PART I

Cautionary Statement Regarding Forward-Looking Statements

          We have made, and may continue to make, various forward-looking statements with respect to our financial position, business strategy, projected costs, projected savings, and plans and objectives of management. Such forward-looking statements are identified by the use of forward-looking words or phrases such as "anticipates," "intends," "expects," "plans," "believes," "estimates," or words or phrases of similar import. These forward-looking statements are subject to numerous assumptions, risks, and uncertainties, and the statements looking forward beyond 2001 are subject to greater uncertainty because of the increased likelihood of changes in underlying factors and assumptions. Actual results could differ materially from those anticipated by the forward-looking statements.

           Factors that could cause actual results to differ materially include, but are not limited to, those described below:

          In addition to factors previously disclosed by us and factors identified elsewhere herein, certain other factors could cause actual results to differ materially from such forward-looking statements. All subsequent written and oral forward-looking statements attributable to us, or persons acting on our behalf, are expressly qualified in their entirety by reference to such factors.

          Our forward-looking statements represent our judgment only on the dates such statements are made. By making any forward-looking statements, we assume no duty to update them to reflect new, changed, or unanticipated events or circumstances.

Item 1.  Business.

Overview

          We are a fast-growing electric power generating company committed to delivering a broad range of wholesale energy and related products and services to independent system operators, utilities, municipalities, cooperatives and retail aggregators. We are growing our business by strategically acquiring, developing and modernizing non-nuclear electric generating facilities located in critical locations in regions across the United States and Canada that are deregulating the electric power industry. We approach our business with financial discipline, applying a rigorous and multi-faceted approach to valuing acquisitions and development opportunities, including the strict application of rate of return targets on invested capital. We currently own 80 plants with an aggregate capacity of 5,396 megawatts. We also have three projects under construction with a total capacity of 1,208 megawatts, with announced plans to develop additional projects with a total capacity of 4,385 megawatts. If we complete all of our announced projects, we will have an aggregate capacity of almost 11,000 megawatts in operation.

          Our facilities in operation are diversified by fuel type and geographically. The tables below set forth the assets owned by our regional operating companies:

                          Orion Power New York, L.P. Facilities Summary

                                            Capacity       Primary
Asset                                        (MW)         Fuel Type               Location Served
- -----                                        -----        ---------               ---------------
Hydroelectric assets....................       650          Water            Central and Northern New
                                                                                    York State

Assets Located in New York City:
    Astoria Generating Station..........     1,265        Natural Gas/Oil    New York City - Queens
    Gowanus Generating Station..........       494           Oil             New York City - Brooklyn
    Narrows Generating Station..........       271        Natural Gas        New York City - Brooklyn

Carr Street Generating Station..........       102        Natural Gas        East Syracuse, NY
                                               ---

             Total......................     2,782
                                             =====

                                   Orion Power MidWest, L.P. Facilities Summary

                                            Capacity     Primary
Asset                                        (MW)       Fuel Type         Location Served
- -----                                        -----      ---------         ---------------
Avon Lake Generating Station............      739          Coal           Cleveland, OH
Brunot Island Generating Station........      234           Oil           Pittsburgh, PA
Cheswick Generating Station.............      570          Coal           Pittsburgh, PA
Elrama Generating Station...............      487          Coal           Pittsburgh, PA
New Castle Generating Station...........      338          Coal           West Pittsburg, PA
Niles Generating Station................      246          Coal           Youngstown, OH
                                              ---

         Total..........................        2,614
                                                =====

          In order to provide a broad range of energy products and services and to better manage electric and fuel commodity risk, we seek to diversify the fuel types of our facilities as set forth in the table below:

                                         Fuel Type Summary
                                         -----------------
                                                       Capacity
   Primary Fuel                                       (Megawatts)     Percentage
   ------------                                       -----------     ----------
   Coal............................................     2,290            42%
   Natural Gas / Oil (Dual fuel capability)........     1,462            27%
   Natural Gas.....................................       201             4%
   Fuel Oil........................................       793            15%
   Water...........................................       650            12%
                                                          ---            ---

            Total..................................     5,396           100%

          In addition, we manage electric and fuel commodity price risk by attempting to sell a majority of our output forward through long term and short term contracts and purchase in advance the associated fuel to match the term of those sales. We target to sell forward approximately 60-75% of our forecasted electric energy output in advance.

          On November 17, 2000, we completed an initial public offering of 27,500,000 shares of common stock at an offering price of $20.00 per share. We sold 24,279,032 shares and the selling stockholders, Constellation Enterprises, Inc. and its affiliates, sold an additional 3,220,968 shares. The net proceeds to us from the offering, after deducting underwriting discounts and commissions and other expenses, were $443.5 million, $209 million of which was used to acquire Columbia Electric Corporation. The remaining $243.5 million is being used for development projects and for general corporate and working capital purposes and may be used for additional acquisitions. Of the $243.5 million, $100.0 million was used to fund construction of the Ceredo Generating Station, $23.5 million was used for general corporate operating expenses, and $120.0 million remained available as cash at December 31, 2000.

Industry Overview

           Deregulation and Opportunity

          The United States electric power industry, including companies generating, transmitting, distributing and retailing power, is undergoing significant change driven in large part by the shift towards deregulation. This industry historically has been characterized by vertically integrated electric utility monopolies with the ability to sell electricity to a captive customer base. Deregulation, however, has created the opportunity for consumer choice and a substantial increase in competition. This competition has been implemented to varying degrees on the wholesale level in the sale of electricity by generators, marketers and others to utilities and other electric distributors, as well as on the retail level in the sale of electricity to consumers.

          The passage of the Energy Policy Act in 1992 significantly expanded the opportunities available to exempt wholesale power generators like us. Under this law, the Federal Energy Regulatory Commission, or FERC, has required owners and operators of electric transmission facilities to give wholesale generators and other wholesale market participants access to transmission lines on a non-discriminatory basis. This right enables us, as well as other wholesale generators, to sell the energy that we produce into competitive markets for wholesale energy. The Energy Policy Act also created a new class of generators-- exempt wholesale power generators-- that are not subject to portions of the regulatory structure otherwise generally applicable to electric utilities and their holding companies. FERC adopted, and the U.S. Court of Appeals upheld, Order Nos. 888 and 889, providing for nondiscriminatory open-access electric transmission services by public utilities, separate from wholesale sales of electricity. This development has opened wholesale power sales to additional competition. Certain aspects of Order No. 888 are being reviewed by the Supreme Court of the United States and any reversal of that order could make it more difficult or expensive to gain access to certain markets. In December 1999, FERC issued Order No. 2000 encouraging transmission owners to participate in Regional Transmission Organizations, or RTOs. FERC's goal in encouraging participation in these organizations is to enhance wholesale competition by addressing inefficiencies existing in the current administration of the transmission grid. The proposed RTOs throughout the country are at various stages of development. As of early 2001, new regulatory initiatives to increase competition in the domestic power generation industry had been adopted or were being considered at the federal level and by many states.

           Certain states have adopted deregulation initiatives for the electric power industry. As of March 2001, 25 states, including where we own or are constructing generation facilities, such as Maryland, New York, Ohio, Pennsylvania and West Virginia, have enacted some form of legislation or issued comprehensive regulatory orders to restructure their electric power industries in order to promote competition in the wholesale and/or retail sale of electric power. Similar restructuring is being considered or studied in virtually every other state.

           While we do not own any generating assets in California, recent developments in the California electric industry may have a significant impact on the pace and direction of deregulation in other states. California implemented deregulation in a manner that, combined with numerous other factors, resulted in high price spikes and the failure of the California Power Exchange spot market. As a result, two of the major investor-owned utilities are at risk of insolvency. In recent months, the Department of Energy has required generators to supply power to California utilities, although it has ended that requirement. In light of these developments, the federal government and many states are reevaluating existing deregulation initiatives and may be slowing consideration of pending initiatives.

           Consumer demand for reliable power throughout the United States has been increasing. The growing population in urban and developing areas of the country requires additional power, as evidenced by electricity shortages, brownouts and blackouts in portions of the country and very high peak prices for electricity in the wholesale electric market. Additionally, many old power plants will need to be replaced by environmentally cleaner, cheaper and more efficient sources of power.

          As a result of anticipated utility divestitures of generating facilities associated with deregulation initiatives and the need to replace inefficient generating facilities, we believe there exists a significant opportunity for investment in the power generation industry. We are one of many companies actively pursuing the opportunities created by this evolving industry. In our case, we are doing so by seeking to acquire and develop a portfolio of generating facilities in order to operate as a competitive electric generating and wholesale supply company in a deregulated marketplace.

           Market Fundamentals

           Generally, electric generating facilities can be categorized into three categories (baseload, intermediate and peaking) based on their operating characteristics in the production of energy for the region they serve. The various tiers of baseload, intermediate and peaking facilities serving a particular area or region are often referred to as the "generation stack" for that area or region. Our current facilities are weighted towards baseload and intermediate units, though our assets include several peaking units near the top of the generation dispatch stack in the New York City, Ohio and Pennsylvania markets. The operating assets located in Ohio and Pennsylvania are predominately baseload facilities.

          In many areas, especially in large cities, the demand for electricity is greater than the capacity of electric transmission lines to supply electricity from outside regions. This creates a need for a power plant to be located within the area, known as a load pocket. Load pockets that cover large regions may themselves contain smaller load pockets. The existence of a load pocket may require selected generating units inside the load pocket to produce electricity, even though less costly sources of electricity may exist outside of the load pocket. The construction of additional electric transmission facilities can reduce or eliminate load pockets by increasing transmission capacity. Additionally, the construction of generating units within a load pocket may increase competition and may reduce market prices. Our assets currently serve load pockets in Cleveland, New York City and Pittsburgh.

          We look to acquire or develop generating facilities that are located in load pockets because we believe these facilities will have a more stable revenue stream, which reduces the seasonality of our business. The elimination of a load pocket in which we own a generating facility through either the construction of additional transmission or generating capacity could negatively impact our business. In addition, restrictive rules governing market prices within a load pocket could negatively impact our business.

Business Strategy

          Our strategy is to acquire and develop a portfolio of premier non-nuclear generating facilities in deregulating markets in the United States and Canada that provide electricity and related products for the regions in which they are located, while seeking to maximize value for our stockholders. We believe that by operating a carefully assembled portfolio of generating assets in a cost-efficient manner and marketing our output to our customers with a limited amount of commodity price risk, we will be able to compete effectively in the newly deregulated market for wholesale electric power. We approach our business with financial discipline, applying a rigorous and multi-faceted approach to valuing investment opportunities. We also place a high priority on integrating acquired and newly developed assets and related employees into our operations.

           Based on the opportunities for investment in our industry, we believe we will be able to grow our business rapidly and become one of the ten largest power generators in the U.S. while maintaining strict financial control. We attempt to have a significant market share in each region in which we choose to compete, and believe we will become a prominent power generator in each of those regions. Our strategy to build and operate this business includes the following key elements:

           Attract and Retain Talented, Entrepreneurial Employees. We believe that the quality of our employees will be the most critical factor in our success. We hire high quality employees from a variety of different backgrounds, including in the wholesale and unregulated power industry, utility operations, financial services and commodity trading, and offer them superior tools and training, which we couple with substantial authority and responsibility. We are committed to a flat, non-hierarchical organization that offers our employees internal growth opportunities. To achieve our growth targets, our employees must be motivated to work together and focused on expanding our business. Meaningful amounts of their expected compensation are tied to increasing stockholder value, including incentive cash compensation and stock option plans. A substantial number of our employees participate in our stock option program, and our executive officers and employees own, either directly or indirectly through stock options, over 5% of the company on a fully diluted basis.

           Assemble and Maintain a Competitive Portfolio of U.S. and Canadian Generating Facilities. We employ a rigorous, multifaceted approach to our investment opportunities. We believe that access to the complementary skill sets of our key management members provides us with a significant competitive advantage in successfully completing acquisition opportunities. As we grow our asset base to meet the market opportunity, we will continue to focus on the following:

           Optimize Performance of Facilities. We are committed to optimizing the performance of our facilities to meet the demands of a competitive market. We will do so by improving the operating efficiency of our facilities, which historically have been operated in a regulated environment that often did not encourage cost efficiency. We increase our employees' authority and responsibility by eliminating layers of management. We believe that this allows us to increase productivity and operating efficiency to maximize profitability. We also have opportunities to improve fuel procurement practices to lower overall fuel costs and increase fuel quality.

           Grow Through Redevelopment of Existing Facilities and Development of New Facilities. We are focused on growing our business through the development and construction of power generating facilities. We believe that there is significant need for additional generating capacity throughout North America to replace aging and inefficient facilities, as well as to satisfy increasing demand. These new facilities may be created through the redevelopment of existing assets or through development at new sites.

          We are capitalizing on the existing infrastructure at our current plants by expanding and modernizing certain generating units. The existing assets at these sites allow us to build additional generating capacity at critical sites and for anticipated capital costs that other developers are unlikely to be able to reproduce. New power generation facilities are currently under construction at two sites and under development at two additional sites. We expect to commence the construction, siting and permitting of new power plants to meet the need to provide efficient, low-cost energy and related products to areas of North America where demand is projected to exceed the current power supply.

          In pursuing this strategy, we intend to use our management and technical knowledge, and expertise in finance, fuel, operations and power marketing, which we believe provide us with a competitive advantage. We believe that we can maximize the return on our investments in these new and existing facilities by utilizing and building upon our current infrastructure and organization. Given the early stages of development of some of these facilities, we may in the future elect not to pursue these activities or we may not otherwise be able to do so.

           Build Strong Relationships with Local Customers. We seek to sell a majority of our power under contracts of varying lengths. Therefore, we strive to build strong relationships with the electric utilities, municipalities, cooperatives and retail aggregators in the regions in which we generate energy, including the companies that sell us our facilities. We believe that these entities will continue to be the primary providers of electricity to retail consumers in a deregulated environment, and that they will need products in addition to energy, such as capacity, operating reserves, voltage support, and automatic generation control, in order to reliably serve their customers' needs. By providing these services, we believe that we can earn a better return than would be available by primarily selling commodity energy into the spot markets as they develop. In order to facilitate the development of these relationships, we will operate our facilities on a decentralized basis, using local management with expertise in the local power markets.

          As an initial step in building these relationships, we have entered into transition contracts to sell energy and other products to Niagara Mohawk Power Corporation and Duquesne Light Company, from whom we purchased assets. As substantially all of the obligations under these contracts are expected to expire in the third quarter of 2001 for Niagara Mohawk Power Corporation and early 2002 for Duquesne Light Company, we have sought to continue these relationships beyond the expiration date of these contracts and enter into new relationships with other entities that provide retail electric service. In particular, we have extended the period during which we will supply energy to Duquesne Light Company until December 31, 2004. See "--Orion Power MidWest, L.P.--Provider of Last Resort Contract." Additionally, we are examining opportunities to extend the energy sales contract with Niagara Mohawk Power Corporation through September 2004.

          The majority of the capacity and energy of the Liberty Project, which is under construction in Pennsylvania, is also committed under a 14-year tolling agreement. See "--Orion Power Development Company, Inc.--Construction and Development."

           Actively manage energy and fuel merchant market risk. We are focused on maximizing the net margin of energy and related products while minimizing risk. Our electric markets and fuels group actively markets output from and manages fuel procurement for the facilities on a monthly, daily and real-time basis. We operate a 24-hour, seven-day-per-week service desk to dispatch facilities, manage output and fuels and respond to operational issues on a real-time basis.

          We do not engage in any speculative trading of electricity or fuel. A key component to our risk management strategy is to sell a majority of our output forward through long-term and short-term contracts and purchase in advance the associated fuel to match the term of those sales. We believe that this approach allows us to successfully manage electric and fuel commodity risk while maximizing our profit margins.

2000 Acquisitions of Facilities

          On April 28, 2000, we purchased seven generating plants located in Ohio and Pennsylvania with a capacity of 2,614 megawatts from Duquesne Light Company. The net purchase price for the assets was approximately $1.8 billion in cash. In connection with this acquisition, we assumed approximately $24.4 million of liabilities relating to employee benefits and environmental remediation and assumed Duquesne Light Company's responsibility as provider of last resort for a specified period.

          On December 11, 2000, we purchased from Columbia Energy Group (now a subsidiary of NiSource Inc.) all the outstanding stock of Columbia Electric Corporation, a power generation company with natural-gas-fired projects in various stages of construction or development. Columbia Electric had divested its partial ownership interest in facilities already in operation prior to our acquisition. The net purchase price for this acquisition was $209 million in cash. In connection with this acquisition, we assumed a $334 million credit facility, of which approximately $148 million was outstanding as of December 31, 2000. We also assumed from Columbia Energy Group construction contract and tolling agreement guarantees of approximately $6 million and equity investment obligations of approximately $41 million. As part of the Columbia Electric acquisition, we also assumed a tolling agreement for the Liberty Electric Generating Station.

Operations

          We operate our business on a decentralized basis. The majority of day-to-day operating decisions are made by employees either at the facilities or in our regional offices. This allows employees in our headquarters to focus on those activities that benefit from economies of scale, that require inter-regional coordination and that continue to grow our business.

          We own 5,396 megawatts of generating, capacity, with historic generation of energy totaling over 20 million megawatt hours per year. Capacity refers to the net tested, operational capability of a generating facility to produce energy in the summer. The capacity of a particular facility will vary seasonally, typically as a result of differences in ambient air temperature. As a result, capacity is typically measured twice--once for the summer and once for the winter. Our portfolio utilizes four primary fuels: coal, natural gas, oil, and water. Many of our facilities that burn natural gas have the ability to switch between burning either natural gas or oil as the primary fuel type. No one fuel type currently accounts for as much as 50% of our capacity.

Corporate Operations

          Our corporate headquarters are located in Baltimore, Maryland. The corporate office is focused on selected activities, including corporate administration, accounting, financing, power sales, fuel procurement, asset management, risk management and business development. As of December 31, 2000, there were 54 employees located in the corporate office, including all of the executive officers. We conduct our day-to-day operations by subsidiaries which are wholly-owned either by us or by another one of our subsidiaries.

          We centralize some aspects of asset management, risk management, power sales, and fuel procurement. The combined power sales and fuel procurement group, which, as of December 31, 2000, totaled 18 employees, focuses on optimizing the net margin earned on sales of energy, capacity, and ancillary services after taking out the cost of fuel and limiting the amount of risk in our activities. This group concentrates solely on power sales and fuel procurement for our assets and is not authorized by senior management to engage in speculative trading or activities for unaffiliated third parties.

          Our business development team, consisting of six people, focuses on maximizing value and growing our business, both through new acquisitions and new project development. Most of our corporate employees, including all of our executive officers, are directly involved in our business development efforts.

          We instituted a risk management committee to help monitor our business activities. The committee meets at least once per month and has a broad mandate to review all areas of our business, set policies for managing risk positions, and direct management on appropriate actions to reduce our significant risks.

Orion Power New York, L.P.

           Facilities. Our regional operating company, Orion Power New York, L.P., which is headquartered outside Syracuse, New York manages our assets located in New York State. Orion Power New York manages a total of 74 power generation facilities of which 72 are currently operational. Total aggregate capacity of these facilities is approximately 2,607 megawatts. The facilities consist of 70 hydroelectric facilities, of which 68 are active, three facilities located in New York City and the Carr Street Generating Station in East Syracuse. In April 2000, we acquired three subsidiaries of Constellation Operating Services that, pursuant to strategic alliance agreements, operated the assets located in New York. As of December 31, 2000, Orion Power New York employed 372 people as direct employees.

          We have not owned these facilities for a substantial period of time, and therefore, our historical financial and operating results do not provide a longer term perspective on the operation of the assets located in New York.

           Assets Located in New York City. We currently bid the energy produced by the assets located in New York City into the energy and ancillary services markets operated by the New York independent system operator (NY-ISO). Because our assets located in New York City serve a transmission-constrained area, bids for energy produced by these facilities are subject to market power mitigation measures as implemented by the NY-ISO, in addition to the New York City capacity regulations. The market power mitigation measures provide that if the energy bid price for our assets located in New York City exceeds the market price at a specified location reference point outside New York City by 5% or more, our bid price is replaced with an energy reference price that approximates our cost of production. All units that are dispatched will then receive the market clearing price. Due to the fact that our units are located in critical areas in New York City and are often dispatched for uneconomic reasons, we receive the greater of the market clearing price or the cost of production.

           Hydroelectric Assets. We have sold all of the output of the hydroelectric assets, including energy, capacity, and ancillary services, to Niagara Mohawk Power Corporation on a bilateral basis through September 30, 2001. Under this contract, we receive an annual fixed payment, totaling $71.8 million for the period October 1999 through September 2000 and $73.6 million for the period October 2000 through September 2001, and a variable payment of $20 per megawatt hour for all generation above approximately 2.2 million megawatt hours. The actual targets are set on a quarterly basis to reflect the seasonal fluctuations in energy production from our hydroelectric assets, and payments are made monthly. If we fail to meet the minimum generation threshold, we are obligated to pay penalties to Niagara Mohawk. The 2.2 million megawatt hour target is approximately 78% of the average generation for the units over the last ten years. Generation at hydroelectric facilities, however, varies based on precipitation. We are currently working to extend this contract.

           Carr Street. We have entered into a gas tolling agreement with Constellation Power Source covering the Carr Street Generating Station, which continues until 2003. Under this agreement, Constellation Power Source has the exclusive right to all energy, capacity and ancillary services produced by the plant. Constellation Power Source pays for, and is responsible for, all fuel used by the plant during the term of the gas tolling agreement. We are currently paid approximately $3.6 million per annum as a fixed fee and $3.15 per megawatt hour generated, both of which escalate by approximately 2.5% per annum. We have guaranteed certain aspects of the plant's operating performance and failure to meet these guarantees could result in penalties.

Orion Power MidWest, L.P.

           Facilities. Our regional operating company, Orion Power MidWest, L.P., which is headquartered near Pittsburgh, Pennsylvania, manages our assets located in Ohio, Pennsylvania and West Virginia. The assets consist of seven power generating facilities, six of which are active, located in western Pennsylvania and Ohio, and one generating facility, the Ceredo Electric Generating Station, currently under construction in West Virginia. We acquired the West Virginia facility from Columbia Energy Group in December 2000, and it is scheduled to begin commercial operations as a 500 megawatt peaking facility in June 2001. The remaining seven facilities were acquired from Duquesne Light Company in April 2000, three of which Duquesne had recently acquired in an asset swap with FirstEnergy Corp. The other four (including the retired facility) have historically been owned and operated by Duquesne Light Company. The six operating facilities have a total aggregate capacity of approximately 2,614 megawatts, with five of such facilities using coal as their primary fuel source and one such facility using oil. The majority of the coal units operate as baseload units because of their low production costs per megawatt hour. In addition, in connection with the Duquesne acquisition we entered into the provider of last resort contract with Duquesne Light Company. As of December 31, 2000, we employed 454 people in the direct operation of the eight facilities managed by Orion Power MidWest.

          We have not owned these facilities for a substantial period of time, and therefore, our historical financial and operating results do not provide a longer term perspective on the operation of these assets.

           Provider of Last Resort Contract. As part of our acquisition of seven facilities located in Ohio and western Pennsylvania in April 2000, we entered into the provider of last resort contract with Duquesne Light Company. Under the contract, we are obligated for a specific period to provide energy to Duquesne Light Company to meet its obligations to satisfy the demands of any customer in the Duquesne Light Company service area that does not elect to buy energy from a competitive supplier as allowed by the Pennsylvania state deregulatory initiatives or that elects to return to Duquesne Light Company as the designated provider of last resort. Under this contract, we must provide all of the energy necessary to meet the contractual requirements with no minimum and no maximum quantity and Duquesne Light Company must buy all of the energy needed to satisfy its provider of last resort obligation from us.

          The provider of last resort contract is a wholesale contract between us and Duquesne Light Company, and we have no responsibility for selling energy directly to the related retail customers, nor are we obligated to provide capacity or other ancillary services. Therefore, we have no involvement in billing retail customers or collecting amounts owed by retail customers.

          The Duquesne Light Company service area covers approximately 580,000 retail customers. According to information provided by Duquesne Light Company, the peak demand for the Duquesne Light Company control area was approximately 2,673 megawatts, and the total amount of electricity consumed was approximately 14,103,000 megawatt hours in 2000. As of December 31, 2000, approximately 79% of the customers in the Duquesne Light Company control area, as measured by energy consumption, received energy from Duquesne Light Company as the provider of last resort. The peak provider of last resort load was approximately 2,335 megawatts for 2000. The total amount of electricity consumed by provider of last resort customers was approximately 10,811,387 megawatt hours for 2000.

           Under the provider of last resort contract, the prices we receive are a specified portion of Duquesne Light Company's current retail rates, which have been approved by the Pennsylvania Public Utility Commission. Our average gross selling price was approximately $40 per megawatt hour for 2000. From this amount, Duquesne Light Company deducts the Pennsylvania gross receipts tax of 4.4%, $1 per megawatt hour for ancillary services that Duquesne Light Company procures from another party and transmission line losses. Based on recent historical patterns of usage for each of Duquesne Light Company's rate classes, we expect our average gross selling price in 2001 will be almost $41 per megawatt hour.

          The provider of last resort contract continues in effect for each rate class until the amount of Duquesne Light Company's stranded costs allocated to that rate class have been recovered through the surcharge being added to each customer's monthly bill. For two rate classes, all stranded costs have already been recovered, and therefore the provider of last resort obligation is satisfied for these rate classes. The remaining rate classes are projected to complete stranded cost recovery between 2001 and 2003, with most rate classes expected to have completed stranded cost recovery before the summer of 2002. Accordingly, we expect the majority of the original provider of last resort contract obligations to end during early 2002.

          We have reached agreement with Duquesne Light Company, which was approved by FERC, to extend the provider of last resort contract until December 31, 2004 and to amend the price and certain other terms. The new agreement will become effective for each Duquesne Light Company retail customer class as that class comes off the retail tariff that relates to the existing contract, which, based on historic patterns, should occur in early 2002. The extension differs from the existing tariff and contract in certain respects, including:

           Given the expected demand for energy from provider of last resort customers and the historic energy generation from our assets located in Ohio and Pennsylvania and our peaking power plant under construction in West Virginia, we generally expect to produce more energy than needed to meet our provider of last resort obligations. We will attempt to sell this excess energy into the market and will receive the prevailing market price at the time. The provider of last resort demand, however, will fluctuate on a continuous, real-time basis, and will likely peak during summer and winter, on weekdays, and during some hours of the day. This could cause the provider of last resort demand to be greater than the amount of energy we are able to generate at any given moment. As a result, we may need to purchase energy from the market to cover our contractual obligations. This is likely to occur at times of higher market prices, although the price we receive will be determined as described above and will not fluctuate with the market. This situation could also arise or worsen if we have operational problems at one or more of our generating facilities that reduce their ability to produce energy. Failure to provide sufficient energy could give rise to penalties under the contracts. A severe under-delivery of energy that forces Duquesne Light Company to deny some customers energy could give rise to penalties of $1,000 per megawatt hour under the initial provider of last resort contract or $100 per megawatt hour under the extension. This risk should diminish as the number of rate classes eligible for provider of last resort service is reduced. Constellation Power Source currently manages our position in the merchant energy market under an agreement that expires on March 31, 2001. Upon expiration of this contract, we will deal directly with all counterparties in the market.

Orion Power Development Company, Inc.

           Orion Power Development Company, Inc., which is based in Baltimore, Maryland, manages our assets under construction and development. Our development company's primary objective will be to grow our portfolio of generating assets in a timely manner by developing efficient generating facilities that can provide wholesale customers with reliable, low-cost electricity and related products and services. Our development team has extensive experience in business development, power plant siting, system design, equipment procurement, construction management, economic analysis and risk management. Our development team seeks to identify attractive market opportunities and transmission constrained areas and then pursues a structured approach tailored to the needs of the specific markets. Our development team works closely with all members of the Orion Power team to execute our overall growth strategy. As of December 31, 2000, Orion Power Development Company, Inc. had no direct employees. Consequently, some of the employees of Orion Power Holdings, Inc. managed the daily business of and the development projects owned by Orion Power Development Company, Inc.

          With the exception of the Ceredo Electric Generating Station in Ceredo, West Virginia, the facilities which we purchased from Columbia Energy Group in December 2000 will be owned and managed through Orion Power Development Company, Inc.

Construction and Development

          A primary facet of our strategy is to continue to grow by developing additional capacity at our facilities by repowering or adding units at existing facilities and by building new facilities throughout the U.S. and Canada.

          For example, in 2000, we restored a unit at the Astoria Generating Station in New York City that was shut down by the prior owner in 1993. We have been granted the right to operate this unit for up to three years in order to increase capacity in New York City and enhance electric reliability. The restored unit is capable of producing approximately 175 megawatts of energy.

          We currently have three projects that are under construction:

          We are currently pursuing a number of development opportunities:

           Given the early stage of all of the aforementioned projects, we may elect not to pursue these activities or we may otherwise not be able to do so.

          In September 2000, we entered into a letter of intent for the delivery over the next four years of 10 combustion turbine generators from Siemens Westinghouse Power Corporation as part of our development efforts. The total purchase price is approximately $345 million, substantially all of which is payable at various times in 2003 and 2004. We paid a $5 million deposit in the third quarter of 2000 and will pay an additional $5 million deposit in the first quarter of 2001. Furthermore, as part of our acquisition of Columbia Electric Corporation, we acquired the rights to the eight turbine generators to be delivered by GE Power Systems, which are being installed in the projects under construction. As of December 31, 2000, approximately $33.9 million remained to be paid for these eight turbines, of which $32 million was due at December 31, 2000, and recorded in accounts payable on the balance sheet.

          The following table outlines our projects currently in construction and under development:

                                                   In Construction
                                                                                          Currently
                              Planned                                                      Expected
                             Capacity                                                     Operation
Facility                       (MW)      Primary Fuel Type         Location Served           Date
- --------                       -----     -----------------         ---------------           ----
Ceredo                          500      Natural Gas               Wayne County, WV       June 2001
Brunot Island                    140     Natural Gas               Pittsburgh, PA              2002
Liberty                         568      Natural Gas               Philadelphia, PA            2002
                                ---
Total in Construction         1,208
                              -----

                                                  Under Development
                                                                                                    Currently
                               Planned                                                               Expected
                              Capacity                                                              Operation
Facility                        (MW)      Primary Fuel Type                 Location Served            Date
- --------                        -----     -----------------                 ---------------            ----
Astoria
  Phase 1                         385     Natural Gas                       New York, NY               2004
  Phase 2                         200     Natural Gas                       New York, NY               2005
Henderson
  Phase 1                         250     Natural Gas                       Henderson County, KY       2004
  Future Phases                   250     Natural Gas                       Henderson County, KY       TBD
Kelson Ridge
  Phase 1                         550     Natural Gas                       Charles County, MD         2004
  Future Phases                 1,100     Natural Gas                       Charles County, MD         2006
Avon Lake repowering
  Phase 1                         550     Evaluating Coal v. Natural Gas    Cleveland, OH              TBD
  Future Phases                   550     Evaluating Coal v. Natural Gas    Cleveland, OH              TBD
Niles                             550     Evaluating Coal v. Natural Gas    Youngstown, OH             TBD
                               -----
Total under Development         4,385
                               -----

Total Projects Announced        5,593
                               =====

          The actual commercial operation dates of these facilities will be dependent on various factors, including timely delivery of and performance of the turbines, transformers and other major equipment, timely construction of the gas and electric interconnection lines and any unusual conditions at the sites or otherwise which may impact construction, and we cannot assure you that these facilities will operate as scheduled.

Recent Market Developments

           New York Market Framework. The New York wholesale energy market has recently been reorganized, with the NY-ISO taking over responsibility for daily operation of the transmission system and the administration of bid-based markets for energy, capacity, and ancillary services. The day-ahead and real-time energy and ancillary services markets started on November 18, 1999. The capacity market began with an auction in early April 2000 for the summer 2000 six-month capacity period.

           Under the NY-ISO, generators like us are able to sell energy to any wholesale customer in the state. These sales may be done under bilateral contracts, in which pricing and other provisions are determined through private negotiation, or by bidding into the day-ahead and real-time energy and ancillary services markets. The NY-ISO has only recently been formed, and the markets it operates are new. The NY-ISO has experienced problems in administering New York's competitive wholesale energy markets since its inception. As a result, some parties involved in New York's wholesale market and certain members of the NY-ISO have asked that the NY-ISO and, in some instances, FERC review the structure of the wholesale market. Consequently, the NY-ISO is in the process of reviewing and revising market rules and the implementation of its software. This process has created some uncertainty for future market conditions in New York. There can be no assurance that changes to New York's competitive wholesale energy markets will not adversely affect our operations. The NY-ISO has the ability to revise prices, which could lead to delayed or disputed collection of amounts due to us for sales of energy and ancillary services. The NY-ISO also has the ability, in some cases subject to FERC approval, to impose cost-based pricing and/or price caps.

          The NY-ISO applied to FERC to impose a cost-based price with respect to the ten minute spinning reserve and ten minute non-spinning reserve markets. FERC granted the NY-ISO's request with respect to the ten-minute non-spinning reserve market. In July 2000, FERC imposed a bid cap of $1,000 per megawatt hour to be consistent with the independent system operators in the Mid-Atlantic and New England. This cap is in place through April 2001, and parties have requested extensions of the cap. Other independent system operators have suggested various forms of cost-based bidding for energy and related services.

           The NY-ISO recently announced it will implement a measure known as a "circuit breaker" under which day-ahead energy bids will be automatically reviewed and, if necessary, mitigated if economic or physical withholding is determined by the summer of 2001. A number of additional changes have recently been proposed for the New York wholesale market, which could be in place as early as the summer of 2001. These include the following:

          The NY-ISO has established a capacity market, beginning with the summer 2000 capacity season, to ensure that there is enough generation capacity to meet retail energy demand and ancillary services requirements. All power retailers are required to demonstrate commitments for capacity sufficient to meet their peak forecasted load plus a reserve requirement, currently set at 18%. As an extra reliability measure, power retailers located in New York City are required to procure the majority of this capacity (currently 80% of their peak forecasted load) from generating units located in New York City. Since New York City is currently short of this capacity requirement and the existing capacity is owned by only a few entities, a price cap of $105 per kilowatt year has been instituted for in-city generators. In 2000, in two separate auctions, we sold an average of 1,983 megawatts at the price cap of $105 per kilowatt year. This price cap and other rules relating to the capacity market may be reviewed by regulatory agencies from time to time and may change.

           Midwest Market Framework. The assets managed by Orion Power MidWest, L.P. are located in the ECAR region. The ECAR region covers part or all of the following states: Indiana, Kentucky, Maryland, Michigan, Ohio, Pennsylvania, Virginia and West Virginia. There is no ISO or similar entity in place for the entire ECAR region, although the utilities in the region are proposing at least three plans for an independent system operator and/or a regional transmission operator. The ECAR market is characterized by substantial costs for transmitting power from one location to another, because each independent utility charges a tariff to use its transmission facilities. Therefore, moving power across multiple control areas becomes expensive and may become difficult or impossible at times of maximum demand.

          The current market in the ECAR region is relatively illiquid and is dominated by private bilateral contracts between parties. Notwithstanding the general lack of liquidity, markets do exist for several areas within the ECAR region. The ECAR region also lacks a specific capacity market and well-developed markets for ancillary services.

           Given the competing proposals currently under consideration and the many divergent interests which exist in the ECAR region, we expect that any adoption of ISOs or similar entities will be gradual. Some entities, including Duquesne Light Company, have considered joining the PJM-West market, a newly created wholesale market that would cover the western portion of the Mid-Atlantic region as early as December 2001. If Duquesne Light Company, our primary customer in the ECAR Region, joins the PJM-West market, we may well enter the newly created wholesale market as well. We are unable to determine what impact, if any, joining the PJM-West market would have on our business or financial prospects.

Regulation

          We are subject to complex and stringent energy, environmental, and other governmental laws and regulations at the federal, state, and local levels in connection with the development, ownership, and operation of our electric generation facilities. The federal and state energy laws and regulations create burdens and risks for our operations, as well as opportunities for further acquisitions of facilities at attractive prices.

Federal Energy Regulation

          The Federal Energy Regulatory Commission, or FERC, is an independent agency within the Department of Energy that regulates the transmission and wholesale sale of electricity in interstate commerce under the authority of the Federal Power Act. FERC is also responsible for licensing and inspecting private, municipal and state-owned hydroelectric projects. FERC determines whether a public utility qualifies for exempt wholesale generator status under the Public Utility Holding Company Act, which was amended by the Energy Policy Act of 1992.

           Federal Power Act. The Federal Power Act gives FERC exclusive rate-making jurisdiction over wholesale sales of electricity and transmission of electricity in interstate commerce. FERC regulates the owners of facilities used for the wholesale sale of electricity and its transmission in interstate commerce as "public utilities" under the Federal Power Act. The Federal Power Act also gives FERC jurisdiction to review certain transactions and numerous other activities of public utilities.

           Under the Federal Power Act, an entity that sells electricity at wholesale is a public utility, subject to FERC's jurisdiction. Public utilities are required to obtain FERC's acceptance of their rate schedules for wholesale sales of electricity. Because we are selling electricity in the wholesale market, we are deemed to be a public utility for purposes of the Federal Power Act. In most cases, FERC does not actively regulate the rates for facilities operated by wholesale generating companies like ours. Accordingly, FERC has granted market-based rate authority for the Carr Street facility, our hydroelectric assets, our assets located in Ohio and Pennsylvania and, subject to various market power mitigation measures, our assets located in New York City. Market-based rate authority enables us to price based upon market conditions rather than upon our costs. Certain parties recently requested significant modifications to the New York City market power mitigation measures which, if implemented, would impair our ability to collect market prices for our electricity.

           Usually, FERC's orders which grant us market-based rate authority, reserve the right to revoke or revise our market-based rate authority on a prospective basis if FERC subsequently determines that we possess excessive market power. If we lost our market-based rate authority or if significant new mitigation rules were adopted, we may be required to obtain FERC's acceptance of a cost-of-service rate schedule and may become subject to the accounting, record-keeping and reporting requirements that are imposed only on utilities with cost-based rate schedules. When FERC considers our request for market-based rate authority in connection with a new acquisition or development project, it may include generation owned or controlled by our stockholders in determining whether we possess market power.

          FERC also regulates the rates, terms, and conditions for electricity transmission in interstate commerce. Tariffs established under FERC regulation give us access to transmission lines, which enable us to sell the energy we produce into competitive markets for wholesale energy.

          In April 1996, FERC issued an order requiring all public utilities to file "open access" transmission tariffs that give wholesale generators, as well as other wholesale sellers and buyers of electricity, access to transmission facilities on a non-discriminatory basis. This order is being reviewed by the Supreme Court of the United States. All utilities filed open access tariffs. Some utilities are seeking permission from FERC to recover costs associated with stranded investments through add-ons to their transmission rates. To the extent that FERC permits these charges, the cost of transmission may be too high on some systems to be of practical use to wholesale sellers like us.

          FERC is also encouraging the voluntary restructuring of transmission operations through the use of independent system operators and regional transmission groups. The result of establishing these entities typically is to eliminate or reduce transmission charges imposed by successive transmission systems. The full effect of these changes on us is uncertain at this time, in part, because it has not been determined which of these entities will control the transmission systems connected to certain of our generating facilities.

          The Federal Power Act also gives FERC exclusive authority to license non-federal hydroelectric projects on navigable waterways and federal lands. FERC hydroelectric licenses are issued for 30 to 50 years. The hydroelectric assets are licensed by FERC from 2004 through 2036. Individual hydroelectric facilities, representing approximately 90 megawatts of capacity, have licenses that expire over the next ten years. Facilities representing approximately 160 megawatts of capacity have new or initial license applications pending before FERC. Upon expiration of a FERC license, the federal government can take over the project and compensate the licensee, or FERC can issue a new license to either the existing licensee or a new licensee. In addition, upon license expiration, FERC can decommission an operating project and even order that it be removed from the river at the owner's expense. In deciding whether to issue a license, FERC gives equal consideration to a full range of licensing purposes related to the potential value of a stream or river. It is not uncommon for the relicensing process to take between four and ten years to complete. Generally, the relicensing process begins at least five years before the license expiration date and FERC issues annual licenses to permit a hydroelectric facility to continue operations pending conclusion of the relicensing process. We expect that FERC will issue us new or initial hydroelectric licenses for all the facilities with pending applications. Presently, there are no applications for competing licenses and there is no indication that FERC will decommission or order any of the projects to be removed.

           Nonetheless, there remains the possibility that FERC will not issue new or initial licenses for our projects, which could have a material adverse effect on our operations and revenue. In addition, several interested parties have intervened or are likely to intervene in our licensing proceedings. These interested parties may be able to impose conditions and affirmative obligations on our hydropower operations, which could add significant costs to our operations or reduce revenues. In the past, FERC has issued licenses with conditions that have rendered the operation of the relevant projects uneconomic. Therefore, there is no guarantee that the hydroelectric licenses issued by FERC will permit us to operate the projects profitably. Finally, the relicensing process itself is costly, time consuming, and could affect adversely our hydroelectric revenues.

          The remainder of our hydroelectric assets have licenses that expire over an approximate 30 year period, are exempt from licensing because they are small facilities with five megawatts or less or are not within FERC's jurisdiction because they are not located on navigable waterways or federal land. Many of the existing licenses contain conditions that have one or more operational constraints, including restricting energy production, impacting the time of year or day in which generation occurs, raising operating costs, and requiring certain minimum river flow releases, which directly affect our ability to generate energy.

           Public Utility Holding Company Act. The Public Utility Holding Company Act, known as PUHCA, provides that any entity that owns, controls or has the power to vote 10% or more of the outstanding voting securities of an "electric utility company," or a holding company for an electric utility company, is subject to regulation under the Holding Company Act.

           Registered holding companies under the Holding Company Act are required to limit their utility operations to a single, integrated utility system and divest any other operations that are not functionally related to the operation of the utility system. In addition, a company that is a subsidiary of a holding company registered under the Holding Company Act is subject to financial and organizational regulation, including approval by the SEC of certain financings and transactions. Under the Energy Policy Act of 1992, however, FERC can determine that a company engaged exclusively in the business of owning or operating an eligible facility used for the generation of electric energy for sale at wholesale is an "exempt wholesale generator." Accordingly, it is exempt from the Holding Company Act requirements. In the case of facilities previously operated by regulated utilities, FERC can make an exempt wholesale generator determination only after the state utility commission finds that allowing the facility or facilities to be eligible for exempt wholesale generator status will benefit consumers, is in the public interest, and does not violate state law. Each of our operating subsidiaries has been designated by FERC as an exempt wholesale generator.

          We do not expect to engage in any activities that will subject us to regulation under PUHCA. In addition, our certificate of incorporation prohibits us from engaging in, any activities that will subject us to regulation under PUHCA without the consent of Goldman, Sachs & Co. until Goldman, Sachs & Co. and its affiliates own less than 5% of our outstanding common stock. If we were to lose our exempt wholesale generator status, we would become subject to regulation under the Holding Company Act. It would be difficult for us to comply with the Holding Company Act absent a substantial restructuring.

State Energy Regulation

          At the state level, public utility commissions are responsible for approving rates and other terms and conditions under which public utilities purchase electric power from independent producers and sell retail electric power to consumers. In addition, most state laws require approval from the state commission before an electric utility operating in the state may divest or transfer electric generation facilities. These laws also give the commissions authority to regulate the financial activities of electric utilities selling electricity to consumers in their states.

           State public utility commissions have authority to promulgate regulations for implementing some federal laws. Power sales agreements, which we enter into, are also potentially subject to review by state public utility commissions. In particular, the state public utility commissions review the process by which the utility has entered into power sales agreements. States may also assert jurisdiction over the siting, construction, and operation of our facilities, as well as the issuance of securities and the sale or other transfer of assets.

           New York. In 1996, the New York Public Service Commission began proceedings to introduce retail competition in New York State. These initiatives, in conjunction with FERC's "open access" rules, led to the formation of an ISO responsible for centralized control and operation of the state-wide electric transmission grid. They also led to a spot market and a related competitive electric energy auction. This auction is open on a non-discriminatory basis to all electric service providers. Other aspects of New York's restructuring plan include market power mitigation through utility divestiture of fossil fuel generation plants, the unbundling and establishment of separate rates for historic utility functions, and market mitigation measures at the wholesale level.

           Under the New York Public Service Law, the New York Public Service Commission has jurisdiction over corporations engaged in the production of electricity and transfers of electric generation facilities located in the State. The New York Public Service Commission reviewed and approved each of our transactions to acquire our assets located in New York, and made the necessary findings to permit us to seek exempt wholesale generator status from FERC. Moreover, while the NY-ISO is an independent entity, it is considered an "electric corporation" subject to the New York Public Service Law.

          In addition, the New York Public Service Commission has determined that certain requirements of the Public Service Law apply to new forms of electric service providers, which differ from traditional electric utilities. As a result, even though we do not engage in the sale of electricity at retail in New York State, our assets located in New York are subject to "lightened regulation" by the New York Public Service Commission. Under the lightened regulation regime, our assets located in New York are subject to provisions of the Public Service Law that relate to enforcement, investigation, safety, reliability, system improvements, construction, excavation, and the issuance of securities. The provisions relating to the issuance of securities apply to our subsidiaries that operate our assets located in New York, but not to a holding company such as Orion Power Holdings.

           Pennsylvania. In December 1996, Pennsylvania adopted the Electricity Generation Customer Choice and Competition Act, which is now part of the Public Utility Code. The Act is a comprehensive restructuring plan that allows direct access to be phased in over a three-year period beginning January 1, 1999 and culminating in full retail choice by January 1, 2001. Under this plan, one-third of each customer class will be eligible for direct access each year.

           Pennsylvania opened its retail electric market to competition on January 1, 1999. The Act required each utility to submit its restructuring plan to the Pennsylvania Public Utility Commission for approval. The Pennsylvania Public Utility Commission is authorized to permit, but may not require, utilities to divest their generation assets.

          In addition, the Pennsylvania restructuring plan authorizes utilities to implement a non-bypassable Competitive Transition Charge to collect stranded costs, subject to approval by the Pennsylvania Public Utility Commission, and permits securitization of stranded costs.

          The Pennsylvania Public Utility Code also requires that the Pennsylvania Public Utility Commission approve any transfers or acquisitions of property "used or useful in public service." The Pennsylvania Public Utility Commission approved the transaction between Duquesne Light Company and Orion Power MidWest. Unlike New York, however, Pennsylvania does not have a regulatory regime for wholesale generators in the state. Therefore, we do not expect to be subject to regulation by the Pennsylvania Public Utility Commission. However, if we do become subject to regulation by the Pennsylvania Public Utility Commission, additional costs may be imposed on the operations of our assets located in Ohio and Pennsylvania.

           Ohio. The Ohio legislature passed a statute in 1999 providing for implementation of retail competition beginning in 2001. The statute delegated to the Ohio Public Utilities Commission the responsibility for developing certain restructuring rules, including rules relating to market monitoring, stranded cost recovery, and consumer protection. The Ohio Public Utilities Commission proceedings are in a very early stage, and we cannot predict what effect they will have on us. Similar to the case with Pennsylvania, we do not expect to be subject to regulation by the commission. If we do become subject to regulation by the Ohio Public Utilities Commission, however, additional costs may be imposed on the operations of our assets located in Ohio and Pennsylvania.

           West Virginia. In 1998, the West Virginia Legislature enacted HB 4277, which authorized the Public Service Commission to consider whether restructuring was in the public interest and, if so, to submit a restructuring plan for Legislative approval. In January 2000, the Commission issued an order finding restructuring in the public interest and submitting a long-term plan for transition to competitive power supply markets and consumer choice.

           During the 2000 legislative session, the West Virginia Legislature approved the Commission's plan. However, the plan cannot be implemented until the Legislature passes tax measures included in the restructuring plan. In late 2000, the Legislature decided to delay consideration of the tax changes that were necessary before the restructuring plan could be implemented. Consideration of the tax measures was delayed to give the Legislature the opportunity to seek an independent review of the differences between the proposed restructured markets in West Virginia and those that are experiencing difficulty in other regions of the United States. It is anticipated that the Legislature and the Governor will await independent evaluations of the Commission's proposed plan before proceeding to implement deregulation and the development of competitive power supply markets in West Virginia.

           Maryland. In April 1999, Maryland's Governor signed the Electric Customer Choice and Competition Act into law. This law established the legal framework for the restructuring and deregulation of the electric utility industry in Maryland. The Act deregulates the generation, supply, and pricing of electricity and provides that retail electric choice will be fully available to all customers by July 2002. As a consequence of restructuring, the Maryland Public Service Commission no longer has statutory responsibility for the oversight of generation facilities, but will continue its ongoing review of the maintenance and operation of electric utility transmission and distribution facilities in the State. Since the Act removes generation from the Maryland Public Service Commission's jurisdiction, our Maryland generating assets will not be subject to regulation by the Maryland Commission. If we do become subject to regulation by the Maryland Commission, additional costs may be imposed on the operations of our assets located in Maryland.

           Kentucky. In 1998, the Kentucky Legislature passed legislation creating the Kentucky Electricity Restructuring Task Force. In December 1999, the Task Force issued its Findings and Recommendations under its initial authorization. These findings are also found in the Final Report Special Task Force on Electricity Restructuring, issued in September 2000. The first finding was that there was no compelling reason to move quickly towards restructuring in Kentucky. The Task Force based this finding on a number of facts, including Kentucky's current low electricity rates and the possibility that Congress will pass a nationwide restructuring bill. The Task Force advocated a wait-and-see approach that would allow Kentucky to monitor progress in other states and develop options to protect Kentucky's existing low rates.

          In April 2000, the Kentucky General Assembly reauthorized the Task Force. Under the reauthorization, the Task Force is to monitor developments related to electricity restructuring and make recommendations it deems appropriate for consideration by the 2002 General Assembly and the Governor. The Task Force is charged with reporting to the Legislative Research Commission and the Governor no later than November 15, 2001.

Environmental Regulations

          The construction and operation of electric generating facilities are subject to extensive environmental and land use regulation in the United States. Those regulations applicable to us primarily involve the discharge of emissions into the water and air as well as the use of water, but can also include wetlands preservation, endangered species, waste disposal, and noise regulation. These laws and regulations often require a lengthy and complex process of obtaining and renewing licenses, permits, and approvals from federal, state, and local agencies. If these laws and regulations are changed, modifications to our facilities may be required.

           Clean Air Act. In late 1990, Congress passed the Clean Air Act Amendments of 1990, which affect existing facilities as well as new project development. The act and many state laws require significant reductions in SO2 (sulfur dioxide) and NOx (nitrogen oxide) emissions that result from burning fossil fuels.

          The 1990 Amendments create a marketable commodity called an SO2 "allowance." All non-exempt facilities over 25 megawatts that emit SO2 must hold or obtain allowances in order to operate. Each allowance gives the owner the right to emit one ton of SO2. All non-exempt facilities that existed in 1990 have an assigned number of allowances. If additional allowances are needed, they can be purchased from facilities having excess allowances. Our assets located in New York currently have more allowances than needed, while our assets located in Ohio and Pennsylvania require additional allowances or the installation of SO2 controls. We believe that the additional costs of obtaining the number of allowances needed for future projects should not materially affect our ability to purchase and operate such facilities.

          The 1990 Amendments also require states to impose annual operating permit fees. While such permit fees may be substantial and will be greater for coal-fired projects like our assets located in Ohio and Pennsylvania than for those burning gas or other fuels, such fees are not expected to significantly increase our costs.

          The 1990 Amendments also contain other provisions that could materially affect our projects. Various provisions may require permits, inspections, or installation of additional pollution control technology.

          The 1990 Amendments expand the enforcement authority of the federal government by increasing the range of civil and criminal penalties for violations of the Clean Air Act. They enhance administrative civil penalties and add a citizen suit provision. These enforcement provisions also include enhanced monitoring, record-keeping, and reporting requirements for existing and new facilities.

          The Ozone Transport Assessment Group, composed of state and local air regulatory officials from the 37 eastern states, has recommended additional NOx emission reductions that go beyond current federal standards. These recommendations include reductions from utility and industrial boilers during the summer ozone season.

          As a result of the Ozone Transport Assessment Group's recommendations, on October 27, 1998, the EPA issued a rule requiring 22 Eastern states and the District of Columbia to reduce emissions of NOx (a precursor of ozone) in those states. Among other things, the EPA's rule establishes an ozone season, which runs from May through September, and a NOx emission budget for each identified state, including New York, Ohio and Pennsylvania. The EPA rule requires states to implement controls sufficient to meet their NOx budget by May 1, 2003. The states use a marketable commodity called a NOx "allowance" allocation to implement the NOx emission budget. Our assets will be subject to NOx reduction requirements under the EPA rule. Due to relatively low NOx emissions from our facilities, however, our assets located in New York are unlikely to be impacted by this rulemaking. In contrast, the assets located in Ohio and Pennsylvania will be affected significantly. Beginning in 2003, the EPA rule will result in a requirement for substantial NOx reductions or the purchase of additional NOx allowances at the assets located in Pennsylvania, which will likely result in significant capital expenditures by us. The same requirement will impact our Ohio assets in 2004.

          The EPA recently granted several state petitions under Section 126 of the Clean Air Act. Section 126 allows the EPA to set limits for specific sources of emissions originating in other states. As a result, the EPA will require reductions in NOx emissions at the majority of our fossil energy facilities at levels consistent with those required under the EPA rule. Consistent with the EPA's rule, reductions have been proposed which would need to be achieved by May 1, 2004 through the implementation of controls or the purchase of emission allowances. We believe that our assets located in New York City are already in compliance with these limits. We anticipate capital expenditures of approximately $300 million at the assets located in Ohio and Pennsylvania through 2010 to address these anticipated air emissions issues. We expect that the majority of these expenditures under the EPA rule and the EPA's Section 126 initiative will occur between 2002 and 2008. However, particularly given the trend towards more stringent environmental regulation, it is possible that the amount we must spend to bring the facilities into compliance may change materially. In addition, the time at which these capital expenditures must be made could be accelerated, and operations could be halted at these facilities until any necessary improvements are made.

          In October and November 1999, the EPA and several states filed suits or announced their intention to file suits against a number of coal-fired power plants in Midwestern and Eastern states. These suits relate to alleged violations of the Clean Air Act. More specifically, they derive from the deterioration prevention and non-attainment provisions of the Clean Air Act's new source review requirements. In 1999, the EPA requested information relating to the Avon Lake Generating Station and Niles Generating Station from the previous owner of these facilities. This was part of the EPA's broader industry information request, and forms the basis for the agency's new source review actions against coal-fired power plants. Although there have not been any new source review-related suits filed against the Avon Lake Generating Station or the Niles Generating Station, there can be no assurance that either of them will not be the target of any such action in the future. Based on the levels of emissions control that the EPA and/or states are seeking in these new source review enforcement actions, we believe that significant additional costs and penalties could be incurred, planned capital expenditures could be accelerated, or operations could be halted at these stations if they ever became targets of a new source review enforcement action.

           Individual states can also regulate air emissions, the costs of compliance with which could be significant. For example, in 1999, New York Governor George Pataki introduced new emission requirements for generation facilities in the State, which must be achieved by 2003. The New York State requirements, among other things, require year-round reductions in nitrogen oxide emissions, which were previously limited to summertime reductions. Additionally, under these requirements, we have to reduce our sulfur dioxide emissions from our New York power plants. These emission reductions would be phased in between January 1, 2003 and January 1, 2007. Compliance with these emission reductions requirements, if they become effective, could have a material adverse impact on the operation of our assets located in New York. While we anticipate that we should be able to satisfy these constraints, additional constraints may be added in various jurisdictions that may affect our facilities and increase our costs of compliance.

          The 1990 Amendments required the EPA to evaluate the public health impacts of emissions of mercury, a hazardous air pollutant, from power plants. The EPA has not proposed emissions controls because commercially viable control technologies have not been developed for utility boilers. However, the EPA has announced that it intends to propose regulations by 2003 and issue final rules by 2004. When emissions controls are mandated, all coal-fired utility boilers would be affected and the cost of compliance could be substantial.

          The Kyoto Protocol regarding greenhouse gas emissions and global warming was signed by the United States, thereby committing the United States to significant reductions in greenhouse gas emissions between 2008-2012. The U.S. Senate must ratify the agreement for the protocol to take effect. Future initiatives on this issue and the ultimate effect of the Kyoto Protocol are unknown at this time. Fossil fuel-fired power plants, however, are believed to be significant sources of carbon dioxide emissions, which constitute a principal greenhouse gas. Therefore, the power industry's compliance costs with mandated federal greenhouse gas reductions could be significant.

           Clean Water Act. Our facilities are subject to a variety of state and federal regulations governing existing and potential water /wastewater and stormwater discharges from the facilities. Generally, federal regulations promulgated through the Clean Water Act govern overall water/wastewater and stormwater discharges through permits. Under current provisions of the Clean Water Act, existing permits must be renewed at least every five years, at which time permit limits come under extensive review and can be modified to account for more stringent regulations. In addition, the permits can be modified at any time. Many of our facilities need to renew their Clean Water Act permits over the next two years. Major issues to be addressed when permits are renewed include the impact of intake screens and cooling systems on fish, as well as the adverse impact of discharging large quantities of warm water to public rivers and lakes. The cost of addressing any of these environmental issues could be substantial.

          In addition, changes to the environmental permits of our coal or other fuel suppliers may increase the cost of fuel, which in turn could have a significant impact on our operations.

           Emergency Planning and Community Right-to-Know Act. In April 1997, the EPA expanded the list of industry groups required to report the Toxic Release Inventory under Section 313 of the Emergency Planning and Community Right-to-Know Act to include electric utilities. Our operating facilities will be required to complete a toxic chemical inventory release form for each listed toxic chemical manufactured, processed, or otherwise used in excess of threshold levels for the applicable reporting year. The purpose of this requirement is to inform the EPA, states, localities, and the public about releases of toxic chemicals to the air, water, and land that can pose a threat to the community.

           Changes in the laws governing disposal of coal ash generated by our coal-fired plants to classify coal ash as a hazardous waste or otherwise restrict the disposal of coal ash could increase our costs and expose us to greater potential liabilities for environmental remediation. The ash disposal sites used by our coal-fired facilities are permitted under state regulations. Those sites under our operational control have approved closure plans in place, and funds have been budgeted to accomplish the closures.

           Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, among other things, imposes cleanup requirements for threatened or actual releases of hazardous substances that may endanger public health or welfare of the environment. Under CERCLA, joint and several liability may be imposed on waste generators, site owners, and operators and others regardless of fault or the legality of the original disposal activity. Although all waste substances generated by the facilities are generally not regarded as hazardous substances, some products used in the operations and the disposal of such products are governed by CERCLA and similar state statutes. As a result of CERCLA's no-fault, retroactive liability scheme, we cannot assure you that we would be free from substantial liabilities in the future.

           Consent Orders. The assets located in New York City are subject to a consent order issued by the New York State Department of Environmental Conservation. The consent order requires active investigation and remediation of past releases of petroleum and other substances at the facilities by the prior owner. The consent order also contains obligations related to compliance with air emission and opacity regulations, corrective action requirements for solid waste management units, and investigation and implementation of measures to reduce water contamination and the killing of fish. The total liability assumed and recorded by Orion Power New York associated with these obligations was $9.2 million in the aggregate. We intend to fund this liability with cash flow from operations.

Competition

           We have many strong and well capitalized competitors in the wholesale power generation industry. These are both domestic and international organizations, many of whom have extensive and diversified operating expertise and financial resources that are greater than those we possess. We face competition in the markets for energy, capacity, and ancillary services, as well as intense competition for the acquisition and development of additional facilities.

           We anticipate increasing competition from international companies for acquisitions as the market continues to deregulate. As a result, it may be more difficult for us to compete effectively in future competitive bidding situations. In recent years, the industry has been characterized by increasingly strong competition with respect to the acquisition of existing electric generating facilities. This includes a trend away from negotiated transactions and towards competitive bidding.

           Following the expiration of our various transition power and capacity agreements, we will be subject to competition in the market for energy, capacity, and ancillary services. We will principally compete on the basis of the price of our products, although we will also compete to a lesser extent on the basis of reliability and availability. The continuing deregulation of the industry is likely to increase competition and may place downward pressure on energy prices.

Employees

          As of December 31, 2000, we employed approximately 870 people. Of these employees, approximately 554 are covered by collective bargaining agreements. The collective bargaining agreements expire at various dates between June 2001 and June 2006. We have never experienced a work stoppage, strike, or labor dispute. We consider relations with our employees to be good.

Item 2.   Properties.

          Our corporate offices currently occupy approximately 15,340 square feet of leased office space in Baltimore, Maryland, which lease expires in 2005, subject to renewal options.

          In addition to our corporate office space, we lease or own various real property and facilities relating to our assets and development activities. Our principal facilities are generally described under the descriptions of our three operating subsidiaries contained elsewhere. We believe that we have title to our facilities in accordance with standards generally accepted in the energy industry, subject to exceptions which, in our opinion, would not have a material adverse effect on the use or value of the facilities. Substantially all of our assets are pledged to our bank lenders under our credit facilities.

          We believe that all of our existing office and generating facilities, including the facilities under construction, are adequate for our needs through calendar year 2001. If we require additional space, we believe that we will be able to secure space on commercially reasonable terms without undue disruption to our operations.

          Our total lease expense for all of our properties described above was approximately $1.1 million for 2000, and will be approximately $1.1 million for 2001.

Item 3.   Legal Proceedings.

          We are involved in various litigation matters in the ordinary course of our business. We are not currently involved in any litigation that we expect, either individually or in the aggregate, will have a material adverse effect on our financial condition or results of operations.

Item 4.   Submission of Matters to a Vote of Security Holders

          None.

Executive Officers of the Registrant

          Our executive officers are as follows:

                                      Officer Since
            Name                Age      Since        Position
            ----                ---      -----        --------
Jack A. Fusco................   38       1998         Chief Executive Officer, President and Director
Scott B. Helm................   36       1998         Executive Vice President and Chief Financial Officer
W. Thaddeus Miller...........   50       1999         Executive Vice President and Chief Legal Officer
E. Thomas Webb...............   48       1998         Senior Vice President of Operations
Michael J. Gluckman..........   63       2000         Senior Vice President of Corporate Development

          Our officers are elected by our Board of Directors and serve at the discretion of the Board.

           Jack A. Fusco has been our Chief Operating Officer since our inception in March 1998. He was appointed President and Chief Executive Officer in November 1999. Mr. Fusco has over 16 years of experience in various areas of the power generation industry. Prior to joining us, Mr. Fusco was a Vice President at Goldman Sachs Power, an affiliate of Goldman, Sachs & Co., beginning in 1997. Prior to joining Goldman, Sachs & Co., Mr. Fusco was Executive Director of International Development and Operations for Pacific Gas & Electric's non-regulated subsidiary PG&E Enterprises. In that role, he was responsible for the development and implementation of PG&E's International Business Strategy and the launching of International Generating Company, an international wholesale power producer. Mr. Fusco holds a B.S. in Mechanical Engineering from California State University, and is a Registered Professional Mechanical Engineer in the State of California.

           Scott B. Helm joined us in September 1998 as Chief Financial Officer and was appointed Executive Vice President in November 1999. He is responsible for managing our accounting and finance functions. Prior to joining us, he was a Vice President in the Investment Banking Division of Goldman, Sachs & Co., commencing in 1994, where he generally focused on commodity, cyclical and industrial clients. Mr. Helm holds a B.S.B.A. from Washington University.

           W. Thaddeus Miller joined us in June 1999 as Chief Legal Officer, and was appointed Executive Vice President in November 1999. Mr. Miller has been advising us on legal matters since our inception. Prior to joining us, Mr. Miller was a Vice President and Associate General Counsel for Goldman, Sachs & Co., commencing in 1994 specializing in commodities, with particular emphasis on energy matters, where he advised our stockholder, GS Capital Partners II, L.P., on certain legal matters in connection with its investment in us. Prior to joining Goldman, Sachs & Co., Mr. Miller was a partner with Watson, Farley & Williams, an international law firm. He has been practicing law for over 20 years. Mr. Miller holds a B.S. from the United States Merchant Marine Academy (Kings Point) and a J.D. from St. John's University School of Law.

           E. Thomas Webb joined us in September 1998 as Vice President of Asset Management. In November 1999, he was appointed as Senior Vice President. Prior to joining us, Mr. Webb was employed by Pacific Gas & Electric from 1977 to August 1998 in a variety of posts, including power plant management, transmission and distribution operations and most recently as a manager of transmission projects. Mr. Webb has over 23 years of experience in the power generation industry. Mr. Webb holds a B.S. in Mechanical Engineering from California Polytechnic State University and an M.B.A. from St. Mary's College of California. Mr. Webb is a Registered Professional Mechanical Engineer in the State of California.

           Michael J. Gluckman joined us in December 2000 in connection with the acquisition of Columbia Electric Corporation, where he was President and Chief Executive Officer since 1996. Dr. Gluckman has over 30 years of experience in the energy industry, including research and development for all forms of fossil and renewable generation, development and assessment of advanced gas turbine technology, assessment of emerging electric markets, as well as a broad range of project development activities. Prior to joining Columbia Electric Corporation in 1996, Dr. Gluckman served as President and CEO of Paradigm Power Incorporated. Dr. Gluckman also spent 17 years with the Electric Power Research Institute. Dr. Gluckman holds a B.S. degree from the University of Cape Town in South Africa and a Ph.D. in chemical engineering from the City College of the City University of New York.

PART II

Item 5.   Market for Registrant's Common Equity and Related Stockholder Matters.

          Our common stock began trading on the New York Stock Exchange ("NYSE") on November 14, 2000 under the symbol "ORN." Prior to such date, no public market for our common stock existed. Set forth below are the high and low sales prices as reported on the NYSE Composite Tape.

2000:

Quarter                                            High                 Low
- -------                                            ----                 ---

4th Quarter (commencing November 14, 2000)        $24.625             $16.688

          As of March 1, 2001, there were approximately 30 shareholders of record. We believe there are approximately 6,500 beneficial owners of our common stock.

Dividend Policy

          We have never declared or paid any cash dividends on our common stock. We currently intend to retain any future earnings to fund the development and growth of our business. Therefore, we do not anticipate paying any cash dividends on our common stock in the foreseeable future. Our senior notes and credit facilities limit our ability to pay cash dividends.

Use of Proceeds from November 2000 Initial Public Offering

          In November 2000, the Company completed an initial public offering. The following information relates to that offering and the use of proceeds from that offering.

                  Underwriting Discounts and Commissions:         $34,375,000
                  Finders Fees:                                   $         0
                  Expenses Paid to or for Underwriters:           $         0
                  Other Expenses:                                  $2,686,000
                                                                  -----------
                           Total Expenses:                        $37,061,000
                                                                  ===========

          None of the expenses of the offering consisted of direct or indirect payments to (i) directors, officers, general partners or affiliates of the Company, (ii) persons owning 10 percent or more of any class of equity securities of the Company, or (iii) affiliates of the Company, other than approximately $16.4 million of the expenses of the offering which consisted of underwriting discounts and commissions paid to Goldman, Sachs & Co., which is an affiliate of the Company and an affiliate of persons owning 10 percent or more of the common stock of the Company. The net proceeds to the Company from the offering, after deducting underwriting discounts and commissions and other expenses, were approximately $443.5 million, approximately $209 million of which were used to acquire Columbia Electric Corporation. The remaining $243.5 million will be used for other acquisitions and/or development projects and for general corporate purposes, of which $100.0 million was used to fund construction of the Ceredo Generating Station, $23.5 million was used for general corporate operating expenses, and $120.0 million remained available as cash at December 31, 2000. The proceeds were invested in AAA-rated short term securities and will continue to be until the funds are appropriately deployed. None of such payments were made to directors, officers or 10% or more stockholders or to any associates or affiliates of the foregoing.

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 all of the financial statements and the notes thereto and other financial information included elsewhere herein. We have supplied selected capacity and other data set forth below under the caption "Operating Data."

                                    Orion Power Holdings, Inc. and Subsidiaries
                                        Selected Consolidated Financial Data
                                               (Dollars in Thousands)

                                                           March 10, 1998
                                                           (Inception) to      Year Ended      Year Ended
                                                            December 31,       December 31,     December 31,
                                                                1998              1999             2000
                                                                ----              ----             ----
Statement of Income Data:

Revenue ...............................................   $      314          $  134,074          957,569
                                                                 ---             -------          -------
Operating expenses:
   Fuel ...............................................           --              20,463          437,763
   Operations and maintenance .........................           24              22,732           97,607
   General and administrative .........................        2,620              16,755           37,082
   Taxes other than income tax ........................           --              20,785           60,751
   Depreciation and amortization ......................           94              18,938          103,196
   Charge for buyout of operations and maintenance
     contracts with related party......................           --                  --           19,000
                                                                ----                ----           ------
Total operating expenses...............................        2,738              99,673          755,399
                                                               -----              ------          -------
Operating (loss) income................................       (2,424)             34,401          202,170
Interest expense, net..................................         (124)            (23,943)        (153,389)
                                                               -----             -------        ---------
(Loss) income before (benefit) provision for income tax       (2,548)             10,458           48,781
Income tax (benefit) provision.........................       (1,006)              4,796           20,242
                                                             -------               -----           ------
Net (loss) income......................................   $   (1,542)    $         5,662   $       28,539
                                                             =======               =====           ======

(Loss) Earnings per Average Common Share:
   Basic ..............................................   $   (12.94)    $          0.39   $         0.46
                                                             =======                ====             ====
   Diluted ............................................   $   (12.94)    $          0.38   $         0.44
                                                             =======                ====             ====

Statement of Cash Flows Data:
Cash flows from operating activities ..................   $   (2,335)    $        10,456   $       (2,756)
Cash flows from investing activities ..................      (16,407)         (1,047,167)      (2,113,133)
Cash flows from financing activities ..................       20,345           1,113,657        2,173,174

Operating Data:
Consolidated EBITDA(a).................................   $   (2,330)    $        53,339   $      305,366
                                                             =======              ======          =======
Megawatt hours produced during period..................        7,283           2,793,689       14,801,420
Net capacity owned at end of period (Megawatts)........          102               2,613            5,396

                                                                      As of December 31,
Balance Sheet Data:                                           1998                1999               2000
                                                              ----                ----               ----
Working capital(b) ...................................    $    3,108    $         154,245    $    473,696
Total assets .........................................        20,450            1,252,007       3,870,190
Total debt, including current portion ................         2,593              787,680       2,367,898
Total stockholders' equity ...........................        17,068              395,416       1,254,782

                                                         March 10, 1998
                                                         (inception) to     Year Ended       Year Ended
                                                          December 31,     December 31,     December 31,
                                                             1998              1999             2000
                                                             ----              ----             ----
                                                                      (dollars in thousands)
Consolidated EBITDA.................................     $   (2,330)      $     53,339     $   305,366
                                                             =======            ======         =======
Megawatt hours produced during period...............          7,283          2,793,689      14,801,420
Net capacity owned at end of period (Megawatts).....            102              2,613           5,396

Source                                                            Amount         Interest Rate
- ------                                                            ------         -------------
                                                                      (dollars in millions)

Orion Power New York Credit Facility........................       $ 650             8.10 %
Orion Power MidWest Credit Facility.........................       1,170             8.49
12% Senior Notes due 2010...................................         400            12.00
Orion Power Holdings Revolving Credit Facility                       ---              N/A
Liberty Electric Credit Facility ...........................         148             8.49
                                                                   -----            -----


     Total..................................................      $2,368             8.98 %(a)
                                                                  ======             =========

                                                                                1999                2000
                                                                                ----                ----
Assets
Current assets:
     Cash and cash equivalents                                           $       78,549       $    135,834
     Restricted cash                                                             56,866            283,426
     Accounts receivable, net of allowances for bad debts of
       $1,458 in 2000                                                            37,271            154,777
     Inventories and supplies                                                    10,427             44,881
     Deferred income tax assets                                                   1,083             14,920
     Prepaid expenses and other current assets                                   13,765             28,307
                                                                                 ------             ------
Total current assets                                                            197,961            662,145
                                                                                -------            -------

Property and equipment, net of accumulated depreciation of $18,075 and
$116,861 for 1999 and 2000, respectively                                        975,835          3,083,546
                                                                                -------          ---------

Other noncurrent assets:
     Prepaid expenses and other noncurrent assets                                 3,164             12,134
     Identifiable purchased intangibles, net of accumulated
       amortization of $857 and $4,998, for 1999 and 2000, respectively          59,284             70,786
     Deferred financing costs, net of accumulated amortization of                15,763             41,579
       $2,178 and $13,459, for 1999 and 2000, respectively                       ------             ------
Total other noncurrent assets                                                    78,211            124,499
                                                                                 ------            -------
Total assets                                                             $    1,252,007       $  3,870,190
                                                                              =========          =========

The accompanying notes are an integral part of these consolidated balance sheets.

Orion Power Holdings, Inc. and Subsidiaries

Consolidated Balance Sheets
as of December 31, 1999 and 2000
(In Thousands, Except Share Data)

                                                                  1999                 2000
                                                                  ----                 ----
Liabilities and stockholders' equity
Current liabilities:
     Accounts payable                                       $       23,643        $      117,000
     Accrued expenses                                               14,420                50,711
     Accrued interest                                                3,573                18,641
     Deferred revenue                                                1,794                 1,836
     Note payable - current portion                                    286                   261
                                                                       ---                   ---
Total current liabilities                                           43,716               188,449

Note payable, long-term                                                308                    --
Notes payable to stockholders                                       71,086                    --
Long-term debt                                                     716,000             2,367,637
Deferred income tax liabilities                                      3,094                 8,931
Other long-term liabilities                                         22,387                50,391
                                                                    ------                ------
Total liabilities                                                  856,591             2,615,408
                                                                   -------             ---------

Commitments and contingencies (Note 8)

Stockholders' equity:
     Common stock, $.01 par value; 200 million shares
       authorized; 36,162,629 and 93,095,926 shares
       issued and outstanding as of
       December 31, 1999 and 2000, respectively
                                                                       362                   931
     Additional paid-in capital                                    393,416             1,230,467
     Deferred compensation                                          (1,811)               (3,359)
     Notes receivable from officers                                   (671)               (5,916)
     Retained earnings                                               4,120                32,659
                                                                     -----                ------
Total stockholders' equity                                         395,416             1,254,782
                                                                   -------             ---------
Total liabilities and stockholders' equity                  $    1,252,007        $    3,870,190
                                                                 =========             =========

The accompanying notes are an integral part of these consolidated balance sheets.

Orion Power Holdings, Inc. and Subsidiaries

Consolidated Statements of (Loss) Income
for the Period from March 10, 1998 (Date of Inception) to December 31, 1998
and for the Years Ended December 31, 1999 and 2000
(In Thousands, Except Per Share Amounts)

                                                            1998             1999                 2000
                                                            ----             ----                 ----

 Operating revenues (Note 6)                          $       314        $   134,074          $   957,569
 Operating expenses
      Fuel                                                     --             20,463              437,763
      Operations and maintenance (Note 6)                      24             22,732               97,607
      General and administrative                            2,620             16,755               37,082
      Taxes, other than income taxes                        -----             20,785               60,751
      Depreciation and amortization                            94             18,938              103,196
       Charge for buyout of operations and
          maintenance contracts with related
          party (Notes 3 and 6)                              --                   --               19,000
                                                             ---                 ---               ------
 Total operating expenses                                   2,738             99,673              755,399
                                                            -----             ------              -------

 Operating (loss) income                                   (2,424)            34,401              202,170
 Interest income                                               13              1,824               15,281
 Interest expense                                            (137)           (25,767)            (168,670)
                                                            ------           -------             --------
 (Loss) income before (benefit) provision for
   income tax                                              (2,548)            10,458               48,781
 Income tax (benefit) provision                            (1,006)             4,796               20,242
                                                           ------              -----               ------
 Net (loss) income                                  $      (1,542)       $     5,662          $    28,539
                                                         ========              =====               ======

 (Loss) earnings per average common share:
 Basic                                                 $   (12.94)       $     0.39           $     0.46
                                                          =======              ====                 ====
 Diluted                                               $   (12.94)       $     0.38           $     0.44
                                                          =======              ====                 ====

The accompanying notes are an integral part of these consolidated balance sheets.

Orion Power Holdings, Inc. and Subsidiaries

Consolidated Statements of Changes in Stockholders' Equity
For the Period from March 10, 1998 (Date of Inception) to December 31, 1998
and for the Years Ended December 31, 1999 and 2000
(In Thousands, Except Share Amounts)


                                                                                                Additional
                                                                        Common stock              paid-in
                                                                    Shares         Amount         capital
  Beginning balance, March 10, 1998                                        --    $      --     $         --
        Sale of common stock                                        1,864,542           19           18,626
        Net loss                                                           --           --               --
                                                                          ---          ---              ---
  Balance, December 31, 1998                                        1,864,542           19           18,626
        Sale of common stock, net of fees                          34,298,087          343          382,623
        Distribution to stockholders (Note 6)                              --           --          (9,750)
        Deferred compensation pursuant to issuance of stock
  ------------------------------------------------------------             --           --            1,917
           options
        Amortization of deferred compensation                              --           --               --
        Net income                                                         --           --               --
                                                                          ---          ---              ---
  Balance, December 31, 1999                                       36,162,629          362          393,416
        Sale of common stock, net of fees                          56,933,297          569          851,250
        Distribution to stockholders (Note 6)                              --           --         (17,050)
        Deferred compensation pursuant to issuance of stock
           options                                                         --           --            2,851
        Amortization of deferred compensation                              --           --               --
        Change in notes receivable                                         --           --               --
        Net income                                                         --           --               --
                                                                          ---          ---              ---
  Balance, December 31, 2000                                       93,095,926   $      931     $  1,230,467
                                                                  ===========          ===        =========


                                                                        Notes
                                                                      receivable   Retained
                                                          Deferred       from     (deficit)
                                                         Compensation   officers    earnings     Total
  Beginning balance, March 10, 1998                      $       --     $    --  $      --    $       --
        Sale of common stock                                     --        (35)         --        18,610
        Net loss                                                 --          --    (1,542)       (1,542)
                                                                ---         ---    -------       -------
  Balance, December 31, 1998                                     --        (35)    (1,542)        17,068
        Sale of common stock, net of fees                        --       (636)         --       382,330
        Distribution to stockholders (Note 6)                    --          --         --       (9,750)
        Deferred compensation pursuant to issuance
         of stock options                                    (1,917)         --         --            --
        Amortization of deferred compensation                   106          --         --           106
        Net income                                               --          --      5,662         5,662
                                                                ---         ---      -----         -----
  Balance, December 31, 1999                                (1,811)       (671)      4,120       395,416
        Sale of common stock, net of fees                        --     (5,001)         --       846,818
        Distribution to stockholders (Note 6)                    --          --         --      (17,050)
        Deferred compensation pursuant to issuance
          of stock options                                   (2,851)         --         --            --
        Amortization of deferred compensation                 1,303          --         --         1,303
        Change in notes receivable                               --       (244)         --         (244)
        Net income                                               --          --     28,539        28,539
                                                                ---         ---     ------        ------
  Balance, December 31, 2000                             $  (3,359)    $(5,916)  $  32,659   $ 1,254,782
                                                            =======     =======     ======     =========

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

Orion Power Holdings, Inc. and Subsidiaries

Consolidated Statements of Cash Flows
for the Period from March 10, 1998 (Date of Inception) to December 31, 1998
and for the Years Ended December 31, 1999 and 2000
(In Thousands)

                                                             1998                 1999            2000
                                                             ----                 ----            ----

  Cash flows from operating activities:
       Net (loss) income                                    $(1,542)             $5,662          $28,539
       Adjustments to reconcile net (loss) income to
         net cash (used in) provided by operating
         activities:
             Depreciation and amortization                       94              21,116          114,496
             Charge for buyout of operations and
               maintenance contracts (Notes 3 and 6)            --                  --            18,900
             Deferred income taxes                           (1,006)              3,017           (8,000)
             Deferred compensation                              --                  106            1,303
             Notes receivable from officers                     --                  (21)            (244)
             Change in assets and liabilities:
                    Restricted cash                            (623)            (30,243)        (169,268)
                    Accounts receivable                         (22)            (37,249)        (117,506)
                    Inventories and supplies                     --              (4,182)           7,930
                    Prepaid expenses and other
                      current assets                             (2)              6,004          (13,928)

                    Prepaid expenses and other
                      noncurrent assets                          --               3,164           (2,147)
                    Accounts payable                            477              23,166           83,286
                    Accrued expenses                            235              14,185           36,260
                    Accrued interest                             54               3,540           13,952
                    Other long-term liabilities                  --                 397            3,629
                    Deferred revenue                             --               1,794               42
                                                               ----               -----               --
  Net cash (used in) provided by operating activities        (2,335)             10,456           (2,756)
                                                             ------              ------           ------

  Cash flows from investing activities:
       Purchase of property, equipment and related
         assets in acquisitions (see Notes 2 and 3)         (16,407)         (1,024,332)      (1,975,252)
       Purchase of property and equipment in
         operations                                              --             (22,835)        (137,881)
                                                            -------             -------         --------
  Net cash used in investing activities                     (16,407)        $(1,047,167)       (2,113,133)
                                                            -------          ----------         ---------

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

Orion Power Holdings, Inc. and Subsidiaries

Consolidated Statements of Cash Flows (In Thousands)

Cash flows from financing activities:                        1998               1999             2000
                                                             ----               ----             ----
     Issuance of common stock, net                      $    18,610      $      382,330    $    756,832
     Distribution to stockholders                                --              (9,750)        (17,050)
     Proceeds from long-term debt                                --             720,000       1,629,537
     Payments on long-term debt                                  --              (4,000)       (109,000)
     Proceeds from notes payable to stockholders              1,735             110,539              --
     Payments on notes payable to stockholders                   --             (41,188)             --
                                                             ------           ---------       ---------
     Funding of reserve accounts established with
       the Credit Agreement (restricted cash)                    --             (26,000)        (55,000)
     Payment on note payable                                     --                (333)           (333)
     Payment of deferred financing costs                         --             (17,941)        (31,812)
                                                               ----             --------        -------
Net cash provided by financing activities                    20,345           1,113,657       2,173,174
                                                             ------           ---------       ---------

Net increase in cash and cash equivalents                     1,603              76,946          57,285
Cash and cash equivalents, beginning of period
                                                                 --               1,603          78,549
                                                              -----               -----          ------
Cash and cash equivalents, end of period                $     1,603      $       78,549    $    135,834
                                                              =====              ======         =======

 Supplemental disclosure of cash flow information:
     Cash paid for-
           Interest                                     $        83      $       20,070    $    144,436
                                                                 ==              ======         =======
           Income taxes                                          --      $          640    $     25,111
                                                               ====                 ===          ======
     Noncash disclosure-
           Note payable for inventory                   $       859      $           --    $         --
                                                                ===                ====             ===
           Notes receivable from officers               $        35      $          615    $      5,001
                                                                 ==                 ===           =====
           Other long-term liabilities assumed in
             acquisitions                               $        --      $       21,990    $     24,375
                                                               ====              ======          ======
           Debt assumed in acquisitions                 $        --      $           --    $    131,100
                                                               ====                ====         =======
           Conversion of notes payable to equity        $        --      $           --    $     71,086
                                                               ====                ====          ======

                                        1999                2000
                                        ----                ----
Fuel                              $     3,333           $    17,439
Supplies                                7,094                27,442
                                        -----                ------
                                  $    10,427           $    44,881
                                       ======                ======

                                     1999            2000         Useful Lives
                                     ----            ----         ------------
Structures and improvements      $    196,664     $    637,650        15-40
Production assets                     584,903        1,640,693        10-30
Accessories and other equipment       141,718          340,619        3-15
Other assets                           17,311          117,533        3-30
                                       ------          -------
                                      940,596        2,736,495
Less:  accumulated depreciation       (18,075)        (116,861)
                                      --------        ---------
                                      922,521        2,619,634
Land                                   53,314           66,610
Construction in progress                  ---          397,302
                                      --------         -------

Property and equipment, net        $  975,835     $  3,083,546
                                      -------        ---------

                                                   1999             2000
                                                   ----             ----
FERC licenses                               $    60,141         $   60,348
POLR contract (Note 3)                               --             14,288
Other                                                --              1,148
Accumulated amortization                           (857)            (4,998)
                                                   ----             ------
Total                                       $    59,284         $   70,786
                                                 ======             ======

               Current assets                           $         2,906
               Property and equipment                           336,286
               Noncurrent assets                                 12,127
               Debt and other liabilities assumed              (142,319)
                                                               ---------
                                                          $     209,000
                                                                =======

        2001                              $             261
        2002                                      1,850,937
        2003                                          8,151
        2004                                          8,646
        2005                                          9,146
        Thereafter                                  490,757
                                                    -------
        Total                             $       2,367,898
                                                  ---------

                                                   Defined benefit plans                    OPEB
                                                    1999          2000            1999            2000
                                                    ----          ----            ----            ----
Change in benefit obligation-
    Benefit obligation at January 1             $        --   $     17,398     $        --    $      4,318
    Benefit obligation assumed in acquisition        17,984         10,071           4,226           9,504
    Service cost                                        629          2,215             238             886
    Interest cost                                       517          1,868             121             826
    Benefits paid                                        --         (1,085)             --              --
    Actuarial (gain) loss                           (1,732)            460           (267)           1,871
                                                    -------         ------           -----           -----
    Benefit obligation at December 31           $    17,398   $     30,927     $     4,318    $     17,405
                                                     ======         ======           =====          ======
Change in plan assets-
    Fair value of plan assets at January 1      $        --   $     11,967     $        --    $         --
    Fair value of plan assets assumed in
      acquisition                                    11,668             --              --              --
    Actual return on plan assets                        299            785              --              --
    Employer contributions                               --            597              --              --
    Benefits paid                                        --        (1,085)              --              --
                                                        ---        -------             ---             ---
    Fair value of plan assets at December 31    $    11,967   $     12,264     $        --    $         --
                                                     ======         ======             ===             ===
Funded status-
    Funded status of the plans at December 31   $   (5,431)   $   (18,663)     $   (4,318)    $   (17,405)
    Unrecognized actuarial net gains/(losses)       (1,618)          (887)           (267)           1,603
                                                    -------          -----           -----           -----
Accrued benefit cost                            $   (7,049)   $   (19,550)     $   (4,585)    $   (15,802)
                                                    ======        ========         =======        ========
Assumptions as of December 31:
    Discount rate                                     7.75%          7.75%           7.75%           7.75%
    Expected return on plan assets                    8.50%          8.50%             N/A             N/A
    Rate of compensation increase                     4.50%          4.00%           4.00%           5.00%

                                                       Defined benefit plans              OPEB
                                                        1999           2000       1999            2000
                                                        ----           ----       ----            ----
Components of net periodic benefit cost:
         Service cost                                $    629         $ 2,215   $    238        $   886
         Interest cost                                    517           1,868        121            826
         Expected return on plan assets                  (413)         (1,017)        --             --
         Amortization of actuarial (gain) or loss          --             (38)        --             --
                                                          ---             ----       ---            ---
         Net periodic benefit cost                   $    733         $ 3,028   $    359        $ 1,712
                                                          ===           =====        ===          =====

                                                                1-percentage             1-percentage
                                                               point increase           point decrease
                                                            1999           2000      1999         2000
                                                            ----           ----      ----         ----
Increase (decrease) total service and interest cost
     components                                                $80          $  464   $  (62)      $ (361)
Increase (decrease) OPEB obligation                            908           3,758     (712)      (2,949)

   Year ending December 31,                     Capital                Operating
   ------------------------                     -------                ---------
   2001                                       $      126             $   1,266
   2002                                              126                 1,280
   2003                                              126                 1,298
   2004                                              126                 1,309
   2005                                              126                 1,054
   Thereafter                                      1,145                 3,830
                                                   -----                 -----
                                                   1,775             $  10,037
                                                                         =====
   Interest portion                                 (594)
                                                    -----
   Total                                      $    1,181
                                                   =====

                                                               Number              Weighted-average
                                                             of shares              exercise price
                                                       -----------------------  ------------------------
Outstanding at March 10, 1998 (Date of Inception)                     --           $         --
     Granted                                                      49,964                  10.00
                                                                  ------
Outstanding at December 31, 1998                                  49,964                  10.00
     Granted                                                   1,627,246                  11.91
                                                               ---------
Outstanding at December 31, 1999                               1,677,210                  11.86
     Granted                                                   3,544,813                  17.39
     Forfeited                                                   (32,176)                (14.91)
                                                                 --------
Outstanding at December 31, 2000                               5,189,847                  15.28
                                                               =========
Options exercisable at December 31, 1998                              --                     --

Options exercisable at December 31, 1999                         118,163                  10.00
                                                                 -------
Options exercisable at December 31, 2000                         678,352                  10.66
                                                                 -------

                                                                                   Weighted-average
                                                                                      remaining
                                  Stock options           Weighted-average         contractual life
Range of exercise prices           outstanding             exercise price             (in yrs.)
- ---------------------------- ------------------------- ------------------------ -----------------------
$10.00 - $15.50                     2,996,379                   $11.95                   $8.96
$15.51 - $20.00                     2,193,468                    19.83                    9.86
- ---------------------------- ------------------------- ------------------------ -----------------------
                                    5,189,847                   $15.28                   $9.34
- ---------------------------- ------------------------- ------------------------ -----------------------

                                         Stock options                   Weighted-average
Range of exercise prices                  exercisable                     exercise price
- -------------------------------- ------------------------------- ---------------------------------
$10.00 - $15.50                             678,352                              $10.66
$15.51 - $20.00                                  --                               --
- -------------------------------- ------------------------------- ---------------------------------
                                            678,352                              $10.66
- -------------------------------- ------------------------------- ---------------------------------

                                           1998                  1999                   2000
- ---------------------------------- --------------------- --------------------- -----------------------
Expected life in years                      10                    10                     10
Risk-free interest rate                    N/A                  5.12%                  5.11%
Volatility                                 N/A                  16.40%                 35.00%
Dividend yield                             ---                    ---                    ---
- ---------------------------------- --------------------- --------------------- -----------------------

(Dollars in thousands,
except per share amounts)                   1999                   2000
- ----------------------------------  --------------------- -----------------------
Pro forma net income                       $4,711                $17,853
Pro-forma net income
   per common share-basic                   $0.33                  $0.29
Pro forma net income
   per common share -
   assuming dilution                        $0.32                  $0.28
- ----------------------------------  --------------------- -----------------------

                                                             1999                             2000
                                                    Current        Long-Term       Current         Long-Term
Accumulated deferred income taxes:
     Deferred tax assets-
         Accruals and Prepaids                   $        --     $      --      $  15,352       $     1,090
         Net operating loss carryforward                  --            --             --             5,853
         Amortization differences on
             intangibles                                  --            --            517             6,720
         Long-term liabilities assumed in
             acquisition                                 938         8,007             --            17,964
         Deferred compensation                            --            44             --               532
         Acquisition costs                               145         3,109            122             3,172
                                                       -----        ------         ------            ------
Total deferred tax assets                              1,083        11,160         15,991            26,313
                                                       -----        ------         ------            ------
     Deferred tax liabilities-
         Depreciation differences on property
             and equipment                                --        (5,308)         ------          (25,582)
         Difference in asset basis of property
             and equipment                                --        (8,946)         ------          (18,680)
         Other                                            --            --         (1,071)               --
                                                       -----        ------         ------            ------
Total deferred liabilities                                --       (14,254)        (1,071)          (44,262)
                                                       -----        ------         ------            ------
Net accumulated deferred income tax assets
  (liabilities)                                  $     1,083     $  (3,094)     $  14,920       $    (8,931)
                                                       =====        =======        ======            =======

                                                 1998                    1999                    2000
                                          --------------------    --------------------    ------------------
Current:
     Federal                                $        --             $       1,378           $      14,417
     State                                           --                       401                  13,825
                                                     --                       ---                  ------
                                                     --                     1,779                  28,242
                                                 ------                     -----                  ------
Deferred:
     Federal                                       (880)                    2,418                   1,079
     State                                         (126)                      599                  (9,079)
                                                 -------                    -----                  ------
                                                 (1,006)                    3,017                  (8,000)
                                                 ------                     -----                  ------
Total income tax (benefit) provision        $    (1,006)            $       4,796           $      20,242
                                                 ------                     -----                  ------

                                                            1998          1999          2000
Income tax (benefit) provision computed at Federal
    statutory rates                                      $    (892)    $    3,660     $  17,073
Permanent differences                                           --            484            84
State income taxes, net of Federal income tax benefit          (83)           650         3,085
Other                                                          (31)             2            --
                                                            ------          -----        ------
Total                                                    $  (1,006)    $    4,796     $  20,242
                                                            =======         =====        ======

                                                                                               Per Share
                                                                Net Income       Shares         Amount
                                                                ----------       ------         ------
For the period from March 10, 1998 (Date of Inception) to
December 31, 1998:
     Basic EPS-                                                  $  (1,542)        119,200     $  (12.94)
         Effect of dilutive securities                                  --              --
     Diluted EPS-                                                $  (1,542)        119,200     $  (12.94)
                                                                    =======        =======        =======

For the year ended December 31, 1999:
     Basic EPS-                                                  $   5,662      14,344,400     $    0.39
         Effect of dilutive securities
            Stock options                                               --          83,700
            Warrants                                                    --         518,800
                                                                     -----      ----------
     Diluted EPS-                                                $   5,662      14,946,900     $    0.38
                                                                     =====     ===========          ====

For the year ended December 31, 2000
     Basic EPS-                                                  $  28,539      61,755,269     $    0.46
         Effect of dilutive securities:
             Stock options                                             --          480,364
             Warrants                                                  --        2,202,685
                                                                 ---------       ---------
         Diluted EPS-                                            $  28,539      64,438,318     $    0.44
                                                                    ======      ==========          ====

                                                          Quarter Ended
                                    March 31       June 30           September 30     December 31
2000

Operating Revenues                 $   105,506    $    236,168         $  343,010     $   272,885
Operating Income                   $    28,918    $     65,689         $   59,586     $    47,977
Net Income                         $     8,294    $      5,456         $    3,921     $    10,868
Net Income per share - basic       $      0.23    $       0.09         $     0.05     $      0.13
Net Income per share - diluted     $      0.22    $       0.09         $     0.05     $      0.13

1999

Operating Revenues                 $       933    $      1,090         $   35,612     $    96,439
Operating Income (Loss)            $      (752)   $     (2,016)        $   12,019     $    25,150
Net Income (Loss)                  $      (504)   $     (1,175)        $    2,683     $     4,658
Net Income per share - basic       $     (0.27)   $      (0.61)        $     0.13     $      0.14
Net Income per share - diluted     $     (0.27)   $      (0.61)        $     0.13     $      0.13

ASSETS                                                                   1999                  2000
                                                                   ----------------      ----------------
Current Assets:
   Cash and cash equivalents                                       $       78,081        $      133,653
   Restricted cash                                                            651                    --
   Due from affiliates                                                     17,112               149,910
   Prepaid expenses and other current assets                                  132                 1,294
                                                                   ----------------      ----------------
Total current assets                                                       95,976               284,857
                                                                   ----------------      ----------------
Property and equipment:
   Property and equipment                                                   2,936                 3,333
   less accumulated depreciation                                             (218)                 (564)
Property and equipment, net                                                 2,718                 2,769
Deferred tax asset                                                          3,911                28,212
Deferred financing fees, net of accumulated amortization
   of $1,082 at December 31, 2000                                              --                12,118
Prepaid expenses and other noncurrent assets                                   --                 2,200
Investment in subsidiaries                                                370,787             1,350,831
                                                                   ----------------      ----------------
Total assets                                                       $      473,392        $    1,680,987
                                                                   ================      ================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
   Accounts payable                                                $           --        $          742
   Accrued expenses                                                         4,729                17,226
   Accrued income taxes                                                        --                    --
   Accrued interest                                                         2,161                 8,237
                                                                   ----------------      ----------------
Total current liabilities                                                   6,890                26,205
Notes payable to stockholders                                              71,086                    --
Long-term debt                                                                 --               400,000
                                                                   ----------------      ----------------
Total liabilities                                                          77,976               426,205
                                                                   ----------------      ----------------

Stockholders' Equity:
   Common stock, $.01 par value: 200,000,000 shares authorized;
     36,162,629 and 93,095,926 shares issued and outstanding,
     respectively                                                             362                   931
   Additional paid-in capital                                             393,416             1,230,467
   Deferred compensation                                                   (1,811)               (3,359)
   Notes receivable from officers                                            (671)               (5,916)
   Retained earnings                                                        4,120                32,659
                                                                   ----------------      ----------------
Total stockholders' equity                                                395,416             1,254,782
                                                                   ----------------      ----------------
Total liabilities and stockholders' equity                         $      473,392        $    1,680,987
                                                                   ================      ================

                                                       For the Period From               For the Year Ended
                                                         March 10, 1998
                                                       (Date of Inception)       December 31,      December 31,
                                                      to December 31, 1998           1999             2000
                                                      --------------------       ------------      ------------
Revenue..............................................      $      --           $      --         $       --
Expenses:
   General and administrative........................          2,150               4,441             12,513
   Depreciation and amortization.....................             --                 218                346
   Charge for buyout of operations
     and maintenance contracts with a
     related party...................................             --                  --             19,000
                                                            --------             --------          ---------
                                                               2,150               4,659             31,859
                                                            --------             -------           --------
Operating loss.......................................         (2,150)             (4,659)           (31,859)
Interest income......................................             12                 265              6,019
Interest expense.....................................           (136)             (2,933)           (35,633)
                                                            --------             --------          ---------
Loss before benefit for income taxes.................         (2,274)             (7,327)           (61,473)
Tax benefit..........................................         (1,006)             (2,905)           (24,301)
Equity in earnings from subsidiaries.................           (274)             10,084             65,711
                                                            --------             --------          ---------
Net (loss) income....................................      $  (1,542)          $   5,662         $   28,539
                                                           =========           =========         ==========

                                                              For the Period
                                                              From March 10,
                                                              1998 (Date of          For the Year Ended
                                                               Inception) to
                                                                December 31,    December 31,   December 31,
                                                                    1998           1999            2000
                                                               -------------    ------------   ------------
Cash flows from operating activities:
   Net (loss) income........................................   $   (1,542)      $    5,662      $   28,539
   Adjustments to reconcile net loss to net cash used in
     operating activities--
     Equity in earnings from subsidiaries...................          275          (10,084)        (65,711)
     Deferred income taxes..................................       (1,006)          (2,905)        (24,301)
     Depreciation and amortization..........................           --              218           1,428
     Deferred compensation..................................           --              106           1,303
     Change in notes receivable from officers................          --               --            (244)
     Change in assets and liabilities:
       Restricted cash......................................           --             (651)            651
       Due from affiliates..................................           --          (17,112)       (132,798)
       Prepaid expenses and other current assets............           (2)            (130)         (3,362)
       Accounts payable.....................................           --               --             742
       Accrued expenses.....................................          605            4,123          12,497
       Accrued interest.....................................           54            2,107           6,076
                                                                   ------          -------        --------
Net cash used in operating activities.......................       (1,616)         (18,666)       (175,180)
                                                                   ------          -------        --------
Cash flows from investing activities:
   Purchase of property and equipment.......................           --           (2,936)           (397)
   Investment made in subsidiaries..........................      (18,600)        (342,377)       (914,333)
                                                                  -------         --------        --------
Net cash used in investing activities.......................      (18,600)        (345,313)       (914,730)
                                                                  -------         --------        --------
Cash flows from financing activities:
   Capital contribution from stockholders...................       18,610          382,330         758,682
   Payments of deferred financing                                      --               --         (13,200)
     costs..................................................
   Distribution to stockholders.............................           --           (9,750)             --
   Proceeds from senior notes and credit facility...........           --               --         420,000
   Payments on credit facility..............................           --               --         (20,000)
   Proceeds from notes payable to stockholders..............        1,735          110,539              --
   Payments on notes payable to stockholders................           --          (41,188)             --
                                                                   ------          -------       ---------
Net cash provided by financing activities...................       20,345          441,931       1,145,482
                                                                   ------          -------       ---------
Change in cash and cash equivalents.........................          129           77,952          55,572
Cash and cash equivalents, beginning of period..............           --             129           78,081
                                                                   ------          -------       ---------
Cash and cash equivalents, end of period....................   $      129       $   78,081      $ $133,653
                                                               ==========       ==========      ==========
Supplemental disclosure of cash flow information:
   Cash paid for--
     Interest...............................................   $       83       $      826      $   28,475
                                                               ==========       ==========      ==========
     Income taxes...........................................   $       --       $       --      $       --
                                                               ==========       ==========      ==========
   Noncash disclosures -
     Notes receivable from officers.........................   $       --       $       --      $    5,001
                                                               ==========       ==========      ==========
     Conversion of notes payable to equity..................   $       --       $       --      $   71,086
                                                               ==========       ==========      ==========

                    The accompanying notes are an integral part of these condensed statements.

Year ending December 31,                            Operating
- ------------------------                          --------------
2001                                              $         204
2002                                                        212
2003                                                        220
2004                                                        227
2005                                                        116
Thereafter                                                   --
                                                  --------------
                                                  $         979
                                                  ==============