UNITED STATES SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

Commission File No. 0-20100

BELDEN & BLAKE CORPORATION

5200 Stoneham Road
North Canton, Ohio 44720
(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: (330) 499-1660

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

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

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

     Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

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

     As of February 28, 2005, Belden & Blake Corporation had outstanding 1,500 shares of common stock, without par value, which is its only class of stock. The common stock of Belden & Blake Corporation is not traded on any exchange and, therefore, its aggregate market value and the value of shares held by non-affiliates cannot be determined as of the last business day of the registrant’s most recently completed second fiscal quarter.

DOCUMENTS INCORPORATED BY REFERENCE:

          None.

Table of Contents

     References in this Annual report on Form 10-K to “Belden & Blake,” “the Company,” “we,” “ours,” “us” or like terms refer to Belden & Blake Corporation and its subsidiaries.

Forward-Looking Statements

     The information in this document includes forward-looking statements that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Statements preceded by, followed by or that otherwise include the statements “should,” “believe,” “expect,” “anticipate,” “intend,” “will,” “continue,” “estimate,” “plan,” “outlook,” “may,” “future,” “projection,” “likely,” “possible,” “would,” “could” and variations of these statements and similar expressions are forward-looking statements as are any other statements relating to developments, events, occurrences, results, efforts or impacts. These forward-looking statements are based on current expectations and projections about future events. Forward-looking statements, and the business prospects of Belden & Blake are subject to a number of risks and uncertainties which may cause our actual results in future periods to differ materially from the forward-looking statements contained herein. These risks and uncertainties include, but are not limited to, our access to capital, the market demand for and prices of oil and natural gas, our oil and gas production and costs of operation, results of our future drilling activities, the uncertainties of reserve estimates, general economic conditions, new legislation or regulatory changes, changes in accounting principles, policies or guidelines and environmental risks. These and other risks are described on page 40 under the Heading “Risk Factors” and in our other filings with the Securities and Exchange Commission (“SEC”). We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, changes in assumptions, or otherwise.

PART I

Items 1 and 2. BUSINESS AND PROPERTIES

GENERAL

     Belden & Blake Corporation, an Ohio corporation, was formed on June 14, 1991 and is wholly owned by Capital C Energy Operations, LP (“Capital C”), a Delaware limited partnership. Capital C acquired us pursuant to a merger completed on July 7, 2004. Capital C is a controlled affiliate of Carlyle/Riverstone Global Energy and Power Fund II, L.P. (“Carlyle/Riverstone”), a private equity fund. The general partner of Carlyle/Riverstone is jointly controlled by Riverstone Holdings LLC and The Carlyle Group.

     We are an independent energy company engaged in the exploitation, development, production, operation and acquisition of oil and natural gas properties. Our operations are focused in the Appalachian Basin in Ohio, Pennsylvania and New York and in the Antrim Shale formation in the Michigan Basin.

     We maintain our corporate offices at 5200 Stoneham Road, North Canton, Ohio 44720. Our telephone number at that location is (330) 499-1660.

SIGNIFICANT EVENTS

Mergers and Acquisitions

     Acquisition by Carlyle/Riverstone

     Pursuant to an Agreement and Plan of Merger with Capital C, dated as of June 15, 2004 (the “Merger Agreement”), a wholly owned subsidiary of Capital C merged with and into us (the “Merger”) and we were the surviving corporation. The Merger was completed on July 7, 2004.

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     Capital C is a Delaware limited partnership owned by an affiliate of Carlyle/Riverstone and by Capital C Energy Partners, L.P. Carlyle/Riverstone is a private equity fund established by Riverstone Holdings LLC and The Carlyle Group to make investments in the energy and power industries globally. Capital C Energy Partners, L.P. is a privately owned partnership formed in 2002 to accumulate and manage a portfolio of onshore U.S. oil and gas properties. Carlyle/Riverstone controls and owns the majority of Capital C.

     In the Merger, each issued and outstanding share of our common stock was converted into the right to receive cash. All outstanding amounts of indebtedness under our prior credit facility were repaid. In connection with the Merger, pursuant to a consent solicitation and tender offer previously announced by the Company, over 98% of our $225 million aggregate principal amount of 9-7/8% Senior Subordinated Notes (the 9-7/8% Notes) were tendered and repaid at the closing of the Merger. As of September 30, 2004, all of the $225 million aggregate principal amount of the 9-7/8% Notes had been paid.

     Merger with Subsidiaries

     Effective December 30, 2004, we merged with our wholly owned subsidiaries, The Canton Oil and Gas Company (“COG”) and Ward Lake Drilling, Inc. (“WLD”), and we were the surviving corporation. COG and WLD were the guarantor subsidiaries to our $192.5 million 8.75% Senior Secured Notes due 2012 described below.

Senior Secured Notes due 2012

     On July 7, 2004, we completed the sale of $192.5 million of our 8.75% Senior Secured Notes due 2012 (the “Notes”) in a private offering to qualified institutional buyers in reliance on Rule 144A of the Securities Act of 1933, as amended (the “Securities Act”) and to non-U.S. persons under Regulation S of the Securities Act. The net proceeds, along with proceeds from the Senior Facilities as defined below, were used principally to repay $225 million of our 9-7/8% Senior Subordinated Notes due 2007 (the “9-7/8% Notes”) and to repay indebtedness outstanding under our revolving credit facility. On December 23, 2004, we commenced an exchange offer which allowed the holders of the unregistered Notes to exchange the unregistered Notes for new notes with materially identical terms that had been registered under the Securities Act of 1933, as amended. The exchange offer expired on February 4, 2005, and all of the unregistered Notes were exchanged for registered Notes.

The Senior Facilities

     In connection with the Merger, we entered into a new Senior Credit Agreement providing for a $100 million term facility, a $30 million revolving facility (including letters of credit) and a $40 million letter of credit facility (collectively, the “Senior Facilities”). Indebtedness under the Senior Facilities constitutes our senior secured indebtedness and is secured by a first-priority lien on a substantial majority of the aggregate value of our estimated proved producing reserves on a present value (discounted at 10%) basis and substantially all of our other real and personal property, each on a first-priority senior secured

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     basis. The Notes constitute our senior secured indebtedness and are secured by a second-priority lien on the same assets.

The Hedges

     Also at the time of the Merger, we entered into long-term commodity hedges (the “Hedges”) with J. Aron under a master agreement and related confirmations and documentation (collectively, the “Hedge Agreement”) and, as required by the Senior Facilities and the indenture governing the Notes, we will maintain such Hedges with J. Aron or its successor or permitted assigns.

     The letter of credit facility provides up to $40 million of credit support for our obligations under the Hedge Agreement and other hedging transactions. Our obligations under the Hedge Agreement are also secured by up to $15 million of letters of credit under the revolving facility. To the extent our obligations exceed such letters of credit, such obligations under the Hedge Agreement and other hedging transactions will be secured by a second-priority lien on the same assets securing the Senior Facilities and the Notes.

Dispositions

     Sale of Arrow Oilfield Service Company

     We sold the Michigan assets of Arrow Oilfield Service Company (“Arrow”) in May 2004. We sold the Ohio and Pennsylvania assets of Arrow in June 2004. These transactions were classified as discontinued operations. Historical information has been restated to remove Arrow from continuing operations.

     Sale of Trenton Black River Assets

     On June 25, 2004, we completed the sale of substantially all of our interests, or rights to our interests, in the Trenton Black River (“TBR”) assets in accordance with a letter agreement dated June 14, 2004 with a third party. This transaction was classified as discontinued operations. Historical information has been restated to remove the TBR properties from continuing operations.

DESCRIPTION OF BUSINESS

Overview

     We are an independent energy company engaged in the exploitation, development, production, operation and acquisition of oil and natural gas properties. Our operations are focused in the Appalachian Basin in Ohio, Pennsylvania and New York and in the Antrim Shale formation in the Michigan Basin.

     In the fourth quarter of 2004, we achieved average net production from continuing operations of approximately 47.5 Mmcfe (million cubic feet of natural gas equivalent) per day consisting of 41.0 Mmcf (million cubic feet) of natural gas and 1,077 Bbls (barrels) of oil per day. At December 31, 2004, we owned interests in 4,126 gross (3,197 net) productive oil and gas wells in Ohio, Pennsylvania, New York and Michigan with estimated proved reserves totaling 285 Bcfe (billion cubic feet of natural gas equivalent) consisting of 251 Bcf (billion cubic feet) of natural gas and 5.6 Mmbbl (million barrels) of oil. The estimated future net cash flows from these reserves had a present value (discounted at 10%) before income taxes of approximately $510 million at December 31, 2004. The weighted average prices related to estimated proved reserves at December 31, 2004 were $6.49 per Mcf (thousand cubic feet) for natural gas and $40.12 per Bbl for oil.

     At December 31, 2004, we operated approximately 3,652 wells, or 89% of our gross wells representing approximately 98% of the value of our estimated proved developed reserves on a present value (discounted at 10%) basis. We believe that operational control of our properties, coupled with ownership of selected gathering assets, enables us to better control our operating costs and capital expenditures and execute our field development plans. At December 31, 2004, we owned leases on 712,267 gross (565,060 net) acres, including 272,697 gross (198,578 net) undeveloped acres.

     We own and operate approximately 1,268 miles of natural gas gathering lines in Ohio, Pennsylvania, New York and Michigan, which are connected directly to various intrastate and interstate natural gas transmission systems. The interconnections with these pipelines afford us marketing access to numerous gas markets, including those in the northeastern United States. The proximity of our properties in the Appalachian and Michigan Basins to large commercial and industrial natural gas markets has generally resulted in premium wellhead gas prices compared with the New York Mercantile Exchange (“NYMEX”) price for gas delivered at the Henry Hub in Louisiana. Monthly spot natural gas prices in our market areas are typically 15 to 60 cents higher per Mcf than comparable NYMEX prices.

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Oil and Gas Reserves

     The following table sets forth our estimated proved oil and gas reserves as of December 31, 2002, 2003 and 2004 determined in accordance with the rules and regulations of the SEC. These estimates of proved reserves were prepared by Wright & Company, Inc., independent petroleum consultants. Estimated proved reserves are the estimated quantities of oil and gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

     See Note 17 to the Consolidated Financial Statements for more detailed information regarding our oil and gas reserves.

     The present value of the estimated future net cash flows before income taxes from our estimated proved reserves as of December 31, 2004, determined in accordance with the rules and regulations of the SEC, was $510 million ($346 million after income taxes). Estimated future net cash flows represent estimated future gross revenues from the production and sale of estimated proved reserves, net of estimated costs (including production taxes, ad valorem taxes, operating costs, development costs and additional capital investment). Estimated future net cash flows were calculated on the basis of prices and costs estimated to be in effect at December 31, 2004 without escalation, except where changes in prices were fixed and readily determinable under existing contracts.

     The following table sets forth the weighted average prices, including fixed price contracts, for oil and gas used in determining our estimated proved reserves. We do not include our natural gas and crude oil hedging financial instruments, consisting of swaps and collars, in the determination of our oil and gas reserves.

     At December 31, 2004, as specified by the SEC, the prices for oil and natural gas used in this calculation were regional cash price quotes on the last day of the year except for volumes subject to fixed price contracts. Consequently, these may not reflect the prices actually received or expected to be received for oil and natural gas due to seasonal price fluctuations and other varying market conditions. The prices shown above are weighted average prices for the total reserves.

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     Our estimated proved reserves as of December 31, 2004 were approximately 285 Bcfe compared with estimated proved reserves from continuing operations as of December 31, 2003 of approximately 355 Bcfe. Estimated proved reserves as of December 31, 2004 decreased approximately 70 Bcfe from December 31, 2003, as presented in the table below.

     During 2004, the primary focus of our drilling program was on proved undeveloped locations. The result of this program converted approximately 16.3 Bcfe of estimated proved undeveloped reserves into estimated proved developed reserves. Production for 2004 was 17.6 Bcfe.

     Revisions of previous estimates accounted for a decrease of approximately 56.7 Bcfe. The majority of this reduction was in the estimated proved undeveloped reserves category. Of this decrease, approximately 21.2 Bcfe related to engineering revisions, which resulted from our analysis of our drilling results in the past several years as compared to reserve estimates of proved undeveloped well locations in our prior year’s reserve report. Additionally, as a result of higher future development and operating costs, total estimated proved reserves were reduced by approximately 17.5 Bcfe. Increases in our estimated proved reserves of 9.2 Bcfe resulted from increases in commodity prices at December 31, 2004 compared to 2003. Furthermore, approximately 19.7 Bcfe of estimated proved undeveloped reserves were reclassified to an unproved category, as the locations were more than one direct offset spacing unit from a productive well. During 2004, we performed a lease review of our proved undeveloped locations, which, due to leases that have expired or that we have surrendered, resulted in a downward adjustment of approximately 7.4 Bcfe to our estimated proved undeveloped reserves at December 31, 2004.

     Reserves estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Furthermore, different reserve engineers may make different estimates of reserves and cash flow based on the same available data and these differences may be significant. Therefore, these estimates are not precise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas

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reserves will most likely vary from those estimated. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

Appalachian Basin — Conventional Properties

     The Appalachian Basin is the oldest and geographically one of the largest oil and gas producing regions in the United States. Although the Appalachian Basin has sedimentary formations to depths of 15,000 feet or more, oil and natural gas has primarily been produced from shallow, highly developed formations at depths of 1,000 to 6,500 feet. Our drilling completion rates and those of others drilling in these shallow, highly developed formations historically have exceeded 90% with production generally lasting longer than 20 years.

     We currently own working interests in 2,782 gross (2,445 net) wells in the Appalachian Basin, excluding our coalbed methane wells, which currently produce approximately 23.1 Mmcfe net per day. Most of our production in the Appalachian Basin is derived from the shallow (1,000 to 6,500 feet) Medina, Clinton and Clarendon formations, predominately in Pennsylvania and Ohio.

     During 2004, we drilled 27 gross (26.4 net) development Medina wells, 15 gross (15.0 net) development Clarendon wells in Pennsylvania and 3 gross (3.0 net) Clinton wells in Ohio. We plan to continue this development drilling program by drilling 40 gross (38.8 net) Medina wells, 35 gross (35.0 net) Clarendon wells and 20 gross (20.0 net) Clinton wells in 2005.

Michigan Basin Properties

     The Michigan Basin has operational similarities to the Appalachian Basin, geographic proximity to our operations in the Appalachian Basin and proximity to premium gas markets. We own working interests in 1,184 gross (592 net) wells in the Michigan Basin which currently produce approximately 19.2 Mmcfe net per day.

     Most of our production in the Michigan Basin is derived from the shallow (700 to 2,000 feet), Antrim Shale formation. Completion rates for companies drilling to this formation have exceeded 90%, with production often lasting 20 years or more. Because the production rate from Antrim Shale wells is relatively low, cost containment is a crucial aspect of our operations. Our operations in the Michigan Basin are more capital intensive than our Appalachian Basin operations because of the low natural reservoir pressures and the high initial water content of the Antrim Shale formation.

     During 2004, we drilled 38 gross (30.7 net) wells to the Antrim Shale formation. We plan to drill 35 gross (33.2 net) wells in the Antrim Shale formation in 2005.

Appalachian Basin — Coalbed Methane Properties

     We own working interests in 160 producing coalbed methane (“CBM”) wells in Pennsylvania and own leases on approximately 69,000 gross (62,000 net) acres of undeveloped CBM properties. We own a 100% working interest in all of our CBM wells. Current production from these wells is approximately 2.9 Mmcf net per day. We drilled 18 CBM wells in 2004 and plan to drill an additional 15 CBM wells in 2005.

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Oil and Gas Operations and Production

     Operations. We operate 89% of the wells in which we hold working interests. We maintain production field offices in Ohio, Pennsylvania and Michigan. Through these offices, we review our properties to determine what action can be taken to control operating costs and/or improve production.

     We own and operate approximately 1,268 miles of natural gas gathering lines in Ohio, Pennsylvania, New York and Michigan, which are connected directly to various intrastate and interstate natural gas transmission systems. The interconnections with these pipelines afford us marketing access to numerous gas markets.

     Production, Sales Prices and Costs. The following table sets forth certain information regarding our net oil and natural gas production, revenues and unit expenses for the years indicated, excluding discontinued operations. However, it does not exclude all dispositions of properties that did not qualify as discontinued operations. See Note 5 to the Consolidated Financial Statements.

Exploration and Development

     Our activities include development and exploratory drilling in both the low risk formations and the less developed formations of the Appalachian and Michigan Basins.

     In 2004, we drilled 106 gross (96.9 net) wells to shallow, highly developed formations in our operating area. The result of this drilling activity is shown in the table on page 9.

     In 2005, we expect to spend approximately $36 million, including exploratory dry hole expense, on development and exploratory drilling and other capital expenditures. We expect to drill approximately 145 gross (142.0 net) wells. In 2005, we plan to spend substantially all of our drilling capital expenditures on shallow, highly developed formations.

     We were a pioneer in CBM development and production in Pennsylvania, and we presently own a 100% working interest in 160 CBM gas wells in Indiana, Westmoreland and Fayette counties. CBM

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wells in this area range in depth from 1,200 to 1,500 feet and typically encounter three to six unmined coal seams. With approximately 77,000 gross (69,000 net) CBM acres currently under lease in Pennsylvania, we believe the CBM may contribute significantly to our drilling portfolio. We plan to drill 15 gross (15.0 net) CBM wells in 2005.

     The Antrim Shale formation, the principal shallow formation in the Michigan Basin, is characterized by high formation water production in the early years of a well’s productive life with water production decreasing over time. Antrim Shale wells produce natural gas that typically climbs to peak rates of 60 Mcf to 125 Mcf per day over a three to 12 month period as the producing formation becomes less water saturated. Production generally holds flat for several months, followed by initial annual decline rates of 10% to 25% that decrease over time to 5% or less. Average well lives are 20 years or more. We plan to drill 35 gross (33.2 net) wells to the Antrim Shale formation in 2005.

     In addition to our CBM and Antrim drilling, we also plan to drill 40 gross (38.8 net) wells to the Medina formation, 35 gross (35.0 net) wells to the Clarendon formation in Pennsylvania and 20 gross (20.0 net) wells to the Clinton formation in Ohio during 2005.

     Certain typical characteristics of our drilling programs in the shallow, highly developed formations we target are described below:

     The Appalachian Basin has productive and potentially productive sedimentary formations to depths of 15,000 feet or more, but the combination of long-lived production and high drilling completion rates in the shallow formations has curbed the development of the deeper formations in the basin.

     We have also tested the Niagaran Carbonate, Onondaga Limestone, Oriskany Sandstone and Knox formations. In the future, we may allocate a portion of our drilling budget to drill wells in these and other deeper or less developed formations.

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     Drilling Results. The following table sets forth drilling results from continuing operations with respect to wells drilled by us during the past three years:

Disposition of Assets

     We sold the Michigan assets of Arrow in May 2004. We sold the Ohio and Pennsylvania assets of Arrow in June 2004. According to Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards No. (SFAS) 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the disposition of Arrow was classified as discontinued operations. Historical information has been restated to remove Arrow from continuing operations.

     On June 25, 2004, we completed the sale of substantially all of our interests, or rights to our interests, in the TBR assets in accordance with a letter agreement dated June 14, 2004 with a third party. According to SFAS 144, the disposition of this group of wells is classified as discontinued operations. Historical information has been restated to remove the TBR properties from continuing operations.

     We regularly review our oil and gas properties for potential disposition.

Employees

     As of February 28, 2005, we had 180 full-time employees, including 153 oil and gas exploration and production employees and 27 general and administrative employees. Our management and technical staff in the categories above included six petroleum engineers, one geologist and one geophysicist.

Competition

     The oil and gas industry is highly competitive. Competition is particularly intense with respect to the acquisition of producing properties and undeveloped acreage and the sale of oil and gas production. There is competition among oil and gas producers as well as with other industries in supplying energy and fuel to end-users.

     Our competitors in oil and gas exploration, development and production include major integrated oil and gas companies as well as numerous independent oil and gas companies, individual proprietors, natural gas pipeline companies and their affiliates. Many of these competitors possess and employ financial and personnel resources substantially in excess of those available to us. Such competitors may be able to pay more for desirable prospects or producing properties and to evaluate, bid for and purchase a

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greater number of properties or prospects than our financial or personnel resources will permit. Our ability to add to our reserves in the future will depend on the availability of capital, the ability to exploit our current developed and undeveloped lease holdings and the ability to select and acquire suitable producing properties and prospects for future exploration and development.

Customers

     Each of the following customers accounted for 10% or more of our consolidated revenues during 2004: WPS Energy Services, National Fuel Gas and Exelon Energy.

Regulation

     Regulation of Production. In all states in which we are engaged in oil and gas exploration and production, our activities are subject to regulation. Such regulations may extend to requiring drilling permits, spacing of wells, the prevention of waste and pollution, the conservation of oil and natural gas and other matters. Such regulations may impose restrictions on the production of oil and natural gas by limiting the number of wells or the location where wells may be drilled and by reducing the rate of flow from individual wells below their actual capacity to produce, which could adversely affect the amount or timing of our revenues from such wells. Moreover, future changes in local, state or federal laws and regulations could adversely affect our operations and financial condition.

     Federal Regulation of Sales and Transportation of Natural Gas. Historically, the transportation and sale for resale of natural gas in interstate commerce has been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and Federal Energy Regulatory Commission (“FERC”) regulations. In the past, the federal government has regulated the prices at which natural gas could be sold. Currently, sales by producers of natural gas can be made at uncontrolled market prices. Congress could, however, reenact price controls in the future.

     Our sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation are subject to extensive federal and state regulation. From 1985 to the present, several major regulatory changes have been implemented by Congress and the FERC that affect the economics of natural gas production, transportation and sales. In addition, the FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, that remain subject to the FERC’s jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation.

     The ultimate impact of the complex rules and regulations issued by the FERC since 1985 cannot be predicted. In addition, many aspects of these regulatory developments have not become final but are still pending judicial and FERC final decisions. We cannot predict what further action the FERC will take on these matters. We do not believe, however, that we will be affected by any action taken in a materially different way than other natural gas producers, gatherers and marketers with which we compete.

     Federal Regulation of Sales and Transportation of Crude Oil. Our sales of crude oil and condensate are not currently regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. Certain regulations

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implemented by the FERC in recent years could result in an increase in the cost of pipeline transportation service. We do not believe, however, that these regulations affect us any differently than other producers.

     Environmental Regulations. Our oil and natural gas exploration, development, production and pipeline operations are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency, also referred to as the “U.S. EPA,” issue regulations to implement and enforce such laws, which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties or may result in injunctive relief if we fail to comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require bonds to be posted for the anticipated costs of plugging and abandoning wells, and can require remedial action to prevent pollution from former operations, such as plugging abandoned wells or closing pits, and impose substantial liabilities for pollution resulting from our operations.

     The regulatory burden on the oil and natural gas industry increases the cost of doing business and consequently may affect our profitability. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly regulation could materially adversely affect our operations and financial position, as well as those of the oil and gas industry in general. While we have not yet experienced any material adverse effect from compliance or non-compliance with these environmental requirements, there is no assurance that this trend will continue in the future.

     The Comprehensive Environmental Response, Compensation and Liability Act, as amended, also known as “CERCLA” or “Superfund,” and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons for the release of a hazardous substance into the environment. These persons include the owner and/or operator of a disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up these hazardous substances for damages to natural resources and for the costs of certain health studies.

     The Resource Conservation and Recovery Act, as amended, also known as “RCRA,” specifically excludes from the definition of hazardous waste “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy.” However, these wastes that we may generate may be regulated by the EPA or state agencies as solid waste. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils, may be regulated as hazardous waste. Although the costs of managing these wastes generated by us may be significant, we do not expect to experience more burdensome costs than similarly situated companies involved in oil and gas exploration and production.

     We currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the exploration and production of oil and gas. Hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon may be subject

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to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes or property contamination, or to perform remedial plugging or pit closure operations to prevent future contamination.

     The federal Clean Air Act and analogous state laws restricts the emission of air pollutants from many sources, including equipment we use such as compressors to transport natural gas in our pipelines. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur costs in order to remain in compliance.

     Our operations involve discharges to surface waters of fluids associated with the production of oil and gas. The federal Clean Water Act and analogous state laws impose restrictions and strict controls regarding the discharge of these fluids from oil and gas operations into state waters or waters of the United States prohibiting discharge, except in accord with the terms of a permit issued by U.S. EPA or the state. We hold several permits for the discharge of ground water that is produced in conjunction with our coalbed methane operations in Pennsylvania. These operations can produce substantial amounts of water as a byproduct when extracting gas. Our facilities in Michigan use injection wells to dispose of wastewater that is produced as a byproduct of oil and gas production. These injection wells are subject to stringent regulation and permitting requirements. At our oil and gas wells in Ohio and Pennsylvania, wastewater is collected in aboveground tanks and collected by third-party contractors for disposal off-site. The Clean Water Act also prohibits certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers. The U.S. EPA also has adopted regulations requiring certain oil and gas exploration and production facilities to obtain permits for storm water discharges under certain circumstances. Sanctions for failure to comply with Clean Water Act requirements include administrative, civil and criminal penalties, as well as injunctive relief.

     The Oil Pollution Act of 1990, as amended, also known as the “OPA,” pertains to the prevention of and response to spills or discharges of hazardous substances or oil into navigable water of the United States. The OPA imposes strict, joint and several liability on responsible parties for oil removal costs and a variety of public and private damages, including natural resource damages. Regulations under the OPA and the Clean Water Act also require certain owners and operators of facilities that store or otherwise handle oil, such as ours, to prepare and implement spill prevention, control, and countermeasure, or “SPCC,” plans and spill response plans relating to possible discharges of oil into surface waters. The SPCC regulations were amended in 2002 and some plans may require revision by February 17, 2006 and implementation of any such revised plans by August 18, 2006. We own and/or operate a substantial number of facilities that require SPCC plans or comparable plans under state law, and we are currently evaluating the extent of compliance by our facilities with SPCC regulations and comparable state requirements. We cannot assure you that costs that may be necessary for compliance with these SPCC and comparable state requirements will not be material.

Producing Well Data

     As of December 31, 2004, we owned interests in 4,126 gross (3,197 net) producing oil and gas wells and operated approximately 3,652 wells, including wells operated for third parties. By operating a high percentage of our properties, we are able to control expenses, capital allocation and the timing of development activities in the areas in which we operate. In the fourth quarter of 2004, our net production was approximately 47.5 Mmcfe per day consisting of 41.0 Mmcf of natural gas and 1,077 Bbls of oil per day.

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     The following table summarizes by state our productive wells at December 31, 2004:

Acreage Data

     The following table summarizes by state our gross and net developed and undeveloped acreage at December 31, 2004:

     Developed acreage includes 235,104 gross (208,753 net) acres of undrilled acreage held by production.

Item 3. LEGAL PROCEEDINGS

     In February 2000, four individuals filed a suit in Chautauqua County, New York on their own behalf and on the behalf of others similarly situated, seeking damages for the alleged difference between the amount of lease royalties actually paid and the amount of royalties that allegedly should have been paid. Other natural gas producers in New York were served with similar complaints. We believe the complaint is without merit and are defending the complaint vigorously. Although the outcome is still uncertain, we believe the action will not have a material adverse effect on our financial position, results of operations or cash flows. We no longer own the wells that are subject to the suit.

     In April 2002, we were notified of a claim by an overriding royalty interest owner in Michigan alleging the underpayment of royalty resulting from disputes as to the interpretation of the terms of several farmout agreements. On July 6, 2004, a suit was filed in Otsego County, Michigan by affiliates of Merit Energy Company, the successor in interest to these royalty interests, alleging substantially the same underpayments. We believe there will be no material amount payable above and beyond the amount accrued as of December 31, 2004

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and therefore, the result will have no material adverse effect on our financial position, results of operation or cash flows.

     We were audited by the state of West Virginia for the years 1996 through 1998. The state assessed taxes which we contested and filed a petition for reassessment. In February 2003, we were notified by the State Tax Commissioner of West Virginia that our petition for reassessment had been denied and taxes due, plus accrued interest, are now payable. We disagreed with the decision, appealed, and received a favorable ruling. The state did not appeal the Circuit Court decision. We received a $324,000 refund of our appeal bond and expect to receive a refund of overpaid severance taxes of approximately $100,000 plus interest.

     We are involved in several lawsuits arising in the ordinary course of business. We believe that the result of such proceedings, individually or in the aggregate, will not have a material adverse effect on our financial position, results of operations or cash flows.

     Environmental costs, if any, are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed as incurred. Expenditures that extend the life of the related property or reduce or prevent future environmental contamination are capitalized. Liabilities related to environmental matters are only recorded when an environmental assessment and/or remediation obligation is probable and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash payments for the liability are fixed or reliably determinable. At December 31, 2004, no significant environmental remediation obligation exists which is expected to have a material effect on our financial position, results of operations or cash flows.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     On November 1, 2004, Capital C, our sole shareholder, approved by written consent in lieu of a meeting, a resolution naming Michael Becci and James A. Winne III to our Board of Directors and increasing our Board’s membership from six to eight. The terms of our other directors on such date, Gregory A. Beard, Michael B. Hoffman, Pierre F. Lapeyre Jr., and David M. Leuschen, continued after such date.

     On November 29, 2004, Capital C approved by written consent in lieu of a meeting, a resolution adopting Amended and Restated Regulations of the Corporation.

     On December 16, 2004, Capital C approved by written consent in lieu of a meeting, a resolution decreasing our Board’s membership from eight to six.

     On February 14, 2005, Capital C approved by written consent in lieu of a meeting, a resolution increasing our Board’s membership from six to seven.

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PART II

Item 5.	MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

     There is no established public trading market for our equity securities.

     All of our equity securities at February 28, 2005, were held by Capital C.

Dividends

     No dividends have been paid on our Common Stock. We currently have no intention to pay any dividends on our Common Stock.

Equity Compensation Plan Information:

     As of February 28, 2005, we do not have an equity compensation plan.

Item 6. SELECTED FINANCIAL DATA

     The Selected Financial Data should be read in conjunction with the Consolidated Financial Statements at Item 15(a).

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Item 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

     We are an Ohio corporation wholly owned by Capital C Energy Operations, LP, a Delaware limited partnership (“Capital C”). Capital C acquired us pursuant to a merger completed on July 7, 2004 (the “Merger”). Capital C is a controlled affiliate of Carlyle/Riverstone Global Energy and Power Fund II, L.P., a private equity fund (“Carlyle/Riverstone”). The general partner of Carlyle/Riverstone is jointly controlled by Riverstone Holdings LLC and The Carlyle Group.

     We are an independent energy company engaged in the exploitation, development, production, operation and acquisition of oil and natural gas properties. Our operations are focused in the Appalachian Basin in Ohio, Pennsylvania and New York and in the Antrim Shale formation in the Michigan Basin.

     At December 31, 2004, our total estimated proved reserves related to continuing operations were 285 Bcfe. Natural gas comprised approximately 88% of our estimated proved reserves, and 78% of our estimated proved reserves were classified as proved developed. Substantially all of our reserves are located in shallow, highly developed formations with long-lived, stable production profiles. At December 31, 2004 our conventional Appalachian properties accounted for 52% of our estimated proved reserves, while the Michigan properties and our Appalachian coalbed methane properties (“CBM”) accounted for 42% and 6%, respectively.

     In connection with the acquisition by Capital C, our existing indebtedness was refinanced. The principal elements of the refinancing including entering into the Senior Credit Agreement, providing for a $100 million term facility, a $30 million revolving facility and a $40 million letter of credit facility (collectively, the “Senior Facilities”), and our issuance of $192.5 million of 8.75% Senior Secured Notes due 2012 (the “Notes”).

     During the periods discussed, we earned revenue through the production and sale of oil and natural gas and, to a lesser extent, from gas gathering and marketing. In 2004, we sold the assets of Arrow Oilfield Services (”Arrow”) and substantially all of our interests, or rights to our interests, in our Trenton Black River (“TBR”) operations. Both of these transactions were classified as discontinued operations. Historical information has been restated to remove the TBR properties and Arrow from continuing operations.

     Our financial results and cash flows can be significantly impacted as commodity prices fluctuate in response to changing market conditions. We use derivative instruments on a significant portion of our oil and natural gas production to reduce the volatility of oil and natural gas prices and to protect cash flow available for our development drilling program. In connection with the acquisition by Capital C, at the effective time of the Merger, we became a party to a long-term hedging program (the “Hedges”) with J. Aron under a master agreement and related confirmations and documentation (collectively, the “Hedge Agreement”) required by the Senior Facilities and the indenture governing the Notes, we will maintain such Hedges with J. Aron or its successor permitted assigns. We anticipate that the Hedges will cover approximately 69% of the expected production through 2013 from our current estimated proved reserves and will range from 65% to 80% of such expected production in any year.

     The average price realized for our natural gas increased $0.16 per Mcf to $5.08 per Mcf in 2004 compared to $4.92 per Mcf in 2003. The average price realized for our natural gas decreased from $4.95 per Mcf in 2002 to $4.92 per Mcf in 2003. The monthly average settle for natural gas trading on the New York Mercantile Exchange (“NYMEX”) increased from $3.22 per Mmbtu in 2002 to $5.39 per Mmbtu in 2003 and to $6.14 per Mmbtu in 2004. Our selling price of natural gas is generally higher than the

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NYMEX price due to the favorable regional basis received throughout our areas of operations along with a favorable Btu (“British thermal unit”) content of our gas. The remainder of the difference is due to fixed price contracts and our hedging activities during these periods. Our average realized price for oil increased from $22.72 per Bbl in 2002 to $28.06 per Bbl in 2003 and $34.42 per Bbl in 2004.

CRITICAL ACCOUNTING POLICIES

     We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States (“GAAP”) and SEC guidance. See the “Notes to Consolidated Financial Statements” included in “Item 8. Financial Statements and Supplementary Data” for a more comprehensive discussion of our significant accounting policies. GAAP requires information in financial statements about the accounting principles and methods used and the risks and uncertainties inherent in significant estimates including choices between acceptable methods. Following is a discussion of our most critical accounting policies:

Successful Efforts Method of Accounting

     The accounting for and disclosure of oil and gas producing activities requires our management to choose between GAAP alternatives and to make judgments about estimates of future uncertainties.

     We use the “successful efforts” method of accounting for oil and gas producing activities as opposed to the alternate acceptable “full cost” method. Under the successful efforts method, property acquisition and development costs and certain productive exploration costs are capitalized while non-productive exploration costs, which include certain geological and geophysical costs, exploratory dry hole costs and costs of carrying and retaining undeveloped properties, are expensed as incurred. The geological and geophysical costs include costs for salaries and benefits of our personnel in those areas and other third party costs. The costs of carrying and retaining undeveloped properties include salaries and benefits of our land department personnel, delay rental payments made on new and existing leases, ad valorem taxes on existing leases and the cost of previously capitalized leases that are written off because the leases were dropped or expired. Exploratory dry hole costs include the costs associated with drilling an exploratory well that has been determined to be a dry hole.

     The major difference between the successful efforts method of accounting and the full cost method is under the full cost method of accounting, such exploration costs and expenses are capitalized as assets, pooled with the costs of successful wells and charged against the net income (loss) of future periods as a component of depletion expense.

Oil and Gas Reserves

     Our estimated proved developed and estimated proved undeveloped reserves are all located within the Appalachian and Michigan Basins in the United States. There are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. In addition, estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are expected to change as future information becomes available. Material revisions of reserve estimates may occur in the future, development and production of the oil and gas reserves may not occur in the periods assumed and actual prices realized and actual costs incurred may vary significantly from assumptions used. Estimated proved reserves represent estimated quantities of natural gas and oil that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. Estimated proved developed reserves are estimated proved reserves expected to be recovered through wells and equipment

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in place and under operating methods being used at the time the estimates were made. The accuracy of a reserve estimate is a function of:

	--	the quality and quantity of available data;
	--	the interpretation of that data;
	--	the accuracy of various mandated economic assumptions; and
	--	the judgment of the persons preparing the estimate.

     Our estimated proved reserve information for the 2004 predecessor company period ended July 1, 2004, is based on our internal engineering estimates. Our estimated proved reserve information for all other periods included in this Annual Report is based on estimates prepared by independent petroleum consultants. Estimates prepared by others may be higher or lower than these estimates.

Capitalization, Depreciation, Depletion and Impairment of Long-Lived Assets

     See the “Successful Efforts Method of Accounting” discussion above. Capitalized costs related to estimated proved properties are depleted using the unit-of-production method. Depreciation, depletion and amortization of proved oil and gas properties are calculated on the basis of estimated recoverable reserve quantities. These estimates can change based on economic or other factors. No gains or losses are recognized upon the disposition of oil and gas properties except in extraordinary transactions. Sales proceeds are credited to the carrying value of the properties. Maintenance and repairs are expensed, and expenditures which enhance the value of properties are capitalized.

     Unproved oil and gas properties are stated at cost and consist of undeveloped leases. These costs are assessed periodically to determine whether their value has been impaired, and if impairment is indicated, the costs are charged to expense.

     Gas gathering systems are stated at cost. Depreciation expense is computed using the straight-line method over 15 years.

     Property and equipment are stated at cost. Depreciation of non-oil and gas properties is computed using the straight-line method over the useful lives of the assets ranging from 3 to 15 years for machinery and equipment and 30 to 40 years for buildings. When assets other than oil and gas properties are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is reflected in income for the period. The cost of maintenance and repairs is expensed as incurred, and significant renewals and betterments are capitalized.

     Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the sum of the expected future undiscounted cash flows is less than the carrying amount of the asset, a loss is recognized for the difference between the fair value and the carrying amount of the asset. Fair value is determined based on management’s outlook of future oil and natural gas prices and estimated future cash flows to be generated by the assets, discounted at a market rate of interest. Impairment of unproved properties is based on the estimated fair value of the property.

Derivatives and Hedging

     Our financial results and cash flows can be significantly impacted as commodity prices fluctuate widely in response to changing market conditions. Under the provisions of SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, we recognize all derivative financial instruments as either assets or liabilities at fair value. The changes in fair value of derivative instruments

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not qualifying for designation as cash flow hedges that occur prior to maturity are initially reported in expense in the consolidated statements of operations as derivative fair value (gain) loss. All amounts recorded in this line item are ultimately reversed within the same line item and included in oil and gas sales revenues over the respective contract terms. Changes in the fair value of derivative instruments that are fair value hedges are offset against changes in the fair value of the hedged assets, liabilities, or firm commitments, through net income (loss). Changes in the fair value of derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time as the hedged items are recognized in net income (loss).

     The relationship between the hedging instruments and hedged item must be highly effective in achieving the offset of changes in fair values or cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. We measure effectiveness at least on a quarterly basis. Ongoing assessments of hedge effectiveness will include verifying and documenting that the critical terms of the hedge and forecasted transaction do not change. Ineffective portions of a derivative instrument’s change in fair value are immediately recognized in net income (loss). If there is a discontinuance of a cash flow hedge because it is probable that the original forecasted transaction will not occur, deferred gains or losses are recognized in earnings immediately.

     From time to time we may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage our exposure to natural gas or oil price volatility and support our capital expenditure plans. Our derivative financial instruments primarily take the form of swaps or collars. At December 31, 2004, our derivative contracts were comprised of natural gas swaps and collars and crude oil swaps, which were placed with a major financial institution that we believe is a minimal credit risk. Qualifying derivative financial instruments are designated as cash flow hedges.

     We consider our natural gas swaps to be highly effective and expect there will be no ineffectiveness to be recognized in net income (loss) since the critical terms of the hedging instruments and the hedged forecasted transactions are the same. We have not experienced ineffectiveness on our natural gas swaps because we use NYMEX-based commodity derivative contracts to hedge on the same basis as our natural gas production is sold (NYMEX-based sales contracts). We have collar agreements that could not be redesignated as cash flow hedges because these collars were not effective due to unrealized losses at the date of the Merger. These collars qualified and were designated as cash flow hedges from their inception through the predecessor company period ended July 1, 2004. Although these collars are not deemed to be effective hedges in accordance with the provisions of SFAS 133, we have retained these instruments as protection against changes in commodity prices and we will continue to record the mark-to-market adjustments on these natural gas collars, through 2005, in our income statement. Our NYMEX crude oil swaps are highly effective and were designated as cash flow hedges. We have ineffectiveness on the crude oil swaps because the oil is sold locally at a posted price which is different from the NYMEX price. Historically, there has been a high correlation between the posted price and NYMEX. The changes in the fair values of the natural gas collars and the ineffective portion of the crude oil swaps are recorded as “Derivative fair value gain or loss.”

Revenue Recognition

     Oil and gas production revenue is recognized as production and delivery take place. Oil and gas marketing revenues are recognized when title passes.

Asset Retirement Obligations

     On January 1, 2003, we adopted SFAS 143, “Accounting for Asset Retirement Obligations.” SFAS 143 amends SFAS 19, “Financial Accounting and Reporting by Oil and Gas Producing

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Companies” which requires us to recognize a liability for the fair value of our asset retirement obligations associated with its tangible, long-lived assets. The majority of our asset retirement obligations recorded relate to the plugging and abandonment (excluding salvage value) of our oil and gas properties. The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect adjustment to record a $4.0 million increase in long-term asset retirement obligation liabilities, a $621,000 increase in current asset retirement obligation liabilities, a $3.2 million increase in the carrying value of oil and gas assets, a $5.2 million decrease in accumulated depreciation, depletion and amortization and a $1.4 million increase in deferred income tax liabilities. The net effect of adoption was to record a gain of $2.4 million, net of tax, as a cumulative effect of a change in accounting principle in our consolidated statement of operations in the first quarter of 2003.

     Subsequent to the adoption of SFAS 143, there has been no significant current period activity with respect to additional retirement obligations, settled obligations, accretion expense and revisions of estimated cash flows. The asset retirement obligations increased as a result of purchase accounting for the Merger, primarily due to a lower discount rate and revised estimates of asset lives on certain oil and gas wells. The unaudited pro forma income from continuing operations for the year ended December 31, 2002 was $4.3 million and has been prepared to give effect to the adoption of SFAS 143 as if it had been adopted on January 1, 2002. Assuming retroactive application of the change in accounting principle as of January 1, 2002, liabilities would have increased approximately $6 million.

     At December 31, 2004, there were no assets legally restricted for purposes of settling asset retirement obligations. A reconciliation of our liability for asset retirement obligations for the year ended December 31, 2004 and 2003 is as follows (in thousands):

New Accounting Pronouncements

     In January 2003, the FASB issued FIN 46, “Consolidation of Variable Interest Entities — An Interpretation of Accounting Research Bulletin (ARB) 51.” FIN 46, as amended by FIN 46(R); in December 2003, is an interpretation of ARB 51, “Consolidated Financial Statements,” and addresses consolidation by business enterprises of variable interest entities (VIEs). The primary objective of FIN 46 is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. FIN 46 requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity’s expected losses if they occur, receive a majority of the entity’s expected residual returns if they occur, or both. An enterprise shall consider the rights and obligations conveyed by its variable interests in

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making this determination. This guidance applied immediately to VIEs created after January 31, 2003, and to VIEs in which an enterprise obtains an interest after that date. It applies in the first fiscal year or interim period beginning after December 15, 2003, to VIEs in which an enterprise holds a variable interest that it acquired before February 1, 2003. The adoption of FIN 46 and FIN 46(R) did not have any effect on our financial statement disclosures, financial position, results of operations or cash flows.

     In April 2003, the FASB issued SFAS 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS 149 is intended to result in more consistent reporting of contracts as either freestanding derivative instruments subject to SFAS 133 in its entirety, or as hybrid instruments with debt host contracts and embedded derivative features. SFAS 149 is effective for our financial statements for the interim period beginning July 1, 2003. The adoption of SFAS 149 did not have a material effect on our financial position, results of operations or cash flows.

     In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment.” SFAS 123(R) revises SFAS 123, “Accounting for Stock-Based Compensation,” and focuses on accounting for share-based payments for services by employer to employee. SFAS 123(R) requires companies to expense the fair value of employee stock options and other equity-based compensation at the grant date. SFAS 123(R) does not require a certain type of valuation model and either a binomial or Black-Scholes model may be used. The provisions of SFAS 123(R) are effective for financial statements for fiscal periods ending after June 15, 2005. We did not have stock-based compensation arrangements outstanding at December 31, 2004. The impact of adoption will depend on future issuance of stock-based compensation arrangements. Our future cash flows will not be impacted by the adoption of SFAS 123(R). See Note 2 to the Consolidated Financial Statements in Item 8 of this Annual Report for the accounting policy description for “Stock Based Compensation” for further information.

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Estimated Proved Reserves Evaluation

     Our estimated proved reserves as of December 31, 2004 were approximately 285 Bcfe compared with estimated proved reserves from continuing operations as of December 31, 2003 of approximately 355 Bcfe. Wright & Company, Inc. (“Wright”), independent petroleum consultants, prepared reports of our estimated proved reserves as of December 31, 2004 and 2003. Estimated proved reserves as of December 31, 2004 decreased approximately 70 Bcfe from December 31, 2003, as presented in the table below.

     During 2004, the primary focus of our drilling program was on proved undeveloped locations. The result of this program converted approximately 16.3 Bcfe of estimated proved undeveloped reserves into estimated proved developed reserves. Production for 2004 was 17.6 Bcfe.

     Revisions of previous estimates accounted for a decrease of approximately 56.7 Bcfe. The majority of this reduction was in the estimated proved undeveloped reserves category. Of this decrease, approximately 21.2 Bcfe related to engineering revisions which resulted from our analysis of our drilling results in the past several years as compared to reserve estimates of proved undeveloped well locations in our prior year’s reserve report. Additionally, as a result of higher future development and operating costs, total estimated proved reserves were reduced by approximately 17.5 Bcfe. Increases in our estimated proved reserves of 9.2 Bcfe resulted from increases in commodity prices at December 31, 2004 compared to 2003. Furthermore, approximately 19.7 Bcfe of estimated proved undeveloped reserves were reclassified to an unproved category, as the locations were more than one direct offset spacing unit from a productive well. During 2004, we performed a lease review of our proved undeveloped locations, which, due to leases that have expired or that we have surrendered, resulted in a downward adjustment of approximately 7.4 Bcfe to our estimated proved undeveloped reserves at December 31, 2004.

     Reserves estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating reserves is complex. This process requires

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significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Furthermore, different reserve engineers may make different estimates of reserves and cash flow based on the same available data and these differences may be significant. Therefore, these estimates are not precise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

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Results of Operations

     As a result of the Merger, the results of operations for the periods subsequent to July 1, 2004 are not necessarily comparable to those prior to July 1, 2004. The following table combines the predecessor company 183 day period ended July 1, 2004 with the successor company 183 day period ended December 31, 2004 for purposes of the discussion of year-end results. The following table sets forth financial data for the periods indicated. Dollars are stated in thousands and percentages are stated as a percentage of total revenues.

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     The following Management’s Discussion and Analysis is based on the results of operations from continuing operations, unless otherwise noted. Accordingly, the discontinued operations have been excluded. See Note 5 to the Consolidated Financial Statements.

Production, Sales Prices and Costs

     The following table sets forth certain information regarding our net oil and natural gas production, revenues and expenses for the years indicated. This table includes continuing operations only.

2004 Compared to 2003

Revenues

     Net operating revenues increased from $95.1 million in 2003 to $100.6 million in 2004. The increase was due to higher gas sales revenues of $4.5 million and higher oil sales revenues of $1.5 million partially offset by lower gas gathering and marketing revenues of $558,000.

     Gas volumes sold increased 433 Mmcf (3%) from 14.8 Bcf in 2003 to 15.3 Bcf in 2004 resulting in an increase in gas sales revenues of approximately $2.1 million. Oil volumes sold decreased approximately 32,000 Bbls (8%) from 413,000 Bbls in 2003 to 381,000 Bbls in 2004 resulting in a decrease in oil sales revenues of approximately $890,000. The gas sales volume increase was primarily due to the production from wells drilled in 2003 and 2004 and increased production as a result of additional expenditures to stimulate production on declining wells partially offset by normal production declines. The lower oil sales volumes are due to normal production declines. Our drilling program primarily targets natural gas reserves.

     The average price realized for our natural gas increased $0.16 per Mcf to $5.08 per Mcf in 2004 compared to 2003, which increased gas sales revenues by approximately $2.4 million. As a result of our hedging activities, gas sales revenues were decreased by $20.8 million ($1.36 per Mcf) in 2004 and decreased by $10.3 million ($.69 per Mcf) in 2003. The average price realized for our oil increased from

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$28.06 per Bbl in 2003 to $34.42 per Bbl in 2004, which increased oil sales revenues by approximately $2.4 million. As a result of our hedging activities, oil sales revenues were decreased by approximately $1.5 million ($3.96 per Bbl) in 2004.

     The operating margin from oil and gas sales on a per unit basis increased from $3.59 per Mcfe in 2003 to $3.71 per Mcfe in 2004. The average price increased $0.27 per Mcfe which was partially offset by an increase in production expense of $0.13 per Mcfe in 2004 compared to 2003. Approximately $0.06 per Mcfe of the increase in production expense was due to recording the cost of selling purchased oil inventory as a result of purchase accounting for the Merger.

     The decrease in gas gathering and marketing revenues was due to a $948,000 decrease in gas marketing revenues partially offset by a $390,000 increase in gas gathering revenues. The lower marketing revenues were primarily the result of decreased gas volumes from third party wells. The increase in gas gathering revenues was primarily due to higher margins on a gathering system in Pennsylvania.

Costs and Expenses

     Production expense increased $2.6 million (13%) from $20.0 million in 2003 to $22.6 million in 2004 primarily due to an increase in labor resulting from continued well development activities, an increased focus on production and compressor optimization, a general increase in fuel and power costs and $462,000 of additional non-cash stock-based compensation expense recorded in the second quarter of 2004 to reflect the increased value of our stock. Production expense was also increased in the second half of 2004 due to recording approximately $975,000 in cost associated with the selling of purchased oil inventory as a result of purchase accounting for the Merger. Oil inventory was recorded at fair value of approximately $31.88 per Bbl as of July 1, 2004. The average production cost increased from $1.16 per Mcfe in 2003 to $1.29 per Mcfe in 2004. The per unit increase was primarily due to the higher costs discussed above partially offset by certain fixed costs spread over greater volumes in 2004. Purchase accounting and the non-cash stock-based compensation expense were responsible for $0.06 and $0.03 per Mcfe of the per unit increase, respectively.

     Production taxes increased $318,000 from $2.4 million in 2003 to $2.8 million in 2004 primarily due to higher oil and gas prices in Michigan, where production taxes are based on a percentage of revenues, excluding the effects of hedging. Average per unit production taxes increased from $0.14 per Mcfe in 2003 to $0.16 per Mcfe in 2004 primarily due to the increase in the selling price of natural gas in 2004, excluding the effects of hedging.

     Exploration expense decreased $1.3 million (20%) from $6.8 million in 2003 to $5.5 million in 2004 primarily due to decreases in expired lease expense, seismic expense and exploratory dry hole expense partially offset by additional non-cash stock-based compensation expense recorded in the second quarter of 2004. We have decreased exploration activity in order to focus our drilling efforts on lower risk developmental drilling. However, we expect to continue to incur exploration expense for costs related to our ongoing operations which are classified as exploration expense under the successful efforts method of accounting. See Note 2 to the Consolidated Financial Statements.

     General and administrative expense increased $592,000 (13%) from 2003 to 2004 primarily due to management fees and reimbursements of $641,000 paid, respectively, to Capital C and Legend Natural Gas, LP (“Legend”) and $292,000 of additional non-cash stock-based compensation expense recorded in the second quarter of 2004 to reflect the increased value of our stock.

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     Depreciation, depletion and amortization increased by $8.5 million from $18.1 million in 2003 to $26.6 million in 2004. This increase was primarily due to an increase in depletion expense. Depletion expense increased $9.0 million (61%) from $14.6 million in 2003 to $23.6 million in 2004 due to higher gas volumes and a higher depletion rate per Mcfe. Depletion per Mcfe increased from $0.85 per Mcfe in 2003 to $1.35 per Mcfe in 2004, primarily due to a higher cost basis resulting from purchase accounting for the Merger in the last six months of 2004. Approximately $0.26 per Mcfe of the increase in depletion per Mcfe was due to the $112.4 million deferred tax gross-up to producing oil and gas properties.

     Derivative fair value gain/loss was a gain of $319,000 in 2003 compared to a loss of $1.2 million in 2004. The derivative fair value gain/loss reflects the changes in fair value of certain derivative instruments that are not designated or do not qualify as cash flow hedges and $1.6 million related to the ineffective portion of crude oil swaps qualifying for hedge accounting which was recorded in the third quarter of 2004.

     Transaction expenses of $26 million were recorded in the predecessor period. These expenses include severance and retention payments made to employees, unamortized loan costs written off, temporary financing facility costs, costs of the consent solicitation process for our $225 million Senior Subordinated Notes due 2007 (the “9-7/8% Notes”) and buyer and seller investment banking fees, professional fees and other transaction expenses.

     Interest expense increased $481,000 (2%) from $23.6 million in 2003 to $24.1 million in 2004. This increase was due to an increase in average outstanding borrowings partially offset by lower blended interest rates.

     Income tax expense decreased $9.2 million from $3.2 million in 2003 to a benefit of $6.0 million in 2004. The decrease was due to a decrease in income from continuing operations before income taxes coupled with a lower effective tax rate in 2004. The effective tax rate was reduced due to certain nondeductible transaction-related expenses recorded in the predecessor period. This was partially offset by an increase in the tax rate from a benefit of $1.5 million recorded in the successor period. This benefit was the result of a change in the effective state tax rate due to the merger of two of our subsidiaries into Belden & Blake Corporation on December 30, 2004.

     Discontinued operations relating to the TBR and Arrow asset sales resulted in a gain, net of tax, of $28.9 million in 2004 compared to a loss, net of tax, of $10.7 million in 2003. This was primarily attributable to the $45.2 million ($28.0 million net of tax) net gain on the sales of the TBR and Arrow recorded in the second quarter of 2004.

2003 Compared to 2002

Revenues

     Net operating revenues decreased from $104.0 million in 2002 to $95.1 million in 2003. The decrease was due to lower gas sales revenues of $5.6 million, lower oil sales revenues of $266,000 and lower revenues from gas gathering and marketing of $3.0 million.

     Gas volumes sold decreased 1.1 Bcf (7%) from 15.9 Bcf in 2002 to 14.8 Bcf in 2003 resulting in a decrease in gas sales revenues of approximately $5.2 million. Oil volumes sold decreased approximately 109,000 Bbls (21%) from 522,000 Bbls in 2002 to 413,000 Bbls in 2003 resulting in a decrease in oil sales revenues of approximately $2.5 million. The oil and gas volume decreases were due to the sales of 202 wells in Ohio in the first quarter of 2002, 1,138 wells in Ohio in the third quarter of 2002 and 135 wells in Pennsylvania in the fourth quarter of 2002 and the natural production decline of the wells partially offset by production from wells drilled in 2002 and 2003.

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     The average price realized for our natural gas decreased $0.03 per Mcf to $4.92 per Mcf in 2003 compared to 2002, which decreased gas sales revenues in 2003 by approximately $445,000. As a result of our hedging activities, gas sales revenues were decreased by $10.3 million ($0.69 per Mcf) in 2003 and increased by $21.6 million ($1.36 per Mcf) in 2002. The average price paid for our oil increased from $22.72 per barrel in 2002 to $28.06 per barrel in 2003, which increased oil sales revenues by approximately $2.2 million.

     The operating margin from oil and gas sales (oil and gas sales revenues less production expense and production taxes) on a per unit basis decreased from $3.60 per Mcfe in 2002 to $3.59 per Mcfe in 2003.

     The decrease in gas gathering and marketing revenues was primarily the result of decreased gas marketing activity, the termination of a gas marketing contract and lower margins on a gathering system in Pennsylvania.

Costs and Expenses

     Production expense decreased $230,000 from $20.2 million in 2002 to $20.0 million in 2003. This decrease was primarily due to the sales of wells in Ohio and Pennsylvania during 2002, partially offset by higher operating costs incurred as a result of colder temperatures and greater amounts of snow during the first quarter of 2003 coupled with increased costs to stimulate production on declining wells in the higher oil and natural gas price environment of 2003. These efforts increased production volumes during 2003 but also had the effect of increasing the per unit cost. The average production cost increased from $1.07 per Mcfe in 2002 to $1.16 per Mcfe in 2003. The per unit increase was primarily due to the higher costs incurred during 2003 as discussed above and certain fixed costs spread over fewer volumes in 2003.

     Production taxes increased $660,000 from $1.8 million in 2002 to $2.4 million in 2003 primarily due to higher oil and gas prices in Michigan, where production taxes are based on a percentage of revenues, excluding the effects of hedging. Average per unit production taxes increased 50% from $0.09 per Mcfe in 2002 to $0.14 per Mcfe in 2003 primarily due to a 56% increase in the selling price of natural gas in 2003, excluding the effects of hedging.

     Exploration expense decreased $2.0 million from $8.8 million in 2002 to $6.8 million in 2003 due to a decrease in seismic costs of $1.1 million, a decrease of $252,000 in land leasing expense and a decrease in employment and other compensation related expenses.

     Depreciation, depletion and amortization decreased by $3.2 million from $21.3 million in 2002 to $18.1 million in 2003. This decrease was primarily due to a $286,000 reduction in amortization of loan costs, a $404,000 reduction in the amortization of nonconventional fuel source tax credits and a decrease in depletion expense. Depletion expense decreased $2.0 million (12%) from $16.6 million in 2002 to $14.6 million in 2003 due to lower oil and gas volumes and a lower depletion rate per Mcfe. Depletion per Mcfe decreased from $0.87 per Mcfe in 2002 to $0.85 per Mcfe in 2003, primarily due to the effect of the adoption of SFAS 143. The basis used to calculate depletion expense for oil and gas properties was increased by the fair value of the estimated future plugging liability and decreased by the gross amount of the estimated salvage value of the well equipment.

     Impairment of oil and gas properties was $896,000 in 2003 due to impairment of acreage of $475,000 in certain areas and an impairment of $421,000 in one of our smaller producing property pools. The impairments reduced the property’s book value to its estimated fair value.

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     Accretion expense was $343,000 in 2003 as a result of the adoption of SFAS 143 at the beginning of 2003.

     Derivative fair value gain was $319,000 in 2003 related to certain derivative instruments that are not designated as cash flow hedges. The gain reflects the changes in fair value of those instruments.

     We recorded severance and other nonrecurring charges of $923,000 in 2002 which were primarily related to employment reductions. In 2002, a total of 28 positions were eliminated when we combined our Pennsylvania/ New York District with our Ohio District to form a new “Appalachian District.” These actions were necessary to capitalize on operational and administrative efficiencies and bring our employment level in line with current and anticipated future staffing.

     Interest expense increased $1.1 million (5%) from $22.5 million in 2002 to $23.6 million in 2003. This increase was due to an increase in average outstanding borrowings and higher blended interest rates.

     Income tax expense decreased $2.1 million from $5.3 million in 2002 to $3.2 million in 2003. The decrease in expense is due to a decrease in income from continuing operations and a lower effective tax rate in 2003.

     Loss from discontinued operations increased from a net loss of $6.5 million in 2002 to a loss of $10.7 million in 2003. Discontinued operations relate to the New York Medina wells sold in 2002 and the TBR and Arrow assets sold in the second quarter of 2004. The increase is primarily due to a $7.9 million ($5.2 million net of tax benefit) increase in loss from the TBR assets as a result of higher TBR exploration expense in 2003 and an impairment recorded on undeveloped TBR acreage in 2003. This increase was partially offset by a $1.2 million decrease in loss from the New York Medina wells as a result of the $3.2 million ($1.8 million net of tax benefit) loss recorded on the sale in 2002.

Liquidity and Capital Resources

Cash Flows

     We expect that our primary sources of cash in 2005 will be from funds generated from operations and from borrowings under the Senior Facilities. Based on our current level of operations, we believe our cash flow from operations, available cash and available borrowings under our Senior Facilities, will be adequate to meet our future liquidity needs for the foreseeable future.

     The primary sources of cash in the year ended December 31, 2004 were net proceeds from the sale of our TBR and Arrow assets, funds generated from operations and from borrowings under our credit facilities, and the proceeds from the issuance of the Notes. Funds used during this period were primarily used for operations, exploration and development expenditures, interest expense, Merger expenses and repayment of debt. Our liquidity and capital resources are closely related to and dependent upon the current prices paid for our oil and natural gas.

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     The following table summarizes the net cash flow for the periods presented:

     Our operating activities provided cash flows of $44.3 million during 2004 compared to $26.2 million in 2003. The increase was primarily due to higher cash received for oil and gas revenues (net of hedging) of $6.0 million and changes in certain working capital items of $11.0 million.

     Cash flows used in investing activities decreased $4.2 million in 2004 due to a decrease in acquisitions of $4.8 million and a decrease in exploration expense of $1.4 million partially offset by $2.6 million in lower asset sales in 2004 compared to 2003.

     Cash flows used in financing activities in 2004 were primarily due to the Merger and payments on the predecessor company credit facility.

     During 2004, working capital from continuing operations increased $3.9 million from a deficit of $7.1 million at December 31, 2003 to a deficit of $3.2 million at December 31, 2004. The increase was primarily due to an increase in cash of $17.0 million, an increase in accounts receivable of $4.4 million and an increase in deferred income tax assets of $3.7 million. This was offset by an increase in accrued expenses of $10.7 million, an increase in the net current liability for the fair value for derivatives of $8.5 million, a decrease in other current assets of $1.3 million and an increase of $1.2 million for the current portion of long-term liabilities. Accrued expenses increased primarily due to an increase of $6.9 million in accrued interest expense.

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Capital Expenditures

     The table below sets forth our total capital expenditures for each of the years ending December 31, 2004, 2003 and 2002.

     During 2004, we spent approximately $25 million, including exploratory dry hole expense, on our drilling and other capital expenditures related to continuing operations. In 2004, we drilled 101 gross (93.1 net) development wells of which 100 gross (92.1 net) wells were successfully completed as producers in the target formation and 1 gross (1.0 net) well was a dry hole. We also drilled five gross (3.8 net) exploratory wells which were all dry holes. One additional exploratory well drilled in 2004 is still being evaluated.

     We plan to spend approximately $36 million during 2005 on our drilling activities, including exploratory dry hole expense, and other capital expenditures. We intend to finance our planned capital expenditures through our cash on hand, available cash flow, borrowings under our revolving credit facility and, to a lesser extent, the sale of non-strategic assets. At December 31, 2004, and at February 28, 2005, we had approximately $13.8 million available under our revolving facility. The level of our future cash flow will depend on a number of factors including the demand for and price levels of oil and gas, the scope and success of our drilling activities and our ability to acquire additional producing properties. There can be no assurance that the future drilling of our proved undeveloped locations will provide adequate liquidity in the future.

Financing and Credit Facilities

Senior Secured Notes due 2012

     We have $192.5 million of our Notes outstanding as of December 31, 2004. The Notes mature July 15, 2012. Interest is payable semi-annually on January 15 and July 15 of each year. The Notes are secured on a second-priority lien on the same assets subject to the liens securing our obligations under the Senior Facilities. The Notes are subject to redemption at our option at specific redemption prices.

     The Notes are governed by an indenture (the “Indenture”), which contains certain covenants that limit our ability to incur additional indebtedness and issue stock, pay dividends, make distributions, make

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investments, make certain other restricted payments, enter into certain transactions with affiliates, dispose of certain assets, incur liens securing indebtedness of any kind other than permitted liens and engage in mergers and consolidations.

     On December 23, 2004, we commenced an exchange offer, which allowed the holders of the unregistered Notes to exchange the unregistered Notes for new notes with materially identical terms that had been registered under the Securities Act of 1933, as amended. The exchange offer expired on February 4, 2005, and all of the unregistered Notes were exchanged for registered Notes. The Notes are not listed on any securities exchange.

Senior Facilities

     At December 31, 2004, we had a $170 million senior credit facility comprised of: a seven year $100 million term facility; a six year $30 million revolving facility for working capital requirements and general corporate purposes, including the issuance of letters of credit; and a six year $40 million letter of credit facility (the “Senior Facilities”) that may be used only to provide credit support for our obligations under the Hedge Agreement and other hedging transactions. The Senior Facilities are secured by a first-priority lien on certain of our assets. At December 31, 2004, the interest rate under our base rate option was 7.0%. Under our three month LIBOR option the rate was 5.24%. At December 31, 2004, we had $56.2 million of outstanding letters of credit. At December 31, 2004, there was no outstanding balance under the revolving credit agreement. Under the term facility the outstanding balance was $89.5 million. We had $13.8 million of borrowing capacity under our revolving credit facility available for general corporate purposes. As of December 31, 2004, we were in compliance with all financial covenants and requirements under the existing credit facilities.

     Term Facility

     The Term Facility consists of a $100 million term loan that was made on July 7, 2004. Proceeds of the term loan were used to fund a portion of the consideration in the Merger, to refinance our existing indebtedness, and to pay expenses associated with the transactions.

     All or a portion of the term loan will bear interest, at our option, either at the Base Rate or at the Eurodollar Rate plus, in each case, a specified margin subject to adjustment. The Base Rate is a rate calculated daily as the highest of (i) the annual rate of interest quoted in The Wall Street Journal, Money Rates Section as the Prime Rate (currently defined as the base rate on corporate loans posted by at least 75% of the nation’s thirty (30) largest banks), and (ii) the federal funds effective rate plus 1/2 of 1%. Interest on any portion of the term loan bearing interest based on the Base Rate is payable quarterly on January 1, April 1, July 1, and October 1 of each year.

     The Eurodollar Rate is equal to the LIBOR as adjusted for certain regulatory reserve costs. At our election, interest periods for that portion of the term loan bearing interest at the Eurodollar Rate may be one, two, three and six months. Interest on any portion of the term loan bearing interest based on the Eurodollar Rate is payable quarterly on January 1, April 1, July 1, and October 1 of each year. Interest on overdue term loan amounts accrues at a rate equal to the Base Rate plus the applicable margin plus 2.00%.

     The term loan amortizes quarterly at the rate of 0.25% of the outstanding amount of the term loan per quarter during the first six years, with the balance payable in equal quarterly installments during the seventh year. The term loan is required to be paid in full on July 7, 2011. We are entitled to voluntarily prepay the term loan at any time, in whole or in part, without premium or penalty.

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     We must make mandatory prepayments of the term loan utilizing funds derived from certain proceeds as follows: (i) 100% of the net cash proceeds of the sale or disposition of our property and assets and that of our subsidiaries (other than net cash proceeds of sales or dispositions of inventory in the ordinary course of business and net cash proceeds less than a specified amount that are reinvested in other assets useful in our business within 360 days); (ii) 100% of the net cash proceeds of insurance paid on account of any loss by us or our subsidiaries of any property or assets, other than net cash proceeds less than a specified amount that are reinvested in other assets useful in our business or that of our subsidiaries (or used to replace damaged or destroyed assets) within 360 days of receipt thereof; (iii) 50% of the net cash proceeds received from the issuance of equity securities by us or our subsidiaries (other than issuances pursuant to employee stock plans); (iv) 100% of the net cash proceeds received from the incurrence of indebtedness by us or our subsidiaries (other than indebtedness otherwise permitted under the documentation for the Senior Facilities), payable no later than the first business day following the date of receipt; and (v) 100% (subject to reduction if certain financial performance measures are obtained) of “excess cash flow” payable within 105 days of fiscal year end. Mandatory prepayments are applied to scheduled amortization payments on the term loan on a pro rata basis.

     As a result of the amount of our calculation of excess cash flow, as defined in our credit agreement, we elected to make a prepayment of $10 million on December 16, 2004. We have no additional mandatory prepayment requirement for 2004, based on the calculation of excess cash flow.

     Revolving Facility

     The Revolving Facility is a $30 million revolving credit facility that may be used by us for revolving loans and letters of credit including letters of credit to secure the Hedges and other hedging transactions. Revolving loans may be borrowed anytime beginning July 7, 2004 and ending on July 7, 2010. Proceeds of the revolving loan may be used for ongoing working capital requirements and general corporate purposes and up to $15 million for the issuance of letters of credit (in addition to the letters of credit provided under the letter of credit facility described below) to provide credit support for our obligations under the Hedge Agreement and other hedging transactions. An additional $5 million of letters of credit may be obtained during the term of the Revolving Facility for general corporate purposes.

     All or a portion of the revolving loans will bear interest, at our option, either at the Base Rate (as discussed above under Term Facility) plus a specified margin subject to adjustment or at the Eurodollar Rate (as discussed above under Term Facility) plus a specified margin subject to adjustment. Interest on any portion of the revolving loan bearing interest based on the Based Rate is payable on March 31, June 30, September 30 and December 31 of each year. Interest on any portion of the revolving loan bearing interest based on the Eurodollar Rate is payable at the end of each interest period, and if an interest period is longer than three months, every three months during the interest period. Interest on overdue revolving loan amounts accrues at a rate equal to the Base Rate plus the applicable margin plus 2.00%.

     Letters of credit issued under the revolving facility accrue fees equal to a specified rate per annum on the average daily maximum amount available to be drawn under such letters of credit. Letter of credit fees are payable quarterly in arrears on January 1, April 1, July 1, and October 1 of each year. In addition, a fronting fee on the average daily maximum amount available to be drawn under such letters of credit will be payable to the issuing bank for each letter of credit.

     We are required to pay a commitment fee equal to 0.50% per annum times the daily average undrawn portion of the Revolving Facility (reduced by the amount of letters of credit issued and outstanding under the Revolving Facility) which shall accrue from July 7, 2004 and shall be payable quarterly in arrears on January 1, April 1, July 1, and October 1 of each year.

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     The revolving loan does not amortize. The revolving loan is required to be paid in full on July 7, 2010. We are entitled to voluntarily prepay the revolving loan at any time, in whole or in part, without premium or penalty. Any portion of the revolving loan that is prepaid may be reborrowed. Once the term loan has been repaid in full, we must make mandatory prepayments of the revolving loan on the same basis as described above in the discussion of the term loan.

     Letter of Credit Facility

     The Letter of Credit Facility provides for the issuance of up to $40 million of letters of credit. Letters of credit under the Letter of Credit Facility may be obtained any time beginning on July 7, 2004 and ending on July 7, 2010. These letters of credit may be used only to provide credit support for our obligations under the Hedge Agreement and other hedging transactions.

     Letters of credit issued under the Letter of Credit Facility accrue fees equal to a specified rate per annum on the average daily maximum amount available to be drawn under such letters of credit. These letter of credit fees are payable quarterly in arrears on January 1, April 1, July 1, and October 1 of each year. In addition, a fronting fee on the average daily maximum amount available to be drawn under such letters of credit will be payable to the issuing bank for each letter of credit.

     We are required to pay an annual commitment fee based upon the daily average undrawn portion of the Letter of Credit Facility (reduced by the amount of letters of credit issued and outstanding under the Letter of Credit Facility) which shall accrue from July 7, 2004 and shall be payable quarterly in arrears on January 1, April 1, July 1, and October 1 of each year.

     Once the term loan and the revolving loan has been repaid in full, we must apply the amounts that would otherwise be mandatory prepayments to cash collateralize our obligations to the lenders under the letters of credit.

     Guarantees and Security

     Each of our existing and subsequently acquired domestic (and, to the extent no material adverse tax consequences would result, foreign) subsidiaries (other than Immaterial Subsidiaries) will guarantee all obligations under the Senior Facilities.

     The Senior Facilities, each guaranty and any interest rate hedging obligations that we or our subsidiaries have entered into with a lender or our affiliates are secured by first-priority security interests in certain of our assets and those of our subsidiaries, subject to permitted liens. This security includes a first-priority security interest in all of our capital stock and all capital stock of each of our domestic subsidiaries (other than Immaterial Subsidiaries) and all intercompany debt.

     Our obligations under the Hedge Agreement, to the extent not secured by cash or letters of credit, are secured by second-priority security interests in the assets securing the Senior Facilities. The Notes are secured by second-priority security interests in the assets securing the Senior Facilities and the Hedge Agreement. The priority of the security interests and related creditor rights with respect to the Senior Facilities, the Hedge Agreement, and the Notes are described in the intercreditor agreement.

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     Covenants

     Our Senior Facilities contain customary affirmative and negative covenants for senior financings of this kind including:

	•	a minimum interest coverage covenant;
	•	a capital expenditures covenant;
	•	a maximum total first-priority senior leverage ratio covenant;
	•	a covenant imposing limitations on exploration and drilling capital expenditures (other than in connection with estimated proved undeveloped reserves);
	•	a covenant imposing maximum total leverage to PV-10 of our total estimated proved reserves;
	•	a covenant imposing a limitation on our indebtedness;
	•	a covenant imposing limitations on liens; and
	•	a covenant imposing limitations on restricted payments.

     Events of Default

     Our Senior Facilities contain customary events of default including:

	•	failure to make payments when due;
	•	defaults under the Hedge Agreement;
	•	defaults under other agreements or instruments of indebtedness;
	•	noncompliance with covenants;
	•	breaches of representations and warranties;
	•	bankruptcy;
	•	judgments in excess of a specified amount;
	•	ERISA defaults;
	•	impairment of security interests in collateral;
	•	invalidity of guarantees; and
	•	“change of control.”

     At the time of the Merger all outstanding amounts due under the then existing revolving credit were repaid.

9 7/8% Senior Subordinated Notes

     As of September 30, 2004, all of the $225 million aggregate principal amount of our 9-7/8% Notes were tendered and all of the principal amount had been paid.

     From time to time the Company may enter into interest rate swaps to hedge the interest rate exposure associated with the credit facility, whereby a portion of the Company’s floating rate exposure is exchanged for a fixed interest rate. There were no interest rate swaps in 2004, 2003 or 2002.

     At December 31, 2004, the aggregate long-term debt maturing in the next five years is as follows: $1,005,000 (2005); $1,006,000 (2006); $1,007,000 (2007); $1,008,000 (2008) and $278,071,000 (2009 and thereafter).

Derivative Instruments

     The Hedges

     On July 7, 2004, we became a party to the Hedges with J. Aron pursuant to the Hedge Agreement. We have agreed to maintain these Hedges with J. Aron or its successor or permitted assigns. We anticipate that the Hedges will cover approximately 69% of the expected production through 2013 from our current estimated proved reserves and will range from 65% to 80% of such expected production in any year. The Hedges primarily take the form of monthly settled fixed price swaps in respect of the settlement prices for the market standard NYMEX futures contracts on crude oil and natural gas. Under

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such transactions, we pay NYMEX-based floating price per Mmbtu, in the case of Hedges on natural gas, and we pay a NYMEX-based floating price per Bbl, in the case of Hedges on crude oil, for each month during the term of the Hedges and receive a fixed price per Mmbtu or Bbl (as the case may be) according to a monthly schedule of fixed prices that we established upon completion of the Merger. The transactions will be settled on a net basis. The notional amounts of the Hedges were designed to provide sufficient hedged cash flow to cover operating expenditures, general and administrative expenses, interest expenses and the majority of capital expenditures needed to develop proved reserves.

     We are required to cause the Hedge Agreement to remain in effect for so long as any portion of the Senior Facilities or the Notes remains outstanding. The Hedges are documented under a standard International Swap Dealers Association (“ISDA”) agreement with customized credit terms, designed to mitigate the liquidity pressures in a high commodity price environment. The initial collateral requirements and ongoing margin requirements (based on market movements) are satisfied by letters of credit issued under the Senior Facilities, with an aggregate capitalization of $55 million. To support any exposure in excess of amounts supported by the letters of credit, we have granted J. Aron a second lien on the same assets that secure the Senior Facilities and the Notes and, to the extent our obligations exceed such letters of credit, such obligations are secured by a second-priority lien on the same assets securing the Senior Facilities and the Notes and are guaranteed by the same subsidiaries that guarantee the Senior Facilities and the Notes on a second-priority senior secured basis. We may enter into crude oil and natural gas hedges with parties other than J. Aron, which hedges may be secured by the letters of credit issued under the Senior Facilities and by a second-priority lien on the same assets securing the Senior Facilities and the Notes.

     To manage our exposure to natural gas or oil price volatility, we may partially hedge our physical gas or oil sales prices by selling futures contracts on the NYMEX or by selling NYMEX-based commodity derivative contracts which are placed with major financial institutions that we believe are minimal credit risks. The contracts may take the form of futures contracts, swaps, collars or options.

     In March 2003, we entered into a collar for 4,320 Bbtu of our natural gas production in 2004 with a ceiling price of $5.80 per Mmbtu and a floor price of $4.00 per Mmbtu. We also sold a floor at $3.00 per Mmbtu on this volume of gas. This aggregate structure has the effect of: 1) setting a maximum price of $5.80 per Mmbtu; 2) floating at prices from $4.00 to $5.80 per Mmbtu; 3) locking in a price of $4.00 per Mmbtu if prices are between $3.00 and $4.00 per Mmbtu; and 4) receiving a price of $1.00 per Mmbtu above the price if the price is $3.00 or less. All prices are based on monthly NYMEX settle. Upon the Merger, these contracts were transferred to J. Aron and re-established at a ceiling price of $5.75. These contracts were settled during 2004.

     In April 2003, we entered into a collar for 6,000 Bbtu of our natural gas production in 2005 with a ceiling price of $5.37 per Mmbtu and a floor price of $4.00 per Mmbtu. We also sold a floor at $3.10 per Mmbtu on this volume of gas. This aggregate structure has the effect of: 1) setting a maximum price of $5.37 per Mmbtu; 2) floating at prices from $4.00 to $5.37 per Mmbtu; 3) locking in a price of $4.00 per Mmbtu if prices are between $3.10 and $4.00 per Mmbtu; and 4) receiving a price of $0.90 per Mmbtu above the price if the price is $3.10 or less. All prices are based on monthly NYMEX settle. Upon the Merger, these contracts were transferred to J. Aron and re-established at a ceiling price of $5.32.

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     Our financial results and cash flows can be significantly impacted as commodity prices fluctuate widely in response to changing market conditions. Accordingly, we may modify our fixed price contract and financial hedging positions by entering into new transactions. The following tables reflect the natural gas and crude oil volumes and the weighted average prices under financial hedges (including settled hedges) at February 28, 2005:

     At December 31, 2004, the fair value of futures contracts covering 2005 through 2013 oil and gas production represented an unrealized loss of $78.4 million. Commodity prices have changed significantly since December 31, 2004 and, as a result, the fair value of our hedges as of March 23, 2005 was an unrealized loss of approximately $152.4 million.

Inflation and Changes in Prices

     The average price realized for our natural gas decreased from $4.95 per Mcf in 2002 to $4.92 per Mcf in 2003, then increased to $5.08 in 2004. The average price realized for our oil increased from $22.72 per Bbl in 2002 to $28.06 per Bbl in 2003 and increased to $34.42 per Bbl in 2004. These prices reflect average prices for oil and gas sales of our continuing operations. The prices include the effect of our oil and gas hedging activity.

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     The price of oil and natural gas has a significant impact on our results of operations. Oil and natural gas prices fluctuate based on market conditions and, accordingly, cannot be predicted. Costs to drill, complete and service wells can fluctuate based on demand for these services which is generally influenced by high or low commodity prices. Our costs and expenses may be subject to inflationary pressures if oil and gas prices are favorable.

     A large portion of our natural gas is sold subject to market sensitive contracts. Natural gas price risk is mitigated (hedged) by the utilization of over-the-counter NYMEX swaps, options or collars. Natural gas price hedging decisions are made in the context of our strategic objectives, taking into account the changing fundamentals of the natural gas marketplace.

Contractual Obligations

     We have various commitments primarily related to leases for office space, vehicles, natural gas compressors and computer equipment. We expect to fund these commitments with cash generated from operations.

     The following table summarizes our contractual obligations at December 31, 2004.

     In addition to the items above, we have a severance plan and a change of control plan. See “Executive Compensation – Employment and Severance Agreements” in Item 11 of this Annual Report. We have entered into joint operating agreements, area of mutual interest agreements and joint venture agreements with other companies. These agreements may include drilling commitments or other obligations in the normal course of business.

     The following table summarizes our commercial commitments at December 31, 2004.

     In the normal course of business, we have performance obligations which are supported by surety bonds or letters of credit. These obligations are primarily site restoration and dismantlement, royalty payments and exploration programs where governmental organizations require such support. We also have letters of credit with our hedging counterparty.

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     We have certain other commitments and uncertainties related to our normal operations, including any obligation to plug wells.

Off-Balance Sheet Arrangements

     We have no off-balance sheet arrangements.

RISK FACTORS

     Our business activities are subject to significant hazards and risks, including those described below. If any of these events should occur, our business, financial condition, liquidity or results of operations could be materially adversely affected. Please also refer to the cautionary note under “Forward-Looking Statements” on page 1 of this Annual Report.

Risks Relating to Our Business

     Hedging transactions may limit our potential gains or expose us to loss.

          To manage our exposure to price risks in the marketing of our natural gas, we enter into natural gas fixed-price physical delivery contracts as well as commodity price swap and collar contracts from time to time with respect to a portion of our current or future production. In connection with the Merger, we became a party to a long-term hedging program with J. Aron. We anticipate the Hedges will cover approximately 69% of the expected production through 2013 from our current estimated proved reserves. These transactions may limit our potential gains if natural gas prices were to rise substantially over the prices specified in the Hedge Agreement. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

	•	our production is less than expected;
	•	there is a narrowing of price differentials between delivery points for our production and the delivery points assumed in the hedge arrangements;
	•	there is a failure of a hedge counterparty to perform under the Hedge Agreement or other hedge transactions; or
	•	a sudden, unexpected event materially impacts natural gas and crude oil prices.

     Our operations require large amounts of capital that may not be recovered or raised.

          If our revenues were to decrease due to lower oil and natural gas prices, decreased production or other reasons, and if we could not obtain capital through our credit facilities or otherwise, our ability to execute our development plans, replace our reserves or maintain our production levels could be greatly limited. Our current development plans will require us to make large capital expenditures for the exploitation and development of our natural gas properties. Historically, we have funded our capital expenditures through a combination of funds generated internally from sales of production or properties, the issuance of equity, long-term debt financing and short-term financing arrangements. We cannot assure you, however, that our business will generate sufficient cash flow from operations or that future borrowings will be available to us under our new Senior Facilities in an amount sufficient to enable us to pay our indebtedness, including the Notes or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness, including the Notes on or before maturity. We cannot assure you that we will be able to refinance any of our indebtedness, including our new Senior Facilities and the Notes,

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on commercially reasonable terms or at all. Future cash flows and the availability of financing will be subject to a number of variables, such as:

	•	the success of our projects in the Appalachian and Michigan basins;
	•	our success in locating and producing new reserves;
	•	the level of production from existing wells; and
	•	prices of oil and natural gas.

          In addition, debt financing could lead to a diversion of cash flow to satisfy debt servicing obligations and to restrictions on our operations.

     Oil and natural gas prices are volatile, and an extended decline in prices would hurt our profitability and financial condition.

          While we will enter into long-term hedges covering most of our production in an effort to mitigate the risk of a decline in prices for oil and gas, a substantial portion of our production will remain unhedged. We expect that the markets for oil and gas will continue to be volatile. Any substantial or extended decline in the price of oil or gas would negatively affect our financial condition and results of operations. Our revenues, operating results, profitability, future rate of growth and the carrying value of our oil and gas properties depend heavily on prevailing market prices for oil and gas. A material decline could reduce our cash flow and borrowing capacity, as well as the value and the amount of our natural gas reserves. Substantially all of our proved reserves are natural gas. Therefore, we are more directly impacted by volatility in the price of natural gas. Various factors beyond our control can affect prices of natural gas. These factors include: North American supplies of oil and gas; political instability or armed conflict in oil or gas producing regions; the price and level of foreign imports; worldwide economic conditions; marketability of production; the level of consumer demand; the price, availability and acceptance of alternative fuels; the availability of pipeline capacity; weather conditions; and actions of federal, foreign, state, and local authorities.

          These external factors and the volatile nature of the energy markets make it difficult to estimate future commodity prices.

     If oil and natural gas prices decrease or our drilling efforts are unsuccessful, we may be required to write down the carrying value of our oil and natural gas properties.

          There is a risk that we will be required to write down the carrying value of our oil and gas properties, which would reduce our earnings and stockholders’ equity. A write down could occur when oil and gas prices are low or if we have substantial downward adjustments to our estimated proved reserves, increases in our estimates of development costs or deterioration in our drilling results.

          We account for our natural gas and crude oil exploration and development activities using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, developmental dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The capitalized costs of our oil and gas properties may not exceed the estimated future net cash flows from our properties. If capitalized costs exceed future net revenues, we write down the costs of the properties to our estimate of fair market value. Any such charge will not affect our cash flow from operating activities, but it will reduce our earnings and stockholders’ equity.

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          The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive but may actually deliver oil and gas in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature and an allocation of costs is required to properly account for the results. The evaluation of oil and gas leasehold acquisition costs requires judgment to estimate the fair value of these costs with reference to drilling activity in a given area.

          We review our oil and gas properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value. Once incurred, a write down of oil and gas properties is not reversible at a later date even if gas or oil prices increase. Given the complexities associated with oil and gas reserve estimates and the history of price volatility in the oil and gas markets, events may arise that would require us to record an impairment of the recorded book values associated with oil and gas properties.

     Information concerning our reserves and future net revenues is uncertain.

          This Annual Report and our SEC filings contain estimates of our estimated proved oil and natural gas reserves and the estimated future net revenues from such reserves. Actual results will most likely vary from amounts estimated, and any significant variance could have a material adverse effect on our future results of operations.

          Reserve estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Furthermore, different reserve engineers may make different estimates of reserves and cash flow based on the same available data and these differences may be significant. Therefore, these estimates are not precise.

          Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves disclosed by us. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

          At December 31, 2004, approximately 22% of our estimated proved reserves related to continuing operations were proved undeveloped. Estimation of proved undeveloped reserves and proved developed non-producing reserves is nearly always based on analogy to existing wells rather than the performance data used to estimate producing reserves. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. Production revenues from estimated proved developed non-producing reserves will not be realized until some time in the future. The reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of our reserves and the costs associated with these reserves in accordance with industry standards, these estimated costs may not be accurate, development may not occur as scheduled and actual results may not be as estimated.

          Analysts and investors should not construe the present value of future net reserves, or PV-10, as the current market value of the estimated oil and natural gas reserves attributable to our properties. We have based the estimated discounted future net cash flows from estimated proved reserves on prices and

41

costs as of the date of the estimate, in accordance with applicable regulations, whereas actual future prices and costs may be materially higher or lower. Many factors will affect actual future net cash flows, including:

	•	the amount and timing of actual production;
	•	supply and demand for natural gas;
	•	curtailments or increases in consumption by natural gas purchasers; and
	•	changes in governmental regulations or taxation.

          The timing of the production of oil and natural gas and of the related expenses affect the timing of actual future net cash flows from estimated proved reserves and, thus, their actual present value. In addition, the 10% discount factor, which we are required to use to calculate PV-10 for reporting purposes, is not necessarily the most appropriate discount factor given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject.

     Our exploitation and development drilling activities may not be successful.

          Our future drilling activities may not be successful, and we cannot assure you that our overall drilling success rate or our drilling success rate for activity within a particular area will not decline. In addition, the wells that we drill may not recover all or any portion of our capital investment in the wells, infrastructure, or the underlying leaseholds. Unsuccessful drilling activities could negatively affect our results of operations and financial condition. The cost of drilling, completing and operating wells is often uncertain, and a number of factors can delay or prevent drilling operations, including:

	•	unexpected drilling conditions;
	•	pressure or irregularities in formations;
	•	equipment failures or accidents;
	•	ability to hire and train personnel for drilling and completion services;
	•	adverse weather conditions;
	•	compliance with governmental requirements; and
	•	shortages or delays in the availability of drilling rig services and the delivery of equipment.

          In addition, we may not be able to obtain any options or lease rights in potential drilling locations that we identify. There is no guarantee that the potential drilling locations that we have identified will ever produce oil or natural gas.

          If our development drilling activities are not successful, we may not be able to replace or grow our reserves.

     Our acquisition activities may not be successful.

          As part of our growth strategy, we may make additional acquisitions of businesses and properties. However, suitable acquisition candidates may not be available on terms and conditions we find acceptable, and acquisitions pose substantial risks to our business, financial condition and results of operations. In pursuing acquisitions, we compete with other companies, many of which have greater

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financial and other resources to acquire attractive companies and properties. Even if future acquisitions are completed, the following are some of the risks associated with acquisitions:

	•	some of the acquired businesses or properties may not produce revenues, earnings or cash flow at anticipated levels;
	•	we may assume liabilities that were not disclosed or that exceed our estimates;
	•	we may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems;
	•	acquisitions could disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures; and
	•	we may incur additional debt related to future acquisitions.

          If our acquisition activities are not successful, our ability to replace or grow our reserves may be limited.

     We face strong competition in the oil and natural gas industry, and the resources of many of our competitors are greater than ours.

          We operate in a highly competitive industry. We compete with major oil companies, independent producers and institutional and individual investors, who are actively seeking oil and natural gas properties throughout the world, along with the equipment, labor and materials required to operate properties. Many of our competitors have financial and technological resources vastly exceeding those available to us. Many oil and natural gas properties are sold in a competitive bidding process in which we may lack technological information or expertise available to other bidders. We cannot assure you that we will be successful in acquiring and developing profitable properties in the face of this competition.

     Our operations are subject to the business and financial risk of oil and natural gas exploration.

          The business of exploring for and, to a lesser extent, developing oil and natural gas properties is an activity that involves a high degree of business and financial risk. Property acquisition decisions generally are based on various assumptions and subjective judgments that are speculative. It is impossible to predict accurately the ultimate production potential, if any, of a particular property or well. Moreover, the successful completion of an oil or natural gas well does not ensure a profit on investment. A variety of factors, both geological and market-related, can cause a well to become uneconomic or marginally economic.

     Our business is subject to operating hazards that could result in substantial losses.

          The oil and natural gas business involves operating hazards such as well blowouts, craterings, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, formations with abnormal pressures, pipeline ruptures or spills, pollution, releases of toxic gas and other environmental hazards and risks, any of which could cause us a substantial loss. In addition, we may be held liable for environmental damage caused by previous owners of property that we own or lease. As a result, we may face substantial liabilities to third parties or governmental entities, which could reduce or eliminate funds available for operation, development, production or acquisitions or cause us to incur losses. An event that is not fully covered by insurance (for example losses resulting from pollution and environmental risks, which are not fully insurable) could have a material adverse effect on our financial condition and results of operations.

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     We must comply with complex federal, state and local laws and regulations.

          Federal, state, and local authorities extensively regulate the oil and natural gas industry. Noncompliance with these statutes and regulations may lead to substantial penalties, and the overall regulatory burden on the industry increases the cost of doing business and, in turn, decreases profitability. Regulations affect various aspects of oil and natural gas drilling and production activities, including the pricing and marketing of oil and natural gas production, the drilling of wells (through permit and bonding requirements), the positioning of wells, the unitization or pooling of oil and natural gas properties, environmental matters, safety standards, the sharing of markets, production limitations, plugging and abandonment, and restoration. These laws and regulations are under constant review for amendment or expansion.

     We may incur substantial costs to comply with stringent environmental regulations.

          Our operations are subject to stringent and constantly changing environmental laws and regulations adopted by federal, state, and local governmental authorities. We could be forced to expend significant resources to comply with new laws or regulations, or changes to current requirements. We will continue to be subject to uncertainty associated with new regulatory interpretations and inconsistent interpretations between governmental environmental agencies. We could face significant liabilities to the government and third parties for discharges of oil, natural gas or other pollutants into the air, soil or water, and we could have to spend substantial amounts on investigations, litigation and remediation, as well as our efforts to prevent future spills. Moreover, our failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory and remedial obligations and the issuance of injunctions that restrict or prohibit the performance of operations. See “Items 1 and 2 — Business and Properties — Regulation.”

     Our business depends on gathering and transportation facilities owned by others.

          The marketability of our natural gas production depends in part on the availability, proximity and capacity of gathering and pipeline systems owned by third parties, and changes in our contracts with these third parties could materially affect our operations.

          In addition, federal, state, and local regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, and general economic conditions could adversely affect our ability to gather or transport our oil and natural gas. “Items 1 and 2 — Business and Properties — Regulation.”

     All of our common stock is owned by one controlling shareholder whose interests may differ from those of the holders of our Notes.

          We are a wholly owned subsidiary of Capital C. As a result of this ownership, Capital C is able to direct the election of our Board of Directors and therefore, direct our management and policies. Capital C may unilaterally approve mergers and other fundamental corporate changes involving us, which require shareholder approval. The interests of Capital C as shareholder may differ from the interests of holders of our Notes. See “Item 13 — Certain Relationships and Related Transactions.”

     Our structure may present conflicts of interest.

          Carlyle/Riverstone controls our sole shareholder, Capital C. David M. Leuschen, Pierre F. Lapeyre, Jr., Michael B. Hoffman and Gregory A. Beard are Managing Directors at Riverstone Holdings LLC, which jointly controls the general partner of Carlyle/Riverstone with The Carlyle Group. Carlyle/Riverstone currently has interests in three other oil and gas exploration and production companies, Legend Natural Gas, LP, Legend Natural Gas II, LP (collectively, “Legend”) and Mariner Energy, Inc., and may acquire interests in additional companies at any time. Messrs. Leuschen, Lapeyre

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and Beard are directors of Legend and Mariner Energy, Inc. or its affiliates. In addition, Messrs. Becci and Winne are directors, Executive Officers and limited partners of Legend. We can give no assurance that conflicts of interest will not arise with respect to corporate opportunities. Also, we can give no assurance that conflicts will not arise with respect to the time and attention devoted to us by Messrs. Becci and Winne.

Risks Relating to the Notes

     We may incur substantial additional debt, which could negatively impact our financial condition, results of operations and business prospects and prevent us from fulfilling our obligations under the Notes.

     After giving effect to the sale of the Notes and the borrowing under the Senior Facilities and the application of the net proceeds therefrom and our entry into the Hedge Agreement, we had approximately $348.6 million in outstanding debt and letters of credit issued. We are permitted to incur additional debt, including debt that may share in the first-priority liens on the collateral securing the Senior Facilities, the Hedges, and the Notes, provided we meet certain requirements in the indenture governing the Notes, the Hedge Agreement and the new Senior Facilities. We will also be permitted to incur additional debt that is secured by the collateral on an equal and ratable basis with the Notes if we satisfy a secured leverage ratio test. Our ability to incur additional debt in the future as either first-priority secured or second-priority secured and, in such event, to enable the holders thereof to share in the collateral on either a priority basis to or a pari passu basis with holders of the Notes may have the effect of diluting the value of the collateral securing the Notes. In addition, our level of debt could have important consequences for our operations, including:

•

making it more difficult for us to satisfy our obligations under the Notes or other debt and, if we fail to comply with the requirements of any of our debt, could result in an event of default;

•

requiring us to dedicate a substantial portion of our cash flow from operations to required payments on debt, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities;

•

limiting our ability to obtain additional financing in the future for working capital, capital expenditures and other general corporate activities;

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•

limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

•

detracting from our ability to withstand successfully a downturn in our business or the economy generally; and

•

placing us at a competitive disadvantage relative to other less leveraged competitors.

     In addition, all amounts owing under the revolving and letter of credit components of the new Senior Facilities will become due before any principal payments on the Notes are scheduled to become due and such amounts may need to be refinanced. Furthermore, to the extent that we are unable to repay the principal amount of the Notes at maturity out of cash on hand, we will need to refinance the Notes, or repay the Notes with the proceeds of an equity offering, at or prior to their maturity. There can be no assurance that we will be able to generate sufficient cash flow to service our interest payment obligations under our indebtedness or that future borrowings or equity financing will be available for the payment or refinancing of our indebtedness. To the extent that we are not successful in negotiating renewals of our borrowings or in arranging new financing, we may have to sell significant assets, which would have a material adverse effect on our business and results of operations. Among the factors that will affect our ability to effect an offering of our capital stock or refinance the Notes are financial market conditions and our value and performance at the time of such offering or refinancing. There can be no assurance that any such offering or refinancing can be successfully completed.

     All of these factors could have a material adverse effect on our business, financial condition, results of operations, prospects and ability to satisfy our obligations under the Notes.

     The holders of the Notes may not be able to realize fully the value of the liens securing the Notes.

     The Notes are secured by second-priority liens, on a parity basis with the liens securing the Hedges, on certain of our assets and the assets of our subsidiary guarantors, subject to certain permitted prior liens. The same assets have also been pledged to secure existing and future first-priority secured debt. To the extent that any of these assets are released from the liens securing the Senior Facilities and the Hedges, these assets will also be released from the liens securing the Notes. The Notes will be effectively subordinated in right of payment to all of our and our subsidiary guarantors’ existing and future first-priority secured debt to the extent of the value of the assets securing that debt.

     The holders of the first-priority liens will receive all proceeds from the liquidation of the collateral until all obligations secured by such liens are paid in full. Following payment of the first-priority liens in full, the holders of the second-priority liens will receive all proceeds from the liquidation of the collateral until all obligations secured by such liens are paid in full. The amount to be received from a liquidation of the collateral will depend upon numerous factors including market and economic conditions, the availability of buyers, the timing and manner of sale and similar factors. There can be no assurance that the collateral can or will be liquidated in a short period of time. No independent appraisals of any of the pledged property have been prepared by or on behalf of us in connection with the issuance of Notes. Accordingly, we cannot assure you that the proceeds of any sale of the pledged assets following an acceleration of the maturity of the Notes would be sufficient to satisfy, or would not be substantially less than, amounts due on the Notes after satisfying our obligations secured by the first-priority and other second-priority liens.

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     If the proceeds of any sale of the pledged assets were not sufficient to repay all amounts due on the Notes, the holders of the Notes (to the extent the Notes were not repaid from the proceeds of the sale of the pledged assets) would have only an unsecured claim against our remaining assets.

     The lien ranking and voting provisions set forth in the indenture and the collateral trust agreement substantially limit the rights of the holders of the Notes with respect to the collateral securing the Notes.

     The rights of the holders of the Notes with respect to the collateral securing the Notes are substantially limited pursuant to the terms of the lien-ranking and voting provisions set forth in the indenture and the collateral trust agreement. Under those provisions, at any time that obligations that have the benefit of the first-priority liens are outstanding, any actions that may be taken in respect of the collateral, including the ability to cause the commencement of enforcement proceedings against the collateral and to control the conduct of such proceedings, and the approval of amendments to, releases of collateral from the lien of, and waivers of past defaults under, the security documents, will be at the direction of the holders of the obligations secured by the first-priority liens. The trustee, on behalf of the holders of the Notes, does not have the ability to control or direct such actions, even if the rights of the holders of the Notes are adversely affected. Our creditors with first-priority liens may have interests that are different from the interests of the holders of the Notes. Additional releases of collateral from the second-priority lien securing the Notes may be permitted under some circumstances.

     The potential environmental liability of secured lenders may affect the value of the collateral for the Notes.

     We have mortgaged real property as collateral for the Notes. Real property mortgaged as security to a lender may be subject to both known and unknown environmental risks. As a holder of a security interest in real property, under certain circumstances you could be held liable for the environmental costs of remediating or preventing releases or threatened releases of hazardous substances at the mortgaged property. Under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, a lender that participates in the management or operation of a mortgaged property can be liable as an owner or operator for certain environmental costs. In addition, if the mortgaged property were subject to material contamination, the value of the property could be substantially reduced and the lender may choose not to foreclose.

     Your interest in the collateral may be adversely affected by the failure to perfect security interests in certain collateral acquired in the future.

     The security interest in the collateral securing the Notes includes certain of our personal property and real property and that of our subsidiaries, a pledge of certain stock and other equity interests, intercompany notes and the proceeds of the foregoing, whether now owned or acquired or arising in the future. Applicable law requires that certain property and rights acquired after the grant of a general security interest can be perfected only at the time such property and rights are acquired and identified. We cannot assure you that the collateral trustee will monitor, or that we will inform the collateral trustee of, any future acquisition of property and rights that constitute collateral, and that the necessary action will be taken to properly perfect the security interest in such after-acquired collateral. Such failure may result in the loss of the security interest therein or the priority of the security interest in favor of the Notes against third parties.

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     Your rights may be adversely affected by bankruptcy proceedings.

     An investment in the Notes, as in any type of security, involves certain insolvency and bankruptcy considerations that investors should carefully consider. In the event we, or any of our subsidiary guarantors, were to become a debtor subject to insolvency proceedings under the United States Bankruptcy Code (“Bankruptcy Code”), it is likely delays in payment of the Notes and in enforcing remedies under the Notes, any guarantee or the liens securing the Notes and the guarantees would result. Provisions under the Bankruptcy Code or general principles of equity that could result in the impairment of your rights include, but are not limited to, the automatic stay, avoidance of preferential transfers by a trustee or debtor-in-possession, substantive consolidation, limitations on collectibility of unmatured interest or attorney fees and forced restructuring of the Notes.

     Under the Bankruptcy Code, a secured creditor such as the trustee or collateral agent is prohibited from repossessing its security from a debtor in a bankruptcy case, or from disposing of security repossessed from such debtor, without bankruptcy court approval. Moreover, bankruptcy law permits the debtor to continue to retain and to use collateral, and the proceeds, products, rents, or profits of such collateral, even though the debtor is in default under the applicable debt instruments, provided that the secured creditor is given “adequate protection.” The term “adequate protection” is not defined under bankruptcy law and, because of the broad discretionary powers of a bankruptcy court, it is impossible to predict how long payments under the Notes could be delayed following commencement of a bankruptcy case, whether or when the trustee or collateral agent would repossess or dispose of the collateral, or whether or to what extent holders of the Notes would be compensated for any delay in payment or loss of value of the collateral through the requirements of “adequate protection.” Furthermore, in the event the bankruptcy court determines that the value of the collateral is not sufficient to repay all amounts due on the Notes, the holders of the Notes would have “undersecured claims.” Federal bankruptcy laws do not permit the payment or accrual of interest, costs, and attorneys’ fees for “undersecured claims” during the debtor’s bankruptcy case. Furthermore, the undersecured portion of such claims are unsecured claims and have a lower priority than secured claims in a bankruptcy and there is a risk that the principal amount of such claims may not be repaid in full.

     Under the Bankruptcy Code, a trustee or debtor-in-possession may generally recover payments or transfers of property of a debtor if such payment or transfer:

•

was to or for the benefit of a creditor;

•

was in payment of an antecedent debt owed before the transfer was made;

•

was made while the debtor was insolvent;

•

was within 90 days (or one year if the payment was to an “insider” of the debtor) before the filing of the bankruptcy case; and

•

enabled the creditor to receive more than it would have received in a liquidation under Chapter 7 of the Bankruptcy Code if the transfer had not been made and the creditor received payment of the debt as provided in the Bankruptcy Code.

     By way of example, if payments were made on the Notes prior to the filing of a bankruptcy case and a court subsequently determined that the value of the collateral pledged by the entity making the payment was less than the debt owed, such payments could be subject to avoidance as a preferential transfer.

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     A financial failure by us could also result in impairment of payment of the Notes if a bankruptcy court were to “substantively consolidate” us with our subsidiaries. If a bankruptcy court substantively consolidated us with our subsidiaries, the assets of each entity would be subject to the claims of creditors for all entities. Such a consolidation would expose the holders of the Notes not only to the usual impairments arising from bankruptcy, but also to potential dilution of the amount ultimately recoverable because of the larger creditor base.

     Forced restructuring of the Notes could occur through the “cram-down” provision of the Bankruptcy Code. Under this provision, the Notes could be restructured over the objections of holders of the Notes as to their general terms, primarily interest rate and maturity. Additionally, the Notes could be bifurcated into secured debt and unsecured debt if a bankruptcy court were to find that the debt owed by us exceeded the value of the collateral. If this were to occur, the unsecured portion of the debt could be afforded different treatment than the secured portion of the debt, including, but not limited to, the disallowance of the accrual of post-petition interest on the Notes.

     In addition, the indenture provides that, in the event of a bankruptcy, the trustee and the collateral trustee may not object to a number of important matters following the filing of a bankruptcy petition so long as any first-priority lien debt is outstanding. After such a filing, the value of your collateral could materially deteriorate and you would be unable to raise an objection. The right of the holders of obligations secured by first-priority liens on the collateral to foreclose upon and sell the collateral upon the occurrence of an event of default also would be subject to limitations under applicable bankruptcy laws if we or any of our subsidiaries become subject to a bankruptcy proceeding.

     Any future pledge of collateral might be avoidable in bankruptcy.

     Any future pledge of collateral in favor of the collateral trustee, including pursuant to security documents delivered after the date of the indenture, might be avoidable by the pledgor (as debtor-in-possession) or by its trustee in bankruptcy if certain events or circumstances exist or occur, including, among others, if the pledgor is insolvent at the time of the pledge, the pledge permits the holders of the Notes to receive a greater recovery than if the pledge had not been given and a bankruptcy proceeding in respect of the pledgor is commenced within 90 days following the pledge, or, in certain circumstances, a longer period.

     We may not be able to repurchase the Notes upon a change of control.

     Upon the occurrence of certain change of control events, holders of the Notes may require us to repurchase all or any part of their Notes. We may not have sufficient funds at the time of the change of control to make the required repurchases of the Notes. Additionally, certain events that would constitute a “change of control” (as defined in the indenture governing the Notes) would constitute an event of default under our Senior Facilities that would, if it should occur, permit the lenders to accelerate the debt outstanding under our Senior Facilities and that, in turn, would cause an event of default under the indenture.

     The source of funds for any repurchase required as a result of any change of control will be our available cash or cash generated from oil and natural gas operations or other sources, including borrowings, sales of assets, sales of equity or funds provided by a new controlling entity.

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     We cannot assure you, however, that sufficient funds would be available at the time of any change of control to make any required repurchases of the Notes tendered and to repay debt under our senior secured credit facilities. Furthermore, using available cash to fund the potential consequences of a change of control may impair our ability to obtain additional financing in the future. Any future credit agreements or other agreements relating to debt to which we may become a party will most likely contain similar restrictions and provisions.

     If the Notes receive an investment grade rating, many of the covenants in the indenture governing the Notes will be suspended, thereby reducing some of the protections for holders of our Notes in the indenture.

     If at any time the Notes receive investment grade ratings from both Standard & Poor’s Rating Services and Moody’s Investor Services, Inc., subject to certain additional conditions, many of the covenants in the indenture governing the Notes applicable to us and to our restricted subsidiaries, including the limitations on debt and restricted payments, will be suspended. While these covenants will be reinstated if we fail to maintain investment grade ratings on the Notes or in the event of a continuing default or event of default thereunder during the suspension period holders of our Notes will not have the protection of these covenants and we will have greater flexibility to incur indebtedness and make restricted payments.

     The terms of our Senior Facilities, as well as the Hedges and the indenture relating to the Notes, restrict our current and future operations, particularly our ability to respond to industry or economic changes or to take certain actions.

     Our Senior Facilities and the Hedge Agreement contain, and any future refinancing of our Senior Facilities likely would contain, a number of restrictive covenants that impose significant operating and financial restrictions on us. Our Senior Facilities and, to some extent, the Hedge Agreement include covenants restricting, among other things, our ability to:

•

incur additional debt;

•

pay dividends and make investments, loans or advances;

•

incur capital expenditures;

•

create liens;

•

use the proceeds from sales of assets and capital stock;

•

enter into sale and leaseback transactions;

•

enter into transactions with affiliates;

•

transfer all or substantially all of our assets; and

•

enter into merger or consolidation transactions.

     Our Senior Facilities also include financial covenants, including requirements that we maintain:

•

a minimum interest coverage ratio;

•

a maximum total leverage ratio; and

•

a maximum total first-priority senior leverage ratio to the PV-10 of our estimated proved reserves.

     The indenture relating to the Notes also contains covenants including, among other things, restrictions on our ability to:

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•

incur additional indebtedness;

•

pay dividends or make other distributions on stock, redeem stock or redeem subordinated obligations;

•

make investments;

•

create liens or other encumbrances; and

•

sell or otherwise dispose of all or substantially all of our assets, or merge or consolidate with another entity.

     A failure to comply with the covenants contained in our Senior Facilities or the indenture could result in an event of default (or an event of default under the Hedge Agreement which would result in an event of default under the Senior Facilities), which could materially and adversely affect our operating results and our financial condition. In the event of any default under our Senior Facilities or an event of default under the Hedge Agreement, the lenders under our Senior Facilities, or the Hedge counterparty, respectively, could elect to declare all borrowings outstanding or obligations thereunder, together with accrued and unpaid interest and fees, to be due and payable, and to require us to apply all of our available cash to repay the obligations owing to such entities, which would be an event of default under the Notes. In addition, our existing debt and any new debt may impose financial restrictions and other covenants on us that may be more restrictive than those applicable to the Notes.

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Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

          Among other risks, we are exposed to interest rate and commodity price risks.

          The interest rate risk relates to existing debt under our revolving credit facility as well as any new debt financing needed to fund capital requirements. We may manage our interest rate risk through the use of interest rate swaps to hedge the interest rate exposure associated with the credit agreement, whereby a portion of our floating rate exposure is exchanged for a fixed interest rate. A portion of our long-term debt consists of senior secured notes where the interest component is fixed. We had no derivative financial instruments for managing interest rate risks in place as of December 31, 2004, 2003 and 2002. If market interest rates for short-term borrowings increased 1%, the increase in our annual interest expense would be approximately $895,000. This sensitivity analysis is based on our financial structure at December 31, 2004.

          The commodity price risk relates to our natural gas and crude oil produced, held in storage and marketed. Our financial results can be significantly impacted as commodity prices fluctuate widely in response to changing market forces. From time to time we may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage our exposure to commodity price volatility. The fixed-price physical contracts generally have terms of a year or more. We employ a policy of hedging gas production sold under NYMEX-based contracts by selling NYMEX-based commodity derivative contracts which are placed with major financial institutions that we believe are minimal credit risks. The contracts may take the form of futures contracts, swaps or options. If NYMEX gas prices decreased $0.50 per Mcf, our gas sales revenues would decrease by $1.6 million, after considering the effects of the hedging contracts in place at December 31, 2004. At December 31, 2004 we had hedges on a portion of our oil production from 2005 through 2013. If the price of crude oil decreased $3.00 per Bbl, oil sales revenue for the year would decrease by $300,000. We had net pre-tax losses on our hedging activities of $22.3 million in 2004 and $10.3 million in 2003. This sensitivity analysis is based on our 2004 oil and gas sales volumes and assumes the NYMEX gas price would be above the ceiling in 2005 listed in the table on page 38.

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

          The Index to Consolidated Financial Statements and Schedules on page F-1 sets forth the financial statements included in this Annual Report on Form 10-K and their location herein. Schedules have been omitted as not required or not applicable because the information required to be presented is included in the financial statements and related notes.

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

          Not applicable.

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Item 9A. CONTROLS AND PROCEDURES

          Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2004. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2004. There were no changes in our internal control over financial reporting during the fourth quarter of 2004 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. OTHER INFORMATION

          Not applicable.

PART III

Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

          Our executive officers and directors and their respective positions and ages of as of March 5, 2005 were as follows:

          All of our executive officers serve at the pleasure of our Board of Directors. None of our executive officers is related to any other executive officer or director. The Board of Directors consists of seven members, each of whom will hold office until our next annual shareholder meeting. The business experience of each executive officer and director is summarized below.

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          James A. Winne III. On December 16, 2004, Mr. Winne was appointed Chief Executive Officer and Chairman of our Board of Directors. Prior to that he served as Senior Vice President since his appointment on November 1, 2004. Mr. Winne has been a director since November 1, 2004. Mr. Winne is President, Chief Executive Officer and a member of the Board of Supervisors of Legend Natural Gas, LP and Legend Natural Gas II, LP, each a privately held oil and gas company located in Houston, Texas and an affiliate of Carlyle/Riverstone (collectively, “Legend”). He has over 25 years of experience in the oil and gas industry. Prior to joining Legend in 2001, he served as President and Chief Executive Officer of North Central Oil Corporation from 1993 to 2001. Mr. Winne attended the University of Houston and is a Registered Land Professional. He serves on the Board of Directors of Encore Acquisition Company, an oil and gas company and is currently chairman of the Compensation Committee and a member of the Nominating and Corporate Governance Committee.

          Michael Becci. On December 16, 2004, Mr. Becci was appointed President and Chief Operating Officer. Prior to that he served as Senior Vice President since his appointment on November 1, 2004. Mr. Becci has been a director since November 1, 2004. Mr. Becci is Vice President, Chief Financial Officer and a member of the Board of Supervisors of Legend. Previously, he served as Vice President, Chief Financial Officer and Director of North Central Oil Corporation from 1990 to 2001. He is a Certified Public Accountant with over 20 years of experience in the oil and gas industry. Mr. Becci holds a Bachelor of Science degree in Business Administration from Valparaiso University.

          Robert W. Peshek. Mr. Peshek has been our Senior Vice President since December of 2003. Previously, he served as Vice President of Finance since 1997 and in 1999 was appointed Chief Financial Officer. Prior to that, he served as Corporate Controller and Tax Manager from 1994 to 1997. Prior to joining our company, Mr. Peshek served as a Senior Manager of the Tax Department at Ernst & Young LLP from 1981 to 1994. He is a Certified Public Accountant. Mr. Peshek holds a Bachelor of Business Administration degree from Kent State University where he graduated with honors. His professional affiliations include the American Institute of Certified Public Accountants and the Ohio Society of Certified Public Accountants. Mr. Peshek is a member of the Ohio Oil and Gas Association.

          David M. Becker. Mr. Becker has been our Vice President since May of 2000. He is also General Manager of the Michigan Exploration and Production District since 1995. Mr. Becker joined our company as a result of the acquisition of Ward Lake Energy, Inc., in February of 1995. He worked for Ward Lake from 1988 to 1995, serving most recently as President and COO. Previously he served as Facility Engineer for Shell Oil Company in New Orleans, Louisiana from 1984 to 1988. He has 23 years of experience in the oil and gas industry. Mr. Becker received his Bachelor of Science degree in Mechanical Engineering from Michigan Technical University. His professional affiliations include the Michigan Oil and Gas Association and the American Petroleum Institute.

          Duane D. Clark. Mr. Clark has been our Vice President of Legal Affairs/ Gas Marketing since April 2001. Previously, he served as Vice President of Gas Marketing. He joined us in 1995 as a Gas Marketing Analyst. Prior to joining our company, Mr. Clark held various management positions with Quaker State Corporation from 1978 to 1995. He has 26 years of experience in the oil and gas industry. Mr. Clark received his Bachelor of Arts degree in Mathematics and Economics from Ohio Wesleyan University. His professional affiliations include the Ohio Oil and Gas Association.

          Patricia A. Harcourt. Ms. Harcourt has been our Vice President of Administration since January 2003. Previously she served as Director of Administration from 2001 to 2003 and Director of Corporate Communications from 1994 to 2001. She joined us in 1988 as Investor Relations Coordinator. Prior to joining us, Ms. Harcourt was employed by Austin Powder Company as Employee Relations Administrator. She received her Bachelor of Arts degree in Communications from Bowling Green State University. She has 17 years of experience in the oil and gas industry and is a member of the Ohio Oil

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and Gas Association. Ms. Harcourt is also a member of the National Investor Relations Institute and the Society for Human Resource Management.

          Frederick J. Stair. Mr. Stair has been our Vice President and Corporate Controller since January 2003 and 1997, respectively. Prior to that date he served as Controller of the Exploration and Production Division from 1991 to 1997. Mr. Stair joined us in 1981 and has 24 years of accounting experience in the oil and gas industry. He graduated from the University of Akron where he received a Bachelor of Science degree in Accounting. Mr. Stair is a member of the Council of Petroleum Accountants Societies of Appalachia.

          Gregory A. Beard. In July 2004, Mr. Beard was elected to our Board of Directors. Mr. Beard is a Managing Director with Riverstone Holdings, LLC and has been with the firm since 2000. Prior to joining Riverstone, Mr. Beard was an Associate with Asen and Company, a privately held investment firm, from 1997 to 2000, and was associated with a Nashville, Tennessee-based investment firm from 1995 to 1997. Mr. Beard began his career as a Financial Analyst at Goldman Sachs in 1993. Mr. Beard currently serves as a director of Legend, Capital C Energy, LLC, affiliates of Mariner Energy, Inc. and CDM Resource Management, Ltd.

          Michael B. Hoffman. In July 2004, Mr. Hoffman was elected to the Board of Directors. Mr. Hoffman is a Managing Director of Riverstone Holdings, LLC, and serves on the Managing Committee responsible for all portfolio activities of Carlyle/Riverstone. Prior to joining Riverstone, Mr. Hoffman was Senior Managing Director and Head of the Mergers & Acquisitions Advisory Group at The Blackstone Group. He was also a member of Blackstone’s Management, Executive and Investment Committees. Before joining Blackstone in 1989, Mr. Hoffman was the Partner in charge of the Merger & Acquisitions Department of Smith Barney, Harris Upham & Co. Mr. Hoffman currently serves as a director of Buckeye Pipe Line Company LLC, the general partner of Buckeye Partners, L.P., Capital C Energy, LLC, Topaz Power Group, LLC, Microban International and Onconova Therapeutics. In addition, Mr. Hoffman serves on the Board of Trustees of Lenox Hill Hospital and Manhattan Eye, Ear and Throat Hospital.

          Pierre F. Lapeyre, Jr. In July 2004, Mr. Lapeyre was elected to our Board of Directors. Mr. Lapeyre is a Founder and Managing Director of Riverstone Holdings, LLC and serves on the Managing Committee responsible for all portfolio activities of Carlyle/Riverstone. Prior to founding Riverstone in May 2000, Mr. Lapeyre served as a Managing Director of Goldman Sachs in its Global Energy and Power Group since 1996. Mr. Lapeyre joined Goldman Sachs in 1986 and spent his 14-year investment banking career focused on the energy and power sectors. Mr. Lapeyre currently serves on the boards of Legend, Topaz Power Group, LLC, Seabulk International, Inc., CDM Resource Management, Ltd., Capital C Energy, LLC, Mariner Energy, Inc., SemGroup, LP, Stallion Oilfield Services and Frontier Holdings, Ltd.

          David M. Leuschen. In July 2004, Mr. Leuschen was elected to our Board of Directors. Mr. Leuschen is a Founder and Managing Director of Riverstone Holdings, LLC and serves on the Managing Committee responsible for all portfolio activities of Carlyle/Riverstone. Prior to founding Riverstone in May 2000, Mr. Leuschen spent 22 years with Goldman Sachs. He joined the firm in 1977, established their Global Energy and Power Group in 1982, became a Partner in 1986, and remained a Partner with the firm until leaving to found Riverstone in 2000. Mr. Leuschen currently serves as a director of Seabulk International Inc., Frontier Holdings, Ltd., Legend, Buckeye Pipe Line Company LLC, the general partner of Buckeye Partners, L.P., Mariner Energy, Inc., Petroplus International N.V. and Mega Energy LLC, as well as a number of other private industry-related businesses and nonprofit Boards of Directors. He is also owner and President of Switchback Ranch LLC, an integrated cattle ranching operation in the western United States.

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          Morris B. “Sam” Smith. In February 2005, Mr. Smith was elected to our Board of Directors. Mr. Smith was also designated a member and chairman of our Audit Committee. Mr. Smith retired from Encore Acquisition Company, an independent oil and gas company, in December 2003 where he last held the positions of Executive Vice President, Chief Financial Officer and Treasurer. Prior to joining Encore, Mr. Smith worked for Union Pacific Resources, an independent oil and gas company, from 1996 until 2000 where he held the position of Vice President of Finance and Chief Financial Officer. He received his Bachelor of Business Administration degree from McMurry University where he currently serves as Chairman of the Board of Trustees. Mr. Smith also serves on the Board of Directors of Cano Petroleum, Inc. and is the chairman of Cano’s audit committee.

Audit Committee

          Messrs. Beard, Lapeyre and Smith serve on our Audit Committee. Mr. Smith is an “audit committee financial expert” as defined in Item 401(h) of Regulation S-K. Mr. Smith is not “independent” as defined by the New York Stock Exchange’s listing standards because he was employed as the Chief Financial Officer of Encore Acquisition Company at the same time Mr. Winne served on Encore Acquisition Company’s compensation committee.

Code of Ethics

          We have adopted a Code of Ethics that applies to our Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Corporate Controller and any person performing similar functions. It is available without charge upon oral or written request, by contacting:

Belden & Blake Corporation
5200 Stoneham Road
North Canton, Ohio 44720
Attention: Duane Clark, Secretary
Telephone: (330) 499-1660

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Item 11. EXECUTIVE COMPENSATION

          The following table shows annual and long-term compensation for services in all capacities during the fiscal years ended December 31, 2004, 2003 and 2002 of our Chief Executive Officers and our other four most highly compensated executive officers.

Summary Compensation Table