Item 1. Business
Overview
Mirant Americas Generation, LLC, including its subsidiaries (collectively, the “Company” or “Mirant Americas Generation”) is a national independent power provider and an indirect wholly-owned subsidiary of Mirant Corporation (“Mirant”). We produce and sell substantially all of the output from our generating facilities in the forward and spot markets and the remainder under contracts with third parties. We use derivative financial instruments, such as commodity forwards, futures, options and swaps to manage our exposure to fluctuations in electric energy and fuel prices. We are a Delaware limited liability company that owns or leases approximately 12,035 megawatts (“MW”) of electric generation capacity in the United States. We operate 72 generating units at 21 plants serving customers located near major metropolitan load centers in Maryland, California, New York, Massachusetts and Texas.
Pursuant to the Plan of Reorganization (the “Plan”), in December 2005 Mirant contributed its interest in Mirant Potomac River, LLC (“Mirant Potomac River”) and Mirant Peaker, LLC (“Mirant Peaker”) our indirect wholly owned subsidiary Mirant Mid-Atlantic, LLC (“Mirant Mid-Atlantic”) and its interest in Mirant Zeeland, LLC (“Mirant Zeeland”) and Mirant Americas Energy Marketing, LP (“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, L.P., and Mirant Americas Gas Marketing, LLC, (collectively, the “Trading Debtors”) to Mirant North America, LLC (“Mirant North America”), a newly organized holding company subsidiary. All of the contributed subsidiaries were under the common control of Mirant and are collectively referred to as the “Contributed Subsidiaries.” Mirant’s contribution of the Contributed Subsidiaries resulted in a change in the Mirant Americas Generation reporting entity under Accounting Principles Board Opinion No. 20, “Accounting Changes”, and accordingly we have restated the financial statements for all prior periods to reflect the financial information of the new reporting entity. See Note 4 for further discussion. On January 31, 2006, the trading and marketing business of the Trading Debtors was transferred to Mirant Energy Trading, LLC (“Mirant Energy Trading”) a wholly-owned subsidiary of Mirant North America.
We have a number of service agreements for labor and administrative services with Mirant and Mirant Services, LLC (“Mirant Services”). In addition, Mirant Energy Trading, and previously Mirant Americas Energy Marketing, provides services to other Mirant affiliates related to the sale of electric power and the procurement of fuel and emissions allowances. These agreements are discussed further in Note 6.
The annual, quarterly and current reports, and any amendments to those reports, that we file with or furnish to the U.S. Securities and Exchange Commission (“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 in this website is not incorporated into this Form 10-K,
As used in this report, “we,” “us,” “our,” the “Company” and “Mirant Americas Generation” refer to Mirant Americas Generation, LLC and its subsidiaries, unless the context requires otherwise.
Reorganization under Chapter 11 of the Bankruptcy Code
On July 14, 2003 (the “Petition Date”), and various dates thereafter, Mirant Americas Generation and its subsidiaries were among the 83 direct and indirect Mirant subsidiaries in the United States that, along with Mirant (collectively, the “Mirant Debtors”), filed with the United States Bankruptcy Court for the Northern District of Texas, Fort Worth Division (the “Bankruptcy Court”) voluntary petitions for relief under Chapter 11 of Title 11 of the United States Bankruptcy Code (as amended, the “Bankruptcy Code”), commencing the case In re Mirant Corporation et al., Case No. 03-46590 (DML).
During the pendency of the Chapter 11 proceedings, we, along with the other Mirant Debtors, operated our business as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code, the Federal Rules of Bankruptcy Procedure and applicable orders, as well as other applicable laws and rules. In general, each of the Mirant Debtors, as a debtor-in-possession, was authorized under the Bankruptcy Code to continue to operate as an ongoing business, but not to engage in transactions outside the ordinary course of business without the prior approval of the Bankruptcy Court.
On December 9, 2005, the Bankruptcy Court entered an order confirming our Plan, which became effective on January 3, 2006. The Plan set forth the structure of the Mirant Debtors at emergence and outlined how the claims of creditors and stockholders were to be treated. The implementation of the Plan resulted in, among other things, a new Mirant capital structure, the discharge of certain indebtedness, the satisfaction or disposition of various types of claims against the Mirant Debtors, the assumption or rejection of certain contracts and the establishment of a new Mirant Board of Directors.
On January 3, 2006, substantially all of the assets of the old Mirant were transferred to New Mirant, which, pursuant to the Plan, has no successor liability for any unassumed obligations of the old Mirant. Additionally Mirant Energy Trading, pursuant to the Plan, has no successor liability for any unassumed obligations of the Trading Debtors. After these transfers took place, old Mirant and the Trading Debtors, were transferred to a trust created under the Plan.
Competitive Environment
Historically, vertically integrated electric utilities with monopolistic control over franchised territories dominated the power generation industry in the United States. The enactment of the Public Utility Regulatory Policies Act of 1978 (“PURPA”), and the subsequent passage of the Energy Policy Act of 1992, fostered the growth of independent power producers. During the 1990s, a series of regulatory policies were partially implemented at both the federal and state levels to encourage competition in wholesale electricity markets.
As a result, independent power producers built new generating plants, purchased plants from regulated utilities and marketed wholesale power. Independent system operators (“ISOs”) and regional transmission organizations (“RTOs”) were created to administer the new markets and maintain system reliability. Beginning in the fall of 2001, however, in response to extreme price volatility and energy shortages in California, regulators began to re-examine the nature and pace of deregulation of wholesale electricity markets and that re-examination is continuing.
Independent power producers, as well as utilities, constructed primarily natural gas fired plants in the 1990s because such plants could be constructed more quickly and were less expensive to permit and build than nuclear facilities or plants fired by other fossil fuels. Stagnation in the growth of natural gas supplies, the increased demand from new generation facilities and the damage caused by hurricanes Katrina and Rita resulted in a sharp increase in the prices of natural gas during 2005. These high natural gas prices have significantly affected electricity prices in markets where gas fired units generally set the price. Some companies are constructing or attempting to obtain permits to construct additional liquefied natural gas receiving facilities which would increase the non-domestic supply of natural gas to the United States and could help to mitigate natural gas prices.
Coal fired generation and nuclear generation account for approximately 50% and 20%, respectively, of the electricity produced in the United States. Current high electricity prices as a result of high natural gas prices have led to renewed interest in new coal fired or nuclear plants. Some regulated utilities are proposing to construct clean coal units or new nuclear plants, in some cases with governmental subsidies or under legislative mandate. These utilities often are able to recover fixed costs through regulated retail rates, including, in many circumstances, the costs of environmental improvements to existing coal facilities,
allowing them to build, buy and upgrade without relying on market prices to recover their investments as we must do.
A number of factors combined to create excess generating capacity in certain U.S. markets, including the substantial increase in construction of generation facilities following the deregulation efforts described above, capital investments by utilities aimed at extending the lives of older units and the inability to decommission certain plants for reliability reasons. Although electricity supply and demand spreads have begun to tighten, we do not expect our primary markets to reach target reserve margins, approximately 15% of excess capacity over peak demand, until 2008 to 2010. However, given the time necessary to permit and construct new power plants, we think that certain markets in the United States need to begin now the process of adding generating capacity to meet growing demand. Many ISOs are considering capacity markets as a way to encourage such construction of additional generation, but it is not clear whether independent power producers will be sufficiently incentivized to build this new generation.
As a result of recent events, many regulated utilities are seeking to acquire distressed assets or build new generation, in each case with regulatory assurance that the utility will be permitted to recover its costs, plus earn a return on its investment. Success by utilities in those efforts may put independent power producers at a disadvantage because they rely heavily on market prices rather than regulatory assurances.
Operating Regions
Overview
Our core business is the production and sale of electrical energy, electrical capacity (the ability to produce electricity on demand) and ancillary services (services that are ancillary to transmission services). Our customers are ISOs, utilities, municipal systems, aggregators, electric cooperative utilities, producers, generators, marketers and large industrial customers. We serve four primary geographic areas: (i) the Mid-Atlantic Region, (ii) the Northeast Region, (iii) the Mid-Continent Region and (iv) the West Region, including Texas.
Ownership and Operations of Electricity Generation Assets
As of December 31, 2005, we owned or leased generation facilities in the United States with an aggregate generation capacity of over 12,000 MW. Our generating portfolio is diversified across fuel types, power markets and dispatch types and serves customers located near many major metropolitan load centers. We own or control approximately 85% of Mirant’s U.S. generating capacity.
Commercial Operations
Our commercial operations consist primarily of procuring fuel, dispatching electricity, hedging the production and sale of electricity by our generating facilities, and providing logistical support for the operation of our facilities (by, for example, procuring transportation for coal). We often sell the electricity we produce into the wholesale market at the prices in effect at the time we produce it (“spot prices”). Those prices are volatile, however, and in order to reduce the risk of that volatility we often enter into hedges-forward sales of electricity into the wholesale market and purchases of enough fuel and emissions allowances to allow us to produce and sell the electricity-for different periods of time. We procure these hedges in over-the-counter transactions or exchanges where electricity, fuel and emissions allowances are broadly traded, or through specific transactions with a seller, 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”), and subsequent to Mirant’s contribution of the trading and marketing operations to us, we buy and sell some electricity that we do not produce and some fuel and emissions allowances that we do not need to produce electricity (“proprietary trading”).
Proprietary trading is a small part of our commercial operations, which we do in order to gain information about the markets, in support of our asset management, and to take advantage of opportunities that we may see 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 trading positions and value-at-risk in our proprietary trading activities.
Commercial operations for our subsidiaries and other Mirant subsidiaries were conducted historically through Mirant Americas Energy Marketing. As of February 1, 2006, the energy trading and marketing operations of Mirant Americas Energy Marketing are being performed by Mirant Energy Trading.
Mirant Energy Trading has contracted with our subsidiaries and other Mirant subsidiaries that own generation facilities to procure fuel, dispatch facilities and sell the electricity generated in the wholesale market. Mirant Energy Trading uses dispatch models to make daily decisions regarding the quantity and the price of the power that our facilities will generate and sell into the markets. In markets governed by ISOs and RTOs, Mirant Energy Trading bids the energy from generation facilities into the day-ahead energy market and sells ancillary services through the ISO markets. Mirant Energy Trading works with the ISOs and RTOs in real time to ensure that Mirant and our generation facilities are dispatched economically to meet the reliability needs of the market. In non-ISO markets, Mirant Energy Trading conducts business through bilateral transactions pursuant to which Mirant Energy Trading provides dispatch schedules to the generation facilities.
We currently economically hedge a substantial portion of our Mid-Atlantic coal fired baseload generation (generation that is dispatched most of the time) and our New England oil fired generation through over-the-counter transactions. However, we generally do not hedge most of our cycling and peaking units (generating facilities that are not dispatched as frequently) due to the limited value we can extract in the marketplace and the high cost of collateral typically required to support these contracts. As of March 3, 2006, we have economically hedged approximately 90%, 60%, 30%, and 30% of our expected Mid-Atlantic coal fired generation for the remainder of 2006, 2007, 2008 and 2009, respectively, and purchased approximately 100%, 80%, 30% and 30% of the expected Mid-Atlantic coal requirements for such periods. Included in such amounts are financial swap transactions entered into by Mirant Mid-Atlantic with a counterparty in January 2006 pursuant to which Mirant Mid-Atlantic economically hedged approximately 80%, 50%, and 50% of its expected on-peak coal fired baseload generation for 2007, 2008 and 2009, respectively. The financial swap transactions are senior unsecured obligations of Mirant Mid-Atlantic and do not require us to post cash collateral either in the form of initial margin or to secure exposure due to changes in power prices. In addition, as of March 3, 2006, we have economically hedged approximately 50% of our expected oil fired generation in New England for the remainder of 2006 and procured approximately 50% of the corresponding expected oil requirements.
While over-the-counter transactions make up a substantial portion of our economic hedge portfolio, Mirant Energy Trading also sells non-standard, structured products to customers. In addition to energy, these products typically include capacity, ancillary services and other energy products. We view these transactions as a method of mitigating the risk of certain portions of our business that are not easy to economically hedge in the over-the-counter market. Typically, we are able to sell these products at a higher premium than standard products. For certain generation facilities, we have sought to enter into longer-term transactions to provide certainty of cash flows over an extended period. These transactions are typically tolling transactions whereby we receive a fixed capacity payment and, in return, grant an exclusive right for the counterparty to procure the fuel for the generation facility and take title to the power generated. Additionally, we have facilities in our business unit operating under long-term contracted capacity and reliability must run (“RMR”) contracts. At December 31, 2005, our contracted capacity pursuant to these agreements was approximately 2,699 MW with terms expiring through April 2014.
We enter into contracts of varying terms to secure appropriate quantities of fuel that meet the varying specifications of our generating facilities. For our coal fired generation facilities, we purchase coal from a variety of suppliers under contracts with terms of varying lengths, some of which extend to 2009. For our oil fired units, fuel is typically purchased under short-term contracts usually linked to a transparent oil index price. For our gas fired units, fuel is typically purchased under short-term contracts with a variety of suppliers on a day-ahead or monthly basis.
Our coal supply primarily comes from both the Central Appalachian and Northern Appalachian coal regions. All of our coal is delivered by rail. We monitor coal supply and delivery logistics carefully, and despite occasional interruptions of scheduled deliveries we have managed to avoid any significant impact to our operations. We maintain an inventory of coal at our coal fired facilities for this purpose. Interruptions of scheduled deliveries can occur because of supply disruptions due to strikes or other reasons or as a result of rail system disruptions due to weather or other reasons.
Mid-Atlantic Region
We own or lease four generation facilities with a total generation capacity of approximately 5,256 MW in the Washington D.C. area: Chalk Point, Morgantown, Dickerson and Potomac River. Our Mid-Atlantic region had a combined 2005 capacity factor of 39%. The Chalk Point facility is our largest facility in the region. It consists of two coal fired baseload units, two oil and gas fired intermediate units, two oil fired and five gas and oil fired peaking units, for a total generation capacity of 2,429 MW. Our next largest facility in the region is the Morgantown facility, and it consists of two dual-fueled (coal and oil) baseload units and six oil fired peaking units, for a total generation capacity of 1,492 MW. The Dickerson facility has three coal fired baseload units, one oil fired and two gas and oil fired peaking units, for a total generation capacity of 853 MW. The Potomac River station has three coal fired baseload units and two coal fired intermediate units, for a total generation capacity of 482 MW.
Power generated by our Mid-Atlantic facilities is sold into the Pennsylvania-New Jersey-Maryland Interconnection, LLC (“PJM”) market. For a discussion of the PJM market, see “Regulatory Environment-U.S. Public Utility Regulation” below. In connection with the acquisition of the Mid-Atlantic facilities from Potomac Electric Power Company (“PEPCO”) in 2000, Mirant Americas Energy Marketing agreed to supply PEPCO its full load requirement in the District of Columbia under a transition power agreement (“TPA”), which expired in January 2005 (the “DC TPA”). There was a similar TPA in place to supply PEPCO’s load in Maryland, which expired in June 2004 (the “Maryland TPA”). We also have participated in standard offer service auctions in Maryland and Washington, D.C. Power sales, made either directly through these functions or indirectly through subsequent market transactions that are a result of the auction process, serve as economic hedges for the Mid-Atlantic assets.
On August 24, 2005, power production at all five units of the Potomac River generating facility was temporarily halted in response to a directive from the Virginia Department of Environmental Quality (“Virginia DEQ”). The decision to temporarily shut down the facility arose from findings of a study commissioned under the order by consent referred to above. The Virginia DEQ’s directive was based on results from the study’s computer modeling showing that air emissions from the facility have the potential to contribute to localized, modeled exceedances of the health-based national ambient air quality standards (“NAAQS”) under certain conditions. On August 25, 2005, the District of Columbia Public Service Commission filed an emergency petition and complaint with the Federal Energy Regulatory Commission (“FERC”) and the Department of Energy (“DOE”) to prevent the shutdown of the Potomac River facility. The matter remains pending before the FERC and the DOE. On December 20, 2005, due to a determination by the DOE that an emergency situation exists with respect to a shortage of electric energy, the DOE ordered Mirant Potomac River to generate electricity at the Potomac River generation facility, as requested by PJM, during any period in which one or both of the transmission lines serving the central Washington, D.C. area are out of service due to a planned or unplanned outage. In addition, the DOE
ordered Mirant Potomac River, at all other times, for electric reliability purposes, to keep as many units in operation as possible and to reduce the start-up time of units not in operation. The DOE required Mirant Potomac River to submit a plan, on or before December 30, 2005, that met this requirement and did not significantly contribute to NAAQS exceedances. The DOE advised that it would consider Mirant Potomac River’s plan in consultation with the Environmental Protection Agency (“EPA”). The order further provides that Mirant Potomac River and its customers should agree to mutually satisfactory terms for any costs incurred by it under this order or just and reasonable terms shall be established by a supplemental order. Certain parties filed for rehearing of the DOE order, and on February 17, 2006, the DOE issued an order granting rehearing solely for purposes of considering the rehearing requests further. Mirant Potomac River submitted an operating plan in accordance with the order. On January 4, 2006, the DOE issued an interim response to Mirant Potomac River’s operating plan authorizing immediate operation of one baseload unit and two cycling units, making it possible to bring the entire plant into service within approximately 28 hours. We are selling the output of the facility into PJM. The DOE’s order expires after September 30, 2006, but we expect we will be able to continue to operate these units after that expiration. In a letter received December 30, 2005, the EPA invited Mirant Potomac River and the Virginia DEQ to work with the EPA to ensure that Mirant Potomac River’s operating plan submitted to the DOE adequately addresses NAAQS issues. The EPA also asserts in its letter that Mirant Potomac River did not immediately undertake action as directed by the Virginia DEQ’s August 19, 2005, letter and failed to comply with the requirements of the Virginia State Implementation Plan established by that letter. Mirant Potomac River received a second letter from the EPA on December 30, 2005, requiring Mirant to provide certain requested information as part of an EPA investigation to determine the Federal Clean Air Act (“Clean Air Act”) compliance status of the Potomac River facility. The facility will not resume normal operations until it can satisfy the requirements of the Virginia DEQ and the EPA with respect to NAAQS, unless, for reliability purposes, it is required to return to operation by a governmental agency having jurisdiction to order its operation. On January 9, 2006, the FERC issued an order directing PJM and PEPCO to file a long-term plan to maintain adequate reliability in the Washington D.C. area and surrounding region and a plan to provide adequate reliability pending implementation of this long-term plan. On February 8, 2006, PJM and PEPCO filed their proposed reliability plans. We are working with the relevant state and federal agencies with the goal of restoring all five units of the facility to normal operation in 2007.
Northeast Region
We own generating facilities in the Northeast region consisting of approximately 3,063 MW of capacity. Our Northeast region had a combined 2005 capacity factor of 34%. The Northeast region is comprised of the New York and New England sub-regions. The subsidiaries that own our New York facilities remain in bankruptcy. For further information, see “Item 3. Legal Proceedings.” Generation is sold from our Northeast facilities through a combination of bilateral contracts, spot market transactions and structured transactions.
New York. Our New York generating facilities were acquired from Orange and Rockland Utilities, Inc. (“Orange and Rockland”) and Consolidated Edison Company of New York, Inc. in June 1999. The New York generating facilities consist of the Bowline and Lovett facilities and various smaller generating facilities comprising a total of approximately 1,672 MW of capacity. The Bowline facility is a 1,125 MW dual-fueled (natural gas and oil) facility comprised of one intermediate/peaking unit and one intermediate unit. The Lovett facility consists of two baseload units capable of burning coal and gas comprising a total of 348 MW and a peaking unit capable of burning gas or oil comprising 63 MW. The smaller New York generating facilities have a total capacity of 136 MW and consist of the Hillburn and Shoemaker facilities, which each contain a single peaking unit capable of running on natural gas or jet fuel, and the Mongaup 1-4, Swinging Bridge 1-2 and Rio 1-2 facilities, which each contain a hydroelectric intermediate unit. We also have an operational interest in the Grahamsville facility, which has a
hydroelectric baseload unit. Our operational interest in the Grahamsville facility was pursuant to a sublease between Orange and Rockland and Mirant NY-Gen, LLC (“Mirant NY-Gen”), which expired on December 30, 2005. We have executed an interim agreement to extend this arrangement, which will be in effect until the earlier of December 31, 2006, or the end of the month following the month in which we receive regulatory approvals from the FERC and the New York Public Service Commission to transfer the facility to Orange and Rockland, which will transfer the facility to the City of New York. We received approval of the transfer from the FERC on February 27, 2006. A proposed expansion at the Bowline facility to add a natural gas and distillate oil fired unit with a total of 750 MW of generation capacity is currently suspended and we are attempting to extend permits such that we have the option to complete the project. Our New York plants operate in a market operated by the Independent System Operator of New York (“NYISO”). For a discussion of the NYISO, see “Regulatory Environment-U.S. Public Utility Regulation” below.
Our current plan is to retire one unit of the Mirant Lovett, LLC (“Mirant Lovett”) facility in 2007 and the remaining two units in 2008. However, we are exploring ways in which to avoid retiring the facility. In order for the facility to remain viable, we need to accomplish three primary tasks. First, we need agreements with the local taxing authorities to reduce property taxes. Although conditions remain to be met before the agreements are final, all of the taxing authorities have agreed in principle to refunds for past disputed taxes and substantial reductions in property taxes through 2012. Second, we need to reach agreement with the State of New York on amendments to a consent decree entered into on June 11, 2003, to resolve issues related to the new source review (“NSR”) regulations promulgated under the Clean Air Act (the “2003 Consent Decree”), which amendments would address the installation of environmental equipment. Third, as current market conditions do not allow Mirant Lovett to recover the necessary returns to fund the installation of environmental controls required under the 2003 Consent Decree, we will need an agreement with a third party assuring us of enough revenue to justify required capital expenditures. It is our view that the Lovett facility is necessary to the provision of reliable electricity to New York City and other areas within the NYISO.
In May of 2005, a sinkhole was discovered in the dam of our Swinging Bridge facility. Mirant NY-Gen is currently discussing with the FERC appropriate remediation for this sinkhole. We conducted a flood study to determine downstream consequences if the maximum capacity of the reservoirs were exceeded at our New York Swinging Bridge, Rio and Mongaup generation facilities, which may require that Mirant NY-Gen be requested by the FERC to remediate these dams as well. Mirant NY-Gen has initiated discussions with the FERC for surrendering its permits to operate all the hydroelectric facilities at Swinging Bridge, Rio and Mongaup, and expects to begin that formal process soon. It is not possible at this point to determine the cost of remediating the dam and surrendering the permits, but such costs may be substantial.
New England. Our New England generating facilities, with a total capacity of 1,391 MW, were acquired from subsidiaries of Commonwealth Energy System and Eastern Utilities Associates in December 1998. The New England generating facilities consist of the Canal station, the Kendall station, the Martha’s Vineyard diesels and an interest in the Wyman Unit 4 facility. The Canal and Kendall facilities, located in close proximity to Boston, consist of approximately 1,112 MW and 256 MW of generating capacity, respectively, and are designed to operate during periods of intermediate and peak demand. The Kendall facility is a combined cycle facility capable of producing both steam and electricity for sale. Both the Canal and Kendall facilities possess the ability to burn both natural gas and fuel oil. The Martha’s Vineyard diesels, with 14 MW of capacity, supply electricity on the island of Martha’s Vineyard during periods of high demand or in the event of a transmission interruption. The Wyman Unit 4 interest is an approximate 1.4% ownership interest (equivalent to 8.8 MW) in the 614 MW Wyman Unit 4 located on Cousin’s Island, Yarmouth, Maine. It is primarily owned and operated by the Florida Power and Light Group.
The capacity, energy and ancillary services from our New England generating units are sold into the New England Power Pool (“NEPOOL”) bilateral markets and into the markets administered by the Independent System Operator-New England (“ISO-NE”) through Mirant Energy Trading. For a discussion of the NEPOOL and the ISO-NE, see “Regulatory Environment-U.S. Public Utility Regulation” below. We had made a determination that market fundamentals in NEPOOL did not permit us to operate the Kendall facility on an economical basis as a merchant facility. We therefore planned to shut down, at least temporarily, the Kendall facility from January 2005 through December 2007, with the possibility of restarting operations as early as January 2008. However, the ISO-NE determined that part of the capacity of the Kendall facility was needed for reliability and proposed an RMR agreement with a term lasting until the earlier of (1) the date a locational installed capacity cost recovery mechanism applicable to the Kendall facility is in place or (2) 120-days after we are provided written notice. We entered into a settlement agreement with NSTAR Electric and Gas Corporation and ISO-NE and filed the settlement, which included the RMR agreement with the FERC. The FERC has approved the RMR agreement and we expect that the agreement will extend at least through the second quarter of 2006.
Mid-Continent Region
Pursuant to the Plan, Mirant (indirectly through a subsidiary) contributed its interest in Mirant Zeeland to our subsidiary, Mirant North America. The Zeeland facility, located in Zeeland, Michigan, is comprised of simple cycle units totaling 307 MW of capacity and a 530 MW combined cycle facility (837 MW of total capacity). The Zeeland facility is interconnected with the International Transmission Company, which is a member of the Midwest Independent Transmission System Operator (“MISO”), and operated under the East Central Reliability Coordination Agreement (“ECAR”) which, as of January 2006, has been merged with the Mid-American Interconnected Network (“MAIN”) and the Mid-Atlantic Area Council (“MAAC”) reliability regions and is part of ReliabilityFirst, the North American Electric Reliability Council (“NERC”) subregion. ReliabilityFirst is the successor organization to the three NERC regional reliability councils: MAAC, ECAR and MAIN.
We have a tolling agreement for the electrical energy output (307 MW, simple cycle) from the Zeeland plant, Units 1A and 1B, which expires on May 31, 2006. The tolling agreement provides for the generation owner to provide electric energy and related services using fuel supplied by the customer or with a pass-through to the customer of actual fuel cost. We receive a monthly capacity payment, a variable operating and maintenance payment on a per megawatt hour (“MWh”) basis and a start-up payment each time the unit is turned on. Our counterparty provides to the Zeeland plant all the fuel required to operate the contractual portion of the plant. Mirant Zeeland indirectly provides a heat rate and availability guarantee. There are bonus and penalty provisions in the agreement for availability outside allowable limits.
Mirant Zeeland Phase 2 (530 MW combined cycle output) has a tolling contract for 100% of its output through December 2006. The toll is with Mirant Energy Trading, which in turn has an agreement with a counterparty. We receive a monthly capacity payment, variable operations and maintenance payments on a per MWh basis and a start up payment. There are heat rate and availability guarantees with associated bonuses and penalties for being outside of tolerance bands. The fuel required to operate the facility during the term of the toll is provided to Mirant Zeeland through Mirant Energy Trading’s agreement with its counterparty. Mirant Zeeland operates under the MISO market and the ReliabilityFirst subregional reliability council of NERC.
For a discussion of the MISO, see “Regulatory Environment-U.S. Public Utility Regulation” below.
West Region
Our West region facilities, with a total capacity of 2,879 MW, are primarily gas fired generating facilities located in California and Texas. Our West region had a combined 2005 capacity factor of 13%.
California. Our generating facilities in California consist of the Pittsburg, Contra Costa and Potrero facilities, which have generation capacity of 1,311 MW, 674 MW and 362 MW, respectively, for a total capacity of 2,347 MW. The Pittsburg and Contra Costa facilities are intermediate facilities and both generate electricity by using gas fired steam boilers. They are located in Contra Costa County, approximately ten miles apart along the Sacramento/San Joaquin River. The Potrero facility, located in the City of San Francisco, has one natural gas fired baseload steam boiler from which it generates electricity and three oil fired peaking distillate fueled combustion turbines.
The majority of our California assets are subject to RMR arrangements with the California Independent System Operator (“CAISO”). These agreements are described further under “Regulatory Environment-U.S. Public Utility Regulation” below. Our California subsidiaries currently have the largest portfolio of units which operate under RMR arrangements in California, reflecting that the location of these units makes them key to electric system reliability. In September 2005, the CAISO Board approved RMR designations for 2006 that are the same as designations for 2005. Pittsburg Unit 7 and Contra Costa Unit 6 are not subject to an RMR arrangement, and thus function solely as merchant facilities in the CAISO. Mirant Energy Trading either sells the output of Pittsburg Unit 7 and Contra Costa Unit 6 into the market through bilateral transactions with utilities and other merchant generators, or dispatches the units in the CAISO clearing markets.
Pittsburg Unit 7, which has 682 MW of generation capacity, operated pursuant to a tolling agreement with a third party that expired in December 2005. We are currently seeking proposals for a one-, two- or three-year tolling arrangement or resource adequacy capacity sale on both Pittsburg Unit 7 and Contra Costa Unit 6. If we are unable to enter into a new tolling agreement for Pittsburg Unit 7 on acceptable terms, we may retire this unit.
Texas. We operate one facility in Texas, the Bosque facility, which consists of a gas fired combustion turbine with a corresponding steam turbine with a capacity of 230 MW that is available to serve baseload and intermediate demand. Additionally, Bosque Units 1 and 2 are gas fired peaking facilities with a capacity of 151 MW each. We have entered into a tolling agreement that grants the counterparty exclusive rights to the power and ancillary services generated by the Bosque facility through December 2006.
Our Bosque facility operates in the Electric Reliability Council of Texas (“ERCOT”) market. For a discussion of ERCOT, see “Regulatory Environment-U.S. Public Utility Regulation” below.
Regulatory Environment
U.S. Public Utility Regulation
The U.S. electricity industry is subject to comprehensive regulation at the federal, state and local levels. At the federal level, the FERC has exclusive jurisdiction under the Federal Power Act over sales of electricity at wholesale and the transmission of electricity in interstate commerce. Any of our subsidiaries that owns generating facilities selling at wholesale or that markets electricity at wholesale outside of ERCOT is a “public utility” subject to the FERC’s jurisdiction under the Federal Power Act. These subsidiaries must comply with certain FERC reporting requirements and FERC-approved market rules and are subject to FERC oversight of mergers and acquisitions, the disposition of FERC-jurisdictional facilities, and the issuance of securities. In addition, under the Natural Gas Act, the FERC has limited jurisdiction over certain sales for resale of natural gas, but does not regulate the prices received by our subsidiary that markets natural gas.
The Energy Policy Act of 2005 (“EPAct 2005”) became law on August 8, 2005, and it contains a wide range of provisions addressing many aspects of the electric industry. The EPAct 2005 repealed the Public Utility Holding Company Act of 1935 (“PUHCA”) and enacted the Public Utility Holding Company Act of 2005, which imposes on us additional obligations to maintain books and records unless we qualify for an exemption from these requirements, which is anticipated. The EPAct 2005 requires the FERC and other agencies to engage in numerous rulemakings and we are evaluating the potential impacts and opportunities that may result from these rulemakings. The EPAct 2005 authorizes the FERC to oversee new Electric Reliability Organizations that will develop and enforce national and regional reliability standards. In addition, the EPAct 2005 greatly expands the FERC’s ability to impose criminal and civil penalties for violations of the Federal Power Act with a specific emphasis on market manipulation and market transparency.
The FERC has authorized our subsidiaries that constitute public utilities under the Federal Power Act to sell energy and capacity at wholesale market-based rates and has authorized some of these subsidiaries to sell certain ancillary services at wholesale market-based rates. The majority of the output of the generation facilities owned by our subsidiaries that constitute public utilities is sold pursuant to this authorization, although certain of our facilities sell their output under cost-based RMR agreements, as explained below. The FERC may revoke or limit our market-based rate authority if it determines that we possess market power in a regional market. The FERC requires that our subsidiaries with market-based rate authority, as well as those with blanket certificate authorization permitting market-based sales of natural gas, adhere to certain market behavior rules and codes of conduct. If any of our subsidiaries violates the market behavior rules or codes of conduct, the FERC may require a disgorgement of profits or revoke its market-based rate authority or blanket certificate authority. If the FERC were to revoke market-based rate authority, our affected subsidiary would have to file a cost-based rate schedule for all or some of its sales of electricity at wholesale. If the FERC revoked the blanket certificate authority of any of our subsidiaries, it would no longer be able to make certain sales of natural gas.
The majority of our facilities operate in ISO/RTO regions. In areas where ISOs or RTOs control the regional transmission systems, market participants have expanded access to transmission service. ISOs and RTOs also may operate real-time and day-ahead energy and ancillary services markets, which are governed by FERC-approved tariffs and market rules. Some RTOs and ISOs also operate capacity markets. Changes to the applicable tariffs and market rules may be requested by market participants, state regulatory agencies and the system operator, and such proposed changes, if approved by the FERC, could have an impact on our operations and business plan. While participation by transmission-owning public utilities in ISOs and RTOs has been and is expected to continue to be voluntary, the majority of such public utilities in New England, New York, the Mid-Atlantic, the Midwest and California have joined the existing ISO/RTO for their respective region.
Our subsidiaries owning generation were exempt wholesale generators under the PUHCA, as amended. With the repeal of the PUHCA and the adoption of the Public Utility Holding Company Act of 2005, the FERC has put in place new regulations effective February 8, 2006, that allow our subsidiaries owning generation to retain their exempt wholesale generator status.
At the state and local levels, regulatory authorities historically have overseen the distribution and sale of retail electricity to the ultimate end user, as well as the siting, permitting and construction of generating and transmission facilities. Our existing generation may be subject to a variety of state and local regulations, including regulations regarding the environment, health and safety, maintenance, and expansion of generation facilities. To the extent that a subsidiary sells at the retail level in a state with a retail access program, it may be subject to state certification requirements and to bidding rules to provide default service to customers who choose to remain with their regulated utility distribution companies.
Mid-Atlantic Region. Our Mid-Atlantic facilities sell power into the markets operated by PJM, which the FERC approved to operate as an ISO in 1997 and as an RTO in 2002. We have access to the PJM transmission system pursuant to PJM’s Open Access Transmission Tariff. PJM operates the PJM Interchange Energy Market, which is the region’s spot market for wholesale electricity, provides ancillary services for its transmission customers, performs transmission planning for the region and dispatches generators accordingly. PJM administers day-ahead and real-time marginal cost clearing price markets and calculates electricity prices based on a locational marginal pricing model. A locational marginal pricing model determines a price for energy at each node in a particular zone taking into account the limitations on transmission of electricity and losses involved in transmitting energy into the zone, resulting in a higher zonal price when cheaper power cannot be imported from another zone. Generation owners in PJM are subject to mitigation, which limits the prices that they may receive under certain specified conditions.
Load serving entities in PJM are required to have adequate sources of capacity. PJM operates a capacity market whereby load serving entities can procure their capacity requirements through a system-wide single clearing price auction. In PJM, all capacity is assumed to be universally deliverable, regardless of its location. PJM has greatly expanded its system over the last three years to include Allegheny Power, Commonwealth Edison, American Electric Power, Inc. (“AEP”), Duquesne Light, Dayton Power & Light (“DP&L”) and Dominion-Virginia Power. As a result, capacity prices have significantly declined. The PJM expansions have resulted in an apparent system-wide surplus of capacity, despite the fact that certain regions in PJM-Mid-Atlantic will need capacity additions within the next few years.
On August 31, 2005, PJM filed its Reliability Pricing Model (“RPM”) with the FERC. This proposal is intended to replace its current capacity market rules. The new RPM proposal would provide for establishment of locational deliverability zones for capacity phased in over a several year period beginning on June 1, 2006. If ultimately approved by the FERC in a form not materially different from what was filed, the new RPM would result in increased opportunities for generators to receive more revenues for their capacity. However, on November 5, 2005, PJM proposed to delay the effective date of the RPM until June 1, 2007, and it is impossible to predict whether this or a similar proposal will be adopted.
In addition, PJM and the MISO have been directed by the FERC to establish a common and seamless market, an effort that is largely dependent upon the MISO’s ability first to establish and operate its markets. The development of a joint market is contingent on the approval of the internal costs to both entities to develop and operate the infrastructure necessary for joint operations. It is unclear at this time if either the respective entities or the FERC will approve such costs to achieve a common and seamless market.
Northeast Region. Our New York plants participate in a market controlled by the NYISO, which replaced the New York Power Pool. The NYISO provides statewide transmission service under a single tariff and interfaces with neighboring market control areas. To account for transmission congestion and losses, the NYISO calculates energy prices using a locational marginal pricing model that is similar to that used in PJM and ISO-NE. The NYISO also administers a spot market for energy, as well as markets for installed capacity and services that are ancillary to transmission service, such as operating reserves and regulation service (which balances resources with load). The NYISO employs an Automated Mitigation Procedure (“AMP”) in its day-ahead market that automatically caps energy bids when certain established bid screens indicate a bidder may have market power. In response to a January 14, 2005, order of the U.S. Court of Appeals for the Washington, D.C. Circuit, in the spring of 2005 the NYISO discontinued use of the AMP in the upstate region known as ‘‘Rest of State.’’ In addition, the NYISO’s locational capacity market rules use a demand curve mechanism to determine for every month the required amount of installed capacity as well as installed capacity prices to be paid for three locational zones: New York City, Long Island and Rest of State. Our facilities operate outside of New York City and Long Island. On April 21, 2005, the FERC issued an order accepting the NYISO’s demand curves for capability years
2005/2006, 2006/2007 and 2007/2008 with minor modifications to the NYISO’s proposal. It is possible that the new demand curves may result in increased prices within the NYISO for capacity.
Our New England plants participate in a market administered by ISO-NE. Mirant Energy Trading is a member of NEPOOL, which is a voluntary association of electric utilities and other market participants in Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont, and which functions as an advisory organization to ISO-NE. The FERC approved ISO-NE as the RTO for the New England region effective on February 1, 2005, making ISO-NE responsible for market rule filings at the FERC, in addition to its responsibilities for the operation of transmission systems and administration and settlement of the wholesale electric energy, capacity and ancillary services markets. ISO-NE utilizes a locational marginal pricing model, with a price mitigation method similar to the NYISO’s AMP (discussed above), although it is implemented via manual processes rather than the automated process employed in New York. In 2004, the FERC approved a locational installed capacity market for ISO-NE (the ‘‘LICAP proposal’’) based on the demand curve concept used by the NYISO to be implemented in January 2006. The LICAP proposal included demand curves, which are administrative mechanisms used to establish electricity generation capacity prices. A hearing on the demand curve parameters was held in February and March 2005 and an initial decision was issued by the presiding administrative law judge that found in favor of many of the suppliers’ issues in the hearing. A subsequent FERC order issued on October 21, 2005, pushed back the LICAP implementation date to no sooner than October 1, 2006, and put in place procedures to pursue a settlement on alternatives to the LICAP mechanism. On March 6, 2006, a settlement in principle was filed with FERC that provides for a capacity market with a transition period from December 2006 through June 2010 with fixed rate payments to generators and a Forward Capacity Market beginning in 2010. The settling parties request FERC approval of the settlement by June 30, 2006. We expect that the settlement will be opposed by some parties to the original LICAP proceeding. If approved, without modification, the settlement will result in increased revenue opportunities for Mirant Canal and Mirant Kendall for the December 2006 to June 2010 time period. We cannot, however, predict if the settlement will be approved by the FERC without modification nor can we predict whether the FERC will implement the settlement dates as requested.
Mid-Continent Region. Our Mid-Continent plant is located in the Midwest market and participates in a market administered by the MISO. The MISO commenced administering energy markets similar to those operated by PJM in the spring of 2005. The MISO uses locational marginal pricing for energy. The MISO proposes to implement a permanent solution to resource adequacy by June 1, 2007, but has not yet identified a specific capacity market design or when it will file a tariff with the FERC. The MISO also implements mitigation rules similar to those of the NYISO, without an automatic mitigation mechanism.
West Region. Our generation facilities in the West are located in the Western Interconnection and ERCOT market in Texas. Our California facilities are located in the CAISO’s control area. The CAISO schedules transmission transactions, arranges for necessary ancillary services and administers a real-time balancing energy market. Most sales in California are pursuant to bilateral contracts, but a significant percentage is sold in the real-time market. The CAISO does not operate a forward market like those described for PJM and other Eastern ISO markets, nor does it currently operate a capacity market.
The CAISO has proposed changes to its market design to more closely mirror the Eastern ISO markets. The market redesign has been delayed several times, with full implementation now expected in 2007 or 2008. The California Public Utilities Commission (“CPUC”) has taken the lead role for establishing capacity requirements in California and has ordered California’s load serving entities to demonstrate, beginning in the summer of 2006, that they have acquired sufficient capacity to serve their forecast retail load plus a specified reserve margin. Any proposal for a capacity market in California is subject to filing with and approval by the FERC, and at this time, the CAISO has not proposed a capacity market mechanism in its market redesign. The CPUC has also taken a role in developing recommended options with respect to a wholesale capacity market in conjunction with the CAISO. We cannot at this time
predict the outcome or the result of the CPUC proceeding or the timing or development of a wholesale capacity market by either the CPUC or the CAISO.
The majority of our assets in California are subject to RMR arrangements with the CAISO. These agreements require certain of our facilities, under certain conditions and at the CAISO’s request, to operate at specified levels in order to support grid reliability. Under the RMR arrangements, we recover through fixed charges either a portion (RMR Contract Condition 1) or all (RMR Contract Condition 2) of the annual fixed revenue requirement of the generation assets as approved by the FERC (the “Annual Requirement”). Our California generation facilities operating under RMR Contract Condition 1 depend on revenue from sales of the output of the plants at market prices to recover the portion of the plant’s fixed costs not recovered through RMR payments.
Our subsidiaries owning facilities subject to the RMR arrangements have entered into two power purchase agreements (“PPAs”) with Pacific Gas & Electric (“PG&E”) that allow PG&E to dispatch and purchase the power output of all units of those generation facilities designated by the CAISO as RMR units under the RMR arrangements. The first agreement was in effect during 2005 and the second agreement extends from 2006 through 2012. Under those agreements, those units designated as RMR by the CAISO are designated as RMR Contract Condition 1, but during 2005 through 2008, PG&E is paying us charges equivalent to the rates we charged during 2004 when the units were designated RMR Contract Condition 2, reduced on an aggregate basis from those 2004 rates by $5 million. After 2008, we will file annually for FERC approval of the Annual Requirement, which, once approved by the FERC, will set the rates to be charged.
The CAISO imposed a $400 per MWh cap, effective on January 1, 2006, on prices for energy and has implemented an AMP similar to that used by the NYISO. In addition, owners of non-hydroelectric generation in California, including certain of our facilities, must offer to keep their generation on line and stand ready to offer power into the CAISO’s spot markets if the output is not under contract or scheduled for delivery within the hour, unless granted a waiver by the CAISO (the ‘‘must-offer requirement’’). The practical effect of this rule is to obtain operating reserves without paying for them, and to release excess supply energy into the market, thus depressing prices. On August 26, 2005, the Independent Energy Producers, a trade association, filed a complaint at the FERC, requesting that the FERC require the CAISO to implement a Reliability Capacity Services Tariff (‘‘RCST’’) that would pay generators for the capacity obtained pursuant to the must-offer requirement. If granted by the FERC, the new RCST may result in increased capacity revenue opportunities for generators.
The CPUC has issued a series of orders purporting to require exempt wholesale generators and other power plant owners to comply with detailed operation, maintenance and logbook standards for electricity generating facilities. In its orders, the CPUC has stated its intent to implement and enforce these detailed standards so as to maintain and protect the public health and safety of California residents and businesses, to ensure that electric generating facilities are effectively and appropriately maintained and efficiently operated, and to ensure electrical service reliability and adequacy. The CPUC has adopted detailed reporting requirements for the standards, and conducts frequent on-site spot inspections and more comprehensive facility audits to evaluate compliance. Some standards are intended to ensure that units are maintained in a state of readiness so as to be available to operate if requested by a control area operator, while others provide procedures for changing a unit’s long-term status. The CPUC’s efforts to implement and enforce the operation, maintenance and logbook standards could interfere with our future ability to make economic business decisions regarding our units, including decisions regarding unit retirements, and could have a material adverse impact on our business activities in California.
Our Texas plants participate in a market administered by ERCOT, which manages a major portion of the state’s electric power grid. ERCOT oversees competitive wholesale and retail markets resulting from electricity restructuring in Texas and protects the overall reliability of the ERCOT grid. ERCOT, the only ISO that manages both wholesale and retail market operations, is regulated by the Public Utility Commission of Texas (“PUCT”). The PUCT conducts market monitoring within ERCOT. Price mitigation measures in ERCOT include a $1,000 per MWh price cap and RMR-type contracts for congested areas. The PUCT has recently conducted hearings on wholesale market design issues that will focus on adding a congestion management mechanism based on locational pricing, using nodal locational pricing with day-ahead and real-time markets. Presently, we cannot estimate when the enhancements will be completed and implemented.
Environmental Regulation
Our business is subject to extensive environmental regulation by federal, state and local authorities. This requires us to comply with applicable laws and regulations, and to obtain and comply with the terms of government issued operating permits. Our costs of complying with environmental laws, regulations and permits are substantial. For example, we estimate that our capital expenditures for environmental compliance will be approximately $300 million for 2006 and will be $1 billion to $1.5 billion from 2006 through 2011. Our potential capital expenditures for environmental regulation are difficult to estimate because we cannot now assess what regulations may be applicable or what costs might be associated with certain regulations. Our capital expenditures will be materially impacted if the State of Maryland passes legislation or imposes regulations that increase beyond applicable federal law the restrictions on emissions of sulfur dioxide (“SO2”), nitrogen oxide (“NOx”) and mercury, or imposes restrictions on emissions of carbon dioxide (“CO2”). This legislation or regulation, or similar legislation or regulations in other states or by the federal government, may render some of our units uneconomic.
Air emissions regulations. Our most significant environmental requirements generally fall under the Clean Air Act and similar state laws. Under the Clean Air Act, we are required to comply with a broad range of mandates concerning air emissions, operating practices and pollution control equipment. Several of our facilities are located in or near metropolitan areas, such as New York City, Boston, San Francisco and Washington, D.C., which are classified by the EPA as not achieving certain NAAQS. As a result of the NAAQS classification of these areas, our operations are subject to more stringent air pollution requirements, including, in some cases, further emissions reductions. In the future, we anticipate increased regulation of generation facilities under the Clean Air Act and applicable state laws and regulations concerning air quality. Significant air regulatory programs to which we are subject include those described below.
Acid rain program. The EPA promulgated regulations that establish cap and trade programs for SO2 emissions (the ‘‘Acid Rain Program’’) from electric generating units in the United States. Under this system, the Acid Rain Program set a permanent ceiling (or cap) of 8.95 million allowances for total annual SO2 allowance allocations to utilities. Each allowance permits a unit to emit one ton of SO2 during or after a specified year. Affected utility units were allocated allowances based on their historic fuel consumption and a specific emissions rate. Allowances may be bought, sold or banked. Some of our facilities have surplus allowances, and some are required to purchase additional SO2 allowances to cover their emissions and maintain compliance. The costs of SO2 allowances have increased substantially in recent years. Prior to 2004, prices generally ranged between $100 and $200 per ton. Prices rose from approximately $200 per ton to approximately $800 per ton during 2004 and to approximately $1,600 per ton in 2005. We expect to be a net purchaser of allowances for 2006. Many factors can affect the price of SO2 allowances, and we cannot be certain that the price of allowances will not increase substantially from current historical highs in future years. Depending on the actual price and number of SO2 allowances we need to buy, such costs may materially impact us. This program and other regulations requiring further reductions in SO2 emissions, such as the Clean Air Interstate Rule (“CAIR”), may result in our deciding to further reduce emissions at
some of our facilities through new control technology. The cost of additional pollution control technology could be significant; however, it could be partially offset by the avoided cost of purchasing SO2 allowances. For additional discussion of SO2 control technology see the discussion of the CAIR below.
NOx SIP call. New NOx regulations will require a combination of capital expenditures and the purchase of emissions allowances in the future. The EPA has promulgated regulations that established emissions cap and trade programs for NOx emissions from electric generating units in most of the eastern states (the “NOx SIP Call”). These programs were implemented beginning May 2003 in the Northeast and May 2004 in the rest of the Eastern United States. Under these regulations, a facility receives an allocation of NOx emissions allowances. If a facility exceeds its allocated allowances, the facility must purchase additional allowances. Some of our facilities in these states have been required to purchase NOx allowances to cover emissions to maintain compliance. The cost of allowances will fluctuate in future years, and depending on the actual price and number of NOx allowances we need to buy, such costs could materially affect our operations. As a result, we may decide to reduce NOx emissions through control technology in addition to what is already installed or planned. The cost of additional pollution control technology could be significant; however, it may be partially offset by the avoided cost of purchasing NOx allowances to operate the facility.
CAIR. In March 2005, the EPA issued the CAIR, which establishes in the Eastern United States a more stringent SO2 cap and allowance-trading program and a year round NOx cap and allowance-trading program applicable to generation facilities. These cap and trade programs would be implemented in two phases, with the first phase going into effect in 2010 and more stringent caps going into effect in 2015. In order to comply with the first phase of those regulations, we will have to install additional pollution control equipment, and/or purchase additional emissions allowances, at significant cost. Currently, we are planning to install pollution control equipment at our facilities to address, in part, our requirements under the first phase of the CAIR. The costs of that equipment are included in our estimate of anticipated environmental capital expenditures from 2006 through 2011. However, since the determination of how much pollution control equipment to install is based upon factors such as the cost of emissions allowances and the operational demands on our generation facilities, our plans may change significantly over the coming years.
CAMR. The EPA promulgated the Clean Air Mercury Rule (“CAMR”) on March 15, 2005, which utilizes a market-based cap and trade approach under Section 111 of the Clean Air Act. It requires emissions reductions in two phases, with the first phase going into effect in 2010 and the more stringent cap going into effect in 2018. It is our view that the pollution control equipment we intend to install to comply with the CAIR should adequately reduce mercury emissions to the levels required by 2010. We cannot currently estimate the costs to comply with the reductions required by 2018, but they may be material. The CAMR has faced considerable political and legal opposition, as a result of which the EPA in October 2005 issued a notice of proposed rulemaking to reconsider certain aspects of the CAMR. The CAMR is currently being challenged in federal court. Those challenges may lead to amendments to the CAMR or passage of different mercury control legislation, which could require stricter control of mercury emissions and/or more expensive control equipment.
NSR enforcement initiative. In 1999, the Department of Justice (“DOJ”) on behalf of the EPA commenced enforcement actions against a number of companies in the power generation industry for alleged violations of the NSR regulations, which require permitting and impose other requirements for certain maintenance, repairs and replacement work on facilities. These enforcement actions can result in a facility owner having obligations to, among other things, install emissions controls at significant costs. These enforcement actions were broadly challenged by the industry in the courts and the EPA. We have complied with the NSR regulations as they have been interpreted in final, binding decisions. In 2001 the EPA requested information concerning some of our facilities covering a time period that predates our ownership or leasing. The challenges to the new interpretation of the NSR regulations may affect the
enforcement actions, but there is no assurance that there will not be further requests or enforcement proceedings that can materially affect our plants.
State air regulations. Various states where we do business also have other air quality laws and regulations with increasingly stringent limitations and requirements that will become applicable in future years to our facilities and operations. We expect to incur additional compliance costs as a result of these additional state requirements, which could include significant expenditures on emissions controls or have other impacts on operations.
For example, the Commonwealth of Massachusetts has finalized regulations to further reduce NOx and SO2 emissions from certain generation facilities and to regulate CO2 and mercury emissions for the first time. Mercury emissions reductions will be required exclusively from coal fired facilities. Portions of these regulations, which become effective in the 2005-2008 time frame, will apply to our oil fired Canal facility in the state, will increase our operating costs and will likely necessitate the installation of additional emissions control technology.
Another example of state regulation that affects our generation facilities arises in the San Francisco Bay area, where we own generation facilities. Regional NOx emissions standards have become increasingly stringent on a specified schedule over a several year period, culminating in 2005. We continued to apply our NOx implementation plan for these facilities, which included the installation of selective catalytic reduction (“SCR”) emissions control equipment at our Potrero Unit 3 facility and the partial curtailment of two of our higher NOx emitting units.
In 2000, the State of New York issued a notice of violation (“NOV”) to the previous owner of our Lovett facility alleging NSR violations associated with the operation of that facility prior to its acquisition by us. On June 11, 2003, Mirant New York, Inc. (“Mirant New York”), Mirant Lovett and the State of New York entered into the 2003 Consent Decree. The 2003 Consent Decree was approved by the Bankruptcy Court on October 15, 2003. Under the 2003 Consent Decree, Mirant Lovett has three options: (1) install emissions controls on Lovett’s two coal fired units; (2) shut down one unit and convert one unit to natural gas; or (3) shut down both coal burning units in 2007 and 2008. If Mirant Lovett elects to install emissions controls on its two coal fired units by 2007 through 2008, it must install: (1) emissions controls consisting of SCR technology to reduce NOx emissions; (2) alkaline in-duct injection technology to reduce SO2 emissions; and (3) a baghouse. Additionally, in 2003, the State of New York finalized air regulations that significantly reduced allowances for NOx and SO2 emissions from generation facilities through a state emissions cap and trade program, which will become effective during the 2005-2008 timeframe. We have recognized that the 2003 Consent Decree and the new regulations, taken together with property taxes based on assessed values for our New York facilities that are far in excess of actual values and with NYISO rules that do not take into consideration the importance of the Mirant Lovett facility to the reliable supply of electricity, would have rendered the continuing operation of the Mirant Lovett facility uneconomic. It is therefore our current plan to retire the Lovett generating facility by 2008. In an effort to keep the plant operating, we are trying to negotiate agreements to reduce property taxes and to compensate Mirant Lovett for its contribution to the reliability of the electricity system, which will enable us to agree with the State of New York to make capital expenditures on environmental controls in excess of $200 million, significantly more than contemplated by the 2003 Consent Decree. The 2003 Consent Decree required Mirant Lovett to notify the state of its selected option by August 1, 2004, which date was extended by the State of New York to August 1, 2005, with subsequent extensions to February 15, 2006. On February 15, 2006, Mirant Lovett submitted a proposal to the State of New York for the installation of certain environmental controls in excess of those in the 2003 Consent Decree conditioned on execution and approval of acceptable property tax and reliability agreements. Pursuant to the Bankruptcy Court’s order approving the 2003 Consent Decree, Mirant Lovett may not enter into a binding agreement to construct the environmental controls or to elect a shutdown of the facility without first obtaining the approval of the Bankruptcy Court.
Climate change. Concern over climate change deemed by many to be induced by rising levels of greenhouse gases in the atmosphere has led to significant legislative and regulatory efforts to limit greenhouse gas emissions.
In 1998, the United States became a signatory to the Kyoto Protocol of the United Nations Framework Convention on Climate Change. The Kyoto Protocol, which became effective in February 2005 after Russia’s ratification in November 2004, calls for developed nations to reduce their emissions of greenhouse gases to 5% below 1990 levels by 2012. CO2, which is a major byproduct of the combustion of fossil fuel, is a greenhouse gas that would be regulated under the Kyoto Protocol. The United States Senate indicated that it would not enact the Kyoto Protocol, and in 2002 President Bush confirmed that the United States would not enter into the Kyoto Protocol. Instead, the President indicated that the United States would support voluntary measures for reducing greenhouse gases and technologies that would use or dispose of CO2 effectively and economically. As the Kyoto Protocol becomes effective in other countries, there is increasing pressure for sources in the United States to be subject to mandatory restrictions on CO2 emissions. In the last year, the United States Congress has considered bills that would regulate domestic greenhouse gas emissions, but such bills have not received sufficient Congressional approval to date to become law. If the United States ultimately ratifies the Kyoto Protocol and/or if the United States Congress or individual states or groups of states in which we operate ultimately pass legislation regulating the emissions of greenhouse gases (see discussion of the Regional Greenhouse Gas Initiative below), any resulting limitations on generation facility CO2 emissions could have a material adverse impact on all fossil fuel fired generation facilities (particularly coal fired facilities), including ours.
On December 20, 2005, seven states in the Northeast agreed to go forward with the implementation of a cooperative known as the Regional Greenhouse Gas Initiative (“RGGI”). This is the first multi-state regional initiative that uses a regional cap and trade program to reduce CO2 emissions from power plants of 25 MW or greater. The program aims to stabilize CO2 emissions to current levels from 2009 to 2015. This will be followed by a 10% reduction in emissions by 2019. This initiative envisions participating states executing a memorandum of understanding and then promulgating implementing regulations based on the RGGI template. The recommended allocation scheme calls for allocation of 20% of allowances to a public benefit purpose and 5% to a regional strategic carbon fund, thereby further reducing allowances available to affected facilities. In the future, the RGGI may include other sources of greenhouse gas emissions and greenhouse gases other than CO2. If the RGGI results in mandatory regulations in states where we have generating units, our costs of implementation may be material. New York, where we have generating units, is a participant in the RGGI. Massachusetts, where we also have generating units, originally agreed to participate but later withdrew.
On June 1, 2005, the Governor of California established greenhouse gas reduction targets for California, which would by 2010, reduce statewide greenhouse gas emissions to 2000 emissions levels; by 2020, reduce statewide greenhouse gas emissions to 1990 emissions levels; and by 2050, reduce statewide greenhouse gas emissions to 80% below 1990 levels. Implementing strategies to reach these targets will be the responsibility of a Climate Action Team, an interagency team established by the Governor. The team is led by the California EPA and is composed of high level representatives from key state agencies. This team will report to the Governor and the Legislature in early 2006.
Proposed Maryland clean power rule and other air legislative and regulatory developments. In addition to the implementation of existing requirements, there are additional environmental requirements under consideration by the federal and various state legislatures and environmental regulatory bodies. Maryland’s governor announced in November 2005 that he intends to propose a Maryland Clean Power Rule, that would require deep reductions in NOx emissions (69% reduction) by the year 2009, and in SO2 emissions (85% reduction) and mercury emissions (70% reduction) by the year 2010, at six Maryland coal fired generation facilities, including our Chalk Point, Dickerson and Morgantown facilities. If the rulemaking proceeds according to the timing indicated by the Governor’s office, that regulation would
become effective in the summer of 2006. Although we have not fully evaluated the impacts of the Governor’s proposed rule as announced, if adopted, it would limit our ability to acquire emissions allowances for use associated with our Maryland power facilities, and would require us to consider the economic impact of increasing substantially our capital expenditures from 2006 through 2010, which may have a material impact on us. The Governor’s rule, which does not require legislative approval, was approved by the Air Quality Control Advisory Council on March 13, 2006, and will be the subject of regional public hearings in the early spring of 2006. Maryland hopes to adopt the rule during the summer of 2006.
In addition to the proposed state regulations, the Maryland Legislature is in the process of moving the Healthy Air Act in both the Senate (“SB 154”) and in the House (“HB 189”). The House and Senate bills were introduced simultaneously on January 19, 2006. The legislation is similar to the Maryland Clean Power Rule; however, it would require deeper reductions of NOx, SO2, mercury and CO2. On March 20, 2006, the Senate passed their version of the bill which requires reductions of NOx in two phases beginning in 2009 and 2012 and SO2 in 2010 and 2015. It also requires reductions of mercury emissions by the years 2010 and 2012. More importantly, unlike the Maryland Clean Power Rule, the legislation also addresses CO2 by requiring the State to join the Northeast Regional Greenhouse Gas Initiative (“RGGI”). RGGI will require mandatory reductions of CO2 emissions beginning in 2009 with a second phase in 2019. The House bill is likely to be acted upon by March 31, 2006. If passed in the House, the two bills would be debated and combined into one to be sent to the Governor for his approval. The reductions would be required at all three of our Maryland coal fired generation facilities. There is currently no technology that would meet the proposed requirements for mercury and CO2, and we would have to consider running the facilities less in order to comply.
In addition to the state activities, at the federal level, the Bush Administration has submitted to Congress Clean Air Act multi-emissions reform legislation, which would promulgate a new emissions cap and trade program for NOx, SO2 and mercury emissions from generation facilities. This legislation would require generation facilities to reduce overall emissions of these pollutants by approximately 50-75% phased in during the 2008-2018 timeframe, which is similar to the types of overall reductions required under CAIR and CAMR. More stringent multi-emissions reform legislation also has been proposed in Congress by some lawmakers. If enacted as proposed, some of this legislation may materially impact us.
The EPA and the states are also in the process of implementing new, more stringent ozone and particulate matter ambient air quality standards and the EPA’s rules addressing regional haze visibility issues. The full implementation of any of these rules may result in further emissions reduction requirements for some of our facilities.
Water regulations. We are required under the Federal Water Pollution Control Act (“Clean Water Act”) to comply with effluent and intake requirements, technological controls requirements and operating practices. Our wastewater discharges are subject to permitting under the Clean Water Act, and our permits under the Clean Water Act are subject to review every five years. As with air quality regulations, federal and state water regulations are expected to increase and impose additional and more stringent requirements or limitations in the future. It is our view that the regulations promulgated by the EPA to implement Section 316(b) of the Clean Water Act, will require us to incur substantial expenses in future years. These regulations address the need to require the best technology available for cooling water intake structures to minimize adverse effects on fish and shellfish. These regulations set performance standards for all existing large power plants and are intended to reduce the losses of aquatic organisms inadvertently pulled into a power plant’s circulating water system. Potential compliance alternatives include using existing technologies, selecting additional fish protection technologies and using restoration measures. Over the next few years, our generation facilities subject to this cooling water intake regulation (Bowline, Canal, Kendall, Pittsburg, Contra Costa, Potrero, Chalk Point, Morgantown, Potomac River and Dickerson) will be evaluating and implementing the requirements of the 316 (b) regulation by completing
impingement and entrainment studies, evaluating technologies, operational measures, and restoration measures. The cost of performing the studies and capital expenditures to install barriers or control devices or to implement other protective measures at three of our facilities is expected to approximate $10 million from 2006 through 2011. The cost of installing protection technologies may be material.
In early 2006, the U.S. Department of the Interior, through its Fish and Wildlife Services division (the “FWS”), sent a letter to the U.S. Army Corps of Engineers requesting that it reinitiate formal consultation on the biological opinion that permits Mirant Delta, LLC (“Mirant Delta”) to use and recycle water from the San Joaquin river for its operation of the Pittsburg and Contra Costa power plants. The formal consultation process explores the environmental impacts of Mirant Delta’s water usage, including the impacts on certain species of fish in the river, and then provides directives regarding the manner in which Mirant Delta may utilize river water for cooling in the plants’ operations. It is our view that Mirant Delta is operating in compliance with its water usage permits and that this reopening of the formal consultation process is improper. Mirant Delta responded to the FWS, asserting that it has implemented all investigative and operational measures prescribed by the FWS to reduce the impact of its water usage on the endangered species in the San Joaquin River, and it is currently waiting for a response from the FWS to this communication.
Wastes, hazardous materials and contamination. Our facilities are subject to several waste management laws and regulations. The Resource Conservation and Recovery Act of 1976 set forth comprehensive requirements for handling of solid and hazardous wastes. The generation of electricity produces non-hazardous and hazardous materials, and we incur substantial costs to store and dispose of waste materials from these facilities. The EPA may develop new regulations that impose additional requirements on facilities that store or dispose of fossil fuel combustion materials, including types of coal ash. If so, we may be required to change the current waste management practices at some facilities and incur additional costs for increased waste management requirements.
Additionally, the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (“CERCLA” or “Superfund”) establishes a framework for dealing with the cleanup of contaminated sites. Many states have enacted similar state superfund statutes as well as other laws imposing obligations to investigate and clean up contamination. Areas of soil and groundwater contamination are known to exist at our Pittsburg, Contra Costa and Potrero facilities. Prior to our acquisition of those facilities from PG&E in 1998, PG&E conducted soil and groundwater investigations at those facilities which revealed significant contamination. The consultants conducting the investigation estimated the aggregate cleanup costs at those facilities could be as much as $60 million. Pursuant to the terms of the Purchase and Sale Agreement with PG&E, PG&E has responsibility for the containment or capping of all soil and groundwater contamination at the Potrero generating facility and the disposition of up to 60,000 cubic yards of contaminated soil at the Potrero generating facility and to remediate any groundwater or solid contamination identified by PG&E at the Pittsburg and Contra Costa generating facilities. To date, we have requested that PG&E dispose of 807 cubic yards of contaminated soil at the Potrero generating facility and they have performed such disposal. We are not aware of soil or groundwater conditions that are not covered by third party agreements or insurance policies for which we expect our remediation costs to be material.
Employees
At December 31, 2005, we employed through contracts with Mirant Services, LLC (“Mirant Services”), a direct subsidiary of Mirant, approximately 1,290 people, of whom approximately 1,180 were employed at our power plants. Approximately 74% of the employees at our power plants were represented by the following unions:
· Utility Worker’s Union of America, A.F.L.-C.I.O., Local #369 in Cambridge, Massachusetts. The current collective bargaining agreement expires on February 28, 2009.
· Utility Worker’s Union of America, A.F.L.-C.I.O., Local #480 in Sandwich, Massachusetts. The current collective bargaining agreement expires on May 31, 2006.
· Local Union 503, International Brotherhood of Electrical Workers (“I.B.E.W.”) in New York. The current collective bargaining agreement expires on June 1, 2008.
· Local Union 1900, I.B.E.W. in Maryland and Virginia. The current collective bargaining agreement expires on June 1, 2010.
· Local Union 1245, I.B.E.W. in California. The current collective bargaining agreement expires on October 31, 2008.
· United Steel Workers Local 12502 in Michigan. The current collective bargaining agreement expires on January 1, 2007.
When we enter into and conduct labor negotiations, we engage in contingency planning to mitigate and reduce the risk of disruption, and ensure continuation of our generation activities to the maximum extent possible in the event of an adverse collective action by the union with whom we are negotiating.
Item 1A.
Item 1A. Risk Factors
The following are factors that could affect our future performance:
Our revenues are unpredictable because many of our facilities operate without long-term power purchase 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 many of our generating facilities into competitive power markets or on a short-term fixed price basis through power sales agreements. 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 impact of market regulation. 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, limiting 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:
· the failure of market regulators to develop efficient mechanisms to compensate merchant generators for the value of providing capacity needed to meet demand;
· actions by regulators, ISOs, RTOs and other bodies that may prevent capacity and energy prices from rising to the level sufficient for recovery of our costs, our investment and an adequate return on our investment;
· the ability of wholesale purchasers of power to make timely payment for energy or capacity, which may be adversely impacted by factors such as retail rate caps, refusal by regulators to allow utilities to fully recover their wholesale power costs and investments through rates, catastrophic losses, and losses from investments in unregulated businesses;
· the fact that increases in prevailing market prices for fuel oil, coal, natural gas and emissions allowances may not be reflected in increased prices we receive for sales of energy;
· increases in supplies due to actions of our current competitors or new market entrants, including the development of new generating facilities 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;
· the competitive advantages of certain competitors including continued operation of older power plants in strategic locations after recovery of historic capital costs from ratepayers;
· existing or future regulation of our markets by the FERC, ISOs and RTOs, including any price limitations and other mechanisms to address some of the price volatility or illiquidity in these markets or the physical stability of the system;
· regulatory policies of state agencies which affect the willingness of our customers to enter into long-term contracts generally, and contracts for capacity in particular;
· weather conditions that depress demand or increase the supply of hydro power; and
· changes in the rate of growth in electricity usage as a result of such factors as 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 impact our financial results by increasing the cost of producing power or lowering the price at which we are able to sell our power, and we may be unsuccessful at managing this risk.
Our generation business is subject to changes in power prices and fuel costs, which may impact our financial results and financial position by increasing the cost of producing power and decreasing the amounts we receive from the sale of power. In addition, actual power prices and fuel costs may differ from our expectations.
Mirant Energy Trading engages in asset hedging activities related to sales of electricity and purchases of fuel. The income and losses from these activities are recorded as generation revenues and fuel costs. Mirant Energy Trading may use forward contracts and derivative financial instruments to manage market risk and exposure to volatility in electricity, coal, natural gas, emissions and oil prices. 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 and fuel markets.
Many factors influence commodity prices, including weather, market liquidity, transmission and transportation inefficiencies, availability of competitively priced alternative energy sources, demand for energy commodities, natural gas, crude oil and coal production, natural disasters, wars, embargoes and other catastrophic events, and federal and state environmental regulation and legislation.
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 impact 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. As a result of these and other factors, we cannot predict the impact that risk management decisions may have on our business, 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 natural gas, coal and oil fuel supply.
Although we attempt to purchase fuel based on our known 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.
Some of our generation facilities depend on only one or a few customers or suppliers. These parties, as well as other parties with whom we have contracts, may fail to perform their obligations, or may terminate their existing agreements, which may result in a default on project debt or a loss in revenues and may require us to institute legal proceedings to enforce the relevant agreements.
Several of our power production facilities depend on a single customer or a few customers to purchase most or all of the facility’s output or on a single supplier or a few suppliers to provide fuel, water and other services required for the operation of the facility. The sale and procurement agreements for these facilities may also provide support for any project debt used to finance the related facilities. The failure of any supplier or customer to fulfill its contractual obligations to the facility could have a material adverse effect on such facility’s financial results. The financial performance of these facilities is dependent on the continued performance by customers and suppliers of their obligations under their long-term agreements.
Revenue received by our subsidiaries may be reduced upon the expiration or termination of existing power sales agreements. Some of the electricity we generate from our existing portfolio is sold under long-term power sales agreements that expire at various times. When the terms of each of these power sales agreements expire, it is possible that the price paid to us for the generation of electricity may be reduced significantly, which would substantially reduce our revenue.
Operation of our generation facilities involves risks that may have a material adverse impact on our cash flows and results of operations.
The operation of our generation facilities involves various operating risks, including, but not limited to:
· the output and efficiency levels at which those generation facilities perform;
· interruptions in fuel supply;
· disruptions in the delivery of electricity;
· adverse zoning;
· breakdowns or equipment failures (whether due to age or otherwise);
· restrictions on emissions;
· violations of our permit requirements or changes in the terms of or revocation of permits;
· releases of pollutants and hazardous substances to air, soil, surface water or groundwater;
· shortages of equipment or spare parts;
· labor disputes;
· operator errors;
· curtailment of operations due to transmission constraints;
· failures in the electricity transmission system which may cause large energy blackouts;
· implementation of unproven technologies in connection with environmental improvements; and
· catastrophic events such as fires, explosions, floods, earthquakes, hurricanes or other similar occurrences.
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 impact our cash flows and results of operations, including cash flows available to us to make payments on our debt or our other obligations.
For example on December 16, 2005, one of the generating units at our Chalk Point facility experienced a forced outage as a result of a structural failure in one of its retired-in-place precipitators. The failure caused damage to associated ductwork. The Chalk Point facility resumed normal operations on January 17, 2006.
On September 18, 2005, Unit No. 1 at the Morgantown facility experienced a forced outage in response to high turbine vibration resulting from the failure of one low pressure turbine blade. This failure required the unit to be shut down. The unit returned to service on November 18, 2005.
The accounting for our asset hedging and proprietary trading activities may increase the volatility of our quarterly and annual financial results.
We engage in asset management activities in order to economically hedge our exposure to market risk with respect to (1) electricity sales from our generation facilities, (2) fuel utilized by those facilities and (3) emissions allowances. We generally attempt to balance our fixed-price physical and financial 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 activities, through which we attempt to achieve incremental returns by transacting where we have specific market expertise. Some of the derivatives from our asset hedging and proprietary trading activities are recorded on our balance sheet at fair value pursuant to Statement of Financial Accounting Standards Board (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (“SFAS No. 133”). None of our derivatives recorded at fair market value are designated as hedges under SFAS No. 133 and changes in their fair value 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 electricity and fuel prices. For example, for the year ended December 31, 2005, we were required to mark-to-market contracts resulting in a $21 million charge as compared to the year ended December 31, 2004, when we were required to mark-to-market contracts resulting in a $167 million gain. For a more detailed discussion of the accounting treatment of our asset hedging and proprietary trading activities, see Note 7 to our combined and consolidated financial statements, included herein.
Our 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 corresponding energy and fuel prices; and
· variations in levels of production.
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 generation facilities without relying exclusively on market clearing prices to recover their investments. The competitive advantages of such participants could adversely impact 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 regulation by federal, state and local authorities, which, among other things, restricts the discharge of pollutants into the air, water and soil, and also governs 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. In addition, we may be required to shut down facilities if we are unable to comply with the requirements, such as with CO2 regulations for which there currently is not a technical compliance solution, or if we determine the expenditures required to comply are uneconomic. For example, we currently intend to retire our Lovett generation facility in New York, in part because of substantial environmental capital expenditure requirements, starting with Unit 5 in 2007 and Units 3 and 4 in 2008. We are pursuing alternatives that would make it economically feasible for this generation facility to remain in operation, but there can be no assurances that we will be successful. Furthermore, we had planned to shut down, at least temporarily, the Kendall facility from January 2006 through December 2007, with the possibility of restarting operations in January 2008. However, the ISO-NE determined that a small part of the capacity of the Kendall facility is needed for reliability and negotiated an RMR arrangement for the facility. We may mothball the Kendall facility following the expiration of the RMR arrangement if it is not economically feasible to continue to operate the facility.
In addition, environmental laws, particularly with respect to air emissions, wastewater discharge and cooling water intake structures, are generally becoming more stringent, which may require us to make expensive facility upgrades or restrict our operations to meet more stringent standards. 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 may change, or additional information concerning the way in which such requirements apply to us may be identified. For example, in November 2005, Maryland’s governor announced that he intends to propose a Maryland Clean Power Rule that would require deep reductions in NOx emissions by 2009 and in SO2 and mercury emissions by 2010 at six Maryland coal fired power facilities, including our Chalk Point, Dickerson and Morgantown facilities. If the rulemaking proceeds according to the timing indicated by the Governor’s office, that rule would become law in the summer of
2006. Although we have not fully evaluated the impacts of the Governor’s proposed rule as announced, if adopted as proposed, it would require us to increase substantially our capital expenditure requirements from 2006 through 2010 in a way that could materially and adversely affect us. We may not be able to recover incremental capital costs of compliance with new environmental regulations, which may adversely affect our financial performance and condition.
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 any environmental regulatory approvals or if onerous conditions are imposed, the operation of our generation 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.
Certain environmental laws, including CERCLA and comparable state laws, impose strict and, in many circumstances, joint and several liability for costs of 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 generation 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 generation facilities, at disposal sites we currently utilize or have formerly utilized, 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.
The expected decommissioning and/or site remediation obligations of certain of our generation facilities may negatively impact our cash flows.
We expect that certain of our generation facilities and related properties will become subject to decommissioning and/or site remediation obligations that may require material expenditures. The exact amount and timing of such expenditures, if any, 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 impact our cash flows and may adversely impact our ability to make payments on our obligations.
Our level of 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 our obligations.
As of December 31, 2005, our total indebtedness was approximately $2.6 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 substantial degree of 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 other indebtedness could make it more difficult for us to satisfy our financial obligations; (4) certain of our borrowings, including borrowings under Mirant North America’s 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.
We are a holding company and may not have access to sufficient cash to meet our obligations.
Our operations may not generate sufficient cash to enable us to make principal and interest payments on our indebtedness. In addition, payments to us by our subsidiaries will be contingent upon our subsidiaries’ earnings. Our subsidiaries are permitted under the terms of our indebtedness to incur additional indebtedness that may restrict payments from those subsidiaries to us. We cannot assure you that agreements governing current and future indebtedness of our subsidiaries will permit those subsidiaries to provide us with sufficient cash to fund our obligations.
The Company has no operations and no subsidiaries with operations other than Mirant North America and the subsidiaries that it owns, including Mirant Mid-Atlantic. We have no source of revenue to pay interest or principal on our debt other than money received from distributions. Mirant North America, Mirant Mid-Atlantic and our other subsidiaries are separate and distinct legal entities and they have no obligation, contingent or otherwise, to pay our obligations or to make any funds available to pay those obligations, whether by dividend, distribution, loan or other payment.
Our obligations are effectively subordinated to the obligations or indebtedness of any of our subsidiaries. As of March 3, 2006, Mirant North America had approximately $1.6 billion of indebtedness outstanding under its notes and credit facility. The notes and senior secured credit facilities permit Mirant North America, subject to certain limitations and the condition that there is no default or event of default, to make distributions to us to fund our debt service. A significant portion of our cash from operations is generated by Mirant Mid-Atlantic. Under the Mirant Mid-Atlantic leveraged leases, Mirant Mid-Atlantic is subject to a covenant that does not permit them to make distributions to us unless (1) certain fixed charge coverage ratio and projected fixed charge coverage ratio tests are met and (2) at the time of and after giving effect to such distribution, no significant lease default or lease event of default has occurred and is continuing.
We may be unable to generate sufficient liquidity to service our debt and to post required amounts of cash collateral necessary to effectively hedge market risks.
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 generation facilities and in the prices of fuel, emissions allowances and other inputs required to produce such power by entering into hedging transactions. These asset hedging activities generally require us to post a significant amount of collateral either in the form of cash or letters of credit. As of December 31, 2005, we had approximately $685 million of posted cash collateral and $56 million of letters of credit outstanding primarily to support our asset hedging activities and debt service reserve requirements. 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.
In our efforts to hedge commodity price risk, 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 impact our financial condition and results of operations.
Generally, 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 the generation facilities. The majority of our generation is sold at market prices under the 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 generation 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 assets 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 impact our ability to sell and the price we receive for our energy and capacity.
Changes in the markets in which we compete may have an adverse impact on the results of our operations. For example, in the fall of 2004, PJM completed its integration of AEP, Duquesne Light and DP&L into PJM. Under PJM rules, AEP, Duquesne Light and DP&L were then deemed by PJM to be capable of providing capacity to all areas of PJM. This has depressed the prices that can be charged for capacity in PJM.
Certain of our assets are located in the ERCOT market. Such assets are not generally subject to regulation by the FERC, but are subject to similar types of regulation by the PUCT.
To conduct our business, we must obtain 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 generation technologies, which will subsidize our competitors. Many regulations that could be issued pursuant to the EPAct 2005 may have an adverse impact on our business.
In 2003, the Northeastern United States and parts of Canada suffered a massive blackout allegedly stemming from transmission problems originating in Ohio. In part as a result of this, the EPAct 2005 requires the FERC to select an industry self-regulatory organization which will impose mandatory reliability rules and standards. We cannot predict the impact of this on us.
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 supply of electricity, at both the wholesale and retail level. In addition, any future legislation favoring large, vertically integrated utilities and a concentration of ownership of such utilities could impact our ability to compete successfully, and our business and results of operations could suffer. 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 impact our generation business by making our generation facilities less competitive.
A basic premise of our generation business is that generating power at central facilities achieves economies of scale and produces electricity at a low price. There are other technologies that can produce electricity, most notably fuel cells, microturbines, windmills and photovoltaic solar cells. It is possible that advances in technology will reduce the cost of alternative methods of electricity production to levels that are equal to or below that of most central station electric production, which could have a material impact on our results of operations.
Terrorist attacks, future war or risk of war may adversely impact 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 generation 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 impacted. In addition, such an attack could impact 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 generation industry. We may not have adequate insurance to cover all of these hazards.
Our operations are subject to many hazards associated with the power generation 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 personal injury 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 hurt our financial results and materially harm our financial condition.
The subsidiaries that own our generation facilities in New York, including our Lovett and Bowline facilities, have not emerged from Chapter 11.
Our Lovett and Bowline generation facilities in New York are subject to disputes with local tax authorities regarding property tax assessments and with the New York State Department of Environmental Conservation (the “NYSDEC”) regarding environmental controls. We are also in discussions with the NYISO and utilities regarding an agreement that would compensate Mirant Lovett for its contribution to the reliability of the New York electric power system. The facilities are forecasted to have negative operating cash flows at their current tax valuations. Until a settlement is reached on property taxes, environmental controls and reliability that would permit economically feasible operation, our subsidiaries that own the facilities, Mirant Lovett and Mirant Bowline, LLC (“Mirant Bowline”), will remain in Chapter 11. The Lovett and Bowline facilities are currently in negotiations on all of these issues. Although negotiations are continuing, resolutions may not be reached in the near future or not at all. Until resolutions are reached and the companies emerge from bankruptcy, we will not have access to the cash from operations generated from these subsidiaries.
Mirant NY-Gen, which includes hydroelectric facilities at Swinging Bridge, Rio and Mongaup, and small combustion turbine facilities at Hillburn and Shoemaker, is insolvent. Its expenses are being funded under a debtor-in-possession facility made by Mirant Americas, Inc. (“Mirant Americas”), with the approval of, and under the supervision of, the Bankruptcy Court. Mirant NY-Gen is currently discussing with the FERC appropriate remediation for a sinkhole discovered in May 2005 in the dam at the Swinging Bridge facility. We also conducted a flood study to determine downstream consequences if the maximum capacities of the reservoirs were exceeded at our New York Swinging Bridge, Rio and Mongaup generation facilities, which may cause the FERC to request that Mirant NY-Gen remediate those dams as well. Mirant NY-Gen has initiated discussions with the FERC for surrendering its permits to operate all the hydroelectric facilities at Swinging Bridge, Rio and Mongaup, and expects to begin that formal process soon. It is not possible at this point to determine the cost of remediating the dam and surrendering the permits, but such costs may be substantial.
We may be subject to claims that were not discharged in the bankruptcy cases, which could have a material adverse effect on our results of operations and profitability.
The nature of our business frequently subjects us to litigation. Substantially all of the material claims against us that arose prior to the date of the bankruptcy filing were resolved during our Chapter 11 proceedings. In addition, the Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation and certain debts arising afterwards. With few exceptions, all claims that arose prior to our bankruptcy filing and before confirmation of the Plan are (1) subject to compromise and/or treatment under the Plan or (2) discharged, in accordance with the Bankruptcy Code and terms of the Plan. Circumstances in which claims and other obligations that arose prior to our bankruptcy filing were not discharged primarily relate to certain actions by governmental units under police power authority, where we have agreed to preserve a claimant’s claims, as well as, potentially, instances where a claimant had inadequate notice of the bankruptcy filing. The ultimate resolution of such claims and other obligations may have a material adverse effect on our results of operations and profitability.
We cannot be certain that the bankruptcy proceeding will not adversely affect our operations going forward.
Although we emerged from bankruptcy upon consummation of the Plan, we cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations going forward, including our ability to negotiate favorable terms from suppliers, hedging counterparties and others and to attract and retain customers. The failure to obtain such favorable terms and retain customers could adversely affect our financial performance.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Properties
The following properties were owned or leased as of December 31, 2005:
(1) MW amounts reflect net dependable capacity.
(2) Capacity factor is the average percentage of full capacity used over a year.
(3) Total MW reflects a 1.4% ownership interest, or 8.8 MW, in the 614 MW Wyman plant.
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
Chapter 11 Proceedings
On the Petition Date, and various dates thereafter, the Mirant Debtors filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. On August 21, 2003, and September 8, 2003, the Bankruptcy Court entered orders establishing a December 16, 2003, bar date (the “Bar Date”) for filing proofs of claim against the Mirant Debtors’ estates.
Most of the material claims filed against the Mirant Debtors’ estates were disallowed or were resolved and became “allowed” claims before confirmation of the Plan. For example, the claims filed by the California Attorney General, PG&E, various other California parties, plaintiffs in certain rate payer class action lawsuits, the plaintiffs in certain bondholder litigation, and Utility Choice, L.P., which are described in our 2004 Form 10-K, are among the claims that were resolved prior to confirmation of the Plan. A number of claims, however, remain unresolved.
Except for claims and other obligations not subject to discharge under the Plan and unless otherwise provided below, all claims against the Mirant Debtors’ estates representing obligations that arose prior to July 14, 2003, are subject to compromise under the Plan. This means that the claimant will receive a distribution of Mirant common stock, cash or both common stock and cash in accordance with the terms of the Plan in satisfaction of the claim. As a result, the exact amount of the claim may still be litigated, but we will not be required to make any payment in respect of such litigation until a resolution is obtained, through settlement, judgment or otherwise.
As of December 31, 2005, approximately 23.5 million of the shares of Mirant common stock to be distributed under the Plan to creditors have been reserved for distribution with respect to claims that are disputed by the Mirant Debtors and have not been resolved. Under the terms of the Plan, to the extent such claims are resolved now that we have emerged from bankruptcy, the claimants will be paid from the reserve of 23.5 million shares on the same basis as if they had been paid out when the Plan became effective. That means that their allowed claims will receive the same pro rata distributions of Mirant common stock, cash or both common stock and cash as previously allowed claims in accordance with the terms of the Plan. It is our view that we have funded the disputed claims reserve at a sufficient level to settle the remaining unresolved proofs of claim we received during the bankruptcy proceedings and any claims resulting from Mirant’s rejection of certain contracts with PEPCO, as described below in PEPCO Litigation. However, to the extent the aggregate amount of the payouts determined to be due with respect to such 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 shareholders, and we would have to pay additional cash amounts as necessary under the terms of the Plan to satisfy such pre-petition claims. We will continue to monitor our obligations as the disputed claims are resolved.
Our Lovett and Bowline generation facilities in New York are subject to disputes with local tax authorities regarding property tax assessments and with the NYSDEC regarding environmental controls. Mirant Lovett is also in discussions with the NYISO and utilities regarding an agreement that would compensate Mirant Lovett for the contribution of the Lovett facility to the reliability of the New York electric power system. The facilities are forecasted to have negative operating cash flows at their current tax valuations. Until a settlement is reached on property taxes, environmental controls and reliability, that would permit economically feasible operation, our subsidiaries that own the facilities, Mirant Lovett and Mirant Bowline, will remain in Chapter 11. Mirant Lovett and Mirant Bowline are currently in settlement discussions on all of these issues. Although negotiations are continuing, settlements may not be reached in the near future, or at all. Until such settlements are reached and the companies emerge from bankruptcy, we will not have access to the cash from operations generated from these subsidiaries. Mirant NY-Gen, which owns hydroelectric facilities at Swinging Bridge, Rio and Mongaup, and small combustion turbine facilities at Hillburn and Shoemaker, is insolvent. Its expenses are being funded under a debtor-in-possession
facility made by Mirant Americas with the approval of, and under the supervision of, the Bankruptcy Court. Mirant NY-Gen is currently discussing with the FERC appropriate remediation for a sinkhole discovered in May 2005 in the dam at the Swinging Bridge facility. We conducted a flood study to determine downstream consequences if the maximum capacities of the reservoirs were exceeded at our New York Swinging Bridge, Rio and Mongaup generation facilities, and Mirant NY-Gen could be requested by the FERC to remediate those dams as well. Mirant NY-Gen has initiated discussions with the FERC for surrendering its permits to operate all the hydroelectric facilities at Swinging Bridge, Rio and Mongaup, and expects to begin that formal process soon. It is not possible at this point to determine the cost of remediating the dam at Swinging Bridge and surrendering the permits, but such costs may be substantial.
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 Asset Purchase and Sale Agreement (“APSA”), Mirant and PEPCO entered into the Back-to-Back Agreement with respect to certain PPAs, including PEPCO’s long-term PPAs with Ohio Edison and Panda-Brandywine L.P. (“Panda”), 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 Ohio Edison PPA terminated in December 2005 and the Panda PPA runs until 2021. Under the Back-to-Back Agreement, Mirant is obligated to purchase power from PEPCO at prices that are typically 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 includes as parties PEPCO and various subsidiaries of ours causes our subsidiaries that are 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 have sought to reject the APSA, the Back-to-Back Agreement, and the Assignment and Assumption Agreement, and the rejection motions have not been resolved. 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 the final court order to be part of the APSA), the Back-to-Back Agreement, and the Assignment and Assumption Agreement are to be performed by Mirant Power Purchase, LLC (“Mirant Power Purchase”), whose performance is guaranteed by Mirant. If any of the agreements is successfully rejected, the obligations of Mirant Power Purchase and Mirant’s guarantee obligations terminate with respect to that agreement, and PEPCO would be entitled to a claim in the Chapter 11 proceedings for any resulting damages. That claim would then be addressed under the terms of the Plan. If the Bankruptcy Court were to conclude that the Assignment and Assumption Agreement imposed liability upon our subsidiaries for the obligations under the Back-to-Back Agreement and the Back-to-Back Agreement were to be rejected, the resulting rejection damages claim could result in a claim in the Chapter 11 proceedings against our subsidiaries but any such claim would be reduced by the amount recovered by PEPCO on its comparable claim against Mirant.
California and Western Power Markets
California Rate Payer Litigation. Certain of our subsidiaries are subject to litigation related to their activities in California and the western power markets and the high prices for wholesale electricity experienced in the western markets during 2000 and 2001. Various lawsuits were filed in 2000 through 2003 that asserted claims under California law based on allegations that certain owners of electricity generation facilities in California and energy marketers, including the Company, Mirant Americas Energy
Marketing and our subsidiaries owning generating facilities in California, engaged in various unlawful and anti-competitive acts that served to manipulate wholesale power markets and inflate wholesale electricity prices in California. All of these suits have been dismissed by final orders except for six such suits that were filed between November 27, 2000, and May 2, 2001, in various California Superior Courts and consolidated before the Superior Court for the County of San Diego for pretrial purposes. Although the plaintiffs dismissed Mirant from those suits, they have not filed to dismiss certain of our subsidiaries that are also defendants. On October 3, 2005, the California state court dismissed those six consolidated suits on the grounds that the plaintiffs’ claims were barred by federal preemption as a result of the Federal Power Act. On December 5, 2005, the plaintiffs filed an appeal of the dismissal. The plaintiffs in the six consolidated suits did not file claims in the bankruptcy proceedings, and we expect that their claims are barred by the Plan now that it has become effective.
Bondholder Litigation
Mirant Americas Generation Bondholder Suit. On June 10, 2003, certain holders of senior notes of Mirant Americas Generation maturing after 2006 filed a complaint in the Court of Chancery of the State of Delaware, California Public Employees’ Retirement System, et al. v. Mirant Corporation, et al., that named as defendants Mirant, Mirant Americas, Mirant Americas Generation, certain past and present Mirant directors, and certain past and present Mirant Americas Generation managers. Among other claims, the plaintiffs assert that a restructuring plan pursued by the Company prior to its filing a petition for reorganization under Chapter 11 of the Bankruptcy Code was in breach of fiduciary duties allegedly owed to them by Mirant, Mirant Americas and Mirant Americas Generation’s managers. In addition, the plaintiffs challenge certain dividends and distributions made by Mirant Americas Generation prior to the Petition Date. The plaintiffs seek damages in excess of $1 billion. Mirant has removed this suit to the United States District Court for the District of Delaware. This action was stayed with respect to the Mirant entities that are defendants by the filing of the Chapter 11 proceedings of these entities. The order entered by the Bankruptcy Court confirming the Plan enjoins the prosecution of this action and requires that it be dismissed. On March 8, 2006, the Bankruptcy Court entered an order compelling the plaintiffs in this action to dismiss their complaint in accordance with the terms of the Plan. On March 17, 2006, the parties filed a stipulation of dismissal dismissing the suit.
U.S. Government Inquiries
Department of Justice Inquiries. In November 2002, Mirant received a subpoena from the DOJ, acting through the United States Attorney’s office for the Northern District of California, requesting information about its activities and those of its subsidiaries for the period since January 1, 1998. The subpoena requested information related to the California energy markets and other topics, including the reporting of inaccurate information to the trade press that publish natural gas or electricity spot price data. The subpoena was issued as part of a grand jury investigation. The DOJ’s investigation of the reporting of inaccurate natural gas price information is continuing, and Mirant has held preliminary discussions with DOJ regarding the disposition of this matter. The DOJ’s investigation is based upon the same circumstances that were the subject of an investigation by the Commodity Futures Trading Commission (“CFTC”) that was settled in December 2004. As described in Mirant’s Annual Report on Form 10-K for the year ended December 31, 2004, in Legal Proceeding- Other Governmental Proceedings-CFTC Inquiry, Mirant and Mirant Americas Energy Marketing pursuant to the settlement consented to the entry of an order by the CFTC in which it made findings, which are neither admitted nor denied by Mirant and Mirant Americas Energy Marketing, that (1) from January 2000 through December 2001, certain Mirant Americas Energy Marketing natural gas traders (a) knowingly reported inaccurate price, volume, and/or counterparty information regarding natural gas cash transactions to publishers of natural gas indices and (b) inaccurately reported to index publishers transactions observed in the market as Mirant Americas Energy Marketing transactions and (2) from January to October 2000, certain Mirant Americas Energy
Marketing west region traders knowingly delivered the false reports in an attempt to manipulate the price of natural gas. Under the settlement, the CFTC received a subordinated allowed, unsecured claim against Mirant Americas Energy Marketing of $12.5 million in the Chapter 11 proceedings. The DOJ could decide that further action against Mirant and Mirant Americas Energy Marketing is not appropriate or could seek indictments against one or more Mirant entities, or the DOJ and Mirant could agree to a disposition that might involve undertakings or fines, the amount of which cannot be reasonably estimated at this time but which could be material. Mirant has cooperated fully with the DOJ and intends to continue to do so. At this time, it is our view that any action taken by the DOJ against Mirant or its subsidiaries related to the reporting of natural gas price information would not involve us or our subsidiaries except to the extent that any disposition of this matter results in ongoing undertakings by Mirant Energy Trading as the recipient of the assets of Mirant Americas Energy Marketing under the Plan.
Environmental Matters
EPA Information Request. In January 2001, the EPA issued a request for information to Mirant concerning the air permitting and air emissions control implications under the NSR of past repair and maintenance activities at the Potomac River plant in Virginia and the Chalk Point, Dickerson and Morgantown plants in Maryland. The requested information concerns the period of operations that predates the Company subsidiaries’ ownership and lease of those plants. Mirant has responded fully to this request. Under the APSA, PEPCO is responsible for fines and penalties arising from any violation associated with historical operations prior to the Company subsidiaries’ acquisition or lease of the plants. If the Mirant Debtors succeed in rejecting the APSA as described above in PEPCO Litigation, PEPCO may assert that it has no obligation to reimburse Mirant for any fines or penalties imposed upon Mirant for periods prior to the Company subsidiaries’ acquisition or lease of the plants. If a violation is determined to have occurred at any of the plants, the Company subsidiary owning or leasing the plant may be responsible for the cost of purchasing and installing emissions control equipment, the cost of which may be material. If such violation is determined to have occurred after the Company’s subsidiaries acquired or leased the plants or, if occurring prior to the acquisition or lease, is determined to constitute a continuing violation, the Company subsidiary owning or leasing the plant at issue would also be subject to fines and penalties by the state or federal government for the period subsequent to its acquisition or lease of the plant, the cost of which may be material.
Mirant Potomac River Notice of Violation. On September 10, 2003, the Virginia DEQ issued an NOV to Mirant Potomac River alleging that it violated its Virginia Stationary Source Permit to Operate by emitting NOx in excess of the “cap” established by the permit for the 2003 summer ozone season. Mirant Potomac River responded to the NOV, asserting that the cap is unenforceable, noting that it can comply through the purchase of emissions allowances and raising other equitable defenses. Virginia’s civil enforcement statute provides for injunctive relief and penalties. On January 22, 2004, the EPA issued an NOV to Mirant Potomac River alleging the same violation of its Virginia Stationary Source Permit to Operate as set out in the NOV issued by the Virginia DEQ.
On September 27, 2004, Mirant Potomac River, Mirant Mid-Atlantic, the Virginia DEQ, the Maryland Department of the Environment, the DOJ and the EPA entered into, and filed for approval with the United States District Court for the Eastern District of Virginia, a consent decree that, if approved, will resolve Mirant Potomac River’s potential liability for matters addressed in the NOVs previously issued by the Virginia DEQ and the EPA. The consent decree requires Mirant Potomac River and Mirant Mid-Atlantic to (1) install pollution control equipment at the Potomac River plant and at the Morgantown plant leased by Mirant Mid-Atlantic in Maryland, (2) comply with declining system-wide ozone season NOx emissions caps from 2004 through 2010, (3) comply with system-wide annual NOx emissions caps starting in 2004, (4) meet seasonal system average emissions rate targets in 2008 and (5) pay civil penalties and perform supplemental environmental projects in and around the Potomac River plant expected to
achieve additional environmental benefits. Except for the installation of the controls planned for the Potomac River units and the installation of SCR or equivalent technology at Mirant Mid-Atlantic’s Morgantown Units 1 and 2 in 2007 and 2008, the consent decree does not obligate the Company’s subsidiaries to install specifically designated technology, but rather to reduce emissions sufficiently to meet the various NOx caps. Moreover, as to the required installations of SCRs at Morgantown, Mirant Mid-Atlantic may choose not to install the technology by the applicable deadlines and leave the units off either permanently or until such time as the SCRs are installed. The consent decree is subject to the approval of the district court and the Bankruptcy Court.
The owners/lessors under the lease-financing transactions covering the Morgantown and Dickerson plants (the “Owners/Lessors”) objected to the proposed consent decree in the Bankruptcy Court and filed a motion to intervene in the district court action. As part of a resolution of disputed matters in the Chapter 11 proceedings, the Owners/Lessors have now agreed not to object to the consent decree, subject to certain terms set forth in the Plan and Confirmation Order.
On July 22, 2005, the district court granted a motion filed by the City of Alexandria seeking to intervene in the district court action, although the district court imposed certain limitations on the City of Alexandria’s participation in the proceedings. On September 23, 2005, the City of Alexandria filed a motion seeking authority to file an amended complaint in the action seeking injunctive relief and civil penalties under the Clean Air Act for alleged violations by Mirant Potomac River of its Virginia Stationary Source Permit To Operate and the State of Virginia’s State Implementation Plan. Based upon a computer modeling, the City of Alexandria asserted that emissions from the Potomac River plant exceed NAAQS for SO2, nitrogen dioxide (“NO2”), and particulate matter. The City of Alexandria also contended based on its modeling analysis that the plant’s emissions of hydrogen chloride and hydrogen fluoride exceed Virginia state emissions standards. Mirant Potomac River disputes the City of Alexandria’s allegations that it has violated the Clean Air Act and Virginia law. On December 2, 2005, the district court denied the City of Alexandria’s motion seeking to file an amended complaint.
Mirant Potomac River Downwash Study. On September 23, 2004, the Virginia DEQ and Mirant Potomac River entered into an order by consent with respect to the Potomac River plant under which Mirant Potomac River agreed to perform a modeling analysis to assess the potential effect of “downwash” from the plant (1) on ambient concentrations of SO2, NO2, carbon monoxide (“CO”) and particulate matter less than or equal to 10 micrometers (“PM10”) for comparison to the applicable NAAQS and (2) on ambient concentrations of mercury for comparison to Virginia Standards of Performance for Toxic Pollutants. Downwash is the effect that occurs when aerodynamic turbulence induced by nearby structures causes emissions from an elevated source, such as a smokestack, to be mixed rapidly toward the ground resulting in higher ground level concentrations of emissions. If the modeling analysis indicates that emissions from the facility may cause exceedances of the NAAQS for SO2, NO2, CO or PM10, or exceedances of mercury compared to Virginia Standards of Performance for Toxic Pollutants, the consent order requires Mirant Potomac River to submit to the Virginia DEQ a plan and schedule to eliminate and prevent such exceedances on a timely basis. Upon approval by the Virginia DEQ of the plan and schedule, the approved plan and schedule is to be incorporated by reference into the consent order. The results of the computer modeling analysis showed that emissions from the Potomac River plant have the potential to contribute to localized, modeled instances of exceedances of the NAAQS for SO2, NO2 and PM10 under certain conditions.
On August 24, 2005, power production at all five units of the Potomac River generating facility was temporarily halted in response to a directive from the Virginia DEQ. The decision to temporarily shut down the facility arose from findings of a study commissioned under the order by consent referred to above. The Virginia DEQ’s directive was based on results from the study’s computer modeling showing that air emissions from the facility have the potential to contribute to localized, modeled exceedances of the health-based NAAQS under certain conditions. On August 25, 2005, the District of Columbia Public
Service Commission filed an emergency petition and complaint with the FERC and the DOE to prevent the shutdown of the Potomac River facility. The matter remains pending before the FERC and the DOE. On September 21, 2005, Mirant Potomac River commenced partial operation of one unit of the plant. On December 20, 2005, due to a determination by the DOE that an emergency situation exists with respect to a shortage of electric energy, the DOE ordered Mirant Potomac River to generate electricity at the Potomac River generation facility, as requested by PJM, during any period in which one or both of the transmission lines serving the central Washington, D.C. area are out of service due to a planned or unplanned outage. In addition, the DOE ordered Mirant Potomac River, at all other times, for electric reliability purposes, to keep as many units in operation as possible and to reduce the start-up time of units not in operation. The DOE required Mirant Potomac River to submit a plan, on or before December 30, 2005, that met this requirement and did not significantly contribute to NAAQS exceedances. The DOE advised that it would consider Mirant Potomac River’s plan in consultation with the EPA. The order further provides that Mirant Potomac River and its customers should agree to mutually satisfactory terms for any costs incurred by it under this order or just and reasonable terms shall be established by a supplemental order. Certain parties filed for rehearing of the DOE order, and on February 17, 2006, the DOE issued an order granting rehearing solely for purposes of considering the rehearing requests further. Mirant Potomac River submitted an operating plan in accordance with the order. On January 4, 2006, the DOE issued an interim response to Mirant Potomac River’s operating plan authorizing immediate operation of one baseload unit and two cycling units, making it possible to bring the entire plant into service within approximately 28 hours. The DOE’s order expires after September 30, 2006, but we expect we will be able to continue to operate these units after that expiration. In a letter received December 30, 2005, the EPA invited Mirant Potomac River and the Virginia DEQ to work with the EPA to ensure that Mirant Potomac River’s operating plan submitted to the DOE adequately addresses NAAQS issues. The EPA also asserts in its letter that Mirant Potomac River did not immediately undertake action as directed by the Virginia DEQ’s August 19, 2005, letter and failed to comply with the requirements of the Virginia State Implementation Plan established by that letter. Mirant Potomac River received a second letter from the EPA on December 30, 2005, requiring Mirant to provide certain requested information as part of an EPA investigation to determine the Clean Air Act compliance status of the Potomac River facility. The facility will not resume normal operations until it can satisfy the requirements of the Virginia DEQ and the EPA with respect to NAAQS, unless, for reliability purposes, it is required to return to operation by a governmental agency having jurisdiction to order its operation. On January 9, 2006, the FERC issued an order directing PJM and PEPCO to file a long-term plan to maintain adequate reliability in the Washington D.C. area and surrounding region and a plan to provide adequate reliability pending implementation of this long-term plan. On February 8, 2006, PJM and PEPCO filed their proposed reliability plans. We are working with the relevant state and federal agencies with the goal of restoring all five units of the facility to normal operation in 2007. The financial and operational implications of the discontinued or limited operation of the Potomac River plant or any such modifications are not known at this time, but could be material depending on the length of time that operations are discontinued or limited.
City of Alexandria Nuisance Suit. On October 7, 2005, the City of Alexandria filed a suit against Mirant Potomac River and Mirant Mid-Atlantic in the Circuit Court for the City of Alexandria. The suit asserts nuisance claims, alleging that the Potomac River plant’s emissions of coal dust, flyash, NOx, SO2, particulate matter, hydrogen chloride, hydrogen fluoride, mercury and oil pose a health risk to the surrounding community and harm property owned by the City. The City seeks injunctive relief, damages and attorneys’ fees. On February 17, 2006, the City amended its complaint to add additional allegations in support of its nuisance claims relating to noise and lighting, interruption of traffic flow by trains delivering coal to the Potomac River plant, particulate matter from the transport and storage of coal and flyash, and potential coal leachate into the soil and groundwater from the coal pile.
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 Company’s Chapter 11 proceedings asserting a claim seeking to require the Company to provide funding to its subsidiaries owning generating facilities in New York to satisfy certain specified environmental compliance obligations. The State of New York alleges that during the pendency of the Chapter 11 proceedings the Company and its subsidiaries that have emerged from bankruptcy made decisions on behalf of the Company’s subsidiaries owning generating facilities in New York and did not appropriately maintain the corporate separateness between itself and those subsidiaries. The Company disputes those allegations. The State of New York cites 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, most of which are not material. The most significant compliance obligation identified by the State of New York in its notice of administrative claim relates to the 2003 Consent Decree entered into by Mirant New York and Mirant Lovett with the State of New York to resolve issues related to NSR requirements under the Clean Air Act related to the Lovett plant. Under the 2003 Consent Decree, Mirant Lovett is required to make an election to install certain environmental controls on units 4 and 5 of the Lovett facility or shut down those units by 2007 to 2008. The State of New York notes in its notice of administrative claim that the cost of implementing such environmental controls could exceed $200 million. The State of New York and the NYSDEC have executed a stipulated order with the Company and its New York subsidiaries to stay resolution of this administrative claim. The stipulated order was entered by the Bankruptcy Court on February 23, 2006.
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’s failure to implement a marine life exclusion system at its Lovett generating plant and to perform monitoring for the exclusion of certain aquatic organisms from the plant’s cooling water intake structures violates Mirant Lovett’s water discharge permit issued by the State of New York. The plaintiff requests the court to enjoin Mirant Lovett from continuing to operate the Lovett generating plant 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 attorney’s fees. On April 20, 2005, the district court approved a stipulation agreed to by the plaintiff and Mirant Lovett that stays the suit until 60 days after entry of an order by the Bankruptcy Court confirming a plan of reorganization for Mirant Lovett becomes final and non-appealable.
Mirant Lovett Coal Ash Management Facility. On July 8, 2004, the NYSDEC issued an NOV for improper closure of the coal ash management facility (“CAMF”) at the Lovett plant. The Notice of Violation identified two separate issues. The first was the failure of the previous owner/operator of the CAMF to obtain a closure certification for Stage 1 of the CAMF that conformed with applicable New York regulations. It is our view that we have submitted documentation demonstrating that the CAMF was properly closed, however that issue is still in dispute. The second issue relates to the closure of Stage 2 of the CAMF in 2002. Erosion of the barrier protection layer and topsoil developed within a few years of the closure of Stage 2. On November 8, 2005, the NYSDEC issued an additional notice of violation to Mirant Lovett asserting that the leachate collection system for the Lovett CAMF was not properly constructed because it allows storm water or groundwater to come into contact with the disposed wastes and leachate. Due to the ongoing evaluation to determine what remedial actions are required, the exact cost of remedial action is unknown at this time.
New York Dissolved Oxygen. On September 29, 2003, the NYSDEC issued a complaint to Mirant New York, for alleged failure to comply with state regulatory standards for minimum dissolved oxygen in the Mongaup River at the Swinging Bridge, Mongaup Falls and Rio hydroelectric projects owned by Mirant NY-Gen. The complaint sought a civil penalty of $120,000 and an order requiring Mirant New York to upgrade the three hydroelectric projects to prevent further discharges that do not meet the standards for minimum dissolved oxygen. In its complaint the NYSDEC proposed that $100,000 of the $120,000 penalty it was seeking be suspended on the condition that Mirant New York complete corrective actions for each facility by a certain schedule it proposed. On June 1, 2004, Mirant New York filed an
answer and motion to dismiss on grounds including that Mirant New York is not the owner of the hydroelectric projects. Mirant New York granted an extension of time to allow the NYSDEC to respond, and the NYSDEC has not yet responded. Mirant NY-Gen, the owner of the hydroelectric projects, has agreed with the NYSDEC upon a consent order to resolve the complaint. Under the consent order, Mirant NY-Gen will pay a fine of $8,000 and install certain specified equipment on the operational turbine at the Swinging Bridge facility. The specified equipment already has been installed on the Mongaup Falls and Rio facilities. In addition, Mirant NY-Gen is required to install this same equipment at the other, currently non-operational turbine at the Swinging Bridge facility within thirty days of that turbine becoming operational. The Bankruptcy Court approved the settlement on February 22, 2006, and the parties are proceeding to execute the consent order.
Mirant Bowline Oil Storage NOV. On January 4, 2006, the NYSDEC issued an NOV asserting various violations of regulations relating to a major oil storage facility, secondary containment, compliance report, underground storage tanks and a small oil storage facility at the Bowline plant. The NOV identified issues with labeling, maintenance and monitoring procedures and leak detection. The NOV did not seek a specific penalty amount but noted that the violations identified could each subject Mirant Bowline to a civil penalty of up to $37,500 per day. Mirant Bowline is working with the NYSDEC to address the issues identified.
New York Major Oil Storage Facility Licenses. The major oil storage facility license for the Bowline generating facility expires on March 31, 2006. Mirant Bowline’s renewal application for the Bowline facility has not yet been approved by the NYSDEC. Mirant Bowline is working with the NYSDEC to obtain authorization for continued operation of the Bowline major oil storage facility; however, if such authorization is not timely approved, Mirant Bowline may be subject to certain penalties or may be required to temporarily suspend operations at the Bowline facility.
Mirant Bowline Oil Spill. In November 2001, Mirant Bowline removed two underground oil storage tanks that had been used to collect oil recovered from the oil/water separators that are used for pretreatment of wastewater from the Bowline generating facility. Contaminated soil was found during the removal of one of the tanks and was removed from the site. Mirant Bowline is unable to confirm from documents at the facility whether the spill was reported to the NYSDEC and to the Rockland County, New York authorities. Consequently, Mirant Bowline reported a potential non-reported spill to the NYSDEC on February 23, 2006.
Morgantown Particulate Emissions. On March 3, 2006, Mirant Mid-Atlantic received a notice sent on behalf of the Maryland Department of the Environment (“MDE”) alleging that violations of particulate matter emissions limits applicable to Unit 1 at the Morgantown plant 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.
City of Alexandria Zoning Action
On December 18, 2004, the City Council for the City of Alexandria, Virginia (the “City Council”) adopted certain zoning ordinance amendments recommended by the City Planning Commission that resulted in the zoning status of Mirant Potomac River’s generating plant being changed from “noncomplying use” to “nonconforming use subject to abatement.” Under the nonconforming use status, unless Mirant Potomac River applies for and is granted a special use permit for the plant during the seven-year abatement period, the operation of the plant must be terminated within a seven-year period, and no alterations that directly prolong the life of the plant will be permitted during the seven-year period. If Mirant Potomac River were to apply for and receive a special use permit for the plant, the City Council
would likely impose various conditions and stipulations as to the permitted use of the plant and to seek to limit the period for which it could continue to operate.
At its December 18, 2004, meeting, the City Council also approved revocation of two special use permits issued in 1989 (the “1989 SUPs”), one applicable to the administrative office space at Mirant Potomac River’s plant and the other for the plant’s transportation management plan. Under the terms of the approved action, the revocation of the 1989 SUPs was to take effect 120 days after the City Council revocation, provided, however, that if Mirant Potomac River within such 120-day period filed an application for the necessary special use permits to bring the plant into compliance with the zoning ordinance provisions then in effect, the effective date of the revocation of the 1989 SUPs would be stayed until final decision by the City Council on such application. The approved action further provides that if such special use permit application is approved by the City Council, revocation of the 1989 SUPs will be dismissed as moot, and if the City Council does not approve the application, the revocation of the 1989 SUPs will become effective and the plant will be considered a nonconforming use subject to abatement.
On January 18, 2005, Mirant Potomac River and Mirant Mid-Atlantic filed a complaint against the City of Alexandria and the City Council in the Circuit Court for the City of Alexandria. The complaint seeks to overturn the actions taken by the City Council on December 18, 2004, changing the zoning status of Mirant Potomac River’s generating plant and approving revocation of the 1989 SUPs, on the grounds that those actions violated federal, state and city laws. The complaint asserts, among other things, that the actions taken by the City Council constituted unlawful spot zoning, were arbitrary and capricious, constituted an unlawful attempt by the City Council to regulate emissions from the plant, and violated Mirant Potomac River’s due process rights. Mirant Potomac River and Mirant Mid-Atlantic request the court to enjoin the City of Alexandria and the City Council from taking any enforcement action against Mirant Potomac River or from requiring it to obtain a special use permit for the continued operation of its generating plant. On January 18, 2006, the court issued an oral ruling following a trial that the City of Alexandria acted unreasonably and arbitrarily in changing the zoning status of Mirant Potomac River’s generating plant and in revoking the 1989 SUPs. On February 24, 2006, the court entered judgment in favor of Mirant Potomac River and Mirant Mid-Atlantic declaring the change in the zoning status of Mirant Potomac River’s generating plant adopted December 18, 2004, to be invalid and vacating the City Council’s revocation of the 1989 SUPs. The City of Alexandria has filed notice of its appeal of this judgment.
PEPCO Assertion of Breach of Local Area Support Agreement
Following the shutdown of the Potomac River plant on August 24, 2005, Mirant Potomac River notified PEPCO on August 30, 2005, that it considered the circumstances resulting in the shutdown of the plant to constitute a force majeure event under the Local Area Support Agreement dated December 19, 2000, between PEPCO and Mirant Potomac River. That agreement imposes obligations upon Mirant Potomac River to dispatch the Potomac River plant under certain conditions, to give PEPCO several years advance notice of any indefinite or permanent shutdown of the plant, and to pay all or a portion of certain costs incurred by PEPCO for transmission additions or upgrades when an indefinite or permanent shutdown of the plant occurs prior to December 19, 2010. On September 13, 2005, PEPCO notified Mirant Potomac River that it considers Mirant Potomac River’s shutdown of the plant to be a material breach of the Local Area Support Agreement that is not excused under the force majeure provisions of the agreement. PEPCO contends that Mirant Potomac River’s actions entitle PEPCO to recover as damages the cost of constructing additional transmission facilities. PEPCO on January 24, 2006, filed a notice of administrative claims asserting that Mirant Potomac River’s shutdown of the Potomac River plant causes Mirant Potomac River to be liable for the cost of such transmission facilities, which cost it estimates to be in excess of $70 million. Mirant Potomac River disputes PEPCO’s interpretation of the agreement. The outcome of this matter cannot be determined at this time.
New York Tax Proceedings
The Company’s subsidiaries that own the Bowline and Lovett generating plants in New York are the petitioners in various proceedings (“Tax Certiorari Proceedings”) initially brought in the New York state courts challenging the assessed value of those generating plants determined by their respective local taxing authorities. Mirant Bowline has challenged the assessed value of the Bowline generating facility and the resulting local tax assessments paid for tax years 1995 through 2005. Mirant Bowline succeeded to rights held by Orange & Rockland for the tax years prior to its acquisition of the Bowline Plant in 1999 under its agreement with Orange & Rockland for the purchase of that plant. Mirant Lovett has initiated proceedings challenging the assessed value of the Lovett facility for each of the years 2000 through 2005. If the Tax Certiorari Proceedings result in a reduction of the assessed value of the generating facility at issue in each proceeding, the New York Debtor owning the facility would be entitled to a refund with interest of any excess taxes paid for those tax years.
On September 30, 2003, the Mirant Debtors filed a motion (the “Tax Determination Motion”) with the Bankruptcy Court requesting that it determine what the property tax liability should have been for the Bowline generating facility in each of the years 1995 through 2003 and for the Lovett generating facility in each of the years 2000 through 2003. The bases for the relief requested in the Tax Determination Motion on behalf of Mirant Bowline and Mirant Lovett were that the assessed values of the generating facilities made by the relevant taxing authorities had no justifiable basis and were far in excess of their actual value. The local taxing authorities have opposed the Tax Determination Motion, arguing that the Bankruptcy Court either lacks jurisdiction over the matters addressed by the Tax Determination Motion or should abstain from addressing those issues so that they can be addressed by the state courts in which the Tax Certiorari Proceedings described in the preceding paragraph were originally filed.
Collectively, Mirant Bowline and Mirant Lovett have not paid approximately $62 million assessed by local taxing authorities on the Bowline and Lovett generating facilities for 2003, which fell due on September 30, 2003, and January 30, 2004, approximately $53 million assessed by local taxing authorities on the generating facilities for 2004 that fell due on September 30, 2004, and January 30, 2005, and approximately $59 million assessed by local taxing authorities on the generating facilities for 2005 that fell due on September 30, 2005, and January 30, 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. The failure to pay the taxes due on September 30, 2003, January 30, 2004, September 30, 2004, January 30, 2005, September 30, 2005, and January 30, 2006 could subject Mirant Bowline and Mirant Lovett to additional penalties and interest.
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.
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. Since filing for protection under Chapter 11, we have not paid dividends. We have no equity compensation plans under which we issue our membership interests.
Item 6.
Item 6. Selected Financial Data
The information set forth below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical combined and consolidated financial statements and the notes thereto, which are included elsewhere in this Form 10-K. The selected financial data has been derived from our combined and consolidated financial statements. See Note 1 to our combined and consolidated financial statements for further discussion.
From the Petition Date through emergence, our combined and consolidated financial statements were prepared in accordance with Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code” (“SOP 90-7”). Our Statement of Operations Data for the years ended December 31, 2004 and 2003 does 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. For further discussion of the effects of the Plan, see Note 4 to our combined and consolidated financial statements.
At December 31, 2004 and 2003 certain long-term debt amounts were included in liabilities subject to compromise.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
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 combined and consolidated financial statements and the notes accompanying those financial statements.
Overview
We are a national independent power provider that produces and sells electricity in the United States. On July 14, 2003 (the “Petition Date”), and various dates thereafter, the Company and its subsidiaries were among the 83 direct and indirect Mirant subsidiaries in the United States (collectively, the “Mirant Debtors”), that filed with the United States Bankruptcy Court for the Northern District of Texas, Fort Worth Division (the “Bankruptcy Court”) voluntary petitions for relief under Chapter 11 of Title 11 of the United States Bankruptcy Code (as amended the “Bankruptcy Code”). We continued to operate our business as a debtor-in-possession under the jurisdiction of the Bankruptcy Court in accordance with Chapter 11 of the Bankruptcy Code. As a result, our financial statements include the results of the bankruptcy process.
The Plan of Reorganization (the “Plan”) was confirmed by the Bankruptcy Court on December 9, 2005, and we emerged from bankruptcy on January 3, 2006. As a result, we recorded the effects of the Plan in our financial statements for the year ended December 31, 2005. We recognized a gain of $30 million, included in reorganization items, net related to the effects of the Plan. Among other things, we recognized the reinstatement of certain debt and settlement amounts of claims, all as prescribed by the Plan. See Notes 1 and 3 to our combined and consolidated financial statements contained elsewhere in this report for additional discussion of the key elements of the Plan and Note 4 for the impacts of the Plan on our combined and consolidated financial statements for the year ended December 31, 2005.
The primary factors impacting the earnings and cash flows of our operations are the prices for power, natural gas and coal, which are largely driven by supply and demand. The increase in new generation capacity that followed the restructuring of the power markets in the late 1990’s has created an oversupply situation in most markets which is expected to continue until 2008 to 2010. The imbalance between supply and demand, price controls during periods of high demand and local constraint and lack of appropriate compensation for locational capacity value limit our ability to recover our fixed costs such that we must rely almost entirely on energy gross margins produced by generating electrical energy for a price greater than the cost of the fuel required to run the plants. Demand for power can also vary regionally and seasonally due to, among other things, weather and general economic conditions. Power supplies similarly vary by region and are impacted significantly by available generating capacity, transmission capacity and federal and state regulation. We also are impacted by the relationship between prices for power and fuel, such as natural gas, coal and oil that impact our cost of generating electricity.
We engage in asset hedging activities to economically hedge our positions in order to reduce our exposure to commodity price fluctuations and to achieve acceptable gross margins. In general, we currently economically hedge a substantial portion of our Mid-Atlantic coal fired generation and our New England oil fired generation through over-the-counter transactions. However, we generally do not hedge most of our cycling and peaking capacity due to the limited value we can extract in the marketplace and the high cost of collateral typically required to support these contracts. Many of the power and fuel contracts that we use to economically hedge our portfolio meet the criteria of a derivative and are accounted for at fair value in our combined and consolidated balance sheets. Changes in the fair value represent unrealized gains and losses and result in income volatility when the underlying energy prices are volatile. We currently economically hedge a substantial portion of our Mid-Atlantic coal fired baseload generation (generation that is dispatched most of the time) and our New England oil fired generation through over-the-counter transactions. However, we generally do not hedge most of our cycling and peaking units (generating facilities that are not dispatched as frequently) due to the limited value we can extract in the marketplace and the high cost of collateral typically required to support these contracts. As of March 3, 2006, we have
economically hedged approximately 90%, 60%, 30%, and 30% of our expected Mid-Atlantic coal fired generation for the remainder of 2006, 2007, 2008 and 2009, respectively, and purchased approximately 100%, 80%, 30% and 30% of the expected Mid-Atlantic coal requirements for such periods. Included in such amounts are financial swap transactions entered into by Mirant Mid-Atlantic with a counterparty in January 2006 pursuant to which Mirant Mid-Atlantic economically hedged approximately 80%, 50%, and 50% of its expected on-peak coal fired baseload generation for 2007, 2008 and 2009, respectively. The financial swap transactions are senior unsecured obligations of Mirant Mid-Atlantic and do not require us to post cash collateral either in the form of initial margin or to secure exposure due to changes in power prices. In addition, as of March 3, 2006, we have economically hedged approximately 50% of our expected oil fired generation in New England for the remainder of 2006 and procured approximately 50% of the corresponding expected oil requirements.
Our business is subject to extensive environmental regulation by federal, state and local authorities. This requires us to comply with applicable laws and regulations, and to obtain and comply with the terms of government issued operating permits. Our costs of complying with environmental laws, regulations and permits are substantial. We estimate that our capital expenditures for environmental compliance will be approximately $300 million for 2006 and will be $1 billion to $1.5 billion for 2006 through 2011. Our potential capital expenditures for environmental regulations are difficult to estimate because we cannot now assess what regulations may be applicable or what costs might be associated with the regulation. Our actual capital expenditures will be materially impacted if the State of Maryland passes legislation or imposes regulations that increase beyond applicable federal law the restrictions on emissions of SO2, NOx and mercury, or imposes restrictions on emissions of CO2. This legislation or regulation, or similar legislation or regulation in other states or by the federal government, may render some of our units uneconomic.
A significant portion of our capital resources, in the form of cash and letters of credit is needed to satisfy counterparty collateral requirements. These counterparty collateral requirements reflect our non-investment grade credit ratings, volatile energy prices, generally higher margin levels in the industry and other factors. Whenever feasible, we seek to structure transactions in a way that reduces our potential liquidity needs for collateral.
Bankruptcy Considerations
While in bankruptcy, our financial results were volatile as asset impairments, asset dispositions, restructuring activities, contract terminations and rejections, and claims assessments significantly impacted our combined and consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance post-bankruptcy.
Results of Operations
Our gross margins and expenses from affiliates and nonaffiliates aggregated by classification are as follows (in millions):
In the tables below, the Mid-Atlantic region includes our Morgantown, Chalk Point, Dickerson and Potomac River facilities. The Northeast region includes our New England and New York facilities. The West region includes Mirant Texas, Mirant California and Mirant Zeeland. Energy Marketing includes Mirant Americas Energy Marketing and the other Trading Debtors. Eliminations includes the elimination of intercompany transactions between Mirant Americas Generation subsidiaries.
The following table summarizes capacity factor (average percentage of full capacity used over a year) by region for the years ended December 31, 2005, 2004 and 2003:
The following table summarizes power generation volumes by region for the years ended December 31, 2005, 2004 and 2003 (in gigawatt hours):
2005 versus 2004
Gross margin. Our gross margin decreased $247 million in 2005 compared to 2004.
The following table summarizes the realized and unrealized gross margin for the year ended December 31, 2005 compared to same period in 2004 (in millions):
The following table summarizes the change in realized and unrealized gross margin for the year ended December 31, 2005 compared to same period in 2004 (in millions):
The $247 million decrease in gross margin is detailed as follows (in millions):
Mid-Atlantic operations gross margin decreased $46 million primarily due to the following:
· an increase of $570 million driven by higher market prices for power. Spot market prices for power were higher during the year ended December 31, 2005, compared to the same period in 2004. Average settlement prices increased 63%;
· a decrease of $152 million related to higher fuel prices during the period. Average prices for fuel increased as follows: gas 60%, coal 17% and oil 57%;
· an increase of $44 million related to an increase in prices for ancillary services, consistent with increased energy prices;
· a decrease of $61 million related to generation volumes. Volumes decreased by 2.7%, which had an unfavorable effect of $14 million on gross margin based on average revenue and fuel costs per MWh in 2004. Also included is an unfavorable impact of $47 million due to a change in the mix of generation, with increases in volumes by the more expensive gas and oil fired units and a slight decrease in the generation volumes by the coal fired units. Volumes were impacted by significant unplanned outages primarily related to baseload units;
· a decrease of $414 million due to losses on economic hedges compared to 2004 related primarily to the impact of rising energy prices on the realized economic hedges of our generation output during the 2005 period;
· a decrease of $9 million related to a reduction in revenue due to lower prices for installed capacity as a result of the expansion of the PJM market;
· a decrease of $14 million due to increased emissions expense of $19 million, partially offset by higher emissions revenue of $5 million. Prices for SO2 and NOx emissions allowances increased in 2005 compared to the same period in 2004;
· a decrease of $22 million related to losses of $97 million in the year ended December 31, 2005 on unrealized derivative contracts for future years, compared to losses of $75 million for the same period in 2004. As power prices increased during 2005, we recognized losses on short power positions used to hedge the expected output of our power plants in future years. These losses on unrealized power hedges were greater in 2005 than in 2004, but were partly offset by the settlement of hedges that had a negative value at the start of the year and by a gain in 2005 on unrealized fuel hedges for future years, compared to a loss for the same period in 2004; and
· an increase of $12 million in other primarily due to a $13 million net settlement with a coal supplier related to rail car transportation schedule issues that resulted in lower fuel expense.
Northeast operations gross margin decreased $35 million primarily due to the following:
· an increase of $290 million driven by higher market prices for power. Spot market prices for power were higher during the year ended December 31, 2005 compared to the same period in 2004. Average settlement prices increased 63% in New York and 49% in New England. In 2005, we received $5 million from the NYISO related to adjustments from 2000-2003;
· a decrease of $188 million related to higher fuel prices during the period. Average prices for fuel in New York increased as follows: gas 37%, coal 25%, and oil 56%. Residual oil prices increased 48% and gas prices increased by 42% in New England;
· an increase of $2 million related to an increase in prices for ancillary services, consistent with increased energy prices;
· a decrease of $11 million related to an increase in generation volumes. This incremental generation has a favorable impact of $5 million on gross margin which is offset by an unfavorable variance of $16 million due to a change in the mix of generation, with increases in volumes by the more expensive gas fired units and a slight decrease in the generation volumes by the coal fired units;
· a decrease of $71 million related primarily to the impact of rising energy prices on the realized economic hedges of our generation output, partly offset by the impact of rising fuel prices on the realized economic hedges of our fuel requirements during the period;
· a decrease of $2 million that reflects lower revenues at New York of $11 million due to lower prices for installed capacity. This was partially offset by increased revenues in New England of $9 million due to the Kendall RMR agreement;
· a decrease of $9 million due to reduced sales of surplus emissions allowances to the Mid-Atlantic facilities;
· a decrease of $42 million related to losses of $11 million in the year ended December 31, 2005 on unrealized derivative contracts for future periods, compared to a gain of $31 million for the same period in 2004. As power prices increased during 2005, we recognized losses on power sales contracts used to hedge the expected output of our power plants in future years. These losses on unrealized power hedges for future periods were greater in 2005 than in 2004, but were partly offset by increased gains on unrealized fuel hedges for future periods. In addition, the hedges settled in 2005 had a net favorable value at the beginning of the year and this contributed to the reduction in value of unrealized derivative contracts. In 2004 the settlement of hedges with a net unfavorable value at the beginning of 2004 had the effect of increasing the value of derivative contracts for future periods; and
· a decrease of $4 million in other which includes a decrease in gas sales and transport of $6 million offset by additional receipts in 2005 of $5 million in insurance proceeds related to an outage at the Bowline facility in 2004, compared to $2 million of proceeds received in 2004.
West operations gross margin decreased $29 million primarily due to the following:
· a decrease of $29 million related to reduced merchant generation and the impact of rising energy prices on the realized economic hedges of our generation output, partly offset by the impact of rising fuel prices on the realized economic hedges of our fuel requirements during the period;
· a decrease of $19 million which includes a decrease of $32 million related to the expiration of an RMR contract for one of our California generating facilities in 2004 partially offset by capacity
income from tolling agreements on those California assets not covered by RMR and our facility in Texas and an increase of $13 million related to capacity income from a tolling agreement at the Zeeland facility;
· an increase of $4 million related to a decrease in net unrealized gains on derivative contracts for future periods; and
· an increase of $15 million in other primarily due to lower gas transport costs and reduced losses on gas sales. Under the new power purchase agreements entered into early in 2005, PG&E is responsible for purchasing the fuel for most of the California units. See “Item 1. Business” for further discussion.
Energy Marketing gross margin decreased $159 million primarily due to the following:
· an increase of $304 in realized gross margin, which includes a decrease of $226 million in realized losses on the transition power agreements (“TPAs”) and $19 million decrease in realized losses on the Back-to-Back Agreement.
· a decrease of $335 million primarily related to amortization of the TPAs. The Maryland TPA expired in June 2004 and the DC TPA expired in January 2005. TPA amortization was $9 million at December 31, 2005 and $344 million for the same period in 2004;
· a decrease of $57 million related to a decrease in net unrealized gains on derivative contracts for future periods; and
· a decrease of $71 million related to an increase in unrealized losses on the Back-to-Back agreement. The Back-to-Back agreement was transferred to Mirant Power Purchase, LLC (“Mirant Power Purchase”), a wholly owned subsidiary of Mirant Americas, Inc.
Eliminations gross margin increased by $22 million primarily due to the following:
· an increase of $19 million due to the elimination of a gain on intercompany SO2 emissions allowances transfers in 2004 and the elimination of the related expense recorded in 2005.
Operations and maintenance. Operations and maintenance expenses increased by $2 million primarily due to:
· an increase of $21 million in maintenance expenditures of which $8 million is related to maintenance on the dam at Swinging Bridge, $5 million is related to environmental remediation costs at the Lovett and Hillburn facilities and $11 million is due to increased maintenance at Mid-Atlantic, which includes $3 million related to the unplanned outages at the Morgantown and Chalk Point facilities and $2 million related to the Potomac River downwash project. See “Item 1. Business” for further discussion;
· an increase of $10 million due to a reduction recorded in 2004 in the reserve related to receivables from Enron;
· an increase of $8 million related to the property tax settlements of certain California and New York generation assets in 2004;
· an increase of $5 million due to an increase in the reserve for obsolete spare parts inventory; and
· a decrease of $37 million in operations and maintenance-affiliate primarily due to a $35 million reduction in corporate overhead allocations from Mirant Services.
(Gain) loss on sales of assets. (Gain) loss on sales of assets decreased $64 million primarily due to a loss in 2004 related to the sale of three natural gas combustion turbines.
Other (expense) income, net. Other (expense) income, net increased $729 million primarily due to the recognition of $746 million of interest on liabilities subject to compromise for the period from the Petition Date through December 31, 2005. This was offset by a gain of $44 million related to the 2005 sale of a portion of our investment in a company that provides an electronic commerce platform for the purchase and sale of energy commodities. See Note 2 to our combined and consolidated financial statements contained elsewhere in this report for further discussion.
2004 versus 2003
Gross margin. Gross margin increased $31 million in 2004, primarily due to the following:
The following table summarizes gross margin by region for the years ended December 31, 2004 and 2003 (in millions):
· Mid-Atlantic operations gross margin increased $101 million primarily due to the termination of the Energy and Capacity Sales Agreement (“ECSA”) with Mirant Americas Energy Marketing in May 2003. Revenues received under the ECSA in 2003 were $110 million less than what would have been received from the PJM spot market. Excluding the impact of the ECSA, Mid-Atlantic gross margin would have been $9 million lower in 2004 than in 2003, primarily due to the following:
· an increase of approximately $44 million driven by higher market prices for power;
· an increase of $64 million related to an increase in prices for capacity and ancillary services;
· an increase of $15 million due to gains on realized power hedges;
· a decrease of approximately $68 million related to net unrealized losses on derivative contracts for future periods. Of these contracts, $58 million related to power and $10 million related to oil and gas, and were entered into to economically hedge a portion of the energy price risk related to future Mid-Atlantic operations. The decrease in value of these energy derivative contracts is due to an increase in forward power prices;
· a decrease of $14 million related to a higher emissions expense due mainly to higher prices for SO2 emissions allowances. In order for us to meet our current needs to operate our generation facilities we had to purchase additional emissions allowances. The average price of emissions allowances increased 136% from $180 per ton in 2003 to $425 per ton in 2004;
· a decrease of $8 million due to lower generation volumes;
· a decrease of $13 million due to higher coal prices, partly offset by lower oil and gas prices;
· a decrease of $16 million related to a reduction in realized gains on economic fuel hedges; and
· a decrease of $11 million related to the termination of contracts in 2004.
· Northeast operations gross margin increased $106 million primarily due to the following:
· an increase of $43 million related to net unrealized gains on derivative instruments of approximately $31 million in 2004 compared to $12 million in net unrealized losses in 2003;
· an increase of $27 million due to certain forced outages and transmission line problems in 2003 that did not recur in 2004;
· an increase of $22 million in our realized economic hedging margin due to the impact of 2003 short positions on power in a market where prices for power were rising; and
· an increase of $16 million due to the impact of intercompany emissions allowance sales.
· West operations reflects a reduction in gross margin of $34 million for our generation units in California, Texas and Michigan.
· a decrease of $3 million in California primarily due to a decrease in gains on realized economic hedges of $22 million as a result of reduced economic hedging activity offset by $18 million of savings on gas reservation charges following a contract rejection;
· a decrease of $16 million in Texas primarily due to lower energy prices and a new tolling agreement that began in August 2004 with a third party that is at lower prices than what these units received under a prior agreement with Mirant Americas Energy Marketing; and
· a decrease of $16 million at our Zeeland facility primarily related to purchasing power in the market rather than running the generation facility to serve load deals in 2004.
· Energy Marketing gross margin decreased $151 million primarily due to the following:
· a decrease of $80 million related to amortization of the TPAs due to the expiration of the Maryland TPA in June 2004 resulting in lower amortization and the impact of a late contract change in 2003. The DC TPA expired in January 2005 (as actual MWhs are purchased or sold under these agreements we amortize a ratable portion of the obligation as an increase in revenue);
· a decrease of $3 million in unrealized gains on the Back-to-Back agreement, which were $168 million and $171 million in 2004 and 2003, respectively;
· a decrease of $19 million as a result of an increase in realized losses on the TPA. Realized losses for 2004 and 2003 were $234 million and $215 million, respectively;
· a decrease of $44 million as a result of an increase in realized losses on the PPA, which were $96 million and $52 million in 2004 and 2003, respectively; and
· a decrease of $333 million in energy marketing realized trading partially offset by an increase of $329 million related to net unrealized losses on derivative instruments. Gross margin for the year ended December 31, 2003, reflects unrealized losses offset by realized gross margin related to energy contracts terminated by counterparties as a result of our Chapter 11 filings. As a result of the termination of these contracts the unrealized gains on these contracts became realized in 2003.
Operating expenses. Operating expenses decreased $2,940 million primarily due to the following:
· an increase of $7 million in generation facilities rent related to the additional rent expense for our Morgantown and Dickerson baseload units as a result of the Bankruptcy Court’s granting the motion compelling us to pay incremental rent in 2004. See Note 16 contained elsewhere in this report for further discussion.
· a decrease of $38 million in depreciation and amortization expense primarily due to lower depreciation expense related to our property, plant and equipment after our $1,088 million impairment of long-lived assets in the fourth quarter of 2003;
· an increase of $84 million in operations and maintenance-affiliate related to an increase of $111 million in our corporate overhead allocations from Mirant Services and a decrease of $27 million related to our service agreements with Mirant Services for management, personnel and services; and
· a decrease of $48 million in operations and maintenance-nonaffiliate primarily due to the following:
· an increase of $13 million related to the Commodity Futures Trading Commission (“CFTC”) settlement in December 2004. See Note 14 to our combined and consolidated financial statements contained elsewhere in this report;
· a decrease of $10 million due to a reduction in the allowance related to receivables from Enron;
· a decrease of $8 million related to lower property taxes due to settlements related to certain California and New York generation facilities; and
· a decrease of $32 million related to an energy marketing customer bad debt expense reflected in 2003;
· an increase of $83 million in loss on sales of assets, net primarily related to a $65 million loss on the sale of three natural gas combustion turbines at Bowline 3 in 2004 as compared to a $15 million gain related to the sale of firm transportation agreements and $3 million gain on the sale of crude oil at one of our California facilities in 2003;
· decrease of $3,028 million for impairment losses comprised of the following:
· a decrease of $1,940 million for goodwill impairment charges related to the impairment of goodwill in 2003. For further discussion, see “Critical Accounting Policies and Estimates” and Note 9 to our combined and consolidated financial statements contained elsewhere in this report;
· a decrease of $1,088 million for long-lived asset impairment losses due to an impairment of $1,090 recorded in 2003 for several of our assets. For further discussion, see “Critical Accounting Policies and Estimates” and Note 8 and Note 9 to our combined and consolidated financial statements contained elsewhere in this report.
Other income (expense), net. Other income (expense), net increased $221 million primarily due to suspension of accruals for interest expense after the Petition Date.
Financial Condition
Liquidity and Capital Resources
During the pendency of the Chapter 11 proceedings we satisfied our liquidity and capital requirements with cash from operations and a $500 million Mirant debtor-in-possession credit facility that was approved by the Bankruptcy Court and which provided for borrowings or the issuance of letters of credit. The Chapter 11 proceedings resulted in various restrictions on our activities, including limitations on financing, and the implementation of a centralized cash management system that provided for the collection, concentration and disbursement of funds. The Chapter 11 proceedings also caused uncertainty in our relationships with vendors, suppliers, customers and others with whom we conducted or sought to conduct business. During the Chapter 11 proceedings, we typically posted cash collateral with counterparties. Going forward, we expect relationships with vendors, suppliers, customers, counterparties and others to return to normal industry practices, including the posting of letters of credit instead of cash collateral.
Emergence from Bankruptcy
On December 23, 2005, our subsidiary Mirant North America issued a note offering for $850 million of 7.375% senior unsecured notes due 2013. The funds from this issuance were initially placed in escrow and were released from escrow on January 3, 2006, upon consummation of the Plan. On January 3, 2006, Mirant North America entered into an $800 million senior secured revolving credit facility and a $700 million senior secured term loan. In connection with the closing, $200 million of drawings under the senior secured term loan were deposited into a cash collateral account to support the issuance of up to $200 million of letters of credit issued under the senior secured term loan.
Sources of Funds and Capital Structure
The principal sources of liquidity for our future operations and capital expenditures are expected to be: (i) existing cash on hand and cash flows from the operations of our subsidiaries; (ii) borrowings under Mirant North America’s $800 million six year senior secured revolving credit facility; (iii) $200 million of letters of credit capacity under Mirant North America’s $700 million term loan and (iv) proceeds from the preferred shares issued by Mirant Americas to Mirant Mid-Atlantic and the Company to fund capital expenditures and support the refinancing of the Company’s senior notes due in 2011.
Our operating cash flows may be impacted by, among other things: (i) the difference between the cost of a specific fuel used to generate one megawatt hour of electricity and the market value of the electricity generated (“conversion spread”); (ii) commodity prices (including prices for natural gas, coal, oil and electricity); (iii) the cost of ordinary course operations and maintenance expenses; (iv) planned and unplanned outages; (v) contraction of terms by trade creditors; and (vi) cash requirements for capital expenditures relating to certain facilities (including those necessary to comply with environmental regulations).
We and certain of our subsidiaries, including Mirant North America, are holding companies 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 ability of certain of our subsidiaries to pay dividends and distributions is restricted under the terms of their debt or other agreements. We have no operations and no subsidiaries with operations other than Mirant North America and its subsidiaries, including Mirant Mid-Atlantic. The Mirant North America notes and senior secured credit facilities restrict its ability to make distributions. In addition, under the Mirant Mid-Atlantic leveraged leases, Mirant Mid-Atlantic, which generates a significant portion of our cash from operations, is subject to a covenant that restricts its right to make distributions to us and Mirant North America. Mirant Mid-Atlantic’s ability to satisfy these ratio tests in the future could be impaired by factors which negatively affect the performance of its power generation facilities, including interruptions in operation such as the recent temporary shutdown and continuing curtailment of operations of the Potomac River generation facility.
Reinstated Senior Notes
As part of the Plan, we reinstated senior notes of $1.7 billion maturing in 2011, 2021 and 2031 and agreed to pay $452 million of accrued interest.
Interest Rate; Maturity Date; Redemption Rights. The notes, which mature on May 1, 2011, October 1, 2021, and May 1, 2031, were issued in aggregate principal amounts of $850 million, $450 million and $400 million and bear interest at 8.3%, 8.5%, and 9.125%, respectively. Interest on the 2021 notes is payable on each April 1 and October 1 and interest on the 2011 notes and 2031 notes is payable on each May 1 and November 1.
At any time and at our option, we may redeem the notes of each series, in whole or in part (if in part, by lot or by such other method as the trustee shall deem fair or appropriate) at the redemption price of 100% of principal amount of such notes, plus accrued interest on the principal amount of such notes, if any, to the redemption date, plus the make-whole premium for such notes. The make-whole premium is calculated as follows: (i) the average life of the remaining scheduled payments of principal in respect of outstanding notes of such series (the “Remaining Average Life” of the notes of such series) as of the redemption date; (ii) the yield to maturity for the United States treasury security having an average life equal to the Remaining Average Life of the notes of such series and trading in the secondary market at the price closest to the principal amount thereof (the “Primary Issue” for the notes of such series) (subject to extrapolation if no United States treasury security has an average life equal to the Remaining Average Life of the notes of such series); and (iii) the discounted present value of the then-remaining scheduled payments of principal and interest (but excluding that portion of any scheduled payment of interest that is actually due and paid on the redemption date) in respect of outstanding notes of such series as of the redemption date using a discount factor equal to the sum of (x) the yield to maturity for the Primary Issue for the notes of such series, plus (y) 25 basis points for the 2011 notes, 37.5 basis points for the 2021 notes, and 37.5 basis points for the 2031 notes. The amount of make-whole premium in respect of notes to be redeemed shall be an amount equal to (x) the discounted present value of such notes to be redeemed determined in accordance with clause (iii) above, minus (y) the unpaid principal amount of such new notes; provided, however, that the make-whole premium shall not be less than zero.
Ranking. The notes are senior unsecured obligations of the Company, and are not secured by any of our affiliates or subsidiaries. Thus, the notes are structurally subordinated to all existing and future liabilities of Mirant North America and its subsidiaries, including the indebtedness described below under “Mirant North America” and the obligations under the Mirant Mid-Atlantic leveraged leases described below under “Mirant Mid-Atlantic Operating Leases.”
Certain covenants. The notes are issued under an indenture that limits our ability to:
· incur, assume or guarantee additional indebtedness, or permit its subsidiaries to incur, assume or guarantee indebtedness;
· create liens;
· sell assets; and
· merge, consolidate or sell or otherwise dispose of all or substantially all of our assets.
These covenants are subject to a number of important exceptions and qualifications.
Mirant North America
As contemplated by the Plan, our subsidiary Mirant North America, entered into senior secured credit facilities (the “senior secured credit facilities”) with a syndicate of banks, financial institutions and other entities, including JPMorgan Chase Bank, N.A., Deutsche Bank Trust Company Americas and Goldman Sachs Credit Partners L.P., as lenders (the “Lenders”), and, together with Mirant North America Finance Corp., a subsidiary of Mirant North America, has issued $850 million aggregate principal amount of 7.375% senior unsecured notes due 2013 (the “notes”).
Senior Secured Credit Facilities
The Mirant North America senior secured credit facilities are comprised of an $800 million six-year senior secured revolving credit facility and a $700 million seven-year senior secured term loan. The full amount of the senior secured revolving credit facility is available for the issuance of letters of credit. The senior secured term loan was made in a single drawing at closing and will amortize in nominal quarterly installments aggregating 0.25% of the original principal of the term loan per quarter for the first 27
quarters, with the remainder payable on the final maturity date. In connection with the closing, $200 million of drawings under the senior secured term loan were deposited into a cash collateral account to support the issuance of up to $200 million of letters of credit issued under the senior secured term loan.
Interest rates. Loans under the senior secured credit facilities are available at either of the following rates: (i) a fluctuating rate of interest per annum equal to on any given day the greater of (a) the interest rate per annum publicly announced by JPMorgan Chase Bank, N.A. as its prime rate in effect at its principal office in New York City on that day, and (b) the federal funds rate in effect on that day plus 0.50%, plus the applicable margin described below (“base rate”), or (ii) a fixed rate determined for certain interest periods selected equal to U.S. dollar London InterBank Offered Rate (“LIBOR”) plus the applicable margin described below (“Eurodollar rate”).
The applicable margin with respect to loans under the senior secured revolving credit facility is 1.25% in the case of base rate loans, or 2.25% in the case of Eurodollar rate loans. The applicable margin will also be subject to a possible reduction of up to 0.50% based on the achievement and maintenance of certain leverage ratios by Mirant North America. The applicable margin with respect to the senior secured term loan is 0.75% in the case of base rate loans, or 1.75% in the case of Eurodollar rate loans.
Guarantees; Ranking and security. The obligations of Mirant North America under the senior secured credit facilities are unconditionally and irrevocably guaranteed by all of its direct and indirect subsidiaries, except (i) Mirant Energy Trading and Mirant Mid-Atlantic and its subsidiaries, (ii) until such time such entities emerge from Chapter 11 proceedings, Mirant New York, Mirant Bowline, Mirant Lovett, Mirant NY-Gen and Hudson Valley Gas Corporation, and (iii) any of its subsidiaries designated as unrestricted subsidiaries from time to time ((ii) and (iii) together, the “unrestricted subsidiaries”). The guarantee obligations of these subsidiary guarantors are secured by first priority security interests on substantially all the assets of such subsidiary guarantors, subject to certain permitted liens and certain exceptions.
All loans under the senior secured credit facilities are senior, secured indebtedness of Mirant North America secured by first priority security interests in substantially all of the assets of Mirant North America subject to permitted liens under the senior secured credit facilities and certain exceptions. The obligations of the subsidiaries of Mirant North America that are providing guarantees under the senior secured credit facilities are secured by first priority security interests in substantially all of the assets of each such subsidiary, subject to certain permitted liens under the senior secured credit facilities and certain exceptions.
Commitment/facility fees and default interest. A commitment fee calculated on the daily average unused portion of the commitments under the senior secured revolving credit facility is payable quarterly in arrears at an annual rate of 0.375%. The commitment fee is subject to a possible reduction of 0.125% based on the achievement and maintenance of certain leverage ratios by Mirant North America.
A fee on outstanding letters of credit under the senior secured revolving credit facility is paid to the Lenders quarterly in arrears on a pro rata basis. The letter of credit fee is calculated on the average daily aggregate available amount under all letters of credit under the senior secured revolving credit facility at a rate per annum equal to the applicable margin for Eurodollar rate loans under the senior secured revolving credit facility less the amount of the fronting fee of the issuing banks under the senior secured revolving credit facility. A fronting fee at the rate of 0.125% per annum calculated on the face amount of each letter of credit under the senior secured revolving credit facility and each letter of credit that is cash collateralized with a portion of the senior secured term loan proceeds will be paid quarterly in arrears to the relevant issuing bank.
In the event of a default in the payment of principal or interest under the senior secured credit facilities or in the payment of any fees or other amounts due and payable under the related loan
documents, interest accrues on the overdue amount at the applicable rate plus an additional 2% until such amount is paid in full.
Certain covenants. The senior secured credit facilities contain covenants that:
· require Mirant North America to maintain at the end of each fiscal quarter: (i) a ratio of earnings before interest, taxes, depreciation and amortization (“EBITDA”) to interest expense of at least 2:1, and (ii) a ratio of net debt to EBITDA of not more than 6:1, in each case calculated on a rolling four fiscal quarter basis ending on the last day of such fiscal quarter;
· restrict the ability of Mirant North America and its restricted subsidiaries to incur debt other than certain permitted debt unless, the ratio of net debt to EBITDA is less than 4:1, calculated on a rolling four fiscal quarter basis ending on the last day of such fiscal quarter and after giving pro forma effect to the incurrence of the debt; and
· restrict the ability of Mirant North America and its restricted subsidiaries to make certain restricted payments, including, without limitation, (i) any dividend payments or distribution of cash or property, (ii) payments, redemption or repurchase of affiliate subordinated debt or (iii) purchase or redemption of its or its restricted subsidiaries’ capital stock subject to certain exceptions, including the ability to make payments to us to be applied to interest payments due on our senior notes maturing in 2011, 2021 and 2031, as long as there is no default or event of default and none would result therefrom.
In addition, the senior secured credit facilities contain customary covenants that restrict the ability of Mirant North America and its restricted subsidiaries to:
· engage in mergers, acquisitions and asset sales;
· incur liens and engage in sale-leaseback transactions;
· make investments and capital expenditures;
· transact with affiliates; and
· change its fiscal year.
Events of default. The senior secured credit facilities contain customary events of default, including, without limitation, payment defaults, material breach of representations and warranties, covenant defaults, cross-defaults, cross-accelerations, material judgments and certain events of bankruptcy or insolvency. In addition, the senior secured credit facilities contain the following events of default:
· Except with the written consent of a majority of the Lenders, the series A and B preferred shares issued by Mirant Americas should cease to be enforceable or rights of the holders thereof are amended or waived; and
· Mirant North America should cease to be controlled, directly or indirectly, by Mirant Corporation.
If an event of default occurs, the Lenders are entitled to accelerate the amounts owing under the senior secured credit facilities and to take all other actions permitted to be taken by a secured creditor.
Mandatory prepayments. Mirant North America is required to prepay the amounts outstanding under the senior secured term loan and to permanently reduce the commitments under the senior secured revolving credit facility with proceeds received from certain transactions, as follows:
· 100% of any net cash proceeds in excess of $50 million received from any asset sale that is not committed within 365 days thereof to acquire or repair assets useful in the business or is not so applied within 180 days thereafter; and
· 100% of any net cash proceeds from any insurance or other recovery payment in excess of $20 million received that is not committed within 365 days of the recovery event to acquire or repair assets useful in the business or is not so applied within 24 months thereafter.
In addition, Mirant North America is further required to prepay the senior secured term loan with 50% of free cash flow (less amounts paid to us for the purpose of paying interest on our senior notes) for each fiscal year (commencing with the 2006 fiscal year), provided, that the foregoing percentage shall be reduced to 25% based on the achievement and maintenance of a ratio of net debt to EBITDA of 2:1 or lower.
Senior Notes
The notes were issued by Mirant North America Escrow, LLC (“Mirant North America Escrow”) and its wholly-owned subsidiary, MNA Finance Corp. Mirant North America Escrow was a wholly-owned subsidiary of Mirant North America. Upon emergence, Mirant North America Escrow was merged with and into Mirant North America with Mirant North America as the surviving entity. Upon the consummation of the merger, Mirant North America assumed all of the obligations of Mirant North America Escrow and MNA Finance Corp. became a direct, wholly-owned subsidiary of Mirant North America. MNA Finance Corp. was formed and exists solely for the purpose of serving as a co-issuer of the notes and as a guarantor of the senior secured credit facilities.
Interest Rate; Maturity Date; Redemption Rights. The notes, which were issued in an aggregate principal amount of $850 million and bear interest at 7.375%, mature on December 31, 2013. Interest on the notes is payable on each June 30 and December 31, commencing June 30, 2006.
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.
Guarantees and ranking. The notes are guaranteed on a senior unsecured basis by certain subsidiaries of Mirant North America, each of which also guarantees the obligations under the senior secured credit facilities. Any subsidiaries that in the future guarantee any of the indebtedness of Mirant North America, including indebtedness under its senior secured credit facilities, or indebtedness of any subsidiary guarantor, will also guarantee the notes. The notes are:
· general unsecured obligations of Mirant North America and the subsidiary guarantors;
· effectively junior in right of payment to the secured debt of Mirant North America and the subsidiary guarantors to the extent of the value of the assets securing such debt;
· rank equally in right of payment with all of the existing and future unsecured unsubordinated debt of Mirant North America and the subsidiary guarantors;
· senior in right of payment to all of the existing and future senior subordinated and subordinated debt of Mirant North America and the subsidiary guarantors;
· structurally subordinated to all of the existing and future liabilities (including trade payables) of each of our subsidiaries that do not guarantee the notes; and
· structurally senior to all of the existing and future liabilities (including trade payables) of Mirant Corporation and Mirant Americas Generation to the extent of the value of the Mirant North America and its subsidiaries, including Mirant Mid-Atlantic.
Certain covenants. The notes are issued under an indenture with Law Debenture Trust Company of New York, as trustee (the “Trustee”). The indenture limits the ability of Mirant North America and its restricted subsidiaries to:
· incur, assume or guarantee additional indebtedness;
· issue redeemable stock and preferred stock;
· repurchase capital stock;
· make other restricted payments including, without limitation, paying dividends and making investments;
· create liens;
· redeem debt that is junior in right of payment to the notes;
· sell or otherwise dispose of assets, including capital stock of subsidiaries;
· enter into agreements that restrict dividends from subsidiaries;
· merge, consolidate or sell or otherwise dispose of all or substantially all of our assets;
· enter into transactions with affiliates;
· guarantee indebtedness;
· enter into sale/leaseback transactions; and
· enter into new lines of business.
These covenants are subject to a number of important exceptions and qualifications and certain covenants may be suspended in the event Mirant North America achieves and maintains an investment grade credit rating.
Mirant Mid-Atlantic Operating Leases
Mirant Mid-Atlantic leases the Morgantown and Dickerson baseload units and associated property through 2034 and 2029, respectively, and 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. Rent expenses associated with the Morgantown and Dickerson operating leases totaled approximately $99 million, $103 million and $96 million for the years ended December 31, 2005, 2004 and 2003, respectively. While there is variability in the scheduled payment amounts over the lease term, the Company recognizes rental expense for these leases on a straight-line basis. The rental expense based on the original scheduled rent payments is $96 million per year. The additional expense recorded in 2004 and 2005 was payable under the terms of the leases and was commensurate with the 0.5% increase in interest on the lessor notes that was payable by the lessors for the period in which Mirant Mid-Atlantic was not a reporting entity under the Securities Exchange Act of 1934. As of December 31, 2005 and 2004, Mirant Mid-Atlantic had paid approximately $292 million and $285 million, respectively, of actual operating lease payments in accordance with the lease agreements in excess
of rent expense recognized. In addition to the regularly scheduled rent payments, Mirant Mid-Atlantic paid an additional $11 million in 2004, as required by the lease agreements. A further $12 million of scheduled rent due on June 30, 2005, was funded through a draw made by the lease trustee on letters of credit arranged by the Company. In September 2005, the lease trustee made an additional draw of $49 million prior to the expiration of the letters of credit in September 2005. This amount is recorded in funds on deposit in the combined and consolidated balance sheets. On January 3, 2006, as part of the settlement and emergence from bankruptcy, Mirant North America posted a $75 million letter of credit for the benefit of Mirant Mid-Atlantic to cover the debt service reserve obligation on the leases. Upon posting of the letter of credit, the trustee returned $56 million of cash collateral held to Mirant Mid-Atlantic.
As of December 31, 2005, the total notional minimum lease payments for the remaining term of the leases aggregated approximately $2.4 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 that purchased the baseload units from PEPCO. These owner lessors each own the undivided interests in the 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 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 leased facilities and its rights under the related lease and other financing documents.
Certain covenants. The operative documents relating to the Mirant Mid-Atlantic leveraged leases contain certain restrictive covenants, including the following:
Limitations on restricted payments. Mirant Mid-Atlantic cannot make any of the following restricted payments (subject to certain narrow, specifically identified exceptions):
· distributions in respect of equity interests in Mirant Mid-Atlantic (in cash, property, securities or obligations other than additional equity interests of the same type);
· payments or distributions on account of payments of interest, the setting apart of money for a sinking or analogous fund for, or the purchase or redemption, retirement or other acquisition of any portion of any equity interest in Mirant Mid-Atlantic or of any warrants, options or other rights to acquire any such equity interest (or make payments to any person such as phantom stock payments, where the amount of the payment is calculated with reference to fair market or equity value of Mirant Mid-Atlantic); or
· payments on or with respect to the purchase, redemption, defeasance or other acquisition or retirement for value of any subordinated indebtedness;
unless, at the time of and after giving effect to the restricted payment, no significant lease default or lease event of default has occurred and is continuing and Mirant Mid-Atlantic: (1) can satisfy a fixed charge coverage ratio on a historical basis for the last period of four full fiscal quarters; and (2) is projected to satisfy a fixed charge coverage ratio for the next two periods of four full fiscal quarters.
Mirant Mid-Atlantic assumed the leveraged leases pursuant to, and in accordance with, the treatment of such leases in the Plan. With respect to the assumption of the leveraged leases, the Plan provisions
included: (i) an agreement not to issue additional lessor notes unless Mirant Mid-Atlantic is rated BBB-/Baa3 or it has a fixed charge coverage ratio of at least 2.5:1 and the owner lessors consent; (ii) the contribution of Mirant Peaker and Mirant Potomac River to Mirant Chalk Point, LLC. (“Mirant Chalk Point”); (iii) the issuance of the Mirant Americas Series A Preferred Shares to Mirant Mid-Atlantic; and (iv) certain payments to the parties to the leveraged leases, including $6.5 million to the holders of the pass through trust certificates, $6.5 million to the owner lessors, $2.9 million as restoration payments under the leases, and approximately $22 million of professional fees of the lease parties. The $6.5 million paid to the Indenture Trustee for the benefit of the holders of the pass through certificates was paid in January 2006. The other payments were made in December 2005.
In addition, the Plan provided that certain interpretations of, and amendments to, the Mirant Mid-Atlantic leveraged lease documentation are binding upon the parties to the leveraged leases. The interpretations and amendments, which are focused primarily on the calculation of the fixed charge coverage ratio for purposes of the restricted payments test, clarify (i) under which circumstances Mirant Mid-Atlantic may eliminate from the calculation of the fixed charge coverage ratio capital expenditures made, or projected to be made, with respect to the leased facilities, (ii) that Mirant Mid-Atlantic may, in calculating the coverage ratio for the periods prior to emergence from Chapter 11, treat capital expenditures financed with cash previously generated and retained during an earlier period as being made in such earlier period and, thus, eliminated in the calculation for the period being measured, (iii) that Mirant Mid-Atlantic may eliminate from the calculation of the fixed charge coverage ratio capital expenditures made, or projected to be made, with the proceeds of the Mirant Americas Series A Preferred Shares and similar arrangements, subject to certain conditions, and (iv) that, in determining ‘‘Consolidated EBITDA’’ (as defined in the leveraged lease documentation), all adjustments to reconcile net income to net cash provided by (used in) operating activities, excluding changes in operating assets and liabilities, as disclosed in (or projected to be included in) the cash flow statement of Mirant Mid-Atlantic are to be excluded. As of December 31, 2005, and incorporating the interpretations and amendments referred to above, Mirant Mid-Atlantic would have met the restricted payments test.
Limitation in incurrence of indebtedness. Neither Mirant Mid-Atlantic nor any of its subsidiaries (other than Mirant Potomac River and Mirant Chalk Point, each of which are defined as a “Designated Subsidiary”) may incur or assume any indebtedness other than “Permitted Indebtedness,” nor may Mirant Mid-Atlantic permit any Designated Subsidiary to incur or assume any debt other than Designated Subsidiary Permitted Indebtedness. Based on those prohibitions, generally, (1) the only indebtedness Mirant Mid-Atlantic and its subsidiaries (other than the Designated Subsidiaries) may incur is as follows:
· any indebtedness, if, after taking into account the incurrence of such indebtedness, both S&P and Moody’s confirm their respective ratings of the pass through certificates outstanding prior to incurring the indebtedness, and there is no event of default outstanding under the leases;
· indebtedness incurred for working capital purposes;
· indebtedness relating to letters of credit, surety bonds or performance bonds or guarantees issued in the ordinary course of business;
· indebtedness meeting the definition of ‘‘Subordinated Indebtedness’’;
· indebtedness not to exceed $100 million in the aggregate for principal, less the aggregate principal amount of indebtedness incurred as set forth in operative documents;
· indebtedness represented by ‘‘Interest Rate Hedging Transactions’’ entered into in the ordinary course of business;
· indebtedness secured by a pre-existing lien on any assets acquired by Mirant Mid-Atlantic, so long as the indebtedness is recourse only to those assets and not to the general credit of Mirant Mid-Atlantic;
· with regard to subsidiaries other than the Designated Subsidiaries, the indebtedness is Non-Recourse Indebtedness (as defined in the operative documents);
· any intercompany loans;
· indebtedness incurred to finance capital expenditures made to comply with law or to finance ‘‘Required Improvements’’ as defined in the Facility Lease Agreements;
· indebtedness incurred to refinance permitted existing indebtedness, provided that period of repayment is not shorter than the original debt and the principal of the new debt does not exceed the refinanced debt except for a reasonable premium as the cost of the refinancing; or
· indebtedness guaranteed by Mirant or one or more direct or indirect parents of Mirant Mid-Atlantic, provided that each of such guarantors has a sufficiently high credit rating as set forth in the operative documents;
and (2) the only indebtedness that the Designated Subsidiaries may incur is essentially the same types of indebtedness as Mirant Mid-Atlantic is permitted to incur except that the tests are applied with regard to the applicable Designated Subsidiary, and that each Designated Subsidiary is limited by a sub-cap of $50 million in connection with the overall permission given to Mirant Mid-Atlantic and its subsidiaries to incur $100 million of debt in the aggregate, and the Designated Subsidiaries do not have a separate category of Designated Subsidiary Permitted Indebtedness for working capital purposes, for ‘‘Subordinated Indebtedness,’’ or indebtedness represented by ‘‘Interest Rate Hedging Transactions,’’ for indebtedness incurred to refinance permitted existing indebtedness, nor for indebtedness guaranteed by Mirant or one or more direct or indirect parents of Mirant Mid-Atlantic.
Limitation on merger and consolidation or sale of substantially all assets. Mirant Mid-Atlantic is not permitted to, nor may it permit the Designated Subsidiaries to, consolidate or merge with or into any other entity, or sell, lease or otherwise dispose of all or substantially all of its properties or assets to any person or entity except that, if, after giving effect thereto, no lease event of default occurs, (a) any Designated Subsidiary may merge into Mirant Mid-Atlantic or into any other Designated Subsidiary, and (b) Mirant Mid-Atlantic or any Designated Subsidiary may merge into another entity or may sell its assets to another entity if the surviving entity (if it is an entity other than Mirant Mid-Atlantic or a Designated Subsidiary) meets certain criteria and expressly assumes all of the obligations of Mirant Mid-Atlantic or the applicable Designated Subsidiary, as the case may be, under the applicable documents.
Limitations on sale of assets. Mirant Mid-Atlantic is not permitted to, nor may it permit any Designated Subsidiary to, sell any assets other than those that fall within the definition of ‘‘Permitted Asset Sales’’ set forth in the operative documents.
Restrictions on liens. Mirant Mid-Atlantic is not permitted to, nor may it permit any Designated Subsidiary to, create, incur, assume or otherwise suffer to exist any liens on its respective assets, other than those that fall within the definition of ‘‘Permitted Encumbrances’’ set forth in the operative documents.
Assignment and sublease. Without the consent of other parties to the operative documents, Mirant Mid-Atlantic cannot assign or sublease its interest under a facility lease unless certain requirements are met.
Uses of Funds
Our requirements for liquidity and capital resources, other than for the day-to-day operation of our generation facilities, are significantly influenced by two activities: (i) the hedging and proprietary trading activities of Mirant Energy Trading and (ii) capital expenditures required to keep our power generation facilities in operation.
Collateral requirements. The asset hedging and, to a lesser extent, proprietary trading activities of Mirant Energy Trading, represent a significant need for liquidity and capital resources. These liquidity requirements are primarily driven by margin and collateral posting requirements with counterparties and disbursement and receipt timing (i.e., buying fuel before receiving energy revenues). As of December 31, 2005, we had approximately $685 million of posted cash collateral and $56 million of letters of credit outstanding primarily to support our asset hedging activities and debt service reserve requirements. 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. We do not assume that we will be provided with unsecured credit from third parties when budgeting our working capital requirements.
Capital Expenditures. Capital expenditures were $100 million, $89 million and $151 million for the years ended December 31, 2005, 2004 and 2003, respectively. Our capital expenditures for 2006 are expected to be approximately $300 million. For a more detailed discussion of environmental expenditures we expect to incur in the future, see “Item 1. Business”.
Debt service. At December 31, 2005, we had approximately $2.6 billion of long-term debt and had an additional $700 million as of March 3, 2006. Our expected annual interest expense is approximately $212 million. Under the terms of its senior secured term facility, Mirant North America is required to use 50% of its free cash flow for each fiscal year (less amounts paid to us for the purpose of paying interest on our senior notes) to pay down its senior secured term loan, in addition to our scheduled amortization of approximately $7 million per year. The percentage of free cash flow that Mirant North America is required to use to pay down its senior secured term loan may be reduced to 25% upon the achievement by it of a net debt to EBITDA ratio of less than 2:1.
Debtor-in-Possession Financing for New York Subsidiaries
We entered into an agreement (the ‘‘New York DIP Agreement’’) to make secured debtor-in-possession financing in an amount of (i) $20 million, plus (ii) an amount equal to the amount of credit support provided on behalf of Mirant New York, Mirant Bowline, Mirant Lovett, and Hudson Valley Gas Corporation (collectively, the ‘‘New York DIP Borrowers’’), to the extent such amounts are collateralized with cash or cash equivalents by the New York DIP Borrowers. The facility is available on a joint and several basis to the New York DIP Borrowers. On January 31, 2006, all the assets of Mirant Americas Energy Marketing were transferred to Mirant Energy Trading, with Mirant Energy Trading to succeed to all rights and assume all obligations of Mirant Americas Energy Marketing under the New York DIP Agreement. The financing under the New York DIP Agreement can be utilized through borrowings by the New York DIP Borrowers, the issuance of letters of credit for the account of any of the New York DIP Borrowers or in support of commercial transactions entered into by Mirant Energy Trading for the benefit of the New York DIP Borrowers, the posting of cash in respect of obligations incurred for the benefit of any of the New York DIP Borrowers, including the making of prepayments for fuel and other commodities for the benefit of any of the New York DIP Borrowers. Under the New York DIP Agreement, the amount which represents the excess on the effective date of the Plan of (x) credit support posted for the benefit of the New York DIP Borrowers by the lenders in respect of transactions entered into on their behalf over (y) the amount of cash collateral posted by the New York DIP Borrowers to the lenders is deemed to be a loan made to the New York DIP Borrowers on such date. The New York DIP Borrowers have posted $16.1 million cash collateral with Mirant Energy Trading in accordance with the February 28, 2006, collateral allocation performed in good faith by Mirant Energy Trading. To the extent that the required level of credit support provided to the New York DIP Borrowers is reduced, the amount of such reduction is required to be returned to the New York DIP Borrowers. The financing under the New York DIP Agreement has a stated maturity of 180 days, subject to renewal or extension, and is available until the earlier of (x) the expiration of such period or (y) with respect to each of the New York DIP Borrowers, the
effective date of a confirmed plan of reorganization for such New York DIP Borrower in its Chapter 11 case. Subject to the authorization of the Bankruptcy Court, the obligations of the New York DIP Borrowers under the New York DIP Agreement, pursuant to Section 364(c) of the Bankruptcy Code, (i) constitutes a claim having priority over any or all administrative expenses of the kind specified in sections 503(b) or 507(b) of the Bankruptcy Code, (ii) is secured by a lien on property of the estates of the New York DIP Borrowers that is not otherwise subject to a lien and (iii) is secured by a junior lien on property of the estates of the New York DIP Borrowers that is subject to a lien. The financing bears interest at a rate to be determined and to be subject to Bankruptcy Court approval. The New York DIP Agreement contains certain events of default, and the ability of the New York DIP Borrowers to borrow thereunder is subject to certain conditions precedent. In addition, the New York DIP Agreement contains covenants that, among other things, restrict the ability of the New York DIP Borrowers to engage in mergers, acquisitions and asset sales, to make investments and to incur indebtedness.
Cash Flows
Cash used in operating activities increased $41 million for the year ended December 31, 2005, compared to the same period in 2004. Our cash used in operating activities is volatile as a result of seasonality, changes in energy prices and fluctuations in our working capital requirements. Most notably, when we enter into transactions to economically hedge our expected generation output or fuel requirements and those positions move out-of-the money, we are required to post cash collateral due to our credit rating.
2005 Cash Flow
Operating Activities
Net cash provided by operating activities excluding the changes in operating assets and liabilities was $61 million for the year ended December 31, 2005. This was primarily due to the following:
· Our gross margin in 2005 excluding unrealized gains and losses and the non-cash revenue related to the TPA amortization was $893. This amount was substantially offset by operating and maintenance expenses of $590 million and $99 million of rent expense for our leased generation facilities.
· In 2005 we had cash expenses related to the bankruptcy of $103 million
See “Results of Operations” section of Item 7. Management’s Discussion and Analysis for further discussion.
In 2005, changes in operating assets and liabilities required $253 million in cash. We posted an additional $278 million of cash collateral with counterparties and brokers in 2005. Other changes in operating assets and liabilities were a net source of $25 million in 2005. Of this amount, approximately $25 million related to property taxes recognized but not paid in the year.
Investing Activities
In 2005, we had capital expenditures of $100 million primarily related to our Mid-Atlantic facilities and received $48 million from the sale of our investment in a company that provides an electronic commerce platform for the purchase and sale of energy commodities and $4 million related to the 2004 sale of the Bowline turbines.
Financing Activities
In 2005, financing activities provided $18 million in cash as a result of proceeds from the issuance of debt of $21 million less $3 million in cash to repay debt related to our capital lease obligations at the Peaker and Zeeland generating facilities.
2004 Cash Flow
Operating Activities
Net cash used by operating activities excluding the changes in operating assets and liabilities was $98 million for the year ended December 31, 2004. This was primarily due to the following:
· Our gross margin in 2004 excluding unrealized gains and losses and the non-cash revenue related to the TPA amortization was $617 million. This amount was more than offset by operating and maintenance expenses of $681 million excluding a bad debt recovery of $10 million.
· In 2004 we had cash expenses related to the cost of bankruptcy of $60 million and paid interest on Mirant Debtor debts of $13 million. The lower interest payments in 2004 compared to 2003 are due to the bankruptcy filing in July 2003.
In 2004, working capital changes, which are reflected as changes in operating assets and liabilities, required $53 million in cash. This was primarily due to the following:
· Net collateral uses to support commercial operations in 2004 were $77 million. This is favorable compared to 2003 due to the decrease in asset related fuel purchases in 2004 and favorable market movements in power and economic fuel hedging in 2004 compared to 2003, and
· Other working capital sources were $24 million in 2004. Other working capital sources were primarily due to decreases in accounts receivables from energy contracts settled early by counterparties as a result of our Chapter 11 filings of $54 million and increases in accounts payable to affiliate of $117 million. The increase in accounts payable to affiliate was primarily due to letters of credit being drawn upon by counterparties and banks for the energy trading business through Mirant partially offset by settlements related to Mirant’s discontinued Canadian trading operations. Other working capital requirements for 2004 relate primarily to increases in inventories of $63 million due to rising commodity prices, primarily SO2 allowances used in our Mid-Atlantic power plants and decreases in accounts payable of $104 million related to contract settlements.
Investing activities: Net cash provided by investing activities totaled $280 million in 2004. In 2004 Mirant repaid Mirant Americas Energy Marketing $326 million in notes receivable. In 2004, the proceeds from the sale of the Bowline unit 3 turbines were $42 million offset by capital expenditures of $89 million.
Financing activities: Net cash provided by financing activities was $4 million in 2004. We received $7 million from Mirant Americas under the make-whole contract. In 2004, we repaid long-term debt of $3 million related to our capital lease obligation at the Peaker and Zeeland generation facilities.
2003 Cash Flow
Operating Activities. Net cash used in operating activities, excluding the effects of working capital, was $39 million in 2003. This was primarily due to the following:
· Our gross margin in 2003 excluding unrealized gains and losses and the non-cash revenue related to the TPA amortization was $814 million. This amount was offset by operating and maintenance expenses of $616 million excluding a bad debt expense of $32 million.
· In 2003 we paid interest on Mirant Debtor debts of $159 million.
In 2003, working capital changes, which are reflected as changes in operating assets and liabilities, required $99 million in cash. This was primarily due to the following:
· Net collateral uses to support commercial operations in 2003 were $149 million. The posted additional cash collateral with counterparties primarily related to energy contract positions, and
· Other working capital sources of $50 million in 2003. Other working capital sources were primarily due to decreases in accounts receivables from energy contracts settled early by counterparties as a result of our Chapter 11 filings of $317 million and increases in accounts payable to affiliate of $31 million. The $31 million increase in accounts payable to affiliate was primarily due to letters of credit being drawn upon by counterparties and banks for the energy trading business through Mirant partially offset by payments to Mirant Services. Other working capital requirements for 2003 relate primarily to the decreases in accounts payable of $170 million, decreases in other liabilities of $65 million primarily related to the Enron bankruptcy proceedings and increases in prepaid rent of $68 million related to lease payments on Dickerson and Morgantown facilities.
Investing activities: Net cash used in investing activities totaled $189 million in 2003. In 2003, we had an increase in notes receivable from affiliate of $376 million and $151 million of capital expenditures primarily related to our Mid-Atlantic, New York and Zeeland facilities. We received cash from the repayment of notes receivable of $58 million and received proceeds from the sale of our Neenah plant in Wisconsin of $109 million and the sale of Mirant Americas Energy Capital assets of $161 million.
Financing activities: Net cash provided by financing activities was $528 million in 2003. In 2003 capital contributions received were $439 million and dividends paid were $347 million. We received $315 million and paid $29 million in return of capital from Mirant Americas under the make-whole contract. Additionally, we received $285 million from issuance of notes payable to affiliate in 2003. We had proceeds from issuance of debt related to our energy marketing business of $7 million and repaid long-term debt of $100 million related to Mirant Americas Energy Capital, $29 million related to Mirant Americas Development Capital and $13 million related to our capital lease obligations at the Peaker and Zeeland generation facilities.
Debt Obligations, Off-Balance Sheet Arrangements and Contractual Obligations
At December 31, 2005, our debt obligations, off-balance sheet arrangements and contractual obligations were as follows (in millions):
Operating leases are off-balance sheet arrangements primarily related to our minimum lease payments associated with our lease of the Morgantown and Dickerson baseload units. See Note 16 to our combined and consolidated financial statements contained elsewhere in this report.
Long-term debt includes the current portion of long-term debt and long-term debt on the combined and consolidated balance sheets. Long-term debt also includes interest assuming no refinancing. In
addition to the amounts shown above, on January 3, 2006, Mirant North America entered into an $800 million senior secured revolving credit facility and a $700 million senior secured term loan. The annual scheduled maturities and interest accrued on the $700 million senior secured term loan are: $53 million for 2006, $52 million for 2007, $52 million for 2008, $51 million for 2009, $51 million for 2010 and $752 million for 2011 and thereafter. The draws on the $800 million senior secured revolving credit facility were repaid in January and February 2006. See Note 11 to our combined and consolidated financial statements for further discussion.
Long-term service agreements represent our total estimated commitments under our long-term service agreements associated with turbines installed or in storage. See Note 16 to our combined and consolidated financial statements for further discussion.
Fuel and transportation commitments relate primarily to a long-term synthetic fuel purchase agreement, coal purchase commitments for our Mid-Atlantic facilities and a fuel supply agreement with an independent third party to provide approximately 90% of the estimated coal to be burned at one of the New York facilities through 2005. In the first quarter of 2006, we entered into additional significant coal commitments. See Note 16 to our combined and consolidated financial statements for further discussion.
The company had total minimum commitments under the fuel and transportation agreements of $513 million at December 31, 2005.
Other purchase commitments represent the 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 generation facilities. We entered into an agreement on June 24, 2005 for an SCR System at the Morgantown generating station. The system will be furnished and installed to comply with a State of Maryland environmental consent decree to reduce the emissions of NOx. The contract value of this capital expenditure is approximately $94 million. Payments are made monthly upon acceptance of project milestones with the final payment scheduled for June of 2008. Mirant Services entered into an agreement on February 10, 2006 for an equipment agreement at the Potomac River Generating station. The equipment shall be furnished and supplied to disperse emissions which will exceed State of Virginia environmental requirements. The contract value of this capital expenditure is approximately $6 million. Payments shall be made upon acceptance of project milestones with the final payment scheduled for December of 2006.
At December 31, 2005, liabilities subject to compromise relate only to our New York subsidiaries that remain in bankruptcy. See Note 3 to our combined and consolidated financial statements for further discussion.
Critical Accounting Policies and Estimates
The accounting policies described below are considered critical to obtaining an understanding of our combined and consolidated financial statements because their application requires significant estimates and judgments by management in preparing our combined and consolidated financial statements. Management’s estimates and judgments are inherently uncertain and may differ significantly from actual results achieved. It is our view that the following critical accounting policies and the underlying estimates and judgments involve a higher degree of complexity than others do. We discussed the selection of and application of these accounting policies with our Board of Managers and our independent auditors.
Fresh Start Applicability
In connection with our emergence from bankruptcy, we would be required under Statement of Position 90-7, “Financial Reporting by Entities in Reorganization under the Bankruptcy Code” (“SOP 90-7”) to adopt fresh start reporting under certain conditions. Fresh start reporting requires the debtor to use
current fair values in its balance sheet for both assets and liabilities and to eliminate all prior earnings or deficits. The two requirements to fresh start reporting are:
· the reorganization value of the company’s assets immediately before the date of confirmation of the plan of reorganization is less than the total of all post-petition liabilities and allowed claims; and
· the holders of existing voting shares immediately before confirmation receive less than 50% of the voting shares upon emergence.
We refer to these requirements as the “fresh start applicability test.” For purposes of applying the fresh start applicability test, reorganization value is defined in the glossary of SOP 90-7 as “the value attributed to the reconstituted entity, as well as the expected net realizable value of those assets that will be disposed before reconstitution occurs. Therefore, this value is viewed as the fair value of the entity before considering liabilities and approximates the amount a willing buyer would pay for the assets of the entity immediately after the restructuring.”
In most bankruptcy proceedings, the reorganization value is determined through the court process; it is either negotiated by the parties or ordered by the court if the parties cannot agree to a value. In the bankruptcy proceedings of the Mirant Debtors, no Mirant reorganization value was determined by the Bankruptcy Court or agreed upon by the parties.
In order to determine the reorganization value of Mirant for purposes of the fresh start applicability test, Mirant employed a market-based approach that incorporates the trading value of the Mirant Debtors’ publicly traded debt and equity securities in the days preceding the confirmation date of the Plan. Mirant deemed that this approach is appropriate as it is an objective and timely measurement of the fair value of Mirant. Mirant disclosed this intended approach in Exhibit “D” of the Disclosure Statement, which was approved by the Bankruptcy Court and used to solicit votes on the Plan.
The calculation of the reorganization value included the averaging of the trading value of Mirant’s publicly traded debt and equity securities for the three days preceding the confirmation of the Plan on December 9, 2005. The trading values of debt were obtained through independent broker quotes for both Mirant and Mirant Americas Generation. These prices were used to determine an implied value for their respective claim classes, as both public and private claims within each claim class receive identical treatment under the Plan. Then, the market value of Mirant’s trust preferred securities and its common equity were added to the calculation.
In order to obtain an indication of total value of Mirant’s debt and equity, debt of non-bankrupt subsidiaries was included, as well as adjustments for items representing debt obligations that were not otherwise included in Mirant’s claims. Finally, the total reorganization value of Mirant’s assets was derived by adding non-interest bearing liabilities to the fair value of Mirant’s debt and equity securities described above.
The result of the calculation indicated that Mirant and the Company, were not allowed to adopt fresh start reporting because the reorganization value of Mirant immediately prior to the confirmation date exceeded the total of post-petition liabilities and allowed claims. As a result, Mirant’s, and the Company’s assets and liabilities were not adjusted to fair value; but rather liabilities compromised by the Plan were stated at present values of amounts to be paid and forgiveness of debt was reported as an extinguishment of debt in accordance with SFAS No. 145, “Rescission of FASB Statements No. 4, 44 and 64; Amendment of FASB Statement 13; and Technical Corrections,” (“SFAS No. 145”).
The applicability test of fresh start reporting was sensitive to changes in the price of the securities, and a decrease of approximately 2% in the average price of the securities for the period measured would have resulted in the requirement for Mirant and the Company to adopt fresh start reporting. The adoption of fresh start reporting would have had a material impact on our balance sheet at December 31, 2005, as well as succeeding statements of operations. Under fresh start reporting, our assets and liabilities would be stated at fair value, including our power generation facilities and identifiable intangible assets such as
emissions allowances and energy contracts. The depreciation and amortization associated with these assets would also differ materially from our historical combined and consolidated financial statements. In addition, our accumulated deficit would have been eliminated. Therefore, the successor Company under fresh start reporting would not have been comparable to the predecessor Company prior to the application of fresh start reporting.
See Note 3 to our combined and consolidated financial statements for further information on our accounting while in bankruptcy.
Accounting for Energy Trading and Marketing Activities
Our business uses derivatives and other energy contracts to economically hedge our electricity generation and to engage in proprietary trading activities. We use a variety of derivative contracts, such as futures, swaps, forwards 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 No. 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. The fair value of such contracts is included in price risk management assets and liabilities-affiliate and price risk management assets and liabilities-nonaffiliate in our combined and consolidated balance sheets. A limited number of transactions do not meet the definition of a derivative or are considered normal purchases or normal sales, a permissible scope exception under SFAS No. 133. Thus, such transactions qualify for the use of accrual accounting.
Determining the fair value of derivatives involves significant estimates based largely on the mid-point of quoted market prices. 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. Our modeling techniques include assumptions for market prices, correlation and volatility, such as using the prices of one delivery point to calculate the price of the contract’s delivery point. 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 price risk management assets and liabilities-nonaffiliate in our combined and consolidated balance sheets are also impacted by our assumptions such as interest rate, counterparty credit risk and liquidity risk. The nominal value of the contracts is discounted using a forward interest rate curve based on the LIBOR. In addition, the fair value of our derivative contracts is reduced to reflect the estimated risk of default of counterparties on their contractual obligations to us.
The amounts recorded as revenues-affiliate and nonaffiliate and as cost of fuel, electricity and other products-affiliate and nonaffiliate 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 No. 133, our financial statements-including gross margin, operating income and balance sheet ratios-are, at times, volatile and subject to fluctuations in value primarily due to changes in energy and fuel prices.
Due to the complexity of the models used to value the derivative instruments, a significant change in estimate could have a material impact on our results of operations.
See Note 7 to our combined and consolidated financial statements for further information on financial instruments related to energy trading and marketing activities.
Income Taxes
We are a limited liability company treated as a branch for income tax purposes. As a result, Mirant Americas, Inc. (“Mirant Americas”) and Mirant have direct liability for the majority of the federal and state income taxes relating to the Company’s operations. We have allocated current and deferred income taxes to each regarded corporate member entity of our consolidated group as if each regarded corporate entity member 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, we have not recorded current period tax benefits on each regarded corporate entity’s ability to carry back its separate company current year net operating loss as realization of such losses were dependent on reimbursements from Mirant, at Mirant’s discretion under the tax sharing agreement. Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and net tax operating losses and tax credit carryforwards. 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 were recognized in income in the period that included the enacted change.
Several significant changes to our tax posture occurred as a result of the Plan. Implementation of the Plan included the conversion of certain of our 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 our 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 have been eliminated as of December 31, 2005. Certain of our other subsidiaries continue to exist as regarded corporate entities for income tax purposes, including Mirant New York, Inc., Hudson Valley Gas Corporation, Mirant Kendall, LLC and Mirant Special Procurement, Inc.
In December 2005, pursuant to the Plan, Mirant rejected and thereby eliminated 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, our 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, with the exception of income tax payables and receivables related to Mirant New York, Inc. which continues to remain in bankruptcy at December 31, 2005.
Asset Impairments
We evaluate our long-lived assets (property, plant and equipment) and definite-lived intangibles for impairment whenever indicators of impairment exist or when we commit to sell the asset. SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,”(SFAS No. 144”) requires management to recognize an impairment charge if the sum of the undiscounted expected future cash flows from a long-lived asset or definite-lived intangible is less than the carrying value of that asset. The amount of an impairment charge is calculated as the excess of the asset’s carrying value over its fair value, which generally represents the discounted expected future cash flows from that asset or in the case of assets we expect to sell, at fair value less costs to sell.
The determination of impairment requires management to apply judgment in estimating future energy prices, environmental and other maintenance expenditures and other cash flows. Our estimates of the fair value of the assets include significant assumptions about the timing of future cash flows, remaining useful lives and selecting a discount rate that reflects the risk inherent in future cash flows.
These estimates and assumptions are subject to a high degree of uncertainty. If actual results are not consistent with the assumptions used in estimating future cash flows and asset fair values, we may be exposed to additional losses that could be material to our results of operations.
Asset Retirement Obligations
We account for asset retirement obligations under SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”) and under FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143” (“FIN 47”). SFAS No. 143 requires an entity to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. FIN 47 expanded on SFAS 143 to include conditional asset retirement obligations that should be recorded when estimable. Upon initial recognition of a liability for an asset retirement obligation, the Company capitalizes an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. The liability is accreted to its present value and the capitalized cost is depreciated over the useful life of the related asset. Asset retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 and FIN 47 are those obligations for which a requirement exists under enacted laws, statutes and written or oral contractions, including obligations arising under the doctrine of promissory estoppel.
We have identified certain asset retirement obligations within our power generation operations. These asset retirement obligations are primarily related to asbestos abatement at some of our generating facilities, equipment on leased property and other environmental obligations related to the closing of ash disposal sites.
Liabilities associated with asset retirement obligations are estimated by applying a present value calculation to current engineering cost estimates of satisfying the obligations. Significant inputs to the present value calculation include current cost estimates, estimated asset retirement dates and appropriate discount rates. Where appropriate, multiple cost and/or retirement scenarios have been weighted. We update liabilities associated with asset retirement obligations as significant assumptions change or as relevant new information becomes available. However, actual future costs to satisfy asset retirement obligations could differ materially from the current recorded liabilities.
Estimated Useful Lives
The estimated useful lives of our long-lived assets are used to compute depreciation expense, future asset retirement obligations, and are also used in impairment testing. Estimated useful lives are based, in part, on the assumption that we provide an appropriate level of capital expenditures while the assets are still in operation. Without these continued capital expenditures, the useful lives of these assets could decrease significantly. Estimated lives could be impacted by such factors as future energy prices, environmental regulations, various legal factors and competition. If the useful lives were found to be shorter than originally estimated, depreciation expense may increase, liabilities for future asset retirement obligations may be insufficient and impairments in the carrying value of tangible and intangible assets may result.
See Note 8 to our combined and consolidated financial statements for further information on long-lived assets.
Goodwill and Indefinite-lived Intangible Assets
We evaluate our goodwill and indefinite-lived intangible assets for impairment at least annually and periodically if indicators of impairment are present. An impairment occurs when the fair value of a reporting unit is less than its carrying value including goodwill. For this test our business constitutes a single reporting
unit. The amount of the impairment charge, if an impairment exists, is calculated as the difference between the fair value of the reporting unit goodwill and its carrying value. We perform our annual assessment of goodwill at October 31 and whenever contrary evidence exists as to the recoverability of goodwill.
The accounting estimates related to determining the fair value of goodwill require management to make assumptions about cost of capital, future revenues, operating costs and forward commodity prices over the life of the assets. Our assumptions about future revenues, costs and forward prices require significant judgment because such factors have fluctuated in the past and will continue to do so in the future.
The results of our 2003 analysis indicated that goodwill was impaired and we recorded an impairment charge of $1,625 million, representing the entire balance of goodwill. Our fair value was determined using discounted cash flow techniques and assumptions as to business prospects using the best information available.
The critical assumptions used in our impairment analysis included the following: assumptions as to the future electricity and fuel prices, future levels of gross domestic product growth, levels of supply and demand, future operating expenditures and capital expenditure requirements, and estimates of our weighted average cost of capital.
The above assumptions were critical to the Company’s determination of the fair value of its goodwill. The combined subjectivity and sensitivity of our assumptions and estimates used in our goodwill impairment analysis could result in a reasonable person concluding differently regarding those critical assumptions and estimates.
See Note 9 to our combined and consolidated financial statements for further information on goodwill and other intangible assets.
Litigation
We are currently involved in certain legal proceedings. We estimate the range of liability through discussions with applicable legal counsel and analysis of case law and legal precedents. We record our best estimate of a loss, or the low end of our range if no estimate is better than another estimate within a range of estimates, when the loss is considered probable. As additional information becomes available, we reassess the potential liability related to our pending litigation and revise our estimates. Revisions in our estimates of the potential liability could materially impact our results of operations, and the ultimate resolution may be materially different from the estimates that we make.
See “Item 3. Legal Proceedings” and Note 14 to our combined and consolidated financial statements for further information related to our legal proceedings.
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 power generating business, we are exposed to energy commodity price risk associated with the acquisition of fuel needed to generate electricity, as well as the 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 the 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 Policies and Estimates” for a discussion of the accounting treatment for proprietary trading and asset management activities.
The financial performance of our power generation business is influenced by the difference between the variable cost of converting source 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 megawatt hour of electricity and the market value of the electricity generated is commonly referred to as the “conversion spread.” Absent the impacts 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 additional facility generation capacity 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 by the same magnitude or direction, which results in conversion spreads for a particular generation facility widening or narrowing (or becoming negative) over time.
Through our asset management activities, we enter into a variety of exchange-traded and over-the-counter 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 risk and changes in conversion spreads. These derivatives have varying terms and durations, or tenors, which range from a few days to a number of 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 required to be reflected at fair value are presented as price risk management assets and liabilities-affiliate and price risk management assets and liabilities-nonaffiliate in the accompanying combined and 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 over-the-counter market price quotations, time value, credit quality, liquidity and volatility factors underlying options and contracts.
The volumetric weighted average maturity, or weighted average tenor, of the price risk management portfolio at December 31, 2005, was seven months. The net notional amount, or net short position, of the price risk management assets and liabilities-affiliate and price risk management assets and liabilities-nonaffiliate at December 31, 2005 was approximately 8 million equivalent MWh. These amounts do not include the impact of the financial swap transactions entered into by Mirant Mid-Atlantic in January 2006.
The fair values of our price risk management assets and liabilities-affiliate and price risk management assets and liabilities-nonaffiliate, net of credit reserves, as of December 31, 2005, are included in the following table (in millions):
Value at Risk
Effective November 5, 2003, our Risk Management Policy prohibits the trading of certain products (e.g., natural gas liquids and pulp and paper) and contains limits related to our asset management and
proprietary trading activities. Our Risk Management Policy establishes a value-at-risk (“VaR”) limit with respect to our proprietary trading activities of $7.5 million. There is no VaR limit with respect to our asset management activities, as these activities are only allowable if they reduce the commodity price exposure of our generation assets. We manage the market risks associated with our asset management activities in conjunction with the physical generation assets that they are designed to economically hedge. As a result, our asset management portfolio is not included for purposes of compliance with our Risk Management Policy.
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.
Mirant North America’s $800 million senior secured revolving credit facility and $700 million senior secured term loan provide for a variable rate of interest. If both facilities were fully drawn, a 1% per annum increase in the average market rate would result in an increase in our annual interest expense of approximately $8 million and $7 million, respectively.
Market Risk Management
We manage the price risk associated with price risk management activities through a variety of methods. To ensure that hedge positions are risk reducing in nature, we measure the impact of each price risk management transaction executed relative to our overall asset position, including previously executed hedge transactions that such price risk management transaction is designed to hedge. See “Item 7. Critical Accounting Policies and Estimates” for accounting treatment for price risk management activities.
Credit Risk
Credit risk represents the loss that we would incur if a counterparty failed to perform under its contractual obligations. 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. We measure credit risk as the loss we would record if our customers failed to perform pursuant to the terms of their contractual obligations less the value of collateral held by us, if any, to cover such losses. 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 Americas Generation, LLC:
We have audited the accompanying consolidated balance sheet of Mirant Americas Generation, LLC (a wholly-owned indirect subsidiary of Mirant Corporation) and subsidiaries (the “Company”) as of December 31, 2005, and the combined balance sheet of the Company as of December 31, 2004, and the related combined statements of operations, equity (deficit) and comprehensive loss and cash flows for each of the years in the three-year period ended December 31, 2005. These combined and consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these combined and consolidated 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 combined and consolidated financial statements referred to above present fairly, in all material respects, the financial position of Mirant Americas Generation, LLC and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.
As discussed in Notes 1, 2, 3 and 4 to the combined and consolidated financial statements, on December 9, 2005, the United States Bankruptcy Court for the Northern District of Texas, Fort Worth Division confirmed Mirant Corporation’s Plan of Reorganization (the “Plan”). The Plan became effective on January 3, 2006 and the Company emerged from Chapter 11 of Title 11 of the U.S. Bankruptcy Code. In connection with the provisions of the Plan, Mirant Corporation contributed certain net assets to the Company, with effect from December 31, 2005, resulting in a change in reporting entity under Accounting Principles Board Opinion No. 20, Accounting Changes; accordingly, the Company has restated the financial statements for all prior periods to reflect the financial information of the new reporting entity. The Company recorded the effects of the Plan as of December 31, 2005.
As discussed in Note 2 to the combined and consolidated financial statements, the Company adopted 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 31, 2006
MIRANT AMERICAS GENERATION, LLC AND SUBSIDIARIES
(Wholly-Owned Indirect Subsidiary of Mirant Corporation)
Combined Statements of Operations
See accompanying notes to combined and consolidated financial statements.
MIRANT AMERICAS GENERATION, LLC AND SUBSIDIARIES
(Wholly-Owned Indirect Subsidiary of Mirant Corporation)
December 31, 2005 Consolidated Balance Sheet
and
December 31, 2004 Combined Balance Sheet
See accompanying notes to combined and consolidated financial statements.
MIRANT AMERICAS GENERATION, LLC AND SUBSIDIARIES
(Wholly-Owned Indirect Subsidiary of Mirant Corporation)
Combined Statements of Equity (Deficit) and Comprehensive Loss
For the Years ended December 31, 2005, 2004 and 2003
(in millions)
See accompanying notes to combined and consolidated financial statements.
MIRANT AMERICAS GENERATION, LLC AND SUBSIDIARIES
(Wholly-Owned Indirect Subsidiary of Mirant Corporation)
Combined Statements of Cash Flows
See accompanying notes to combined and consolidated financial statements.
MIRANT AMERICAS GENERATION AND SUBSIDIARIES
NOTES TO COMBINED AND CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2005, 2004 and 2003
1. Background and Description of Business
Mirant Americas Generation, LLC, including its subsidiaries (collectively, the “Company” or “Mirant Americas Generation”), is a national independent power provider and an indirect wholly-owned subsidiary of Mirant Corporation (“Mirant”). The Company produces and sells substantially all of the output from its generating facilities in the forward and spot markets and the remainder under contracts with third parties. The Company uses derivative financial instruments, such as commodity forwards, futures, options and swaps to manage its exposure to fluctuations in electric energy and fuel prices. The Company is a Delaware limited liability company and owns or leases approximately 12,035 megawatts (“MW”) of electric generation capacity in the United States. The Company operates 72 generating units at 21 plants serving customers located near major metropolitan load centers in Maryland, California, New York, Massachusetts and Texas.
Pursuant to the Plan of Reorganization (the “Plan”), in December 2005 Mirant contributed its interest in Mirant Potomac River, LLC (“Mirant Potomac River”) and Mirant Peaker, LLC (“Mirant Peaker”) to our indirect wholly owned subsidiary Mirant Mid-Atlantic, LLC (“Mirant Mid-Atlantic”) and its interest in Mirant Zeeland, LLC (“Mirant Zeeland”) and Mirant Americas Energy Marketing, LP (“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, L.P., and Mirant Americas Gas Marketing, LLC, (collectively, the “Trading Debtors”) to Mirant North America, LLC (“Mirant North America”), a newly organized holding company subsidiary. All of the contributed subsidiaries were under the common control of Mirant and are collectively referred to as the “Contributed Subsidiaries.” Mirant’s contribution of the Contributed Subsidiaries resulted in a change in the Mirant Americas Generation reporting entity under Accounting Principles Board Opinion No. 20, “Accounting Changes”, and accordingly the Company has restated the financial statements for all prior periods to reflect the financial information of the new reporting entity. See Note 4 for further discussion. On January 31, 2006, the trading and marketing business of the Trading Debtors was transferred to Mirant Energy Trading, LLC (“Mirant Energy Trading”), a wholly-owned subsidiary of Mirant North America.
The Company has a number of service agreements for labor and administrative services with Mirant and Mirant Services, LLC (“Mirant Services”). In addition, Mirant Energy Trading, and previously Mirant Americas Energy Marketing, provides services to other Mirant affiliates related to the sale of electric power and the procurement of fuel and emissions allowances. These agreements are discussed further in Note 6.
2. Accounting and Reporting Policies
Basis of Presentation
The accompanying combined and consolidated financial statements of Mirant Americas Generation have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).
The accompanying combined and consolidated financial statements include the accounts of Mirant Americas Generation and its wholly-owned subsidiaries and the Contributed Subsidiaries as discussed in Note 1 and have been prepared from the historical records maintained by Mirant Americas Generation, its
subsidiaries and the Contributed Subsidiaries. All significant intercompany accounts and transactions have been eliminated.
For the period subsequent to July 14, 2003 (the “Petition Date”), and various dates thereafter, the accompanying combined and consolidated financial statements have been prepared in accordance with Statement of Position 90-7, “Financial Reporting by Entities in Reorganization under the Bankruptcy Code” (“SOP 90-7”). Accordingly, all pre-petition liabilities subject to compromise have been segregated in the combined and consolidated balance sheets for the years ended December 31, 2005 and 2004, and classified as liabilities subject to compromise at the estimated amounts of allowable claims. The United States Bankruptcy Court for the Northern District of Texas, Fort Worth Division (the “Bankruptcy Court”) confirmed the Plan pursuant to an order dated December 9, 2005 (the “Confirmation Order”), and waived the stay of the Confirmation Order. Accordingly, immediately upon the entry of the Confirmation Order, the terms of the Plan and Confirmation Order were deemed binding upon Mirant and 83 of its direct and indirect subsidiaries in the United States (collectively, the “Mirant Debtors”) and all other parties affected by the Plan. The Plan became effective on January 3, 2006. For financial reporting purposes, Mirant recorded the effects of the Plan on December 31, 2005. Estimated claims related to the Company’s New York operations consisting of approximately 1,672 MW including Mirant Lovett, LLC (“Mirant Lovett”), Mirant Bowline, LLC (“Mirant Bowline”) and Mirant NY-Gen, LLC (“Mirant NY-Gen”), which remain in bankruptcy, total $34 million as of December 31, 2005, and are included in liabilities subject to compromise in the consolidated balance sheet.
The implementation of the Plan resulted in, among other things, a new Mirant capital structure, the discharge of debt of the Mirant Debtors , the satisfaction or disposition of various types of claims against the Mirant Debtors, the assumption or rejection of certain contracts and the establishment of a new Mirant Board of Directors. In accordance with SOP 90-7, if the Mirant reorganization value of the assets of the emerging entity immediately before the date of confirmation is less than the total of all post-petition liabilities and allowed claims, and if the holders of existing voting shares immediately before confirmation receive less than 50 percent of the voting shares of the emerging entity, the entity must adopt fresh start reporting upon its emergence from Chapter 11. The calculation of the Mirant reorganization value included the trading value of Mirant’s debt and equity securities for the three days preceding the confirmation of the Plan on December 9, 2005.
The result of the calculation indicated that Mirant and its subsidiaries would not be allowed to adopt fresh start reporting because the Mirant reorganization value immediately prior to the confirmation date exceeded the total post-petition liabilities and allowed claims. For further discussion of fresh start reporting see “Critical Accounting Policies and Estimates”
Use of Estimates
The preparation of the combined and consolidated 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 combined and consolidated 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 liabilities resulting from the bankruptcy;
· estimating future cash flows in determining impairments of long-lived assets, goodwill and indefinite-lived intangible assets;
· estimating losses to be recorded for contingent liabilities; and
· estimating obligations related to asset retirements.
Recently Adopted Accounting Standards
In March 2005, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations: an interpretation of FASB Statement No. 143,” (“FIN 47”), which expands the scope of asset retirement obligations to be recognized under Statement of Financial Accounting Standards (“SFAS”) No. 143 “Accounting for Asset Retirement Obligations” (“SFAS No. 143”), 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, the Company capitalizes 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 fair value and the capitalized cost is depreciated over the remaining useful life of the related asset. Asset retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 and FIN 47 are those conditional and unconditional obligations for which a requirement exists under enacted laws, statutes and written or oral contractions, including obligations arising under the doctrine of promissory estoppel. For further discussion see “Cumulative Effect of Changes in Accounting Principles” below.
FIN 47 was effective for financial statements ending after December 15, 2005. At December 31, 2005, the Company recorded conditional asset retirement obligations related to the retirement of its generating facilities of $27 million. The cumulative effect of adopting FIN 47 was $16 million.
In December 2004, the FASB issued SFAS No. 153, “Exchanges of Productive Assets: an Amendment of APB Opinion No. 29,” (“SFAS No. 153”). SFAS No. 153 addresses the measurement of exchanges of certain nonmonetary assets. It amends APB Opinion No. 29, “Accounting for Nonmonetary Exchanges,” and requires that nonmonetary exchanges (except for certain exchanges of products or property held for sale in the ordinary course of business) be accounted for at the fair value of the assets exchanged, with gains or losses being recognized, if the fair value is determinable within reasonable limits and the transaction has commercial substance. The provisions of SFAS No. 153 are effective for transactions involving nonmonetary exchanges that occur in fiscal periods beginning after June 15, 2005. The Company has determined that certain exchanges of emissions allowances that the Company may periodically transact would qualify as nonmonetary exchanges under SFAS No. 153. For the year ended December 31, 2005, the Company identified certain transactions involving exchanges of emissions allowances of one vintage year for a different year. The adoption of SFAS No. 153 had no material impact on the Company’s combined and consolidated results of operations, cash flows or financial position as of December 31, 2005.
Revenue Recognition
The Company recognizes affiliate and nonaffiliate revenue when electric power is delivered, capacity is made available or ancillary services are provided to an affiliate or customer pursuant to contractual commitments that specify volume, price and delivery requirements, and collection of such revenue is probable. Some sales of energy are based on economic dispatch, or “as-ordered” by the Pennsylvania-New Jersey-Maryland Interconnection, LLC (“PJM”), based on member participation agreements, but without an underlying contractual commitment. Independent system operator (“ISO”) revenues and revenues for sales of energy based on economic-dispatch, are recorded on the basis of megawatt hour (“MWh”) delivered, at the relevant day-ahead or real-time prices. The Company also recognizes affiliate and nonaffiliate revenue when ancillary services have been performed and collection of such revenue is probable.
Derivative Financial Instruments
Derivative financial instruments are recorded in the accompanying combined and consolidated balance sheets at fair value as either price risk management assets or liabilities-affiliate or price risk management assets or liabilities-nonaffiliate, and changes in fair value are recognized currently in earnings, unless specific hedge accounting criteria are met. If the derivative is designated as a fair value
hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized currently in earnings. If the derivative is designated as a cash flow hedge, the changes in the fair value of the derivative are recorded in other comprehensive income (“OCI”) and the realized gains and losses related to these derivatives are recognized in earnings in the same period as the settlement of the underlying hedged transaction. Any ineffectiveness related to cash flow hedges is recognized currently in earnings. The assets and liabilities related to derivative instruments that have not been designated as hedges for accounting purposes are included in price risk management assets and liabilities-affiliate and price risk management assets and liabilities-nonaffiliate. For the years ended December 31, 2005, 2004 and 2003, the Company did not have any commodity derivative instruments that it had designated as fair value or cash flow hedges for accounting purposes. The Company’s derivative financial instruments are categorized by one of three types, based on the business objective the instrument is expected to achieve: asset management, legacy and proprietary trading. All asset management, legacy and proprietary trading derivative activities are recorded at fair value, except for a limited number of transactions that qualify for the normal purchases or normal sales exclusion from SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (“SFAS No.133”) and therefore qualify for 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 generation 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 combined statements of operations. Changes in the fair value and settlements of contracts for proprietary trading activities are recorded as net trading revenue affiliate and nonaffiliate in accompanying combined statements of operations.
Concentration of Revenues
In 2005, 2004 and 2003, the Company earned a significant portion of its operating revenue and gross margin from the PJM energy market, where the Company’s Mirant Mid-Atlantic generation facilities are located.
Concentration of Labor Subject to Collective Bargaining Agreements
At December 31, 2005, approximately 68% of the Company’s employees that have been employed through contracts with Mirant Services, LLC (“Mirant Services”) are subject to collective bargaining agreements. Approximately 9% of the employees are covered by collective bargaining agreements that will expire within one year.
Cash and Cash Equivalents
Mirant Americas Generation considers all short-term investments with an original maturity of three months or less to be cash equivalents.
Restricted Cash
Restricted cash is included in current and noncurrent assets as funds on deposit in the accompanying combined and consolidated balance sheets and amounted to $1.5 billion and $324 million at December 31, 2005 and 2004, respectively. For 2005, current and noncurrent funds on deposit were $1.5 billion and $5 million, respectively. For 2004, current and noncurrent funds on deposit were $319 million and $5 million, respectively. Restricted cash includes deposits with brokers and cash collateral posted with third parties to support the Company’s commodity positions. In addition, as of December 31, 2005, restricted cash included $853 million in escrow related to the senior notes offering in December 2005. This amount was released from escrow on January 3, 2006.
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 at December 31, 2005 and 2004. Fuel stock is removed from inventory as it is used in the production of electricity. Materials and supplies are removed from inventory when they are used for repairs, maintenance or capital projects.
Emissions Allowances
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 sulfur dioxide (“SO2”) and nitrogen oxide (“NOx”) are removed from inventory and charged to cost of fuel, electricity and other products in the accompanying combined statements of operations as they are utilized against emissions volumes that exceed the allowances granted to the Company by the Environmental Protection Agency (“EPA”).
Emissions allowances granted by the EPA related to generation facilities owned by the Company are recorded at fair value at the date of the acquisition of the facility and are included in property, plant and equipment. These emissions allowances are depreciated on a straight-line basis over the estimated useful life of the respective generation facility, which ranges from 12 to 42 years, and are charged to depreciation and amortization expense in the accompanying combined statements of operations.
Emissions allowances granted by the EPA related to generation facilities leased by the Company are recorded at fair value at the commencement of the lease in other intangible assets. These emissions allowances are amortized on a straight-line basis over the term of the lease, and are charged to depreciation and amortization expense in the accompanying combined statements of operations.
The Company has determined that certain exchanges of emissions allowances that the Company may periodically transact would qualify as nonmonetary exchanges under SFAS No. 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 plant 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 recognized on a straight-line basis over the estimated useful life of the asset. Upon the retirement or sale of property, plant and equipment, the cost of such assets and the related accumulated depreciation are removed from the combined and 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 the advanced stages of development and during the 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. Upon commencement of commercial operations of the plant or project, capitalized interest, as a component of the total cost of the plant, is amortized over the estimated useful life of the plant or the life of the cooperation period of the
various energy conversion agreements. 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 interest expense of approximately $749 million in 2005 on liabilities subject to compromise. This amount represents interest from the Petition Date through the effective date of the Plan.
Goodwill and Intangible Assets
Goodwill represents the excess of costs over the fair value of assets of businesses acquired. Goodwill and intangible assets acquired in a purchase business combination that are determined to have an indefinite useful life are not amortized, but instead tested for impairment at least annually. 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. An impairment occurs when the fair value of a reporting unit is less than its carrying value including goodwill. The Company has determined that its operations constitute a single reporting unit. The fair value of the reporting unit is calculated using discounted cash flow techniques and assumptions as to business prospects using the best information available. The Company recognized a full impairment of goodwill in 2003. See Note 9 for additional information.
Environmental Remediation Costs
Mirant Americas Generation accrues for costs associated with environmental remediation obligations 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 remedial 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, Inc. (“Mirant Americas”) and Mirant have direct liability for the majority of the federal and state income taxes relating to the Company’s operations. 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 has not recorded current period tax benefits on each regarded corporate entity’s ability to carry back its separate company current year net operating loss (NOL)as realization of such losses is dependent on
reimbursements from Mirant, at Mirant’s discretion under the tax sharing agreement. Deferred tax assets and liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and NOL carryforwards. 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 are recognized in income in the period that included the enacted change.
Several 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 certain 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 regarded corporate entities were also liquidated, and now form part of 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 Mirant New York, Inc., Hudson Valley Gas Corporation, Mirant Kendall, LLC and Mirant Special Procurement, Inc.
In December 2005, pursuant to the Plan, Mirant rejected and thereby eliminated 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, with the exception of income tax payables and receivables related to Mirant New York, Inc. which continues to remain in bankruptcy at December 31, 2005.
SFAS No. 109, “Accounting for 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. Cumulative losses in recent years are the most compelling form of negative evidence considered by management in this determination. Additionally, management considered the fact that Mirant has not reimbursed the Company for current period NOLs since the Petition Date and the uncertainty regarding future reimbursements from Mirant. In 2005, 2004 and 2003, the Company recognized changes in its valuation allowance of $(534) million, $(4) million and $658 million, respectively, related to its net deferred tax assets.
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 No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” 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 the discounted future cash flows of the asset. Assets to be disposed of are separately presented in the accompanying combined and 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 combined and 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. At December 31, 2005, the Company recorded a cumulative effect of a change in accounting principle of approximately $16 million, net of tax, related to the adoption of this accounting standard.
In October 2002, the Emerging Issues Task Force (“EITF”) reached a consensus on EITF Issue 02-03, Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities, to rescind EITF Issue 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities. Accordingly, energy-related contracts that are not accounted for pursuant to SFAS No. 133, such as transportation contracts, storage contracts, and tolling agreements, are required to be accounted for as executory contracts using the accrual method of accounting and not fair value. Energy-related contracts that meet the definition of a derivative pursuant to SFAS No. 133 continue to be carried at fair value. In addition, the EITF observed that accounting for energy-related inventory at fair value by analogy to the consensus on EITF Issue 98-10 is not appropriate and that such inventory is not to be recognized at fair value. As a result of the consensus on EITF Issue 02-03, all nonderivative energy trading contracts on the combined balance sheet as of January 1, 2003 that existed on October 25, 2002 and energy-related inventories that were recorded at fair value have been adjusted to historical cost resulting in a cumulative effect adjustment of $7 million, net of taxes, which was recorded in the first quarter of 2003.
The Company adopted SFAS No. 143 effective January 1, 2003, related to costs associated with legal obligations to retire tangible long-lived assets. Asset retirement obligations are recorded at 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. In the first quarter of 2003, the Company recorded a charge as a cumulative effect of a change in accounting principle of approximately $3 million, net of tax, related to the adoption of this accounting standard.
Investments
As of December 31, 2004, the Company had a $6 million investment in a company that provides an electronic commerce platform for the purchase and sale of energy commodities. The Company accounted for this investment using the cost method in 2004 and the investment was included in investments in the accompanying combined balance sheet. In the fourth quarter of 2005, the investee completed an initial public offering and the Company’s investment was exchanged for approximately 2.8 million shares of common stock of the investee. The Company sold a portion of its investment for $48 million. The Company recorded a gain on sale of investments of $44 million related to this sale. The fair value of the Company’s remaining investment in the investee of approximately $30 million is classified as securities available for sale and is included in other current assets on the consolidated balance sheet as of December 31, 2005. The Company has recorded an unrealized gain in accumulated other comprehensive income of $27 million in the consolidated balance sheet at December 31, 2005 related to this investment.
Fair Value of Financial Instruments
SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” 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, 2005 and 2004, financial instruments recorded at contractual amounts that approximate market or fair value include cash and cash equivalents, funds on deposit, receivables from affiliate, excluding pre-petition amounts discussed below, and 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, 2005 and 2004, the fair value of the Company’s long-term accounts receivable of $2 million and $27 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, 2005, the carrying value of the Company’s long-term debt approximated fair value.
At December 31, 2004, the Company’s receivables from affiliate included $295 million of pre-petition amounts and current notes receivable from affiliate included $40 million of pre-petition amounts for which fair value was not readily determinable because of their intercompany nature and the status of the bankruptcy cases. At December 31, 2004, the Company’s long-term notes receivable from affiliate had a carrying value of $255 million. The fair value of Mirant Americas Generation’s long-term notes receivable from affiliate was not readily determinable because of their intercompany nature and the status of the bankruptcy cases. Under the Plan, the pre-petition receivables from affiliate and pre-petition notes receivable from affiliate were resolved pursuant to a global settlement whereby intercompany claims did not receive any distribution.
Rent Expense
Rent expense related to the Company’s operating leases is recognized on a straight-line basis over the terms of the leases. Rent expense for generation facilities is reported separately as generation facilities rent in the accompanying combined statements of operations. Payments made under the terms of the lease agreement in excess of the amount of lease expense recognized are recorded as prepaid rent in the accompanying combined and consolidated balance sheets. Prepaid rent attributable to periods beyond one year is included in noncurrent assets.
3. Bankruptcy Related Disclosures
On January 19, 2005, the Mirant Debtors filed a Plan and Disclosure Statement (the “Disclosure Statement”) with the Bankruptcy Court. The Bankruptcy Court confirmed the Plan pursuant to the Confirmation Order. Accordingly, the terms of the Plan and Confirmation Order were deemed binding upon the Mirant Debtors and all other parties affected by the Plan. The Plan became effective on January 3, 2006. For financial statement presentation purposes, Mirant and the Company recorded the effects of the Plan on December 31, 2005. Mirant Americas Generation’s New York subsidiaries remain in bankruptcy.
The Plan included the following key elements:
· The business of the Mirant Debtors continued to operate in its current form, subject to certain internal structural changes including the organization of a new parent entity (“New Mirant”).
· In addition to amounts borrowed under Mirant North America’s senior secured revolving credit facility, Mirant had approximately $4.4 billion of debt after emergence.
· The pre-petition intercompany claims between and among the Mirant Debtors were resolved as part of a global settlement.
· The holders of unsecured claims against the Consolidated Mirant Debtors received a pro rata share of:
· 96.25% of the shares of New Mirant common stock issued under the Plan, excluding: (i) 2.3% of shares of New Mirant common stock issued to certain holders of claims against the Mirant Americas Generation Debtors, and (ii) the shares reserved for issuance pursuant to the New Mirant employee stock programs; and
· the right to receive cash payments equal to 50% of the cash recoveries, if any, from certain designated avoidance actions. In connection with the Plan, MC Asset Recovery, LLC (“MC Asset Recovery”) was formed as a wholly-owned subsidiary of Mirant on December 30, 2005, to prosecute, settle and/or liquidate certain avoidance actions.
The holders of certain subordinated obligations had the right to receive 3.5% of the shares of New Mirant common stock (which shares are included in the 96.25% referred to above), to receive warrants to purchase an additional 5% of the shares of New Mirant common stock, and to participate pari passu with the holders of Mirant unsecured claims in the recoveries under the designated avoidance actions.
· The outstanding common stock in Mirant was cancelled and the holders thereof received:
· 3.75% of the shares of New Mirant common stock (subject to the exclusions noted above for Mirant’s general unsecured creditors, as applicable);
· warrants to purchase up to an additional 10% of the shares of New Mirant common stock; and
· the right to receive cash payments equal to 50% of the recoveries, if any, from certain designated avoidance actions.
· The claims against the Consolidated Mirant Americas Generation Debtors were paid in full through:
· the reinstatement of the Mirant Americas Generation senior notes maturing in 2011, 2021 and 2031, and the payment of $452 million of accrued interest; and
· the issuance to all other holders of secured and unsecured claims against the Consolidated Mirant Americas Generation Debtors of (a) approximately $1.35 billion in cash and (b) 2.3% of the shares of New Mirant common stock, subject to certain exclusions.
· Mirant contributed (or caused to be contributed) additional value to Mirant Americas Generation, including:
· the transfer of the Trading Debtors to Mirant North America in return for $250 million of cash;
· commitments to make capital contributions: (a) through the issuance by Mirant Americas of up to $265 million of redeemable Series A Preferred Shares redeemable by Mirant Mid-Atlantic to fund environmental capital expenditures, and (b) through the issuance by Mirant Americas of $150 million of Series B Preferred Shares, redeemable by Mirant Americas Generation, to support the refinancing of its notes due 2011;
· the transfer of Mirant Potomac River to Mirant Chalk Point, LLC (“Mirant Chalk Point”) a wholly-owned subsidiary of Mirant Mid-Atlantic, and the transfer of Mirant Peaker to Mirant Mid-Atlantic and the subsequent merger of Mirant Peaker into Mirant Chalk Point; and
· the transfer of Mirant Zeeland to Mirant North America.
· Mirant Mid-Atlantic assumed the Mirant Mid-Atlantic leveraged leases in accordance with the terms of the Plan and subject to the order of the Bankruptcy Court with respect to the interpretation of certain provisions of the leveraged lease documentation.
On January 3, 2006, substantially all of the assets of Mirant were transferred to New Mirant, which has no successor liability for any unassumed obligations of Mirant. Additionally, Mirant Energy Trading has no successor liability for any unassumed obligations of the Trading Debtors. After these transfers took place, old Mirant and the Trading Debtors were transferred to a trust created under the Plan.
Interest Expense
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. As a result, the Company recorded interest expense of approximately $749 million in 2005 on liabilities subject to compromise. This amount represents interest from the Petition Date through the effective date of the Plan. The interest amount was calculated based on the provisions of the Plan. The $749 million expense amount included approximately $452 million related to Mirant Americas Generation senior notes maturing in 2011, 2021 and 2031, which were reinstated under the Plan.
Liabilities Subject to Compromise
At December 31, 2005, amounts related to allowed claims and estimated unresolved claims that are to be settled in cash are $1.8 billion and are recorded in claims payable and estimated claims accrual on the accompanying combined and consolidated balance sheets. Due to the confirmation of the Plan on December 9, 2005, the Company’s liabilities subject to compromise balances at December 31, 2005, relate only to those of its New York subsidiaries that remain in bankruptcy.
At December 31, 2004, liabilities subject to compromise included certain liabilities incurred prior to the Petition Date. The amounts of the various categories of liabilities that were subject to compromise are set forth below. Such amounts represented the Company’s estimates of known potential claims that were likely to be resolved in connection with the bankruptcy filings.
The amounts subject to compromise at December 31, 2005, and 2004 consisted of the following items (in millions):
Reorganization Items
Reorganization items, net represents expense or income and gain or loss amounts that were recorded in the combined statements of operations as a result of the bankruptcy proceedings. The following were the significant items within this category (in millions):
New York Subsidiaries
Condensed consolidated balance sheet data as of December 31, 2005 is set forth below for the Company’s New York subsidiaries that remain in bankruptcy.
4. Change in Reporting Entity
As discussed in Note 1, pursuant to the Plan Mirant contributed its interest in the Contributed Subsidiaries to the Company resulting in a change in the Mirant Americas Generation reporting entity.
The following tables and discussion summarize the effects of the Contributed Subsidiaries on the previously reported Mirant Americas Generation’s consolidated statements of operations for 2004 and 2003 (in millions):
Historically, the Company’s operating subsidiaries were party to services agreements with Mirant Americas Energy Marketing. Mirant Americas Energy Marketing was responsible for marketing the output of the Company’s facilities and procurement of fuel for the Company’s facilities, as well as for executing contracts, including economic hedges, to reduce price risk. Transactions between the operating subsidiaries and Mirant Americas Energy Marketing were included in operating revenues-affiliate and cost of fuel, electricity, and other products-affiliate, in the previously reported Mirant Americas Generation statements of operations. Because Mirant Americas Energy Marketing is part of the combined Mirant Americas Generation financial statements, these affiliate transactions are now eliminated. In addition, Mirant Americas Energy Marketing’s sales and purchase transactions with nonaffiliates are now reflected in Mirant Americas Generation combined statements of operations.
The following table and discussion summarizes the effects of the Contributed Subsidiaries on the previously reported Mirant Americas Generation consolidated balance sheet at December 31, 2004 (in millions):
(1) Funds on deposit represents collateral of Mirant Americas Energy Marketing on deposit with brokers and counterparties.
(2) Historically, the Company’s operating subsidiaries were party to services agreements with Mirant Americas Energy Marketing. Mirant Americas Energy Marketing was responsible for executing contracts, including economic hedges, to reduce price risk. The fair value of energy contracts between the operating subsidiaries and Mirant Americas Energy Marketing were included in the respective price risk management-affiliate accounts, in the previously reported Mirant Americas Generation balance sheets. Because Mirant Americas Energy Marketing is part of the combined Mirant Americas Generation financial statements, these transactions are now eliminated. In addition, the fair value of energy contracts between Mirant Americas Energy Marketing and nonaffiliates are now reflected in the Mirant Americas Generation combined balance sheet in the respective price risk management-nonaffiliate accounts.
(3) Receivables-affiliate increased from the previously reported amount as a result of $288 million of receivables due to the Contributed Subsidiaries from Mirant affiliates not included in these combined and consolidated financial statements. This amount was partially offset by the elimination of receivables due to the Company’s operating subsidiaries from Mirant Americas Energy Marketing.
(4) Receivables-nonaffiliate and accounts payable and accrued liabilities increased significantly due to the inclusion of Mirant Americas Energy Marketing in the combined balance sheet. These accounts included the settled amounts of the energy contracts entered into by Mirant Americas Energy Marketing in the wholesale energy markets.
(5) Mirant Potomac River and Mirant Peaker owed Mirant Mid-Atlantic $152 million and $71 million, respectively, at December 31, 2004. The inclusion of these subsidiaries in the combined Mirant Americas Generation balance sheet results in the elimination of the intercompany amounts. The offsetting eliminating affiliate liability is included in the adjustment to liabilities subject to compromise.
5. Inventory
Inventory at December 31, consisted of the following (in millions):
The increase in fuel inventory in 2005 is primarily due to rising commodity prices. The decrease in purchased emissions allowances is due to utilization of allowances during 2005.
6. 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 have been included in the accompanying combined statements of operations as follows (in millions):
Services and Risk Management Agreements with Affiliates
The Company, through Mirant Energy Trading, and previously Mirant Americas Energy Marketing, provides energy marketing and fuel procurement services to the following affiliates: Mirant Las Vegas, LLC, Mirant Sugar Creek, LLC and Mirant Wichita Falls, LP. Amounts due from each affiliate under their respective service agreements are recorded as a net accounts payable-affiliate or accounts receivable-affiliate because of each subsidiary’s legal right to offset.
Beginning January 1, 2004, Mirant changed its allocation methodology related to its energy marketing overhead expenses. Under the new methodology, substantially all energy marketing costs are now allocated to Mirant’s operating subsidiaries. During the years ended December 31, 2005, 2004 and 2003, the total energy marketing costs were $54 million, $83 million and $23 million, respectively. During the years ended December 31, 2005, 2004 and 2003 the Company allocated approximately $8 million, $14 million and $1 million, respectively, in costs under these agreements to affiliates that are not included in the Mirant Americas Generation combined statements of operations. These costs allocated to affiliates are included in generation revenue-affiliate.
For the period from January 1, 2006 to January 31, 2006, Mirant Americas Energy Marketing continued to provide these services to the affiliates. Beginning February 1, 2006 Mirant Energy Trading began providing these services to the affiliates.
Administration Arrangements with Mirant Services
In 2003 Mirant Services utilized a fixed administration charge to various subsidiaries of Mirant, including the Company, which served to reimburse Mirant Services for various indirect administrative services performed on the subsidiaries’ behalf, including information technology services, regulatory support, consulting, legal and accounting and financial services. The fixed charge was approximately $4.7 million per month in 2003. Beginning January 1, 2004, Mirant changed its allocation methodology related to the allocation of its corporate overhead expenses. Under the new methodology, substantially all of Mirant’s corporate overhead costs are now allocated to Mirant’s operating subsidiaries.
For the years ended December 31, 2005, 2004 and 2003, the Company incurred approximately $133 million, $168 million and $57 million, respectively, in costs under these arrangements, which are included in operations and maintenance-affiliate in the accompanying combined statements of operations.
Make-Whole Reimbursement Agreement
Under the asset purchase and sale agreement for the Potomac Electric Power Company (“PEPCO”) generating assets, Mirant assumed and recorded net obligations of approximately $2.4 billion, representing the estimated fair value (at the date of acquisition) of out-of-market energy delivery and power purchase agreements (“PPAs”), which consisted of five PPAs and two TPAs. The estimated fair value of the contracts was derived using forward prices obtained from brokers and other external sources in the market place, including brokers and trading platforms/exchanges such as New York Mercantile Exchange (“NYMEX”) and estimated load information. Mirant Americas Energy Marketing assumed these obligations from Mirant pursuant to a liability assignment agreement.
Mirant Americas and Mirant Americas Energy Marketing entered into a Make-Whole Reimbursement Agreement (the “Make-Whole Agreement”), whereby Mirant Americas was obligated to reimburse Mirant Americas Energy Marketing for losses arising from the TPAs, PPAs, and related hedges of these agreements. In any month that Mirant Americas Energy Marketing realized net gains related to the TPAs, PPAs, and related hedges, it was required to pay these amounts to Mirant Americas. Amounts received were recorded as capital contributions and amounts paid were recorded as capital distributions in the accompanying combined financial statements. Payments received from Mirant Americas under the Make-Whole Agreement in 2004 and 2003 were $7 million and $315 million, respectively. Amounts paid to Mirant Americas under the Make-Whole Agreement were $29 million in 2003. Under the Plan, claims arising out of the Make-Whole Agreement were resolved pursuant to a global settlement, whereby intercompany claims did not receive distributions.
Sales to Mirant Energy Marketing Canada
Historically, Mirant Americas Energy Marketing purchased natural gas from Mirant Energy Marketing Canada, a subsidiary of Mirant. These purchases were reflected in net trading revenue-affiliate on the combined statements of operations. The natural gas was sold to third parties; therefore, the revenue was reflected in net trading revenue-nonaffiliate in the combined statements of operations. In
2003, Mirant sold a substantial portion of the Canadian operation and decided to exit the remaining elements of their trading business in Canada. Gas purchases from Mirant Energy Marketing Canada for the years ended December 31, 2005, 2004 and 2003 were $3 million, $17 million and $718 million, respectively.
Restructuring Charges
During the years ended December 31, 2005, 2004 and 2003, the Company recorded restructuring charges of $3 million, $5 million and $9 million, respectively, for severance costs and other charges, which are included in operations and maintenance-affiliate in the accompanying combined statements of operations. During the year ended December 31, 2003, the Company recorded restructuring charges of $4 million for severance costs and costs related to suspending planned power plant developments, which are included in operations and maintenance-nonaffiliate in the accompanying 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.
Turbine Lease Facility Arrangement
At December 31, 2004, the Company had accounts receivable from affiliate with Mirant Americas of $147 million and Mirant Americas Procurement, Inc. of $71 million. These amounts related to a warehouse operating lease facility arrangement. Amounts due to third parties under this arrangement were $214 million and amounts due to affiliates were $3 million. These amounts were included in liabilities subject to compromise at December 31, 2004. Pursuant to the Plan, the pre-petition receivables from affiliate were resolved pursuant to a global settlement, whereby intercompany claims did not receive any distribution.
Notes Receivable from Affiliate and Notes Payable to Affiliate
During the pendency of the Chapter 11 proceedings, Mirant and certain of its subsidiaries participated in an intercompany cash management program approved by the Bankruptcy Court, pursuant to which cash balances at Mirant and the participating subsidiaries were transferred to central concentration accounts and, if necessary, lent to Mirant or any participating subsidiary to fund working capital and other needs, subject to the intercompany borrowing limits approved by the Bankruptcy Court. At December 31, 2005, the Company had current note payable to affiliate of $21 million and at December 31, 2004, the Company had current notes receivable from affiliate of $44 million related to the intercompany cash management program. The Company had current notes receivable from affiliate of $6 million at December 31, 2004 related to the disposal of the Mirant Americas Energy Capital Assets.
At December 31, 2004, unsecured noncurrent notes receivable from affiliate consisted of a $255 million note receivable from Mirant Americas, which was contributed to the Company effective January 1, 2002, when Mirant Americas transferred its ownership interest in Mirant New England to the Company. The note was payable on demand with 6% interest, which was payable monthly. Interest earned by the Company from Mirant Americas was approximately $8 million for the year ended December 31, 2003. The Company did not record any interest income on this note since the Petition Date and due to the bankruptcy proceedings, the Company classified the note receivable as long-term notes receivable from affiliate at December 31, 2004. Interest earned would have been $15 million for each of the years ended December 31, 2005 and 2004, if not for the bankruptcy proceeding. Pursuant to the Plan, this noncurrent note receivable from affiliate was resolved pursuant to a global settlement, whereby intercompany claims did not receive any distribution.
Payable to Mirant Americas Pursuant to the Plan
Under the Plan, the Company 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 the Trading Debtors. This amount is included in payable to affiliate at December 31, 2005 in the consolidated balance sheet and was paid in January 2006.
Mirant Guarantees
In 2004 and 2003 Mirant New England, was required to sell electricity at fixed prices to Cambridge Electric Light Company (“Cambridge”) and Commonwealth Electric Company (“Commonwealth”) in order for them to meet their supply requirements to certain retail customers. In April 2002, Mirant issued a guarantee in the amount of $188 million for any obligations Mirant New England may incur under its Wholesale Transition Service Agreement with Cambridge and Commonwealth. Both the guarantee and the agreement expired in February 2005.
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 is unable to pay its lease payment obligations. In June 2005 and September 2005, the full amount of the pre-petition letters of credit was drawn in the amount of $61 million. On January 3, 2006, as part of the settlement and the Company’s emergence from bankruptcy, Mirant North America posted a $75 million letter of credit for the benefit of Mirant Mid-Atlantic to cover debt service reserve obligations on Mirant Mid-Atlantic’s leases. Upon the posting of the letter of credit, the trustee 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 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 expires in June 2006.
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 hedging 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.
Preferred Stock In Mirant Americas
The Plan provided for Mirant Americas, the Company’s indirect parent to make certain capital contributions to Mirant Americas Generation and Mirant Mid-Atlantic. These capital contributions were made in the form of mandatory redeemable preferred stock in Mirant Americas.
Series A Preferred Shares
In December 2005, Mirant Americas issued preferred shares to Mirant Mid-Atlantic (the “Series A Preferred Shares”) for the purpose of funding future environmental capital expenditures. The Series A Preferred Shares have a mandatory redemption scheduled for June 30 of each year (“Scheduled Redemption Date”) at a price equal to the portion of the liquidation preference (“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 of 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 $208 million as a component of equity in the Company’s consolidated balance sheet at December 31, 2005. The fair value was determined using a discounted cash flow method based on the Specified Redemption Amounts using a 6.21% discount rate.
Series B Preferred Shares
In December 2005, Mirant Americas issued preferred shares to Mirant Americas Generation (the “Series B Preferred Shares”) for the purpose of supporting the refinancing of $850 million of Mirant Americas Generation senior notes due in 2011. The Series B Preferred Shares have a mandatory redemption date of April 1, 2011, for the liquidation preference amount of $150 million. At any time after June 30, 2010, Mirant Americas Generation has the right to put the Series B Preferred Shares to Mirant at the liquidation preference amount.
The Series B Preferred Shares are recorded at a fair value of $111 million as a component of equity in the Company’s consolidated balance sheet at December 31, 2005. The fair value was determined using a discounted cash flow method based on the expected redemption date and the liquidation preference amount using a 6.21% discount rate.
7. Derivative Financial Instruments
Interest Rate Hedging
Historically, the Company has entered into interest rate swaps in which it agreed to exchange, at specified intervals, the difference between fixed and variable interest amounts calculated by reference to agreed-upon notional amounts. These interest rate swaps were designated to hedge the variable interest rate risk in the underlying debt obligations. For swaps that qualify as cash flow hedges, the changes in the fair value of the swaps are deferred in other OCI, and reclassified from OCI as an adjustment to interest expense over the term of the hedged instruments. Gains and losses resulting from the termination of qualifying hedges prior to their stated maturities were recognized ratably over the remaining term of the hedged instruments. At December 31, 2005, the Company was not a party to any interest rate swaps. Pursuant to the bankruptcy proceedings, interest payments were suspended on the debt associated with the Company’s interest rate swaps accounted for as qualifying hedges that had previously been settled. Therefore, the remaining losses related to these interest rate hedges totaling $52 million after tax, were reclassified from OCI to earnings in 2003, effective with the Chapter 11 filing.
Commodity Financial Instruments
The Company manages the risks around fuel supply and power to be generated from its physical asset positions (“asset management”), and attempts to achieve incremental returns by entering into additional energy contracts where it has specific market expertise or physical asset positions (“proprietary trading”).
The Company 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 the electricity produced 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 over-the-counter financial markets. Option contracts are traded on both a national exchange and in over-the-counter financial markets. These contractual agreements have varying terms, notionals, 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 over-the-counter contracts, as well as other contractual arrangements.
Derivative instruments are recorded at their estimated fair value in the Company’s accompanying combined and 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 used for asset management purposes are reflected in generation revenue and changes in the fair value and settlements of fuel derivative contracts used for asset management purposes are reflected in cost of fuel and other products in the accompanying combined statements of operations. Changes in the fair value and settlements of derivatives held for trading purposes are reflected in net trading revenues in the accompanying combined statements of operations. As of December 31, 2005, the Company does not have any derivative instruments for which hedge accounting has been elected.
The fair values of Mirant Americas Generation’s price risk management assets and liabilities, net of credit reserves, as of December 31, 2005, are included in the following table (in millions):
The volumetric weighted average maturity, or weighted average tenor, of the price risk management portfolio at December 31, 2005, was seven months. The net notional amount, or net short position, of the price risk management assets and liabilities at December 31, 2005, was approximately 8 million equivalent MWh.
In January 2006, the Company entered into financial swap transactions with a third party, the effect of which economically hedged the Company’s Mid-Atlantic expected on-peak coal fired generation by approximately 80%, 50% and 50% for 2007, 2008 and 2009, respectively.
The fair values of Mirant Americas Generation’s price risk management assets and liabilities, net of credit reserves, as of December 31, 2004, are included in the following table (in millions):
8. Property, Plant and Equipment
Property, plant and equipment consisted of the following at December 31, 2005 and 2004 (in millions):
The Company does not expect to independently complete its suspended construction projects. The Company plans to either pursue partnerships to complete one or more of the projects, sell the projects, or abandon the projects. In the year ended December 31, 2004, the Company completed the sale of turbines that had been part of a suspended construction project at its Bowline facility. These turbines had a book value of $107 million. The proceeds received in 2004 were $42 million and the Company collected an additional $4 million in March 2005.
Depreciation of the recorded cost of depreciable property, plant and equipment is recognized on a straight-line basis over the estimated useful lives of the assets. The Company received emissions allowances in the acquisition of the PEPCO assets for both SO2 and NOx emissions and the right to future allowances. The acquired allowances related to owned facilities are included in production assets above, and are depreciated over the average life of the related assets. Mirant Americas Generation does not depreciate its suspended construction project costs.
Mirant Americas Generation evaluates its long-lived assets (property, plant and equipment) and definite-lived intangibles for impairment whenever events or changes in circumstances indicate that the Company may not be able to recover the carrying amount of the asset. An asset impairment charge must be recognized if the sum of the undiscounted expected future cash flows from a long-lived asset or definite-lived intangible 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. In the case of assets the Company expects to sell, the impairment charge is based on the estimated sales value less costs to sell.
Following is a summary of long-lived asset impairment charges related to property, plant and equipment recorded for the year ended December 31, 2003 (in millions):
For purposes of testing for impairment losses, the Company groups long-lived assets and definite-lived intangibles at the lowest level at which separate cash flows can be identified, which generally was determined to be the individual generating assets or several generating assets operated as a group. The long-lived assets evaluated for impairment consist of property, plant and equipment, construction work in progress, development rights, trading rights, acquired emissions allowances and other definite-lived intangibles.
9. Goodwill and Other Intangible Assets
Goodwill
The Company evaluated goodwill and indefinite-lived intangible assets for impairment at least annually and periodically if indicators of impairment were present. The results of the Company’s analysis in 2003 indicated that goodwill was impaired and the Company recorded an impairment charge of $1.9 billion, representing the entire balance of goodwill, in the accompanying combined statement of operations for the year ended December 31, 2003.
The critical assumptions used in the Company’s impairment analysis included the following: assumptions as to the future electricity and fuel prices; future levels of gross domestic product growth; levels of supply and demand; future operating and capital expenditures; and estimates of the Company’s weighted average cost of capital.
The above assumptions were critical to the Company’s determination of the fair value of its goodwill. The combined subjectivity and sensitivity of the assumptions and estimates used in the goodwill impairment analysis could result in a reasonable person concluding differently on those critical assumptions and estimates, possibly resulting in an impairment charge having been required for a lesser amount.
Other Intangible Assets
Following is a summary of other intangible assets at December 31, 2005 and 2004 (in millions):
Trading rights represent intangible assets recognized in connection with asset purchases that represent the Company’s ability to generate additional cash flows by incorporating the Company’s proprietary 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 generation facilities.
Emissions allowances recorded in intangible assets relate to allowances granted for the leasehold baseload units at the Morgantown and Dickerson facilities, as well as the Company’s units in California. Allowances granted by the EPA for other owned assets are recorded within property, plant and equipment, net on the combined and consolidated balance sheets.
Substantially all of Mirant Americas Generation’s other remaining intangible assets are subject to amortization and are being amortized on a straight-line basis over their estimated useful lives.
Amortization expense was approximately $8 million, $8 million and $17 million for the years ended December 31, 2005, 2004 and 2003, respectively. Assuming no future acquisitions, dispositions or impairments of intangible assets, amortization expense is estimated to be $8 million for each of the next five years.
Following is a summary of impairment charges related to intangible assets recorded for the year ended December 31, 2003 (in millions):
10. Dispositions and Assets Held for Sale
Disposition of Assets
On September 13, 2005, Mirant Mid-Atlantic executed an agreement to sell its Mirant service center building and accompanying 68 acres located in Upper Marlboro, Maryland for $13 million. Mirant expects to close on a sale of the building on or before December 31, 2006.
During the fourth quarter of 2004, the Company entered into an agreement to dispose of three natural gas turbines related to a suspended construction project. The sale resulted in the Company receiving $42 million in the fourth quarter of 2004 and $4 million in the first quarter of 2005. As a result, the Company in the year ended December 31, 2004, recognized a loss related to these turbines of $65 million which is included in loss (gain) on sales of assets, net in the combined statements of operations. In 2003, the Company recognized a gain of $15 million on the sale of firm transportation agreements to Cargill, and a gain of $3 million on the sale of crude oil.
Discontinued Operations
In the first quarter of 2003, the Company completed the sale of its Neenah generating facility for approximately $109 million. The asset was sold at approximately book value. In May and August 2003, Mirant Americas Energy Capital completed the sale of its two remaining investments for approximately $41 million and $3 million, respectively, which approximated book value.
A summary of operating results for these discontinued operations prior to their disposal for the year ended December 31, 2003 follows (in millions):
Discontinuance of Activities
Certain of the Contributed Subsidiaries do not have significant ongoing operating activities. The historical nature of the entities is described below.
Mirant Americas Energy Capital was formed in 1999 to engage in the business of providing equity investment or secured financing to independent oil and gas producers for the purpose of developing, acquiring, or refinancing proved or producing oil and gas properties in the United States. Mirant Americas Energy Capital did in some instances use its affiliate, Mirant Americas Energy Marketing, to market the gas of the entities in which it invested. Mirant Americas Energy Capital Assets was later formed as a subsidiary of Mirant Americas Energy Capital to engage in similar activities. Mirant Americas Production Company was formed in 2001 for the purpose of acquiring non-operating, undivided interests in certain oil and gas producing properties. Mirant disposed of the majority of the significant assets and operations of
Mirant Americas Energy Capital, Mirant Americas Energy Capital Assets, and Mirant Americas Production Company in a series of transactions between December 2002 and August 2003. As of December 31, 2004, Mirant Americas Energy Capital had notes receivable from affiliate of $6 million. Pursuant to the Plan, the pre-petition note receivable from affiliate was resolved pursuant to a global settlement, whereby intercompany claims did not receive any distribution.
Mirant Americas Development and Mirant Americas Development Capital were formed to support Mirant’s business development activities. For example, permits or other contracts would be entered into by Mirant Americas Development and later transferred to a new Mirant subsidiary once formed. Mirant Americas Development Capital was the entity used to facilitate a turbine lease facility. The activities of these entities related to greenfield development projects and substantially ceased in 2003. As of December 31, 2004, Mirant Americas Development had receivables from affiliate of $224 million. Pursuant to the Plan, the pre-petition receivables from affiliate were resolved pursuant to a global settlement, whereby intercompany claims did not receive any distribution.
Assets Held for Sale
The Company reclassified $7 million related to the Mirant service center building from property, plant and equipment to assets held for sale as of December 31, 2005 and 2004, in the accompanying combined and consolidated balance sheets.
11. Long-Term Debt
Long-term debt at December 31, 2005 was as follows (in millions):
Pursuant to the Plan, Mirant Americas Generation reinstated $1.7 billion of senior notes maturing in 2011, 2021 and 2031, and agreed to pay $452 million of accrued interest. Pursuant to the Plan, the Company and its subsidiaries eliminated approximately $1.5 billion of debt.
Senior Secured Credit Facilities
The Mirant North America senior secured credit facilities are comprised of an $800 million six-year senior secured revolving credit facility and a $700 million seven-year senior secured term loan. The full amount of the senior secured revolving credit facility is available for the issuance of letters of credit. The senior secured term loan was made in a single drawing at closing and will amortize in nominal quarterly installments aggregating 0.25% of the original principal of the term loan per quarter for the first 27 quarters, with the remainder payable on the final maturity date. In connection with the closing, $200 million of drawings under the senior secured term loan were deposited into a cash collateral account to support the issuance of up to $200 million of letters of credit issued under the senior secured term loan.
Loans under the senior secured credit facilities are available at either of the following rates: (i) a fluctuating rate of interest per annum equal to on any given day the greater of (a) the interest rate per
annum publicly announced by JPMorgan Chase Bank, N.A. as its prime rate in effect at its principal office in New York City on that day, and (b) the federal funds rate in effect on that day plus 0.50%, plus the applicable margin described below (“base rate”), or (ii) a fixed rate determined for certain interest periods selected equal to U.S. dollar London InterBank Offered Rate (“LIBOR”) plus the applicable margin described below (“Eurodollar rate”).
The applicable margin with respect to loans under the senior secured revolving credit facility is 1.25% in the case of base rate loans, or 2.25% in the case of Eurodollar rate loans. The applicable margin will also be subject to a possible reduction of up to 0.50% based on the achievement and maintenance of certain leverage ratios by Mirant North America. The applicable margin with respect to the senior secured term loan is 0.75% in the case of base rate loans, or 1.75% in the case of Eurodollar rate loans.
Senior Notes
Mirant North America Escrow, LLC (“Mirant North America Escrow”) and its wholly-owned subsidiary, MNA Finance Corp. issued notes in an aggregate principal amount of $850 million which bear interest at 7.375%, and mature on December 31, 2013 (the “Notes”). Interest on the Notes is payable on each June 30 and December 31, commencing June 30, 2006. Mirant North America Escrow was a wholly-owned subsidiary of Mirant North America. Upon emergence, Mirant North America Escrow was merged with and into Mirant North America with Mirant North America as the surviving entity. Upon the consummation of the merger, Mirant North America assumed all of the obligations of Mirant North America Escrow and MNA Finance Corp. became a direct, wholly-owned subsidiary of Mirant North America. MNA Finance Corp. was formed and exists solely for the purpose of serving as a co-issuer of the notes and as a guarantor of the senior secured credit facilities.
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.
At December 31, 2005, the annual scheduled maturities of debt, during the next five years and thereafter were as follows (in millions):
Concurrent with the emergence from bankruptcy of the Company and its subsidiaries, the following senior unsecured indebtedness was terminated in conjunction with settlement provisions of the Plan. The Company and its subsidiaries have no outstanding obligations with respect to the following indebtedness (in millions):
Capital Leases
Long-term debt includes the Company’s two capital leases. At December 31, 2005 and 2004, the total amount outstanding under the capital leases was $47 million and $50 million, respectively. At December 31, 2005 and 2004, the current portion of the long-term debt under these capital leases was $3 million and $4 million, respectively.
The amount outstanding under the Mirant Peaker electric power generation facility capital lease which matures in 2015 is $36 million with an 8.19% annual interest rate. The annual principal payments under this lease are approximately $3 million in 2006 through 2010 and $21 million thereafter.
The amount outstanding under the Mirant Zeeland capital lease which matures in 2012 is $11 million with a 9.5% annual interest rate. This lease is of a pipeline to the Mirant Zeeland generation facility. The annual principal payments under this lease are less than $1 million in 2006 and 2007, approximately $1 million in 2008 and 2009, $2 million in 2010 and $6 million thereafter.
The following is a summary of the assets under each respective capital lease, recorded in property, plant and equipment, net at December 31, 2005 and 2004 (in millions):
Debtor-in-Possession Financing
In 2005, the Company and its subsidiaries participated in an intercompany cash management program for the Mirant Debtors approved by the Bankruptcy Court and were parties to the debtor-in-possession credit facility dated November 5, 2003 (the “DIP Facility”). The parties to the DIP Facility, including the Company, were in compliance with the DIP Facility covenants, or had received affirmative waivers of compliance where compliance was not attained, as of December 31, 2005. In October 2005, the Bankruptcy Court approved an extension of the DIP Facility through January 31, 2006. The DIP Facility was terminated on the emergence of the Mirant Debtors on January 3, 2006.
Sources of Funds and Capital Structure
The principal sources of liquidity for the Company’s future operations and capital expenditures are expected to be: (i) existing cash on hand and cash flows from the operations of the Company’s subsidiaries; (ii) borrowings under Mirant North America’s $800 million six year senior secured revolving credit facility; and (iii) $200 million of letters of credit capacity under Mirant North America’s $700 million term loan and (iv) proceeds from the preferred shares issued by Mirant Americas to Mirant Mid-Atlantic and the Company to fund capital expenditures and support the refinancing of the Company’s senior notes due in 2011.
The Company and certain of its subsidiaries, including Mirant North America, are holding companies and as a result, such subsidiaries are dependent upon dividends, distributions and other payments from their respective subsidiaries to generate the funds necessary to meet their obligations. The ability of certain of the Company’s subsidiaries to pay dividends and distributions is restricted under the terms of their debt or other agreements. The Company has no operations and no subsidiaries with operations other than Mirant North America and its subsidiaries, including Mirant Mid-Atlantic. 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, the cash of Mirant Mid-Atlantic would not be able to be distributed. Based on the Company’s calculation of the fixed charge coverage ratios under the leveraged leases as of December 31, 2005, Mirant Mid-Atlantic meets the required 1.7 to 1.0 ratio for restricted payments, both on a historical and projected basis. During bankruptcy, cash movements among the Mirant Debtors were made pursuant to intercompany loans. During bankruptcy, the Mirant Debtors did not make dividends, distributions or capital contributions.
The Mirant North America senior secured credit facilities and notes include certain covenants typical in such credit facilities and notes, including restrictions on dividends, distributions and other restricted payments. Further, the Mirant North America senior secured credit facilities include financial covenants that will exclude from the calculation of compliance with such covenants 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 Mirant North America under the leveraged lease transaction is expected to have a material impact on the calculation of the financial covenants under the Mirant North America senior secured credit facilities and other debt of Mirant North America and on its ability to make distributions to the Company.
Debtor-in-Possession Financing for New York Subsidiaries
The Company, together with Mirant Americas Energy Marketing, entered into an agreement (the ‘‘New York DIP Agreement’’) to make secured debtor-in-possession financing in an amount of (i) $20 million, plus (ii) an amount equal to the amount of credit support provided on behalf of (w) Mirant New York, Inc. (“Mirant New York”), (x) Mirant Bowline, (y) Mirant Lovett, and (z) Hudson Valley Gas Corporation (collectively, the “New York DIP Borrowers”), to the extent such amounts are collateralized with cash or cash equivalents by the New York DIP Borrowers. The facility is available on a joint and several basis to the New York DIP Borrowers. On January 31, 2006, all the assets of Mirant Americas Energy Marketing were transferred to Mirant Energy Trading, and Mirant Energy Trading succeeded to all rights and assumes all obligations of Mirant Americas Energy Marketing under the New York DIP Agreement. The financing under the New York DIP Agreement can be utilized through borrowings by the New York DIP Borrowers, the issuance of letters of credit for the account of any of the New York DIP Borrowers or in support of commercial transactions entered into by Mirant Energy Trading for the benefit of the New York DIP Borrowers, the posting of cash in respect of obligations incurred for the benefit of any of the New York DIP Borrowers, including the making of prepayments for fuel and other commodities for the benefit of any of the New York DIP Borrowers. Under the New York DIP Agreement, the amount which represents the excess on the effective date of the Plan of (x) credit support posted for the benefit of the New York DIP Borrowers by the lenders in respect of transactions entered into on their behalf over (y) the amount of cash collateral posted by the New York DIP Borrowers to the lenders is deemed to be a loan made to the New York DIP Borrowers on such date. The New York DIP Borrowers have posted $16.1 million cash collateral with Mirant Energy Trading in accordance with the February 28, 2006, collateral allocation performed in good faith by Mirant Energy Trading. To the extent that the required level of credit support provided to the New York DIP Borrowers is reduced, the amount of such reduction is required to be returned to the New York DIP Borrowers. The financing under the New York DIP Agreement has a stated maturity of 180 days, subject to renewal or extension, and is available until the earlier of (x) the expiration of such period or (y) with respect to each of the New York DIP Borrowers, the effective date of a confirmed plan of reorganization for such New York DIP Borrower in its Chapter 11 case. Subject to the authorization of the Bankruptcy Court, the obligations of the New York DIP Borrowers under the New York DIP Agreement, pursuant to Section 364(c) of the Chapter 11 of Title 11 of the United States Bankruptcy Code (“Bankruptcy Code”), (i) constitute a claim having priority over any or all administrative expenses of the kind specified in sections 503(b) or 507(b) of the Bankruptcy Code, (ii) are secured by a lien on property of the estates of the New York DIP Borrowers that is not otherwise subject to a lien and (iii) are secured by a junior lien on property of the estates of the New York DIP Borrowers that is subject to a lien. The financing is expected to bear interest at a rate to be determined and to be subject to Bankruptcy Court approval. The New York DIP Agreement contains certain events of default, and the ability of the New York DIP Borrowers to borrow thereunder is subject to certain conditions precedent. In addition, the New York DIP Agreement contains covenants that, among other things, restrict the ability of the New York DIP Borrowers to engage in mergers, acquisitions and asset sales, to make investments and to incur indebtedness.
12. Other Comprehensive (Loss) Income
Other comprehensive (loss) income 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 (loss) income, net of tax are as follows (in millions):
The $55 million in accumulated other comprehensive loss at December 31, 2002, is primarily associated with deferred interest rate swap hedging losses accounted for as qualifying hedges under SFAS No. 133 that had been previously settled.
Pursuant to the bankruptcy proceedings, interest payments were suspended on the debt associated with the Company’s interest rate swaps. Therefore, the deferred interest rate swap hedging losses were reclassified from other comprehensive loss to earnings in 2003, effective with the Chapter 11 filing.
The $27 million in accumulated other comprehensive income at December 31, 2005 is associated with unrealized gains on available for sale securities. The unrealized gains will be reclassified to earnings when the securities are sold.
13. Income Taxes
Details of the income tax provision (benefit) are as follows (in millions):
A reconciliation of the Company’s expected federal statutory income tax (benefit) provision to the effective income tax provision (benefit) 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, 2005 and 2004 (in millions):
Several 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 certain 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 regarded corporate entities were also liquidated, and now form part of 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 Mirant New York, Inc., Hudson Valley Gas Corporation, Mirant Kendall, LLC and Mirant Special Procurement, Inc.
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, 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. Cumulative prior year losses are the most compelling form of negative evidence considered by management in this determination. Additionally, management considered the fact that Mirant had not reimbursed the Company for current period net operating losses since the Petition Date. In 2005, 2004 and 2003, the Company had recognized changes in its valuation allowance of $(534) million, $(4) million and $658 million, respectively, related to its net deferred tax assets.
At December 31, 2005, the Company had $182 million of NOL carryforwards for federal income tax purposes expiring from 2022 to 2025 and $322 million of NOL carryforwards for state income tax purposes expiring on various dates. These NOL carryforwards are available to offset future federal and state income taxes.
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 with no distribution for such liability. Pursuant to the Plan, Mirant has indemnified the Company with respect to this obligation.
The Company has contingent liabilities related to tax uncertainties arising in the ordinary course of business in other jurisdictions. The Company periodically assesses its contingent liabilities in connection with these uncertainties based upon the latest information available. For those uncertainties where it is probable that a loss has been incurred and the loss or range of loss can be reasonably estimated, a liability is recorded on the combined and consolidated financial statements. As additional information becomes available, the assessment and estimates of such liabilities are adjusted accordingly.
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 (benefit) that would be reported if the Company were to be allocated income taxes related to its operations.
Pro forma income tax provision (benefit) 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 (benefit) provision for continuing operations adjusted for reorganization items to the pro forma effective tax provision (benefit) (in millions):
The tax effects of temporary differences that give rise to significant portions of the pro forma deferred tax assets and liabilities would be as follows at December 31, 2005 and 2004 (in millions):
The ultimate utilization of the Company’s remaining NOLs will depend on several factors, including its future financial performance and certain tax elections. Specifically, the Company’s utilization of NOLs will be impacted by whether Mirant elects NOL treatment under Internal Revenue Code Section (“§”) 382(l) (5) or § 382(l) (6). Under § 382(l)(5), Mirant would have unlimited use of its NOLs as long as there is not a change of ownership (broadly defined as 50 percent change of five percent shareholders) within two years of emergence. On a pro forma basis, the § 382(l)(5) election would require the Company to reduce its federal NOLs to approximately $1,834 million from $2,009 million due to interest accrued on debt settled with stock for the three years prior to emergence. Under § 382(l) (6), Mirant would be subject to an overall annual limitation on use of NOLs. Mirant will make the § 382(l) (5) or § 382(l) (6) election in its 2006 annual tax return filed in 2007.
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 6, since the underlying transaction is disregarded for income tax purposes.
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 No. 5, “Accounting for Contingencies,” 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 combined and consolidated financial position, results of operations or cash flows.
Chapter 11 Proceedings
On the Petition Date, and various dates thereafter, the Mirant Debtors filed voluntary petitions for relief under Chapter 11 of the Bankruptcy Code. On August 21, 2003, and September 8, 2003, the Bankruptcy Court entered orders establishing a December 16, 2003, bar date (the “Bar Date”) for filing proofs of claim against the Mirant Debtors’ estates.
Most of the material claims filed against the Mirant Debtors’ estates were disallowed or were resolved and became “allowed” claims before confirmation of the Plan. For example, the claims filed by the California Attorney General, Pacific Gas & Electric (“PG&E”), various other California parties, plaintiffs in certain rate payer class action lawsuits, the plaintiffs in certain bondholder litigation, and Utility Choice, L.P., which are described in the Company’s 2004 Form 10-K, are among the claims that were resolved prior to confirmation of the Plan. A number of claims, however, remain unresolved.
Except for claims and other obligations not subject to discharge under the Plan and unless otherwise provided below, all claims against the Mirant Debtors’ estates representing obligations that arose prior to July 14, 2003, are subject to compromise under the Plan. This means that the claimant will receive a distribution of Mirant common stock, cash, or both Mirant common stock and cash in accordance with the terms of the Plan in satisfaction of the claim. As a result, the exact amount of the claim may still be litigated, but the Company will not be required to make any payment in respect of such litigation until a resolution is obtained, through settlement, judgment or otherwise.
As of December 31, 2005, approximately 23.5 million of the shares of Mirant common stock to be distributed under the Plan have been reserved for distribution with respect to claims that are disputed by the Mirant Debtors and have not been resolved. Under the terms of the Plan, to the extent such claims are resolved now that the Company has emerged from bankruptcy, the claimants will be paid from the reserve of 23.5 million shares on the same basis as if they had been paid out when the Plan became effective. That means that their allowed claims will receive the same pro rata distributions of Mirant common stock, cash, or both common stock and cash as previously allowed claims in accordance with the terms of the Plan. The Company maintains that it has funded the disputed claims reserve at a sufficient level to settle the remaining unresolved proofs of claim it received during the bankruptcy proceedings and any claims resulting from the rejection of certain contracts with PEPCO, as described below in PEPCO Litigation. However, to the extent the aggregate amount of the payouts determined to be due with respect to such 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 shareholders, and the Company would have to pay additional cash amounts as necessary under the terms of the Plan to satisfy such pre-petition claims. The Company will continue to monitor its obligations as the disputed claims are resolved.
The Company’s Lovett and Bowline generation facilities in New York are subject to disputes with local tax authorities regarding property tax assessments and with the New York State Department of Environmental Conservation, (“NYSDEC”) regarding environmental controls. Mirant Lovett is also in discussions with the Independent System Operator of New York (“NYISO”) and utilities regarding an agreement that would compensate Mirant Lovett for the contribution of the Lovett facility to the reliability of the New York electric power system. The facilities are forecasted to have negative operating cash flows at their current tax valuations. Until a settlement is reached on property taxes, environmental controls and reliability that would permit economically feasible operation, the Company’s subsidiaries that own the facilities, Mirant Lovett and Mirant Bowline, will remain in Chapter 11. Mirant Lovett and Mirant Bowline are currently in settlement discussions on all of these issues. Although negotiations are continuing, settlements may not be reached in the near future, or at all. Until such settlements are reached and the companies emerge from bankruptcy, we will not have access to the cash from operations generated from these subsidiaries. Mirant NY-Gen, which owns hydroelectric facilities at Swinging Bridge, Rio and Mongaup, and small combustion turbine facilities at Hillburn and Shoemaker, is insolvent. Its expenses are being funded under a debtor-in-possession facility made by Mirant Americas with the approval of, and under the supervision of, the Bankruptcy Court. Mirant NY-Gen is currently discussing with the Federal Energy Regulatory Commission (“FERC”) appropriate remediation for a sinkhole discovered in May 2005 in the dam at the Swinging Bridge facility. Mirant NY-Gen conducted a flood study to determine downstream consequences if the maximum capacities of the reservoirs were exceeded at its New York Swinging Bridge, Rio and Mongaup generation facilities, and Mirant NY-Gen could be requested by the
FERC to remediate those dams as well. Mirant NY-Gen has initiated discussions with the FERC for surrendering its permits to operate all the hydroelectric facilities at Swinging Bridge, Rio and Mongaup, and expects to begin that formal process soon. It is not possible at this point to determine the cost of remediating the dam at Swinging Bridge and surrendering the permits, but such costs may be substantial.
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 Asset Purchase and Sale Agreement (“APSA”), Mirant and PEPCO entered into the Back-to-Back Agreement with respect to certain PPAs, including PEPCO’s long-term PPAs with Ohio Edison Company (“Ohio Edison”) and Panda-Brandywine L.P. (“Panda”), 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 Ohio Edison PPA terminated in December 2005 and the Panda PPA runs until 2021. Under the Back-to-Back Agreement, Mirant is obligated to purchase power from PEPCO at prices that are typically 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 includes as parties PEPCO and various subsidiaries of ours causes our subsidiaries that are 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 have sought to reject the APSA, the Back-to-Back Agreement, and the Assignment and Assumption Agreement, and the rejection motions have not been resolved. 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 are to be performed by Mirant Power Purchase, LLC (“Mirant Power Purchase”), whose performance is guaranteed by Mirant. If any of the agreements is successfully rejected, the obligations of Mirant Power Purchase, and Mirant’s guarantee obligations terminate with respect to that agreement, and PEPCO would be entitled to a claim in the Chapter 11 proceedings for any resulting damages. That claim would then be addressed under the terms of the Plan. If the Bankruptcy Court were to conclude that the Assignment and Assumption Agreement imposed liability upon the Company’s subsidiaries for the obligations under the Back-to-Back Agreement and the Back-to-Back Agreement were to be rejected, the resulting rejection damages claim could result in a claim in the Chapter 11 proceedings against the Company’s subsidiaries but any such claim would be reduced by the amount recovered by PEPCO on its comparable claim against Mirant.
California and Western Power Markets
California Rate Payer Litigation. Certain of our subsidiaries are subject to litigation related to their activities in California and the western power markets and the high prices for wholesale electricity experienced in the western markets during 2000 and 2001. Various lawsuits were filed in 2000 through 2003 that asserted claims under California law based on allegations that certain owners of electricity generation facilities in California and energy marketers, including the Company, Mirant Americas Energy Marketing and our subsidiaries owning generating facilities in California, engaged in various unlawful and anti-competitive acts that served to manipulate wholesale power markets and inflate wholesale electricity prices in California. All of these suits have been dismissed by final orders except for six such suits that were filed between November 27, 2000, and May 2, 2001, in various California Superior Courts and consolidated before the Superior Court for the County of San Diego for pretrial purposes. Although the plaintiffs dismissed Mirant from those suits, they have not filed to dismiss certain of our subsidiaries that are also
defendants. On October 3, 2005, the California state court dismissed those six consolidated suits on the grounds that the plaintiffs’ claims were barred by federal preemption as a result of the Federal Power Act. On December 5, 2005, the plaintiffs filed an appeal of the dismissal. The plaintiffs in the six consolidated suits did not file claims in the Chapter 11 proceedings, and it is the Company’s view that their claims are barred by the Plan now that it has become effective.
FERC Refund Proceedings. On July 25, 2001, the FERC issued an order requiring proceedings (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, to the California Independent System Operator (“CAISO”) or the California Power Exchange (“Cal PX”) from October 2, 2000, through June 20, 2001 (the “Refund Period”). Various parties have appealed these FERC orders to the United States Court of Appeals for the Ninth Circuit (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 California Department of Water Resources (the “DWR”) and other parties. Any such expansion of the Refund Period or the types of sales of electricity potentially subject to refund could significantly increase the refund exposure of Mirant Americas Energy Marketing in this proceeding. Although Mirant Americas Energy Marketing is the Mirant entity that engaged in transactions with the CAISO and the Cal PX, the orders issued by the FERC in the refund proceedings, and the filings made by other parties in those proceedings, generally refer to the Mirant entity involved as Mirant without being more specific. It is the Company’s view that the Mirant entity that would actually be liable to third parties for any refunds determined by the FERC to be owed, or that would be due any receivables found to be owed to Mirant, is Mirant Americas Energy Marketing.
In the July 25, 2001, order, the FERC also ordered that a preliminary evidentiary proceeding be held to develop a factual record on 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. In that proceeding, the California Attorney General, the California Public Utility Commission (the “CPUC”) and the California Electricity Oversight Board (the “EOB”) filed to recover certain refunds from parties, including Mirant Americas Energy Marketing, for bilateral sales of electricity to the DWR at the California/Oregon border, claiming that such sales took place in the Pacific Northwest. In an order issued June 25, 2003, the FERC ruled that no refunds were owed and terminated the proceeding. On November 10, 2003, the FERC denied requests for rehearing filed by various parties. Various parties have appealed the FERC’s decision to the Ninth Circuit.
On September 9, 2004, the Ninth Circuit reversed the FERC’s dismissal of 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. The Ninth Circuit remanded the proceeding to the FERC for it to determine 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. Mirant Americas Energy Marketing and other parties have filed a petition for rehearing with the Ninth Circuit that remains pending.
On January 14, 2005, Mirant and certain of its subsidiaries, including the Company, entered into a Settlement and Release of Claims Agreement (the “California Settlement”) with PG&E, Southern California Edison Company (“SCE”), 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”) and with the Office of Market Oversight and Investigations of the FERC. The California Settlement settled a number of disputed lawsuits and regulatory proceedings that were pursued originally in state and federal
courts and before the FERC. The Mirant entities that are parties to the California Settlement (collectively, the “Mirant Settling Parties”) include Mirant Corporation, Mirant Americas Energy Marketing, the Company, and Mirant North America, (as the successor to Mirant California Investments, Inc.). The California Settlement was approved by the FERC on April 13, 2005, and became effective 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 proceeding also initiated by the FERC in July 2001 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, and (3) in any proceedings at the FERC resulting from the Ninth Circuit’s reversal of the FERC’s dismissal of 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 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. Subject to applicable bankruptcy law, however, Mirant Americas Energy Marketing will continue to be liable 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 of 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).
It is the Company’s view 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 Mirant Americas Generation, that a FERC staff report issued on March 26, 2003, identified as having potentially engaged in one or more trading strategies of the type employed by Enron Corporation and its affiliates (“Enron”), as described in Enron memos released by the FERC in May 2002. 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. The Trading Practices Order requires the CAISO to identify transactions between January 1, 2000, and June 20, 2001, that may involve the identified trading strategies, and then requires the applicable sellers involved in those transactions to demonstrate why such transactions were not violations of the CAISO and Cal PX tariffs. On September 30, 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, under which Mirant Americas Energy Marketing would pay $332,411 to settle the show cause proceeding, except for an issue related to sales of ancillary services, which is discussed below. In a November 14, 2003, order in a different proceeding, the FERC ruled that certain allegations of improper trading conduct with respect to the selling of ancillary services during 2000 should be resolved in the show cause proceeding. On December 19, 2003, the Mirant entities filed with the FERC for approval of an amendment to the Trading Settlement Agreement reached with the FERC Trial Staff
with respect to the sale of ancillary services. Under that amendment, the FERC would have an allowed unsecured claim in Mirant Americas Energy Marketing’s bankruptcy proceeding for $3.67 million in settlement of the allegations with respect to the sale of ancillary services. 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 have filed motions for rehearing with the FERC, which motions remain pending.
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 has appealed that dismissal to the United States Court of Appeals for the Ninth Circuit. The sales made under the contract with Nevada Power have been completed, and we expect 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 Co. 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. On June 25, 2003, the FERC dismissed this proceeding. Southern California Water has appealed that dismissal to the United States Court of Appeals for the Ninth Circuit. The contract with Southern California Water Company continues through 2006. 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 Co., including any potential refund obligations.
Bondholder Litigation
Mirant Americas Generation Bondholder Suit. On June 10, 2003, certain holders of senior notes of Mirant Americas Generation maturing after 2006 filed a complaint in the Court of Chancery of the State of Delaware, California Public Employees’ Retirement System, et al. v. Mirant Corporation, et al., that named as defendants Mirant, Mirant Americas, Mirant Americas Generation, certain past and present Mirant directors, and certain past and present Mirant Americas Generation managers. Among other claims, the plaintiffs assert that a restructuring plan pursued by the Company prior to its filing a petition for reorganization under Chapter 11 of the Bankruptcy Code was in breach of fiduciary duties allegedly owed to them by Mirant, Mirant Americas and Mirant Americas Generation’s managers. In addition, the plaintiffs challenge certain dividends and distributions made by Mirant Americas Generation prior to the Petition Date. The plaintiffs seek damages in excess of $1 billion. Mirant has removed this suit to the United States District Court for the District of Delaware. This action was stayed with respect to the Mirant entities that are defendants by the filing of the Chapter 11 proceedings of these entities. The order entered by the Bankruptcy Court confirming the Plan enjoins the prosecution of this action and requires that it be dismissed. On March 8, 2006, the Bankruptcy Court entered an order compelling the plaintiffs in this action to dismiss their complaint in accordance with the terms of the Plan. On March 17, 2006, the parties filed a stipulation of dismissal dismissing the suit.
U.S. Government Inquiries
Department of Justice Inquiries. In November 2002, Mirant received a subpoena from the Department of Justice (“DOJ”), acting through the United States Attorney’s office for the Northern
District of California, requesting information about its activities and those of its subsidiaries for the period since January 1, 1998. The subpoena requested information related to the California energy markets and other topics, including the reporting of inaccurate information to the trade press that publish natural gas or electricity spot price data. The subpoena was issued as part of a grand jury investigation. The DOJ’s investigation of the reporting of inaccurate natural gas price information is continuing, and Mirant has held preliminary discussions with DOJ regarding the disposition of this matter. The DOJ’s investigation is based upon the same circumstances that were the subject of an investigation by the Commodity Futures Trading Commission (“CFTC”) that was settled in December 2004. As described in Mirant’s Annual Report on Form 10-K for the year ended December 31, 2004, in Legal Proceedings-Other Governmental Proceedings-CFTC Inquiry, Mirant and Mirant Americas Energy Marketing pursuant to the settlement consented to the entry of an order by the CFTC in which it made findings, which are neither admitted nor denied by Mirant and Mirant Americas Energy Marketing, that (1) from January 2000 through December 2001, certain Mirant Americas Energy Marketing natural gas traders (a) knowingly reported inaccurate price, volume, and/or counterparty information regarding natural gas cash transactions to publishers of natural gas indices and (b) inaccurately reported to index publishers transactions observed in the market as Mirant Americas Energy Marketing transactions and (2) from January to October 2000, certain Mirant Americas Energy Marketing west region traders knowingly delivered the false reports in an attempt to manipulate the price of natural gas. Under the settlement, the CFTC received a subordinated allowed, unsecured claim against Mirant Americas Energy Marketing of $12.5 million in the Chapter 11 proceedings. The DOJ could decide that further action against Mirant and Mirant Americas Energy Marketing is not appropriate or could seek indictments against one or more Mirant entities, or the DOJ and Mirant could agree to a disposition that might involve undertakings or fines, the amount of which cannot be reasonably estimated at this time but which could be material. Mirant has cooperated fully with the DOJ and intends to continue to do so. At this time, it is the Company’s view that any action taken by the DOJ against Mirant or its subsidiaries related to the reporting of natural gas price information would not involve us or our subsidiaries except to the extent that any disposition of this matter results in ongoing undertakings by Mirant Energy Trading as the recipient of the assets of Mirant Americas Energy Marketing under the Plan.
Environmental Matters
EPA Information Request. In January 2001, the EPA issued a request for information to Mirant concerning the air permitting and air emissions control implications under the EPA’s new source review regulations (“NSR”) promulgated under the Federal Clean Air Act (“Clean Air Act”) of past repair and maintenance activities at the Potomac River plant in Virginia and the Chalk Point, Dickerson and Morgantown plants in Maryland. The requested information concerns the period of operations that predates the Company subsidiaries’ ownership and lease of those plants. Mirant has responded fully to this request. Under the APSA, PEPCO is responsible for fines and penalties arising from any violation associated with historical operations prior to the Company subsidiaries’ acquisition or lease of the plants. If the Mirant Debtors succeed in rejecting the APSA as described above in PEPCO Litigation, PEPCO may assert that it has no obligation to reimburse Mirant for any fines or penalties imposed upon Mirant for periods prior to the Company subsidiaries’ acquisition or lease of the plants. If a violation is determined to have occurred at any of the plants, the Company subsidiary owning or leasing the plant may be responsible for the cost of purchasing and installing emissions control equipment, the cost of which may be material. If such violation is determined to have occurred after the Company’s subsidiaries acquired or leased the plants or, if occurring prior to the acquisition or lease, is determined to constitute a continuing violation, the Company subsidiary owning or leasing the plant at issue would also be subject to fines and penalties by the state or federal government for the period subsequent to its acquisition or lease of the plant, the cost of which may be material.
Mirant Potomac River Notice of Violation. On September 10, 2003, the Virginia Department of Environmental Quality (“Virginia DEQ”) issued a Notice of Violation (“NOV”) to Mirant Potomac River alleging that it violated its Virginia Stationary Source Permit to Operate by emitting NOx in excess of the “cap” established by the permit for the 2003 summer ozone season. Mirant Potomac River responded to the NOV, asserting that the cap is unenforceable, noting that it can comply through the purchase of emissions allowances and raising other equitable defenses. Virginia’s civil enforcement statute provides for injunctive relief and penalties. On January 22, 2004, the EPA issued an NOV to Mirant Potomac River alleging the same violation of its Virginia Stationary Source Permit to Operate as set out in the NOV issued by the Virginia DEQ.
On September 27, 2004, Mirant Potomac River, Mirant Mid-Atlantic, the Virginia DEQ, the Maryland Department of the Environment, the DOJ and the EPA entered into, and filed for approval with the United States District Court for the Eastern District of Virginia, a consent decree that, if approved, will resolve Mirant Potomac River’s potential liability for matters addressed in the NOVs previously issued by the Virginia DEQ and the EPA. The consent decree requires Mirant Potomac River and Mirant Mid-Atlantic to (1) install pollution control equipment at the Potomac River plant and at the Morgantown plant leased by Mirant Mid-Atlantic in Maryland, (2) comply with declining system-wide ozone season NOx emissions caps from 2004 through 2010, (3) comply with system-wide annual NOx emissions caps starting in 2004, (4) meet seasonal system average emissions rate targets in 2008 and (5) pay civil penalties and perform supplemental environmental projects in and around the Potomac River plant expected to achieve additional environmental benefits. Except for the installation of the controls planned for the Potomac River units and the installation of selective catalytic reduction (“SCR”) or equivalent technology at Mirant Mid-Atlantic’s Morgantown Units 1 and 2 in 2007 and 2008, the consent decree does not obligate the Company’s subsidiaries to install specifically designated technology, but rather to reduce emissions sufficiently to meet the various NOx caps. Moreover, as to the required installations of SCRs at Morgantown, Mirant Mid-Atlantic may choose not to install the technology by the applicable deadlines and leave the units off either permanently or until such time as the SCRs are installed. The consent decree is subject to the approval of the district court and the Bankruptcy Court.
The owners/lessors under the lease-financing transactions covering the Morgantown and Dickerson plants (the “Owners/Lessors”) objected to the proposed consent decree in the Bankruptcy Court and filed a motion to intervene in the district court action. As part of a resolution of disputed matters in the Chapter 11 proceedings, the Owners/Lessors have now agreed not to object to the consent decree, subject to certain terms set forth in the Plan and Confirmation Order.
On July 22, 2005, the district court granted a motion filed by the City of Alexandria seeking to intervene in the district court action, although the district court imposed certain limitations on the City of Alexandria’s participation in the proceedings. On September 23, 2005, the City of Alexandria filed a motion seeking authority to file an amended complaint in the action seeking injunctive relief and civil penalties under the Clean Air Act for alleged violations by Mirant Potomac River of its Virginia Stationary Source Permit To Operate and the State of Virginia’s State Implementation Plan. Based upon a computer modeling, the City of Alexandria asserted that emissions from the Potomac River plant exceed national ambient air quality standards (“NAAQS”) for SO2, nitrogen dioxide (“NO2”), and particulate matter. The City of Alexandria also contended based on its modeling analysis that the plant’s emissions of hydrogen chloride and hydrogen fluoride exceed Virginia state emissions standards. Mirant Potomac River disputes the City of Alexandria’s allegations that it has violated the Clean Air Act and Virginia law. On December 2, 2005, the district court denied the City of Alexandria’s motion seeking to file an amended complaint.
Mirant Potomac River Downwash Study. On September 23, 2004, the Virginia DEQ and Mirant Potomac River entered into an order by consent with respect to the Potomac River plant under which Mirant Potomac River agreed to perform a modeling analysis to assess the potential effect of “downwash”
from the plant (1) on ambient concentrations of SO2, NO2, carbon monoxide (“CO”) and particulate matter less than or equal to 10 micrometers (“PM10”) for comparison to the applicable NAAQS and (2) on ambient concentrations of mercury for comparison to Virginia Standards of Performance for Toxic Pollutants. Downwash is the effect that occurs when aerodynamic turbulence induced by nearby structures causes emissions from an elevated source, such as a smokestack, to be mixed rapidly toward the ground resulting in higher ground level concentrations of emissions. If the modeling analysis indicates that emissions from the facility may cause exceedances of the NAAQS for SO2, NO2, CO or PM10, or exceedances of mercury compared to Virginia Standards of Performance for Toxic Pollutants, the consent order requires Mirant Potomac River to submit to the Virginia DEQ a plan and schedule to eliminate and prevent such exceedances on a timely basis. Upon approval by the Virginia DEQ of the plan and schedule, the approved plan and schedule is to be incorporated by reference into the consent order. The results of the computer modeling analysis showed that emissions from the Potomac River plant have the potential to contribute to localized, modeled instances of exceedances of the NAAQS for SO2, NO2 and PM10 under certain conditions.
On August 24, 2005, power production at all five units of the Potomac River generating facility was temporarily halted in response to a directive from the Virginia DEQ. The decision to temporarily shut down the facility arose from findings of a study commissioned under the order by consent referred to above. The Virginia DEQ’s directive was based on results from the study’s computer modeling showing that air emissions from the facility have the potential to contribute to localized, modeled exceedances of the health-based NAAQS under certain conditions. On August 25, 2005, the District of Columbia Public Service Commission filed an emergency petition and complaint with the FERC and the Department of Energy (“DOE”) to prevent the shutdown of the Potomac River facility. The matter remains pending before the FERC and the DOE. On September 21, 2005, Mirant Potomac River commenced partial operation of one unit of the plant. On December 20, 2005, due to a determination by the DOE that an emergency situation exists with respect to a shortage of electric energy, the DOE ordered Mirant Potomac River to generate electricity at the Potomac River generation facility, as requested by PJM, during any period in which one or both of the transmission lines serving the central Washington, D.C. area are out of service due to a planned or unplanned outage. In addition, the DOE ordered Mirant Potomac River, at all other times, for electric reliability purposes, to keep as many units in operation as possible and to reduce the start-up time of units not in operation. The DOE required Mirant Potomac River to submit a plan, on or before December 30, 2005, that met this requirement and did not significantly contribute to NAAQS exceedances. The DOE advised that it would consider Mirant Potomac River’s plan in consultation with the EPA. The order further provides that Mirant Potomac River and its customers should agree to mutually satisfactory terms for any costs incurred by it under this order or just and reasonable terms shall be established by a supplemental order. Certain parties filed for rehearing of the DOE order, and on February 17, 2006, the DOE issued an order granting rehearing solely for purposes of considering the rehearing requests further. Mirant Potomac River submitted an operating plan in accordance with the order. On January 4, 2006, the DOE issued an interim response to Mirant Potomac River’s operating plan authorizing immediate operation of one baseload unit and two cycling units, making it possible to bring the entire plant into service within approximately 28 hours. The DOE’s order expires after September 30, 2006, but Mirant Potomac River expects it will be able to continue to operate these units after that expiration. In a letter received December 30, 2005, the EPA invited Mirant Potomac River and the Virginia DEQ to work with the EPA to ensure that Mirant Potomac River’s operating plan submitted to the DOE adequately addresses NAAQS issues. The EPA also asserts in its letter that Mirant Potomac River did not immediately undertake action as directed by the Virginia DEQ’s August 19, 2005, letter and failed to comply with the requirements of the Virginia State Implementation Plan established by that letter. Mirant Potomac River received a second letter from the EPA on December 30, 2005, requiring Mirant to provide certain requested information as part of an EPA investigation to determine the Clean Air Act compliance status of the Potomac River facility. The facility will not resume normal operations
until it can satisfy the requirements of the Virginia DEQ and the EPA with respect to NAAQS, unless, for reliability purposes, it is required to return to operation by a governmental agency having jurisdiction to order its operation. On January 9, 2006, the FERC issued an order directing PJM and PEPCO to file a long-term plan to maintain adequate reliability in the Washington D.C. area and surrounding region and a plan to provide adequate reliability pending implementation of this long-term plan. On February 8, 2006, PJM and PEPCO filed their proposed reliability plans. The Company is working with the relevant state and federal agencies with the goal of restoring all five units of the facility to normal operation in 2007. The financial and operational implications of the discontinued or limited operation of the Potomac River plant or any such modifications are not known at this time, but could be material depending on the length of time that operations are discontinued or limited.
City of Alexandria Nuisance Suit. On October 7, 2005, the City of Alexandria filed a suit against Mirant Potomac River and Mirant Mid-Atlantic in the Circuit Court for the City of Alexandria. The suit asserts nuisance claims, alleging that the Potomac River plant’s emissions of coal dust, flyash, NOx, SO2, particulate matter, hydrogen chloride, hydrogen fluoride, mercury and oil pose a health risk to the surrounding community and harm property owned by the City. The City seeks injunctive relief, damages and attorneys’ fees. On February 17, 2006, the City amended its complaint to add additional allegations in support of its nuisance claims relating to noise and lighting, interruption of traffic flow by trains delivering coal to the Potomac River plant, particulate matter from the transport and storage of coal and flyash, and potential coal leachate into the soil and groundwater from the coal pile.
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 Company’s Chapter 11 proceedings asserting a claim seeking to require the Company to provide funding to its subsidiaries owning generating facilities in New York to satisfy certain specified environmental compliance obligations. The State of New York alleges that during the pendency of the Chapter 11 proceedings the Company and its subsidiaries that have emerged from bankruptcy made decisions on behalf of the Company’s subsidiaries owning generating facilities in New York and did not appropriately maintain the corporate separateness between itself and those subsidiaries. The Company disputes those allegations. The State of New York cites 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, most of which are not material. The most significant compliance obligation identified by the State of New York in its notice of administrative claim relates to a consent decree entered into on June 11, 2003 (the “2003 Consent Decree”), by Mirant New York and Mirant Lovett with the State of New York to resolve issues related to NSR requirements under the Clean Air Act related to the Lovett plant. Under the 2003 Consent Decree, Mirant Lovett is required to make an election to install certain environmental controls on units 4 and 5 of the Lovett facility or shut down those units by 2007 to 2008. The State of New York notes in its notice of administrative claim that the cost of implementing such environmental controls could exceed $200 million. The State of New York and the NYSDEC have executed a stipulated order with the Company and its New York subsidiaries to stay resolution of this administrative claim. The stipulated order was entered by the Bankruptcy Court on February 23, 2006.
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 Federal Water Pollution Control Act (the “Clean Water Act”). The suit alleges that Mirant Lovett’s failure to implement a marine life exclusion system at its Lovett generating plant and to perform monitoring for the exclusion of certain aquatic organisms from the plant’s cooling water intake structures violates Mirant Lovett’s water discharge permit issued by the State of New York. The plaintiff requests the court to enjoin Mirant Lovett from continuing to operate the Lovett generating plant 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 attorney’s fees. On April 20, 2005, the district court approved a stipulation agreed to by the plaintiff and
Mirant Lovett that stays the suit until 60 days after entry of an order by the Bankruptcy Court confirming a plan of reorganization for Mirant Lovett becomes final and non-appealable.
City of Alexandria Zoning Action
On December 18, 2004, the City Council for the City of Alexandria, Virginia (the “City Council”) adopted certain zoning ordinance amendments recommended by the City Planning Commission that resulted in the zoning status of Mirant Potomac River’s generating plant being changed from “noncomplying use” to “nonconforming use subject to abatement.” Under the nonconforming use status, unless Mirant Potomac River applies for and is granted a special use permit for the plant during the seven-year abatement period, the operation of the plant must be terminated within a seven-year period, and no alterations that directly prolong the life of the plant will be permitted during the seven-year period. If Mirant Potomac River were to apply for and receive a special use permit for the plant, the City Council would likely impose various conditions and stipulations as to the permitted use of the plant and seek to limit the period for which it could continue to operate.
At its December 18, 2004, meeting, the City Council also approved revocation of two special use permits issued in 1989 (the “1989 SUPs”), one applicable to the administrative office space at Mirant Potomac River’s plant and the other for the plant’s transportation management plan. Under the terms of the approved action, the revocation of the 1989 SUPs was to take effect 120 days after the City Council revocation, provided, however, that if Mirant Potomac River within such 120-day period filed an application for the necessary special use permits to bring the plant into compliance with the zoning ordinance provisions then in effect, the effective date of the revocation of the 1989 SUPs would be stayed until final decision by the City Council on such application. The approved action further provides that if such special use permit application is approved by the City Council, revocation of the 1989 SUPs will be dismissed as moot, and if the City Council does not approve the application, the revocation of the 1989 SUPs will become effective and the plant will be considered a nonconforming use subject to abatement.
On January 18, 2005, Mirant Potomac River and Mirant Mid-Atlantic filed a complaint against the City of Alexandria and the City Council in the Circuit Court for the City of Alexandria. The complaint seeks to overturn the actions taken by the City Council on December 18, 2004, changing the zoning status of Mirant Potomac River’s generating plant and approving revocation of the 1989 SUPs, on the grounds that those actions violated federal, state and city laws. The complaint asserts, among other things, that the actions taken by the City Council constituted unlawful spot zoning, were arbitrary and capricious, constituted an unlawful attempt by the City Council to regulate emissions from the plant, and violated Mirant Potomac River’s due process rights. Mirant Potomac River and Mirant Mid-Atlantic request the court to enjoin the City of Alexandria and the City Council from taking any enforcement action against Mirant Potomac River or from requiring it to obtain a special use permit for the continued operation of its generating plant. On January 18, 2006, the court issued an oral ruling following a trial that the City of Alexandria acted unreasonably and arbitrarily in changing the zoning status of Mirant Potomac River’s generating plant and in revoking the 1989 SUPs. On February 24, 2006, the court entered judgment in favor of Mirant Potomac River and Mirant Mid-Atlantic declaring the change in the zoning status of Mirant Potomac River’s generating plant adopted December 18, 2004, to be invalid and vacating the City Council’s revocation of the 1989 SUPs. The City of Alexandria has filed notice of its appeal of this judgment.
PEPCO Assertion of Breach of Local Area Support Agreement
Following the shutdown of the Potomac River plant on August 24, 2005, Mirant Potomac River notified PEPCO on August 30, 2005, that it considered the circumstances resulting in the shutdown of the plant to constitute a force majeure event under the Local Area Support Agreement dated December 19, 2000, between PEPCO and Mirant Potomac River. That agreement imposes obligations upon Mirant
Potomac River to dispatch the Potomac River plant under certain conditions, to give PEPCO several years advance notice of any indefinite or permanent shutdown of the plant, and to pay all or a portion of certain costs incurred by PEPCO for transmission additions or upgrades when an indefinite or permanent shutdown of the plant occurs prior to December 19, 2010. On September 13, 2005, PEPCO notified Mirant Potomac River that it considers Mirant Potomac River’s shutdown of the plant to be a material breach of the Local Area Support Agreement that is not excused under the force majeure provisions of the agreement. PEPCO contends that Mirant Potomac River’s actions entitle PEPCO to recover as damages the cost of constructing additional transmission facilities. PEPCO, on January 24, 2006, filed a notice of administrative claims asserting that Mirant Potomac River’s shutdown of the Potomac River plant causes Mirant Potomac River to be liable for the cost of such transmission facilities, which cost it estimates to be in excess of $70 million. Mirant Potomac River disputes PEPCO’s interpretation of the agreement. The outcome of this matter cannot be determined at this time.
Asbestos Cases
As part of the PEPCO purchase, Mirant agreed to indemnify PEPCO for certain liabilities arising in lawsuits filed after December 19, 2000, even if they relate to incidents occurring prior to that date, with certain qualifications. Since the acquisition, PEPCO has notified Mirant of more than 100 asbestos cases, distributed among three Maryland jurisdictions (Prince George’s County, Baltimore City and Baltimore County), as to which it claims a right of indemnity. Based on information and relevant circumstances known at this time, the Company does not anticipate that these suits will have a material adverse effect on its financial position, results of operations or cash flows. Under the Plan these indemnity obligations arising under the APSA with PEPCO became the obligations of Mirant Power Purchase.
New York Tax Proceedings
The Company’s subsidiaries that own the Bowline and Lovett generating plants in New York are the petitioners in various proceedings (“Tax Certiorari Proceedings”) initially brought in the New York state courts challenging the assessed value of those generating plants determined by their respective local taxing authorities. Mirant Bowline has challenged the assessed value of the Bowline generating facility and the resulting local tax assessments paid for tax years 1995 through 2005. Mirant Bowline succeeded to rights held by Orange & Rockland Utilities, Inc. (“Orange & Rockland”) for the tax years prior to its acquisition of the Bowline Plant in 1999 under its agreement with Orange & Rockland for the purchase of that plant. Mirant Lovett has initiated proceedings challenging the assessed value of the Lovett facility for each of the years 2000 through 2005. If the Tax Certiorari Proceedings result in a reduction of the assessed value of the generating facility at issue in each proceeding, the New York Debtor owning the facility would be entitled to a refund with interest of any excess taxes paid for those tax years.
On September 30, 2003, the Mirant Debtors filed a motion (the “Tax Determination Motion”) with the Bankruptcy Court requesting that it determine what the property tax liability should have been for the Bowline generating facility in each of the years 1995 through 2003 and for the Lovett generating facility in each of the years 2000 through 2003. The bases for the relief requested in the Tax Determination Motion on behalf of Mirant Bowline and Mirant Lovett were that the assessed values of the generating facilities made by the relevant taxing authorities had no justifiable basis and were far in excess of their actual value. The local taxing authorities have opposed the Tax Determination Motion, arguing that the Bankruptcy Court either lacks jurisdiction over the matters addressed by the Tax Determination Motion or should abstain from addressing those issues so that they can be addressed by the state courts in which the Tax Certiorari Proceedings described in the preceding paragraph were originally filed.
Collectively, Mirant Bowline and Mirant Lovett have not paid approximately $62 million assessed by local taxing authorities on the Bowline and Lovett generating facilities for 2003, which fell due on September 30, 2003, and January 30, 2004, approximately $53 million assessed by local taxing authorities on the generating facilities for 2004 that fell due on September 30, 2004, and January 30, 2005, and approximately $59 million assessed by local taxing authorities on the generating facilities for 2005 that fell due on September 30, 2005, and January 30, 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. The failure to pay the taxes due on September 30, 2003, January 30, 2004, September 30, 2004, January 30, 2005, September 30, 2005, and January 30, 2006, could subject Mirant Bowline and Mirant Lovett to additional penalties and interest.
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.
Other Contingencies
On May 5, 2005, Mirant NY-Gen discovered a sinkhole at its Swinging Bridge dam, located in Sullivan County, New York. In response, Mirant NY-Gen filled this sinkhole, inspected the dam’s penstock and slopes for damage, drew down the lake level, and cleaned the diversion tunnel. Mirant NY-Gen’s analysis indicates that the most probable cause of the sinkhole was erosion of soil comprising the dam through a hole in the penstock. The dam is currently stabilized, but is in need of additional repairs. Mirant NY-Gen currently expects to incur additional costs to repair the dam that could be material. Mirant NY-Gen currently expects to recover insurance proceeds for a portion of these repair costs. As a result of the sinkhole, Mirant NY-Gen was required to perform and provide to the FERC a flood study relating to the Swinging Bridge, Rio and Mongaup reservoirs to determine the maximum capacity of the reservoirs and the down stream consequences of a rain event resulting in a greater than the maximum capacity event. The flood study found that under the very extreme weather conditions assumed for the study (which included rainfall over a short period in amounts well in excess of the highest rainfall amounts recorded for such a period historically), the water flowing into the reservoirs could cause the level of the reservoirs to exceed the height of the dams at Mirant NY-Gen’s hydro facilities, leading to downstream flooding. Mirant NY-Gen is evaluating the results of the flood study and determining what modifications may be warranted to its hydro facilities based on those results. The costs of such modifications, if any are necessary, are unknown at this time, but could be significant. Mirant NY-Gen currently remains in Chapter 11. Mirant NY-Gen has requested the Bankruptcy Court to approve a debtor-in-possession loan to it from Mirant Americas to provide funding for the repairs on the Swinging Bridge dam.
15. Asset Retirement Obligations
Effective January 1, 2003, the Company adopted SFAS No. 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. The liability is accreted to its present fair value, and the capitalized cost is depreciated over the useful life of the related asset. Asset retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 and FIN 47 are those for which a legal obligation exists under enacted laws, statutes and written or oral contractions, including obligations arising under the doctrine of promissory estoppel.
The Company identified certain asset retirement obligations within its power generation operations. 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, closing of ash disposal sites and closing of owned 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 acquired 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. However, 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 represents the balance of the asset retirement obligations and the additions and accretion of the asset retirement obligations (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):
16. Commitments and Contingencies
Mirant Americas Generation 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 and Letters of Credit
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 trade credit support 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 of default by the Company, the counterparty can draw on a letter of credit or apply cash collateral held to satisfy the existing amounts outstanding under an open contract. Letters of credit that
expired in 2005 were drawn or replaced with another form of credit support to the counterparty, as required. The Company’s outstanding issued letters of credit totaled $56 million as of December 31, 2005.
Following is a summary of cash collateral posted with counterparties and brokers and letters of credit issued at December 31, (in millions):
Commitments
In addition to debt and other obligations in the combined and consolidated balance sheets, Mirant Americas Generation has the following annual commitments at December 31, 2005 under various agreements (in millions):
Operating Leases
Mirant Mid-Atlantic leases the Morgantown and Dickerson baseload units and associated property through 2034 and 2029, respectively, and 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. Rent expenses associated with the Morgantown and Dickerson operating leases totaled approximately $99 million, $103 million and $96 million for the years ended December 31, 2005, 2004 and 2003, respectively. While there is variability in the scheduled payment amounts over the lease term, the Company recognizes rental expense for these leases on a straight-line basis. The rental expense based on the original scheduled rent payments is $96 million per year. The additional expense recorded in 2005 and 2004 was payable under the terms of the leases and was commensurate with the 0.5% increase in interest on the lessor notes that was payable by the lessors for the period in which Mirant Mid-Atlantic was not a reporting entity under the Securities Exchange Act of 1934. As of December 31, 2005 and 2004, Mirant Mid-Atlantic had paid approximately $292 million and $285 million, respectively, of actual operating lease payments in accordance with the lease agreements in excess of rent expense recognized. In addition to the regularly scheduled rent payments, Mirant Mid-Atlantic paid an additional $11 million in 2004, as required by the lease agreements. A further $12 million of scheduled rent due on June 30, 2005, was funded through a draw made by the lease trustee on letters of credit arranged by the Company. In September 2005, the lease trustee made an additional draw of $49 million prior to the letters of credit expiration in September 2005. This amount is recorded in funds on deposit in the combined and consolidated balance sheets. On January 3, 2006, as part of the settlement and emergence from bankruptcy, Mirant North America posted a $75 million letter of credit for the benefit of Mirant Mid-Atlantic to cover the debt service reserve obligation on the leases. Upon posting of the letter of credit, the lease trustee returned $56 million of cash collateral held to Mirant Mid-Atlantic.
As of December 31, 2005, the total notional minimum lease payments for the remaining terms of the leases aggregated approximately $2.4 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 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.
On November 30, 2005, the Company entered into a settlement agreement with the Morgantown and Dickerson facilities’ owner lessors and the indenture trustee. Pursuant to this settlement agreement and the Plan, the Company has made several payments including a settlement payment of $6.5 million each to the owner lessors and the indenture trustee, $2.9 million as restoration payments under the leases, and a reimbursement of legal and consulting fees of approximately $22 million. With the exception of $6.5 million paid to the indenture trustee in January 2006, the remaining amounts were paid in December 2005. The total costs of $38 million have been recorded in reorganization items, net in the combined statements of operations.
The Company has commitments under other operating leases with various terms and expiration dates. Total minimum lease payments under non-cancelable operating leases is $16 million for the period from 2006 to 2010 and total $15 million thereafter. Expenses associated with these commitments totaled approximately $4 million, $5 million and $4 million during 2005, 2004 and 2003, respectively.
Fuel and Transportation Commitments
In April 2002, Mirant Mid-Atlantic entered into a long-term synthetic fuel purchase agreement. The fuel supplier converts coal feedstock received at Mirant Mid-Atlantic’s Morgantown facility into a synthetic fuel. Under the terms of the agreement, Mirant Mid-Atlantic is required to purchase a minimum of 2.4 million tons of fuel per annum through December 2007. Minimum purchase commitments became effective upon the commencement of the synthetic fuel plant operation at the Morgantown facility in July 2002. The purchase price of the fuel varies with the delivered cost of the coal feedstock. Based on current coal prices, as of December 31, 2005, total estimated commitments under this agreement were $200 million. Expenses associated with this agreement totaled approximately $125 million, $141 million and $115 million for the years ended December 31, 2005, 2004 and 2003, respectively, and are recorded in cost of fuel, electricity and other products-nonaffiliate on the accompanying combined statements of operations.
In addition to the coal commitment described above, the Company has approximately $245 million in purchase commitments related to an arrangement between Mirant Energy Trading, formerly Mirant Americas Energy Marketing, and the synthetic fuel supplier whereby the synthetic fuel supplier is required to purchase coal directly from the coal supplier. Mirant Energy Trading’s coal purchase commitments, and thereby the Company’s commitments, are reduced to the extent that the synthetic fuel supplier purchases coal under this arrangement. During the first quarter of 2005, the Company recognized a $13 million gain due to a net settlement in lieu of receiving certain volumes of coal from the coal supplier as a result of rail car transportation scheduling issues which resulted in lower cost of fuel-affiliate.
The Company has also entered into a fuel supply agreement with an independent third party to provide approximately 90% of the estimated coal to be burned at one of the New York facilities through
2005. The Company had total minimum commitments under fuel purchase and transportation agreements of $513 million at December 31, 2005.
This supplier concentration could adversely affect the Company’s financial position or results of operations should these parties default under the provisions of the agreements.
Long-Term Service Agreements
As of December 31, 2005, the total estimated commitments under long-term service agreements (“LTSAs”) associated with turbines installed or in storage were approximately $271 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 several major 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 inflationary adjustment.
Other Purchase Commitments
Other purchase commitments represents open purchase orders less invoices received or accrued 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 the Company’s generation facilities. Mirant Mid-Atlantic entered into an agreement on June 24, 2005 for an SCR System at the Morgantown generating station. The system shall be furnished and installed to comply with a State of Maryland environmental consent decree to reduce the emissions of NOx. The contract value of this capital expenditure is approximately $94 million.
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 due to 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, 2005. Based upon this assessment, our management concluded that, as of December 31, 2005, 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.
Changes in Internal Controls
Since October 1, 2005, our Board of Managers and several key senior management positions, including the Chief Executive Officer, have been replaced with new management personnel not previously with the Company. Because a company’s control environment is affected both by the attitude of senior management and management’s awareness of the function of the control environment, we have examined our control environment in light of these management changes to ensure that it is still functioning appropriately.
The Company’s new senior management personnel have extensive experience in our sector and have demonstrated their support for a strong control environment. Furthermore, since their arrival, certain factors that we rely on to establish and maintain the proper “tone at the top,” including corporate governance policies and communication programs, have been supported and strengthened. We have maintained the same information technology controls, and our internal audit and internal control organizations continue to function in the same manner as they did prior to the management changes and without restriction or limitation.
The management of the Company, therefore, has concluded that the changes to senior management that occurred in the fourth quarter of 2005 did not materially affect, and are not reasonably likely to materially affect, internal controls.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant
The following table sets forth information with respect to our managers who are not also executive officers as of January 1, 2006.
The following table sets forth information with respect to our executive officers as of January 1, 2006.
Robert E. Driscoll
Chief Operating Officer of Mirant Americas Generation, LLC and Mirant Mid-Atlantic, LLC as of January 9, 2006. Mr. Driscoll is Senior Vice President and Head of Asset Management, U.S. Region of Mirant Corporation. From 2001 through 2005, he was employed as Chief Executive Officer, Australia and Senior Vice President, Asia of Edison Mission Energy and from 1995 through 2001, he was employed as Senior Vice President, Asia of Edison Mission Energy.
S. Linn Williams
Executive Vice President and General Counsel of Mirant Americas Generation, LLC and Mirant Mid-Atlantic, LLC since 2006. Executive Vice President, General Counsel and Chief Compliance Officer of Mirant since 2005. Served as an International Chamber of Commerce arbitrator (2004-2005). Chief Executive Officer, European Division (1998-2000), and Senior Vice President and General Counsel (1994-1998) of Edison Mission Energy.
Vance N. Booker
Senior Vice President, Administration of Mirant Americas Generation, LLC and Mirant Mid-Atlantic, LLC since 2002. Senior Vice President, Administration of Mirant since 1999. Vice President, Administration of Mirant (1998-1999).
Paul R. Gillespie
Senior Vice President of Mirant Americas Generation, LLC, and Mirant Mid-Atlantic, LLC and Mirant since January 2006. Served as Counsel and Tax Counsel at Haynes and Boone, LLP (2002-2005). Vice President of Tax at Primus Telecommunications (2004-2005), Vice President of Tax and Associate General Counsel at Optiglobe Communications, Inc (2000-2001) and Vice President of Tax at Edison Mission Energy (1996-2000).
The executive officers of Mirant Americas Generation, LLC were elected to serve until their successors are elected and have qualified or until their removal, resignation, death or disqualification.
Family Relationships
None
Certain Legal Proceedings
On July 14, 2003, Mirant and most of its domestic subsidiaries filed for reorganization under Chapter 11 of the United States Bankruptcy Code. Certain of the Company’s officers are also officers or directors of other subsidiaries that filed for reorganization under Chapter 11. As such, each of the Company’s executive officers has been associated with a corporation that filed a petition under the federal bankruptcy laws within the last five years.
Audit Committee and Audit Committee Financial Expert
We do not have a separately designated standing Audit Committee. Because Mirant Americas Generation 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
The Code of Ethics that applies to Mirant’s senior financial officers also applies to the senior financial officers of Mirant Americas Generation. A copy of the code is posted on Mirant’s website at www.mirant.com and also will be provided, without charge, upon request made in writing to the 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, Inc.
Item 11.
Item 11. Executive Compensation
Our executives and managers are not compensated separately for their service as executive officers and managers of Mirant Americas Generation.
We are a limited liability company that is managed by a Board of Managers. All members of our Board of Managers are officers of Mirant or its subsidiaries, and they do not receive any additional compensation for their services as managers. Mirant Services, a direct subsidiary of Mirant, directly pays the salaries of our officers listed in Item 10. A portion of those salaries are effectively reimbursed to Mirant by us through an administrative services agreement with Mirant Services. Consequently, we have no compensation committee and no direct employment agreements.
None of our officers have any contracts or agreements in their capacities as officers of Mirant Americas Generation.
All members of our management are eligible to participate in certain employee benefit plans and arrangements sponsored by Mirant for its similarly situated employees. These may include the pension plan, savings plan, long-term incentive compensation plan, annual incentive compensation plan, health and welfare plans and other plans that may be established in the future.
All of our equity is held by our direct parent, Mirant Americas, Inc. 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, Inc.; therefore, none of our managers or officers holds any equity interests in Mirant Americas Generation.
Item 13.
Item 13. Certain Relationships and Related Transactions
Our relationships with affiliates and related transactions are described in Note 6 to our combined and consolidated financial statements.
Item 14.
Item 14. Principal Accountant Fees and Services
Not Applicable.
PART IV
Item 15.
Item 15. Exhibits and Financial Statements
a) 1. Financial Statements
Our consolidated financial statements, including the notes thereto and independent auditors’ report thereon, are set forth on pages 79 through 131 of the Annual Report on Form 10-K, and are incorporated herein by reference.
2. Financial Statement schedules
None
3. Exhibit Index
4.7*
Fourth Supplemental Indenture (designated in Mirant Americas Generation, Inc. Registration Statement on Form S-4/A Amendment No. 1, Registration No. 333-85124 as Exhibit 4.5)
4.8*
Fifth Supplemental Indenture (designated in Mirant Americas Generation, Inc. Registration Statement on Form S-4/A Amendment No. 1, Registration No. 333-85124 as Exhibit 4.6)
4.9*
Form of Senior Note Indenture between Mirant North America, LLC, Mirant North America Escrow, LLC, MNA Finance Corp. and Law Debenture Trust Company of New York, as Trustee (Designated in Mirant Corporation 10-K for the year ended December 31, 2005 as Exhibit 4.2)
10.1*
Mirant Americas Generation, LLC-Facility B Credit Agreement (Designated on Form 8-K filed February 12, 2003 as Exhibit 10.70)
10.2*
Mirant Americas Generation, LLC-Facility C Credit Agreement (Designated on Form 8-K filed February 12, 2003 as Exhibit 10.71)
10.3*
California Settlement Agreement dated January 13, 2005 (Designated on Mirant Corporation Form 10-K for the year ended December 31, 2004 as Exhibit 10.39)
10.4*
Mirant North America, LLC-Credit Agreement with Deutsche Bank Securities Inc., Goldman Sachs Credit Partners L.P., and JPMorgan Chase Bank, N.A. (designated in Mirant Corporation Form 10-K for the year ended December 31, 2005 as Exhibit 10.33)
10.5
Administrative Services Agreement dated as of January 3, 2006 between Mirant Americas Generation, Inc. and Mirant Services, LLC
10.6
Power Sale, Fuel Supply and Services Agreement dated as of January 3, 2006 among Mirant Americas Energy Marketing, LP, Mirant Bowline, LLC, Mirant Lovett, LLC, and Mirant NY-Gen, LLC
10.7
Power Sale, Fuel Supply and Services Agreement dated as of January 3, 2006 among Mirant Americas Energy Marketing, LP, Mirant Canal, LLC, and Mirant Kendall, LLC
10.8
Power Sale, Fuel Supply and Services Agreement dated as of January 3, 2006 between Mirant Americas Energy Marketing, LP and Mirant Chalk Point, LLC
10.9
Power Sale, Fuel Supply and Services Agreement dated as of January 3, 2006 between Mirant Americas Energy Marketing, LP and Mirant Mid-Atlantic, LLC
10.10
Power Sale, Fuel Supply and Services Agreement dated January 3, 2006 between Mirant Americas Energy Marketing, LP and Mirant Potomac River, LLC
10.11
Power Sale, Fuel Supply and Services Agreement dated January 3, 2006 between Mirant Americas Energy Marketing, LP and Mirant Texas, LP
10.12
Power Sale, Fuel Supply and Services Agreement dated January 3, 2006 among Mirant Americas Energy Marketing, LP, Mirant Delta, LLC, and Mirant Potrero, LLC
10.13
Power Sale, Fuel Supply and Services Agreement dated January 3, 2006 among Mirant Americas Energy Marketing, LP and Mirant Zeeland, LLC
10.14*
2005 Omnibus Incentive Compensation Plan (Designated on Mirant Corporation Form 8-K filed January 3, 2006 as Exhibit 10.1)
12.1*
Statement regarding ratio of earnings to fixed charges (designated in Mirant Americas Generation, Inc. Registration Statement on Form S-4/A Amendment No. 1, Registration No.333-85124 as Exhibit 12.1)
16.1*
Arthur Andersen LLP letter to the Securities and Exchange Commission dated May 15, 2002 (designated as Exhibit 16 on Form 8-K filed May 16, 2002)
21.1
Subsidiaries of Mirant Americas Generation, LLC
31.1
Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(a)).
31.2
Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(a)).
32.1
Certification of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(b)).
32.2
Certification of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Rule 13a-14(b)).
* 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 31st day of March, 2006.
MIRANT AMERICAS GENERATION, LLC
By:
/S/ ROBERT M. EDGELL
Robert M. Edgell
President and Chief Executive Officer and Manager
(Principal Executive Officer)
MIRANT AMERICAS GENERATION, LLC
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on March 31, 2006 by the following persons on behalf of the registrant and in the capacities indicated.
Signatures
Title
/s/ ROBERT M. EDGELL
President and Chief Executive Officer and Manager of
Robert M. Edgell
Mirant Americas Generation, LLC
(Principal Executive Officer)
/S/ J. WILLIAM HOLDEN III
Senior Vice President, Chief Financial Officer and
J. William Holden III
Treasurer of Mirant Americas Generation, LLC
(Principal Financial Officer)
/S/ THOMAS E. LEGRO
Senior Vice President, Controller and Principal Accounting
Thomas E. Legro
Officer of Mirant Americas Generation, LLC
(Principal Accounting Officer)
/S/ EDWARD R. MULLER
Manager of
Edward R. Muller
Mirant Americas Generation, LLC
/S/ JAMES V. IACO
Manager of
James V. Iaco
Mirant Americas Generation, 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.