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, 2008

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 28, 2009, 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.

TABLE OF CONTENTS

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)
EXHIBIT INDEX
Exhibit 10.9
Exhibit 23.1
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

DOCUMENTS INCORPORATED BY REFERENCE:

None.

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, including the financial and capital market crisis, new legislation or regulatory changes, changes in accounting principles, policies or guidelines and environmental risks. These and other risks are described on page 15 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.

1

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.

2

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.

3

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. 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 the 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.

Credit Agreement

In 2005, we amended and restated our then existing 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. The obligations under the Amended Credit Agreement are secured by substantially all of our assets.

4

Effective April 9, 2009, the Company entered into the Fourth Amendment, Waiver and Agreement related to the Amended Credit Agreement. The agreement was entered into to provide for certain waivers and modifications to the debt terms and covenants. This amendment was a direct result of the determination as of December 31, 2008, that the Company, would not maintain compliance with certain financial covenants during 2009 and 2010. Accordingly, on April 9, 2009, our bank group waived the leverage ratio for the quarters ended March 31, 2009 and June 30, 2009 and amended the Amended Credit Agreement to increase the maximum leverage ratio to 5.375 : 1.0 through December 31, 2009, 5.25 : 1.0 at March 31, 2010 and 5.0 : 1.0 at June 30, 2010. The bank group also waived the interest coverage ratio as of June 30, 2009 and amended the Amended Credit Agreement to reduce our minimum interest coverage ratio to 2.0 : 1.0 through March 31, 2010 and 2.25 : 1.0 at June 30, 2010. Additionally, Capital C, our parent, has committed to the Company to provide financial support. Taking into consideration the amended financial covenants and the financial support from Capital C, the Company, as of April 9, 2009, has projected that it would maintain compliance with such amended covenants through 2009 and 2010.

Additionally, the amendment provided that the borrowings under the Amended Credit Agreement bear interest (i) at the greater of the prime rate, an adjusted federal funds rate or an adjusted Eurodollar rate, plus an applicable margin ranging from 1.0% to 1.75% 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 2.5% to 3.25% based on the aggregate principal amount outstanding under the Amended Credit Agreement. The agreement was also amended for the following:

• Set the Borrowing Base at $100 million.

• Set the Borrowing Base redetermination dates to March 15^th and September 15^th each year.

• Prohibit payment of dividends to our shareholder.

• Prohibit Senior Secured Note repurchases by the Company.

• Prohibit principal or cash interest payments on the Capital C Subordinated Note.

• Prohibit borrowings to fund restructuring of the hedge agreements.

• Require the pay down of the Amended Credit Agreement with certain proceeds of asset sales and equity contributions, of which $20 million is required to be paid by July 15, 2009.

• Reduce the Borrowing Base by the amount of each repayment until the aggregate amount of such repayments is equal to $30 million.

• Increase the percentage of the value of total proved reserves that is required to be mortgaged from 75% to 80% effective May 31, 2009.

At December 31, 2008, we were in compliance with our covenants under the Amended Credit Agreement. Our leverage ratio was 4.25 : 1.0 and the interest coverage ratio was 2.72 : 1.0.

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 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 2006, the first quarter of 2007 and the first three quarters of 2008 were paid in cash. Interest payments for the last three quarters of 2007 and the fourth quarter of 2008 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. Pursuant to the Fourth Amendment to our credit agreement, cash payments for principal or interest on the Subordinated Note are prohibited. The Subordinated Note is subordinate to our senior debt, which includes obligations under the Amended Credit Agreement, a long-term hedging program (the “Hedges”) with J. Aron under a master agreement and related confirmations and documentation (collectively, the “Hedge Agreement”) and notes issued under our Indenture dated July 7, 2004 with BNY Midwest Trust Company, as indenture trustee (“Senior Secured Notes”).

Impairment of goodwill

We recorded a goodwill impairment charge of $90.1 million in the fourth quarter of 2008 due to the significant decline in oil and gas prices. See further discussion in “Critical Accounting Policies and Estimates,” in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and Note 9, “Goodwill.”

5

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 2008, we achieved average net production of approximately 41.8 MMcfe per day consisting of 36.0 MMcf of natural gas and 956 Bbls of oil per day. At December 31, 2008, we owned interests in 4,550 gross (3,608 net) productive oil and gas wells in Ohio, Pennsylvania, New York and Michigan with estimated proved reserves totaling 223 Bcfe consisting of 200 Bcf of natural gas and 3.8 MMbbl of oil. The estimated future net cash flows from these reserves had a present value (discounted at 10%) after income taxes of approximately $253 million at December 31, 2008. The weighted average prices related to estimated proved reserves at December 31, 2008 were $6.38 per Mcf for natural gas and $41.00 per Bbl for oil.

We 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, 2008, Enervest Operating operated approximately 4,006 wells, or 88% of our gross wells representing approximately 97% of the value of our estimated proved developed reserves on a present value (discounted at 10%) basis. At December 31, 2008, we owned leases on 639,724 gross (562,068 net) acres, including 409,268 gross (381,165 net) undeveloped acres.

We own approximately 1,660 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 2008, our average per unit gas prices (excluding the effects of hedging) in Appalachia and Michigan were $0.45 and $0.08, respectively, higher than the average NYMEX monthly settle price for 2008.

6

Oil and Gas Reserves

The following table sets forth our estimated proved oil and gas reserves as of December 31, 2006, 2007 and 2008 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,
	2008		2007		2006
Estimated proved reserves
Gas (Bcf)		199.8		227.2		233.0
Oil (Mbbl)		3,833		5,149		5,181
Bcfe		222.8		258.1		264.1

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

The present value of the estimated future net cash flows after income taxes from our estimated proved reserves as of December 31, 2008, determined in accordance with the rules and regulations of the SEC, was $253 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, 2008 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, consisting of natural gas and crude oil swaps and natural gas basis differential swaps, in the determination of our oil and gas reserves.

	December 31,
	2008		2007		2006
Gas (per Mcf)	$	6.38	$	7.54	$	5.91
Oil (per Bbl)		41.00		92.77		57.21

At December 31, 2008, 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 prices 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.

7

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.

We currently own working interests in 3,118 gross (2,800 net) wells in the Appalachian Basin, excluding our coalbed methane wells, which currently produce approximately 21.3 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 2008, we drilled 22 gross (21.8 net) development wells in the Medina Formation in Pennsylvania, 38 gross (38.0 net) development wells in the Clarendon Formation in Pennsylvania, 1 gross (1.0 net) Onondaga development well in Pennsylvania, 6 gross (3.1 net) Clinton development wells in Ohio and 5 gross (5.0 net) Utica Shale development wells in Ohio. We also drilled 3 gross (3.0 net) exploratory dry holes in 2008. Due to a change in market conditions, the anticipated 2009 focus will be primarily in the following three areas: Knox exploration in Ohio, operational reworks and enhancement projects, and Marcellus recompletions and new drilling in Pennsylvania. We will continue to evaluate our development drilling opportunities in our traditional areas such as the Medina and Clarendon formations in Pennsylvania and the Clinton Formation in Ohio as market conditions improve.

Michigan Basin Properties

The Michigan Basin has operational similarities to the Appalachian Basin, including geographic proximity to natural gas markets, which has generally resulted in premium wellhead prices as compared to NYMEX prices. We own working interests in 1,227 gross (603 net) wells in the Michigan Basin which currently produce approximately 16.5 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 2008, we drilled 24 gross (11.6 net) wells to the Antrim Shale Formation. We plan to drill 10 gross (5.6 net) wells in the Antrim Shale Formation in 2009. We also drilled 2 gross and (1.9 net) exploratory dry holes in 2008.

Appalachian Basin — Coalbed Methane Properties

We own a 100% working interest in 205 producing coalbed methane (“CBM”) wells in Pennsylvania and own leases on approximately 63,185 gross (61,078 net) acres, including approximately 53,017 gross (52,708 net) undeveloped CBM acres. Current production from these wells is approximately 2.9 MMcf net per day. We drilled 3 CBM wells in 2008 and have no plans to drill additional CBM wells in 2009.

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 1,660 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.

8

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,
	2008		2007		2006
Production
Gas (MMcf)		13,217		13,357		14,104
Oil (Mbbl)		334		348		373
Total production (MMcfe)		15,221		15,446		16,340
Average price (1)
Gas (per Mcf)	$	8.62	$	6.81	$	8.77
Oil (per Bbl)		94.40		67.42		62.78
Per Mcfe		9.55		7.41		9.00
Average costs (per Mcfe)
Production expense	$	1.73	$	1.59	$	1.45
Production taxes		0.20		0.15		0.15
Depletion		2.31		2.31		2.30

(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,
	2008		2007		2006
Gas (per Mcf)	$	9.31	$	7.34	$	7.22
Oil (per Bbl)		94.40		67.42		62.78
Per Mcfe		10.15		7.87		7.67

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 2008, we spent approximately $28.3 million on development and exploratory drilling and other capital expenditures including exploratory dry hole costs. We drilled 98 gross (83.5 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 10. We also drilled 5 gross and (4.9 net) exploratory dry holes on 2008.

In 2009, we expect to spend approximately $15 million on development and exploratory drilling and other capital expenditures. Due to a change in market conditions for oil and natural gas, the anticipated 2009 focus primarily will be in the following three areas: Knox exploration in Ohio, operational reworks and enhancement projects and Marcellus recompletions and new drilling in Pennsylvania. We will continue to evaluate our development drilling opportunities in our traditional areas such as the Antrim play in Michigan, the Medina and Clarendon plays in Pennsylvania and the Clinton play in Ohio.

We were a pioneer in CBM development and production in Pennsylvania, and we presently own a 100% working interest in 205 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. We have approximately 63,185 CBM acres currently under lease in Pennsylvania. We currently have no plans to drill CBM wells in 2009.

9

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.

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

		Range of Average
		Drilling and
		Completion Costs per
	Range of Well Depths	Well
	(in feet)	(in thousands)
Ohio:
Clinton	3,500–5,750	$360–420
Pennsylvania:
Coalbed Methane	1,000–1,600	210–320
Clarendon	1,100–2,100	120–150
Medina	5,300–6,200	370–400
Michigan:
Antrim	1,300–2,100	310–370

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, Marcellus 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
	2006		2007		2008		2006(1)		2007		2008
Productive:
Gross		177		96		98		—		—		—
Net		170.3		92.0		83.5		—		—		—
Dry:
Gross		2		—		—		1		—		5
Net		2.0		—		—		0.5		—		4.9
Wells in progress:
Gross		—		—		—		—		—		—
Net		—		—		—		—		—		—

⁽¹⁾ Includes one well (dry hole) that was classified as a well in progress in 2005.

10

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.

In March of 2008, we sold a 50-70% option interest in certain deep rights on approximately 201,000 net acres in Ohio and Pennsylvania for $3.0 million.

Employees

As of February 28, 2009, we had no employees. On March 15, 2006, we entered into a joint operating agreement with EnerVest Operating L.L.C. (“EnerVest Operating”), a subsidiary of EnerVest. 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 2008: 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. We do not believe any of our customers are credit risks.

Title to Properties

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. Prior to completing an acquisition of producing natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. As a result, we have obtained title opinions on a significant portion of our natural gas properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the natural gas and oil industry. Our properties are subject to customary royalty and other interests, liens for current taxes and other burdens that we believe do not materially interfere with the use of or affect our carrying value of the properties.

11

Regulation

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

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

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

The 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 address 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 noncompliance with these environmental requirements, there is no assurance that this trend will continue in the future.

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Under the federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, and comparable state laws, liability generally is joint and several for costs of investigation and remediation and for natural resource damages, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances (“Hazardous Substances”). These classes of persons, or so-called potentially responsible parties (“PRP”), include current and certain past owners and operators of a facility where there has been a release or threat of release of a Hazardous Substance and persons who disposed of or arranged for the disposal of the Hazardous Substances found at such a facility. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the PRP the costs of such action. Although CERCLA generally exempts “petroleum” from the definition of Hazardous Substance, in the course of its operations, we have generated and will generate wastes that fall within CERCLA’s definition of Hazardous Substances. We may also be an owner or operator of facilities on which Hazardous Substances have been released. We may be responsible under CERCLA for all or part of the costs to clean up facilities at which such substances have been released and for natural resource damages, as a past or present owner or operator or as an arranger. To our knowledge, we have not been named a PRP under CERCLA nor have any prior owners or operators of our properties been named as PRP’s related to their ownership or operation of such property.

Although oil and gas wastes generally are exempt from regulation as hazardous wastes (“Hazardous Wastes”) under the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes, it is possible some wastes we generate presently or in the future may be subject to regulation under RCRA and state analogs. The U.S. EPA and various state agencies have limited the disposal options for certain wastes, including hazardous wastes and is considering adopting stricter disposal standards for non-hazardous wastes. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils, may be regulated as hazardous waste. Although the costs of managing these wastes generated by us may be significant, we do not expect to experience more burdensome costs than similarly situated companies involved in oil and gas exploration and production.

We currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the exploration and production of oil and gas. Hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon may be subject 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. Federal and state laws generally require new and modified sources of air pollutants to obtain permits prior to commencing construction, which may require, among other things, stringent, technical controls. Other federal and state laws designed to control hazardous (toxic) air pollutants, might require installation of additional controls. Administrative enforcement agencies can bring actions for failure to strictly comply with air pollution regulations or permits and generally enforce compliance through administrative, civil or criminal enforcement actions, resulting in fines, injunctive relief and imprisonment.

More stringent laws and regulations relating to climate change and greenhouse gases (GHGs) may be adopted in the future and could cause us to incur material expenses in complying with them. The U.S. Congress last session considered climate change-related legislation to regulate GHG emissions that could affect our operations and our regulatory costs, as well as the value of oil and natural gas generally. Although that legislation did not pass, expectations are that Congress will continue to consider some type of climate change legislation and that U.S. EPA may consider climate change-related regulatory initiatives. As a result, there is a great deal of uncertainty as to how and when federal regulation of GHGs might take place. In addition to possible federal regulation, a number of states, individually and regionally, also are considering or have implemented GHG regulatory programs. These potential federal and state initiatives may result in so-called cap-and-trade programs, under which overall GHG emissions are limited and GHG emissions are then allocated and sold, and possibly other regulatory requirements, that could result in our incurring material expenses to comply, e.g., by being required to purchase or to surrender allowances for GHGs resulting from our operations. These regulatory initiatives also could adversely affect the marketability of the oil and natural gas we produce.

13

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, a term broadly defined, 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, including permit 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 waters of the United States. The OPA imposes strict, joint and several liability on liable responsible parties for oil removal costs and a variety of public and private damages, including natural resource damages. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge or, in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. 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.

The federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes impose requirements related to disclosure and organization of certain information related to hazardous materials. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes may require us to organize and/or disclose information about hazardous materials used or produced in our operations.

Producing Well Data

As of December 31, 2008, we owned interests in 4,550 gross (3,608 net) producing oil and gas wells of which approximately 4,006 wells were operated by EnerVest Operating. In the fourth quarter of 2008, our net production was approximately 41.8 MMcfe per day consisting of 36.0 MMcf of natural gas and 956 Bbls of oil per day.

The following table summarizes by state our productive wells at December 31, 2008:

	December 31, 2008
	Gas Wells				Oil Wells				Total
State	Gross		Net		Gross		Net		Gross		Net
Ohio		1,048		893		677		609		1,725		1,502
Pennsylvania		1,476		1,392		104		104		1,580		1,496
New York		18		7		—		—		18		7
Michigan		1,210		601		17		2		1,227		603
		3,752		2,893		798		715		4,550		3,608

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Acreage Data

The following table summarizes by state our gross and net developed and undeveloped acreage at December 31, 2008:

	December 31, 2008
	Developed Acreage				Undeveloped Acreage				Total Acreage
State	Gross		Net		Gross		Net		Gross		Net
Ohio		112,644		64,701		115,151		115,072		227,795		179,773
Pennsylvania		50,642		49,907		251,227		226,981		301,869		276,888
New York		2,828		2,241		26,805		26,226		29,633		28,467
Michigan		64,302		64,014		14,752		11,553		79,054		75,567
Indiana		40		40		1,333		1,333		1,373		1,373
		230,456		180,903		409,268		381,165		639,724		562,068

In prior filings developed acreage included undrilled acreage held by production. Beginning with fiscal year 2008, undrilled acreage held by production is included in undeveloped acreage.

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 69% of the expected 2009 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;

• 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 which risk has increased with the current economic and financial crisis; or

• a sudden, unexpected event materially impacts natural gas and crude oil prices.

While we believe J. Aron to be a strong and creditworthy counterparty, current disruptions occurring in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair their ability to perform under the terms of the hedging contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

15

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 Amended Credit Agreement in an amount sufficient to enable us to pay our indebtedness, including the Senior Secured Notes or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness, including the Senior Secured Notes on or before maturity. We cannot assure you that we will be able to refinance any of our indebtedness, including our Amended Credit Agreement and the Senior Secured Notes, on commercially reasonable terms or at all, especially given the current economic and financial market crisis. 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.

We depend upon access to the credit markets to fund our growth strategy. Currently, the credit markets are experiencing an unprecedented disruption which, if it continues for an extended period of time, will adversely affect our growth strategy.

U.S. and international financial and credit markets are experiencing unprecedented volatility and disruption. The current disruption in the financial and credit markets has made it unlikely that we could successfully issue common stock, debt securities or secure a loan to fund our growth in the near future. In addition, the current markets for bank credit facilities are unfavorable to borrowers. If the disruption in the financial markets continues for a substantial period of time, our ability to fund growth may be adversely affected.

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. If gas prices decreased $1.00 per Mcf, our gas sales revenues would decrease by approximately $13.2 million. If the price of crude oil decreased $10.00 per Bbl, our oil sales revenues would decrease by approximately $3.3 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 $4.4 million after considering the effects of the derivative contracts in place as of December 31, 2008. This sensitivity analysis is based on our 2008 oil and gas sales volumes. A material decline could reduce our cash flow and borrowing capacity, as well as the value and the amount of our natural gas reserves. Approximately 90% of our proved reserves are natural gas. Therefore, we are more directly impacted by volatility in the price of natural gas. For example, as of December 31, 2008, a 10% reduction in the price of oil and natural gas would have reduced our future net cash flow from proved reserves by $29 million. 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, including the current economic and capital market crisis; 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.

16

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

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

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

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. In 2008, we recorded an impairment to our oil and natural gas properties of $3.9 million.

Information concerning our reserves and future net revenues is uncertain.

This Annual Report and our other 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, 2008, approximately 11% 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.

17

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;

• 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.

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.

18

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 insure 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.

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 Senior Secured 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 Senior Secured Notes. See “Item 13 — Certain Relationships and Related Transactions.”

19

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 J. Aron Swap 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.

Effective April 9, 2009, the Company entered into the Fourth Amendment, Waiver and Agreement related to the Amended Credit Agreement. The agreement was entered into to provide for certain waivers and modifications to the debt terms and covenants. This amendment was a direct result of the determination as of December 31, 2008, that the Company, would not maintain compliance with certain financial covenants during 2009 and 2010. Accordingly, on April 9, 2009, our bank group waived the leverage ratio for the quarters ended March 31, 2009 and June 30, 2009 and amended the Amended Credit Agreement to increase the maximum leverage ratio to 5.375 : 1.0 through December 31, 2009, 5.25 : 1.0 at March 31, 2010 and 5.0 : 1.0 at June 30, 2010. The bank group also waived the interest coverage ratio as of June 30, 2009 and amended the Amended Credit Agreement to reduce our minimum interest coverage ratio to 2.0 : 1.0 through March 31, 2010 and 2.25 : 1.0 at June 30, 2010. Additionally, Capital C, our parent, has committed to the Company to provide financial support. Taking into consideration the amended financial covenants and the financial support from Capital C, the Company, as of April 9, 2009, has projected that it would maintain compliance with such amended covenants through 2009 and 2010.

Additionally, the amendment provided that the borrowings under the Amended Credit Agreement bear interest (i) at the greater of the prime rate, an adjusted federal funds rate or an adjusted Eurodollar rate, plus an applicable margin ranging from 1.0% to 1.75% 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 2.5% to 3.25% based on the aggregate principal amount outstanding under the Amended Credit Agreement. The agreement was also amended for the following:

• Set the Borrowing Base at $100 million.

• Set the Borrowing Base redetermination dates to March 15^th and September 15^th each year.

• Prohibit payment of dividends to our shareholder.

• Prohibit Senior Secured Note repurchases by the Company.

• Prohibit principal or cash interest payments on the Capital C Subordinated Note.

• Prohibit borrowings to fund restructuring of the hedge agreements.

• Require the pay down of the Amended Credit Agreement with certain proceeds of asset sales and equity contributions, of which $20 million is required to be paid by July 15, 2009.

• Reduce the Borrowing Base by the amount of each repayment until the aggregate amount of such repayments is equal to $30 million.

• Increase the percentage of the value of total proved reserves that is required to be mortgaged from 75% to 80% effective May 31, 2009.

At December 31, 2008, we were in compliance with our covenants under the Amended Credit Agreement. Our leverage ratio was 4.25 : 1.0 and the interest coverage ratio was 2.72 : 1.0.

In addition, our existing debt agreements and any new debt agreements may impose financial restrictions and other covenants on us that may be more restrictive than those applicable to the Senior Secured Notes.

Our Amended Credit Agreement and the Hedge Agreement contain, and any future refinancing of our Amended Credit Agreement 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.

20

Our Amended Credit Agreement 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 Senior Secured 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.

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, 2009, were held by Capital C.

Dividends

We paid cash dividends of $2.5 million in 2008, $9.8 million in 2007 and $20.0 million in 2006.

21

Item 6. SELECTED FINANCIAL DATA

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

													Predecessor I						Predecessor II
	Successor Company												Company						Company
										For the 138			For the 227			For the 178			For the 188
										Day Period			Day Period			Day Period			Day Period
										from August			From January			from July			from January
										16, 2005 to			1, 2005 to			7, 2004 to			1, 2004 to
	As of or for the year ended December 31,									December 31,			August 15,			December 31,			July 6,
(in thousands)	2008			2007			2006			2005			2005			2004			2004
Continuing Operations:
Revenues	$	158,426		$	125,140		$	158,774		$	76,642		$	77,960		$	62,256		$	50,816
Depreciation, depletion and amortization		35,560			36,087			38,074			14,341			21,265			17,527			9,089
Impairment of oil and gas properties		3,924			31			546			—			—			—			—
Impairment of goodwill		90,076			—			—			—			—			—			—
Income (loss) from continuing operations		(28,944	)		(35,322	)		52,199			17,563			(320	)		7,263			(18,869	)
Balance sheet data:										As of 12/31/2005						As of 12/31/2004
Working capital (deficit) from continuing operations		(16,806	)		(14,224	)		(11,635	)		(38,999	)					(4,907	)
Oil and gas properties and gathering systems, net		613,834			627,556			641,879			648,417						502,765
Total assets		669,464			774,225			777,023			810,118						570,853
Long-term debt, less current portion		265,863			291,118			285,560			277,648						281,396
Total shareholders’ (deficit) equity		76,551			102,223			143,703			89,399						57,088

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, financial data for the period subsequent to August 15, 2005 is presented on our new basis of accounting, while the financial data for prior periods reflect the historical results of the two predecessor companies. Vertical black lines are presented to separate the financial data 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.

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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, 2008, our total estimated proved reserves were 223 Bcfe. Natural gas comprised approximately 90% of our estimated proved reserves, and 89% 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, 2008, our conventional Appalachian properties accounted for 48% of our estimated proved reserves, while the Michigan properties and our Appalachian CBM properties accounted for 44% and 8%, 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 $100 million, and a $40 million letter of credit facility and our issuance of a $25 million Subordinated Promissory Note with a related party (see Note 20 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 Amended Credit Agreement and the indenture governing the Senior Secured Notes, we will maintain such Hedges with J. Aron or its successor permitted assigns. We anticipate that the Hedges will cover approximately 69% of the expected 2009 through 2013 production from our current estimated proved reserves and will range from 62% to 77% of such expected production in any year.

The average price realized for our natural gas, inclusive of qualified effective hedges, decreased from $8.77 per Mcf in 2006 to $6.81 per Mcf in 2007 and then increased to $8.62 per Mcf in 2008. The monthly average settle for natural gas trading on the NYMEX decreased from $7.23 per MMbtu in 2006 to $6.86 per MMbtu in 2007 and then increased to $9.04 per MMbtu in 2008. 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 2008, our average per unit gas prices (excluding the effects of hedging) in Appalachia and Michigan were $0.45 and $0.08, respectively, higher than the average NYMEX monthly settle price for 2008. The remainder of the difference is primarily due to our qualified hedging activities during these periods. Our average realized price for oil increased from $62.78 per Bbl in 2006 to $67.42 per Bbl in 2007 and to $94.40 per Bbl in 2008.

We recorded a goodwill impairment charge of $90.1 million in the fourth quarter of 2008 due to the significant decline in oil and gas prices.

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Impact of the Current Financial and Credit Markets

The U.S. and other world economies are currently in a recession which could last well into 2009 and beyond. Additionally, the financial and credit markets are undergoing unprecedented disruptions. Many financial institutions have liquidity concerns prompting intervention from governments. Our exposure to the disruptions in the financial markets includes our credit facility and investments exposure.

Our credit facility extends through August 16, 2010. If the disruption in the financial markets continues for an extended period of time, replacement or amendment of the credit facility may be more expensive.

Current market conditions also elevate concerns about cash and cash equivalent investments, which at December 31, 2008 totaled $22.8 million. We have reviewed the creditworthiness of the banks and financial institutions with which we maintain investments, each of whom we believe to be creditworthy, as well as the securities underlying these investments.

We have also reviewed the creditworthiness of our hedge counterparty and believe that it is creditworthy.

Additionally, oil and gas prices are also volatile as evidenced by the significant decline during late 2008 and early 2009. Continued lower commodity prices will reduce the Company’s cash flows from operations.

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:

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 all 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.

24

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.

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.

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 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. The fair value of the reporting unit is based on estimates of future net cash flows from proved reserves and from future exploration for and development of unproved reserves. In the fourth quarter of 2008, we recorded a goodwill impairment charge of $90.1 million due to the significant drop in oil and gas prices resulting in part from the global economic and market crisis.

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.

25

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, 2008, 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. Our NYMEX crude oil swaps were highly effective and were designated as cash flow hedges through August 16, 2005. 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 fair value of the oil swaps subsequent to 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.

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, 2008 or 2007. 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 additional wells having been drilled and accretion expense.

At December 31, 2008, 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, 2008 and 2007 is as follows (in thousands):

	Year Ended			Year Ended
	December 31,			December 31,
	2008			2007
Beginning asset retirement obligations	$	22,264		$	20,734
Liabilities incurred		565			220
Liabilities settled		(399	)		(219	)
Accretion expense		1,412			1,290
Revisions in estimated cash flows		43			239
Ending asset retirement obligations	$	23,885		$	22,264

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Results of Operations

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,
	2008					2007					2006
Revenues
Oil and gas sales	$	145,398		91.8	%	$	114,427		91.4	%	$	147,122		92.7	%
Gas gathering and marketing		12,254		7.7			10,275		8.2			11,294		7.1
Other		774		0.5			438		0.4			358		0.2
		158,426		100.0			125,140		100.0			158,774		100.0
Expenses
Production expense		26,342		16.6			24,585		19.7			23,692		14.9
Production taxes		3,054		1.9			2,265		1.8			2,404		1.5
Gas gathering and marketing		10,252		6.5			8,640		6.9			9,360		5.9
Exploration expense		2,543		1.6			1,935		1.5			1,797		1.1
General and administrative expense		8,188		5.2			8,236		6.6			9,796		6.2
Depreciation, depletion and amortization		35,560		22.4			36,087		28.8			38,074		24.0
Impairment of goodwill		90,076		56.9
Inpairment of oil and gas properties		3,924		2.5			31		—			546		0.3
Accretion expense		1,412		0.9			1,290		1.0			1,226		0.8
Derivative fair value (gain) loss		(55,940	)	(35.3	)		78,120		62.5			(37,356	)	(23.5	)
		125,411		79.2			161,189		128.8			49,539		31.2
Operating income (loss)		33,015		20.8			(36,049	)	(28.8	)		109,235		68.8
Other (income) expense
(Gain) on early extinguishment of debt		—		—			—		—			(436	)	(0.3	)
Interest expense		22,818		14.4			23,712		18.9			23,553		14.8
Other income, net		(495	)	(0.3	)		(516	)	(0.4	)		(316	)	(0.2	)
Income (loss) before income taxes		10,692		6.7			(59,245	)	(47.3	)		86,434		54.5
Provision (benefit) for income taxes		39,636		25.0			(23,923	)	(19.1	)		34,235		21.6
Net (loss) income		(28,944	)	(18.3	)		(35,322	)	(28.2	)		52,199		32.9

27

The following Management’s Discussion and Analysis is based on the results of operations from continuing operations, unless otherwise noted.

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,
	2008		2007		2006
Production
Gas (MMcf)		13,217		13,357		14,104
Oil (Mbbl)		334		348		373
Total production (MMcfe)		15,221		15,446		16,340
Average price (1)
Gas (per Mcf)	$	8.62	$	6.81	$	8.77
Oil (per Bbl)		94.40		67.42		62.78
Per Mcfe		9.55		7.41		9.00
Average costs (per Mcfe)
Production expense	$	1.73	$	1.59	$	1.45
Production taxes		0.20		0.15		0.15
Depletion		2.31		2.31		2.30

(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,
	2008		2007		2006
Gas (per Mcf)	$	9.31	$	7.34	$	7.22
Oil (per Bbl)		94.40		67.42		62.78
Per Mcfe		10.15		7.87		7.67

2008 Compared to 2007

Revenues

Net operating revenues increased $33.3 million from $125.1 million in 2007 to $158.4 million in 2008. The increase was primarily due to higher gas sales revenues of $22.9 million, higher oil sales revenue of $8.1 million and higher gas gathering and marketing revenues of $2.0 million.

Gas volumes sold decreased 140 MMcf (1%) from 13.4 Bcf in 2007 to 13.2 Bcf in 2008 resulting in a decrease in gas sales revenues of approximately $950,000. Oil volumes sold decreased approximately 14,000 Bbls (4%) from 348,000 Bbls in 2007 to 334,000 Bbls in 2008 resulting in a decrease in oil sales revenues of approximately $960,000. The lower oil and gas sales volumes are due to normal production declines, which were partially offset by production from new wells drilled in 2008.

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The average price realized for our natural gas increased $1.81 per Mcf to $8.62 per Mcf in 2008 compared to 2007, which increased gas sales revenues by approximately $23.9 million. As a result of our qualified effective hedging activities, gas sales revenues were lower by $9.2 million ($0.69 per Mcf) in 2008 and lower by $7.1 million ($0.53 per Mcf) in 2007 than if our gas was not hedged. The average price realized for our oil increased from $67.42 per Bbl in 2007 to $94.40 per Bbl in 2008, which increased oil sales revenues by approximately $9.0 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 increase in gas gathering and marketing revenues was due to a $1.5 million increase in gas marketing revenues and a $510,000 increase in gas gathering revenues. The higher marketing revenues were primarily the result of higher gas prices. The increase in gas gathering revenues was primarily due to an increase in third party gathering volumes on gathering systems in Pennsylvania.

Costs and Expenses

Production expense increased $1.7 million from $24.6 million in 2007 to $26.3 million in 2008. This increase was primarily due to higher fuel costs, increases in labor and oilfield service costs, increases in gas processing fees and increased workover expense. The average production cost increased from $1.59 per Mcfe in 2007 to $1.73 per Mcfe in 2008 due to these cost increases and the lower oil and gas sales volumes in 2008.

Production taxes increased $789,000 from $2.3 million in 2007 to $3.1 million in 2008, primarily due to higher gas prices in Michigan, where production taxes are based on a percentage of revenues, excluding the effects of hedging. Average per unit production taxes increased from $0.15 per Mcfe in 2007 to $0.20 per Mcfe in 2008.

Gathering and marketing expense increased $1.7 million from $8.6 million in 2007 to $10.3 million in 2008 primarily due to higher gas marketing costs as a result of higher gas prices in 2008.

Exploration expense increased $608,000 from $1.9 million in 2007 to $2.5 million in 2008. The increase was primarily due to an increase in expired lease expense and exploratory dry hole expense of $744,000.

General and administrative expense was $8.2 million in 2007 and 2008 and decreased $48,000 primarily due to a decrease in franchise tax and insurance expense which was partially offset by an increase in professional services expense.

Depreciation, depletion and amortization decreased by $527,000 from $36.1 million in 2007 to $35.6 million in 2008. This decrease was primarily due to a decrease in depletion expense. Depletion expense decreased $495,000 from $35.7 million in 2007 to $35.2 million in 2008 due to lower volumes produced. Depletion per Mcfe was $2.31 per Mcfe in 2007 and 2008.

Impairment of goodwill was $90.1 million in 2008 due to the significant drop in oil and gas prices resulting in part from the global economic and market crisis.

Impairment of oil and gas properties was $3.9 million in 2008 due to the write-down of our investment in properties in the Utica Shale formation in Ohio and other unproved properties.

Derivative fair value gain/loss was a gain of $55.9 million in 2008 compared to a loss of $78.1 million in 2007. 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 decreased $894,000 from $23.7 million in 2007 to $22.8 million in 2008. This decrease was due to lower blended interest rates in 2008.

Income tax expense increased from a benefit of $23.9 million in 2007 to an expense of $39.6 million in 2008. The increase in income tax expense was primarily due to an increase in the net income before income taxes in 2008 and an increase in the effective tax rate due to the impairment of goodwill which is not an allowable expense in the calculation of taxable income.

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2007 Compared to 2006

Revenues

Net operating revenues decreased $33.7 million from $158.8 million in 2006 to $125.1 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 reduced 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 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 $893,000 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 $9.8 million in 2006 to $8.2 million in 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.

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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.

Liquidity and Capital Resources

Cash Flows

We expect that our primary sources of cash in 2009 will be from funds generated from operations, additional equity contributions from Capital C and 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 Amended Credit Agreement, will be adequate to meet our short-term liquidity needs for the foreseeable future.

The primary sources of cash in the year ended December 31, 2008 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,
	2008			2007			Change
	(in millions)
Cash flows provided by operating activities	$	96.7		$	68.1		$	28.6
Cash flows (used in) investing activities		(27.5	)		(23.1	)		(4.4	)
Cash flows (used in) financing activities		(62.4	)		(34.9	)		(27.5	)
Net increase (decrease) in cash and cash equivalents	$	6.8		$	10.1		$	(3.3	)

Our operating activities provided cash flows of $96.7 million during 2008 compared to $68.1 million in 2007. The increase was primarily due to a $33.0 million increase in oil and gas sales, excluding the effects of hedging which was partially offset by a $3.3 million decrease in operating assets.

Cash flows used in investing activities were $27.5 million in 2008 compared to $23.1 in 2007. This increase was due to an increase of $5.9 million in property and equipment additions which was partially offset by an increase in proceeds from property and equipment sales of $2.8 million.

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Cash flows used in financing activities in 2008 were $62.4 million compared to $34.9 million in 2007. This increase was primarily due to the $30.2 million increase in the settlement of derivative liabilities and a $4.5 million decrease in proceeds from the revolving line of credit which was partially offset by a decrease in payments to shareholders of $7.3 million.

During 2008, our working capital decreased $2.6 million from a deficit of $14.2 million at December 31, 2007 to a deficit of $16.8 million at December 31, 2008. The decrease was primarily due to an increase in the current portion of long-term liabilities of $24.9 million and a decrease in the deferred tax asset of $9.3 million, which was partially offset by a decrease in the current liability for the fair value of derivatives of $23.2 million and an increase in cash of $6.8 million.

Capital Expenditures

The table below sets forth our total capital expenditures for each of the years ending December 31, 2008, 2007 and 2006.

	Year Ended December 31,
	2008		2007		2006
	(in millions)
Total capital expenditures
Drilling including exploratory dry hole expense	$	25	$	21	$	35
Production enhancements and field improvements		2		1		1
Leasehold acreage		1		1		1
Total	$	28	$	23	$	37

During 2008, we spent approximately $28.3 million, including exploratory dry hole expense, on our drilling and other capital expenditures. In 2008, we drilled 98 gross (83.5 net) development wells, all of which were successfully completed as producers in the target formation. We also drilled 5 gross (4.9 net) exploratory dry holes in 2008.

We plan to spend approximately $15 million during 2009 on our drilling activities and other capital expenditures. We intend to finance our planned capital expenditures through our cash on hand, available cash flow and, to a lesser extent, the sale of non-strategic assets. 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, effects of the current economic and financial crisis, 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, 2008. 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	%

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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

In 2005, we amended and restated our then existing credit agreement, by entering into a First Amended and Restated Credit and Guaranty 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. 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. At December 31, 2008, the borrowing base was $113.4 million and the outstanding balance was $99.9 million. J.P. Morgan Chase and Amegy Bank became members of the bank group in September 2005. 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.

Effective April 9, 2009, the Company entered into the Fourth Amendment, Waiver and Agreement related to the Amended Credit Agreement. The agreement was entered into to provide for certain waivers and modifications to the debt terms and covenants. This amendment was a direct result of the determination as of December 31, 2008, that the Company, would not maintain compliance with certain financial covenants during 2009 and 2010. Accordingly, on April 9, 2009, our bank group waived the leverage ratio for the quarters ended March 31, 2009 and June 30, 2009 and amended the Amended Credit Agreement to increase the maximum leverage ratio to 5.375 : 1.0 through December 31, 2009, 5.25 : 1.0 at March 31, 2010 and 5.0 : 1.0 at June 30, 2010. The bank group also waived the interest coverage ratio as of June 30, 2009 and amended the Amended Credit Agreement to reduce our minimum interest coverage ratio to 2.0 : 1.0 through March 31, 2010 and 2.25 : 1.0 at June 30, 2010. Additionally, Capital C, our parent, has committed to the Company to provide financial support. Taking into consideration the amended financial covenants and the financial support from Capital C, the Company, as of April 9, 2009, has projected that it would maintain compliance with such amended covenants through 2009 and 2010.

Additionally, the amendment provided that the borrowings under the Amended Credit Agreement bear interest (i) at the greater of the prime rate, an adjusted federal funds rate or an adjusted Eurodollar rate, plus an applicable margin ranging from 1.0% to 1.75% 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 2.5% to 3.25% based on the aggregate principal amount outstanding under the Amended Credit Agreement. The agreement was also amended for the following:

• Set the Borrowing Base at $100 million.

• Set the Borrowing Base redetermination dates to March 15^th and September 15^th each year.

• Prohibit payment of dividends to our shareholder.

• Prohibit Senior Secured Note repurchases by the Company.

• Prohibit principal or cash interest payments on the Capital C Subordinated Note.

• Prohibit borrowings to fund restructuring of the hedge agreements.

• Require the pay down of the Amended Credit Agreement with certain proceeds of asset sales and equity contributions, of which $20 million is required to be paid by July 15, 2009.

• Reduce the Borrowing Base by the amount of each repayment until the aggregate amount of such repayments is equal to $30 million.

• Increase the percentage of the value of total proved reserves that is required to be mortgaged from 75% to 80% effective May 31, 2009.

At December 31, 2008, we were in compliance with our covenants under the Amended Credit Agreement. Our leverage ratio was 4.25 : 1.0 and the interest coverage ratio was 2.72 : 1.0.

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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 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 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 2006, the first quarter of 2007 and the first three quarters of 2008 were paid in cash. Interest payments for the last three quarters of 2007 and the fourth quarter of 2008 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. Pursuant to the Fourth Amendment to our credit agreement, cash payments for principal or interest on the Subordinated Note are prohibited. The Subordinated Note is 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

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, 2006, 2007 and 2008, 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, 2008, the aggregate long-term debt maturing in the next five years is as follows: $25.0 million (2009); $74.9 million (2010); $10,000 (2011); $187.1 million (2012) and $32,000 (2013 and thereafter).

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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. None of our contracts currently qualify for hedge accounting.

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 69% of the expected 2009 through 2013 production from our current estimated proved reserves and will range from 62% to 77% 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. 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 Amended Credit Agreement and by a second-priority lien on the same assets securing the Amended Credit Agreement and the Senior Secured Notes.

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 February 28, 2009.

	Natural Gas Swaps				Crude Oil Swaps				Natural Gas Basis Swaps
			NYMEX				NYMEX
			Price per				Price per				Basis
Year Ending	Bbtu		Mmbtu		Mbbls		Bbl		Bbtu		Differential
December 31, 2009		9,529	$	4.43		191	$	29.34		7,390	$	0.337
December 31, 2010		8,938		4.28		175		28.86		7,666		0.243
December 31, 2011		8,231		4.19		157		28.77		5,110		0.252
December 31, 2012		7,005		4.09		138		28.70		3,660		0.110
December 31, 2013		6,528		4.04		127		28.70		—		—

At December 31, 2008, the fair value of futures contracts covering 2009 through 2013 oil and gas production represented an unrealized loss of $117.2 million. Commodity prices have decreased since December 31, 2008 and, as a result, the fair value of our oil and gas derivatives as of February 28, 2009 was an unrealized loss of approximately $83.7 million.

At December 31, 2008, we had a non-qualified interest rate swap in place on $80 million of our outstanding debt under the revolving credit facility through September 30, 2010. The swap provides 1-month LIBOR fixed rates at 4.07%, plus the applicable margin, on $80 million through September 2010. At December 31, 2008, the fair value of the interest rate swap represented an unrealized loss of $3.5 million.

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Inflation and Changes in Prices

The average price realized for our natural gas decreased from $8.77 per Mcf in 2006 to $6.81 per Mcf in 2007, and increased to $8.62 in 2008. The average price realized for our oil increased from $62.78 per Bbl in 2006 to $67.42 per Bbl in 2007 and increased to $94.40 per Bbl in 2008. These 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.

The following table summarizes our contractual obligations at December 31, 2008.

	Payments Due by Period
Contractual Obligations at			Less than 1						After 5
December 31, 2008	Total		Year		1 - 3 Years		4 - 5 Years		Years
	(in thousands)
Long-term debt	$	287,044	$	25,008	$	74,895	$	187,109	$	32
Asset retirement obligations		23,885		229		386		17		23,253
Derivative liabilities		120,792		20,512		55,868		44,412		—
Interest on debt		64,565		19,874		35,406		9,285		—
Operating leases		6,749		4,523		2,226		—		—
Total contractual cash obligations	$	503,035	$	70,146	$	168,781	$	240,823	$	23,285

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, 2008.

	Total		Amount of Commitment Expiration Per Period
Commercial Commitments at	Amounts		Less than 1		1 - 3		4 - 5		Over 5
December 31, 2008	Committed		Year		Years		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.

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Off-Balance Sheet Arrangements

We have $40.9 million in letters of credit as described above.

NEW ACCOUNTING STANDARDS

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 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. We adopted SFAS No. 157 on January 1, 2009 for our nonfinancial assets and nonfinancial liabilities, and the adoption did not have a material impact 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 was effective for fiscal years beginning after November 15, 2007. We have elected not 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 and must be applied prospectively to business combinations completed on or after that date. We adopted SFAS No. 141(R) on January 1, 2009, and there was no impact 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 adopted SFAS No. 160 on January 1, 2009, and there was no impact on our consolidated financial statements.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133. SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities and how they affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 is effective for fiscal years and interim periods beginning after November 15, 2008. We adopted the disclosure requirements of SFAS No. 161 on January 1, 2009.

In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles. SFAS No. 162 identifies the sources for accounting principles and the framework for selecting the principles to be used in preparing financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States. SFAS No. 162 was effective on November 15, 2008.

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In December 2008, the SEC published Modernization of Oil and Gas Reporting, a revision to its oil and natural gas reporting disclosures. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (i) report the independence and qualifications of its reserves preparer or auditor; (ii) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (iii) report oil and natural gas reserves using an average price based upon the prior 12 month period rather than year end prices. The new disclosure requirements are effective for registration statements filed on or after January 1, 2010, and for annual reports on Forms 10-K and 20-F for fiscal years ending on or after December 31, 2009. We will adopt the new disclosure requirements on December 31, 2009.

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, 2008, we had an interest rate swap in place on $80 million of our outstanding debt under the revolving credit facility through September 30, 2010. The swap provides a 1-month LIBOR fixed rates at 4.07%, plus the applicable margin, on $80 million through September 2010. These interest rate swaps do not qualify for hedge accounting, therefore, all cash settles and changes in the fair value of these swaps are recorded in derivative fair value gain/loss. If market interest rates for short-term borrowings increased 1%, the increase in our annual interest expense would be approximately $999,000. The impact of this rate increases on our cash flows would be significantly less than these amounts due to our interest rate swaps. If market interest rates increased 1% the decrease in our cash flow would be approximately $199,000. This sensitivity analysis is based on our financial structure at December 31, 2008.

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, 2008, we had derivatives covering a portion of our oil and gas production from 2009 through 2013. Our oil and gas sales revenues included a net pre-tax loss of $7.1 million in 2007 and a net pre-tax loss of $9.2 million in 2008 on our qualified hedging activities.

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 $13.2 million. If the price of crude oil decreased $10.00 per Bbl, our oil sales revenues would decrease by approximately $3.3 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 $4.4 million after considering the effects of the derivative contracts in place as of December 31, 2008. This sensitivity analysis is based on our 2008 oil and gas sales volumes.

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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, 2008 or 2007.

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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, 2008.

Pursuant to the requirements of rules 13a-15(f) and 15d-15(f) of the Securities and Exchange Act of 1934, the Report on Internal Control over Financial Reporting has been signed below by the following person on behalf and in the capacities indicated below.

/s/ Mark A. Houser	/s/ James M. Vanderhider
Mark A. Houser	James M. Vanderhider
Chief Executive Officer, Chairman of the Board of Directors and Director	President, Chief Financial Officer and Director

Houston, TX
April 9, 2009

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, 2008 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 regarding the preparation and fair presentation of published financial statements.

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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, 2008 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, 2008.

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, 2008 that materially affected, or that are reasonably likely to materially affect, internal control over financial reporting.

This annual report does not include an attestation report of the company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the company’s registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this annual report.

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, 2009 were as follows:

Name	Age		Position
Mark A. Houser		47	Chief Executive Officer and Chairman of the Board of Directors
James M. Vanderhider		50	President, Chief Financial Officer and Director
Kenneth Mariani		47	Senior Vice President, Chief Operating Officer and Director
Frederick J. Stair		49	Vice President of Accounting
Barry K. Lay		52	Vice President of Operations
Sandra K. Fraley		43	Vice President of Land and Legal and Secretary
David M. Elkin		43	Vice President of Engineering
Mark L. Barnhill		53	Vice President of Exploration
Matthew Coeny		38	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 Board of Trustees of Goodwill Industries of Houston and on the Board of Directors of the Houston Center Club, a social and athletic club.

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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 27 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.

Ms. Fraley resigned from the Company in all capacities on March 31, 2009.

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.

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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 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 Citi 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 Operating 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: James M. Vanderhider, President
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 2008.

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, 2008, 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, 2009 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, 2009, we do not have any outstanding stock options or plans to grant any options.

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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 $6.6 million for overhead fees, $7.1 million for field labor, vehicles and district office expense, $265,000 for drilling overhead fees and $1.0 million for drilling labor costs in 2008.

As of December 31, 2008, we owed EnerVest Operating $1.1 million and EnerVest owed us $12,000.

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, 2008 was $27.6 million. We made cash payments of $2.0 million and borrowed an additional $677,000 for interest payments against the note in 2008.

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 LLP served as our independent Registered Public Accounting Firm for the years ended December 31, 2008 and 2007. Aggregate fees for professional services provided to us by Deloitte & Touche LLP for the years ended December 31, 2008 and 2007 were as follows:

	December 31,
	2008		2007
Audit fees	$	470,000	$	408,500
Audit-related fees		—		—
Tax fees		—		—
All other fees		—		—
	$	470,000	$	408,500

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.

49

No.			Description
	10.9	*	Fourth Amendment, Waiver and Agreement to the First Amended and Restated Credit and Guaranty Agreement dated as of August 16, 2005.
	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.
	23.1	*	Consent of Independent Petroleum Engineering Consultants.
	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

50

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
April 9, 2009	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	Chief Executive Officer	April 9, 2009
Mark A. Houser	Chairman of the Board of Directors and Director (Principal Executive Officer)	Date
/s/ James M. Vanderhider	President, Chief Financial	April 9, 2009
James M. Vanderhider	Officer and Director (Principal Financial Officer)	Date
/s/ Frederick J. Stair	Vice President of Accounting	April 9, 2009
Frederick J. Stair	(Principal Accounting Officer)	Date
/s/ Kenneth Mariani	Senior Vice President, Chief	April 9, 2009
Kenneth Mariani	Operating Officer and Director	Date
/s/ Matthew Coeny	Director	April 9, 2009
Matthew Coeny		Date

51

BELDEN & BLAKE CORPORATION
INDEX TO CONSOLIDATED
FINANCIAL STATEMENTS AND SCHEDULES

Item 15(a) (1) and (2)

	Page
CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets as of December 31, 2008 and 2007		F-3
Consolidated Statements of Operations: Years ended December 31, 2008, 2007 and 2006		F-4
Consolidated Statements of Shareholders’ Equity (Deficit): Years ended December 31, 2008, 2007 and 2006		F-5
Consolidated Statements of Cash Flows: Years Ended December 31, 2008, 2007 and 2006		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.

F-1

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, 2008 and 2007, and the related consolidated statements of operations, shareholders’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these 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 Belden & Blake Corporation and subsidiaries as of December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 7 to the consolidated financial statements, effective April 9, 2009, the Company entered into the Fourth Amendment, Waiver and Agreement related to the Amended Credit Agreement.

/s/ DELOITTE & TOUCHE LLP

Houston, TX
April 9, 2009

F-2

BELDEN & BLAKE CORPORATION

CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)

	December 31,
	2008			2007
ASSETS
Current assets
Cash and cash equivalents	$	22,816		$	16,014
Accounts receivable (less accumulated provision for doubtful accounts: December 31, 2008 — $312; December 31, 2007 — $806)		19,244			18,071
Inventories		1,004			1,084
Deferred income taxes		7,946			17,282
Other current assets		332			370
Fair value of derivatives		430			37
Total current assets		51,772			52,858
Property and equipment, at cost
Oil and gas properties (successful efforts method)		735,398			713,912
Gas gathering systems		1,413			1,308
Land, buildings, machinery and equipment		2,836			2,761
		739,647			717,981
Less accumulated depreciation, depletion and amortization		124,175			88,549
Property and equipment, net		615,472			629,432
Goodwill		—			90,076
Fair value of derivatives		868			29
Other assets		1,352			1,830
	$	669,464		$	774,225
LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Accounts payable	$	3,570		$	2,656
Accrued expenses		19,251			20,363
Current portion of long-term liabilities		25,237			367
Fair value of derivatives		20,520			43,696
Total current liabilities		68,578			67,082
Long-term liabilities
Bank and other long-term debt		74,938			99,947
Senior secured notes		163,302			164,240
Subordinated promissory note — related party		27,623			26,931
Asset retirement obligations and other long-term liabilities		23,863			22,164
Fair value of derivatives		101,570			192,661
Deferred income taxes		133,039			98,977
Total long-term liabilities		524,335			604,920
Shareholder’s equity
Common stock: without par value; 3,000 shares authorized; 1,534 shares issued		—			—
Additional paid in capital		122,500			125,000
Retained earnings		(32,754	)		(3,810	)
Accumulated other comprehensive loss		(13,195	)		(18,967	)
Total shareholder’s equity		76,551			102,223
	$	669,464		$	774,225

See accompanying notes.

F-3

BELDEN & BLAKE CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands)

	For the Year Ended December 31,
	2008			2007			2006
Revenues
Oil and gas sales	$	145,398		$	114,427		$	147,122
Gas gathering and marketing		12,254			10,275			11,294
Other		774			438			358
		158,426			125,140			158,774
Expenses
Production expense		26,342			24,585			23,692
Production taxes		3,054			2,265			2,404
Gas gathering and marketing		10,252			8,640			9,360
Exploration expense		2,543			1,935			1,797
General and administrative expense		8,188			8,236			9,796
Depreciation, depletion and amortization		35,560			36,087			38,074
Impairment of goodwill		90,076			—			—
Impairment of oil and gas properties		3,924			31			546
Accretion expense		1,412			1,290			1,226
Derivative fair value (gain) loss		(55,940	)		78,120			(37,356	)
		125,411			161,189			49,539
Operating income (loss)		33,015			(36,049	)		109,235
Other expense (income)
Gain on early extinguishment of debt		—			—			(436	)
Interest expense		22,818			23,712			23,553
Other income, net		(495	)		(516	)		(316	)
Income (loss) before income taxes		10,692			(59,245	)		86,434
Provision (benefit) for income taxes		39,636			(23,923	)		34,235
Net (loss) income	$	(28,944	)	$	(35,322	)	$	52,199

See accompanying notes.

F-4

BELDEN & BLAKE CORPORATION

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (DEFICIT)

(in thousands)

											Accumulated Other
	Common		Common		Paid in			Equity			Comprehensive			Total
	Shares		Stock		Capital			(Deficit)			Income			Equity
January 1, 2006		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 earnings												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 loss									(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 earnings												(779	)		(779	)
Total comprehensive income															(31,730	)
Dividends									(9,750	)					(9,750	)
December 31, 2007		2		—	$	125,000		$	(3,810	)	$	(18,967	)	$	102,223
Comprehensive income (loss):
Net loss									(28,944	)					(28,944	)
Other comprehensive income (loss), net of tax:
Change in derivative fair value												(409	)		(409	)
Reclassification adjustment for derivative (gain) loss reclassified into earnings												6,181			6,181
Total comprehensive income															(23,172	)
Dividends						(2,500	)		—						(2,500	)
December 31, 2008		2		—	$	122,500		$	(32,754	)	$	(13,195	)	$	76,551

See accompanying notes.

F-5

BELDEN & BLAKE CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	For the Year			For the Year			For the Year
	Ended			Ended			Ended
	December 31,			December 31,			December 31,
	2008			2007			2006
Cash flows from operating activities:
Net (loss) income	$	(28,944	)	$	(35,322	)	$	52,199
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization		35,560			36,087			38,074
Impairment of goodwill		90,076			—			—
Impairment of oil and gas properties		3,924			31			546
Accretion expense		1,412			1,290			1,226
(Gain) loss on debt extinguishment and disposal of property and equipment		—			(75	)		(472	)
Amortization of derivatives and other noncash derivative activities		(46,064	)		84,901			(56,057	)
Exploration expense		1,974			610			738
Deferred income taxes		39,636			(23,923	)		33,710
Other non-cash expense		747			2,783			1,483
Change in operating assets and liabilities, net of effects of acquisition and disposition of businesses:
Accounts receivable and other current assets		(1,135	)		1,734			5,210
Inventories		147			(266	)		100
Accounts payable and accrued expenses		(630	)		219			(10,201	)
Net cash provided by operating activities		96,703			68,069			66,556
Cash flows from investing activities:
Proceeds from property and equipment disposals		3,049			267			7,419
Exploration expense		(1,974	)		(610	)		(738	)
Additions to property and equipment		(28,620	)		(22,696	)		(36,839	)
Decrease (increase) in other assets		54			(10	)		(18	)
Net cash used in investing activities		(27,491	)		(23,049	)		(30,176	)
Cash flows from financing activities:
Repayment of senior secured notes		—			—			(33,933	)
Payment to shareholders and optionholders or dividends		(2,500	)		(9,750	)		(20,000	)
Settlement of derivative liabilities recorded in purchase accounting		(59,901	)		(29,659	)		(28,042	)
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		(9	)		(24	)		(26	)
Net cash used in financing activities		(62,410	)		(34,933	)		(38,625	)
Net increase (decrease) in cash and equivalents		6,802			10,087			(2,245	)
Cash and cash equivalents at beginning of period		16,014			5,927			8,172
Cash and cash equivalents at end of period	$	22,816		$	16,014		$	5,927

See accompanying notes.

F-6

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.

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.

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. The fair value of the reporting unit is based on estimates of future net cash flows from proved reserves and from future exploration for and development of unproved reserves. In the fourth quarter of 2008, we recorded a goodwill impairment charge of $90.1 million due to the significant drop in oil and gas prices.

(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.

F-7

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 previously reported amounts in order to conform to current year presentation. Such reclassifications do not effect earnings. Interest income is reported in “Other income, net” in the Statements of Operations. For the years ended December 31, 2007 and 2006 “Other income, net” has been adjusted to include $516,000 and $316,000, respectively, of interest income to conform with current year presentation. These amounts were previously recorded as “Other” revenue in our Statements of Operations. This reclassification had no material impact on total operating revenue, operating income or net income for the years ended December 31, 2007 and 2006.

Use of Estimates in the Financial Statements

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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.

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 $783,000, $31,000 and $332,000 in 2008, 2007 and 2006, respectively, which reduced the book value of unproved oil and gas properties to their estimated fair value.

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

F-8

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. In performing the review for long-lived asset recoverability during 2008, we recorded $3.1 million of impairments which reduced the book value of producing properties to their estimated fair value. 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 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. 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 2008, we performed our annual assessment of impairment of the goodwill and determined that there was no impairment. In the fourth quarter of 2008, we recorded a goodwill impairment charge of $90.1 million due to the significant drop in oil and gas prices.

At December 31, 2008 and 2007, we had $717,000 and $1.1 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 2008, 2007 and 2006. At December 31, 2008, the amortization of deferred debt issuance costs in the next five years is as follows: $424,000 in 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, 2008 or 2007. Oil and gas marketing revenues are recognized when title passes.

F-9

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 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, 2006, 2007 or 2008.

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 designated as cash flow hedges are 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.

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.

F-10

A reconciliation of our liability for plugging and abandonment costs for the years ended December 31, 2008 and 2007 is as follows (in thousands):

	Year Ended			Year Ended
	December 31,			December 31,
	2008			2007
Beginning asset retirement obligations	$	22,264		$	20,734
Liabilities incurred		565			220
Liabilities settled		(399	)		(219	)
Accretion expense		1,412			1,290
Revisions in estimated cash flows		43			239
Ending asset retirement obligations	$	23,885		$	22,264

(3) New Accounting Pronouncements

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 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. We adopted SFAS No. 157 on January 1, 2009 for our nonfinancial assets and nonfinancial liabilities, and the adoption did not have a material impact 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 was effective for fiscal years beginning after November 15, 2007. We have elected not 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 and must be applied prospectively to business combinations completed on or after that date. We adopted SFAS No. 141(R) on January 1, 2009, and there was no impact on our consolidated financial statements.

F-11

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 adopted SFAS No. 160 on January 1, 2009, and there was no impact on our consolidated financial statements.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133. SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities and how they affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 is effective for fiscal years and interim periods beginning after November 15, 2008. We adopted the disclosure requirements of SFAS No. 161 on January 1, 2009.

In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles. SFAS No. 162 identifies the sources for accounting principles and the framework for selecting the principles to be used in preparing financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States. SFAS No. 162 was effective on November 15, 2008.

In December 2008, the SEC published Modernization of Oil and Gas Reporting, a revision to its oil and natural gas reporting disclosures. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (i) report the independence and qualifications of its reserves preparer or auditor; (ii) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (iii) report oil and natural gas reserves using an average price based upon the prior 12 month period rather than year end prices. The new disclosure requirements are effective for registration statements filed on or after January 1, 2010, and for annual reports on Forms 10-K and 20-F for fiscal years ending on or after December 31, 2009. We will adopt the new disclosure requirements on December 31, 2009.

(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.

F-12

In March, 2008, we sold a 50%-70% option interest in certain deep rights on approximately 201,000 net acres in Ohio and Pennsylvania for $3.0 million.

(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, 2008, 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.

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. Our NYMEX crude oil swaps were highly effective and were designated as cash flow hedges through August 16, 2005. 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 fair value of the oil swaps subsequent to 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 2008 and 2007, net losses of $10.2 million ($6.2 million after tax) and $7.6 million ($4.6 million after tax), respectively, were reclassified from accumulated other comprehensive income to earnings. The fair value of open hedges in accumulated other comprehensive income increased $677,000 ($409,000 million after tax) in 2008 and decreased $6.3 million ($3.8 million after tax) in 2007. At December 31, 2008, the estimated net loss in accumulated other comprehensive income that is expected to be reclassified into earnings within the next 12 months is approximately $4.8 million. At December 31, 2008, we have partially hedged our exposure to the variability in future cash flows through December 2013.

F-13

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, 2008:

	Natural Gas Swaps				Crude Oil Swaps				Natural Gas Basis Swaps
			NYMEX				NYMEX
			Price per				Price per				Basis
Year Ending	Bbtu		Mmbtu		Mbbls		Bbl		Bbtu		Differential
December 31, 2009		9,529	$	4.43		191	$	29.34		6,388	$	0.344
December 31, 2010		8,938		4.28		175		28.86		6,388		0.255
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, 2008, 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 4.07% on $80 million through September 2010, plus the applicable margin. These interest rate swaps do not qualify for hedge accounting, therefore, all cash settles and changes in the fair value of these swaps are recorded in derivative fair value gain/loss. At December 31, 2008, the fair value of the interest rate swap represented an unrealized loss of $3.5 million.

F-14

(6) Details of Balance Sheets

	December 31,
	2008			2007
	(in thousands)			(in thousands)
Accounts receivable
Accounts receivable	$	3,884		$	3,509
Allowance for doubtful accounts		(312	)		(806	)
Oil and gas production receivable		15,672			15,368
	$	19,244		$	18,071
Inventories
Oil	$	755		$	671
Natural gas		—			—
Material, pipe and supplies		249			413
	$	1,004		$	1,084
Property and equipment, gross oil and gas properties
Producing properties	$	662,473		$	628,707
Non-producing properties
Proved		58,995			66,793
Unproved		13,930			18,344
Other		—			68
	$	735,398		$	713,912
Land, buildings, machinery and equipment
Land, buildings and improvements	$	838		$	838
Machinery and equipment		1,998			1,923
	$	2,836		$	2,761
Accrued expenses
Accrued interest expense	$	6,418		$	6,499
Accrued other expenses		5,837			6,230
Accrued drilling and completion costs		1,727			1,296
Accrued income taxes		—			2
Ad valorem and other taxes		968			985
Undistributed production revenue		4,301			5,351
	$	19,251		$	20,363

F-15

(7) Long-Term Debt

Long-term debt consists of the following (in thousands):

	December 31,
	2008		2007
Senior secured notes	$	159,475	$	159,475
Bank revolving credit facility		99,876		99,876
Subordinated promissory note (related party)		27,623		26,931
Other		70		79
		287,044		286,361
Less current portion		25,008		8
Long-term debt		262,036		286,353
Fair value adjustment — senior secured notes		3,827		4,765
	$	265,863	$	291,118

Senior Secured Notes due 2012

We have $159.5 million of our Senior Secured Notes outstanding as of December 31, 2008 and 2007. 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 $163.3 million at December 31, 2008. The fair value adjustment of $3.8 million is shown separately in the table above. The accretion of $866,000 and $938,000 was recorded as a reduction of interest expense in 2007 and 2008. 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

In 2005, we amended and restated our then existing 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. The 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.

F-16

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. At December 31, 2008, the borrowing base was $113.4 million. The outstanding balance at December 31, 2008 and 2007 was $99.9 million. 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.

Effective April 9, 2009, the Company entered into the Fourth Amendment, Waiver and Agreement related to the Amended Credit Agreement. The agreement was entered into to provide for certain waivers and modifications to the debt terms and covenants. This amendment was a direct result of the determination as of December 31, 2008, that the Company, would not maintain compliance with certain financial covenants during 2009 and 2010. Accordingly, on April 9, 2009, our bank group waived the leverage ratio for the quarters ended March 31, 2009 and June 30, 2009 and amended the Amended Credit Agreement to increase the maximum leverage ratio to 5.375 : 1.0 through December 31, 2009, 5.25 : 1.0 at March 31, 2010 and 5.0 : 1.0 at June 30, 2010. The bank group also waived the interest coverage ratio as of June 30, 2009 and amended the Amended Credit Agreement to reduce our minimum interest coverage ratio to 2.0 : 1.0 through March 31, 2010 and 2.25 : 1.0 at June 30, 2010. Additionally, Capital C, our parent, has committed to the Company to provide financial support. Taking into consideration the amended financial covenants and the financial support from Capital C, the Company, as of April 9, 2009, has projected that it would maintain compliance with such amended covenants through 2009 and 2010.

Additionally, the amendment provided that the borrowings under the Amended Credit Agreement bear interest (i) at the greater of the prime rate, an adjusted federal funds rate or an adjusted Eurodollar rate, plus an applicable margin ranging from 1.0% to 1.75% 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 2.5% to 3.25% based on the aggregate principal amount outstanding under the Amended Credit Agreement. The agreement was also amended for the following:

• Set the Borrowing Base at $100 million.

• Set the Borrowing Base redetermination dates to March 15^th and September 15^th each year.

• Prohibit payment of dividends to our shareholder.

• Prohibit Senior Secured Note repurchases by the Company.

• Prohibit principal or cash interest payments on the Capital C Subordinated Note.

• Prohibit borrowings to fund restructuring of the hedge agreements.

• Require the pay down of the Amended Credit Agreement with certain proceeds of asset sales and equity contributions, of which $20 million is required to be paid by July 15, 2009.

• Reduce the Borrowing Base by the amount of each repayment until the aggregate amount of such repayments is equal to $30 million.

• Increase the percentage of the value of total proved reserves that is required to be mortgaged from 75% to 80% effective May 31, 2009.

At December 31, 2008, we were in compliance with our covenants under the Amended Credit Agreement. Our leverage ratio was 4.25 : 1.0 and the interest coverage ratio was 2.72 : 1.0.

F-17

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 to 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 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. We made cash payments of $2.0 million and borrowed an additional $677,000 against the Subordinated Note for interest payments in 2008. The Subordinated Note has no prepayment penalty or premium and may be prepaid in whole or in part at any time. Pursuant to the Fourth Amendment to our credit agreement, cash payments for principal or interest on the Subordinated Note are prohibited. The Subordinated Note is 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, 2008, the aggregate long-term debt maturing in the next five years is as follows: $25.0 million (2009); $74.9 million (2010); $10,000 (2011); $187.1 (2012) and $32,000 (2013 and thereafter). Our term loan facility requires mandatory prepayments annually based on the calculation of excess cash flow, as defined in the agreement.

F-18

(8) Leases

We lease natural gas compressors under noncancelable agreements with lease periods of one to five years. Rent expense amounted to $3.8 million in 2008 and $3.1 million in 2007 and 2006.

Future minimum commitments under leasing arrangements as of December 31, 2008 were as follows:

	Operating
As of December 31, 2008	Leases
	(in thousands)
2009	$	4,523
2010		2,226
2011		—
2012		—
2013 and thereafter		—
Total minimum rental payments	$	6,749

(9) Goodwill

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. The fair value of the reporting unit is based on estimates of future net cash flows from proved reserves and from future exploration for and development of unproved reserves. In the fourth quarter of 2008, we recorded a goodwill impairment charge of $90.1 million in the due to the significant drop in oil and gas prices.

(10) Impairment of Oil and Gas Properties

For the period ended December 31, 2008, we reviewed our oil and gas properties for impairment as prescribed by SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. As a result of this evaluation an impairment of $1.9 million was recorded during the fourth quarter of 2008 to proved properties in the Utica Shale formation in Ohio and other unproved properties. We also recorded an impairment of $2.0 million during the second quarter of 2008 to proved properties in the Utica Shale formation in Ohio.

F-19

(11) 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):

	For the year		For the year			For the year
	ended		ended			ended
	December 31,		December 31,			December 31,
	2008		2007			2006
Current
Federal	$	—	$	(525	)	$	525
State		—		—			—
		—		(525	)		525
Deferred
Federal		35,076		(20,499	)		29,771
State		4,560		(2,899	)		3,938
		39,636		(23,398	)		33,709
Total	$	39,636	$	(23,923	)	$	34,234

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:

	For the year			For the year			For the year
	ended			ended			ended
	December 31,			December 31,			December 31,
	2008			2007			2006
Statutory federal income tax rate		35.0	%		35.0	%		35.0	%
Increases (reductions) in taxes resulting from:
State income taxes, net of federal tax benefit		4.6			4.6			4.6
Transaction related expenses
Permanent differences related to goodwill impairment		333.1			—			—
Other, net		(2.0	)		0.8			—
Effective income tax rate for the period		370.7	%		40.4	%		39.6	%

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.

F-20

Significant components of deferred income tax liabilities and assets are as follows (in thousands):

	December 31,			December 31,
	2008			2007
Deferred income tax liabilities:
Property and equipment, net	$	213,795		$	213,509
Other, net		3,885			2,559
Total deferred income tax liabilities		217,680			216,068
Deferred income tax assets:
Accrued expenses		881			882
Asset retirement obligations		8,620			8,062
Fair value of derivatives		56,984			102,286
Net operating loss carryforwards		32,226			29,429
Senior Secured Notes		2,913			2,913
Tax credit carryforwards		1,775			1,775
Other, net		664			502
Valuation allowance		(11,476	)		(11,476	)
Total deferred income tax assets		92,587			134,373
Net deferred income tax liability	$	125,093		$	81,695
Long-term liability	$	133,039		$	98,977
Current asset		(7,946	)		(17,282	)
Net deferred income tax liability	$	125,093		$	81,695

At December 31, 2008, we had approximately $68.5 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 $258 million, which expire between 2009 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.

(12) 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 2006, 2007 or 2008 and as of December 31, 2008, no options were outstanding under the plan.

F-21

(13) 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.

The following table summarizes our contractual obligations at December 31, 2008.

	Payments Due by Period
Contractual Obligations at			Less than 1						After 5
December 31, 2008	Total		Year		1 - 3 Years		4 - 5 Years		Years
	(in thousands)
Long-term debt	$	287,044	$	25,008	$	74,895	$	187,109	$	32
Asset retirement obligations		23,885		229		386		17		23,253
Derivative liabilities		120,792		20,512		55,868		44,412		—
Interest on debt		64,565		19,874		35,406		9,285		—
Operating leases		6,749		4,523		2,226		—		—
Total contractual cash obligations	$	503,035	$	70,146	$	168,781	$	240,823	$	23,285

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, 2008.

		Total	Amount of Commitment Expiration Per Period
Commercial Commitments at	Amounts		Less than 1						Over 5
December 31, 2008	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.

F-22

(14) Supplemental Disclosure of Cash Flow Information

	For the year			For the year			For the year
	ended			ended			ended
	December 31,			December 31,			December 31,
(in thousands)	2008			2007			2006
Cash paid during the period for:
Interest	$	22,764		$	17,939		$	25,317
Income taxes, net of refunds		—			—			—
Non-cash investing and financing activities:
Non-cash additions to property and equipment		(1,728	)		(1,296	)		(1,784	)
Non-cash additions to debt		(692	)		(1,931	)		—

(15) 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 $111.6 million at December 31, 2008 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, 2008, our derivative contracts consisted of natural gas swaps, natural gas basis differential swaps, crude oil swaps and interest rate swaps. At December 31, 2008, the fair value of futures contracts covering 2008 through 2013 oil and gas production represented an unrealized loss of $117.2 million. At December 31, 2008, the fair value of our interest rate futures contracts covering 2009 through September 2010 represented an unrealized loss of $3.5 million.

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(16) Fair Value Measurements

SFAS 157 establishes a valuation hierarchy for disclosure of the inputs to valuation used to measure fair value. This hierarchy prioritizes the inputs into the following three levels:

• Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.

• Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration.

• Level 3 inputs are unobservable inputs based on our own assumptions used to measure assets and liabilities at fair value.

A financial asset or liability’s classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement.

The following table presents the fair value hierarchy table for our assets and liabilities that are required to be measured at fair value on a recurring basis:

				Fair Value Measurements at December 31, 2008
				Quoted Prices in		Significant
				Active Markets		Other			Significant
				for Identical		Observable			Unobservable
				Assets		Inputs			Inputs
	Total Carrying Value			(Level 1)		(Level 2)			(Level 3)
Derivative instruments	$	(120,792	)	$	—	$	(120,792	)	$	—

Our derivative instruments consist of over-the-counter (“OTC”) contracts which are not traded on a public exchange. These derivative instruments are indexed to active trading hubs for the underlying commodity, and are OTC contracts commonly used in the energy industry and offered by a number of financial institutions and large energy companies.

As the fair value of these derivative instruments is based on inputs using market prices obtained from independent brokers or determined using quantitative models that use as their basis readily observable market parameters that are actively quoted and can be validated through external sources, including third-party pricing services, brokers and market transactions, we have categorized these derivative instruments as Level 2.

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(17) 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.

	December 31,		December 31,		December 31,
(in thousands)	2008		2007		2006
Acquisition costs:
Proved properties	$	1,504	$	107	$	16
Unproved properties		802		567		511
Developmental costs		26,845		21,910		36,052
Exploratory costs		2,543		1,935		2,343
		31,694		24,519		38,922

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, 2008, 2007 and 2006 have been prepared by Wright & Company, Inc., independent petroleum consultants.

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The following table sets forth changes in estimated proved and estimated proved developed reserves for the periods indicated:

	Oil			Gas
	(Mbbl)			(Mmcf)			Mmcfe
January 1, 2006		5,210			246,680			277,938
Extensions and discoveries		156			12,892			13,830
Purchase of reserves in place		41			881			1,130
Sale of reserves in place		—			(1,342	)		(1,342	)
Revisions of previous estimates		146			(11,996	)		(11,123	)
Production		(372	)		(14,104	)		(16,337	)
December 31, 2006		5,181			233,011			264,096
Extensions and discoveries		153			4,853			5,771
Purchase of reserves in place		—			5,340			5,340
Revisions of previous estimates		163			(2,647	)		(1,668	)
Production		(348	)		(13,357	)		(15,445	)
December 31, 2007		5,149			227,200			258,094
Extensions and discoveries		78			6,415			6,883
Purchase of reserves in place		22			61			193
Revisions of previous estimates		(1,082	)		(20,625	)		(27,117	)
Production		(334	)		(13,217	)		(15,221	)
December 31, 2008		3,833			199,834			222,832
Proved developed reserves
December 31, 2006		3,832			188,374			211,368
December 31, 2007		3,890			186,765			210,105
December 31, 2008		3,559			176,340			197,694

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 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.

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The standardized measure of discounted future net cash flows relating to estimated proved oil and gas reserves is presented below:

	December 31,
	2008			2007			2006
	(in thousands)
Estimated future cash inflows (outflows)
Revenues from the sale of oil and gas	$	1,431,631		$	2,190,884		$	1,672,532
Production costs		(534,167	)		(590,328	)		(526,928	)
Development costs		(57,491	)		(152,465	)		(134,553	)
Future income taxes		(262,865	)		(497,904	)		(316,413	)
Future net cash flows		577,108			950,187			694,638
10% timing discount		(324,433	)		(561,301	)		(395,157	)
Standardized measure of discounted future net cash flows	$	252,675		$	388,886		$	299,481

At December 31, 2008, 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 natural gas and crude oil swaps and natural gas basis differential swaps in the determination of our oil and gas reserves.

	December 31,
	2008		2007		2006
Gas (per Mcf)	$	6.38	$	7.54	$	5.91
Oil (per Bbl)		41.00		92.77		57.21

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The principal sources of changes in the standardized measure of future net cash flows are as follows:

	Year ended			Year ended			Year ended
	December 31,			December 31,			December 31,
	2008			2007			2006
Beginning of year	$	388,886		$	299,481		$	545,764
Sale of oil and gas, net of production costs		(125,165	)		(96,317	)		(102,710	)
Extensions and discoveries, less related estimated future development and production costs		9,514			14,720			25,806
Previously estimated development costs incurred during the period		26,845			21,910			29,477
Purchase of reserves in place less estimated future production costs		643			2,728			170
Sale of reserves in place less estimated future production costs		—			—			(4,122	)
Changes in estimated future development costs		31,949			(7,337	)		(33,665	)
Revisions of previous quantity estimates		(47,442	)		(237	)		(20,621	)
Net changes in prices and production costs		(195,400	)		196,244			(354,397	)
Change in income taxes		101,046			(75,511	)		148,217
Accretion of 10% timing discount		38,889			29,948			83,145
Changes in production rates (timing) and other		22,910			3,257			(17,583	)
End of period	$	252,675		$	388,886		$	299,481

(18) 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 2008, we had three customers that each accounted for 10% or more of consolidated revenues with sales of $32.3 million, $30.7 million and $22.9 million, respectively. 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.

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(19) Quarterly Results of Operations (Unaudited)

The results of operations for the four quarters of 2008 and 2007 are shown below (in thousands).

	First			Second			Third		Fourth
2008
Operating revenues	$	34,307		$	50,302		$	45,463	$	28,354
Gross profit		15,526			30,884			24,926		8,565
Net (loss) income		(11,634	)		(58,907	)		91,705		(50,108	)
2007
Operating revenues	$	29,422		$	34,801		$	29,420	$	31,059
Gross profit		11,580			15,676			11,555		12,379
Net income		(23,299	)		2,415			7,268		(21,706	)

(20) Related Party Transactions

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 $5.3 million in 2006, $6.0 million in 2007 and $6.6 million in 2008 for overhead fees. We also paid $6.7 million in 2006, $7.5 million in 2007 and $7.1 million in 2008 for field labor, vehicles and district office expense; $875,000 in 2006, $331,000 in 2007 and $265,000 in 2008 for drilling overhead fees and $1.3 million in 2006, $1.2 million in 2007 and $1.0 million in 2008 for drilling labor costs 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, 2008, we owed EnerVest Operating $1.1 million and EnerVest owed us $12,000.

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, 2008 was $27.6 million. We made cash payments of $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. In 2008, we made cash payments of $2.0 million and borrowed and additional $677,000 against the Note for interest payments.

F-29

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.

(21) Subsequent Events

In January 2009, we entered into a sublease agreement covering 58,123 acres in Ohio for $2.5 million.

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EXHIBIT INDEX

10.9*	Fourth Amendment, Waiver and Agreement to the First Amended and Restated Credit and Guaranty Agreement dated as of August 16, 2005.
23.1*	Consent of Independent Petroleum Engineering Consultants.
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