-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, N1G2Y3rWqFZaMcweEQfpPQcehr/Wkl8UpCM5jfdcclH4SmPovdCH9Yt3XexEpgy2 Oj946BkVc+b+RtO8YzH71Q== 0000950152-08-002424.txt : 20080328 0000950152-08-002424.hdr.sgml : 20080328 20080328164541 ACCESSION NUMBER: 0000950152-08-002424 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 20071231 FILED AS OF DATE: 20080328 DATE AS OF CHANGE: 20080328 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BELDEN & BLAKE CORP /OH/ CENTRAL INDEX KEY: 0000880114 STANDARD INDUSTRIAL CLASSIFICATION: DRILLING OIL & GAS WELLS [1381] IRS NUMBER: 341686642 STATE OF INCORPORATION: OH FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 000-20100 FILM NUMBER: 08720015 BUSINESS ADDRESS: STREET 1: 5200 STONEHAM RD STREET 2: P O BOX 2500 CITY: NORTH CANTON STATE: OH ZIP: 44720 BUSINESS PHONE: 3304991660 MAIL ADDRESS: STREET 1: 5200 STONEHAM RD STREET 2: P O BOX 2500 CITY: NORTH CANTON STATE: OH ZIP: 44720 FORMER COMPANY: FORMER CONFORMED NAME: BELDEN & BLAKE ENERGY CORP /OH DATE OF NAME CHANGE: 19920427 10-K 1 l29594ae10vk.htm BELDEN & BLAKE CORPORATION 10-K Belden & Blake Corporation 10-K
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
     
þ   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2007
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File No. 0-20100
BELDEN & BLAKE CORPORATION
(Exact name of registrant as specified in its charter)
     
Ohio   34-1686642
(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification Number)
1001 Fannin Street, Suite 800
Houston, Texas 77002
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code: (713) 659-3500
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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ
     Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes þ No o
     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 a large accelerated filer, an accelerated filer, a non-accelerated filer ,or a smaller reporting company. See definition of “large accelerated filer” and “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer o   Accelerated filer o   Non-accelerated filer þ   Smaller reporting company o
     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
     As of February 29, 2008, Belden & Blake Corporation had outstanding 1,534 shares of common stock, no 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.
 
 

 

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     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,” “continue,” “estimate,” “plan,” “outlook,” “may,” “future,” “projection,” “likely,” “possible,” “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 13 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.

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GLOSSARY OF OIL AND NATURAL GAS TERMS
Bbl. One stock tank barrel or 42 U.S. gallons liquid volume.
Bcf. One billion cubic feet.
Bcfe. One billion cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
Btu. A British thermal unit is a measurement of the heat generating capacity of natural gas. One Btu is the heat required to raise the temperature of a one—pound mass of pure liquid water one degree Fahrenheit at the temperature at which water has its greatest density (39 degrees Fahrenheit).
Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Developed acres. Acres spaced or assigned to productive wells.
Exploratory well. A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive in another reservoir, or to extend a known reservoir.
Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
MBbl. One thousand barrels of oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
MMBbl. One million barrels.
MMBtu. One million British thermal units.
MMcf. One million cubic feet.
MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.
Natural gas liquids. The hydrocarbon liquids contained within natural gas.
Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.
NYMEX. The New York Mercantile Exchange.
Oil. Crude oil and condensate.
Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceeds production expenses and taxes.

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Proved reserves. Proved oil and natural gas reserves, as defined by the Securities and Exchange Commission (the “SEC”) in Article 4—10(a)(2) of Regulation S—X, are the estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions. Comprehensive SEC oil and natural gas reserve definitions can be found on the SEC’s website at www.sec.gov/about.forms/regs-x.pdf.
Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and natural gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved undeveloped drilling location. A site on which a development well can be drilled consistent with spacing rules for purposes of recovering proved undeveloped reserves.
Proved undeveloped reserves or PUDs. Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.
Reservoir. A porous and permeable underground formation containing a natural accumulation of produceable oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.
Standardized measure. Standardized measure is the present value of estimated future net revenues (after income taxes) to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (using prices and costs in effect as of the date of estimation) without giving effect to non—property related expenses such as certain general and administrative expenses and debt service or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%.
Successful well. A well capable of producing oil and/or natural gas in commercial quantities.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.
Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
Workover. Operations on a producing well to restore or increase production.

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PART I
Items 1 and 2. BUSINESS AND PROPERTIES
Item 1A. RISK FACTORS
Item 1B. UNRESOLVED STAFF COMMENTS
Item 3. LEGAL PROCEEDINGS
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
PART II
Item 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Item 6. SELECTED FINANCIAL DATA
Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Item 9A. CONTROLS AND PROCEDURES
Item 9B. OTHER INFORMATION
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT AND CORPORATE GOVERNANCE
Item 11. EXECUTIVE COMPENSATION
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS, MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
PART IV
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
SIGNATURES
Item 15(a) (1) and (2)
EX-31.1
EX-31.2
EX-32.1
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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 (the “Merger”). On August 16, 2005, Capital C was acquired by institutional funds managed by EnerVest, Ltd. (“EnerVest”).
     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 1001 Fannin Street, Suite 800, Houston, Texas 77002-6707. Our telephone number at that location is (713) 659-3500.
SIGNIFICANT EVENTS
     Acquisition by Institutional Funds Managed by EnerVest Ltd.
     On August 16, 2005, the former partners of our direct parent, Capital C, completed the sale of all of the partnership interests in Capital C to certain institutional funds managed by EnerVest, a Houston-based privately held oil and gas operator and institutional funds manager (the “Transaction”). The Transaction resulted in a change in control of our company (“Change in Control”).
     On July 7, 2004, we, Capital C, and Capital C Ohio, Inc., an Ohio corporation and a wholly owned subsidiary of Capital C (“Merger Sub”), completed a merger pursuant to which Merger Sub was merged with and into the Company (the “Merger”), with our company surviving the Merger as a wholly owned subsidiary of Capital C. The Merger resulted in a change in control of our company. The general partner of Capital C was controlled by Carlyle/Riverstone Global Energy and Power Fund II, L.P until the Transaction on August 16, 2005.
     The Transaction and Merger were each accounted for as a purchase effective August 16, 2005 and July 7, 2004, respectively. The Transaction and Merger resulted in a new basis of accounting reflecting estimated fair values for assets and liabilities at August 16, 2005 and July 7, 2004. Accordingly, the financial statements for the period subsequent to August 15, 2005 are presented on our new basis of accounting, while the results of operations for prior periods reflect the historical results of the two predecessor companies. Vertical black lines are presented to separate the financial statements of the two predecessor companies and the successor company. The “Successor Company” refers to the period from August 16, 2005 and forward. The “Predecessor I Company” refers to the period from July 7, 2004 through August 15, 2005. The “Predecessor II Company” refers to the period prior to July 7, 2004.
     Credit Agreement
     On August 16, 2005, we amended and restated our then existing $170 million credit agreement, by entering into a First Amended and Restated Credit and Guaranty Agreement (“Amended Credit Agreement”) by and among us and BNP Paribas, as sole lead arranger, sole book runner, syndication agent and administrative agent. The Amended Credit Agreement provides for loans and other extensions of credit to be made to us up to a maximum aggregate principal amount of $390 million. The obligations under the Amended Credit Agreement are secured by substantially all of our assets.
     On August 3, 2007, our bank group waived the covenant compliance requirement as of June 30, 2007 and amended the Amended Credit Agreement to increase the maximum leverage ratio from 4.0 : 1.0 to 4.25 : 1.0 for the quarters ending on September 30, 2007 and December 31, 2007. If we had not received this waiver, we would not have complied with our leverage ratio covenant as it would have been 4.07 : 1.0 as of June 30, 2007. On March 24, 2008, our bank group waived the covenant compliance requirement as of December 31, 2007 and amended the Amended Credit Agreement to further increase

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the maximum leverage ratio to 4.5 : 1.0 through December 31, 2008. If we had not received this waiver and amendment, we would not have complied with our leverage ratio covenant as it would have been 4.38 : 1.0 as of December 31, 2007.
     In connection with our entry into the Amended Credit Agreement, we executed a Subordinated Promissory Note (“Subordinated Note”) in favor of Capital C in the maximum principal amount of $94 million. Under the Subordinated Note, Capital C loaned $25 million to us on August 16, 2005. The Subordinated Note accrues interest at a rate of 10% per annum and matures on August 16, 2012. Interest payments on the Subordinated Note are due quarterly commencing September 30, 2005. In lieu of cash payments, we have the option to make interest payments on the Subordinated Note by borrowing additional amounts against the Subordinated Note. The interest payments in 2005, 2006 and the first quarter of 2007 were paid in cash. Interest payments for the last three quarters of 2007 were made by additional borrowings against the Subordinated Note. The Subordinated Note has no prepayment penalty or premium and may be prepaid in whole or in part at any time. The Subordinated Note is subordinate to our senior debt, which includes obligations under the Amended Credit Agreement, the J. Aron Swap and notes issued under our Indenture dated July 7, 2004 with BNY Midwest Trust Company, as indenture trustee (“Senior Secured Notes”).
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 2007, we achieved average net production of approximately 41.0 MMcfe per day consisting of 36.0 MMcf of natural gas and 824 Bbls of oil per day. At December 31, 2007, we owned interests in 4,470 gross (3,536 net) productive oil and gas wells in Ohio, Pennsylvania, New York and Michigan with estimated proved reserves totaling 258 Bcfe consisting of 227 Bcf of natural gas and 5.1 MMbbl of oil. The estimated future net cash flows from these reserves had a present value (discounted at 10%) after income taxes of approximately $389 million at December 31, 2007. The weighted average prices related to estimated proved reserves at December 31, 2007 were $7.54 per Mcf for natural gas and $92.77 per Bbl for oil.
     We have entered into an operating agreement with EnerVest Operating L.L.C. (“EnerVest Operating”). Under this operating agreement, EnerVest Operating acts as operator of the oil and gas wells, the related gathering systems and production facilities where our interest entitles us to control the appointment of the operator. As operator, EnerVest Operating manages the drilling and completion of wells and the day to day operating and maintenance activities for our assets. At December 31, 2007, Enervest Operating operated approximately 3,916 wells, or 88% of our gross wells representing approximately 98% of the value of our estimated proved developed reserves on a present value (discounted at 10%) basis. At December 31, 2007, we owned leases on 664,322 gross (571,141 net) acres, including 183,171 gross (129,204 net) undeveloped acres.
     We own approximately 1,620 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 NYMEX price for gas delivered at the Henry Hub in Louisiana. During 2007, our average per unit gas prices (excluding the effects of hedging) in Appalachia and Michigan were $0.59 and $0.19, respectively, higher than the average NYMEX monthly settle price for 2007.

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Oil and Gas Reserves
     The following table sets forth our estimated proved oil and gas reserves as of December 31, 2005, 2006 and 2007 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.
                         
    December 31,
    2007   2006   2005
Estimated proved reserves
                        
Gas (Bcf)
     227.2       233.0       246.7  
Oil (Mbbl)
     5,149       5,181       5,210  
Bcfe
     258.1       264.1       277.9  
     See Note 15 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 after income taxes from our estimated proved reserves as of December 31, 2007, determined in accordance with the rules and regulations of the SEC, was $389 million. 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, additional capital investment and income taxes). Estimated future net cash flows were calculated on the basis of prices and costs estimated to be in effect at December 31, 2007 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 derivative financial instruments in the determination of our oil and gas reserves.
                         
    December 31,
    2007   2006   2005
Gas (per Mcf)
   $ 7.54     $ 5.91     $ 9.83  
Oil (per Bbl)
     92.77       57.21       57.64  
     At December 31, 2007, 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.
     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 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 have historically exceeded 90%, with production generally lasting longer than 20 years.

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     We currently own working interests in 3,062 gross (2,740 net) wells in the Appalachian Basin, excluding our coalbed methane wells, which currently produce approximately 22.1 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 2007, we drilled 25 gross (23.3 net) development wells in the Medina Formation in Pennsylvania, 46 gross (46.0 net) development Clarendon wells in Pennsylvania, 1 gross (1 net) development Onondaga well in Pennsylvania, 2 gross (0.4 net) Knox development wells in Ohio, 1 gross (0.5 net) Berea development well in Ohio and 2 gross (2.0 net) Utica Shale development wells in Ohio. We plan to continue this development drilling program by drilling 15 gross (14.5 net) Medina wells, 60 gross (60.0 net) Clarendon wells and 5 gross (5.0 net) Utica Shale wells in 2008.
Michigan Basin Properties
     The Michigan Basin has operational similarities to the Appalachian Basin’s, geographic proximity to our operations in the Appalachian Basin and proximity to natural gas markets, which has generally resulted in premium wellhead prices as compared to NYMEX prices. We own working interests in 1,206 gross (594 net) wells in the Michigan Basin which currently produce approximately 16.9 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 2007, we drilled 9 gross (8.8 net) wells to the Antrim Shale Formation. We plan to drill 35 gross (17.6 net) wells in the Antrim Shale Formation in 2008.
Appalachian Basin — Coalbed Methane Properties
     We own a 100% working interest in 202 producing coalbed methane (“CBM”) wells in Pennsylvania and own leases on approximately 55,231 gross (54,927 net) acres of undeveloped CBM properties. Current production from these wells is approximately 3.1 MMcf net per day. We drilled 10 CBM wells in 2007 and plan to drill an additional 10 CBM wells in 2008.
Oil and Gas Operations and Production
     Operations. EnerVest Operating operates 88% of the wells in which we hold working interests. They maintain production field offices in Ohio, Pennsylvania and Michigan. Through these offices, EnerVest Operating reviews our properties to determine what action can be taken to control operating costs and/or improve production.
     We own approximately 1,620 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.

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     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. The average prices shown in the table include the effects of our qualified effective hedging activities. See Note 5 to the Consolidated Financial Statements.
                         
    Year Ended December 31,
    2007   2006   2005
Production
                        
Gas (MMcf)
     13,357       14,104       14,560  
Oil (Mbbl)
     348       373       358  
Total production (MMcfe)
     15,446       16,340       16,710  
Average price (1)
                        
Gas (per Mcf)
   $ 6.81     $ 8.77     $ 8.57  
Oil (per Bbl)
     67.42       62.78       46.37  
Per Mcfe
     7.41       9.00       8.46  
Average costs (per Mcfe)
                        
Production expense
   $ 1.59     $ 1.45     $ 1.40  
Production taxes
     0.15       0.15       0.20  
Depletion
     2.31       2.30       2.01  
 
(1)   The average prices presented above include non-cash amounts related to our derivatives as a result of purchase accounting for the Merger and the Transaction. Excluding these non-cash amounts from oil and gas sales revenues would result in the following average prices:
                         
    Year Ended December 31,
    2007   2006   2005
Gas (per Mcf)
   $ 7.34     $ 7.22     $ 6.99  
Oil (per Bbl)
     67.42       62.78       45.38  
Per Mcfe
     7.87       7.67       7.06  
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 2007, we spent approximately $22.7 million on development drilling and other capital expenditures. We drilled 96 gross (92.0 net) development wells to shallow, highly developed formations in our operating area. The results of this drilling activity are shown in the table on page 9.
     In 2008, we expect to spend approximately $34.5 million on development and exploratory drilling and other capital expenditures. We expect to drill approximately 120 gross (102.1 net) development wells in 2008 and spend approximately 65% of our drilling capital expenditures on drilling in shallow, highly developed formations. We plan to spend approximately 29% of our 2008 capital expenditures on development and exploratory projects in newly identified and less developed play areas, including the drilling of 5 gross (5.0 net) development Utica Shale wells.
     We were a pioneer in CBM development and production in Pennsylvania, and we presently own a 100% working interest in 202 CBM gas wells in Indiana, Westmoreland and Fayette counties. CBM 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 55,231 gross (54,927 net) CBM acres currently under lease in Pennsylvania, we believe the CBM may contribute significantly to our drilling portfolio. We plan to drill 10 gross (10.0 net) CBM wells in 2008.

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     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 (17.6 net) wells to the Antrim Shale Formation in 2008.
     In addition to our CBM and Antrim drilling, we plan to drill 15 gross (14.5 net) wells to the Medina Formation and 60 gross (60.0 net) wells to the Clarendon Formation in Pennsylvania. We also plan to drill up to 10 gross (10.0 net) exploratory wells in 2008.
     Certain typical characteristics of our drilling programs in the shallow, highly developed formations we target are described below:
                 
            Range of Average
            Drilling and Completion
    Range of Well Depths   Costs per Well
    (in feet)   (in thousands)
Ohio:
                
Clinton
     3,500 - 5,750     $ 300 - 340  
Pennsylvania:
                
Coalbed Methane
     1,000 - 1,600       190 - 305  
Clarendon
     1,100 - 2,100       90 - 130  
Medina
     5,300 - 6,200       300 - 370  
Michigan:
                
Antrim
     1,300 - 2,100       170 - 370  
     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, Knox, Utica Shale and Trenton Black River 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.
     Drilling Results. The following table sets forth drilling results from continuing operations with respect to wells drilled by us during the past three years:
                                                 
    Development Wells   Exploratory Wells
    2005   2006   2007   2005(1)   2006(2)   2007
Productive:
                                                
Gross
     120       177       96       2       —       —  
Net
     117.2       170.3       92.0       2.0       —       —  
Dry:
                                                
Gross
     —       2       —       1       1       —  
Net
     —       2.0       —       1.0       0.5       —  
Wells in progress:
                                                
Gross
     —       —       —       1       —       —  
Net
     —       —       —       0.5       —       —  
 
(1)   Includes one well (dry hole) that was classified as a well in progress in 2004.
 
(2)   Includes one well (dry hole) that was classified as a well in progress in 2005.

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Disposition of Assets
     On March 31, 2006, we sold our interests in 13 Oriskany wells and the associated gas gathering system for approximately $3.3 million, which approximated the net carrying value of such assets.
     We regularly review our oil and gas properties for potential disposition.
Employees
     As of February 29, 2008, we had no employees. All of our operating, administrative and technical services are provided by employees of EnerVest or other third parties.
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 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.
Principal Customers
     Each of the following customers accounted for 10% or more of our consolidated revenues during 2007: Integrys Energy, National Fuel Resources, Inc. and American Refining Group, Inc. If we were to lose any one of these oil or natural gas purchasers, the loss could temporarily cease production and sale of our oil or natural gas production from the wells subject to contracts with that purchaser. We believe, however, that we would be able promptly to replace the purchaser.
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

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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 future 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 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

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hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon may be subject 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.
     Recent scientific studies have suggested that man made emissions of certain gases, commonly referred to as “greenhouse gases” and including carbon dioxide and methane, may be contributing to the warming of the atmosphere resulting in climate change. In response to such studies, the United States Congress is actively considering legislation to reduce emissions of greenhouse gases. In addition, at least 17 states have already taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts v. EPA, the EPA may regulate greenhouse gas emissions from mobile sources (e.g., cars and trucks) and possibly from stationary sources as well under certain federal Clean Air Act programs, even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. New legislation or regulatory programs that restrict emissions of greenhouse gases in areas where the Company conducts business could adversely affect its operations and the demand for hydrocarbon products generally. The impact of such future programs cannot be predicted, but we do not expect our operations to be affected any differently than other similarly situated domestic competitors.
     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. Our SPCC plans have been updated to comply with the current regulations. We continue to monitor rapid changes in rules and requirements at both the federal and state level regarding spill prevention. 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, 2007, we owned interests in 4,470 gross (3,536 net) producing oil and gas wells of which approximately 3,916 wells were operated by EnerVest Operating. In the fourth quarter of 2007, our net production was approximately 41.0 MMcfe per day consisting of 36.0 MMcf of natural gas and 824 Bbls of oil per day.

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     The following table summarizes by state our productive wells at December 31, 2007:
                                                 
    December 31, 2007
    Gas Wells   Oil Wells   Total
State   Gross   Net   Gross   Net   Gross   Net
Ohio
     1,040       882       685       616       1,725       1,498  
Pennsylvania
     1,413       1,329       104       104       1,517       1,433  
New York
     22       11       —       —       22       11  
Michigan
     1,187       590       19       4       1,206       594  
 
                                                
 
     3,662       2,812       808       724       4,470       3,536  
 
                                                
Acreage Data
     The following table summarizes by state our gross and net developed and undeveloped acreage at December 31, 2007:
                                                 
    December 31, 2007
    Developed Acreage   Undeveloped Acreage   Total Acreage
State   Gross   Net   Gross   Net   Gross   Net
Ohio
     187,742       178,175       16,075       14,816       203,817       192,991  
Pennsylvania
     216,018       188,251       108,671       71,097       324,689       259,348  
New York
     14,371       12,601       21,983       8,543       36,354       21,144  
Michigan
     62,980       62,870       26,770       25,129       89,750       87,999  
Indiana
     40       40       9,672       9,619       9,712       9,659  
 
                                                
 
     481,151       441,937       183,171       129,204       664,322       571,141  
 
                                                
     Developed acreage includes 291,154 gross (263,508 net) acres of undrilled acreage held by production.
Item 1A. 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. Additional risks not presently known to us or which we consider immaterial based on information currently available to us may also materially adversely affect us. 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 63% of the expected 2008 through 2013 production 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;

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  •   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, 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 have entered 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 portion of our production remains 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.

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     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.
     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, 2007, approximately 19% of our estimated proved reserves 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 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;

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  •   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 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.

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  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.
  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.

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     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. See “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.
     Our sole shareholder, Capital C, is owned by institutional funds managed by EnerVest. Messrs. Houser and Vanderhider are Executive officers of EnerVest. EnerVest manages other funds that own interests in oil and gas properties in our area of operations. Mr. Mariani is an Executive officer of EnerVest Operating, an affiliate of EnerVest. EnerVest Operating controls the operations of our wells and the wells owned by other EnerVest managed funds. 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. Houser, Vanderhider and Mariani.
  The terms of our Amended Credit Agreement, as well as the Hedges and the indenture relating to the Senior Secured Notes, restrict our current and future operations, particularly our ability to respond to industry or economic changes or to take certain actions.
     Our Amended Credit Agreement 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 Amended Credit Agreement 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 minimum current ratio.
     The indenture relating to the Notes also contains covenants including, among other things, restrictions on our ability to:
  •   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.

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     On August 3, 2007, our bank group waived the covenant compliance requirement as of June 30, 2007 and amended the Amended Credit Agreement to increase the maximum leverage ratio for the quarters ending on September 30, 2007 and December 31, 2007. On March 24, 2008, our bank group waived the covenant compliance requirement as of December 31, 2007 and amended the Amended Credit Agreement to further increase the maximum leverage ratio through December 31, 2008. If we had not received these waivers and amendments, we would not have complied with this covenant.
     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 Senior Secured 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 Senior Secured Notes.
Item 1B. UNRESOLVED STAFF COMMENTS
     None.
Item 3. LEGAL PROCEEDINGS
     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.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
     None.
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 March 5, 2008, were held by Capital C.
Dividends
     We paid cash dividends of $9.8 million in 2007, $20.0 million in 2006 and $8.5 million in the fourth quarter of 2005. No dividends were paid on our Common Stock prior to the fourth quarter of 2005. We expect to continue to pay dividends as future financial performance permits.
Equity Compensation Plan Information:
     As of March 5, 2008, we do not have an equity compensation plan.

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Item 6. SELECTED FINANCIAL DATA
     The Selected Financial Data should be read in conjunction with the Consolidated Financial Statements at Item 15(a).
                                                             
    Successor Company     Predecessor I Company     Predecessor II Company
                                           
                    For the 138     For the 227   For the 178          
                    Day Period     Day Period   Day Period     For the 188   As of or for
                    from August     From January   from July 7,     Day Period   the year
    As of or for the year ended   16, 2005 to     1, 2005 to   2004 to     from January   ended
    December 31,   December 31,     August 15,   December 31,     1, 2004 to July   December 31,
(in thousands)   2007   2006   2005     2005   2004     6, 2004   2003
Continuing Operations:
                                                            
Revenues
     125,656       159,090     $ 76,671       $ 78,123     $ 62,401       $ 50,822     $ 95,414  
Depreciation, depletion and amortization
     36,087       38,074       14,341         21,265       17,527         9,089       18,098  
Impairment of oil and gas properties
     31       546       —         —       —         —       896  
Income (loss) from continuing operations before cumulative effect of change in accounting principle
    (35,322 )     52,199       17,563         (320 )     7,263         (18,869 )     5,960  
Balance sheet data:
                   As of 12/31/2005             As of 12/31/2004                  
Working capital (deficit) from continuing operations
     (14,224 )     (11,635 )     (38,999 )               (4,907 )               (8,168 )
Oil and gas properties and gathering systems, net
     627,556       641,879       648,417                 502,765                 224,631  
Total assets
     774,225       777,023       810,118                 570,853                 285,930  
Long-term debt, less current portion
     291,118       285,560       277,648                 281,396                 272,637  
Total shareholders’ (deficit) equity
     102,223       143,703       89,399                 57,088                 (58,418 )

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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. Capital C acquired us pursuant to a merger completed on July 7, 2004. On August 16, 2005, Capital C was acquired by institutional funds managed by EnerVest Ltd, a Houston-based privately held oil and gas operator and institutional funds manager. The Transaction resulted in a change in control of the Company.
     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, 2007, our total estimated proved reserves were 258 Bcfe. Natural gas comprised approximately 88% of our estimated proved reserves, and 81% 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, 2007, our conventional Appalachian properties accounted for 51% of our estimated proved reserves, while the Michigan properties and our Appalachian CBM properties accounted for 42% and 7%, respectively.
     In connection with the Transaction, our then existing indebtedness was refinanced. The principal elements of the refinancing included entering into a $390 million credit facility, comprised of a $350 million revolving facility, which currently has a borrowing base of $113.4 million, and a $40 million letter of credit facility (collectively, the “Amended Credit Agreement”), and our issuance of a $25 million Subordinated Promissory Note with a related party (see Note 18 to the Consolidated Financial Statements).
     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.
     Our financial results and cash flows can be significantly impacted as commodity prices fluctuate in response to changing market conditions. We use derivative financial 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”) as 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 63% of the expected 2008 through 2013 production from our current estimated proved reserves and will range from 55% to 75% of such expected production in any year.
     The average price realized for our natural gas, inclusive of qualified effective hedges, increased from $8.57 per Mcf in 2005 to $8.77 per Mcf in 2006 and then decreased to $6.81 per Mcf in 2007. The monthly average settle for natural gas trading on the NYMEX decreased from $8.62 per MMbtu in 2005 to $7.23 per MMbtu in 2006 and then decreased to $6.86 per MMbtu in 2007. Our selling price of natural gas is generally higher than the NYMEX price due to the proximity of our operations to natural gas markets along with a favorable Btu content of our gas. During 2007, our average per unit gas prices (excluding the effects of hedging) in Appalachia and Michigan were $0.59 and $0.19, respectively, higher than the average NYMEX monthly settle price for 2007. The remainder of the difference is primarily due to our qualified hedging activities during these periods. Our average realized price for oil, inclusive of qualified effective hedges, increased from $46.37 per Bbl in 2005 to $62.78 per Bbl in 2006 and to $67.42 per Bbl in 2007.
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 15(a). 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:

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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 costs of carrying and retaining undeveloped properties include 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 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 2005 Predecessor I Company period ended August 15, 2005, 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
     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 certain transactions such as the complete disposition of a geographical/geological pool. 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.

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     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 not qualifying for designation as cash flow hedges are reported in expense in the consolidated statements of operations as derivative fair value (gain) 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 impact earnings.
     The relationship between hedging instruments and the hedged items must be highly effective in achieving the offset of changes in fair values or cash flows attributable to the hedged risk, both at inception of the contract and on an ongoing basis. We assess effectiveness at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. We discontinue hedge accounting prospectively if we determine that a derivative is no longer highly effective as a hedge or if we decide to discontinue the hedging relationship.
     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 price, crude oil price or interest rate volatility and to support our capital expenditure plans. Our derivative financial instruments primarily take the form of swaps or collars. At December 31, 2007, our derivative contracts were comprised of natural gas swaps, natural gas basis differential swaps, crude oil swaps and interest rate swaps, which were placed with major financial institutions that we believe have a minimal credit risk. Qualifying derivative financial instruments are designated as cash flow hedges.
     We use NYMEX-based commodity derivative contracts to hedge natural gas, because our natural gas production is sold pursuant to NYMEX-based sales contracts. Beginning July 7, 2004, we had ineffectiveness on the natural gas swaps due to purchase accounting, which created non-zero value derivatives at the time of the Merger. We had 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 II Company period ended July 6, 2004. Although these collars were not deemed to be effective hedges in accordance with the provisions of SFAS 133, we retained these instruments as protection against changes in commodity prices and we recorded the mark-to-market adjustments on these natural gas collars, through 2005, in our income statement. Our NYMEX crude oil swaps were highly effective and were designated as cash flow hedges through August 16, 2005. We had ineffectiveness on the crude oil swaps because the oil is sold locally at a posted price which is different from the NYMEX price. At August 16, 2005, our oil swaps no longer qualify for cash flow hedge accounting because the assessment of effectiveness indicated that they may not be highly effective on an on-going basis. This occurred due to the application of purchase accounting to the derivatives, which created non-zero value derivatives at the time of the Transaction. The changes in the fair values of the natural gas collars since July 7, 2004, the changes in fair value of the oil swaps subsequent to August 15, 2005, the ineffective portion of the crude oil swaps through August 15, 2005 and the ineffective portion of the natural gas swaps from July 7, 2004 to June 30, 2006 are recorded as “Derivative fair value gain or loss.” As of July 1, 2006, we determined that our gas swaps were no longer highly effective and, therefore, could no longer be designated as cash flow hedges.

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Revenue Recognition
     Oil and natural gas revenues are recognized when production is sold to a purchaser at fixed or determinable prices, when delivery has occurred and title has transferred and collectability of the revenue is probable. We follow the sales method of accounting for natural gas revenues. Under this method of accounting, revenues are recognized based on volumes sold, which may differ from the volume to which we are entitled based on our working interest. An imbalance is recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the under—produced owner(s) to recoup its entitled share through future production. Under the sales method, no receivables are recorded where we have taken less than our share of production. There were no material gas imbalances at December 31, 2007 or 2006. Oil and gas marketing revenues are recognized when title passes.
Asset Retirement Obligations
     We follow SFAS 143, “Accounting for Asset Retirement Obligations.” SFAS 143 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.
     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 in 2004 and the Transaction in 2005, primarily due to a lower discount rate, revised estimates of asset lives on certain oil and gas wells and additional wells having been drilled.
     At December 31, 2007, there were no assets legally restricted for purposes of settling asset retirement obligations. A reconciliation of our liability for asset retirement obligations for the years ended December 31, 2007 and 2006 is as follows (in thousands):
                 
    Year Ended     Year Ended  
    December 31,     December 31,  
    2007     2006  
Beginning asset retirement obligations
   $ 20,734     $ 19,389  
Liabilities incurred
     220       523  
Liabilities settled
     (219 )     (543 )
Accretion expense
     1,290       1,219  
Revisions in estimated cash flows
     239       146  
 
            
Ending asset retirement obligations
   $ 22,264     $ 20,734  
 
            

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Results of Operations
     As a result of the Transaction in 2005, the results of operations for the periods subsequent to August 15, 2005 are not necessarily comparable to those prior to August 16, 2005. The table below combines the Predecessor I Company 227 day period ended August 15, 2005 with the Successor Company 138 day period ended December 31, 2005 for purposes of the discussion of 2005 results, which is a non-GAAP presentation. 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.
                                                 
    Year Ended December 31,
    2007   2006   2005
Revenues
                                                
Oil and gas sales
   $ 114,427       91.1 %   $ 147,122       92.5 %   $ 141,354       91.3 %
Gas gathering and marketing
     10,275       8.2       11,294       7.1       12,990       8.4  
Other
     954       0.7       674       0.4       450       0.3  
             
 
     125,656       100.0       159,090       100.0       154,794       100.0  
 
                                                
Expenses
                                                
Production expense
     24,585       19.6       23,692       14.9       23,413       15.1  
Production taxes
     2,265       1.8       2,404       1.5       3,416       2.2  
Gas gathering and marketing
     8,640       6.9       9,360       5.9       11,110       7.2  
Exploration expense
     1,935       1.5       1,797       1.1       3,653       2.4  
General and administrative expense
     8,236       6.6       9,796       6.2       6,127       3.9  
Depreciation, depletion and amortization
     36,087       28.7       38,074       23.9       34,450       22.3  
Inpairment of oil and gas properties
     31       —       546       0.3       —       —  
Accretion expense
     1,290       1.0       1,226       0.8       1,152       0.7  
Derivative fair value loss (gain)
     78,120       62.2       (37,356 )     (23.5 )     13,312       8.6  
Transaction expense
     —       —       —       —       7,542       4.9  
             
 
     161,189       128.3       49,539       31.1       104,175       67.3  
             
Operating (loss) income
     (35,533 )     (28.3 )     109,551       68.9       50,619       32.7  
Other (income) expense
                                                
(Gain) on early extinguishment of debt
     —       —       (436 )     (0.3 )     —       —  
Interest expense
     23,712       18.9       23,553       14.8       24,468       15.8  
             
(Loss) income before income taxes
     (59,245 )     (47.2 )     86,434       54.1       26,151       16.9  
(Benefit) provision for income taxes
     (23,923 )     (19.0 )     34,235       21.5       8,908       5.8  
             
Net (loss) income
     (35,322 )     (28.2 )     52,199       32.6       17,243       11.1  
             

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     The following Management’s Discussion and Analysis is based on the results of operations from continuing operations, unless otherwise noted. See Note 4 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. The average prices shown in the table include the effects of our qualified effective hedging activities.
                         
    Year Ended December 31,
    2007   2006   2005
Production
                        
Gas (MMcf)
     13,357       14,104       14,560  
Oil (Mbbl)
     348       373       358  
Total production (MMcfe)
     15,446       16,340       16,710  
Average price (1)
                        
Gas (per Mcf)
   $ 6.81     $ 8.77     $ 8.57  
Oil (per Bbl)
     67.42       62.78       46.37  
Per Mcfe
     7.41       9.00       8.46  
Average costs (per Mcfe)
                        
Production expense
   $ 1.59     $ 1.45     $ 1.40  
Production taxes
     0.15       0.15       0.20  
Depletion
     2.31       2.30       2.01  
 
(1)   The average prices presented above include non-cash amounts related to our derivatives as a result of purchase accounting for the Merger and the Transaction. Excluding these non-cash amounts from oil and gas sales revenues would result in the following average prices:
                         
    Year Ended December 31,
    2007   2006   2005
Gas (per Mcf)
   $ 7.34     $ 7.22     $ 6.99  
Oil (per Bbl)
     67.42       62.78       45.38  
Per Mcfe
     7.87       7.67       7.06  
2007 Compared to 2006
Revenues
     Net operating revenues decreased from $159.1 million in 2006 to $125.7 million in 2007. The decrease was due to lower gas sales revenues of $32.8 million and lower gas gathering and marketing revenues of $1.0 million.
     Gas volumes sold decreased 747 MMcf (5%) from 14.1 Bcf in 2006 to 13.4 Bcf in 2007 resulting in a decrease in gas sales revenues of approximately $6.6 million. Oil volumes sold decreased approximately 25,000 Bbls (7%) from 373,000 Bbls in 2006 to 348,000 Bbls in 2007 resulting in a decrease in oil sales revenues of approximately $1.5 million. The lower oil and gas sales volumes are due to normal production declines and a lower level of drilling in 2007, which was partially offset by production from new wells drilled in 2007.
     The average price realized for our natural gas decreased $1.96 per Mcf to $6.81 per Mcf in 2007 compared to 2006, which decreased gas sales revenues by approximately $26.2 million. As a result of our qualified effective hedging activities, gas sales revenues were lower by $7.1 million ($0.53 per Mcf) in 2007 and higher by $18.7 million ($1.33 per Mcf) in 2006

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than if our gas was not hedged. The average price realized for our oil increased from $62.78 per Bbl in 2006 to $67.42 per Bbl in 2007, which increased oil sales revenues by approximately $1.6 million. As of July 1, 2006, we determined that our gas derivatives no longer qualified for cash flow hedge accounting. Changes in the fair value of the gas derivatives from that date forward are recorded in derivative fair value gain/loss. Deferred gains or losses on these gas derivatives are recognized as increases or decreases to gas sales revenues during the same periods in which the underlying forecasted transactions impact earnings.
     The decrease in gas gathering and marketing revenues was due to a $781,000 decrease in gas marketing revenues and a $238,000 decrease in gas gathering revenues. The lower marketing revenues were primarily the result of lower gas prices. The decrease in gas gathering revenues was primarily due to lower margins on a gathering system in Pennsylvania.
Costs and Expenses
     Production expense increased from $23.7 million in 2006 to $24.6 million in 2007. Production expense in 2006 includes $385,000 ($0.02 per Mcfe) due to recording the cost associated with the selling of purchased oil inventory as a result of purchase accounting for the Transaction. Oil inventory was recorded at fair value of approximately $60.50 per Bbl as of August 16, 2005. Excluding the impact of this oil inventory adjustment, production expense increased by approximately $1.3 million in 2007 compared to 2006. This increase was primarily due to higher fuel costs, increases in labor and oilfield service costs and increased workover expense. The average production cost increased from $1.45 per Mcfe in 2006 to $1.59 per Mcfe in 2007 due to these cost increases and the lower oil and gas sales volumes in 2007.
     Production taxes decreased $139,000 from $2.4 million in 2006 to $2.3 million in 2007, primarily due to lower gas prices in Michigan, where production taxes are based on a percentage of revenues, excluding the effects of hedging. Average per unit production taxes were $0.15 per Mcfe in 2006 and 2007.
     Gathering and marketing expense decreased $720,000 from $9.4 million in 2006 to $8.6 million in 2007 primarily due to lower gas marketing costs as a result of lower gas prices in 2007.
     Exploration expense increased $138,000 from $1.8 million in 2006 to $1.9 million in 2007. The increase was primarily due to an increase in expired lease expense.
     General and administrative expense decreased $1.6 million from 2006 to 2007 primarily due to expenses related to the Transaction recorded in 2006 and decreased compensation related expenses in 2007. In 2006, we expensed approximately $1.0 million for costs associated with the transition of accounting and administrative functions to EverVest’s Charleston, West Virginia office and approximately $355,000 related to the restatement of our 2005 Form 10-K and Forms 10-Q.
     Depreciation, depletion and amortization decreased by $2.0 million from $38.1 million in 2006 to $36.1 million in 2007. This decrease was primarily due to a decrease in depletion expense. Depletion expense decreased $1.9 million from $37.6 million in 2006 to $35.7 million in 2007 due to lower volumes produced. Depletion per Mcfe increased from $2.30 per Mcfe in 2006 to $2.31 per Mcfe in 2007.
     Derivative fair value gain/loss was a loss of $78.1 million in 2007 compared to a gain of $37.4 million in 2006. 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, the ineffective portion of crude oil swaps through August 15, 2005 and the ineffective portion of natural gas swaps as a result of purchase accounting. Our oil derivatives did not qualify for cash flow hedge accounting following the Transaction and, therefore, changes in fair value were reflected in derivative fair value gain/loss in 2006. As of July 1, 2006, we determined that our gas derivatives no longer qualified for cash flow hedge accounting and, therefore, changes in fair value subsequent to that date are reflected in derivative fair value gain/loss.
     Interest expense increased $159,000 from $23.6 million in 2006 to $23.7 million in 2007. This increase was due to an increase in average outstanding borrowings and slightly higher blended interest rates.
     Income tax expense decreased from $34.2 million in 2006 to a benefit of $23.9 million in 2007. The decrease in income tax expense was primarily due to a decrease in the net income before income taxes in 2007.

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2006 Compared to 2005
Revenues
     Net operating revenues increased from $154.8 million in 2005 to $159.1 million in 2006. The increase was due to higher oil sales revenues of $6.8 million, partially offset by lower gas sales revenues of $1.0 million and lower gas gathering and marketing revenues of $1.7 million.
     Gas volumes sold decreased 456 MMcf (3%) from 14.6 Bcf in 2005 to 14.1 Bcf in 2006 resulting in a decrease in gas sales revenues of approximately $3.9 million. Oil volumes sold increased approximately 15,000 Bbls (4%) from 358,000 Bbls in 2005 to 373,000 Bbls in 2006 resulting in an increase in oil sales revenues of approximately $670,000. The lower gas sales volumes are due to normal production declines partially offset by production from new wells drilled in 2006. The increase in oil sales volumes sold was primarily due to production from new wells drilled during 2006 in the Clarendon Formation in Pennsylvania, partially offset by normal production declines.
     The average price realized for our natural gas increased $0.20 per Mcf to $8.77 per Mcf in 2006 compared to 2005, which increased gas sales revenues by approximately $2.9 million. As a result of our qualified effective hedging activities, gas sales revenues were higher by $18.7 million ($1.33 per Mcf) in 2006 and lower by $6.6 million ($0.46 per Mcf) in 2005 than if our gas was not hedged. The average price realized for our oil increased from $46.37 per Bbl in 2005 to $62.78 per Bbl in 2006, which increased oil sales revenues by approximately $6.1 million. As a result of our qualified effective hedging activities, oil sales revenues were lower by approximately $2.5 million ($7.00 per Bbl) in 2005 than if our oil was not hedged. Our oil derivatives did not qualify for cash flow hedge accounting following the Transaction and, therefore, did not affect oil sales revenues in 2006. As of July 1, 2006, we determined that our gas derivatives no longer qualified for cash flow hedge accounting. Changes in the fair value of the gas derivatives from that date forward are recorded in derivative fair value gain/loss. Deferred gains or losses on these gas derivatives are recognized as increases or decreases to gas sales revenues during the same periods in which the underlying forecasted transactions impact earnings.
     The decrease in gas gathering and marketing revenues was due to a $1.3 million decrease in gas marketing revenues and a $349,000 decrease in gas gathering revenues. The lower marketing revenues were primarily the result of lower gas prices. The decrease in gas gathering revenues was primarily due to lower margins on a gathering system in Pennsylvania.
Costs and Expenses
     Production expense increased from $23.4 million in 2005 to $23.7 million in 2006. The average production cost increased from $1.40 per Mcfe in 2005 to $1.45 per Mcfe in 2006 due to the increase in production expense and lower oil and gas sales volumes in 2006. Production expense increased by $1.3 million ($0.08 per Mcfe) in 2005 and by $385,000 ($0.02 per Mcfe) in 2006 due to recording the cost associated with the selling of purchased oil inventory as a result of purchase accounting for the Transaction. Oil inventory was recorded at fair value of approximately $60.50 per Bbl as of August 16, 2005. Excluding the impact of these oil inventory adjustments, production expense increased by approximately $1.2 million in 2006 compared to 2005. This increase was primarily due to increases in labor and oilfield service costs.
     Production taxes decreased $1.0 million from $3.4 million in 2005 to $2.4 million in 2006, primarily due to lower gas prices in Michigan, where production taxes are based on a percentage of revenues, excluding the effects of hedging. Average per unit production taxes decreased from $0.20 per Mcfe in 2005 to $0.15 per Mcfe in 2006, primarily due to the decrease in the selling price of natural gas in 2006, excluding the effects of hedging.
     Gathering and marketing expense decreased $1.7 million from $11.1 million in 2005 to $9.4 million in 2006 primarily due to lower gas marketing costs as a result of lower gas prices in 2006.
     Exploration expense decreased $1.9 million from $3.7 million in 2005 to $1.8 million in 2006. The decrease was primarily due to decreased compensation-related expenses, partially offset by $1.1 million of non-cash write-offs for expired leases and other costs incurred on unproved properties.
     General and administrative expense increased $3.7 million from 2005 to 2006 primarily due to COPAS overhead fees paid to EnerVest. We entered into an operating agreement with EnerVest Operating effective October 1, 2005. Under the terms of the agreement, we pay EnerVest Operating a COPAS overhead fee to cover certain production and administrative

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costs. General and administrative expense includes $642,000 and $5.3 million in COPAS overhead charges from EnerVest Operating in 2005 and 2006, respectively, which offset operating cost reductions following the Transaction.
     Depreciation, depletion and amortization increased by $3.7 million from $34.4 million in 2005 to $38.1 million in 2006. This increase was primarily due to an increase in depletion expense. Depletion expense increased $4.1 million from $33.5 million in 2005 to $37.6 million in 2006 due to a higher depletion rate per Mcfe. Depletion per Mcfe increased from $2.01 per Mcfe in 2005 to $2.30 per Mcfe in 2006, primarily due to a higher cost basis resulting from purchase accounting for the Transaction.
     Derivative fair value gain/loss was a gain of $37.4 million in 2006 compared to a loss of $13.3 million in 2005. 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, the ineffective portion of crude oil swaps through August 15, 2005 and the ineffective portion of natural gas swaps as a result of purchase accounting. Our oil derivatives did not qualify for cash flow hedge accounting following the Transaction and, therefore, changes in fair value were reflected in derivative fair value gain/loss in 2006. As of July 1, 2006, we determined that our gas derivatives no longer qualified for cash flow hedge accounting and, therefore, changes in fair value subsequent to that date are reflected in derivative fair value gain/loss.
     Transaction expenses of $7.5 million related to the Transaction were recorded in the Predecessor I Company period ended August 15, 2005. These expenses include severance payments made to employees, unamortized loan costs written off, professional fees and other transaction expenses.
     Interest expense decreased $915,000 from $24.5 million in 2005 to $23.6 million in 2006. This decrease was due to lower blended interest rates which were partially offset by an increase in average outstanding borrowings.
     Income tax expense increased from $8.9 million in 2005 to $34.2 million in 2006. The increase in income tax expense was primarily due to an increase in the net income before income taxes in 2006 along with a higher effective tax rate.

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Liquidity and Capital Resources
Cash Flows
     We expect that our primary sources of cash in 2008 will be from funds generated from operations, from borrowings under the Amended Credit Agreement and from the sale of non-strategic assets. 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, 2007 were funds generated from operations and from borrowings under our credit facilities. Funds used during this period were primarily used for operations, exploration and development expenditures, the settlement of derivatives and interest expense. Our liquidity and capital resources are closely related to and dependent upon the current prices paid for our oil and natural gas.
     The following table summarizes the net cash flow for the periods presented:
                         
    Year Ended December 31,  
    2007     2006     Change  
    (in millions)  
Cash flows provided by operating activities
   $ 68.1     $ 66.6     $ 1.5  
Cash flows (used in) investing activities
     (23.1 )     (30.2 )     7.1  
Cash flows (used in) financing activities
     (34.9 )     (38.6 )     3.7  
 
 
                  
Net increase (decrease) in cash and cash equivalents
   $ 10.1     $ (2.2 )   $ 12.3  
 
                  
     Our operating activities provided cash flows of $68.1 million during 2007 compared to $66.6 million in 2006. The increase was primarily due to a $6.6 million net increase in operating assets and a decrease of $1.6 million in general and administrative expense which was partially offset by a $6.9 million increase in oil and gas sales revenues excluding the effects of hedging activity.
     Cash flows used in investing activities were $23.1 million in 2007 compared to $30.2 in 2006. This decrease was due to a decrease of $14.1 million in property and equipment additions which was partially offset by a decrease in proceeds from property and equipment disposals of $7.2 million.
     Cash flows used in financing activities in 2007 were $34.9 million compared to $38.6 million in 2006. This decrease was primarily due to the $33.9 million repayment of senior secured notes in 2006 and a decrease in dividends paid of $10.3 million which was partially offset by a $38.9 million decrease in debt proceeds and a $1.6 million increase in the settlement of derivative liabilities.
     During 2007, our working capital decreased $2.6 million from a deficit of $11.6 million at December 31, 2006 to a deficit of $14.2 million at December 31, 2007. The decrease was primarily due to an increase in the current liability for fair value of derivatives of $16.1 million which was partially offset by an increase in the deferred income tax asset of $4.7 million and an increase in cash of $10.1 million.

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Capital Expenditures
     The table below sets forth our total capital expenditures for each of the years ending December 31, 2007, 2006 and 2005.
                         
    Year Ended December 31,  
    2007     2006     2005  
            (in millions)          
Total capital expenditures
                        
Drilling including exploratory dry hole expense
   $ 21     $ 35     $ 26  
Production enhancements and field improvements
     1       1       2  
Leasehold acreage
     1       1       1  
 
                  
Total
   $ 23     $ 37     $ 29  
 
                  
     During 2007, we spent approximately $22.7 million, including exploratory dry hole expense, on our drilling and other capital expenditures. In 2007, we drilled 96 gross (92 net) development wells, all of which were successfully completed as producers in the target formation.
     We plan to spend approximately $34.5 million during 2008 on our drilling activities and other capital expenditures. We intend to finance our planned capital expenditures through our cash on hand, available cash flow, borrowings under our Amended Credit Agreement and, to a lesser extent, the sale of non-strategic assets. At December 31, 2007, and at February 29, 2008, we had approximately $12.6 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 $159.5 million of our Senior Secured Notes outstanding as of December 31, 2007. As a result of the application of purchase accounting, the notes were recorded as a liability based on the estimated fair value of $200.7 million on the Transaction date. In June 2006, we repurchased a portion of the outstanding Senior Secured Notes. The repurchased notes had a face value of $33.025 million and were repurchased at 102.750%. A gain of $436,000 was recorded in 2006 in connection with the transaction. The notes mature July 15, 2012. Interest is payable semi-annually on January 15 and July 15 of each year at 8.75% based on the face amount of $159.5 million (for an effective rate of 7.946% based on the fair value on the Transaction date.) The notes are secured on a second-priority lien on the same assets subject to the liens securing our obligations under the Amended Credit Agreement. The Senior Secured Notes are subject to redemption at our option at specific redemption prices.
         
July 15, 2008
     104.375 %
July 15, 2009
     102.188 %
July 15, 2010 and thereafter
     100.000 %
     The Senior Secured 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 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.

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Amended Credit Agreement
     On August 16, 2005, we amended and restated our then existing $170 million credit agreement, by entering into a First Amended and Restated Credit and Guaranty Agreement (“Amended Credit Agreement”) by and among us and BNP Paribas, as sole lead arranger, sole book runner, syndication agent and administrative agent. The Amended Credit Agreement provides for loans and other extensions of credit to be made to us up to a maximum aggregate principal amount of $390 million. The obligations under the Amended Credit Agreement are secured by substantially all of our assets.
     The Amended Credit Agreement provides for a revolving credit line in the aggregate principal amount of $350 million and a hedge letter of credit facility in the aggregate principal amount of $40 million. Borrowings under the Amended Credit Agreement may not exceed the borrowing base, which was initially set at $80.25 million, of which $57 million was drawn at closing on August 16, 2005. At December 31, 2007, the borrowing base was $113.4 million and the outstanding balance was $99.9 million. This agreement was amended on September 27, 2005 to reduce the percentage of the value of total proved reserves that is required to be mortgaged from 75% to 70%. J.P. Morgan Chase and Amegy Bank became members of the bank group in September 2005.
     Borrowings under the Amended Credit Agreement bear interest (i) at the greater of the prime rate or an adjusted federal funds rate, plus an applicable margin ranging from 0% to 0.625% based on the aggregate principal amount outstanding under the Amended Credit Agreement, or, (ii) at the our option, the Eurodollar base rate plus an applicable margin ranging from 1.125% to 2.125% based on the aggregate principal amount outstanding under the Amended Credit Agreement. The full amount borrowed under the Amended Credit Agreement will mature on August 16, 2010.
     The obligations under the Amended Credit Agreement are secured by a first lien security interest in substantially all of our assets. The obligations under the Amended Credit Agreement are further secured by a pledge of 100% of our capital stock held by Capital C, our parent.
     The Amended Credit Agreement contains covenants that will limit our ability to, among other things, incur or guarantee additional indebtedness; create liens; pay dividends on or repurchase our stock; pay principal and interest on certain subordinated debt; make certain types of investments; sell assets or merge with another entity; pledge or otherwise encumber our capital stock; or enter into transactions with affiliates. The Amended Credit Agreement also requires compliance with customary financial covenants, including a minimum interest coverage ratio, a maximum leverage ratio and a minimum current ratio. On August 3, 2007, our bank group waived the covenant compliance requirement as of June 30, 2007 and amended the Amended Credit Agreement to increase the maximum leverage ratio from 4.0 : 1.0 to 4.25 : 1.0 for the quarters ending on September 30, 2007 and December 31, 2007. If we had not received this waiver, we would not have complied with our leverage ratio covenant as it would have been 4.07 : 1.0 as of June 30, 2007. On March 24, 2008, our bank group waived the covenant compliance requirement as of December 31, 2007 and amended the Amended Credit Agreement to increase the maximum Leverage Ratio to 4.5 : 1.0 through December 31, 2008. If we had not received this waiver, we would not have complied with our Leverage Ratio covenant as it would have been 4.38 : 1.0 as of December 31, 2007.
     Borrowings under the revolving credit line will be used by us for general corporate purposes. In accordance with the terms of the Amended Credit Agreement, letters of credit issued under the hedge letter of credit commitment and any related borrowings are to be used solely to secure payment of our obligations under the J. Aron Swap (defined hereinafter).
     In connection with our entry into the Amended Credit Agreement, we executed a Subordinated Promissory Note (“Subordinated Note”) in favor of Capital C in the maximum principal amount of $94 million. Under the Subordinated Note, Capital C loaned $25 million to us on August 16, 2005. The Subordinated Note accrues interest at a rate of 10% per annum and matures on August 16, 2012. We received a fairness opinion from an unrelated financial services firm with respect to the terms of the Subordinated Note made on August 16, 2005. Interest payments on the Subordinated Note are due quarterly commencing September 30, 2005. In lieu of cash payments, we have the option to make interest payments on the Subordinated Note by borrowing additional amounts against the Subordinated Note. The interest payments in 2005, 2006 and the first quarter of 2007 were paid in cash. Interest payments for the last three quarters of 2007 were made by additional borrowings against the Subordinated Note. The Subordinated Note has no prepayment penalty or premium and may be prepaid in whole or in part at any time. The Subordinated Note is expressly subordinate to our senior debt, which includes obligations under the Amended Credit Agreement, the J. Aron Swap and the Senior Secured Notes.

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ISDA Master Agreement
     In connection with the Transaction, we amended and restated the Schedule and Credit Support Annex to our ISDA Master Agreement, dated as of June 30, 2004, by and between us and J. Aron & Company (“J. Aron Swap”), pursuant to which we have agreed, from time to time, to enter into cash-settled hedge transactions with J. Aron & Company, as hedge counterparty, in connection with various gas and oil commodity derivatives transactions. The amendments to the J. Aron Swap conform the terms of the Schedule and Credit Support Annex to the terms of the Amended Credit Agreement, change certain covenants and reduce the maximum amount of the letter of credit securing the hedge obligations from $55 million to $40 million.
     From time to time, we may enter into interest rate swaps to hedge the interest rate exposure associated with the credit facility, whereby a portion of our floating rate exposure is exchanged for a fixed interest rate. At December 31, 2005 and 2006, we had interest rate swaps in place covering $40 million and $80 million, respectively, of our outstanding debt under the revolving credit facility that mature on September 16, 2008. At December 31, 2007, we had interest rate swaps in place covering $80 million of our outstanding debt under the revolving credit facility that mature between September 16, 2008 and September 30, 2010.
     At December 31, 2007, the aggregate long-term debt maturing in the next five years is as follows: $8,000 (2008); $8,000 (2009); $99.9 million (2010); $10,000 (2011) and $186.5 million (2012 and thereafter).
Derivative Instruments
     The Hedges
     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.
     On July 7, 2004, the date of the Merger, we became a party to long-term commodity hedges (the “Hedges”) with J. Aron pursuant to a master agreement and related confirmations and documentation (collectively, the “Hedge Agreement”.) We anticipate that the Hedges will cover approximately 63% of the expected 2008 through 2013 production from our current estimated proved reserves and will range from 55% to 75% 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 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 Secured 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 Amended Credit Agreement, with an aggregate capitalization of $40 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 Amended Credit Agreement and the Senior Secured 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 Amended Credit Agreement and the Senior Secured Notes and are guaranteed by the same subsidiaries that guarantee the Senior Facilities and the Senior Secured 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 Amended Credit Agreement and the Senior Secured Notes.
     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.

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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. These contracts were settled during 2005.
     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 derivative positions by entering into new transactions. The following tables reflect the natural gas and crude oil volumes and the weighted average prices under financial derivatives (including settled contracts) at December 31, 2007. We have not entered into any additional derivative transactions since December 31, 2007.
                                                 
    Natural Gas Swaps   Crude Oil Swaps   Natural Gas Basis Swaps
            NYMEX           NYMEX            
            Price per   Estimated   Price per           Basis
Year Ending   Bbtu   Mmbtu   Mbbls   Bbl   Bbtu   Differential
December 31, 2008
    10,126     $ 4.64       208     $ 29.96       —     $ —  
December 31, 2009
    9,529       4.43       191       29.34       3,650       0.345  
December 31, 2010
    8,938       4.28       175       28.86       3,650       0.325  
December 31, 2011
    8,231       4.19       157       28.77       3,285       0.325  
December 31, 2012
    7,005       4.09       138       28.70       —     —
December 31, 2013
    6,528       4.04       127       28.70       —     —
     At December 31, 2007, the fair value of futures contracts covering 2008 through 2013 oil and gas production represented an unrealized loss of $235.4 million. Commodity prices have increased since December 31, 2007 and, as a result, the fair value of our oil and gas derivatives as of February 29, 2008 was an unrealized loss of approximately $281.5 million.
     At December 31, 2007, we had interest rate swaps in place on $80 million of our outstanding debt under the revolving credit facility through September 30, 2010. The swaps provide 1-month LIBOR fixed rates at 4.285% on $40 million and 5.160% on $40 million through September 2008 and 4.07% on $80 million from September 2008 through September 2010, plus the applicable margin. At December 31, 2007, the fair value of the interest rate swaps represented an unrealized loss of $912,000.
Inflation and Changes in Prices
     The average price realized for our natural gas increased from $8.57 per Mcf in 2005 to $8.77 per Mcf in 2006, and decreased to $6.81 in 2007. The average price realized for our oil increased from $46.37 per Bbl in 2005 to $62.78 per Bbl in 2006 and increased to $67.42 per Bbl in 2007. These prices reflect average prices for oil and gas sales of our continuing operations. The prices include the effect of our qualified effective oil and gas hedging activity.
     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.

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     The following table summarizes our contractual obligations at December 31, 2007.
                                         
    Payments Due by Period  
          Less than 1                     After  
Contractual Obligations at December 31, 2007   Total     Year     1 - 3 Years     4 - 5 Years     5 Years  
                    (in thousands)                  
Long-term debt
   $ 286,361     $ 8     $ 99,893     $ 186,428     $ 32  
Capital lease obligations
     2       2       —       —       —  
Asset retirement obligations
     22,264       359       3,306       444       18,155  
Derivative liabilities
     236,291       44,592       92,421       71,187       28,091  
Interest on debt
     94,612       24,047       44,702       25,863       —  
Operating leases
     10,792       4,330       6,462       —       —  
 
                              
Total contractual cash obligations
   $ 650,322     $ 73,338     $ 246,784     $ 283,922     $ 46,278  
 
                              
     In addition to the items above, 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, 2007.
                                         
            Amount of Commitment Expiration Per Period  
    Total                              
  Amounts     Less than 1                     Over 5  
Commercial Commitments at December 31, 2007   Committed     Year     1 - 3 Years     4 - 5 Years     years  
    (in thousands)  
Standby Letters of Credit
   $ 40,850     $ 40,850     $ —     $ —     $ —  
 
                              
Total Commercial Commitments
   $ 40,850     $ 40,850     $ —     $ —     $ —  
 
                              
     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.
     Off-Balance Sheet Arrangements
     We have $40.9 million in letters of credit as described above.
NEW ACCOUNTING STANDARDS
     In July 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement 109” (“FIN 48”), which clarifies the accounting for uncertainty in tax positions taken or expected to be taken in a tax return, including issues relating to financial statement recognition and measurement. FIN 48 provides that the tax effects from an uncertain tax position can be recognized in the financial statements only if the position is “more-likely-than-not” to be sustained if the position were to be challenged by a taxing authority. The assessment of the tax position is based solely on the technical merits of the position, without regard to the likelihood that the tax position may be challenged. If an uncertain tax position meets the “more-likely-than-not” threshold, the largest amount of tax benefit that is more than 50 percent likely to be recognized upon ultimate settlement with the taxing authority is recorded. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. Consistent with the requirements of FIN 48, we adopted FIN 48 on January 1, 2007. The adoption of FIN 48 did not have a material impact on our financial statements.
     FIN 48 requires us to evaluate whether any material tax position we have taken will more likely than not be sustained upon examination by the appropriate taxing authority. As we believe that all such material tax positions taken by us are supportable by existing laws and related interpretations, there are no material uncertain tax positions to consider in accordance with FIN 48.
     Since we have no unrecognized tax benefits as of December 31, 2007, there is no potential impact on our effective tax rate.
     To the extent penalties and interest would be assessed on any underpayment of income tax, such amounts have been accrued and classified as a component of income tax expense in the financial statements. This is an accounting policy election made by us that is a continuation of our historical policy and will continue to be consistently applied in the future. As of December 31, 2007, we have not accrued any interest and penalties related to unrecognized tax benefits.
     We do not anticipate a significant change in the balance of unrecognized tax benefits within the next 12 months.
     In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, Fair Value Measurements, to provide guidance for using fair value to measure assets and liabilities. SFAS No. 157 establishes a fair value hierarchy and clarifies the principle that fair value should be based on assumptions market participants would use when pricing the asset or liability. SFAS No. 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. SFAS No. 157 was to be effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years; however, in February 2008, the FASB issued FASB Staff Position FAS 157—2, Effective Date of FASB Statement No. 157, which delayed the effective date of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis, for one year. We adopted SFAS No. 157 on January 1, 2008 for our financial assets and financial liabilities, and the adoption did not have a material impact on our consolidated financial statements. We will adopt SFAS No. 157 on January 1, 2009 for our nonfinancial assets and nonfinancial liabilities, and we have not yet determined the impact, if any, on our consolidated financial statements.
     In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. Unrealized gains and losses on items for which the fair value option has been selected are reported in earnings. SFAS No. 159 also establishes

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presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. At the present time, we do not expect to apply the provisions of SFAS No. 159.
     In December 2007, the FASB issued SFAS No 141 (Revised 2007), Business Combinations (“SFAS No. 141(R)”) to significantly change the accounting for business combinations. Under SFAS No. 141(R), an acquiring entity will be required to recognize all the assets acquired and liabilities assumed in a transaction at the acquisition date fair value with limited exceptions and will change the accounting treatment for certain specific items, including:
  •   acquisition costs will generally be expensed as incurred;
 
  •   noncontrolling interests will be valued at fair value at the date of acquisition; and
 
  •   liabilities related to contingent consideration will be recorded at fair value at the date of acquisition and subsequently remeasured each subsequent reporting period. SFAS No. 141(R) is effective for fiscal years beginning after December 15, 2008. We will adopt SFAS No. 141(R) on January 1, 2009, and we have not yet determined the impact, if any, on our consolidated financial statements.
In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — An Amendment of ARB No. 51, to establish new accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 requires the recognition of a noncontrolling interest (minority interest) as equity in the consolidated financial statements and separate from the parent’s equity. The amount of net income attributable to the noncontrolling interest will be included in consolidated net income on the face of the income statement. SFAS No. 160 clarifies that changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation are equity transactions if the parent retains its controlling financial interest. In addition, SFAS No. 160 requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS No. 160 also includes expanded disclosure requirements regarding the interests of the parent and its noncontrolling interest. SFAS No. 160 is effective for fiscal years beginning after December 15, 2008. We will adopt SFAS No. 160 on January 1, 2009, and we have not yet determined the impact, if any, on our consolidated financial statements.
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. At December 31, 2007, we had interest rate swaps in place on $80 million of our outstanding debt under the revolving credit facility through September 30, 2010. The swaps provide 1-month LIBOR fixed rates at 4.285% on $40 million and 5.160% on $40 million through September 2008 and 4.07% on $80 million from September 2008 through September 2010, plus the applicable margin. If market interest rates for short-term borrowings increased 1%, the increase in our annual interest expense would be approximately $198,000. This sensitivity analysis is based on our financial structure at December 31, 2007.
     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 oil and gas production 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. At December 31, 2007, we had derivatives covering a portion of our oil and gas production from 2008 through 2013. Our oil and gas sales revenues included a net pre-tax gain of $18.7 million in 2006 and a net pre-tax loss of $7.1 million in 2007 on our qualified hedging activities.

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     We determined that as of August 15, 2005, our oil derivatives no longer qualify for cash flow hedge accounting and as of July 1, 2006, our gas derivatives no longer qualify for cash flow hedge accounting. From those dates forward, changes in the fair value of the oil and gas derivatives are recorded in derivative fair value gain/loss. Deferred gains or losses on the gas derivatives are recognized as increases or decreases to gas sales revenues during the same periods in which the underlying forecasted transactions impact earnings. If gas prices decreased $1.00 per Mcf, our gas sales revenues would decrease by approximately $13.3 million. If the price of crude oil decreased $10.00 per Bbl, our oil sales revenues would decrease by approximately $3.5 million. The impact of these price decreases on our cash flows would be significantly less than these amounts due to our oil and gas derivatives. Price decreases of $1.00 per Mcf and $10.00 per Bbl would decrease cash flows from the sale of oil and gas by approximately $4.5 million after considering the effects of the derivative contracts in place as of December 31, 2007. This sensitivity analysis is based on our 2007 oil and gas sales volumes.
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
     There were no changes in or disagreements with accountants on accounting or financial disclosures during the years ended December 31, 2007 or 2006.
Item 9A. CONTROLS AND PROCEDURES
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
     Management, including our Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over our financial reporting. Our internal control system was designed to provide reasonable assurance to our Management and Directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
     Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Belden & Blake Corporation’s internal control over financial reporting was effective as of December 31, 2007.
     
/s/ Mark A. Houser
  /s/ James M. Vanderhider
 
   
Mark A. Houser
  James M. Vanderhider
Chief Executive Officer, Chairman of the
  President, Chief Financial Officer and Director
Board of Directors and Director
    
Houston, TX
March 28, 2008

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Evaluation of Disclosure Controls and Procedures
     In accordance with Exchange Act Rule 13a—15 and 15d—15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. 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, 2007 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to provide reasonable assurance that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
Management’s Annual Report On Internal Control Over Financial Reporting
     Our management is responsible for establishing and maintaining an adequate system of internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control system was designed to provide reasonable assurance to our management and board of directors of our general partner regarding the preparation and fair presentation of published financial statements.
     All internal control systems, no matter how well designed, have inherent limitations. Therefore, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies and procedures may deteriorate.
     Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, has conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2007 based on the framework in “Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.” Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2007.
     Changes in Internal Control Over Financial Reporting
     There were no changes in the internal control over financial reporting that occurred during the year ended December 31, 2007 that materially affected, or that are reasonably likely to materially affect, internal control over financial reporting.
Item 9B. OTHER INFORMATION
     Not applicable.

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PART III
Item 10.   DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT AND CORPORATE GOVERNANCE
     Our executive officers and directors and their respective positions and ages of as of March 5, 2008 were as follows:
             
Name   Age   Position
Mark A. Houser
    46     Chief Executive Officer and Chairman of the Board of Directors
 
            
James M. Vanderhider
    49     President, Chief Financial Officer and Director
 
            
Kenneth Mariani
    46     Senior Vice President, Chief Operating Officer and Director
 
            
Frederick J. Stair
    48     Vice President of Accounting
 
            
Barry K. Lay
    51     Vice President of Operations
 
            
Sandra K. Fraley
    42     Vice President of Land and Legal and Secretary
 
            
David M. Elkin
    42     Vice President of Engineering
 
            
Mark L. Barnhill
    52     Vice President of Exploration
 
            
Matthew Coeny
    37     Director
     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 four members. The business experience of each executive officer and director is summarized below.
     Mark A. Houser. On August 16, 2005, Mr. Houser was appointed our Chief Executive Officer and Chairman of the Board of Directors. Since 2006, Mr. Houser has served as EV Management, LLC’s President, COO and Director. EV Management is the general partner of the general partner of EV Energy Partners, LP. Since 1999, Mr. Houser has been the Executive Vice President and Chief Operating Officer of EnerVest, Ltd. Prior to that, Mr. Houser was Vice President, United States Exploration and Production, for Occidental Petroleum Corporation, or Oxy, where he helped lead Oxy’s reorganization of its domestic reserve base. Mr. Houser began his career as an engineer with Kerr—McGee Corporation. He holds a petroleum engineering degree from Texas A&M University and an MBA from Southern Methodist University.
     James M. Vanderhider. Mr. Vanderhider is our President and Chief Financial Officer. Prior to that he served as President and Chief Operating Officer since his appointment on August 16, 2005. Mr. Vanderhider has been a director since August 16, 2005. He also serves as Executive Vice President and Chief Financial Officer of EnerVest and has been with EnerVest since March 1996. Prior to joining EnerVest, Mr. Vanderhider was Executive Vice President and Chief Financial Officer of Torch Energy and Senior Vice President and Chief Financial Officer of Nuevo Energy. Prior to such time, Mr. Vanderhider was a management member of the Internal Audit department of The Coastal Corporation, now a subsidiary of El Paso Corporation. He also held the position of Chief Financial Officer of Walker Energy Partners, a master limited partnership which he helped form. Mr. Vanderhider began his career with Deloitte and Touche in the audit department focusing on the energy industry.
     Mr. Vanderhider received a B.B.A. degree in Accounting from Texas A&M University where he graduated summa cum laude. He is a Certified Public Accountant. Mr. Vanderhider is a native Houstonian and is actively involved with several industry and social organizations. He is a member of the Independent Petroleum Association of America, the American Institute of Certified Public Accountants, Houston Producers’ Forum, Texas Society of Certified Public Accountants, Houston Energy Finance Group, and Houston Acquisitions and Divestitures Organization. He serves on the

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Board of Trustees of Goodwill Industries of Houston and on the Board of Directors of the Houston Center Club, a social and athletic club.
     Kenneth Mariani. On October 3, 2005, Mr. Mariani was appointed Senior Vice President and Chief Operating Officer. He has been a director since August 16, 2005. Mr. Mariani is also Senior Vice President, Eastern Division, for EnerVest and Executive Vice President of CGAS Exploration, Inc., a privately-held oil and gas company owned by certain institutional funds managed by EnerVest. Prior to joining EnerVest in 2000, he served as Vice President of Operations for Energy Corporation of America.
     Mr. Mariani holds a degree in Chemical Engineering from the University of Pittsburgh, graduating cum laude with a Petroleum option. He received his MBA degree from the University of Texas and is a Certified Professional Engineer. Mr. Mariani is an active member of the Independent Oil and Gas Association of West Virginia, recently serving on the Board of Directors, Commerce Committee and Safety Committee. In 2003, he was acting Vice President and Program Chair of this organization. He is past Chairman of the Society of Petroleum Engineers and a member of IPAA. Currently, Mr. Mariani serves on the Board of Directors for the Michigan Oil and Gas Association and the Ohio Oil and Gas Association. He is also active in the Independent Oil and Gas Association of Pennsylvania, the Independent Oil and Gas Association of New York and the Kentucky Oil and Gas Association.
     Frederick J. Stair. Mr. Stair is Vice President of Accounting and has been our Vice President since January 2003. He previously served as our Corporate Controller from 1997 to 2005 and as Controller of the Exploration and Production Division from 1991 to 1997. Mr. Stair joined us in 1981 and has 26 years of accounting experience in the oil and gas industry. Mr. Stair is also Vice President of Accounting – Eastern Division for EnerVest. 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.
     Barry K. Lay. Mr. Lay was appointed as Vice President of Operations effective August 10, 2007. Mr. Lay served as Vice President of Land and Secretary from October 16, 2006 until August 10, 2007. Prior to that he served as Vice President and General Manager of our Pennsylvania/New York District. Prior to joining us in 2002, Mr. Lay was Vice President of Engineering for Waco Oil and Gas Company. He also serves as Vice President of Operations – Eastern Division for EnerVest.
     Mr. Lay has 30 years of experience in the oil and gas industry. Mr. Lay graduated from West Virginia University with a Bachelor of Science degree in Petroleum Engineering. He serves as Chairman for numerous State oil and gas regulatory boards including the West Virginia Oil and Gas Conservation Commission, West Virginia Coal Bed Methane Review Board and the West Virginia Shallow Gas Well Review Board. Mr. Lay is a registered Professional Engineer and a licensed Land Surveyor in the State of West Virginia.
     Sandra K. Fraley. Ms. Fraley was appointed as Vice President of Land and Legal and Secretary effective August 10, 2007. Ms. Fraley also serves as Vice President of Land/Legal and General Counsel for the Eastern Division of EnerVest. Prior to joining EnerVest in 2007, Ms. Fraley served as Vice President and General Counsel of Equitable Production Company.
     Ms. Fraley holds a B.A. from Eastern Kentucky University and a J.D. from the University of Kentucky. Ms. Fraley currently serves on the Board of Trustees for the Energy and Mineral Law Foundation and the Board of Directors for the Kentucky Oil and Gas Association.
     David M. Elkin. Mr. Elkin was appointed Vice President of Engineering on October 16, 2006. He also serves as Vice President of Engineering – Eastern Division for EnerVest. Mr. Elkin joined EnerVest in 2003. He holds a Bachelor of Science in Petroleum and Natural Gas Engineering from The Pennsylvania State University. Prior to joining EnerVest, Mr. Elkin was employed for 17 years with Energy Corporation of America, rising to the position of Vice President of Operations. Mr. Elkin is a member of the Independent Oil and Gas Associations in West Virginia, Pennsylvania, New York, Ohio, Kentucky and Michigan. He is also a member and past officer of the Society of Petroleum Engineers. Mr. Elkin has drilled and operated production in the Appalachian, Michigan, and Powder River basins of North America, as well as the Wairoa basin of New Zealand.
     Mark L. Barnhill. Mr. Barnhill was appointed Vice President of Exploration on October 16, 2006. He also serves as Vice President of Exploration for EnerVest. Mr. Barnhill joined EnerVest in 2001. Prior to joining EnerVest, he was

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Exploration Manager for Energy Corporation of America. Mr. Barnhill has worked as both a geologist and a geophysicist for Texaco, Inc. and Cotton Petroleum. He holds a Bachelor of Science degree in Geology from Wright State University, a Master of Science in Geology from The University of Tulsa, and a Ph.D. in Geology from The University of Cincinnati.
     Mr. Barnhill was a Visiting Research Scientist at Indiana University/Indiana Geological Survey from 1991 to 1994 where he headed several research projects for the Department of the Navy. He is a member of the American Association of Petroleum Geologists, the Independent Oil and Gas Association of West Virginia, the Independent Oil and Gas Association of Pennsylvania, the Ohio Oil and Gas Association and the Michigan Oil and Gas Association. Mr. Barnhill has given numerous talks at major association meetings both nationally and internationally.
     Matthew Coeny. On August 16, 2005, Mr. Coeny was elected to our Board of Directors. Mr. Coeny is a Director of Citigroup Private Equity (“CPE”). CPE is a business unit of Citigroup Inc. (“Citigroup”) and is responsible for private equity investments, mezzanine debt investments and private equity partnership commitments on behalf of Citigroup affiliates and clients. Since joining CPE in 2000, he has participated in the evaluation, due diligence and execution of investments in a variety of industries. Prior to joining CPE, Mr. Coeny worked in Citigroup’s Investment Banking Division where he participated in numerous advisory and capital raising transactions. Prior to joining Citigroup in 1996, he was a Senior Consultant in KPMG’s Corporate Transactions practice. Mr. Coeny received a Bachelor of Science degree in Finance and Accounting from New York University.
Audit Committee
     Our full Board of Directors serves as our Audit Committee.
Code of Ethics
     We have adopted a Code of Ethics that applies to our Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer, Vice President of Accounting and any person performing similar functions. It is available without charge upon oral or written request, by contacting:
Belden & Blake Corporation
1001 Fannin Street, Suite 800
Houston, Texas 77002
Attention: Sandra Fraley, Secretary
Telephone: (713) 659-3500

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Item 11. EXECUTIVE COMPENSATION
     All of our executive officers are full-time employees of EnerVest and its subsidiaries. We have entered into an operating agreement with a subsidiary of EnerVest (described in Item 13). Pursuant to the operating agreement, we pay EnerVest a fee to operate our business, and EnerVest provides us the services of its employees, including our executive officers, to operate our business. The fee we pay to EnerVest does not include any direct reimbursement for the salaries, bonuses or other compensation paid by EnerVest to the EnerVest employees which act as our executive officers. Therefore, no executive officers of Belden & Blake received any remuneration from Belden & Blake Corporation during 2007.
Compensation of Directors
     Our directors are not compensated. We have no independent directors, as independence is defined by the New York Stock Exchange.
Compensation Committee Interlocks and Insider Participation
     We do not have a compensation committee. As of December 31, 2007, none of our officers are compensated by us.

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Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS, MANAGEMENT AND RELATED STOCKHOLDER MATTERS
     The following table sets forth certain information as of March 5, 2008 regarding the beneficial ownership of our common stock by each person who beneficially owns more than five percent of our outstanding common stock, each director, the Chief Executive Officer and the four other most highly compensated executive officers and by all of our directors and executive officers, as a group:
                 
            Percentage of
Five Percent Shareholders   Number of Shares   Shares
Capital C Energy Operations, LP (1)
1001 Fanin Street, Suite 800
Houston, Texas 77002
     1,534       100.0 %
 
(1)   Subsidiaries of EnerVest, Ltd., are the general partners of the limited partnership that owns Capital C Energy Operations, L.P. EnerVest, therefore, also may be deemed to be a beneficial owner of the 1,534 shares (100%) of our Common Stock. The address of EnerVest, Ltd., is 1001 Fannin Street, Suite 800, Houston, Texas 77002. EnerVest is a Texas limited partnership. Messrs. John B. Walker, Jon Rex Jones and A.V. Jones by virtue of their direct and indirect ownership of the limited liability company that acts as EnerVest’s general partner, may be deemed to beneficially own the Common Stock beneficially owned by EnerVest. Messrs. Walker, John Rex Jones and A.V. Jones disclaim beneficial ownership of such Common Stock. The addresses for Messrs. Walker, Jon Rex Jones and A.V. Jones are the same as for EnerVest.
Equity Compensation Plan Information:
     As of March 5, 2008, we do not have an equity compensation plan.

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Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
     On March 15, 2006, we entered into a joint operating agreement with EnerVest Operating L.L.C. (“EnerVest Operating”), a subsidiary of EnerVest. Amounts paid to EnerVest Operating under the terms of the agreement were $6.0 million for overhead fees, $7.5 million for field labor, vehicles and district office expense, $331,000 for drilling overhead fees and $1.2 million for drilling labor costs in 2007.
     As of December 31, 2007, we owed EnerVest Operating $1,531,000 and EnerVest owed us $23,000.
     In connection with the Transaction, we executed a subordinated promissory note in favor of our parent, Capital C in the maximum amount of $94 million. Under the note, Capital C loaned $25 million to us on August 16, 2005 in connection with the Transaction. The note accrues interest at 10% per year and matures on August 16, 2012. We received a fairness opinion from an unrelated financial services firm with respect to the terms of the note made on August 16, 2005. Interest payments on the note are due quarterly commencing September 30, 2005. In lieu of cash payments, we have the option to make interest payments on the note by borrowing additional amounts against the note. The amount due under the note at December 31, 2007 was $26.9 million. We made a cash payment of $616,000 and borrowed an additional $1.9 million for interest payments against the note in 2007.
     Messrs. Houser, Vanderhider and Mariani are officers and directors of the Company and they are officers and equity owners of EnerVest. The institutional funds that are managed by EnerVest and own our direct parent, Capital C, also hold other investments in oil and gas assets and operations. We can give no assurance that conflicts of interest will not arise for 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. Houser, Vanderhider and Mariani.

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Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
     Deloitte & Touche served as our independent auditor for the years ended December 31, 2006 and 2007. Aggregate fees for professional services provided to us by Deloitte & Touche for the years ended December 31, 2007 and 2006 were as follows:
                 
    December 31,  
    2007     2006  
Audit fees
   $ 408,500     $ 390,000  
Audit-related fees
     —       —  
Tax fees
     —       —  
All other fees
     —       1,500  
 
            
 
   $ 408,500     $ 391,500  
 
            
     Fees for audit services include fees associated with the annual audit, the review of our Annual Report on Form 10-K and the reviews of our Quarterly Reports on Form 10-Q. All other fees include research materials. Our Audit Committee approved 100% of these accounting services.
Audit Committee Pre-Approval Policies and Procedures
     The Audit Committee has adopted a policy that requires advance approval of all audit, audit-related, and other services performed by the independent auditor or other public accounting firms. The policy provides for pre-approval by the Audit Committee of specifically defined audit and non-audit services. Unless the specific service has been previously pre-approved with respect to that year, the Audit Committee must approve the permitted service before the independent auditor or public accounting firm is engaged to perform it. The Audit Committee has delegated to the Chairman of the Audit Committee authority to approve permitted services up to $75,000 per year provided that the Chairman reports any decisions to the Committee at its next scheduled meeting. All services of $75,000 or more are required to be approved by a majority of the Committee members.
PART IV
Item 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
     (a) Documents filed as a part of this report:
     1. Financial Statements
     The financial statements listed in the accompanying Index to Consolidated Financial Statements and Schedules are filed as part of this Annual Report on Form 10-K.
     2. Financial Statement Schedules
     No financial statement schedules are required to be filed as part of this Annual Report on Form 10-K.

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     3. Exhibits
     
No.   Description
 
    
2.1
  Agreement and Plan of Merger, dated as of June 15, 2004, by and among Capital C Energy Operations, LP, Capital C Ohio, Inc. and Belden & Blake Corporation, incorporated by reference to Exhibit 2.1 to Belden & Blake Corporation’s Form 8-K dated July 7, 2004 (as amended).
 
    
3.1
  Amended and Restated Articles of Incorporation of Belden & Blake Corporation (fka Belden & Blake Energy Corporation), incorporated by reference to Exhibit 3.1 to Belden & Blake Corporation’s Form 8-K dated November 29, 2004.
 
    
3.2
  Amended and Restated Code of Regulations of Belden & Blake Corporation, incorporated by reference to Exhibit 3.2 to the Company’s Registration Statement on Form S-4 (Registration No. 333-119194).
 
    
4.1
  Indenture, dated as of July 7, 2004, by and among Belden & Blake Corporation, The Canton Oil & Gas Company, Ward Lake Drilling, Inc. and BNY Midwest Trust Company, incorporated by reference to Exhibit 4.2 to Belden & Blake Corporation’s Form 8-K dated July 7, 2004 (as amended).
 
    
10.1
  ISDA Master Agreement, dated as of June 30, 2004, between Capital C Ohio, Inc. and J. Aron & Company, incorporated by reference to Exhibit 10.1 to Belden & Blake Corporation’s Form 8-K dated July 7, 2004 (as amended).
 
    
10.2
  First Amended and Restated Credit and Guaranty Agreement, dated as of August 16, 2005, by and among Belden & Blake Corporation, as borrower, certain subsidiaries of Belden & Blake Corporation, as guarantors, various lenders signatory thereto, and BNP Paribas., as sole lead arranger, sole bookrunner, syndication agent and administrative agent (incorporated by reference to Exhibit 10.1 to Belden & Blake Corporation’s Form 8-K dated August 22, 2005.
 
    
10.3
  Collateral Trust Agreement, dated as of July 7, 2004, among Belden & Blake Corporation, the other Pledgors party from time to time thereto, Goldman Sachs Credit Partners L.P., as Administrative Agent under the Credit Agreement, J. Aron & Company, as Hedge Counterparty under the Hedge Agreement, BNY Midwest Trust Company, as Trustee under the Indenture, and Wells Fargo Bank, N.A., as Collateral Trustee, incorporated by reference to Exhibit 10.7 to Belden & Blake Corporation’s Form 8-K dated July 7, 2004 (as amended).
 
    
10.4
  Schedule to the ISDA Master Agreement, dated as of June 30, 2004 and amended and restated as of August 16, 2005, by and between J. Aron & Company and Belden & Blake Corporation (incorporated by reference to Exhibit 10.2 to Belden & Blake’s 8- K filed on August 22, 2005)
 
    
10.5
  Credit Support Annex to the Schedule to the ISDA Master Agreement, dated as of June 30, 2004 and amended and restated as of August 16, 2005, by and between J. Aron & Company and Belden & Blake Corporation (incorporated by reference to Exhibit 10.3 to Belden & Blake’s 8-K filed on August 22, 2005)
 
    
10.6
  Subordinated Promissory Note, dated August 16, 2005, between Capital C Energy Operations, LP and Belden & Blake Corporation (incorporated by reference to Exhibit 10.8 to Belden & Blake’s 8-K filed on August 22, 2005)
 
    
10.7
  First Amendment to Credit Agreement, dated as of September 27, 2005, by and among Belden & Blake Corporation and BNP Paribas, incorporated by reference to Exhibit 10.25 to the Belden & Blake Corporation’s annual report on Form 10-K for the year ended December 31, 2005.
 
    
10.8
  Operating Agreement dated October 1, 2005, by and between Belden & Blake Corporation and EnerVest Operating L.L.C. incorporated by reference to Exhibit 10.26 to the Belden & Blake Corporation’s annual report on Form 10-K for the year ended December 31, 2005.

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No.   Description
 
    
14.1
  Code of Ethics for Senior Financial Officers, incorporated by reference to Exhibit 14.1 to Belden & Blake Corporation’s Annual Report on Form 10-K for the year ended December 31, 2003.
 
    
31.1*
  Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
    
31.2*
  Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
    
32.1*
  Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
    
32.2*
  Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
*   Filed herewith
     (c) Exhibits required by Item 601 of Regulation S-K
     Exhibits required to be filed by the Company pursuant to Item 601 of Regulation S-K are contained in the Exhibits listed under Item 15(a)3.
     (d) Financial Statement Schedules required by Regulation S-X
     The items listed in the accompanying index to financial statements are filed as part of this Annual Report on Form 10-K.

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SIGNATURES
     Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
         
 
  BELDEN & BLAKE CORPORATION    
 
        
March 28, 2008
  By: /s/ Mark A. Houser    
 
       
Date
  Mark A. Houser, Chief Executive Officer, Chairman of the Board of    
 
  Directors and Director    
     Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
         
/s/ Mark A. Houser
 
Mark A. Houser		   Chief Executive Officer
Chairman of the Board
of Directors and Director
(Principal Executive Officer) 		 
March 28, 2008 
Date
/s/ James M. Vanderhider
 
James M. Vanderhider		   President, Chief Financial
Officer and Director
(Principal Financial Officer) 		 
March 28, 2008 
Date
/s/ Frederick J. Stair
 
Frederick J. Stair		   Vice President of Accounting
(Principal Accounting Officer) 		   
March 28, 2008 
Date
 
Kenneth Mariani		   Senior Vice President, Chief
Operating Officer and Director 		 
 
Date
/s/ Matthew Coeny
 
Matthew Coeny		   Director  
March 28, 2008
Date

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BELDEN & BLAKE CORPORATION
INDEX TO CONSOLIDATED
FINANCIAL STATEMENTS AND SCHEDULES
Item 15(a) (1) and (2)
         
CONSOLIDATED FINANCIAL STATEMENTS   Page
 
Report of Independent Registered Public Accounting Firm
    F-2  
Consolidated Balance Sheets as of December 31, 2007 (Successor Company) and December 31, 2006 (Successor Company)
    F-3  
Consolidated Statements of Operations:
        
Years ended December 31, 2007 and 2006 (Successor Company)
138 day period from August 16, 2005 to December 31, 2005 (Successor Company)
227 day period from January 1, 2005 to August 15, 2005 (Predecessor I Company)
     F-4  
Consolidated Statements of Shareholders’ Equity (Deficit):
        
Years ended December 31, 2007 and 2006 (Successor Company)
138 day period from August 16, 2005 to December 31, 2005 (Successor Company)
227 day period from January 1, 2005 to August 15, 2005 (Predecessor I Company)
     F-5  
Consolidated Statements of Cash Flows:
        
Years Ended December 31, 2007 and 2006 (Successor Company)
138 day period from August 16, 2005 to December 31, 2005 (Successor Company)
227 day period from January 1, 2005 to August 15, 2005 (Predecessor I Company)
     F-6  
Notes to Consolidated Financial Statements
    F-7  
All financial statement schedules have been omitted since the required information is not present in amounts sufficient to require submission of the schedule or because the information required is included in the financial statements.

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Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Owners of Belden & Blake Corporation
Houston, TX
     We have audited the accompanying consolidated balance sheets of Belden & Blake Corporation and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the two years in the period ended December 31, 2007, results of operations and cash flows for the one hundred thirty-eight day period from August 16, 2005 to December 31, 2005, and results of operations and cash flows for the two hundred twenty-seven day period from January 1, 2005 to August 15, 2005 (Predecessor I Company). These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits.
     We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
     In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2007, results of its operations and cash flows for the one hundred thirty-eight day period from August 16, 2005 to December 31, 2005, and results of operations and cash flows for the two hundred twenty-seven day period from January 1, 2005 to August 15, 2005 (Predecessor I Company), in conformity with accounting principles generally accepted in the United States of America.
DELOITTE & TOUCHE LLP
Houston, TX
March 28, 2008

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BELDEN & BLAKE CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
                 
    Successor Company  
    December 31,  
    2007     2006  
ASSETS
                
Current assets
                
Cash and cash equivalents
   $ 16,014     $ 5,927  
Accounts receivable (less accumulated provision for doubtful accounts:
     18,071       19,855  
December 31, 2007- $806; December 31, 2006 - $1,271)
                
Inventories
     1,084       885  
Deferred income taxes
     17,282       12,607  
Other current assets
     370       510  
Fair value of derivatives
     37       378  
 
            
Total current assets
     52,858       40,162  
 
                
Property and equipment, at cost
                
Oil and gas properties (successful efforts method)
     713,912       692,576  
Gas gathering systems
     1,308       1,305  
Land, buildings, machinery and equipment
     2,761       3,031  
 
            
 
     717,981       696,912  
Less accumulated depreciation, depletion and amortization
     88,549       52,564  
 
            
Property and equipment, net
     629,432       644,348  
Goodwill
     90,076       90,076  
Fair value of derivatives
     29       193  
Other assets
     1,830       2,244  
 
            
 
   $ 774,225     $ 777,023  
 
            
 
                
LIABILITIES AND SHAREHOLDER’S EQUITY
                
Current liabilities
                
Accounts payable
   $ 2,656     $ 2,259  
Accrued expenses
     20,363       21,554  
Current portion of long-term liabilities
     367       408  
Fair value of derivatives
     43,696       27,576  
 
            
Total current liabilities
     67,082       51,797  
 
                
Long-term liabilities
                
Bank and other long-term debt
     99,947       95,454  
Senior secured notes
     164,240       165,106  
Subordinated promissory note — related party
     26,931       25,000  
Asset retirement obligations and other long-term liabilities
     22,164       20,627  
Fair value of derivatives
     192,661       160,011  
Deferred income taxes
     98,977       115,325  
 
            
Total long-term liabilities
     604,920       581,523  
 
                
Shareholder’s equity
                
Common stock: without par value; 3,000 shares authorized; 1,534 shares issued
     —       —  
Additional paid in capital
     125,000       125,000  
Retained earnings
     (3,810 )     41,262  
Accumulated other comprehensive loss
     (18,967 )     (22,559 )
 
            
Total shareholder’s equity
     102,223       143,703  
 
            
 
   $ 774,225     $ 777,023  
 
            
See accompanying notes.

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BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)
                                   
    Successor Company       Predecessor I Company  
                    For the 138 Day          
                    Period From August       For the 227 Day Period  
    For the Year Ended     For the Year Ended     16, 2005 to       From January 1, 2005  
    December 31, 2007     December 31, 2006     December 31, 2005       to August 15, 2005  
Revenues
                                  
Oil and gas sales
   $ 114,427     $ 147,122     $ 69,954       $ 71,400  
Gas gathering and marketing
     10,275       11,294       6,551         6,439  
Other
     954       674       166         284  
 
                          
 
     125,656       159,090       76,671         78,123  
 
                                  
Expenses
                                  
Production expense
     24,585       23,692       9,831         13,582  
Production taxes
     2,265       2,404       1,674         1,742  
Gas gathering and marketing
     8,640       9,360       5,481         5,629  
Exploration expense
     1,935       1,797       1,229         2,424  
General and administrative expense
     8,236       9,796       2,163         3,964  
Depreciation, depletion and amortization
     36,087       38,074       14,183         20,267  
Impairment of oil and gas properties
     31       546       —         —  
Accretion expense
     1,290       1,226       407         745  
Derivative fair value loss (gain)
     78,120       (37,356 )     5,054         8,258  
Transaction expense
     —       —       7         7,535  
 
                          
 
     161,189       49,539       40,029         64,146  
 
                          
Operating (loss) income
     (35,533 )     109,551       36,642         13,977  
 
                                  
Other (income) expense
                                  
(Gain) on early extinguishment of debt
     —       (436 )     —         —  
Interest expense
     23,712       23,553       8,684         15,784  
 
                          
(Loss) income before income taxes
     (59,245 )     86,434       27,958         (1,807 )
(Benefit) provision for income taxes
     (23,923 )     34,235       10,395         (1,487 )
 
                          
Net (loss) income
   $ (35,322 )   $ 52,199     $ 17,563       $ (320 )
 
                          
See accompanying notes.

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BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (DEFICIT)
(in thousands)
                                                                 
    Successor Company     Predecessor I Company                     Accumulated Other     Total  
    Common     Common     Common     Common     Paid in     Equity     Comprehensive     Equity  
    Shares     Stock     Shares     Stock     Capital     (Deficit)     Income     (Deficit)  
January 1, 2005
     —       —       2       —       77,500       7,263       (27,675 )     57,088  
Predecessor I Company:
                                                                
Comprehensive income (loss):
                                                                
Net loss
                                             (320 )             (320 )
Other comprehensive income (loss), net of tax:
                                                                
Change in derivative fair value
                                                     (140,613 )     (140,613 )
Reclassification adjustment for derivative (gain) loss reclassified into oil and gas sales
                                                     11,888       11,888  
 
                                                              
Total comprehensive loss
                                                             (129,045 )
Stock-based compensation
                                     2,586                       2,586  
Redemption of common stock
                                     (80,086 )     (6,943 )     156,400       69,371  
Equity adjustment due to purchase accounting
     2               (2 )             116,000                       116,000  
Equity contribution
                                     9,000                       9,000  
                                         
August 16, 2005
     2       —       —       —       125,000       —       —       125,000  
Successor Company:
                                                                
Comprehensive income (loss):
                                                                
Net income
                                             17,563               17,563  
Other comprehensive income (loss), net of tax:
                                                                
Change in derivative fair value
                                                     (55,654 )     (55,654 )
Reclassification adjustment for derivative (gain) loss reclassified into oil and gas sales
                                                     10,990       10,990  
 
                                                              
Total comprehensive loss
                                                             (27,101 )
Dividends
                                             (8,500 )             (8,500 )
                                         
December 31, 2005
     2       —       —       —       125,000       9,063       (44,664 )     89,399  
Comprehensive income (loss):
                                                                
Net income
                                             52,199               52,199  
Other comprehensive income (loss), net of tax:
                                                                
Change in derivative fair value
                                                     19,933       19,933  
Reclassification adjustment for derivative (gain) loss reclassified into oil and gas sales
                                                     2,172       2,172  
 
                                                              
Total comprehensive income
                                                             74,304  
Dividends
                                             (20,000 )             (20,000 )
                                         
December 31, 2006
     2       —       —       —     $ 125,000     $ 41,262     $ (22,559 )   $ 143,703  
Comprehensive income (loss):
                                                                
Net income
                                             (35,322 )             (35,322 )
Other comprehensive income (loss), net of tax:
                                                                
Change in derivative fair value
                                                     4,371       4,371  
Reclassification adjustment for derivative (gain) loss reclassified into oil and gas sales
                                                     (779 )     (779 )
 
                                                              
Total comprehensive income
                                                             (31,730 )
Dividends
                                             (9,750 )             (9,750 )
                                         
December 31, 2007
     2       —       —       —     $ 125,000     $ (3,810 )   $ (18,967 )   $ 102,223  
See accompanying notes.

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BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
                                   
                              Predecessor I  
    Successor Company       Company  
                    For the 138 Day       For the 227 Day  
    For the Year     For the Year     Period From       Period From  
    Ended     Ended     August 16, 2005 to       January 1, 2005  
    December 31,     December 31,     December 31,       to August 15,  
    2007     2006     2005       2005  
Cash flows from operating activities:
                                  
Net (loss) income
   $ (35,322 )   $ 52,199     $ 17,563       $ (320 )
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
                                  
Depreciation, depletion and amortization
     36,087       38,074       14,183         20,267  
Impairment of oil and gas properties
     31       546       —         —  
Accretion expense
     1,290       1,226       407         745  
(Gain) loss on debt extinguishment and disposal of property and equipment
     (75 )     (472 )     57         86  
Amortization of derivatives and other noncash derivative activities
     84,901       (56,057 )     9,511         12,344  
Exploration expense
     610       738       1,229         2,424  
Deferred income taxes
     (23,923 )     33,710       10,395         (1,487 )
Stock-based compensation
     —       —       —         2,586  
Other non-cash expense
     2,783       1,483       158         998  
Change in operating assets and liabilities, net of effects of acquisition and disposition of businesses:
                                  
Accounts receivable and other operating assets
     1,734       5,210       (1,421 )       213  
Inventories
     (266 )     100       484         (85 )
Accounts payable and accrued expenses
     219       (10,201 )     9,813         (8,845 )
 
                          
Net cash provided by operating activities
     68,069       66,556       62,379         28,926  
Cash flows from investing activities:
                                  
Proceeds from property and equipment disposals
     267       7,419       21         5  
Exploration expense
     (610 )     (738 )     (1,229 )       (2,424 )
Additions to property and equipment
     (22,696 )     (36,839 )     (11,640 )       (17,177 )
Decrease (increase) in other assets
     (10 )     (18 )     (26 )       (34 )
 
                          
Net cash used in investing activities
     (23,049 )     (30,176 )     (12,874 )       (19,630 )
Cash flows from financing activities:
                                  
Repayment of senior secured notes
     —       (33,933 )     —         —  
Proceeds from senior secured facility
     —       —       37,000         57,000  
Proceeds from subordinated promissory note
     —       —       —         25,000  
Payment to shareholders and optionholders or dividends
     (9,750 )     (20,000 )     (8,500 )       —  
Settlement of derivative liabilities recorded in purchase accounting
     (29,659 )     (28,042 )     (34,360 )       (20,440 )
Debt issue costs
     —       —       (27 )       (2,120 )
Repayment of senior secured facility — term loan
     —       —       —         (89,500 )
Repayment of senior secured facility
     —       —       (42,000 )       —  
Proceeds from revolving line of credit
     6,500       55,376       —         —  
Repayment of revolving line of credit
     (2,000 )     (12,000 )     —         —  
Repayment of long-term debt and other obligations
     (24 )     (26 )     (5 )       (84 )
Equity contribution
     —       —       —         9,000  
 
                          
Net cash used in financing activities
     (34,933 )     (38,625 )     (47,892 )       (21,144 )
 
                          
Net increase (decrease)in cash and equivalents
     10,087       (2,245 )     1,613         (11,848 )
Cash and cash equivalents at beginning of period
     5,927       8,172       6,559         18,407  
 
                          
Cash and cash equivalents at end of period
   $ 16,014     $ 5,927     $ 8,172       $ 6,559  
 
                          
See accompanying notes.

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BELDEN & BLAKE CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) Transaction and Merger
     Unless the context requires otherwise or unless otherwise noted, when we use the terms “Belden & Blake,” “we,” “us,” “our” or the “Company,” we are referring to Belden & Blake Corporation. On August 16, 2005, the former partners of the direct parent of Belden & Blake Corporation (the “Company”), Capital C Energy Operations, L.P., a Delaware limited partnership (“Capital C”), completed the sale of all of the partnership interests in Capital C to certain institutional funds managed by EnerVest Ltd. (“EnerVest”), a Houston-based privately held oil and gas operator and institutional funds manager (the “Transaction”). The Transaction resulted in a change in control of the Company (“Change in Control”).
     On July 7, 2004, the Company, Capital C and Capital C Ohio, Inc., an Ohio corporation and a wholly owned subsidiary of Capital C (“Merger Sub”), completed a merger pursuant to which Merger Sub was merged with and into the Company (the “Merger”), with the Company surviving the Merger as a wholly owned subsidiary of Capital C. The Merger resulted in a change in control of the Company. The general partner of Capital C was controlled by Carlyle/Riverstone Global Energy and Power Fund II, L.P. and Capital C Energy Partners, L.P. until the Transaction on August 16, 2005.
     The Transaction and Merger were each accounted for as a purchase effective August 16, 2005 and July 7, 2004, respectively. The Transaction and Merger resulted in a new basis of accounting reflecting estimated fair values for assets and liabilities at that date. Accordingly, the financial statements for the period subsequent to August 15, 2005 are presented on our new basis of accounting, while the results of operations for prior periods reflect the historical results of the two predecessor companies. Vertical black lines are presented to separate the financial statements of the two predecessor companies and the successor company. The “Successor Company” refers to the period from August 16, 2005 and forward. The “Predecessor I Company” refers to the period from July 7, 2004 through August 15, 2005.
     Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed in the acquisition. The recorded goodwill is not deductible for tax purposes.
     The principal factors that contributed to the purchase price that resulted in goodwill are as follows:
  •   Cost savings and operational synergies of the Company when combined with the other operations managed by EnerVest. These savings include the elimination of duplicative facilities, reduction of personnel and operating and development costs through the management of a larger asset base.
 
  •   The affiliation with EnerVest, an acquisition-focused company, coupled with the enhanced presence in the Appalachian and Michigan basins with EnerVest’s other operations, provides the opportunity to create value by highgrading investment opportunities and identifying new investment opportunities.
 
  •   The going-concern value of the Company, including its experienced workforce.
 
  •   A deferred tax liability was recorded to recognize the difference between the historical tax basis of the assets and the acquisition costs recorded for book purposes. Goodwill was recorded to recognize this tax basis differential.

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     SFAS No. 142, Goodwill and Other Intangible Assets requires that intangible assets with indefinite lives, including goodwill, be evaluated on an annual basis for impairment or more frequently if an event occurs or circumstances change could potentially result in an impairment.
     The impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. As we have only one reporting unit, the reporting unit used for testing will be the entire company. The fair value of the reporting unit is determined and compared to the book value of that reporting unit. If the fair value of the reporting unit is less than the book value (including goodwill) then goodwill is reduced to its fair value and the amount of the writedown is charged to earnings.
     The fair value of the reporting unit will be based on estimates of future net cash flows from proved reserves and from future exploration for and development of unproved reserves. Downward revisions of estimated reserves or production, increases in estimated future costs or decreases in oil and gas prices could lead to an impairment of all or a portion of goodwill in future periods.
     In connection with the Transaction, we entered into Compensation Agreements (“Compensation Agreements”), each on substantially similar terms, with James A. Winne III, our former Chairman of the Board and Chief Executive Officer, and Michael Becci, our former President and Chief Operating Officer. The Compensation Agreements provide for a severance payment equal to $250,000 and the issuance of 17.1037 restricted shares of common stock in the Company, payable to each of Messrs. Winne and Becci promptly upon the Transaction. In exchange for their severance payments, Messrs. Winne and Becci resigned as officers and directors of the Company effective August 16, 2005. This was reported as compensation expense of $3.1 million and included in the transaction expenses in the Predecessor I Company period ended August 15, 2005.
     We entered into a Contingent Value Agreement (“Contingent Value Agreement”) with the former partners of Capital C, Messrs. Becci and Winne, and the EnerVest funds that purchased Capital C. The Contingent Value Agreement expired during 2007. Under the Contingent Value Agreement, if properties were contributed to a publicly traded partnership or a publicly traded royalty trust (“MLP”), then we had agreed to pay the following aggregate amount to the former partners of Capital C, and Messrs. Becci and Winne:
· 20% of the difference between the value received for the assets upon transfer to a MLP and the book value of the assets, if the transfer occurs within one year following the Transaction; and
     · 10% of the difference between the value received for the assets upon transfer to a MLP and the book value of the assets, if the transfer occurs in the second year following the Transaction.
     Following the Change in Control Transaction, James A. Winne III, resigned as Chairman of the Board of Directors and Chief Executive Officer of the Company, and Michael Becci, resigned as director, President and Chief Operating Officer of the Company. Upon consummation of the Transaction, all of the members of our board of directors resigned on August 16, 2005 and Capital C replaced the board with John B. Walker, James M. Vanderhider, Mark A. Houser, Ken Mariani and Matthew Coeny.
     On August 16, 2005, our board of directors appointed Mark A. Houser as Chairman and Chief Executive Officer and James M. Vanderhider as President and Chief Operating Officer. On October 3, 2005, James M. Vanderhider resigned as Chief Operating Officer and our Board of Directors appointed Ken Mariani as its Senior Vice President and Chief Operating Officer. On October 6, 2005, Robert W. Peshek resigned as Senior Vice President and Chief Financial Officer and our Board of Directors appointed James M. Vanderhider as its Chief Financial Officer. Mr Walker resigned from our Board of Directors on February 2, 2007.

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     We incurred transaction costs associated with the Transaction of $7.5 million including $500,000 of severance costs. These costs were expensed in the Predecessor I Company period ended August 15, 2005. We also capitalized $2.1 million of debt financing costs and recorded obligations of $5.5 million in purchase accounting including $4.2 million of severance cost and $1.2 million of acquisition costs incurred by EnerVest.
(2) Business and Significant Accounting Policies
Business
     We operate in the oil and gas industry. Our principal business is the exploitation, development, production, operation and acquisition of oil and gas properties. Sales of oil are ultimately made to refineries. Sales of natural gas are ultimately made to gas utilities and industrial consumers in Ohio, Michigan, Pennsylvania and New York. The price of oil and natural gas has a significant impact on our working capital and results of operations.
Principles of Consolidation and Financial Presentation
     The accompanying consolidated financial statements include the financial statements of the Company and our subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. Certain reclassifications have been made to conform to the presentation in 2007.
Use of Estimates in the Financial Statements
     The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts. Significant estimates used in the preparation of our financial statements which could be subject to significant revision in the near term include estimated oil and gas reserves.

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Cash Equivalents
     For purposes of the statements of cash flows, cash equivalents are defined as all highly liquid investments purchased with an initial maturity of three months or less.
Concentrations of Credit Risk
     Credit limits, ongoing credit evaluation and account monitoring procedures are used to minimize the risk of loss. Collateral is generally not required. Expected losses are provided for currently and actual losses have been within management’s expectations.
Inventories
     Inventories of material, pipe and supplies are valued at average cost. Crude oil and natural gas inventories are stated at the lower of average cost or market.
Property and Equipment
     We use the “successful efforts” method of accounting for our oil and gas properties. Under this 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 holes and costs of carrying and retaining undeveloped properties, are expensed as incurred. The costs of carrying and retaining undeveloped properties include delay rental payments made on new and existing leases, ad valorem taxes on existing leases and the cost of previously capitalized leases which 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. Capitalized costs related to proved properties are depleted using the unit-of-production method. Depreciation, depletion and amortization of proved oil and gas properties is 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 certain transactions such as the complete disposition of a geographical/geological pool. 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. We recorded impairments of $31,000 and $332,000 in 2007 and 2006, respectively, which reduced the book value of unproved oil and gas properties to their estimated fair value. No impairment was recorded in 2005.
     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. No impairment was recorded in 2007. In performing the review for long-lived asset recoverability during 2006, we recorded $214,000 of impairments which reduced the book value of

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producing properties to their estimated fair value. Fair value was based on estimated future cash flows to be generated by the assets, discounted at a market rate of interest.
Goodwill and Other Intangible Assets
     Under Statement of Financial Accounting Standards No. (SFAS) 142, “Goodwill and Other Intangible Assets” which was issued in June 2001 by the Financial Accounting Standards Board (FASB), goodwill and indefinite lived intangible assets are no longer amortized but are reviewed for impairment annually or if certain impairment indicators arise. Separately identifiable intangible assets that are not deemed to have an indefinite life will continue to be amortized over their useful lives (but with no maximum life).
     As described in Note 1, we recorded goodwill associated with the Transaction which resulted in goodwill of $90.1 million at December 31, 2007 and 2006. In accordance with SFAS No. 142, “Goodwill and Other Intangible Assets”, goodwill is not amortized to earnings, but is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. If the carrying value of goodwill is determined to be impaired, it is reduced for the impaired value with a corresponding charge to pretax earnings in the period in which it is determined to be impaired. During the third quarter of 2007, we performed our annual assessment of impairment of the goodwill and determined that there was no impairment.
     At December 31, 2007 and 2006, we had $1.1 million and $1.6 million, respectively, of deferred debt issuance costs. Deferred debt issuance costs are being amortized over their respective terms. Amortization expense related to deferred debt issuance costs was $424,000 in 2007 and 2006 and $1.2 million in 2005. At December 31, 2007, the amortization of deferred debt issuance costs in the next five years is as follows: $424,000 in each of the next two years (2008 through 2009), $270,000 in 2010 and none in 2011 or 2012.
Revenue Recognition
     Oil and natural gas revenues are recognized when production is sold to a purchaser at fixed or determinable prices, when delivery has occurred and title has transferred and collectability of the revenue is probable. We follow the sales method of accounting for natural gas revenues. Under this method of accounting, revenues are recognized based on volumes sold, which may differ from the volume to which we are entitled based on our working interest. An imbalance is recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the under–produced owner(s) to recoup its entitled share through future production. Under the sales method, no receivables are recorded where we have taken less than our share of production. There were no material gas imbalances at December 31, 2007 or 2006. Oil and gas marketing revenues are recognized when title passes.
Income Taxes
     We use the asset and liability method of accounting for income taxes under SFAS 109, “Accounting for Income Taxes.” Deferred income taxes are provided for temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Deferred income taxes also are recognized for operating losses that are available to offset future taxable income and tax credits that are available to offset future federal income taxes. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the benefits will not be realized.
Stock-Based Compensation
     On December 31, 2002, the FASB issued SFAS 148, “Accounting for Stock Based Compensation–Transition and Disclosure.” SFAS 148 amends SFAS 123, “Accounting for Stock Based Compensation” by providing alternative methods of transition to SFAS 123’s fair value method of accounting for stock-based compensation. SFAS 148 also amends many of the disclosure requirements of

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SFAS 123. The Predecessor Companies measured expense associated with stock-based compensation under the provisions of Accounting Principles Board Opinion No. (APB) 25, “Accounting for Stock Issued to Employees” and its related interpretations. Under APB 25, no compensation expense is required to be recognized upon the issuance of stock options to key employees as the exercise price of the option is equal to the market price of the underlying common stock at the date of grant.
     We had no outstanding stock options or stock-based compensation activity in the years ended December 31, 2005, 2006 or 2007.
     In connection with the closing of the Transaction, we issued approximately 34 shares of common stock to Messrs. Winne and Becci. The shares were purchased from them at the closing of the Transaction. These shares were reported as compensation expense of $2.6 million and included in the transaction expenses in the Predecessor I Company period ended August 15, 2005.
Derivatives and Hedging
     In accordance with SFAS 133, we recognize all derivative financial instruments as either assets or liabilities at fair value. Derivative instruments that are not hedges must be adjusted to fair value through net income (loss). Under the provisions of SFAS 133, 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). Ineffective portions of a derivative instrument’s change in fair value are immediately recognized in net income (loss). Deferred gains and losses on terminated commodity hedges will be recognized as increases or decreases to oil and gas revenues during the same periods in which the underlying forecasted transactions impact earnings. 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. See Note 5.
     The relationship between the hedging instruments and the hedged items 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 assess effectiveness at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Hedge accounting is discontinued prospectively if we determine that a derivative is no longer highly effective as a hedge or if we decide to discontinue the hedging relationship.

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Asset Retirement Obligations
     We follow SFAS 143, “Accounting for Asset Retirement ” which requires us to recognize a liability for the fair value of its asset retirement obligations associated with our tangible, long-lived assets. The majority of our asset retirement obligations relate to the plugging and abandonment (excluding salvage value) of our oil and gas properties. There has been no significant current period activity with respect to additional retirement obligations, settled obligations, accretion expense and revisions of estimated cash flows.
     A reconciliation of our liability for plugging and abandonment costs for the years ended December 31, 2007 and 2006 is as follows (in thousands):
                 
    Year Ended     Year Ended  
    December 31,     December 31,  
    2007     2006  
Beginning asset retirement obligations
   $ 20,734     $ 19,389  
Liabilities incurred
     220       523  
Liabilities settled
     (219 )     (543 )
Accretion expense
     1,290       1,219  
Revisions in estimated cash flows
     239       146  
 
            
Ending asset retirement obligations
   $ 22,264     $ 20,734  
 
            
(3) New Accounting Pronouncements
     In July 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement 109’ (“FIN 48”), which clarifies the accounting for uncertainty in tax positions taken or expected to be taken in a tax return, including issues relating to financial statement recognition and measurement. FIN 48 provides that the tax effects from an uncertain tax position can be recognized in the financial statements only if the position is “more-likely-than-not” to be sustained if the position were to be challenged by a taxing authority. The assessment of the tax position is based solely on the technical merits of the position, without regard to the likelihood that the tax position may be challenged. If an uncertain tax position meets the “more-likely-than-not” threshold, the largest amount of tax benefit that is more than 50 percent likely to be recognized upon ultimate settlement with the taxing authority is recorded. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. Consistent with the requirements of FIN 48, we adopted FIN 48 on January 1, 2007. The adoption of FIN 48 did not have a material impact on our financial statements.
     FIN 48 requires us to evaluate whether any material tax position we have taken will more likely than not be sustained upon examination by the appropriate taxing authority. As we believe that all such material tax positions taken by us are supportable by existing laws and related interpretations, there are no material uncertain tax positions to consider in accordance with FIN 48.
     Since we have no unrecognized tax benefits as of December 31, 2007, there is no potential impact on our effective tax rate.
     To the extent penalties and interest would be assessed on any underpayment of income tax, such amounts have been accrued and classified as a component of income tax expense in the financial statements. This is an accounting policy election made by us that is a continuation of our historical policy and will continue to be consistently applied in the future. As of December 31, 2007, we have not accrued any interest and penalties related to unrecognized tax benefits.
     We do not anticipate a significant change in the balance of unrecognized tax benefits within the next 12 months.
     In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, Fair Value Measurements, to provide guidance for using fair value to measure assets and liabilities. SFAS No. 157 establishes a fair value hierarchy and clarifies the principle that fair value should be based on assumptions market participants would use when pricing the asset or liability. SFAS No. 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. SFAS No. 157 was to be effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years; however, in February 2008, the FASB issued FASB Staff Position FAS 157–2, Effective Date of FASB Statement No. 157, which delayed the effective date of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis, for one year. We adopted SFAS No. 157 on January 1, 2008 for our financial assets and financial liabilities, and the adoption did not have a material impact on our consolidated financial statements. We will adopt SFAS No. 157 on January 1, 2009 for our nonfinancial assets and nonfinancial liabilities, and we have not yet determined the impact, if any, on our consolidated financial statements.
   In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. Unrealized gains and losses on items for which the fair value option has been selected are reported in earnings. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We will adopt SFAS No. 159 on January 1, 2008. At the present time, we do not expect to apply the provisions of SFAS No. 159.

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   In December 2007, the FASB issued SFAS No 141 (Revised 2007), Business Combinations (“SFAS No. 141(R)”) to significantly change the accounting for business combinations. Under SFAS No. 141(R), an acquiring entity will be required to recognize all the assets acquired and liabilities assumed in a transaction at the acquisition date fair value with limited exceptions and will change the accounting treatment for certain specific items, including:
  •   acquisition costs will generally be expensed as incurred;
 
  •   noncontrolling interests will be valued at fair value at the date of acquisition; and
 
  •   liabilities related to contingent consideration will be recorded at fair value at the date of acquisition and subsequently remeasured each subsequent reporting period. SFAS No. 141(R) is effective for fiscal years beginning after December 15, 2008. We will adopt SFAS No. 141(R) on January 1, 2009, and we have not yet determined the impact, if any, on our consolidated financial statements.
   In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements – An Amendment of ARB No. 51, to establish new accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 requires the recognition of a noncontrolling interest (minority interest) as equity in the consolidated financial statements and separate from the parent’s equity. The amount of net income attributable to the noncontrolling interest will be included in consolidated net income on the face of the income statement. SFAS No. 160 clarifies that changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation are equity transactions if the parent retains its controlling financial interest. In addition, SFAS No. 160 requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS No. 160 also includes expanded disclosure requirements regarding the interests of the parent and its noncontrolling interest. SFAS No. 160 is effective for fiscal years beginning after December 15, 2008. We will adopt SFAS No. 160 on January 1, 2009, and we have not yet determined the impact, if any, on our consolidated financial statements.
(4) Dispositions
     On March 31, 2006, we sold our interests in 13 Oriskany wells and the associated gas gathering system for approximately $3.3 million, which approximated the net carrying value of such assets.
     In August, 2006, we closed on the sale of our office building in North Canton, Ohio. Net proceeds from the sale were approximately $3.5 million, which was the carrying value of the property.
(5) Derivatives and Hedging
     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 price, crude oil price or interest rate volatility and to support our capital expenditure plans. Our derivative financial instruments take the form of swaps or collars. At December 31, 2007, our derivative contracts were comprised of natural gas swaps, natural gas basis differential swaps, crude oil swaps and interest rate swaps, which were placed with major financial institutions that we believe are a minimal credit risk. Qualifying derivative financial instruments are designated as cash flow hedges. Changes in fair value of the derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time the hedged items impact earnings. The changes in fair value of non-qualifying derivative contracts will be reported in expense in the consolidated statements of operations as derivative fair value loss.

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     We use NYMEX-based commodity derivative contracts to hedge natural gas, because our natural gas production is sold pursuant to NYMEX-based sales contracts. Beginning July 7, 2004, we had ineffectiveness on the natural gas swaps due to purchase accounting, which created non-zero value derivatives at the time of the Merger. We had 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 6, 2004. Although these collars are not deemed to be effective hedges in accordance with the provisions of SFAS 133, we retained these instruments as protection against changes in commodity prices and the Company continued to record the mark-to-market adjustments on these natural gas collars, through 2005, in our income statement. Our NYMEX crude oil swaps were highly effective and were designated as cash flow hedges through August 16, 2005. We had ineffectiveness on the crude oil swaps because the oil is sold locally at a posted price which is different from the NYMEX price. At August 16, 2005, our oil swaps no longer qualified for cash flow hedge accounting because the assessment of effectiveness indicated that they may not be highly effective on an on-going basis. This occurred due to the application of purchase accounting to the derivatives, which created non-zero value derivatives at the time of the Transaction. The changes in the fair values of the natural gas collars since July 7, 2004, the changes in fair value of the oil swaps subsequent to August 15, 2005, the ineffective portion of the crude oil swaps through August 15, 2005 and the ineffective portion of the natural gas swaps from July 7, 2004 through June 30, 2006 are recorded as “Derivative fair value gain or loss.” As of July 1, 2006, we determined that our gas swaps were no longer highly effective and, therefore, could no longer be designated as cash flow hedges. Changes in the fair value of the gas derivatives from that date forward are recorded in derivative fair value gain/loss. Deferred gains or losses on these gas derivatives are recognized as increases or decreases to gas sales revenues during the same periods in which the underlying forecasted transactions impact earnings.
     During 2007 and 2006, net losses of $7.6 million ($4.6 million after tax) and $3.3 million ($2.2 million after tax), respectively, were reclassified from accumulated other comprehensive income to earnings. The fair value of open hedges in accumulated other comprehensive income decreased $6.3 million ($3.8 million after tax) in 2007 and decreased $30.4 million ($19.9 million after tax) in 2006. At December 31, 2007, the estimated net loss in accumulated other comprehensive income that is expected to be reclassified into earnings within the next 12 months is approximately $9.5 million. At December 31, 2007, we have partially hedged our exposure to the variability in future cash flows through December 2013.
     The following table reflects the natural gas and crude oil volumes and the weighted average prices under financial derivatives (including settled contracts) at December 31, 2007:
                                                 
    Natural Gas Swaps   Crude Oil Swaps   Natural Gas Basis Swaps
            NYMEX           NYMEX            
            Price per   Estimated   Price per       Basis
Year Ending   Bbtu   Mmbtu   Mbbls   Bbl   Bbtu   Differential
December 31, 2008
     10,126     $ 4.64       208     $ 29.96       —     $ —  
December 31, 2009
     9,529       4.43       191       29.34       3,650       0.345  
December 31, 2010
     8,938       4.28       175       28.86       3,650       0.325  
December 31, 2011
     8,231       4.19       157       28.77       3,285       0.325  
December 31, 2012
     7,005       4.09       138       28.70       —       —  
December 31, 2013
     6,528       4.04       127       28.70       —       —  

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     At December 31, 2007, we had interest rate swaps in place on $80 million of our outstanding debt under the revolving credit facility through September 30, 2010. The swaps provide 1-month LIBOR fixed rates at 4.285% on $40 million and 5.160% on $40 million through September 2008 and 4.07% on $80 million from September 2008 through September 2010, plus the applicable margin. At December 31, 2007, the fair value of the interest rate swaps represented an unrealized loss of $912,000.

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(6) Details of Balance Sheets
                   
    December 31,  
    2007       2006  
    (in thousands)  
Accounts receivable
                  
Accounts receivable
   $ 3,509       $ 3,820  
Allowance for doubtful accounts
     (806 )       (1,271 )
Oil and gas production receivable
     15,368         17,306  
 
              
 
   $ 18,071       $ 19,855  
 
              
Inventories
                  
Oil
   $ 671       $ 796  
Natural gas
     —         —  
Material, pipe and supplies
     413         89  
 
              
 
   $ 1,084       $ 885  
 
              
Property and equipment, gross Oil and gas properties
                  
Producing properties
   $ 628,707       $ 597,631  
Non-producing properties
                  
Proved
     66,793         75,483  
Unproved
     18,344         18,719  
Other
     68         743  
 
              
 
   $ 713,912       $ 692,576  
 
              
Land, buildings, machinery and equipment
                  
Land, buildings and improvements
   $ 838       $ 1,091  
Machinery and equipment
     1,923         1,940  
 
              
 
   $ 2,761       $ 3,031  
 
              
Accrued expenses
                  
Accrued interest expense
   $ 6,499       $ 6,631  
Accrued other expenses
     6,230         6,256  
Accrued drilling and completion costs
     1,296         1,784  
Accrued income taxes
     2         525  
Ad valorem and other taxes
     985         911  
Compensation and related benefits
     —         —  
Undistributed production revenue
     5,351         5,447  
 
              
 
   $ 20,363       $ 21,554  
 
              

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(7) Long-Term Debt
Long-term debt consists of the following (in thousands):
                   
    December 31,  
    2007       2006  
Senior secured notes
   $ 159,475       $ 159,475  
Bank revolving credit facility
     99,876         95,376  
Subordinated promissory note (related party)
     26,931         25,000  
Other
     79         85  
 
              
 
     286,361         279,936  
Less current portion
     8         7  
 
              
Long-term debt
     286,353         279,929  
Fair value adjustment — senior secured notes
     4,765         5,631  
 
              
 
   $ 291,118       $ 285,560  
 
              
Senior Secured Notes due 2012
     We have $159.5 million of our Senior Secured Notes outstanding as of December 31, 2007 and 2006. As a result of the application of purchase accounting, the Senior Secured Notes were recorded as a liability based on the estimated fair value of $200.7 million on the Transaction date. Subsequent accretion of the premium and repurchase of bonds reduced this amount to $164.2 million at December 31, 2007. The fair value adjustment of $4.8 million is shown separately in the table above. The accretion of $865,000 and $866,000 was recorded as a reduction of interest expense in 2006 and 2007. The Senior Secured Notes mature July 15, 2012. Interest is payable semi-annually on January 15 and July 15 of each year at 8.75% based on the face amount of $159.5 million (for an effective rate of 7.946% based on the fair value on the Transaction date). The Senior Secured Notes are secured on a second-priority lien on the same assets subject to the liens securing our obligations under the Amended Credit Agreement. The Senior Secured Notes are subject to redemption at our option at specific redemption prices.
         
July 15, 2008
     104.375 %
July 15, 2009
     102.188 %
July 15, 2010 and thereafter
     100.000 %
     The Senior Secured 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 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.
Amended Credit Agreement
     On August 16, 2005, we amended and restated our then existing $170 million credit agreement, by entering into a First Amended and Restated Credit and Guaranty Agreement (“Amended Credit Agreement”) by and among the Company and BNP Paribas, as sole lead arranger, sole book runner, syndication agent and administrative agent. The Amended Credit Agreement provides for loans and other extensions of credit to be made to us up to a maximum aggregate principal amount of $390 million. The

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obligations under the Amended Credit Agreement are secured by substantially all of our assets. J.P. Morgan Chase and Amegy Bank were added to the bank group in September 2005.
     The Amended Credit Agreement provides for a revolving credit line in the aggregate principal amount of $350 million and a hedge letter of credit facility in the aggregate principal amount of $40 million. Borrowings under the Amended Credit Agreement may not exceed the borrowing base, which was initially set at $80.25 million, of which $57 million was drawn at closing on August 16, 2005. At December 31, 2007, the borrowing base was $113.4 million. The outstanding balance at December 31, 2007 and 2006 was $99.9 million and 95.5 million, respectively.
     Borrowings under the Amended Credit Agreement bear interest (i) at the greater of the prime rate or an adjusted federal funds rate, plus an applicable margin ranging from 0% to 0.625% based on the aggregate principal amount outstanding under the Amended Credit Agreement, or, (ii) at our option, the Eurodollar base rate plus an applicable margin ranging from 1.125% to 2.125% based on the aggregate principal amount outstanding under the Amended Credit Agreement. The full amount borrowed under the Amended Credit Agreement will mature on August 16, 2010.
     The obligations under the Amended Credit Agreement are secured by a first lien security interest in substantially all of our assets. The obligations under the Amended Credit Agreement are further secured by a pledge of 100% of our capital stock held by Capital C, our parent. This agreement was amended on September 27, 2005 to reduce the percentage of the value of total proved reserves that is required to be mortgaged from 75% to 70%.
     The Amended Credit Agreement contains covenants that will limit our ability to, among other things, incur or guarantee additional indebtedness; create liens; pay dividends on or repurchase our stock; pay principal and interest on certain subordinated debt; make certain types of investments; sell assets or merge with another entity; pledge or otherwise encumber our capital stock; or enter into transactions with affiliates. The Amended Credit Agreement also requires compliance with customary financial covenants, including a minimum interest coverage ratio, a maximum leverage ratio and a minimum current ratio. On August 3, 2007, our bank group waived the covenant compliance requirement as of June 30, 2007 and amended the Amended Credit Agreement to increase the maximum leverage ratio from 4.0 : 1.0 to 4.25 : 1.0 for the quarters ending on September 30, 2007 and December 31, 2007. If we had not received this waiver, we would not have complied with our leverage ratio covenant as it would have been 4.07 : 1.0 as of June 30, 2007. On March 24, 2008, our bank group waived the covenant compliance requirement as of December 31, 2007 and amended the Amended Credit Agreement to increase the maximum Leverage Ratio to 4.5 : 1.0 through December 31, 2008. If we had not received this waiver, we would not have complied with our Leverage Ratio covenant as it would have been 4.38 : 1.0 as of December 31, 2007.
     Borrowings under the revolving credit line will be used by us for general corporate purposes. In accordance with the terms of the Amended Credit Agreement, letters of credit issued under the hedge letter of credit commitment and any related borrowings are to be used solely to secure payment of our obligations under the J. Aron Swap (defined hereinafter).
     In connection with our entry into the Amended Credit Agreement, we executed a Subordinated Promissory Note (“Subordinated Note”) in favor of Capital C in the maximum principal amount of $94 million. Under the Subordinated Note, Capital C loaned $25 million to us on August 16, 2005. The Subordinated Note accrues interest at a rate of 10% per annum and matures on August 16, 2012. We received a fairness opinion from an unrelated financial services firm with respect to the terms of the Subordinated Note made on August 16, 2005. Interest payments on the Subordinated Note are due quarterly commencing September 30, 2005. In lieu of cash payments, we have the option to make interest payments on the Subordinated Note by borrowing additional amounts against the Subordinated

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Note. The interest payments in 2005 and 2006 were paid in cash. We made a cash payment of $616,000 and borrowed an additional $1.9 million against the Subordinated Note for interest payments in 2007. The Subordinated Note has no prepayment penalty or premium and may be prepaid in whole or in part at any time. The Subordinated Note is expressly subordinate to our senior debt, which includes obligations under the Amended Credit Agreement, the J. Aron Swap and the Senior Secured Notes.
ISDA Master Agreement
     We amended and restated the Schedule and Credit Support Annex to our ISDA Master Agreement, dated as of June 30, 2004, by and between us and J. Aron & Company (“J. Aron Swap”), pursuant to which we have agreed, from time to time, to enter into cash-settled hedge transactions with J. Aron & Company, as hedge counterparty, in connection with various gas and oil commodity derivatives transactions. The amendments to the J. Aron Swap conform the terms of the Schedule and Credit Support Annex to the terms of the Amended Credit Agreement, change certain covenants and reduce the maximum amount of the letter of credit securing the hedge obligations from $55 million to $40 million.
     At December 31, 2007, the aggregate long-term debt maturing in the next five years is as follows: $8,000 (2008); $8,000 (2009); $99.9 million (2010); $10,000 (2011) and $186.5 million (2012 and thereafter). Our term loan facility requires mandatory prepayments annually based on the calculation of excess cash flow, as defined in the agreement.
(8) Leases
     We lease certain computer equipment, vehicles, natural gas compressors and office space under noncancelable agreements with lease periods of one to five years. Rent expense amounted to $3.1 million in 2007 and 2006, $1.3 million in the Successor Company 138 day period ended December 31, 2005 and $2.1 million in the Predecessor I Company 227 day period ended August 15, 2005.
     We also lease certain computer equipment accounted for as capital leases. Property and equipment includes $273,000 of computer equipment under capital leases at December 31, 2007 and 2006. Accumulated depreciation for such equipment includes approximately $271,000 and $236,000 at December 31, 2007 and 2006, respectively.
     Future minimum commitments under leasing arrangements as of December 31, 2007 were as follows:
                 
    Operating     Capital  
As of December 31, 2007   Leases     Leases  
    (in thousands)  
2008
   $ 4,330     $ 2  
2009
     4,091       —  
2010
     2,371       —  
2011
     —       —  
2012 and thereafter
     —       —  
 
            
Total minimum rental payments
   $ 10,792       2  
 
              
Less amount representing interest
             —  
 
              
Present value of net minimum rental payments
             2  
Less current portion
             2  
 
              
Long-term capitalized lease obligations
           $ —  
 
              

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(9) Stock Option Plans
     We have a 1997 non-qualified stock option plan under which we are authorized to issue up to 1,466 shares of common stock to officers and employees. The exercise price of options may not be less than the fair market value of a share of common stock on the date of grant. Options expire on the tenth anniversary of the grant date unless cessation of employment causes earlier termination. No options were granted during 2005, 2006 or 2007 and as of December 31, 2007, no options were outstanding under the plan.

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(10) Taxes
     The provision (benefit) for income taxes on income from continuing operations before cumulative effect of change in accounting principle includes the following (in thousands):
                                   
                              Predecessor I  
    Successor Company       Company  
                    For the 138       For the 227  
                    Day Period       Day Period  
    For the year     For the year     from August       from January  
    ended     ended     16, 2005 to       1, 2005 to  
    December 31,     December 31,     December 31,       August 15,  
    2007     2006     2005       2005  
Current
                                  
Federal
   $ (525 )   $ 525     $ —       $ —  
State
     —       —       —         —  
 
                          
 
     (525 )     525       —         —  
Deferred
                                  
Federal
     (20,499 )     29,771       9,470         (302 )
State
     (2,899 )     3,938       925         (1,185 )
 
                          
 
     (23,398 )     33,709       10,395         (1,487 )
 
                          
Total
   $ (23,923 )   $ 34,234     $ 10,395       $ (1,487 )
 
                          
     The effective tax rate for income from continuing operations before cumulative effect of change in accounting principle differs from the U.S. federal statutory tax rate as follows:
                                     
                               Predecessor I
    Successor Company      Company
                    For the 138      For the 227
                    Day Period      Day Period
    For the year   For the year   From August      from January
    ended   ended   16, 2005 to      1, 2005 to
    December 31,   December 31,   December 31,      August 15,
    2007   2006   2005      2005
Statutory federal income tax rate
     35.0 %     35.0 %     35.0 %        35.0  
Increases (reductions) in taxes resulting from:
                                   
State income taxes, net of federal tax benefit
     4.6       4.6       2.2          42.6  
Transaction related expenses
                                   
Permanent differences
     —       —       —          2.0  
Other, net
     0.8       —       —          2.7  
             
Effective income tax rate for the period
     40.4 %     39.6 %     37.2 %        82.3  
             
     Changes in the effective state tax rate due to changes in the state apportionment rates are included in state income taxes, net of federal income tax benefit.

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     On June 30, 2005 the State of Ohio enacted new tax legislation that will result in the elimination of the income and franchise tax over a four year period and it will be replaced with a gross receipts based tax. As a result of the new tax structure, we recorded a tax benefit of $1.1 million to adjust the recorded deferred tax account balances for Ohio during 2005.
     Significant components of deferred income tax liabilities and assets are as follows (in thousands):
                 
    December 31,     December 31,  
    2007     2006  
Deferred income tax liabilities:
                
Property and equipment, net
   $ 213,509     $ 214,292  
Other, net
     2,559       198  
 
            
Total deferred income tax liabilities
     216,068       214,490  
Deferred income tax assets:
                
Accrued expenses
     882       882  
Asset retirement obligations
     8,062       7,551  
Fair value of derivatives
     102,286       83,522  
Net operating loss carryforwards
     29,429       26,101  
Senior Secured Notes
     2,913       2,913  
Tax credit carryforwards
     1,775       1,775  
Other, net
     502       503  
Valuation allowance
     (11,476 )     (11,476 )
 
            
Total deferred income tax assets
     134,373       111,771  
 
            
Net deferred income tax liability
   $ 81,695     $ 102,719  
 
            
 
                
Long-term liability
   $ 98,977     $ 115,326  
Current asset
     (17,282 )     (12,607 )
 
            
Net deferred income tax liability
   $ 81,695     $ 102,719  
 
            
     At December 31, 2007, we had approximately $74.5 million of net operating loss carryforwards available for federal income tax reporting purposes. These net operating loss carryforwards, if unused, will expire in 2019 through 2025. We also had state net operating losses aggregating $248 million, which expire between 2008 and 2025. The net operating losses are subject to annual limitations due to IRC Section 382 as a result of the Merger in 2004 and the Transaction in 2005. SFAS No. 109 requires a valuation allowance to be recorded when it is more likely than not that some or all of the deferred tax assets will not be realized. We do not believe the application of Section 382 hinders our ability to utilize the federal net operating losses and, accordingly, no valuation allowance has been recorded. The valuation allowance of $11.5 million relates to certain state net operating loss carryforwards which we estimate would expire before they could be used. We have alternative minimum tax credit carryforwards of approximately $1.8 million, which have no expiration date.
     FIN 48 requires us to evaluate whether any material tax position we have taken will more likely than not be sustained upon examination by the appropriate taxing authority. As we believe that all such material tax positions taken by us are supportable by existing laws and related interpretations, there are no material uncertain tax positions to consider in accordance with FIN 48.
(11) Profit Sharing and Retirement Plans
     Prior to 2006, we had a non-qualified profit sharing arrangement under which we contributed discretionary amounts determined by the compensation committee of our Board of Directors based on attainment of performance targets. Amounts were allocated to substantially all employees based on relative compensation. We expensed $417,000 for the Successor Company 138 day period ended December 31, 2005 and $96,000 for the Predecessor I Company 227 day period ended August 15, 2005, for contributions to the profit sharing plan and discretionary bonuses. All amounts were paid in cash.
     Effective April 1, 2006, our 401(k) retirement plan merged into the EnerVest, Ltd., 401(k) Plan.

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     As of December 31, 2005, we had a 401(k) retirement plan which covered substantially all of our employees. Eligible employees made voluntary contributions which we matched $1.00 for every $1.00 contributed up to 4% of an employee’s annual compensation and a $0.50 match for every $1.00 contributed up to the next 2% of compensation. Retirement plan expense amounted to $83,000 for the Successor Company 138 day period ended December 31, 2005 and $255,000 for the Predecessor I Company 227 day period ended August 15, 2005.
(12) Commitments and Contingencies
     The Company is involved in several lawsuits arising in the ordinary course of business. The Company believes 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.

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(13) Supplemental Disclosure of Cash Flow Information
                                   
                              Predecessor
    Successor Company     I Company
                    138 Day     227 Day
                    Period From     Period From
    For the year   For the year   August 16,     January 1,
    ended   ended   2005 to     2005 to
    December 31,   December 31,   December     August 15,
(in thousands)   2007   2006   31, 2005     2005
Cash paid during the period for:
                                  
Interest
   $ 17,939     $ 25,317     $ 2,433       $ 21,885  
Income taxes, net of refunds
     —       —       (163 )       500  
Non-cash investing and financing activities:
                                  
Acquisition of assets in exchange for long-term liabilities
     —       —       —         —  
(14) Fair Value of Financial Instruments
     The fair value of the financial instruments disclosed herein is not representative of the amount that could be realized or settled, nor does the fair value amount consider the tax consequences, if any, of realization or settlement. The amounts in the financial statements for cash equivalents, accounts receivable and notes receivable approximate fair value due to the short maturities of these instruments. The recorded amounts of outstanding bank and other long-term debt approximate fair value because interest rates are based on LIBOR or the prime rate or due to the short maturities. The $159.5 million (face amount) of our Senior Secured Notes due 2012 had an approximate fair value of $161.1 million at December 31, 2007 based on quoted market prices.
     From time to time, we may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage its exposure to natural gas or oil price volatility. We employ a policy of hedging gas production sold under NYMEX-based contracts by selling NYMEX-based commodity derivative contracts. Our NYMEX crude oil swaps are sold locally at posted price which is different from the NYMEX price. Historically there has been a high correlation between the posted price and NYMEX. The contracts may take the form of futures contracts, swaps, collars or options which are placed with major financial institutions that we believe are minimal credit risks. At December 31, 2007, our derivative contracts consisted of natural gas swaps, natural gas basis differential swaps, crude oil swaps and interest rate swaps. At December 31, 2007, the fair value of futures contracts covering 2007 through 2013 oil and gas production represented an unrealized loss of $235.4 million. At December 31, 2007, the fair value of our interest rate futures contracts covering 2008 through September 2010 represented an unrealized loss of $912,000.

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(15) Supplementary Information on Oil and Gas Activities (Unaudited)
     The following disclosures of costs incurred related to oil and gas activities from continuing operations are presented in accordance with SFAS 69.
                                   
                              Predecessor I
    Successor Company     Company
                    138 Day     227 Day
                    Period From     Period From
                    August 15,     January 1,
                    2005 to     2005 to
    December 31,   December 31,   December 31,     August 15,
(in thousands)   2007   2006   2005     2005
Acquisition costs:
                                  
Proved properties
   107     $ 16     $ 33       $ 16  
Unproved properties
     567       511       118         317  
Developmental costs
     21,910       36,052       8,067         18,700  
Exploratory costs
     1,935       2,343       1,229         2,424  
Estimated Proved Oil and Gas Reserves (Unaudited)
     Our estimated proved developed and estimated proved undeveloped reserves are all located within the United States. We caution that 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 those used. Proved reserves represent estimated quantities of natural gas, crude oil and condensate 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 in place and under operating methods being used at the time the estimates were made. The estimates of proved reserves as of December 31, 2007, 2006 and 2005 have been prepared by Wright & Company, Inc., independent petroleum consultants. The estimated proved reserve information for the 2005 Predecessor I Company 227 day period ended August 15, 2005, is based on our internal engineering estimates.

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     The following table sets forth changes in estimated proved and estimated proved developed reserves for the periods indicated:
                                                             
    Successor Company     Predecessor I Company     Total (non-GAAP)
    Oil   Gas     Oil   Gas     Oil   Gas    
    (Mbbl) (1)   (Mmcf)(2)     (Mbbl) (1)   (Mmcf)(2)     (Mbbl) (1)   (Mmcf)(2)   Mmcfe(3)
January 1, 2005
     —       —         5,579       251,326         5,579       251,326       284,800  
Extensions and discoveries
     32       2,037         3       3,532         35       5,569       5,779  
Purchase of reserves in place
     —       1,586         —       690         —       2,276       2,276  
EnerVest transaction
     5,552       249,335         (5,552 )     (249,335 )       —       —       —  
Revisions of previous estimates
     (232 )     (794 )       186       2,863         (46 )     2,069       1,793  
Production
     (142 )     (5,484 )       (216 )     (9,076 )       (358 )     (14,560 )     (16,710 )
 
                                                            
December 31, 2005
     5,210       246,680         —       —         5,210       246,680       277,938  
Extensions and discoveries
     156       12,892                           156       12,892       13,830  
Purchase of reserves in place
     41       881                           41       881       1,130  
Sale of reserves in place
     —       (1,342 )                         —       (1,342 )     (1,342 )
Revisions of previous estimates
     146       (11,996 )                         146       (11,996 )     (11,123 )
Production
     (372 )     (14,104 )                         (372 )     (14,104 )     (16,337 )
 
                                                            
December 31, 2006
     5,181       233,011         —       —         5,181       233,011       264,096  
Extensions and discoveries
     153       4,853                           153       4,853       5,771  
Purchase of reserves in place
     —       5,340                           —       5,340       5,340  
Revisions of previous estimates
     163       (2,647 )                         163       (2,647 )     (1,668 )
Production
     (348 )     (13,357 )                         (348 )     (13,357 )     (15,445 )
 
                                                            
December 31, 2007
     5,149       227,200         —       —         5,149       227,200       258,094  
 
                                                            
Proved developed reserves
                                                            
December 31, 2005
     3,822       203,443                           3,822       203,443       226,375  
 
                                                            
December 31, 2006
     3,832       188,374                           3,832       188,374       211,368  
 
                                                            
December 31, 2007
     3,890       186,765                           3,890       186,765       210,105  
 
                                                            
 
(1)   Thousand barrels
 
(2)   Million cubic feet
 
(3)   Million cubic feet equivalent, barrels are converted to Mcfe based on one barrel of oil to six Mcf of natural gas equivalent.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)
     The following tables, which present a standardized measure of discounted future net cash flows and changes therein relating to estimated proved oil and gas reserves, are presented pursuant to SFAS No. 69. In computing this data, assumptions other than those required by the FASB could produce different

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results. Accordingly, the data should not be construed as representative of the fair market value of our estimated proved oil and gas reserves. The following assumptions have been made:
  -   Future revenues were based on year-end oil and gas prices. Future price changes were included only to the extent provided by existing contractual agreements.
 
  -   Production and development costs were computed using year-end costs assuming no change in present economic conditions.
 
  -   Future net cash flows were discounted at an annual rate of 10%.
 
  -   Future income taxes were computed using the approximate statutory tax rate and giving effect to available net operating losses, tax credits and statutory depletion.
     The standardized measure of discounted future net cash flows relating to estimated proved oil and gas reserves is presented below:
                             
    December 31,  
    2007       2006       2005  
              (in thousands)            
Estimated future cash inflows (outflows)
                            
Revenues from the sale of oil and gas
   $ 2,190,884       $ 1,672,532       $ 2,726,170  
Production costs
     (590,328 )       (526,928 )       (639,366 )
Development costs
     (152,465 )       (134,553 )       (128,933 )
Future income taxes
     (497,904 )       (316,413 )       (651,594 )
 
                      
Future net cash flows
     950,187         694,638         1,306,277  
10% timing discount
     (561,301 )       (395,157 )       (760,513 )
 
                      
Standardized measure of discounted future net cash flows
   $ 388,886       $ 299,481       $ 545,764  
 
                      
     At December 31, 2007, 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.
     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 derivative financial instruments, consisting of swaps and collars, in the determination of our oil and gas reserves.
                         
    December 31,
    2007   2006   2005
Gas (per Mcf)
   $ 7.54     $ 5.91     $ 9.83  
Oil (per Bbl)
     92.77       57.21       57.64  

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     The principal sources of changes in the standardized measure of future net cash flows are as follows:
                                   
                              Predecessor I  
    Successor Company       Company  
                    138 Day Period       227 Day Period  
                    From August 16,       From January  
    Year ended     Year ended     2005 to       1, 2005 to  
    December 31,     December 31,     December 31,       August 15,  
    2007     2006     2005       2005  
Beginning of year
   $ 299,481     $ 545,764     $ 575,512       $ 345,712  
Sale of oil and gas, net of production costs
     (96,317 )     (102,710 )     (60,103 )       (56,391 )
Extensions and discoveries, less related estimated future development and production costs
     14,720       25,806       6,422         11,608  
Previously estimated development costs incurred during the period
     21,910       29,477       8,503         16,667  
Purchase of reserves in place less estimated future production costs
     2,728       170       3,014         1,504  
Sale of reserves in place less estimated future production costs
     —       (4,122 )     —         —  
Changes in estimated future development costs
     (7,337 )     (33,665 )     (13,903 )       (13,356 )
Revisions of previous quantity estimates
     (237 )     (20,621 )     (6,964 )       13,150  
Net changes in prices and production costs
     196,244       (354,397 )     (28,924 )       367,871  
Change in income taxes
     (75,511 )     148,217       20,419         (142,102 )
Accretion of 10% timing discount
     29,948       83,145       33,060         31,857  
Changes in production rates (timing) and other
     3,257       (17,583 )     8,728         (1,008 )
 
                          
End of period
   $ 388,886     $ 299,481     $ 545,764       $ 575,512  
 
                          
(16) Industry Segment Financial Information
     We operate in one reportable segment, as an independent energy company engaged in producing oil and natural gas; exploring for and developing oil and gas reserves; acquiring and enhancing the economic performance of producing oil and gas properties; and marketing and gathering natural gas for delivery to intrastate and interstate gas transmission pipelines. Our operations are conducted entirely in the United States.
Major customers
     During 2007, we had three customers that each accounted for 10% or more of consolidated revenues with sales of $26.3 million, $18.9 million and $18.1 million, respectively. During 2006, we had three customers that each accounted for 10% or more of consolidated revenues with sales of $21.4 million, $20.1 million and $18.5 million, respectively. During 2005, we had three customers that each accounted for 10% or more of consolidated revenues with sales of $21.1 million, $20.5 million and $20.3 million, respectively.

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(17) Quarterly Results of Operations (Unaudited)
     The results of operations for the four quarters of 2007 and 2006 are shown below (in thousands).
                                 
    First   Second   Third   Fourth
2007
                                
Operating revenues
   $ 29,422     $ 34,801     $ 29,420     $ 31,059  
Gross profit
     11,580       15,676       11,555       12,379  
Net (loss) income
     (23,299 )     2,415       7,268       (21,706 )
 
                                
2006
                                
Operating revenues
   $ 44,688     $ 38,466     $ 34,050     $ 41,212  
Gross profit
     25,314       21,604       14,806       20,941  
Net income
     5,388       4,744       34,195       7,872  
(18) Related Party Transactions
     On August 16, 2005, the former partners of Capital C completed the sale of all of the partnership interests in Capital C to certain institutional funds managed by EnerVest, Ltd. EnerVest incurred and was reimbursed $1.1 million by us for transaction costs. This amount was recorded as an accrued expense at December 31, 2005 and was paid in January 2006.
     On March 15, 2006, we entered into a joint operating agreement with EnerVest Operating L.L.C. (“EnerVest Operating”), a subsidiary of EnerVest. The joint operating agreement was effective October 1, 2005 and resulted in expense to us of $642,000 in 2005, $5.3 million in 2006 and $6.0 million in 2007 for overhead fees. We also paid $6.7 million in 2006 and $7.5 million in 2007 for field labor, vehicles and district office expense; $875,000 in 2006 and $331,000 in 2007 for drilling overhead fees and $1.3 million in 2006 and $1.2 million in 2007 for drilling labor costs in 2006 related to this agreement. We reimbursed EnerVest Operating for expenses of $332,000 in 2006 related to the transition of accounting responsibilities to EnerVest Operating’s Charleston, West Virginia office.
     We paid approximately $211,000 to Opportune LLP in the 2006 for consulting services related to the Company’s amended filings and the 2005 Form 10-K. John Vanderhider, brother of James Vanderhider, our President and Chief Financial Officer, is a partner with Opportune.
     We paid approximately $207,000 to PetroAcct LP in 2006 for services related to the transition of accounting and information system responsibilities to EnerVest Operating. A subsidiary of EnerVest, Ltd owned 50% of PetroAcct during 2006. The 50% ownership interest in PetroAcct was sold to Opportune in March 2007.
     As of December 31, 2007, we owed EnerVest Operating $1,531,000 and EnerVest owed us $23,000.
     In connection with the Transaction, we executed a subordinated promissory note in favor of our parent, Capital C in the maximum amount of $94 million. Under the note, Capital C loaned $25 million to us on August 16, 2005 in connection with the Transaction. The note accrues interest at 10% per year and matures on August 16, 2012. We received a fairness opinion from an unrelated financial services firm with respect to the terms of the note made on August 16, 2005. Interest payments on the note are

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due quarterly commencing September 30, 2005. In lieu of cash payments, we have the option to make interest payments on the note by borrowing additional amounts against the note. The amount due under the note at December 31, 2007 was $26.9 million. We made cash payments of $945,000 in 2005 and $2.5 million in 2006. In 2007, we made a cash payment of $616,000 and borrowed an additional $1.9 million against the Note for interest payments.
     Messrs. Houser, Vanderhider and Mariani are officers and directors of the Company and they are officers and equity owners of EnerVest and EnerVest Operating. The institutional funds that are managed by EnerVest and own our direct parent, Capital C, also hold other investments in oil and gas assets and operations. We can give no assurance that conflicts of interest will not arise for 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. Houser, Vanderhider and Mariani.

F-31

EX-31.1 2 l29594aexv31w1.htm EX-31.1 EX-31.1
 

EXHIBIT 31.1
CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
 
I, Mark A. Houser, certify that:
1. I have reviewed this annual report on Form 10-K of Belden & Blake Corporation;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
             
Date:
  March 28, 2008       /s/ Mark A. Houser
 
           
 
          Mark A. Houser, Chief Executive Officer and
 
          Chairman of the Board of Directors

 

EX-31.2 3 l29594aexv31w2.htm EX-31.2 EX-31.2
 

EXHIBIT 31.2
CERTIFICATION PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
 
I, James M. Vanderhider, certify that:
1. I have reviewed this annual report on Form 10-K of Belden & Blake Corporation;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
c) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):
a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
             
Date:
  March 28, 2008       /s/ James M. Vanderhider
 
           
 
          James M. Vanderhider, President,
 
          Chief Financial Officer and Director

 

EX-32.1 4 l29594aexv32w1.htm EX-32.1 EX-32.1
 

Exhibit 32.1
CERTIFICATION PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
 
      In connection with the Annual Report of Belden & Blake Corporation (the “Company”) on Form 10-K for the period ended December 31, 2007, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, in the capacities and on the dates indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the knowledge of the undersigned:
  1.   The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
 
  2.   The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
             
Date:
  March 28, 2008       /s/ Mark A. Houser
 
           
 
          Mark A. Houser, Chief Executive Officer and
 
          Chairman of the Board of Directors
This certification accompanies the Form 10-K and shall not be treated as having been filed as part of the Form 10-K.

 

EX-32.2 5 l29594aexv32w2.htm EX-32.2 EX-32.2
 

Exhibit 32.2
CERTIFICATION PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
 
      In connection with the Annual Report of Belden & Blake Corporation (the “Company”) on Form 10-K for the period ended December 31, 2007, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, in the capacities and on the dates indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the knowledge of the undersigned:
  1.   The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
 
  2.   The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
             
Date:
  March 28, 2008       /s/ James M. Vanderhider
 
           
 
          James M. Vanderhider, President,
 
          Chief Financial Officer and Director
This certification accompanies the Form 10-K and shall not be treated as having been filed as part of the Form 10-K.

 

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