generally decreases over time. Rent expense under the Mirant Mid-Atlantic leases was $96 million for the years ended December 31, 2007 and 2006, and $99 million for the year ended December 31, 2005. In addition, Mirant Mid-Atlantic is required to post rent reserves in an aggregate amount equal to the greater of the next six months rent, fifty percent of the next 12 months rent or $75 million.
Cash Collateral and Letters of Credit. In order to sell power and purchase fuel in the forward markets and perform other energy trading and marketing activities, we are often required to provide trade credit support to our counterparties or make deposits with brokers. In addition, we are often required to provide cash collateral or letters of credit for access to the transmission grid, to participate in power pools, to fund debt service reserves and for other operating activities. Trade credit support includes cash collateral, letters of credit and financial guarantees. In the event that we default, the counterparty can draw on a letter of credit or apply cash collateral held to satisfy the existing amounts outstanding under an open contract. As of December 31, 2007, we had approximately $108 million of posted cash collateral and $290 million of letters of credit outstanding primarily to support our asset management activities, debt service and rent reserve requirements and other commercial arrangements. Of the letters of credit outstanding at December 31, 2007, $199 million was posted under our senior secured term loan and the remainder was issued under our $800 million senior secured revolving credit facility. Our liquidity requirements are highly dependent on the level of our hedging activity, forward prices for energy, emissions allowances and fuel, commodity market volatility and credit terms with third parties. See Note 9 to our consolidated and combined financial statements contained elsewhere in this report for additional information.
The following table summarizes at December 31, 2007 and 2006, for our continuing operations, cash collateral posted with counterparties and brokers and letters of credit issued (in millions):
Debt Obligations, Off-Balance Sheet Arrangements and Contractual Obligations
Our debt obligations, off-balance sheet arrangements and contractual obligations as of December 31, 2007, are as follows (in millions):
Operating leases are off-balance sheet arrangements. These amounts primarily relate to our minimum lease payments associated with our lease of the Morgantown and Dickerson baseload units at our Mid-Atlantic facilities.
Fuel commitments primarily relate to long-term coal agreements and other fuel purchase agreements. As of December 31, 2007, our total estimated fuel commitments were $506 million. In addition, we have transactions for which commercial terms have been negotiated but for which contracts have not yet been executed. Individual transactions may or may not be binding prior to execution of a contract.
As of December 31, 2007, the total estimated commitments under LTSAs associated with turbines were approximately $31 million. These commitments are payable over the terms of the respective agreements, which range from 10 to 20 years. These agreements have terms that allow for cancellation of the contracts by us upon the occurrence of certain events during the term of the contracts. Estimates for future commitments for the LTSAs are based on the stated payment terms in the contracts at the time of execution. These payments are subject to an annual adjustment for inflation.
Other represents open purchase orders less invoices received related to open purchase orders for general procurement of products and services purchased in the ordinary course of business. These include construction, maintenance and labor activities at our generating facilities.
Maryland Healthy Air Act commitments are contracts and open purchase orders related to capital expenditures that we will incur to comply with the limitations for SO2 and NOx emissions under the Maryland Healthy Air Act.
Long-term debt includes the current portion of long-term debt and long-term debt on the consolidated balance sheets. Long-term debt also includes estimated interest on debt based on the U.S. Dollar LIBOR curve as of December 31, 2007.
Cash Flows
The changes in our cash flows are detailed as follows (in millions):
2007 versus 2006
Continuing Operations
Operating Activities. Our cash provided by operating activities is affected by seasonality, changes in energy prices and fluctuations in our working capital requirements. Net cash provided by operating activities from continuing operations decreased $461 million for the year ended December 31, 2007, compared to 2006, primarily as a result of the following:
•
an increase in realized gross margin of $286 million for the year ended December 31, 2007, compared to 2006. See “Results of Operations” for additional discussion of our performance in 2007 compared to 2006;
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an increase from the receipt in 2007 of a net refund of $48 million related to the New York property tax settlement which is included in customer accounts receivable, net in the consolidated statements of cash flows;
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an increase of $18 million related to increases in net interest income as a result of higher cash balances resulting from the dispositions completed in 2007; partially offset by
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a decrease of $517 million as a result of changes in posted collateral levels which are included in funds on deposit in the consolidated statements of cash flows. For the year ended December 31, 2007, we posted an additional $70 million of cash collateral primarily to support energy marketing activities. The change in collateral for the year ended December 31, 2006, provided a source of cash of $447 million primarily because of a decrease in cash collateral to support energy marketing activities of $592 million and a reduction of $56 million in cash collateral posted in connection with the Mirant Mid-Atlantic lease upon posting $75 million of letters of credit. These amounts were partially offset by a use of cash as a result of the deposit of $200 million into a cash collateral account to support the issuance of letters of credit;
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a decrease of $64 million relating to net accounts receivable and accounts payable. The change in net accounts receivable and accounts payable for the year ended December 31, 2007, was a use of cash of $18 million. For the year ended December 31, 2006, the change in net accounts receivable and accounts payable was a source of cash of $46 million;
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a decrease of $60 million primarily as a result of the return in 2007 of deposits previously posted by our counterparties which is included in accounts payable and accrued liabilities in the consolidated statements of cash flows;
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a decrease of $59 million primarily related to changes in our fuel oil and emissions inventories. In 2007, fuel inventory increased $50 million and emissions inventory decreased $18 million.
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a decrease of $24 million resulting from an increase in operations and maintenance expenses, excluding the non-cash gain on the New York property tax settlement in 2006. See “Results of Operations” for additional discussion; and
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a decrease of $89 million related to all other changes.
Investing Activities. Net cash used in investing activities from continuing operations increased by $700 million for the year ended December 31, 2007, compared to 2006. This difference was primarily a result of the following:
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an increase of $426 million in capital expenditures and $22 million in capitalized interest primarily because of our environmental capital expenditures for our Mid-Atlantic generating facilities;
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a decrease of $207 million in repayments of notes receivable from affiliate, net;
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a decrease in proceeds from the sales of assets and investments of $48 million. In 2007, we received proceeds from the sale of assets of $49 million, which included approximately $22 million from the sale of ancillary equipment included in the sale of the Zeeland and Bosque natural gas-fired facilities and $24 million from the sales of emissions to third parties. In 2006, we received $97 million from the sale of assets, which included $12 million from the sale of a building, $20 million for the sale of our investment in the New York Mercantile Exchange and $58 million from the sale of a portion of our investment in InterContinental Exchange; and
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an increase of $3 million in proceeds from property insurance in 2007.
Financing Activities. Net cash used in financing activities from continuing operations decreased by $175 million for the year ended December 31, 2007, compared to 2006. This difference was primarily a result of the following:
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a decrease in proceeds from the issuance of long-term debt of $2.015 billion. Proceeds from the issuance of long-term debt in 2006 included $850 million from the Mirant North America debt offering, $700 million from the Mirant North America senior secured term loan and $465 million drawn on the Mirant North America senior secured revolving credit facility;
•
a decrease in the repayments of long-term debt of $2.106 billion. In 2007, we paid $138 million on the Mirant North America senior secured term loan. In 2006, we repaid $465 million on the Mirant North America senior secured revolving credit facility, which may be reborrowed, and $1.773 billion to settle obligations of Mirant Americas Generation under the Plan in 2006;
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a distribution of $695 million in 2007 to our member, as compared to $381 million for the same period in 2006;
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a payment of $250 million in 2006 to Mirant Americas under the Plan;
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an increase of $112 million as a result of to the issuance (repayment) of affiliate debt. In 2007, we had issuance of $7 million and in 2006 we had repayments of $105 million;
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a decrease in debt issuance costs of $51 million. In 2006, we paid $51 million in debt issuance costs associated with Mirant North America's debt offering, senior secured term loan and secured revolving credit facility;
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a decrease of $20 million as a result of the settlement of members’ obligations primarily related to the New York Entities' emergence under the plan of reorganization; and
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in 2007, we received $5 million from the redemption of preferred stock issued by Mirant Americas.
Discontinued Operations
Operating Activities. Net cash used in operating activities from discontinued operations increased by $39 million for the year ended December 31, 2007, compared to 2006. In 2006, operating activities included cash flows from the Zeeland and Bosque natural gas-fired facilities and Mirant NY-Gen for the entire year. In 2007, operating activities included all the discontinued facilities through their respective dates of sale.
Investing Activities. Net cash provided by investing activities from discontinued operations increased by $509 million for the year ended December 31, 2007, compared to 2006. This difference was primarily a result of the proceeds from the sale of the Zeeland and Bosque natural gas-fired facilities and Mirant NY-Gen in the second quarter of 2007.
Cash Flows
2006 versus 2005
Continuing Operations
Operating Activities. Our cash provided by operating activities is affected by seasonality, changes in energy prices and fluctuations in our working capital requirements. Net cash provided by operating activities from continuing operations increased $1.505 billion for the year ended December 31, 2006, compared to the same period in 2005, primarily due to the following:
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an increase in realized gross margin of $492 million for the year ended December 31, 2006, compared to the same period in 2005. See “Results of Operations” for additional discussion of our improved performance in 2006 compared to the same period in 2005;
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a decrease in energy trading collateral levels of $819 million in the year ended December 31, 2006, compared to the same period in 2005. The change in collateral requirements was due to the settlement of energy contracts combined with energy price declines in the year ended December 31, 2006, compared to the same period in 2005. For the year ended December 31, 2006, $592 million of cash collateral from brokers and counterparties was returned to us. For the year ended December 31, 2005, additional net collateral used to support commercial operations was $227 million; and
•
the release of $71 million cash held in escrow resulting from the settlement agreement for a claim payable to PG&E. See “California Settlement” in Note 15 to our combined and consolidated financial statements contained elsewhere in this report for additional information regarding the settlement.
Investing Activities. Net cash provided by investing activities from continuing operations increased $205 million for the year ended December 31, 2006, compared to 2005. This difference was primarily due to the following:
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an increase of $31 million in capital expenditures and $6 million in capitalized interest for 2006 compared to 2005, primarily due to our environmental capital expenditures in 2006 at Mid-Atlantic;
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an increase of $197 million in the repayment of notes receivable from affiliate. In 2006, we received repayments of notes receivable from affiliates of $207 million compared to $10 million for the same period in 2005; and
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an increase in the proceeds from the sales of assets and investments of $45 million. In 2006, we received $97 million in proceeds from the sales of assets and investments, which included $12 million from the sale of the Mirant Service Center, $20 million from the sale of our investment in the New York Mercantile Exchange and $58 million from the sale of a portion of our investment in InterContinental Exchange. In 2005, proceeds from the sales of assets and investments were $52 million and included $48 million from the sale of a portion of our investment in InterContinental Exchange and $4 million in additional proceeds from the 2004 sale of the Bowline gas turbines.
Financing Activities. Net cash used in financing activities from continuing operations increased by $908 million for the year ended December 31, 2006, compared to 2005. This difference was primarily due to the following:
•
an increase in proceeds from the issuance of long-term debt of approximately $2 billion. Proceeds from the issuance of long-term debt in 2006 included $850 million from the Mirant North America debt offering that was released from escrow on January 3, 2006, $700 million from the Mirant North America senior secured loan and $465 million drawn on the Mirant North America senior secured revolving credit facility. In 2006 we also incurred $51 million in debt issuance costs;
•
in 2005, proceeds from the issuance of debt-affiliate of $21 million represented advances under the intercompany cash management program;
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an increase in repayments of long-term debt comprised of the repayment of $465 million on our senior secured revolving credit facility and approximately $1.773 billion to settle obligations of Mirant Americas Generation under the Plan. In 2006, we also made $105 million repayments of debt to affiliates;
•
distributions to members of $381 million in 2006 compared to $129 million in 2005; and
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the payment of $250 million to Mirant Americas under the Plan.
Critical Accounting Estimates
The accounting policies described below are considered critical to obtaining an understanding of our consolidated and combined financial statements because their application requires significant estimates and judgments by management in preparing our consolidated and combined financial statements. Management’s estimates and judgments are inherently uncertain and may differ significantly from actual results achieved. Management considers an accounting estimate to be critical if the following conditions apply:
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the estimate requires significant assumptions; and
•
changes in the estimate could have a material effect on our consolidated and combined results of operations or financial condition; or,
•
if different estimates that could have been selected had been used, there could be a material effect on our consolidated and combined results of operations or financial condition.
We have discussed the selection and application of these accounting estimates with the Board of Managers and our independent auditors. It is management’s view that the current assumptions and other considerations used to estimate amounts reflected in our consolidated and combined financial statements are appropriate. However, actual results can differ significantly from those estimates under different assumptions and conditions. The sections below contain information about our most critical accounting estimates, as well as the effects of hypothetical changes in the material assumptions used to develop the estimates.
Revenue Recognition and Accounting for Energy Trading and Marketing Activities
Nature of Estimates Required. We utilize two comprehensive accounting models in reporting our consolidated and combined financial position and results of operations as required by GAAP-an accrual model and a fair value model. We determine the appropriate model for our operations based on applicable accounting standards.
The accrual model has historically been used to account for our revenues from the sale of energy, capacity and ancillary services. We recognize revenue when earned and collection is probable as a result of electricity delivered to customers pursuant to contractual commitments that specify volume, price and delivery requirements. Sales of energy are based on economic dispatch, or they may be ‘as-ordered’ by an ISO, based on member participation agreements, but without an underlying contractual commitment. ISO revenues and revenues for sales of energy based on economic-dispatch are recorded on the basis of MWh delivered, at the relevant day-ahead or real-time prices.
The fair value model has historically been used for derivative energy contracts that economically hedge our electricity generating facilities or that are used in our proprietary trading activities. We use a variety of derivative contracts, such as futures, swaps and option contracts, in the management of our business. Such derivative contracts have varying terms and durations, or tenors, which range from a few days to a number of years, depending on the instrument.
Pursuant to SFAS 133, derivative contracts are reflected in our financial statements at fair value, with changes in fair value recognized currently in earnings unless they qualify for a scope exception. We deferred inception gains and losses in accordance with EITF 02-3 for the periods presented. Management considers fair value techniques, valuation adjustments related to credit and liquidity and judgments related to the probability of completing forecasted transactions to be critical accounting estimates. These estimates are considered significant because they are highly susceptible to change from period to period and are dependent on many subjective factors. The fair value of derivative contracts is included in price risk management assets and liabilities affiliate and nonaffiliate in our consolidated balance sheets. Transactions that do not qualify for accounting under SFAS 133, either because they are not derivatives or because they qualify for a scope exception, are accounted for under accrual accounting as described above.
Key Assumptions and Approach Used. Determining the fair value of derivatives involves significant estimates based largely on the mid-point of quoted prices in active markets. The mid-point may vary significantly from the bid or ask price for some delivery points. If no active market exists, we estimate the fair value of certain derivative contracts using quantitative pricing models. Fair value estimates involve uncertainties and matters of significant judgment. Our modeling techniques for fair value estimation include assumptions for market prices, supply and demand market data, correlation and volatility. The degree of complexity of our pricing models increases for longer duration contracts, contracts with multiple pricing features, option contracts and off-hub delivery points.
The fair value of price risk management assets and liabilities affiliate and nonaffiliate in our consolidated balance sheets is also affected by our assumptions as to interest rate, counterparty credit risk and liquidity risk. The nominal value of the contracts is discounted using a forward interest rate curve based on LIBOR. In addition, the fair value of our price risk management assets is reduced to reflect the estimated risk of default of counterparties on their contractual obligations to us.
Effect if Different Assumptions Used. The amounts recorded as revenue or cost of fuel, electricity and other products change as estimates are revised to reflect actual results and changes in market conditions or other factors, many of which are beyond our control. Because we use derivative financial instruments and have not elected cash flow or fair value hedge accounting under SFAS 133, certain components of our financial statements, including gross margin, operating income and balance sheet ratios, are at times volatile and subject to fluctuations in value primarily as a result of changes in energy and fuel prices. As a result of the complexity of the models used to value some of the derivative instruments each period, a significant change in estimate could have a material effect on our results of operations and cash flows at the time contracts are ultimately settled. Upon the adoption of SFAS 157 on January 1, 2008, we will no longer defer inception gains and losses. Additionally, we will incorporate our own credit standing in the fair value measurement of our liabilities. Upon the adoption of FSP FIN 39-1 on January 1, 2008, we will net cash collateral in the measurement of the fair value
of our derivative contracts under master netting arrangements. See Note 4 to our consolidated and combined financial statements contained elsewhere in this report for further information on financial instruments related to energy trading and marketing activities.
For additional information regarding accounting for derivative instruments, see Item 7A.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
We are exposed to market risks associated with commodity prices, interest rates and credit risk.
Commodity Price Risk
In connection with our business of generating electricity, we are exposed to energy commodity price risk associated with the acquisition of fuel needed to generate electricity, as well as the price of electricity produced and sold. A portion of our fuel requirements is purchased in the spot market and a portion of the electricity we produce is sold in the spot market. In addition, the open positions in our proprietary trading activities expose us to risks associated with changes in energy commodity prices. As a result, our financial performance varies depending on changes in the prices of energy and energy-related commodities. See “Critical Accounting Estimates” for a discussion of the accounting treatment for proprietary trading and asset management activities.
The financial performance of our business of generating electricity is influenced by the difference between the variable cost of converting a fuel, such as natural gas, oil or coal, into electricity, and the revenue we receive from the sale of that electricity. The difference between the cost of a specific fuel used to generate one MWh of electricity and the market value of the electricity generated is commonly referred to as the “conversion spread.” Absent the effects of our price risk management activities, the operating margins that we realize are equal to the difference between the aggregate conversion spread and the cost of operating the facilities that produce the electricity sold.
Conversion spreads are dependent on a variety of factors that influence the cost of fuel and the sales price of the electricity generated over the longer term, including conversion spreads of other generating facilities in the regions in which we operate, facility outages, weather and general economic conditions. As a result of these influences, the cost of fuel and electricity prices do not always change in the same magnitude or direction, which results in conversion spreads for a particular generating facility widening or narrowing (or becoming negative) over any given period.
Through our asset management activities, we enter into a variety of exchange-traded and OTC energy and energy-related derivative contracts, such as forward contracts, futures contracts, option contracts and financial swap agreements to manage our exposure to commodity price risks and changes in conversion spreads. These contracts have varying terms and durations which range from a few days to years, depending on the instrument. Our proprietary trading activities also utilize similar contracts in markets where we have a physical presence to attempt to generate incremental gross margin.
Derivative energy contracts that are required to be reflected at fair value are presented as price risk management assets and liabilities-affiliate and nonaffiliate in the accompanying consolidated balance sheets. The net changes in their market values are recognized in income in the period of change. The determination of fair value considers various factors, including closing exchange or OTC market price quotations, time value, credit quality, liquidity and volatility factors underlying options.
The volumetric weighted average maturity, or weighted average tenor, of the price risk management portfolio at December 31, 2007, was approximately 12 months. The net notional amount, or net short position, of the price risk management assets and liabilities-affiliate and nonaffiliate at December 31, 2007, was approximately 26 million equivalent MWh.
The following table provides a summary of the factors affecting the change in net fair value of the price risk management asset and (liability) accounts in 2007 (in millions):
The fair values of our price risk management assets and liabilities-affiliate and nonaffiliate, net of credit reserves, as of December 31, 2007, are as follows (in millions):
We have additional coal contracts with a net fair value of approximately $134 million at December 31, 2007. These contracts are not required to be recorded at fair value under SFAS 133. As such, these contracts are not included in price risk management assets and liabilities in the accompanying consolidated balance sheets.
The following table represents the net price risk management assets and liabilities by tenor (in millions):
Value at Risk
Our Risk Management Policy prohibits the trading of certain products (e.g., natural gas liquids and pulp and paper) and contains limits and restrictions related to our asset management and proprietary trading activities.
We manage the price risk associated with asset management activities through a variety of methods. Our Risk Management Policy requires that asset management activities are restricted to only those activities that are risk-reducing. We ensure compliance with this restriction at the transactional level by testing each individual transaction executed relative to the overall asset position.
We also use VaR to measure the market price risk of our energy asset portfolio as a result of potential changes in market prices. VaR is a statistical model that provides an estimate of potential loss. We calculate VaR based on the parametric variance/covariance approach, utilizing a 95% confidence interval and a one-day holding period on a rolling 24-month forward looking period. Additionally, we estimate correlation based on historical commodity price changes. Volatilities are based on a combination of historical price changes and implied market rates.
VaR is calculated on an asset management portfolio comprised of mark-to-market and non mark-to-market energy assets and liabilities including generating facilities and bilateral physical and financial transactions. We also calculate VaR on portfolios consisting of mark-to-market and non mark-to-market bilateral physical and financial transactions related to our proprietary trading activities and fuel oil management operations. Asset management VaR levels are substantially reduced due to our decision to hedge actively in the forward markets the commodity price risk related to the expected generation and fuel usage of our generating facilities. See Item 1. “Commercial Operations” for discussion of our hedging strategies and Item 7. “Critical Accounting Estimates” for the accounting treatment of asset management and proprietary trading activities.
The following table summarizes year-end, average, maximum and minimum VaR for our asset management portfolio and proprietary trading and fuel oil management operations (in millions):
The asset management VaR declined for the year ended December 31, 2007, as compared to the year ended December 31, 2006, primarily as a result of increased hedging activity against our underlying generating facilities.
Because of inherent limitations of statistical measures such as VaR and the seasonality of changes in market prices, the VaR calculation may not reflect the full extent of our commodity price risk exposure. Additionally, actual changes in the fair value of mark-to-market energy assets and liabilities could differ from the calculated VaR, and such changes could have a material effect on our financial results.
Interest Rate Risk
We have two loans that provide for a variable rate of interest. Interest expense on such borrowings is sensitive to changes in the market rate of interest.
Our total debt from operations that is subject to variable interest rates through either our senior secured term loan or our senior secured revolving credit facility, assuming they are fully drawn, is approximately $1.4 billion. A 1% per annum increase in the average market rate would result in an increase in our annual interest expense of approximately $14 million.
Credit Risk
Credit risk represents the loss that we would incur if a counterparty failed to perform under its contractual obligations less the value of collateral held by us. We have established controls and procedures in our Risk Management Policy to determine and monitor the creditworthiness of customers and counterparties. Our credit policies are established and monitored by the Risk Oversight Committee. The Risk Oversight Committee includes the Chief Financial Officer and management’s representatives from several functional areas. We use published ratings of customers, as well as our internal analysis, to guide us in the process of setting credit levels, risk limits and contractual arrangements, including master netting agreements. Where external ratings are not available, we rely on our internal assessments of customers.
Collection Risk
Once we bill a customer for the commodity delivered or have financially settled the credit risk, we are subject to collection risk. Collection risk is similar to credit risk and collection risk is accounted for when we establish our allowance for bad debts. We manage this risk using the same techniques and processes used in credit risk discussed above.
Item 8.
Item 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
The Member
Mirant North America, LLC:
We have audited the accompanying consolidated balance sheets of Mirant North America, LLC (a wholly-owned indirect subsidiary of Mirant Corporation) and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of operations, equity and comprehensive income (loss) and cash flows for each of the years in the two-year period ended December 31, 2007, and the related combined statements of operations, equity and comprehensive income (loss) and cash flows for the year ended December 31, 2005. These consolidated and combined financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated and combined financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated and combined financial statements referred to above present fairly, in all material respects, the financial position of Mirant North America, LLC and subsidiaries as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 2 to the consolidated and combined financial statements, the Company adopted Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes, in 2007 and Financial Accounting Standards Board Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations: an interpretation of FASB Statement No. 143, in 2005.
/S/KPMG LLP
Atlanta, Georgia
March 9, 2008
MIRANT NORTH AMERICA, LLC AND SUBSIDIARIES
(Wholly-Owned Indirect Subsidiary of Mirant Corporation)
DECEMBER 31, 2007 AND 2006, CONSOLIDATED STATEMENTS OF OPERATIONS
AND
DECEMBER 31, 2005, COMBINED STATEMENT OF OPERATIONS
The accompanying notes are an integral part of these consolidated and combined financial statements.
MIRANT NORTH AMERICA, LLC AND SUBSIDIARIES
(Wholly-Owned Indirect Subsidiary of Mirant Corporation)
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated and combined financial statements.
MIRANT NORTH AMERICA, LLC AND SUBSIDIARIES
(Wholly-Owned Indirect Subsidiary of Mirant Corporation)
DECEMBER 31, 2007 AND 2006, CONSOLIDATED STATEMENTS OF EQUITY
AND COMPREHENSIVE INCOME (LOSS)
AND
DECEMBER 31, 2005, COMBINED STATEMENT OF EQUITY (DEFICIT) AND COMPREHENSIVE INCOME (LOSS)
(in millions)
The accompanying notes are an integral part of these consolidated and combined financial statements.
MIRANT NORTH AMERICA, LLC AND SUBSIDIARIES
(Wholly-Owned Indirect Subsidiary of Mirant Corporation)
DECEMBER 31, 2007 AND 2006, CONSOLIDATED STATEMENTS OF CASH FLOWS
AND
DECEMBER 31, 2005, COMBINED STATEMENT OF CASH FLOWS
(in millions)
The accompanying notes are an integral part of these consolidated and combined financial statements.
MIRANT NORTH AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS
December 31, 2007, 2006 and 2005
1. Description of Business and Organization
Mirant North America is a competitive energy company that produces and sells electricity. The Company owns or leases 10,280 MW of electric generating capacity located in markets in the Mid-Atlantic and Northeast regions and in California. The Company also operates an integrated asset management and energy marketing organization based in Atlanta, Georgia.
Mirant North America is a Delaware limited liability company, a wholly-owned subsidiary of Mirant Americas Generation and an indirect wholly-owned subsidiary of Mirant. Mirant Corporation was incorporated in Delaware on September 23, 2005. Pursuant to the Plan for Mirant and certain of its subsidiaries, on January 3, 2006, New Mirant emerged from bankruptcy and acquired substantially all of the assets of Old Mirant, a corporation that was formed in Delaware on April 3, 1993, and that had been named Mirant Corporation prior to January 3, 2006.
In the third quarter of 2006, Mirant commenced auction processes to sell six U.S. natural gas-fired facilities including the Company’s Zeeland and Bosque facilities. On May 1, 2007, the Company completed the sale of the Zeeland and Bosque natural gas-fired facilities. In addition, on May 7, 2007, the Company completed the sale of Mirant NY-Gen, an indirect wholly-owned subsidiary. In accordance with Mirant North America’s debt covenants, approximately $524 million of the proceeds from the sale of the Zeeland and Bosque facilities are being reinvested in the business. At December 31, 2007, $273 million of such proceeds have been reinvested in the business. See Note 10 for additional information regarding the accounting for these facilities as discontinued operations.
On April 9, 2007, Mirant announced that its Board of Directors had decided to explore strategic alternatives to enhance stockholder value. In the exploration process, the Board of Directors considered whether the interests of stockholders would be best served by returning excess cash from the sale proceeds to stockholders, with Mirant continuing to operate its retained businesses or, alternatively, whether greater stockholder value would be achieved by entering into a transaction with another company, including a sale of Mirant in its entirety. On November 9, 2007, Mirant announced the conclusion of the strategic review process. Mirant plans to return a total of $4.6 billion of excess cash to its stockholders.
The accompanying consolidated financial statements include the accounts of Mirant North America and reflect the effects of the Plan as of December 31, 2005, including:
•
The contribution by Mirant of its interest in Mirant Potomac River and Mirant Peaker to the Company’s indirect wholly-owned subsidiary, Mirant Mid-Atlantic, and its interest in Mirant Zeeland and in Mirant Americas Energy Marketing, Mirant Americas Development, Inc., Mirant Americas Production Company, Mirant Americas Energy Capital, LLC, Mirant Americas Energy Capital Assets, LLC, Mirant Americas Development Capital, LLC, Mirant Americas Retail Energy Marketing, LP, and Mirant Americas Gas Marketing I-XV, LLCs (collectively, the “Trading Debtors”) to Mirant North America. All of the contributed subsidiaries were under the common control of Mirant and are collectively referred to as the “Contributed Subsidiaries.”
•
The transfer of the trading and marketing business of the Trading Debtors to Mirant Energy Trading, a wholly-owned subsidiary of Mirant North America. After these transfers took place on January 31, 2006, the Trading Debtors were transferred to a trust created under the Plan that is not affiliated with the Company.
The accompanying 2005 combined financial statements present the results of operations and cash flows based on the assets, liabilities and operations of the predecessor Contributed Subsidiaries and Mirant Americas Generation.
2. Accounting and Reporting Policies
Basis of Presentation
The accompanying consolidated and combined financial statements of Mirant North America have been prepared in accordance with GAAP.
The accompanying consolidated and combined financial statements include the accounts of Mirant North America and its wholly-owned subsidiaries and the Contributed Subsidiaries and Mirant Americas Generation as discussed in Note 1 and have been prepared from the records maintained by Mirant North America, its subsidiaries and the Contributed Subsidiaries and Mirant Americas Generation. All significant intercompany accounts and transactions have been eliminated in consolidation.
In preparing the Company’s 2007 consolidated statement of cash flow, the Company discovered that capitalized interest expense for projects under construction had been included in cash flows from operating activities, rather than cash flows from investing activities in 2006. The result of the misstatement was an understatement of cash provided by operating activities and an understatement of cash used in investing activities of approximately $6 million for the year ended December 31, 2006. The misstatement had no effect on cash, net income, or stockholders’ equity. The consolidated statement of cash flows for the year ended December 31, 2006, has been adjusted to reflect the immaterial correction of this misstatement.
In accordance with SFAS 144, the results of operations of the Company’s facilities that have been disposed of and have met the criteria for such classification, have been reclassified to discontinued operations and the associated assets and liabilities have been reclassified to assets and liabilities held for sale for all periods presented.
Certain prior period amounts have been reclassified to conform to the current year financial statement presentation.
Use of Estimates
The preparation of consolidated and combined financial statements in conformity with GAAP requires management to make a number of estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from those estimates. The Company’s significant estimates include:
•
determining the fair value of certain derivative contracts;
•
estimating future taxable income in determining its deferred tax asset valuation allowance;
•
estimating the useful lives of the Company’s long-lived assets;
•
determining the value of the Company’s asset retirement obligations;
•
estimating future cash flows in determining impairments of long-lived assets and definite-lived intangible assets; and
•
estimating losses to be recorded for contingent liabilities.
Revenue Recognition
Mirant North America recognizes revenue from the sale of energy when earned and collection is probable. Some sales of energy are based on economic dispatch or ‘as-ordered’ by an ISO, based on member participation agreements, but without an underlying contractual commitment. ISO revenues and revenues from sales of energy based on economic-dispatch are recorded on the basis of MWh delivered, at the relevant day-ahead or real-time prices. When a long-term electric power agreement conveys to the buyer of the electric power the right to use the
generating capacity of Mirant North America’s facility, that agreement is evaluated to determine if it is a lease of the generating facility rather than a sale of electric power. Operating lease revenue for the Company’s generating facilities is normally recorded as capacity revenue and included in operating revenues in the consolidated and combined statements of operations.
Derivative Financial Instruments
Derivative financial instruments are recorded in the accompanying consolidated balance sheets at fair value as either price risk management assets or liabilities-affiliate or nonaffiliate, and changes in fair value are recognized currently in earnings, unless the Company elects to apply fair value or cash flow hedge accounting based on meeting specific criteria in SFAS 133. For the years ended December 31, 2007, 2006 and 2005, the Company did not have any derivative instruments that it had designated as fair value or cash flow hedges for accounting purposes. Mirant North America’s derivative financial instruments are categorized by the Company based on the business objective the instrument is expected to achieve: asset management or proprietary trading. All derivative contracts are recorded at fair value, except for a limited number of transactions that qualify for the normal purchase or normal sale exclusion from SFAS 133 and therefore qualify for the use of accrual accounting.
As the Company’s commodity derivative financial instruments have not been designated as hedges for accounting purposes, changes in such instruments’ fair values are recognized currently in earnings. For asset management activities, changes in fair value of electricity derivative financial instruments are reflected in operating revenue-affiliate and nonaffiliate and changes in fair value of fuel derivative contracts are reflected in cost of fuel, electricity and other products-affiliate and nonaffiliate in the accompanying consolidated and combined statements of operations. Changes in the fair value and settlements of contracts for proprietary trading activities are recorded on a net basis as operating revenue-affiliate and nonaffiliate in the accompanying consolidated and combined statements of operations.
Concentration of Revenues
In 2007, 2006 and 2005, the Company earned a significant portion of its operating revenue and gross margin from the PJM energy market, where its Mirant Mid-Atlantic generating facilities are located. Mirant Mid-Atlantic’s revenues and gross margin as a percentage of the Company’s total revenues and gross margin from continuing operations are as follows:
Concentration of Labor Subject to Collective Bargaining Agreements
Under Mirant North America’s services agreement with Mirant Services, a direct subsidiary of Mirant, Mirant Services provides the Company’s personnel. At December 31, 2007, approximately 1,255 Mirant Services employees worked at the Company’s facilities. At December 31, 2007, approximately 66% of the Company’s total employees are subject to collective bargaining agreements, of which 60% are subject to the collective bargaining agreement in the Mid-Atlantic region.
Cash and Cash Equivalents
The Company considers all short-term investments with an original maturity of three months or less to be cash equivalents. At December 31, 2007, except for amounts held in bank accounts to cover current payables, all of the Company’s cash and cash equivalents were invested in AAA-rated U.S. Treasury money market funds.
Restricted Cash
Restricted cash is included in current and noncurrent assets as funds on deposit and other noncurrent assets in the accompanying consolidated balance sheets. At December 31, 2007, current and noncurrent funds on deposit were $302 million and $7 million, respectively. At December 31, 2006, current and noncurrent funds on deposit were $233 million and $6 million, respectively. Restricted cash includes deposits with brokers and cash collateral posted with third parties to support the Company’s commodity positions as well as a $200 million deposit posted under the Company’s senior secured term loan to support the issuance of letters of credit.
Inventory
Inventory consists primarily of oil, coal, purchased emissions allowances and materials and supplies. Inventory, including commodity trading inventory, is generally stated at the lower of cost or market value. Fuel stock is removed from the inventory account as it is used in the production of electricity. Materials and supplies are removed from the inventory account when they are used for repairs, maintenance or capital projects.
Purchased emissions allowances are recorded in inventory at the lower of cost or market. Cost is computed on an average cost basis. Purchased emissions allowances for SO2 and NOx are removed from inventory and charged to cost of fuel, electricity and other products in the accompanying consolidated and combined statements of operations as they are utilized against emissions volumes that exceed the allowances granted to the Company by the EPA.
Inventory at December 31, 2007 and 2006, consisted of (in millions):
Granted Emissions Allowances
Included in property, plant and equipment are emissions allowances granted by the EPA that were projected to be required to offset physical emissions related to generating facilities owned by the Company. These emissions allowances were recorded at fair value at the date of the acquisition of the facility and are depreciated on a straight-line basis over the estimated useful life of the respective generating facility and are charged to depreciation and amortization expense in the accompanying consolidated and combined statements of operations.
Included in other intangible assets are: (1) emissions allowances granted by the EPA related to generating facilities owned by the Company that are projected to be in excess of those required to offset physical emissions; and (2) emissions allowances related to generating facilities leased by the Company. Emissions allowances related to leased generating facilities are recorded at fair value at the commencement of the lease. These emissions allowances are amortized on a straight-line basis over a period up to 30 years for emissions allowances related to owned generating facilities or the term of the lease for emissions allowances related to leased generating facilities, and are charged to depreciation and amortization expense in the accompanying consolidated and combined statements of operations.
As a result of the capital expenditures Mirant North America is making to comply with the requirements of the Maryland Healthy Air Act, the Company anticipates that it will have significant excess emissions allowances in future periods. The Company plans to continue to maintain some emissions allowances in excess of expected
generation in case its actual generation exceeds its current forecasts for future periods and for possible future additions of generating capacity. During the fourth quarter of 2007, the Company began a program to sell excess emissions allowances dependent upon market conditions. The Company sold approximately $24 million of excess emissions allowances and recognized a gain of $22 million, which is included in gain on sales of assets in the consolidated statement of operations for the year ended December 31, 2007. The Company has determined that certain exchanges of emissions allowances that the Company may periodically transact qualify as nonmonetary exchanges under SFAS 153.
Property, Plant and Equipment
Property, plant and equipment are recorded at cost, which includes materials, labor, and associated payroll-related and overhead costs and the cost of financing construction. The cost of routine maintenance and repairs, such as inspections and corrosion removal, and the replacement of minor items of property are charged to expense as incurred. Certain expenditures incurred during a major maintenance outage of a generating facility are capitalized, including the replacement of major component parts and labor and overhead incurred to install the parts. Depreciation of the recorded cost of depreciable property, plant and equipment is determined using primarily composite rates. Leasehold improvements are depreciated over the shorter of the expected life of the related equipment or the lease term. Upon the retirement or sale of property, plant and equipment the cost of such assets and the related accumulated depreciation are removed from the consolidated balance sheets. No gain or loss is recognized for ordinary retirements in the normal course of business since the composite depreciation rates used by the Company take into account the effect of interim retirements.
Capitalization of Interest Cost
The Company capitalizes interest on projects during their construction period. The Company determines which debt instruments represent a reasonable measure of the cost of financing construction assets in terms of interest cost incurred that otherwise could have been avoided. These debt instruments and associated interest costs are included in the calculation of the weighted average interest rate used for determining the capitalization rate. Once placed in service, capitalized interest, as a component of the total cost of the plant, is amortized over the estimated useful life of the plant. For the years ended December 31, 2007, 2006 and 2005, the Company incurred the following interest costs on debt to nonaffiliates (in millions):
In the third quarter of 2005, the Company determined that it was probable that contractual interest on liabilities subject to compromise from the Petition Date would be incurred for certain claims expected to be allowed under the Plan and, accordingly, recorded approximately $746 million of interest expense in 2005 on liabilities subject to compromise.
Operating Leases
Mirant North America leases various assets under non-cancelable leasing arrangements, including generating facilities, office space and other equipment. The rent expense associated with leases that qualify as operating leases is recognized on a straight-line basis over the lease term within operations and maintenance expense-nonaffiliate in the consolidated and combined statement of operations. The Company’s most significant operating leases are Mirant Mid-Atlantic’s leases of the Morgantown and Dickerson baseload units, which expire in 2034 and 2029, respectively. The Company has an option to extend these leases. Any extensions of the
respective leases would be limited to 75% of the economic useful life of the facility, as measured from the beginning of the original lease term through the end of the proposed remaining lease term. As of December 31, 2007, the total notional minimum lease payments for the remaining terms of the leases of the Morgantown and Dickerson baseload units aggregated approximately $2.1 billion.
Intangible Assets
Intangible assets with definite useful lives are amortized on a straight-line basis over their respective useful lives ranging up to 40 years to their estimated residual values.
Investments
For the years ended December 31, 2006 and 2005, the Company completed the sales of investments described below. The related gains are recorded in gain on sales of investments, net in the consolidated and combined statements of operations.
Equity Investment in InterContinental Exchange. In 2005, the Company sold a portion of its investment in InterContinental Exchange for $48 million and realized a gain of $44 million. In 2006, the Company sold its remaining investment in InterContinental Exchange for $58 million and realized a gain of $54 million.
New York Mercantile Exchange Seats. In late 1998 and early 1999, the Company acquired two seats on the New York Mercantile Exchange. In 2006, the Company sold its investment for $20 million and recognized a gain of $19 million, which is recorded in gain on sales of investments, net on the Company’s consolidated statement of operations.
Environmental Remediation Costs
The Company accrues for costs associated with environmental remediation when such costs are probable and can be reasonably estimated. Accruals for estimated losses from environmental remediation obligations generally are recognized no later than completion of the remediation feasibility study. Such accruals are adjusted as further information develops or circumstances change. The cost of future expenditures for environmental remediation obligations are discounted to their present value.
Debt Issuance Costs
Debt issuance costs are capitalized and amortized as interest expense on a basis that approximates the effective interest method over the term of the related debt.
Income Taxes
The Company is a limited liability company treated as a branch for income tax purposes. As a result, Mirant Americas and Mirant have direct liability for the majority of the federal and state income taxes relating to the Company’s operations. Through December 31, 2005, the Company has allocated current and deferred income taxes to each regarded corporate entity of its consolidated group as if each regarded corporate entity were a single taxpayer utilizing the asset and liability method to account for income taxes except with respect to recognizing certain current period tax benefits. Specifically, the Company did not record current period tax benefits on each regarded corporate entity’s ability to carry back its separate company current year NOL as realization of such losses is dependent on reimbursements from Mirant, which were at Mirant’s discretion under the tax sharing agreement. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. When necessary, deferred tax assets are reduced by a valuation allowance to reflect the amount that is estimated to be recoverable. In assessing the recoverability of its
deferred tax assets, the Company considers whether it is likely that some portion or all of the deferred tax assets will be realized. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
Several significant changes to the Company’s tax posture occurred as a result of the Plan. Implementation of the Plan included the conversion of certain of the Company’s regarded corporate entities to limited liability companies coupled with the liquidation and/or merger of these regarded corporate entities into other disregarded corporate entities for income tax purposes. As a result, certain subsidiaries previously treated as regarded corporate entities for income tax purposes have either been liquidated or converted into disregarded entities for income tax purposes pursuant to the Plan. Additionally, certain partnerships owned by the regarded corporate entities were also liquidated, and now form part of these disregarded entities for income tax purposes. The result of the above Plan effects was to eliminate the Company’s recording of tax expense and benefit prospectively with respect to the liquidated regarded corporate entities. Furthermore, with respect to those liquidated regarded corporate entities, all previously existing deferred tax assets and liabilities were eliminated as of December 31, 2005. Certain of the Company’s other subsidiaries continue to exist as regarded corporate entities for income tax purposes, including Hudson Valley Gas, Mirant Kendall and Mirant Special Procurement, Inc. In May 2007, Mirant New York was converted to a limited liability company, resulting in the elimination of any existing deferred tax assets and liabilities related to Mirant New York.
When it emerged from bankruptcy, Mirant terminated the tax sharing agreement with its direct and indirect wholly owned regarded corporate entities. As a result, Mirant’s direct and indirect wholly owned regarded corporate entities are no longer responsible for reimbursing Mirant for their intercompany tax obligations attributable to their operations. Accordingly, the Company’s income tax receivables and payables with Mirant or Mirant Americas were resolved pursuant to a global settlement under the Plan whereby intercompany receivables and payables received no distribution. The income tax payables and receivables related to Mirant New York, which remained in bankruptcy at December 31, 2006, were resolved upon its emergence from Bankruptcy, which became effective on April 16, 2007; however, for financial statement purposes, Mirant North America has recorded the effects of the plan of reorganization on March 31, 2007.
For those subsidiaries that continue to exist as corporate regarded entities, the Company continues to allocate current and deferred income taxes to each corporate regarded entity as if such entity were a single taxpayer utilizing the asset and liability method to account for income taxes. To the extent the Company provides tax expense or benefit, any related tax payable or receivable to Mirant is reclassified to equity in the same period.
SFAS 109 requires that a valuation allowance be established when it is more-likely-than-not that all or a portion of a deferred tax asset will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences are deductible. In making this determination, management considers all available positive and negative evidence affecting specific deferred tax assets, including the Company’s past and anticipated future performance, the reversal of deferred tax liabilities and the implementation of tax planning strategies.
Objective positive evidence is necessary to support a conclusion that a valuation allowance is not needed for all or a portion of deferred tax assets when significant negative evidence exists.
Impairment of Long-Lived Assets
The Company evaluates long-lived assets, such as property, plant and equipment, and purchased intangible assets subject to amortization, for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. Such evaluations are performed in accordance with SFAS 144. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future cash flows, an impairment charge is recognized as the amount by which the carrying amount of the asset exceeds its fair value. Assets to be disposed of are separately presented in the accompanying consolidated balance sheets and are reported at the lower of the carrying amount or fair value less costs to sell, and are not depreciated. The assets and liabilities of a disposal group classified as held for sale are presented separately in the appropriate asset and liability sections of the accompanying consolidated balance sheets.
Cumulative Effect of Changes in Accounting Principles
The Company adopted FIN 47, effective December 31, 2005, related to the costs associated with conditional legal obligations to retire tangible, long-lived assets. Conditional asset retirement obligations are recorded at the fair value in the period in which they are incurred by increasing the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted to its fair value and the capitalized costs are depreciated over the useful life of the related asset. For the year ended December 31, 2005, the Company recorded a charge as a cumulative effect of changes in accounting principle of approximately $15 million, net of tax, related to the adoption of this accounting standard.
Fair Value of Financial Instruments
SFAS No. 107 requires the disclosure of the fair value of all financial instruments that are not otherwise recorded at fair value in the financial statements. At December 31, 2007 and 2006, financial instruments recorded at contractual amounts that approximate market or fair value include cash and cash equivalents, funds on deposit, receivables from affiliate, customer accounts receivable, notes receivable-affiliate, accounts payable and accrued liabilities, payable to affiliate and notes payable - affiliate. The market values of such items are not materially sensitive to shifts in market interest rates because of the short term to maturity of these instruments. At December 31, 2007 and 2006, the fair value of the Company’s long-term accounts receivable of $1 million and $1 million, respectively, are not readily determinable due to uncertainty regarding the amount and timing of collection from the Company’s customers.
The fair value of the Company’s long-term debt is estimated using quoted market prices when available. At December 31, 2007 and 2006, the carrying value of the Company’s long-term debt approximated fair value.
Recently Adopted Accounting Standards
In February 2006, the FASB issued SFAS 155, which allows fair value measurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation. SFAS 155 is effective for all financial instruments acquired, issued or subject to a re-measurement event beginning in the first fiscal year after September 15, 2006. At the date of adoption, any difference between the total carrying amount of the existing bifurcated hybrid financial instrument and the fair value of the combined hybrid financial instrument will be recognized as a cumulative effect adjustment to beginning retained earnings. The Company adopted SFAS 155 on January 1, 2007. The adoption of SFAS 155 did not affect the Company’s statements of operations, financial position or cash flows.
In March 2006, the FASB issued SFAS 156, which requires all separately recognized servicing assets and servicing liabilities to be measured initially at fair value and permits, but does not require, an entity to measure subsequently those servicing assets or liabilities at fair value. The Company adopted SFAS 156 on January 1,
2007. All requirements for recognition and initial measurement of servicing assets and servicing liabilities have been applied prospectively to transactions occurring after the adoption of this statement. The adoption of SFAS 156 did not have a material effect on the Company’s statements of operations, financial position or cash flows.
On June 28, 2006, the FASB ratified the EITF’s consensus reached on EITF 06-3, which relates to the income statement presentation of taxes collected from customers and remitted to government authorities. The Task Force affirmed as a consensus on this issue that the presentation of taxes on either a gross basis or a net basis within the scope of EITF 06-3 is an accounting policy decision that should be disclosed pursuant to APB 22. A company should disclose the amount of those taxes that is recognized on a gross basis in interim and annual financial statements for each period for which an income statement is presented if those amounts are significant. The Company adopted EITF 06-3 on January 1, 2007. While the amounts are not material, the Company’s policy is to present such taxes on a net basis in the consolidated statements of operations.
On July 13, 2006, the FASB issued FIN 48. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS 109. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return.
On January 1, 2007, the Company adopted the provisions of FIN 48. Only tax positions that meet the more-likely-than-not recognition threshold at the effective date were recognized or continue to be recognized. The total effect of adopting FIN 48 was an increase in member’s interests of $51 million. See Note 7 for additional information on FIN 48.
On May 2, 2007, the FASB issued FSP FIN 48-1, which amended FIN 48 to provide guidance on how an enterprise should determine whether a tax position is effectively settled for the purpose of recognizing previously unrecognized tax benefits. In determining whether a tax position is effectively settled, companies are required to make the assessment on a position-by-position basis; however, a company could conclude that all positions in a particular tax year are effectively settled. The Company’s initial adoption of FIN 48 on January 1, 2007, was consistent with the provisions of FSP FIN 48-1.
New Accounting Standards Not Yet Adopted
On September 15, 2006, the FASB issued SFAS 157, which establishes a framework for measuring fair value under GAAP and expands disclosure about fair value measurements. SFAS 157 requires companies to disclose the fair value of their financial instruments according to a fair value hierarchy (i.e., levels 1, 2 and 3 as defined). Additionally, companies are required to provide enhanced disclosure regarding fair value measurements in the level 3 category, including a reconciliation of the beginning and ending balances separately for each major category of assets and liabilities accounted for at fair value. The Company adopted the provisions of SFAS 157 on January 1, 2008, for financial instruments and nonfinancial assets and liabilities recognized or disclosed at fair value in the financial statements on a recurring basis. The FASB deferred the effective date to January 1, 2009, for nonfinancial assets and liabilities that are not required or permitted to be measured at fair value on a recurring basis.
SFAS 157 nullifies a portion of the guidance in EITF 02-3. Under EITF 02-3, the transaction price presumption prohibited recognition of a day one gain or loss at the inception of a derivative contract unless the fair value of that derivative was substantially based on quoted prices or a valuation process incorporating observable inputs. Day one gains or losses on transactions that had been deferred under EITF 02-3 were recognized in the period that valuation inputs became observable or when the contract performed.
In addition, SFAS 157 also clarifies that an issuer’s credit standing should be considered when measuring liabilities at fair value, precludes the use of a block discount when measuring instruments traded in an actively quoted market at fair value and requires costs relating to acquiring instruments carried at fair value to be recognized as expense when incurred. SFAS 157 requires that a fair value measurement reflect the assumptions market participants would use in pricing an asset or liability based on the best available information.
SFAS 157 clarified that fair value should be measured at the exit price, which is the price to sell an asset or transfer a liability. The exit price may or may not equal the transaction price and the exit price objective applies regardless of a company’s intent or ability to sell the asset or transfer the liability at the measurement date. The Company currently measures fair value using the approximate mid-point of the bid and ask prices. Upon adoption of SFAS 157, the Company will measure fair value based on the bid or ask price for its price risk management assets and liabilities in accordance with the exit price objective.
The provisions of SFAS 157 are to be applied prospectively, except for the initial effect on three specific items: (1) changes in fair value measurements of existing derivative financial instruments measured initially using the transaction price presumption under EITF 02-3, (2) existing hybrid financial instruments measured initially at fair value using the transaction price, and (3) blockage factor discounts. Adjustments to these items required under SFAS 157 are to be recorded as a transition adjustment to beginning retained earnings in the year of adoption.
Upon adoption, the Company recognized a gain of approximately $1 million as a cumulative-effect adjustment to accumulated deficit, net of income tax on January 1, 2008. The cumulative-effect adjustment relates entirely to the recognition of inception gains and losses formerly deferred under EITF 02-3.
On February 15, 2007, the FASB issued SFAS 159, which permits an entity to measure many financial instruments and certain other items at fair value by electing a fair value option. Once elected, the fair value option may be applied on an instrument by instrument basis, is irrevocable and is applied only to entire instruments. SFAS 159 also requires companies with trading and available-for-sale securities to report the unrealized gains and losses for which the fair value option has been elected within earnings for the period presented. SFAS 159 is effective at the beginning of the first fiscal year after November 15, 2007. The Company adopted SFAS 159 on January 1, 2008. The adoption of SFAS 159 did not have a material effect on the Company’s statements of operations, financial position or cash flows as the Company did not elect the fair value option for any of its financial instruments.
On April 30, 2007, the FASB issued FSP FIN 39-1, which amended FIN 39, to indicate that the following fair value amounts could be offset against each other if certain conditions of FIN 39 are otherwise met: (a) those recognized for derivative instruments executed with the same counterparty under a master netting arrangement and (b) those recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) arising from the same master netting arrangement as the derivative instruments. In addition, a reporting entity is not precluded from offsetting the derivative instruments if it determines that the amount recognized upon payment or receipt of cash collateral is not a fair value amount. FSP FIN 39-1 is effective at the beginning of the first fiscal year after November 15, 2007. The adoption of FSP FIN 39-1 requires retrospective application for all financial statements presented as a change in accounting principle. The Company adopted FSP FIN 39-1 on January 1, 2008, and elected to continue to net the price risk management assets and liabilities subject to master netting agreements. The Company will reflect the adoption of FSP FIN 39-1 in its consolidated financial position at March 31, 2008, and reclassify amounts at December 31, 2007, to be consistent with the March 31, 2008, presentation. The adoption of FSP FIN 39-1 has no effect on the Company’s consolidated statements of operations or cash flows.
3. Related Party Arrangements and Transactions
Management, Personnel and Services Agreement with Mirant Services
Mirant Services provides the Company with various management, personnel and other services. The Company reimburses Mirant Services for amounts equal to Mirant Services’ direct costs of providing such services. The total costs incurred under the Management, Personnel and Services Agreement with Mirant Services has been included in the accompanying consolidated and combined statements of operations as follows (in millions):
Services and Risk Management Agreements with Affiliates
Historically, the Company provided energy marketing and fuel procurement services through Mirant Energy Trading to the following affiliates: Mirant Las Vegas, Mirant Sugar Creek, Shady Hills, West Georgia and Mirant Wichita Falls. Mirant Wichita Falls was sold by Mirant in the second quarter of 2006. On May 1, 2007, Mirant completed the sale of the other four affiliates. For the years ended December 31, 2007, 2006 and 2005, the total energy marketing costs were $47 million, $45 million and $54 million, respectively. For the years ended December 31, 2007, 2006 and 2005, the Company recorded a reduction to operations and maintenance of approximately $1 million, $6 million and $8 million, respectively, related to the allocation of costs to affiliates. Subsequent to the sale of these affiliates, the Company no longer recognizes a reduction to operations and maintenance associated with providing services to these affiliates.
Administration Arrangements with Mirant Services
Substantially all of Mirant’s corporate overhead costs are allocated to Mirant’s operating subsidiaries. For the years ended December 31, 2007, 2006 and 2005, the Company incurred approximately $125 million, $132 million and $133 million, respectively, in costs under these arrangements, which are included in operations and maintenance-affiliate in the accompanying consolidated and combined statements of operations.
The Company’s allocation of Mirant’s overhead costs has increased as a result of the recent disposition of Mirant’s Philippine and Caribbean businesses and six U.S. natural gas-fired facilities.
Restructuring Charges
For the years ended December 31, 2007 and 2006, the Company recorded restructuring charges of $1 million and for the year ended December 31, 2005, the Company recorded $3 million of severance costs and other charges, which are included in operations and maintenance-affiliate in the accompanying consolidated and combined statements of operations. The severance costs and other employee termination-related charges associated with the restructuring at the Company’s locations were paid by Mirant Services and billed to the Company and are included in the amounts disclosed above for management, personnel and services.
Notes Receivable from Affiliate and Notes Payable to Affiliate
During the pendency of the Chapter 11 proceedings, Mirant Americas Generation and certain of its subsidiaries and Mirant and certain of its subsidiaries (excluding Mirant Americas Generation and its subsidiaries) participated in separate intercompany cash management programs whereby cash balances at Mirant
and the respective participating subsidiaries were transferred to central concentration accounts to fund working capital and other needs of the respective participants. At December 31, 2007 and 2006, the Company had current notes receivable from Mirant Americas Generation of $93 million and $125 million, respectively, related to its pre-emergence intercompany cash management program. For the years ended December 31, 2007 and 2006, the Company earned $5 million and $6 million, respectively, of interest income related to the notes receivable, which is recorded in interest income-affiliate in the accompanying consolidated statements of operations. At December 31, 2007, and 2006, the Company had current notes payable to affiliate of $20 million and $27 million, respectively, arising out of the balances owed by Mirant Zeeland under Mirant’s pre-emergence cash management program, by Mirant New York, LLC under Mirant Americas Generation’s pre-emergence cash management program and by Mirant NY-Gen under its pre-emergence debtor-in-possession facility with Mirant Americas. The Company incurred interest expense-affiliate of $1 million for the years ended December 31, 2007 and 2006, and $23 million for the year ended December 31, 2005.
Payable to Mirant Americas Pursuant to the Plan
Mirant North America was required to pay $250 million to Mirant Americas within five days of the effective date of the Plan in return for Mirant’s contribution of its interest in the following: Mirant Americas Energy Marketing, Mirant Americas Development, Inc., Mirant Americas Production Company, Mirant Americas Energy Capital, LLC, Mirant Americas Energy Capital Assets, LLC, Mirant Americas Development Capital, LLC, Mirant Americas Retail Energy Marketing, LP, and Mirant Americas Gas Marketing, I-XV, LLCs. This amount was paid in January 2006.
Mirant Letters of Credit
Mirant posted pre-petition letters of credit and a guarantee on behalf of Mirant Mid-Atlantic to provide for the rent payment reserve required in connection with Mirant Mid-Atlantic’s lease obligations in the event that it was unable to pay its lease payment obligations. On January 3, 2006, as part of the settlement of disputes in respect of the Mirant Mid-Atlantic leveraged leases and the Company’s emergence from bankruptcy, Mirant North America posted a $75 million letter of credit for rent payment reserve obligations under the Mirant Mid-Atlantic leveraged leases. Upon the posting of the letter of credit, the trustee under the leveraged leases returned $56 million of cash collateral to Mirant Mid-Atlantic.
Mirant posted a post-petition letter of credit in the amount of $5 million on behalf of Mirant Texas, LP (“Mirant Texas”) as of December 31, 2004, related to a tolling agreement. This post-petition letter of credit was set to expire in January 2006. Upon emergence from bankruptcy, Mirant North America replaced this post-petition letter of credit with a letter of credit issued under its senior secured credit facilities. The letter of credit expired in February 2007.
Prior to 2005, Mirant entered into pre-petition letters of credit to support the Company’s asset management activities. In September 2005, several of these letters of credit were drawn in the amount of $39 million. In January 2006, the remaining pre-petition letter of credit of $7 million was drawn in full. In addition, Mirant entered into post-petition letters of credit to support its asset management activities. In January 2006, letters of credit from the Mirant North America senior secured credit facilities replaced the eleven post-petition letters of credit outstanding at December 31, 2005. See Liquidity and Capital Resources “Cash Collateral and Letters of Credit” for details on letters of credit outstanding at December 31, 2007.
Series A Preferred Shares in Mirant Americas
Pursuant to the Plan, Mirant Americas was required to make capital contributions to Mirant Mid-Atlantic for the purpose of funding future environmental capital expenditures. These capital contributions were made in the form of mandatorily redeemable Series A Preferred Shares, and are reflected as preferred stock in affiliate in the accompanying consolidated balance sheets at December 31, 2007 and 2006. On June 30, 2007, Mirant Americas was required to redeem $5 million in preferred stock held by Mirant Mid-Atlantic, which was completed on July 2, 2007.
The Series A Preferred Shares have a Scheduled Redemption Date at a Specified Redemption Amount as follows (in millions):
The redemption of any of the Series A Preferred Shares on any Scheduled Redemption Date shall be deferred to the extent that Mirant Mid-Atlantic has not incurred prior to the Scheduled Redemption Date, or does not reasonably expect to incur within 180 days of such Scheduled Redemption Date, expenditures with respect to the installation of control technology related to environmental capital expenditures at facilities owned or leased by Mirant Mid-Atlantic. Any amounts so deferred shall be added to the amount of Series A Preferred Shares to be redeemed on the next Scheduled Redemption Date.
Mirant Mid-Atlantic has the right to put the Series A Preferred Shares to Mirant at an amount equal to the Specified Redemption Amount in the event that Mirant Americas fails to redeem the Series A Preferred Shares on a Scheduled Redemption Date.
The Series A Preferred Shares are recorded at a fair value of $229 million and $221 million as a component of equity in the Company’s consolidated balance sheets at December 31, 2007 and 2006, respectively. The fair value was determined using a discounted cash flow method based on the Specified Redemption Amounts using a 6.21% discount rate. For the years ended December 31, 2007 and 2006, the Company recorded $13 million in preferred stock in affiliate and member’s interest in the consolidated balance sheets related to the amortization of the discount on the preferred stock in Mirant Americas.
4. Financial Instruments
Commodity Financial Instruments
The Company manages the risks around fuel supply and power to be generated from its physical asset positions. Mirant manages the price risk associated with asset management activities through a variety of methods. Mirant’s Risk Management Policy requires that asset management activities are restricted to only those activities that are risk-reducing in nature. In addition, the Company, through its proprietary trading and fuel oil management activities, attempts to achieve incremental returns by entering into energy contracts where it has specific market expertise or physical asset positions. Proprietary trading and fuel oil management activities increase risk and expose the Company to risk of loss if prices move differently than expected.
Mirant North America enters into a variety of derivative financial and physical instruments to manage its exposure to the prices of the fuel it acquires for generating electricity, as well as the electricity that it sells. These include contractual agreements, such as forward purchase and sale agreements, futures, swaps and option contracts. Futures are traded on national exchanges and swaps are typically traded in OTC financial markets. Option contracts are traded on both a national exchange and in OTC financial markets. These contractual agreements have varying terms, notional amounts and durations, or tenors, which range from a few days to a number of years, depending on the instrument. As part of its proprietary trading activities, the Company is exposed to certain market risks in an effort to generate gains from changes in market prices by entering into derivative instruments, including exchange-traded and OTC contracts, as well as other contractual arrangements.
Derivative instruments are recorded at their estimated fair value in the Company’s accompanying consolidated balance sheets as price risk management assets and liabilities except for a limited number of transactions that qualify for the normal purchase or normal sale exception election that allows accrual accounting treatment. Changes in the fair value and settlements of electricity derivative financial instruments are reflected in
operating revenue and changes in the fair value and settlements of fuel derivative contracts are reflected in cost of fuel and other products in the accompanying consolidated and combined statements of operations. As of December 31, 2007 and 2006, the Company does not have any derivative instruments for which hedge accounting has been elected.
The fair values of the Company’s price risk management assets and liabilities, net of credit reserves, at December 31, 2007 and 2006, were as follows (in millions):
The following table represents the net price risk management assets and liabilities by tenor (in millions):
The volumetric weighted average maturity, or weighted average tenor, of the price risk management portfolio at December 31, 2007, was approximately 12 months. The net notional amount or net short position, of the price risk management assets and liabilities at December 31, 2007, was approximately 26 million equivalent MWh.
5. Long-Lived Assets
Property, plant and equipment, net consisted of the following at December 31, 2007 and 2006 (dollars in millions):
Depreciation of the recorded cost of property, plant and equipment is recognized on a straight-line basis over the estimated useful lives of the assets. Acquired emissions allowances related to owned facilities that were projected to be required to offset physical emissions are included in production assets above, and are depreciated on a straight-line basis over the average life of the related generating facilities.
Intangible Assets, net
Following is a summary of intangible assets at December 31, 2007 and 2006 (dollars in millions):
Trading rights are intangible assets recognized in connection with asset purchases that represent the Company’s ability to generate additional cash flows by incorporating the Company’s trading activities with the acquired generating facilities.
Development rights represent the right to expand capacity at certain acquired generating facilities. The existing infrastructure, including storage facilities, transmission interconnections and fuel delivery systems and contractual rights acquired by the Company provide the opportunity to expand or repower certain generating facilities.
Emissions allowances recorded in intangible assets relate to emissions allowances granted for owned generating facilities that were projected at the time of acquisition to be in excess of those required to offset physical emissions and emissions allowances granted for the leasehold baseload units at the Morgantown and Dickerson facilities.
Emissions allowances granted by the EPA that were projected at the time of acquisition to be required to offset physical emissions for owned assets are recorded within property, plant and equipment, net on the consolidated balance sheets.
Amortization expense was approximately $8 million for the years ended December 31, 2007, 2006 and 2005. Assuming no future acquisitions, dispositions or impairments of intangible assets, amortization expense is estimated to be approximately $9 million for each of the next five years.
Impairments on Assets Held and Used
In accordance with SFAS 144, an asset classified as held and used shall be tested for recoverability whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recoverable. An asset impairment charge must be recognized if the sum of the undiscounted expected future cash flows from a long-lived asset is less than the carrying value of that asset. The amount of any impairment charge is calculated as the excess of the carrying value of the asset over its fair value. Fair value is estimated based on the discounted future cash flows from that asset or determined by other valuation techniques.
Year Ended December 31, 2007
Background
Mirant Lovett has been in ongoing discussions with the NYSDEC and the New York State Office of the Attorney General regarding environmental controls at the Lovett generating facility in New York. On June 11, 2003, Mirant New York, Mirant Lovett and the State of New York entered into a consent decree (the “2003 Consent Decree”). Under the terms of the 2003 Consent Decree, Mirant Lovett was required to install certain environmental controls on unit 5 of the Lovett facility, convert unit 5 to operate exclusively on natural gas, or discontinue operation of unit 5 by April 30, 2007. The 2003 Consent Decree also required that certain environmental controls be installed on unit 4 by April 30, 2008, or operation of unit 4 had to be discontinued.
On May 10, 2007, Mirant Lovett entered into an amendment to the 2003 Consent Decree with the State of New York that switched the deadlines for shutting down units 4 and 5 so that the deadline for compliance by unit 5 was extended until April 30, 2008, and the deadline for unit 4 was shortened. Unit 4 discontinued operation as of May 7, 2007. In addition, unit 3 discontinued operation because it was uneconomic for the unit to continue to run.
On May 8, 2007, Mirant New York, Mirant Lovett, Mirant Bowline and Hudson Valley Gas also entered into an agreement (the “Tax Assessments Agreement”) with the Town of Stony Point, the Town of Haverstraw and the Village of Haverstraw to set the assessed values for the Lovett and Bowline facilities and the pipeline owned by Hudson Valley Gas for 2007 and 2008 for property tax purposes at the values established for 2006 under a settlement agreement entered into by the Mirant entities and those taxing authorities in December 2006.
The Bankruptcy Court approved the amendment to the 2003 Consent Decree and the Tax Assessments Agreement on May 10, 2007. The United States District Court for the Southern District of New York approved the amendment to the 2003 Consent Decree on May 11, 2007.
On October 20, 2007, Mirant Lovett submitted notices of its intent to discontinue operations of unit 5 of the Lovett generating facility as of midnight on April 19, 2008, to the New York Public Service Commission, the NYISO, Orange and Rockland and several other potentially affected transmission and distribution companies in New York.
In its impairment analysis of the Lovett generating facility in prior periods, the Company assumed multiple scenarios, including the operation of all units of the Lovett facility beyond April 2008. Entering into the amendment to the 2003 Consent Decree and the Tax Assessments Agreement prompted management to test for recoverability of the Lovett facility under SFAS 144 in the second quarter of 2007.
Assumptions and Results
The Company’s assessment of Lovett under SFAS 144 in the second quarter of 2007 involved developing two scenarios for the future expected operation of the Lovett facility. The first scenario considered was the shutdown of unit 5 by April 30, 2008, in accordance with the amendment to the 2003 Consent Decree. The Company also considered a second scenario that assumed operation of unit 5, utilizing coal as the primary fuel source, through 2012 to allow the Lovett facility to continue to contribute to the reliability of the electric system of the State of New York. Property taxes under both scenarios were assumed at the assessed levels specified in the Tax Assessments Agreement for those periods. Additionally, both scenarios included an estimated cost for demolition of the facility to reduce future property taxes, a value for the land on which the facility operates and the sale of previously granted emissions allowances for periods beyond the shutdown date. For purposes of measuring an impairment loss, a long-lived asset or assets must be grouped at the lowest level of independent identifiable cash flows. All of the units at Mirant Lovett are viewed as one group. As required under SFAS 144, the assessment did not include the value of new generating capacity that could potentially be constructed at the current Lovett facility site.
As a result of this assessment, in the second quarter of 2007, the Company recorded an impairment loss of $175 million to reduce the carrying value of the Lovett facility to its estimated fair value. The carrying value of the Lovett facility prior to the impairment was approximately $185 million. The remaining depreciable life for the Lovett facility was also adjusted to April 30, 2008, based on the high likelihood of a shutdown of unit 5 on that date.
Year Ended December 31, 2006
In 2006, the Company’s assessment of the Bowline unit 3 suspended construction project resulted in the conclusion that the Bowline unit 3 project as configured and permitted was not economically viable. As a result of this conclusion, the Company determined the estimated value of the equipment and project termination liabilities. At December 31, 2006, the carrying value of the development and construction costs for Bowline unit 3 exceeded the estimated undiscounted cash flows from the abandonment of the project. The Company recorded an impairment of $118 million, which is reflected in impairment losses on the consolidated statement of operations for the year ended December 31, 2006.
6. Long-Term Debt
Long-term debt at December 31, 2007 and 2006, was as follows (in millions):
Mirant North America Senior Secured Credit Facilities
Mirant North America entered into senior secured credit facilities in January 2006, which are comprised of an $800 million senior secured revolving credit facility and a senior secured term loan with an initial principal balance of $700 million amortized to $555 million as of December 31, 2007. At the closing, $200 million drawn under the senior secured term loan was deposited into a cash collateral account to support the issuance of up to $200 million of letters of credit. At December 31, 2007, there were approximately $199 million of letters of credit outstanding under the senior secured term loan and approximately $91 million of letters of credit outstanding under the $800 million senior secured revolving credit facility. At December 31, 2007, a total of $710 million was available under the senior secured revolving credit facility and the senior secured term loan for cash draws or for the issuance of letters of credit.
In addition to the quarterly installments of $1.75 million, Mirant North America is required to prepay a portion of the outstanding senior secured term loan principal balance once a year. The prepayment is based on an adjusted EBITDA calculation that determines excess free cash flows, as defined in the loan agreement. At December 31, 2007, the current estimate of the mandatory principal prepayment of the term loan in the first quarter of 2008 is approximately $132 million. This amount has been reclassified from long-term debt to current portion of long-term debt at December 31, 2007.
The senior secured credit facilities are senior secured obligations of Mirant North America. In addition, certain subsidiaries of Mirant North America (not including Mirant Mid-Atlantic and its respective subsidiaries and Mirant Energy Trading) have jointly and severally guaranteed, as senior secured obligations, the senior secured credit facilities. The senior secured credit facilities are nonrecourse to any other Mirant entities.
Mirant North America Senior Notes
In December 2005, Mirant North America issued senior notes in an aggregate principal amount of $850 million that bear interest at 7.375% and mature on December 31, 2013. The original senior notes were issued in a private placement and were not registered with the SEC. The proceeds of the original senior notes offering initially were placed in escrow pending the emergence of Mirant North America from bankruptcy. The proceeds were released from escrow in connection with Mirant North America’s emergence from bankruptcy and the closing of the senior secured credit facilities.
In connection with the issuance of the original senior notes, Mirant North America entered into a registration rights agreement under which it agreed to complete an exchange offer for the original senior notes. On June 29, 2006, Mirant North America completed its registration under the Securities Act of $850 million of the senior notes and initiated the exchange offer. The exchange offer was completed on August 4, 2006, with $849.965 million of the outstanding original senior notes being tendered for the senior notes. The terms of the senior notes are identical in all material respects to the terms of the original senior notes, except that the senior notes are registered under the Securities Act and generally are not subject to transfer restrictions or registration rights.
Interest on the notes is payable on each June 30 and December 31. The senior notes are senior unsecured obligations of Mirant North America. In addition, certain subsidiaries of Mirant North America (not including Mirant Mid-Atlantic and its subsidiaries and Mirant Energy Trading) have jointly and severally guaranteed, as senior unsecured obligations, the senior notes. The senior notes are nonrecourse to any other Mirant entities. The notes are redeemable at the option of Mirant North America, in whole or in part, at any time prior to December 31, 2009, at a price equal to 100% of the principal amount, plus accrued and unpaid interest, plus a make-whole premium. At any time on or after December 31, 2009, Mirant North America may redeem the notes at specified redemption prices, together with accrued and unpaid interest, if any, to the date of redemption. At any time prior to December 31, 2008, Mirant North America may redeem up to 35% of the original principal amount of the notes with the proceeds of certain equity offerings at a redemption price of 107.375% of the
principal amount of the notes, together with accrued and unpaid interest, if any, to the date of redemption. Under the terms of the notes, the occurrence of a change of control will be a triggering event requiring Mirant North America to offer to purchase all or a portion of the notes at a price equal to 101% of their principal amount, together with accrued and unpaid interest, if any, to the date of purchase. In addition, certain asset dispositions or casualty events will be triggering events which may require Mirant North America to use the proceeds from those asset dispositions or casualty events to make an offer to purchase the notes at 100% of their principal amount, together with accrued and unpaid interest, if any, to the date of purchase if such proceeds are not otherwise used, or committed to be used, within certain time periods, to repay senior secured indebtedness, to repay indebtedness under the senior secured credit facilities (with a corresponding reduction in commitments) or to invest in capital assets related to its business.
Debt Maturities
At December 31, 2007, the annual scheduled maturities of debt during the next five years and thereafter were as follows (in millions):
With the exception of 2008, the annual scheduled maturities above do not include estimates of the Company’s required payments of its senior secured term loan based on its EBITDA.
Capital Leases
Long-term debt includes a capital lease by Mirant Chalk Point. At December 31, 2007 and 2006, the current portion of the long-term debt under this capital lease was $3 million. The amount outstanding under the capital lease, which matures in 2015, is $30 million with an 8.19% annual interest rate. This lease is of an 84 MW peaking electric power generating facility. Depreciation expense related to this lease was approximately $2 million for each of the years ended December 31, 2007, 2006 and 2005. The principal payments under this lease are approximately $3 million in 2008 through 2010, $4 million in 2011 through 2012 and $13 million thereafter. The gross amount of assets under the capital lease, recorded in property, plant and equipment, net as of December 31, 2007 and 2006, was $24 million. The related accumulated depreciation was $12 million and $10 million as of December 31, 2007 and 2006, respectively.
Sources of Funds and Capital Structure
The principal sources of liquidity for the Company’s future operations and capital expenditures are expected to be: (1) existing cash on hand and cash flows from the operations of the Company’s subsidiaries; (2) letters of credit issued or borrowings made under Mirant North America’s $800 million senior secured revolving credit facility; (3) $200 million letter of credit capacity available under Mirant North America’s senior secured term loan; and (4) proceeds from the redemption of preferred shares issued by Mirant Americas to Mirant Mid-Atlantic to fund capital expenditures.
Mirant North America is a holding company and, as a result, it is dependent upon dividends, distributions and other payments from its subsidiaries to generate the funds necessary to meet its obligations. The ability of the Company and certain of its subsidiaries to pay dividends and make distributions is restricted under the terms of their debt or other agreements. In particular, a substantial portion of the cash from the Company’s operations is generated by Mirant Mid-Atlantic. The Mirant Mid-Atlantic leveraged leases contain a number of covenants, including limitations on dividends, distributions and other restricted payments. Under its leveraged leases, Mirant Mid-Atlantic is not permitted to make any dividends, distributions and other restricted payments unless: (1) it satisfies the fixed charge coverage ratio on a historical basis for the last period of four fiscal quarters; (2) it is projected to satisfy the fixed charge coverage ratio for the next two periods of four fiscal quarters; and (3) no significant lease default or event of default has occurred and is continuing. In the event of a default under the leveraged leases or if the restricted payments test is not satisfied, Mirant Mid-Atlantic would not be able to distribute cash. Based on the Company’s calculation of the fixed charge coverage ratios under the leveraged leases as of December 31, 2007, Mirant Mid-Atlantic meets the required 1.7 to 1.0 ratio for restricted payments, both on a historical and projected basis.
Mirant North America is an intermediate holding company and the sole subsidiary of, and the source of distributions to, Mirant Americas Generation. Mirant Americas Generation relies on distributions from Mirant North America to fund the debt service on its $1.661 billion of senior notes. Mirant North America incurred certain indebtedness pursuant to its senior notes and senior secured credit facilities secured by the assets of Mirant North America and its subsidiaries (other than Mirant Mid-Atlantic and its subsidiaries and Mirant Energy Trading). The indebtedness of Mirant North America includes certain covenants typical in such notes and credit facilities, including restrictions on dividends, distributions and other restricted payments. Further, the notes and senior secured credit facilities include financial covenants that will exclude from the calculation the financial results of any subsidiary that is unable to make distributions or pay dividends at the time of such calculation. Thus, the ability of Mirant Mid-Atlantic to make distributions to Mirant North America under the leveraged lease transaction could have a material effect on the calculation of the financial covenants under the senior notes and senior secured credit facilities of Mirant North America and on its ability to make distributions to Mirant Americas Generation.
7. Income Taxes
Several changes to the Company’s tax posture occurred as a result of the Plan, including the conversion of certain of the Company’s regarded corporate entities to limited liability companies coupled with the liquidation and/or merger of these regarded corporate entities into other disregarded corporate entities for income tax purposes, and certain partnerships owned by the regarded corporate entities were also liquidated and now form part of these disregarded entities for income tax purposes. The result of the plan effects eliminates the Company’s recording of tax expense and benefit beginning January 1, 2006, with respect to the liquidated regarded corporate entities. Furthermore, with respect to those liquidated regarded corporate entities, all previously existing deferred tax assets and liabilities were eliminated as of December 31, 2005. In May 2007, Mirant New York, Inc. was converted to a limited liability company, resulting in the elimination of any existing deferred tax assets and liabilities related to Mirant New York.
Certain of the Company’s other subsidiaries continue to exist as regarded corporate entities for income tax purposes including Hudson Valley Gas, Mirant Kendall, and Mirant Special Procurement Inc. For those regarded corporate entities, the Company allocates current and deferred income taxes to each regarded corporate entity as if such entity were a single taxpayer utilizing the asset and liability method to account for income taxes. To the extent the Company provides tax expense or benefit, any related tax payable or receivable to Mirant is reclassified to equity in the same period. As such, $2 million was reclassified as a capital contribution to member’s interest for the year ended December 31, 2006.
Details of the income tax provision (benefit) are as follows (in millions):
A reconciliation of the Company’s expected federal statutory income tax provision (benefit) to the effective income tax provision for continuing operations adjusted for reorganization items is as follows (in millions):
The tax effects of temporary differences that give rise to significant portions of deferred tax assets and liabilities are as follows at December 31, 2007 and 2006 (in millions):
The amount and ultimate utilization of the Company’s remaining NOLs will depend on several factors, including the Company’s future financial performance and certain Mirant tax elections. At December 31, 2006, Mirant considered it to be more likely than not that it would elect treatment under §382(l)(5). As a result of further tax planning, Mirant made the decision to elect §382(l)(6) in its 2006 income tax return that was filed on
September 15, 2007. As a result, the Company’s deferred income tax items including pre-emergence NOLs are presented in accordance with the §382(l)(6) treatment at December 31, 2007. This change had no net effect on the consolidated balance sheets or consolidated statements of operations because the increase in the deferred tax asset NOLs was equally offset by an increase in the related deferred tax asset valuation allowance.
Under §382(l)(6), the Company will be subject to an annual limitation on the use of the pre-emergence NOLs including the effect of net unrealized built-in gains. The NOLs under this election will not be subject to any previous adjustments for interest accrued on debt settled with stock as required under §382(l)(5).
At December 31, 2007, the Company had $82 million of NOL carryforwards for federal income tax purposes expiring from 2023 to 2027 and $82 million of NOL carryforwards for state income tax purposes with various expiration dates (based on the application of apportionment factors and other state limitations). These NOL carryforwards are available to offset future federal and state income taxes.
SFAS No. 109 requires that a valuation allowance be established when it is more likely than not that all or a portion of a deferred tax asset will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences are deductible. In making this determination, management considers all available positive and negative evidence affecting specific deferred tax assets, including the Company’s past and anticipated future performance, the reversal of deferred tax liabilities, the implementation of tax planning strategies and management’s expectations of future reimbursements of NOL carryforwards from Mirant.
Objective positive evidence is necessary to support a conclusion that a valuation allowance is not needed for all or a portion of deferred tax assets when significant negative evidence exists. The Company continues to maintain its valuation allowance against its deferred tax assets. As of December 31, 2007, the Company’s deferred tax assets reduced by the valuation allowance are completely offset with its deferred tax liabilities. In 2007, 2006 and 2005, the Company recognized changes in its valuation allowance of $(65) million, $(50) million and $(534) million, respectively, related to its net deferred tax assets.
Tax Uncertainties
The Company, through its parent Mirant, negotiated a settlement agreement with the Internal Revenue Service (“IRS”) for certain tax liabilities arising from their audit of the Company’s federal income tax returns for tax years the Company was a subsidiary of the Southern Company. This agreement resulted in an assessment of $14 million including interest. The Company has provided adequate tax provisions in prior years for the recognition of this liability. As this liability represented an intercompany obligation to Mirant, the liability was resolved pursuant to the Plan of Reorganization with no distribution for such liability. Mirant has indemnified the Company with respect to this obligation.
The Company adopted the provisions of FIN 48 on January 1, 2007. Prior to adoption of FIN 48, the Company recognized contingent liabilities related to tax uncertainties when it was probable that a loss had occurred and the loss or range of loss could be reasonably estimated. The recognition of contingent losses for tax uncertainties required management to make significant assumptions about the expected outcomes of certain tax contingencies. Upon adoption of FIN 48, the Company changed its method to recognize only liabilities for uncertain tax positions that are less than or subject to the measurement threshold of the more-likely-than-not standard. As a result of the implementation of FIN 48, for continuing operations the Company recognized a decrease in accrued liabilities of $51 million. The additional tax benefit resulted in an increase of the same amount to member’s interest. The unrecognized tax benefit as a result of adopting FIN 48 is an insignificant amount and would not materially affect the Company’s effective tax rate if it were to be recognized. The Company does not currently anticipate any significant changes to the amount of the unrecognized tax benefit absent changes in judgment about the realizability of its recognized or unrecognized tax benefits.
The unrecognized tax benefit included the review of tax positions relating to open tax years beginning in 1999 and continuing to the present. The Company’s major tax jurisdictions are U.S. federal and several state jurisdictions. For U.S. federal income taxes, all tax years prior to 2004 are closed and for state purposes the earliest open tax year is 1999. However, both the federal and state NOL carryforwards from any closed year is subject to examination until the year that such NOL carryforwards are utilized and that year is closed for audit. The Company’s tax provision continues to include an immaterial amount related to the accrual for any penalties and interest subsequent to its adoption of FIN 48.
Pro Forma Income Tax Disclosures
The Company is not subject to income taxes except for those subsidiaries of the Company that are separate taxpayers. Mirant Americas and Mirant are otherwise directly responsible for income taxes related to the Company’s operations.
The following reflects a pro forma disclosure of the income tax provision that would be reported if the Company was to be allocated income taxes related to its operations. Pro forma income tax provision attributable to income before tax would consist of the following (in millions):
The following table presents the pro forma reconciliation of the Company’s federal statutory income tax provision (benefit) for continuing operations adjusted for reorganization items to the pro forma effective tax provision (in millions):
The tax effects of temporary differences between the carrying amounts of assets and liabilities in the consolidated balance sheet and their respective tax bases which give rise to the pro forma deferred tax assets and liabilities would be as follows at December 31, 2007 and 2006 (in millions):
Mirant elected in its 2006 tax return to reduce the income tax basis of its depreciable assets for any cancellation of debt income that arises from Mirant making an Internal Revenue Code section §382(l)(6) election. As a result, the Company has reduced the tax basis of its depreciable assets by recording a reduction to proforma property and intangible assets of $48 million in 2007.
As a result of Mirant’s election of §382(l)(6) in its 2006 income tax return, the Company’s deferred income tax items including pre-emergence NOLs are presented in accordance with the §382(l)(6) treatment at December 31, 2007. Mirant’s election had no effect on the Company’s pro forma net deferred tax assets or pro forma income tax expense because the increase in the pro forma deferred tax asset NOLs was equally offset by an increase in the related pro forma deferred tax asset valuation allowance.
Under §382(l)(6), the Company would be subject to an annual limitation on the use of the pre-emergence pro forma NOLs including the effect of net unrealized built-in gains. The pro forma NOLs under this election will not be subject to any previous adjustments for interest accrued on debt settled with Mirant stock as required under §382(l)(5).
As of December 31, 2007, a portion of the Company’s proforma NOLs (approximately $70 million) is attributable to excess tax deductions primarily related to bankruptcy transactions. The recognition of the pro forma tax benefit of these excess tax deductions, either through realization or reduction of the pro forma valuation allowance, would be an increase to pro forma member’s interest. These proforma NOLs will be the last utilized for financial reporting purposes.
The Company has not provided a pro forma deferred tax liability with respect to the Company’s investment in the Mirant Americas Preferred Stock discussed in Note 3, since the underlying transaction is disregarded for income tax purposes.
Pro Forma Tax Uncertainties
The pro forma increase in tax benefits that would have been recognized upon adoption of FIN 48 is $86 million. The pro forma unrecognized tax benefit as a result of adopting FIN 48 is an insignificant amount and would not materially affect the Company’s pro forma effective tax rate if it were recognized. The Company’s pro forma tax provision continues to include an immaterial amount related to the accrual for any pro forma penalties and interest subsequent to its adoption of FIN 48.
8. Asset Retirement Obligations
Effective January 1, 2003, the Company adopted SFAS 143, which requires an entity to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. Additionally, effective December 31, 2005, the Company adopted FIN 47, which expands the scope of asset retirement obligations to be recognized to include asset retirement obligations that may be uncertain as to the nature or timing of settlement. Upon initial recognition of a liability for an asset retirement obligation or a conditional asset retirement obligation, an entity shall capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. Over time, the liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Retirement obligations associated with long-lived assets included within the scope of SFAS 143 and FIN 47 are those for which a legal obligation exists under enacted laws, statutes and written or oral contracts, including obligations arising under the doctrine of promissory estoppel.
The Company identified certain asset retirement obligations within its power generating facilities. These asset retirement obligations are primarily related to asbestos abatement in facilities on owned or leased property and other environmental obligations related to fuel storage facilities, wastewater treatment facilities, ash disposal sites and pipelines.
Asbestos abatement is the most significant type of asset retirement obligation identified for recognition in the Company’s adoption of FIN 47. The EPA has regulations in place governing the removal of asbestos. Due to the nature of asbestos, it can be difficult to ascertain the extent of contamination in older facilities unless substantial renovation or demolition takes place. Therefore, the Company incorporated certain assumptions based on the relative age and size of its facilities to estimate the current cost for asbestos abatement. The actual abatement cost could differ from the estimates used to measure the asset retirement obligation. As a result, these amounts will be subject to revision when actual abatement activities are undertaken.
The following table sets forth the balances of the asset retirement obligations as of January 1, 2006, and the additions and accretion of the asset retirement obligations for the years ended December 31, 2007 and 2006. The asset retirement obligations are included in noncurrent liabilities in the consolidated balance sheets (in millions):
The following represents, on a pro forma basis, the amount of the liability for asset retirement obligations as if FIN 47 had been applied during all periods affected (in millions):
9. Commitments and Contingencies
Mirant North America has made firm commitments to buy materials and services in connection with its ongoing operations and has made financial guarantees relative to some of its investments.
Cash Collateral
In order to sell power and purchase fuel in the forward markets and perform other energy trading and marketing activities, the Company often is required to provide trade credit support to its counterparties or make deposits with brokers. In addition, the Company often is required to provide cash collateral for access to the transmission grid to participate in power pools and for other operating activities. In the event of default by the Company, the counterparty can apply cash collateral held to satisfy the existing amounts outstanding under an open contract.
The following is a summary of cash collateral posted with counterparties as of December 31, 2007 and 2006 (in millions):
Commitments
In addition to debt and other obligations in the consolidated balance sheets, Mirant North America has the following annual commitments under various agreements at December 31, 2007, related to its operations (in millions):
Operating Leases
Mirant Mid-Atlantic leases the Morgantown and Dickerson baseload units and associated property through 2034 and 2029, respectively. Mirant Mid-Atlantic has an option to extend the leases. Any extensions of the respective leases would be limited to 75% of the economic useful life of the facility, as measured from the beginning of the original lease term through the end of the proposed remaining lease term. The Company is accounting for these leases as operating leases and recognizes rent expense on a straight-line basis. Rent expense totaled $96 million for the years ended December 31, 2007 and 2006, and $99 million for the year ended December 31, 2005, and is included in operations and maintenance-nonaffiliate in the accompanying consolidated and combined statements of operations. As of December 31, 2007 and 2006, the Company has paid approximately $330 million and $314 million, respectively, of lease payments in excess of rent expense recognized, which is recorded in prepaid rent on the consolidated balance sheets.
As of December 31, 2007, the total notional minimum lease payments for the remaining terms of the leases aggregated approximately $2.1 billion and the aggregate termination value for the leases was approximately $1.4 billion and generally decreases over time. Mirant Mid-Atlantic leases the Morgantown and the Dickerson baseload units from third party owner lessors. These owner lessors each own the undivided interests in these baseload generating facilities. The subsidiaries of the institutional investors who hold the membership interests in the owner lessors are called owner participants. Equity funding by the owner participants plus transaction expenses paid by the owner participants totaled $299 million. The issuance and sale of pass through certificates raised the remaining $1.2 billion needed for the owner lessors to acquire the undivided interests.
The pass through certificates are not direct obligations of Mirant Mid-Atlantic. Each pass through certificate represents a fractional undivided interest in one of three pass through trusts formed pursuant to three separate pass through trust agreements between Mirant Mid-Atlantic and U.S. Bank National Association (as successor in interest to State Street Bank and Trust Company of Connecticut, National Association), as pass through trustee. The property of the pass through trusts consists of lessor notes. The lessor notes issued by an owner lessor are secured by that owner lessor’s undivided interest in the lease facilities and its rights under the related lease and other financing documents.
The Company has commitments under other operating leases with various terms and expiration dates. Minimum lease payments under non-cancelable operating leases approximate $5 million in 2008, $4 million in each of 2009 and 2010, $3 million in 2011, $2 million in 2012 and $17 million thereafter.
Fuel Commitments
Fuel commitments primarily relate to long-term coal agreements and other fuel purchase agreements. As of December 31, 2007, the Company’s total estimated fuel commitments were $506 million. In addition, the Company has transactions for which commercial terms have been negotiated but for which contracts have not yet been executed. Individual transactions may or may not be binding prior to execution of a contract.
Long-Term Service Agreements
As of December 31, 2007, the total estimated commitments under LTSAs associated with turbines were approximately $31 million. These commitments are payable over the terms of the respective agreements, which range from ten to twenty years. These agreements have terms that allow for cancellation of the contracts by the Company upon the occurrence of certain events during the term of the contracts. Estimates for future commitments for the LTSAs are based on the stated payment terms in the contracts at the time of execution. These payments are subject to an annual adjustment for inflation.
Other
Other represents the open purchase orders less invoices received related to open purchase orders for procurement of products and services purchased in the ordinary course of business. These include construction, maintenance and labor activities at the Company’s generating facilities.
Maryland Healthy Air Act
Maryland Healthy Air Act commitments are contracts and open purchase orders related to capital expenditures that the Company expects to incur to comply with the limitations for SO2 and NOx emissions under the Maryland Healthy Air Act.
Guarantees
Mirant generally conducts its business through various intermediate holding companies, including Mirant North America, and various operating subsidiaries which enter into contracts as a routine part of their business activities. In certain instances, the contractual obligations of such subsidiaries are guaranteed by, or otherwise supported by, Mirant or another of its subsidiaries, including expressed guarantees of Mirant North America or letters of credit issued under its credit facilities.
In addition, Mirant North America and its subsidiaries enter into various contracts that include indemnification and guarantee provisions. Examples of these contracts include financing and lease arrangements, purchase and sale agreements, commodity purchase and sale agreements, construction agreements, engagement agreements with vendors and other third parties. While the primary obligation of Mirant North America or a subsidiary under such contracts is to pay money or render performance, such contracts may include obligations to indemnify the counterparty for damages arising from the breach thereof and, in certain instances, other existing or potential liabilities. In many cases, the maximum potential liability of the obligor cannot be estimated, since some of the underlying agreements contain no limits on potential liability.
Upon issuance or modification of a guarantee, the Company determines if the obligation is subject to initial recognition and measurement of a liability and/or disclosure of the nature and terms of the guarantee. Generally, guarantees of the performance of a third party are subject to the recognition and measurement, as well as the disclosure provisions, of FIN 45. Such guarantees must initially be recorded at fair value, as determined in accordance with the interpretation. The Company did not have any guarantees that met the recognition requirements under FIN 45 at December 31, 2007.
Alternatively, guarantees between and on behalf of entities under common control are subject only to the disclosure provisions of the interpretation. The Company must disclose information as to the term of the guarantee and the maximum potential amount of future gross payments (undiscounted) under the guarantee, even if the likelihood of a claim is remote.
Letters of Credit
As of December 31, 2007, the Company and certain of its subsidiaries were contingently obligated for $290 million under letters of credit issued under its senior credit facilities, which includes $199 million letters of credit issued pursuant to its senior secured term loan and $91 million letters of credit issued pursuant to its revolving credit facility. Most of these letters of credit are issued in support of the obligations of Mirant North America and its subsidiaries to perform under commodity agreements, financing or lease agreements or other commercial arrangements. In the event of default by the contracting party, the counterparty can draw on a letter of credit to satisfy the existing amounts outstanding under an open contract. A majority of these letters of credit expire within one year of issuance, and it is typical for them to be renewed on similar terms.
Following is a summary of letters of credit issued as of December 31, 2007 and 2006 (in millions):
Commercial Purchase and Sales Arrangements
In connection with the purchase and sale of fuel, emission allowances and energy to and from third parties with respect to the operation of its subsidiaries’ generating facilities, Mirant North America may be required to guarantee a portion of the obligations of certain of its subsidiaries. These obligations may include liquidated damages payments or other unscheduled payments. The majority of the guarantees are set to expire before the end of 2010, although the obligations of the issuer will remain in effect until all the liabilities created under the guarantee have been satisfied or no longer exist. As of December 31, 2007, Mirant North America and its subsidiaries were contingently obligated for a total of $93 million under such arrangements. The Company does not expect that it will be required to make any material payments under these guarantees.
Other Guarantees and Indemnifications
As of December 31, 2007, the Company has issued $62 million of guarantees of obligations that its subsidiaries may incur as a provision for construction agreements, equipment leases, and on-going litigation. The Company does not expect that it will be required to make any material payments under these guarantees.
The Company, through its subsidiaries, participates in several power pools with RTOs. The rules of these RTOs require that each participant indemnify the pool for defaults by other members. Usually, the amount indemnified is based upon the activity of the participant relative to the total activity of the pool and the amount of the default. Consequently, the amount of such indemnification by the Company cannot be quantified.
On a routine basis in the ordinary course of business, Mirant North America and its subsidiaries indemnify financing parties and consultants or other vendors who provide services. The Company does not expect that it will be required to make any material payments under these indemnity provisions.
Because some of the guarantees and indemnities Mirant North America issues to third parties do not limit the amount or duration of its obligations to perform under them, there exists a risk that it may have obligations in excess of the amounts described above. For those guarantees and indemnities that do not limit its liability exposure, Mirant North America may not be able to estimate its potential liability until a claim is made for payment or performance, because of the contingent nature of these contracts.
10. Dispositions
Overview
The Company had no assets or liabilities held for sale at December 31, 2007. Assets and liabilities held for sale at December 31, 2006, included discontinued operations and other assets that the Company disposed of in 2007. In the third quarter of 2006, Mirant commenced auction processes to sell six of its U.S. natural gas-fired facilities, including the Zeeland (903 MW) and Bosque (546 MW) facilities.
The sale of the Zeeland and Bosque natural gas-fired facilities was completed on May 1, 2007. In the third quarter of 2006, the Company recorded an impairment loss of $71 million to reduce the carrying value of the facilities held for sale to estimated fair value. In subsequent periods, the Company recorded reductions to the impairment loss of approximately $63 million resulting from the sale process. As a result, the Company recognized a cumulative loss of $8 million related to the sale. The net proceeds to the Company after transaction costs were $524 million.
The Company completed the sale of Mirant NY-Gen on May 7, 2007, and recognized a gain of $8 million related to the sale. The proceeds related to the sale were immaterial as a result of the transfer of the net liabilities of Mirant New York-Gen.
At December 31, 2006, assets and liabilities held for sale consisted of the facilities discussed above and certain ancillary equipment included in the sale of the Zeeland and Bosque natural gas-fired facilities.
The table below presents the components of the balance sheet accounts classified as assets and liabilities held for sale for the year ended December 31, 2006 (in millions):
Discontinued Operations
The Company has reclassified amounts for prior periods in the financial statements to report separately, as discontinued operations, the revenues and expenses of components of the Company that have been disposed of as of December 31, 2007.
For the years ended December 31, 2007, 2006 and 2005, income from discontinued operations included the results of operations of the Zeeland and Bosque natural gas-fired facilities and Mirant NY-Gen through their respective dates of sale.
A summary of the operating results for these discontinued operations for the years ended December 31, 2007, 2006 and 2005, is as follows (in millions):
As part of the sale of Mirant NY-Gen, Mirant retained the rights to future insurance recoveries related to repairs of the dam at the Swinging Bridge facility. In the fourth quarter of 2007, the Company reached an insurance settlement and recognized a gain of $10 million, which is included in income from discontinued operations.
11. Bankruptcy Related Disclosures
Mirant’s Plan was confirmed by the Bankruptcy Court on December 9, 2005, and Mirant and the Company emerged from bankruptcy on January 3, 2006. For financial statement presentation purposes, Mirant and the Company recorded the effects of the Plan at December 31, 2005.
Pursuant to the Plan, Mirant North America paid $1.773 billion to settle obligations of Mirant Americas Generation in the year ended December 31, 2006.
Mirant New York Subsidiaries
The Company’s New York subsidiaries, Mirant New York, Mirant Bowline, Mirant Lovett, Hudson Valley Gas and Mirant NY-Gen, remained in bankruptcy at December 31, 2006. On January 26, 2007, Mirant New York, Mirant Bowline (which owns the Bowline facility) and Hudson Valley Gas (collectively the “Emerging New York Entities”) filed their Supplemental Joint Chapter 11 Plan of Reorganization with the Bankruptcy Court and subsequently filed amendments to that plan (as subsequently amended, the “Supplemental Plan”). The Supplemental Plan was confirmed by the Bankruptcy Court on March 23, 2007, and became effective on April 16, 2007, resulting in the Emerging New York Entities’ emergence from bankruptcy. For financial statement presentation purposes, the effects of the Supplemental Plan were recorded on March 31, 2007.
On January 31, 2007, Mirant New York entered into an agreement for the sale of Mirant NY-Gen, which owned the Hillburn and Shoemaker gas turbine facilities and the Swinging Bridge, Rio and Mongaup hydroelectric generating facilities. The sale closed on May 7, 2007, and the Company recognized a gain of $8 million. Mirant NY-Gen emerged from bankruptcy under a plan of reorganization that incorporated the sale and was approved by the Bankruptcy Court on April 27, 2007.
On July 13, 2007, Mirant Lovett (which owns the Lovett facility) filed a plan of reorganization (the “Mirant Lovett Plan”) with the Bankruptcy Court. The Mirant Lovett Plan was confirmed by the Bankruptcy Court on September 19, 2007, and became effective on October 2, 2007, resulting in Mirant Lovett’s emergence from bankruptcy. For financial statement presentation purposes, the effects of the Mirant Lovett Plan were recorded on September 30, 2007. As a result of Mirant Lovett’s emergence, Mirant has no subsidiaries that remain in bankruptcy. See Note 14 for further discussion regarding Mirant Lovett’s emergence from bankruptcy.
Reorganization Items, net
Reorganization items, net represents expense, income and gain or loss amounts that were recorded in the financial statements as a result of the bankruptcy proceedings. In 2006, reorganization items, net relate to refunds received from various New York tax jurisdictions for the settlement of the property tax dispute related to the New York subsidiaries.
Reorganization items, net for the years ended December 31, 2007, 2006 and 2005, are comprised of the following (in millions):
(1) Estimated claims and losses on rejected and amended contracts relate primarily to rejected energy contracts, such as tolling agreements and gas transportation and electric transmission contracts.
12. Other Comprehensive Income (Loss)
Other comprehensive income (loss) includes unrealized gains and losses on certain derivatives that qualified as cash flow hedges and unrealized gains on available-for-sale securities. Changes in accumulated other comprehensive income (loss) net of tax are as follows (in millions):
The $27 million in accumulated other comprehensive income at December 31, 2005, is associated with unrealized gains on available for sale securities. In 2006, the unrealized gains were reclassified to earnings when the securities were sold.
13. Segment Reporting
The Company has four operating segments: Mid-Atlantic, Northeast, California and Other Operations. The Mid-Atlantic segment consists of four generating facilities located in Maryland and Virginia with total net generating capacity of 5,244 MW. The Northeast segment consists of generating facilities located in Massachusetts and New York with total net generating capacity of 2,689 MW. The Company’s California segment consists of three generating facilities located in or near the City of San Francisco, which have total net generating capacity of 2,347 MW. Other Operations includes proprietary trading, fuel oil management and, for periods prior to 2006, includes gains and losses related to a long-term PPA with Pepco (the “Back-to-Back Agreement”) and the transition power agreement with Pepco that expired in January 2005. See Note 15 for further discussion of the Back-to-Back Agreement. Other Operations also includes interest on our debt and interest income on our invested cash balances. In the following tables, eliminations are primarily related to intercompany sales of emissions allowances and interest on intercompany notes receivable and notes payable.
Operating Segments
Operating Segments
Operating Segments
14. Litigation and Other Contingencies
The Company is involved in a number of significant legal proceedings. In certain cases, plaintiffs seek to recover large and sometimes unspecified damages, and some matters may be unresolved for several years. The Company cannot currently determine the outcome of the proceedings described below or the ultimate amount of potential losses and therefore has not made any provision for such matters unless specifically noted below. Pursuant to SFAS 5, management provides for estimated losses to the extent information becomes available indicating that losses are probable and that the amounts are reasonably estimable. Additional losses could have a material adverse effect on the Company’s consolidated and combined financial position, results of operations or cash flows.
Environmental Matters
EPA Information Request. In January 2001, the EPA issued a request for information to Mirant concerning the implications under the EPA’s NSR regulations promulgated under the Clean Air Act of past repair and maintenance activities at the Potomac River facility in Virginia and the Chalk Point, Dickerson and Morgantown facilities in Maryland. The requested information concerned the period of operations that predates the Company subsidiaries’ ownership and lease of those facilities. Mirant responded fully to this request. Under the APSA, Pepco is responsible for fines and penalties arising from any violation associated with operations prior to the acquisition or lease of the facilities by subsidiaries of the Company. If a violation is determined to have occurred at any of the facilities, the Company subsidiary owning or leasing the facility may be responsible for the cost of purchasing and installing emissions control equipment, the cost of which may be material. The Company’s subsidiaries owning or leasing the Chalk Point, Dickerson and Morgantown facilities in Maryland are installing a variety of emissions control equipment on those facilities to comply with the Maryland Healthy Air Act, but that equipment may not include all of the emissions control equipment that could be required if a violation of the EPA’s NSR regulations is determined to have occurred at one or more of those facilities. If such a violation is determined to have occurred after the Company’s subsidiaries acquired or leased the facilities or, if occurring prior to the acquisition or lease, is determined to constitute a continuing violation, the Company’s 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 periods prior to January 3, 2006, when the Plan became effective for the Company and its subsidiaries that own or lease these facilities.
Morgantown Particulate Emissions NOV. On March 3, 2006, Mirant Mid-Atlantic received a notice sent on behalf of the MDE alleging that violations of particulate matter emissions limits applicable to unit 1 at the Morgantown facility occurred on nineteen days in June and July 2005. The notice advises that the potential civil penalty is up to $25,000 per day for each day that unit 1 exceeded the applicable particulate matter limit. The letter further advises that the MDE has asked the Maryland Attorney General to file a civil suit under Maryland law based upon the alleged violations.
Morgantown SO2 Exceedances. Mirant Mid-Atlantic received an NOV dated March 8, 2006, asserting that on three days in June 2005 and January 2006, the Morgantown facility exceeded SO2 emissions limitations specified in its air permit. The NOV indicates that on two of those days the SO2 emissions limitation was exceeded by two different units of the Morgantown facility each day. The NOV did not seek a specific penalty amount but noted that the violations identified could subject Mirant Mid-Atlantic to a civil penalty of up to $25,000 per day.
Morgantown Emissions Observation NOV. On June 30, 2006, the MDE issued an NOV to Mirant Mid-Atlantic indicating that it had failed to comply with the air permit for the Morgantown facility by operating the combustion turbines at the facility for more than 168 hours without performing an EPA Reference Method 9 observation of stack emissions for an 18-minute period. The NOV did not seek a specific penalty amount but noted that the violation identified could subject Mirant Mid-Atlantic to a civil penalty of up to $25,000 per day.
Mirant Potomac River NAAQS Exceedance. On March 23, 2007, the Virginia DEQ issued an NOV to Mirant Potomac River alleging that it violated Virginia’s Air Pollution Control Law and regulations on February 23, 2007, by operating the Potomac River facility in a manner that resulted in a monitored exceedance in a twenty-four hour period of the NAAQS for SO2. As noted in the NOV, Mirant Potomac River was operating on February 23, 2007, as directed by PJM in accordance with a DOE order during a scheduled outage of the Pepco transmission lines serving Washington, D.C. The NOV asserts that plant operators did not implement appropriate actions to minimize SO2 emissions. The NOV did not seek a specific penalty amount but noted that the violations identified could subject Mirant Potomac River to civil penalties of varying amounts under different provisions of the Virginia Code, including a potential civil fine of up to $100,000.
New York State Administrative Claim. On January 24, 2006, the State of New York and the NYSDEC filed a notice of administrative claims in the Mirant Debtors’ Chapter 11 proceedings asserting a claim seeking to require the Mirant Debtors to provide funding to the Company’s subsidiaries owning generating facilities in New York to satisfy certain specified environmental compliance obligations. The State of New York cited various existing outstanding matters between the State and the Company’s subsidiaries owning generating facilities in New York related to compliance with environmental laws and regulations. The State of New York and the NYSDEC executed a stipulated order with the Company’s New York subsidiaries and the other Mirant Debtors to stay resolution of this administrative claim. That stipulated order was approved by the Bankruptcy Court on February 23, 2006. Although this administrative claim remains stayed, the bulk of the existing outstanding matters upon which the claim was based have been separately resolved with the NYSDEC.
Riverkeeper Suit Against Mirant Lovett. On March 11, 2005, Riverkeeper, Inc. filed suit against Mirant Lovett in the United States District Court for the Southern District of New York under the Clean Water Act. The suit alleges that Mirant Lovett failed to implement a marine life exclusion system at its Lovett generating facility and to perform monitoring for the exclusion of certain aquatic organisms from the facility’s cooling water intake structures in violation of Mirant Lovett’s water discharge permit issued by the State of New York. The plaintiff requested the court to enjoin Mirant Lovett from continuing to operate the Lovett generating facility in a manner that allegedly violates the Clean Water Act, to impose civil penalties of $32,500 per day of violation, and to award the plaintiff attorneys’ fees. Mirant Lovett’s view is that it has complied with the terms of its water discharge permit, as amended by a Consent Order entered June 29, 2004. On April 20, 2005, the district court approved a stipulation agreed to by the plaintiff and Mirant Lovett that stayed the suit until 60 days after the entry of the order by the Bankruptcy Court confirming the plan of reorganization for Mirant Lovett became final and non-appealable, which stay expired in late 2007.
Lovett/Bowline SPDES Notices of Violation. On March 8, 2007, Mirant Lovett and Mirant Bowline received NOVs from the NYSDEC alleging certain violations of their State Pollutant Discharge Elimination System, (‘SPDES”) permits. On April 6, 2007, the NYSDEC filed a complaint against Mirant Lovett and Mirant Bowline based on these allegations. The complaint seeks a penalty of $500,000. On December 31, 2007, Mirant Bowline entered into a Consent Order with the NYSDEC that resolved the NOV issued to it. In the Consent Order, Mirant Bowline agreed to pay a fine of $50,000 and to fund an environmental benefit project in the amount of $250,000. Mirant Lovett is in discussions with the NYSDEC to resolve the NOV issued to it and has not yet responded to the complaint filed by the NYSDEC.
Notices of Intent to Sue for Alleged Violations of the Endangered Species Act. Mirant and Mirant Delta have received two letters, one dated September 27, 2007, sent on behalf of the Coalition for a Sustainable Delta, four water districts, and an individual, and the second dated October 16, 2007, sent on behalf of San Francisco Baykeeper (collectively with the parties sending the September 27, 2007, letter, the “Noticing Parties”), providing notice that the Noticing Parties intend to file suit alleging that Mirant Delta has violated, and continues to violate, the federal Endangered Species Act through the operation of its Contra Costa and Pittsburg generating facilities. The 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 Noticing Parties assert that Mirant 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 not been complied with by Mirant 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, in late October 2007, Mirant Delta received correspondence from the U.S. Fish and Wildlife Service, the National Marine Fisheries Service and the Army Corps of Engineers clarifying that Mirant Delta continued to be authorized to take the four species of fish protected under the federal Endangered Species Act. 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 Mirant Delta’s facilities. Mirant Delta disputes the allegations made by the
Noticing Parties. No lawsuits have been filed to date, and San Francisco Baykeeper on February 1, 2008, withdrew its notice of intent to sue.
Chapter 11 Proceedings
On July 14, 2003, and various dates thereafter, Mirant Corporation and certain of its subsidiaries (collectively, the “Mirant Debtors”), including the Company and its subsidiaries, filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. Mirant, the Company and most of the Mirant Debtors emerged from bankruptcy on January 3, 2006, when the Plan became effective. The remaining Mirant Debtors, Mirant New York, Mirant Bowline, Mirant Lovett, Mirant NY-Gen and Hudson Valley Gas, emerged from bankruptcy on various dates in 2007. As of December 31, 2007, approximately one million of the shares of Mirant common stock to be distributed under the Plan had not yet been distributed and have been reserved for distribution with respect to claims disputed by the Mirant Debtors that have not been resolved. Under the terms of the Plan, to the extent unresolved claims are resolved now that the Company has emerged from bankruptcy, the claimants will receive the same pro rata distributions of Mirant common stock, cash, or both common stock and cash as previously allowed claims.
To the extent the aggregate amount of the payouts determined to be due with respect to disputed claims ultimately exceeds the amount of the funded claim reserve, Mirant would have to issue additional shares of common stock to address the shortfall, which would dilute existing Mirant stockholders, and Mirant and Mirant Americas Generation would have to pay additional cash amounts as necessary under the terms of the Plan to satisfy such pre-petition claims.
California and Western Power Markets
FERC Refund Proceedings Arising Out of California Energy Crisis. High prices experienced in California and western wholesale electricity markets in 2000 and 2001 caused various purchasers of electricity in those markets to initiate proceedings seeking refunds. Several of those proceedings remain pending either before the FERC or on appeal to the United States Court of Appeals for the Ninth Circuit (the “Ninth Circuit”). The proceedings that remain pending include proceedings (1) ordered by FERC on July 25, 2001, (the “FERC Refund Proceedings”) to determine the amount of any refunds and amounts owed for sales made by market participants, including Mirant Americas Energy Marketing, in the CAISO or the Cal PX markets from October 2, 2000, through June 20, 2001 (the “Refund Period”), (2) ordered by FERC to determine whether there had been unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest from December 25, 2000, through June 20, 2001 (the “Pacific Northwest Proceeding”), and (3) arising from a complaint filed in 2002 by the California Attorney General that sought refunds for transactions conducted in markets administered by the CAISO and the Cal PX outside the Refund Period set by the FERC and for transactions between the DWR and various owners of generation and power marketers, including Mirant Americas Energy Marketing and subsidiaries of the Company. Various parties appealed FERC orders related to these proceedings to the Ninth Circuit seeking review of a number of issues, including changing the Refund Period to include periods prior to October 2, 2000, and expanding the sales of electricity subject to potential refund to include bilateral sales made to the DWR and other parties. While various of these appeals remain pending, the Ninth Circuit has ruled that the FERC should consider further whether to grant relief for sales of electricity made in the CAISO and Cal PX markets prior to October 2, 2000, at rates found to be unjust, and, in the proceeding initiated by the California Attorney General, what remedies, including potential refunds, are appropriate where entities, including Mirant Americas Energy Marketing, purportedly did not comply with certain filing requirements for transactions conducted under market based rate tariffs.
On January 14, 2005, Mirant and certain of its subsidiaries, including the Company (the “Mirant Settling Parties”), entered into a Settlement and Release of Claims Agreement (the “California Settlement”) with PG&E, Southern California Edison Company, San Diego Gas and Electric Company, the CPUC, the DWR, the EOB and the Attorney General of the State of California (collectively, the “California Parties”). The California Settlement
was approved by the FERC on April 13, 2005, and became effective on April 15, 2005, upon its approval by the Bankruptcy Court. The California Settlement resulted in the release of most of Mirant Americas Energy Marketing’s potential liability (1) in the FERC Refund Proceedings for sales made in the CAISO or the Cal PX markets, (2) in the Pacific Northwest Proceeding, and (3) in any proceedings at the FERC resulting from the complaint filed in 2002 by the California Attorney General. Under the California Settlement, the California Parties and those other market participants who have opted into the settlement have released the Mirant Settling Parties, including Mirant Americas Energy Marketing, from any liability for refunds related to sales of electricity and natural gas in the western markets from January 1, 1998, through July 14, 2003. Also, the California Parties have assumed the obligation of Mirant Americas Energy Marketing to pay any refunds determined by the FERC to be owed by Mirant Americas Energy Marketing to other parties that do not opt into the settlement for transactions in the CAISO and Cal PX markets during the Refund Period, with the liability of the California Parties for such refund obligation limited to the amount of certain receivables assigned by Mirant Americas Energy Marketing to the California Parties under the California Settlement. The settlement did not relieve Mirant Americas Energy Marketing of liability for any refunds that the FERC determines it to owe (1) to participants in the Cal PX and CAISO markets that are not California Parties (or that did not elect to opt into the settlement) for periods outside the Refund Period and (2) to participants in bilateral transactions with Mirant Americas Energy Marketing that are not California Parties (or that did not elect to opt into the settlement).
Resolution of the refund proceedings that remain pending before the FERC or that currently are on appeal to the Ninth Circuit could ultimately result in the FERC concluding that the prices received by Mirant Americas Energy Marketing in some transactions occurring in 2000 and 2001 should be reduced. The Company’s view is that the bulk of any obligations of Mirant Americas Energy Marketing to make refunds as a result of sales completed prior to July 14, 2003, in the CAISO or Cal PX markets or in bilateral transactions either have been addressed by the California Settlement or have been resolved as part of Mirant Americas Energy Marketing’s bankruptcy proceedings. To the extent that Mirant Americas Energy Marketing’s potential refund liability arises from contracts that were transferred to Mirant Energy Trading as part of the transfer of the trading and marketing business under the Plan, Mirant Energy Trading may have exposure to any refund liability related to transactions under those contracts.
FERC Show Cause Proceeding Relating to Trading Practices. On June 25, 2003, the FERC issued a show cause order (the “Trading Practices Order”) to more than 50 parties, including Mirant Americas Energy Marketing and subsidiaries of the Company. The Trading Practices Order identified certain specific trading practices that the FERC indicated could constitute gaming or anomalous market behavior in violation of the CAISO and Cal PX tariffs, and required sellers previously involved in transactions of those types to demonstrate why such transactions were not violations of the CAISO and Cal PX tariffs. On September 30, 2003, and December 19, 2003, the Mirant entities filed with the FERC for approval of a settlement agreement (the “Trading Settlement Agreement”) entered into between certain Mirant entities and the FERC Trial Staff and an amendment to that agreement, under which Mirant Americas Energy Marketing would pay $332,411 and the FERC would have an allowed unsecured claim in Mirant Americas Energy Marketing’s bankruptcy proceeding for $3.67 million to settle the show cause proceeding. The FERC approved the Trading Settlement Agreement, as amended, on June 27, 2005, and the Bankruptcy Court approved it on August 24, 2005. Certain parties filed motions for rehearing with the FERC, which it denied on October 11, 2006. A party to the proceeding has appealed the FERC’s June 27, 2005, order to the Ninth Circuit.
Mirant Americas Energy Marketing Contract Dispute with Nevada Power. On December 5, 2001, Nevada Power Co. filed a complaint at the FERC seeking reformation of the purchase price of energy under a contract it had entered with Mirant Americas Energy Marketing, claiming that the prices under that contract were unjust and unreasonable because, when it entered into the contract, western power markets were dysfunctional and non-competitive markets. On June 25, 2003, the FERC dismissed this complaint. Nevada Power appealed that dismissal to the United States Court of Appeals for the Ninth Circuit, which on December 19, 2006, reversed the dismissal of the complaint and remanded the proceeding to the FERC. On September 25, 2007, the United States Supreme Court granted a petition for writ of certiorari asking that it review that decision by the Ninth Circuit.
The sales made under the contract with Nevada Power have been completed, and the Company expects that any refund claim related to that contract, if not now barred, will be addressed in the Chapter 11 proceedings.
Mirant Americas Energy Marketing Contract Dispute with Southern California Water. On December 21, 2001, Southern California Water Company filed a complaint at the FERC seeking reformation of the purchase price of energy under a long-term contract it had entered with Mirant Americas Energy Marketing, claiming that the prices under that contract were unjust and unreasonable because, when it entered the contract, western power markets were dysfunctional and non-competitive markets. The contract was for the purchase of 15 MWs during the period April 1, 2001, through December 31, 2006. On June 25, 2003, the FERC dismissed this proceeding. Southern California Water appealed that dismissal to the United States Court of Appeals for the Ninth Circuit, which on December 19, 2006, reversed the dismissal of the complaint and remanded the proceeding to the FERC. On September 25, 2007, the United States Supreme Court granted a petition for writ of certiorari asking that it review that decision by the Ninth Circuit. Upon the transfer of the assets of the trading and marketing business to Mirant Energy Trading under the Plan, Mirant Energy Trading assumed Mirant Americas Energy Marketing’s contract obligations to Southern California Water Company, including any potential refund obligations.
Maryland Public Service Commission Complaint to the FERC re PJM Offer Capping Rules
In certain market conditions, such as where congestion requires the dispatch of a generating facility that bid a higher price for electricity than other available generating facilities, PJM’s market rules (the “Offer Capping Rules”) limit the amount that the owner of a generating facility may bid to sell electricity from that facility to its incremental cost of service to produce that electricity. As approved by the FERC, the Offer Capping Rules contain exemptions for generating facilities entering service during certain years (none of which are owned by the Company) and for generating facilities (some of which are owned by the Company) that can relieve congestion arising at certain defined transmission interfaces. On January 15, 2008, the Maryland Public Service Commission (the “MD PSC”) filed a complaint with the FERC requesting that the FERC remove all exemptions to the Offer Capping Rules during hours when the PJM market reflects potentially non-competitive conditions, as determined by the PJM Market Monitor. The complaint alleges that these exemptions to the Offer Capping Rules likely result in higher market clearing prices for electricity in PJM, and higher revenues to the Company and the other owners of generation that are selling electricity, during the periods when the exemptions prevent the application of the Offer Capping Rules to one or more generating facilities. The MD PSC requested that the FERC require a rerunning of the dispatch of the PJM energy markets without application of the exemptions to the Offer Capping Rules for each day from January 15, 2008, through the date that the Commission grants the requested relief and that it require owners of generation to refund any revenues received in excess of the amounts that would have been received had the exemptions not been applied.
In addition, the MD PSC alleged that PJM violated its tariff by not publicly disclosing since mid 2006 quarterly analyses performed by the PJM Market Monitor of the potential for the exercise of market power by owners of generation during periods when market conditions caused the exemptions to the Offer Capping Rules to apply. The MD PSC requested the FERC to initiate an investigation of whether owners of generation exercised market power during such periods, and, if so, to order refunds beginning as of September 8, 2006, or the first date that the FERC determines that PJM violated its tariff.
The Company disputes the allegations made by the MD PSC in its complaint and intends to oppose the complaint and the relief requested. If the FERC were to remove the exemptions to the Offer Capping Rules, and apply the removal retroactively from January 15, 2008, or an earlier date, PJM would have to rerun its day-ahead market from that date forward to determine what prices would have resulted in the absence of the exemptions. Such a rerun of the PJM day-ahead market likely would result in refunds being owed by all sellers, including the Company, but the potential amount cannot be quantified.
Other Legal Matters
The Company is involved in various other claims and legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Company’s financial position, results of operations or cash flows.
15. Settlements and Other Charges
Pepco Litigation
In 2000, Mirant purchased power generating facilities and other assets from Pepco, including certain PPAs between Pepco and third parties. Under the terms of the APSA, Mirant and Pepco entered into the Back-to-Back Agreement with respect to certain PPAs, including Pepco’s long-term PPA with Panda-Brandywine, LP, under which (1) Pepco agreed to resell to Mirant all capacity, energy, ancillary services and other benefits to which it is entitled under those agreements and (2) Mirant agreed to pay Pepco each month all amounts due from Pepco to the sellers under those agreements for the immediately preceding month associated with such capacity, energy, ancillary services and other benefits. The Back-to-Back Agreement, which did not expire until 2021, obligated Mirant to purchase power from Pepco at prices that typically were higher than the market prices for power.
Mirant assigned its rights and obligations under the Back-to-Back Agreement to Mirant Americas Energy Marketing. In the Chapter 11 cases of the Mirant Debtors, Pepco asserted that an Assignment and Assumption Agreement dated December 19, 2000, that included as parties Pepco and various of the Company’s subsidiaries, caused the Company’s subsidiaries that were parties to the agreement to be jointly and severally liable to Pepco for various obligations, including the obligations under the Back-to-Back Agreement. The Mirant Debtors sought to reject the APSA, the Back-to-Back Agreement, and the Assignment and Assumption Agreement. Under the Plan, the obligations of the Mirant Debtors under the APSA (including any other agreements executed pursuant to the terms of the APSA and found by a final court order to be part of the APSA), the Back-to-Back Agreement, and the Assignment and Assumption Agreement were performed after January 3, 2006, by Mirant Power Purchase, whose performance was guaranteed by Mirant, pending resolution of the rejection motions.
On May 30, 2006, Mirant and various of its subsidiaries, including subsidiaries of the Company (collectively the “Mirant Settling Parties”), entered into the Settlement Agreement with the Pepco Settling Parties. The Settlement Agreement could not become effective until it had been approved by the Bankruptcy Court and that approval order had become a final order no longer subject to appeal. The Bankruptcy Court entered an order approving the Settlement Agreement on August 9, 2006. That order was appealed, but the appeal was dismissed by agreement of the parties in August 2007, and the Settlement Agreement became effective August 10, 2007. The Settlement Agreement fully resolved the contract rejection motions that remained pending in the bankruptcy proceedings, as well as other matters disputed between Pepco and Mirant and its subsidiaries. The Back-to-Back Agreement was rejected and terminated effective as of May 31, 2006, and the Assignment and Assumption Agreement was also rejected.
Under the Settlement Agreement, Mirant Power Purchase assumed the remaining obligations under the APSA, and Mirant has guaranteed its performance. With respect to the other agreements executed as part of the closing of the APSA (the “Ancillary Agreements”) and other agreements between Pepco and subsidiaries of Mirant, including subsidiaries of the Company, the Mirant subsidiary that is a party to each agreement has assumed the agreement and Mirant has guaranteed that subsidiary’s performance. Mirant Power Purchase’s obligations under the APSA do not include any obligations related to the Ancillary Agreements. The Settlement Agreement provides that a future breach of the APSA or any Ancillary Agreement by a party to such agreement will not entitle the non-defaulting party to terminate, suspend performance under, or exercise any other right or remedy under or with respect to any of the remainder of such agreements.
The Settlement Agreement granted Pepco a claim against Old Mirant in Old Mirant’s bankruptcy proceedings that was to result in Pepco receiving common stock of Mirant and cash having a value, after liquidation of the stock by Pepco, equal to $520 million. Shortly after the Settlement Agreement became
effective, Mirant distributed approximately 14 million shares of Mirant common stock from the shares reserved for disputed claims under the Plan to Pepco to satisfy its claim. The Mirant shares in the share reserve, including the shares distributed to Pepco, have been treated as issued and outstanding since Mirant emerged from bankruptcy. Pepco’s liquidation of those shares resulted in net proceeds of approximately $522 million and Pepco paid Mirant the amount in excess of $520 million.
New York Tax Proceedings
Mirant New York, Mirant Bowline, Mirant Lovett, and Hudson Valley Gas (collectively with Mirant New York, Mirant Bowline and Mirant Lovett, the “New York Companies”) were the petitioners in various proceedings (the “Tax Certiorari Proceedings”) initially brought in the New York state courts challenging the assessed values determined by local taxing authorities for the Bowline and Lovett generating facilities and a natural gas pipeline (the “HVG Property”) owned by Hudson Valley Gas. Mirant Bowline had challenged the assessed value of the Bowline generating facility and the resulting local tax assessments for tax years 1995 through 2006. Mirant Bowline succeeded to rights held by Orange and Rockland for the tax years prior to its acquisition of the Bowline facility in 1999 under its agreement with Orange and Rockland for the purchase of that facility. Mirant Lovett had challenged the assessed value of the Lovett facility for each of the years 2000 through 2006. Hudson Valley Gas had challenged the assessed value of the HVG Property for each of the years 2004 through 2006. As of December 31, 2006, Mirant Bowline and Mirant Lovett had not paid property taxes on the Bowline and Lovett generating facilities that fell due in the period from September 30, 2003, through December 31, 2006, in order to preserve their respective rights to offset the overpayments of taxes made in earlier years against the sums payable on account of current taxes. Hudson Valley Gas had not paid property taxes that fell due in the period from September 30, 2004, through December 31, 2006.
On December 13, 2006, Mirant and the New York Companies entered into a settlement agreement (the “Tax Settlement Agreement”) with the Town of Haverstraw (“Haverstraw”), the Town of Stony Point (“Stony Point”), the Haverstraw-Stony Point Central School District (the “School District”), the County of Rockland (the “County”), the Village of Haverstraw (“Haverstraw Village”), and the Village of West Haverstraw (“West Haverstraw Village” and collectively with Haverstraw, Stony Point, the School District, the County, and Haverstraw Village, the “Tax Jurisdictions”). The Tax Settlement Agreement was approved by the Bankruptcy Court on December 14, 2006, and resolved all pending disputes regarding real property taxes between the New York Companies and the Tax Jurisdictions. Under the agreement, the New York Companies received total refunds of $163 million from the Tax Jurisdictions and paid unpaid but accrued taxes to the Tax Jurisdictions of $115 million, resulting in the New York Companies receiving a net cash payment in the amount of $48 million. The refunds and unpaid taxes were paid in February 2007. The $163 million of total refunds received by the New York Companies was recognized as a gain in the financial statements in the fourth quarter of 2006. In addition, the New York Companies had previously accrued a liability based upon the unpaid taxes as billed by the Tax Jurisdictions. Due to the reductions of the unpaid taxes that occurred pursuant to the terms of the Tax Settlement Agreement, the New York Companies also recognized in the fourth quarter of 2006 a reduction of operating expenses of approximately $23 million related to 2006 and a gain of approximately $71 million related to prior periods.
California Settlement
The California Settlement described in Note 14 in California and Western Power Markets-FERC Refund Proceedings Arising Out of California Energy Crisis included a provision that either (1) the partially constructed Contra Costa 8 project, which was a planned 530 MW combined cycle generating facility, and related equipment (collectively, the “CC8 Assets”) were to be transferred to PG&E or (2) PG&E would receive additional alternative consideration of $70 million (the “CC8 Alternative Consideration”). To fund the CC8 Alternative Consideration, PG&E received an allowed, unsecured claim in the bankruptcy proceedings against Mirant Delta that resulted in a distribution to PG&E of cash and Mirant common stock with an aggregate value of approximately $70 million. PG&E was required to liquidate the common stock received as part of that distribution and place the net resulting amount plus any cash received into an escrow account.
The California Settlement provided that if the transfer of the CC8 Assets to PG&E did not occur on or before June 30, 2008, then the CC8 Alternative Consideration was to be paid to PG&E and the Mirant Settling Parties would retain the CC8 Assets. If PG&E closed on its acquisition of the CC8 Assets, the funds in the escrow account were to be paid to Mirant Delta. The transfer of the CC8 Assets to PG&E was completed on November 28, 2006, and the $70 million escrow account was paid to Mirant Delta. The Company recognized in the fourth quarter of 2006 a gain of $27 million for the amount by which the escrow account exceeded the carrying amount of the CC8 Assets. The gain was included in other income in the Company’s consolidated and combined statements of operations.
16. Consolidating and Combining Financial Information
In December 2005, the Company’s wholly-owned subsidiary Mirant North America Escrow and its wholly-owned subsidiary MNA Finance Corp. issued $850 million of 7.375% senior notes, which mature on December 31, 2013. Upon Mirant’s and the Company’s emergence from bankruptcy, Mirant North America Escrow was merged with and into Mirant North America with Mirant North America as the surviving entity. See Note 6 for further discussion of the notes.
The notes are unsecured obligations of Mirant North America. However, they are jointly and severally and fully and unconditionally guaranteed on an unsecured senior basis by Mirant North America and certain of its subsidiaries (all of which are wholly-owned). The accompanying consolidating and combining financial information has been prepared and presented pursuant to SEC Regulation S-X Rule 3-10, “Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or being Registered.” This information is not intended to present the financial position, results of operations and cash flows of the individual companies or groups of companies in accordance with GAAP.
The following sets forth condensed consolidating and combining financial statements of the guarantor and non-guarantor subsidiaries:
MIRANT NORTH AMERICA
GUARANTOR/NON-GUARANTOR
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
Year Ended December 31, 2007
(in millions)
MIRANT NORTH AMERICA
GUARANTOR/NON-GUARANTOR
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
Year Ended December 31, 2006
(in millions)
MIRANT NORTH AMERICA
GUARANTOR/NON-GUARANTOR
CONDENSED COMBINING STATEMENTS OF OPERATIONS
Year Ended December 31, 2005
(in millions)
MIRANT NORTH AMERICA
GUARANTOR/NON-GUARANTOR
CONDENSED CONSOLIDATING BALANCE SHEETS
At December 31, 2007
(in millions)
MIRANT NORTH AMERICA
GUARANTOR/NON-GUARANTOR
CONDENSED CONSOLIDATING BALANCE SHEETS
At December 31, 2006
(in millions)
MIRANT NORTH AMERICA
GUARANTOR/NON-GUARANTOR
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
Year Ended December 31, 2007
(in millions)
MIRANT NORTH AMERICA
GUARANTOR/NON-GUARANTOR
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
Year Ended December 31, 2006
(in millions)
MIRANT NORTH AMERICA
GUARANTOR/NON-GUARANTOR
CONDENSED COMBINING STATEMENTS OF CASH FLOWS
Year Ended December 31, 2005
(in millions)
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A.
Item 9A. Controls and Procedures
Inherent Limitations in Control Systems
A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within the Company have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Over time, controls may become inadequate because of changes in conditions, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements resulting from error or fraud may occur and not be detected. As a result, our management, including the Chief Executive Officer and Chief Financial Officer, does not expect that our disclosure controls and procedures, or our internal control over financial reporting, will prevent all error and all fraud.
Effectiveness of Disclosure Controls and Procedures
As required by Exchange Act Rule 13a-15(b), our management, including our Chief Executive Officer and our Chief Financial Officer, conducted an assessment of the effectiveness of the design and operation of our disclosure controls and procedures (as defined by Rules 13a-15(e) and 15d-15(e) under the Exchange Act), as of December 31, 2007. Based upon this assessment, our management concluded that, as of December 31, 2007, the design and operation of these disclosure controls and procedures were effective.
Appearing as exhibits to this annual report are the certifications of the Chief Executive Officer and the Chief Financial Officer required in accordance with Section 302 of the Sarbanes-Oxley Act of 2002.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined by Rules 13a-15(f) under the Exchange Act). The Company’s internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles. Internal control over financial reporting includes those processes and procedures that:
•
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company;
•
provide reasonable assurance that transactions are recorded properly to allow for the preparation of financial statements, in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company;
•
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the consolidated and combined financial statements; and
•
provide reasonable assurance as to the detection of fraud.
Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we carried out an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2007. In conducting our assessment, management utilized the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control-Integrated Framework. Based on this assessment, management concluded that our internal control over financial reporting was effective as of December 31, 2007.
Changes in Internal Controls
During the quarter ended December 31, 2007, there were no significant changes in Mirant North America’s internal control over financial reporting or in other factors that could materially affect or is reasonably likely to affect such internal controls over financial reporting.
Item 9B.
Item 9B. Other Information
None.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant
The table below sets forth information on each member of the Board of Managers of the Company as of December 31, 2007. Each member of the Board of Managers is also an executive officer of Mirant Corporation.
The table below sets forth information on the principal executive officer, principal financial officer and principal accounting officer of Mirant North America as of December 31, 2007. These officers are also officers of Mirant Corporation. Policy-making functions for Mirant North America are performed by the Board of Managers of Mirant North America and the other executive officers of Mirant Corporation. Information on the executive officers of Mirant Corporation will be provided in the Mirant Corporation definitive Proxy Statement for its 2008 Annual Meeting of Stockholders.
The principal executive officer, principal financial officer and principal accounting officer of Mirant North America were elected to serve until their successors are elected and have qualified or until their removal, resignation, death or disqualification.
Audit Committee and Audit Committee Financial Expert
We do not have a separately designated standing Audit Committee. Because Mirant North America is an indirect wholly-owned subsidiary of Mirant Corporation, the Board of Managers does not have independent members and therefore has not separately designated a member as a financial expert.
Section 16(a) Beneficial Ownership Reporting Compliance
We do not have equity securities registered pursuant to Section 12 of the Exchange Act and therefore do not have officers with Section 16 reporting obligations.
Code of Ethics for Senior Financial Officers
Mirant has a Code of Ethics and Business Conduct that applies to all Mirant officers, employees, subsidiaries and the Mirant Board of Directors. In addition, Mirant has adopted a Code of Conduct for Senior Financial Officers applicable to Mirant’s senior financial officers that also applies to the senior financial officers of Mirant North America. A copy of each code is posted on Mirant’s website at www.mirant.com and also will be provided, without charge, upon request made in writing to Mirant’s Corporate Secretary at 1155 Perimeter Center West, Atlanta, GA 30338. We intend to post any amendments and waivers to the Code of Ethics for senior financial officers on this website.
Shareholder Nominees to Board of Directors
We will not adopt procedures by which shareholders may recommend manager candidates because we are a wholly-owned subsidiary of Mirant Americas Generation.
Item 11.
Item 11. Executive Compensation
The officers of Mirant North America are also officers of Mirant. Our officers are not compensated separately in their positions with Mirant North America, and none of our officers has a contract or agreement in his capacity as an officer of Mirant North America. Policy-making functions for Mirant North America are performed by the Board of Managers of Mirant North America and the executive officers of Mirant. Information on compensation for the executive officers of Mirant will be provided in the Mirant definitive Proxy Statement for its 2008 Annual Meeting of Stockholders.
All of our equity is held by our direct parent, Mirant Americas Generation. Therefore, our equity is not publicly traded and there is no basis to compare the price performance of our equity to the price performance of an index or peer group.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management
We are a wholly-owned subsidiary of Mirant Americas Generation; therefore, none of our managers or officers hold any equity interests in Mirant North America.
Item 13.
Item 13. Certain Relationships and Related Transactions
Review and Approval of Related Person Transactions.
We are an indirect wholly-owned subsidiary of Mirant. Mirant’s Nominating and Governance Committee is responsible for reviewing and approving any related party transactions by Mirant, including transactions taken at the subsidiary level. Mirant’s legal department has adopted policies and procedures to assess transactions and relationships between Mirant and/or its subsidiaries and any related parties to determine if they have a direct or indirect material interest in the transaction. All related party transactions must be approved by the Nominating and Governance Committee.
Related Person Transactions
There were no reportable transactions between Mirant North America and related parties in 2007.
Item 14.
Item 14. Principal Accountant Fees and Services
Not Applicable.
PART IV
Item 15.
Item 15. Exhibits and Financial Statement Schedules
a) 1. Financial Statements
Our consolidated and combined financial statements, including the notes thereto and independent auditors’ report thereon, are set forth on pages through of the Annual Report on Form 10-K, and are incorporated herein by reference.
2. Financial Statement Schedules
None.
3. Exhibit Index
* Asterisk indicates exhibits incorporated by reference.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on this 9th day of March, 2008.
MIRANT NORTH AMERICA, LLC
By:
/s/ ROBERT E. DRISCOLL
Robert E. Driscoll
President and Chief Executive Officer
(Principal Executive Officer)
MIRANT NORTH AMERICA, LLC
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on March 9, 2008, by the following persons on behalf of the registrant and in the capacities indicated.
Signatures
Title
/s/ ROBERT E. DRISCOLL
Robert E. Driscoll
President and Chief Executive Officer of
Mirant North America, LLC
(Principal Executive Officer)
/s/ J. WILLIAM HOLDEN III
J. William Holden III
Senior Vice President, Chief Financial Officer and
Treasurer of Mirant North America, LLC
(Principal Financial Officer)
/s/ THOMAS E. LEGRO
Thomas E. Legro
Senior Vice President, Controller and Principal Accounting
Officer of Mirant North America, LLC
(Principal Accounting Officer)
/s/ EDWARD R. MULLER
Edward R. Muller
Manager of Mirant North America, LLC
/s/ JAMES V. IACO
James V. Iaco
Manager of Mirant North America, LLC
/s/ ROBERT M. EDGELL
Robert M. Edgell
Manager of Mirant North America, LLC
Supplemental Information to be Furnished with Reports Filed Pursuant to
Section 15(d) of the Act by Registrants Which Have Not Registered
Securities Pursuant to Section 12 of the Act
No annual report or proxy materials has been sent to securities holders and no such report or proxy material is to be furnished to securities holders subsequent to the filing of the annual report on this Form 10-K.