BELDEN & BLAKE CORPORATION FORM 10-K

April 5, 2006

/s/ Mark A. Houser

Mark A. Houser, Chief Executive Officer, Chairman of the Board of

Directors and Director

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, 2005


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 (State or other jurisdiction of incorporation or organization)		34-1686642 (I.R.S. Employer Identification Number)

First City Tower, 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 o No þ

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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large Accelerated filer o Accelerated Filer o Non-accelerated Filer . þ

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, 2006, Belden & Blake Corporation had outstanding 1,534 shares of common stock, without par value, which is its only class of stock. The common stock of Belden & Blake Corporation is not traded on any exchange and, therefore, its aggregate market value and the value of shares held by non-affiliates cannot be determined as of the last business day of the registrant’s most recently completed second fiscal quarter.

DOCUMENTS INCORPORATED BY REFERENCE:

None.

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.

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 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
PART III
	Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
	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
EX-10.25 First Amendment to Credit Agreement
EX-10.26 Operating Agreement Dated 10-1-05
EX-23.1 Consent - E & Y
EX-23.2 Consent - Deloitte & Touche
EX-31.1 Certification 302 - CEO
EX-31.2 Certification 302 - CFO
EX-32.1 Certification 906 - CEO
EX-32.2 Certification 906 - CFO
EX-99.1

Forward-Looking Statements

The information in this document includes forward-looking statements that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Statements preceded by, followed by or that otherwise include the statements “should,” “believe,” “expect,” “anticipate,” “intend,” “will,” “continue,” “estimate,” “plan,” “outlook,” “may,” “future,” “projection,” “likely,” “possible,” “would,” “could” and variations of these statements and similar expressions are forward-looking statements as are any other statements relating to developments, events, occurrences, results, efforts or impacts. These forward-looking statements are based on current expectations and projections about future events. Forward-looking statements, and the business prospects of Belden & Blake are subject to a number of risks and uncertainties which may cause our actual results in future periods to differ materially from the forward-looking statements contained herein. These risks and uncertainties include, but are not limited to, our access to capital, the market demand for and prices of oil and natural gas, our oil and gas production and costs of operation, results of our future drilling activities, the uncertainties of reserve estimates, general economic conditions, new legislation or regulatory changes, changes in accounting principles, policies or guidelines and environmental risks. These and other risks are described on page 11 under the Heading “Risk Factors” and in our other filings with the Securities and Exchange Commission (“SEC”). We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, changes in assumptions, or otherwise.

PART I

Items 1 and 2. BUSINESS AND PROPERTIES

GENERAL

Belden & Blake Corporation, an Ohio corporation, was formed on June 14, 1991 and is wholly owned by Capital C Energy Operations, LP (“Capital C”), a Delaware limited partnership. Capital C acquired us pursuant to a merger completed on July 7, 2004. On August 16, 2005, Capital C was acquired by institutional funds managed by EnerVest Management Partners, 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 First City Tower, 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 Management Partners, Ltd.

On August 16, 2005, the former partners of our direct parent, Capital C, completed the sale of all of the partnership interests in Capital C to certain institutional funds managed by EnerVest, a Houston-based privately held oil and gas operator and institutional funds manager (the “Transaction”). The Transaction resulted in a change in control of our company (“Change in Control”).

On July 7, 2004, we, Capital C, and Capital C Ohio, Inc., an Ohio corporation and a wholly owned subsidiary of Capital C (“Merger Sub”), completed a merger pursuant to which Merger Sub was merged with and into the Company (the “Merger”), with our company surviving the Merger as a wholly owned subsidiary of Capital C. The Merger resulted in a change in control of our company. The general partner of Capital C was controlled by Carlyle/Riverstone Global Energy and Power Fund II, L.P until the Transaction on August 16, 2005.

2005 are presented on our new basis of accounting, while the results of operations for prior periods reflect the historical results of the two predecessor companies. Vertical black lines are presented to separate the financial statements of the two predecessor companies and the successor company. The “Successor Company” refers to the period from August 16, 2005 and forward. The “Predecessor I Company” refers to the period from July 7, 2004 through August 15, 2005. The “Predecessor II Company” refers to the period prior to July 7, 2004.

Credit Agreement

On August 16, 2005, we amended and restated our existing $170 million Credit Agreement, dated as of July 7, 2004 and amended as of July 22, 2004, by and among us, as borrower, the various lenders named therein, Goldman Sachs Credit Partners, L.P., as sole lead arranger, sole book runner, syndication agent and administrative agent, and General Electric Capital Corporation and National City Bank, as co-documentation agents, by entering into a First Amended and Restated Credit and Guaranty Agreement (“Amended Credit Agreement”) by and among us and BNP Paribas, as sole lead arranger, sole book runner, syndication agent and administrative agent. The Amended Credit Agreement provides for loans and other extensions of credit to be made to us up to a maximum aggregate principal amount of $390 million. The obligations under the Amended Credit Agreement are secured by substantially all of our assets.

In connection with our entry into the Amended Credit Agreement, we executed a Subordinated Promissory Note (“Note”) in favor of Capital C in the maximum principal amount of $94 million. Under the Note, Capital C loaned $25 million to us on August 16, 2005. The Note accrues interest at a rate of 10% per annum and matures on August 16, 2012. 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 interest payments in 2005 were paid in cash. The Note has no prepayment penalty or premium and may be prepaid in whole or in part at any time. The Note is subordinate to our senior debt, which includes obligations under the Amended Credit Agreement, the J. Aron Swap and notes issued under an indenture dated July 7, 2004 with BNY Midwest Trust Company (“Indenture”), as indenture trustee (“Senior Secured Notes”).

DESCRIPTION OF BUSINESS

Overview

In the fourth quarter of 2005, we achieved average net production of approximately 46.5 Mmcfe (million cubic feet of natural gas equivalent) per day consisting of 40.4 Mmcf (million cubic feet) of natural gas and 1,022 Bbls (barrels) of oil per day. At December 31, 2005, we owned interests in 4,254 gross (3,307 net) productive oil and gas wells in Ohio, Pennsylvania, New York and Michigan with estimated proved reserves totaling 278 Bcfe (billion cubic feet of natural gas equivalent) consisting of 247 Bcf (billion cubic feet) of natural gas and 5.2 Mmbbl (million barrels) of oil. The estimated future net cash flows from these reserves had a present value (discounted at 10%) after income taxes of approximately $546 million at December 31, 2005. The weighted average prices related to estimated proved reserves at December 31, 2005 were $9.83 per Mcf (thousand cubic feet) for natural gas and $57.64 per Bbl for oil.

At December 31, 2005, we operated approximately 3,712 wells, or 87% of our gross wells representing approximately 96% of the value of our estimated proved developed reserves on a present value (discounted at 10%) basis. We believe that operational control of our properties, coupled with ownership of selected gathering assets, enables us to better control our operating costs and capital expenditures and execute our field development plans. At December 31, 2005, we owned leases on 702,582 gross (597,684 net) acres, including 229,790 gross (183,703 net) undeveloped acres.

We own and operate approximately 1,553 miles of natural gas gathering lines in Ohio, Pennsylvania, New York and Michigan, which are connected directly to various intrastate and interstate natural gas transmission systems. The interconnections with these pipelines afford us marketing access to numerous gas markets, including those in the northeastern United States. The proximity of our properties in the Appalachian and Michigan Basins to large commercial and industrial natural gas markets has generally resulted in premium wellhead gas prices compared with the New York Mercantile Exchange (“NYMEX”) price for gas delivered at the Henry Hub in Louisiana. During 2005, our average per unit gas prices

(excluding the effects of hedging) in Appalachia and Michigan were $0.65 and $0.15, respectively, higher than the average NYMEX monthly settle price for 2005.

Oil and Gas Reserves

The following table sets forth our estimated proved oil and gas reserves as of December 31, 2003, 2004 and 2005 determined in accordance with the rules and regulations of the Securities and Exchange Commission (“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,
	2003		2004		2005
Estimated proved reserves
Gas (Bcf)		318.1		251.3		246.7
Oil (Mbbl)		6,176		5,579		5,210
Bcfe		355.1		284.8		277.9

See Note 18 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, 2005, determined in accordance with the rules and regulations of the SEC, was $546 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, 2005 without escalation, except where changes in prices were fixed and readily determinable under existing contracts.

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


	December 31,
	2003		2004		2005
Gas (per Mcf)	$	6.19	$	6.49	$	9.83
Oil (per barrel)		29.78		40.12		57.64

At December 31, 2005, as specified by the SEC, the prices for oil and natural gas used in this calculation were regional cash price quotes on the last day of the year except for volumes subject to fixed price contracts. Consequently, these may not reflect the prices actually received or expected to be received for oil and natural gas due to seasonal price fluctuations and other varying market conditions. The prices shown above are weighted average prices for the total reserves.

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

Appalachian Basin — Conventional Properties

The Appalachian Basin is the oldest and geographically one of the largest oil and gas producing regions in the United States. Although the Appalachian Basin has sedimentary formations to depths of 15,000 feet or more, oil and natural gas has

primarily been produced from shallow, highly developed formations at depths of 1,000 to 6,500 feet. Our drilling completion rates and those of others drilling in these shallow, highly developed formations have historically exceeded 90%, with production generally lasting longer than 20 years.

We currently own working interests in 2,886 gross (2,537 net) wells in the Appalachian Basin, excluding our coalbed methane wells, which currently produce approximately 24.3 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 2005, we drilled 34 gross (33.0 net) development wells and one gross (1.0 net) exploratory well in the Medina formation in Pennsylvania, 35 gross (35.0 net) development Clarendon wells in Pennsylvania and 20 gross (19.9 net) Clinton wells in Ohio. We plan to continue this development drilling program by drilling 40 gross (38.8 net) Medina wells, 40 gross (40.0 net) Clarendon wells and 20 gross (20.0 net) Clinton wells in 2006.

Michigan Basin Properties

The Michigan Basin has operational similarities to the Appalachian Basin, geographic proximity to our operations in the Appalachian Basin and proximity to natural gas markets, which has generally resulted in premium wellhead prices as compared to NYMEX prices. We own working interests in 1,199 gross (601 net) wells in the Michigan Basin which currently produce approximately 18.1 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 2005, we drilled 22 gross (20.3 net) wells to the Antrim Shale formation. We plan to drill 30 gross (27.6 net) wells in the Antrim Shale formation in 2006.

Appalachian Basin — Coalbed Methane Properties

We own working interests in 169 producing coalbed methane (“CBM”) wells in Pennsylvania and own leases on approximately 69,600 gross (69,400 net) acres of undeveloped CBM properties. We own a 100% working interest in all of our CBM wells. Current production from these wells is approximately 2.9 Mmcf net per day. We drilled 9 CBM wells in 2005 and plan to drill an additional 30 CBM wells in 2006.

Oil and Gas Operations and Production

Operations. We operate 87% of the wells in which we hold working interests. We maintain production field offices in Ohio, Pennsylvania and Michigan. Through these offices, we review our properties to determine what action can be taken to control operating costs and/or improve production.

Production, Sales Prices and Costs. The following table sets forth certain information regarding our net oil and natural gas production, revenues and unit expenses for the years indicated, excluding discontinued operations. The average prices shown in the table include the effects of our qualified effective hedging activities. See Note 6 to the Consolidated Financial Statements.


	Year Ended December 31,
	2003		2004		2005
Production
Gas (Mmcf)		14,834		15,267		14,560
Oil (Mbbl)		413		381		358
Total production (Mmcfe)		17,311		17,553		16,710
Average price
Gas (per Mcf)	$	4.92	$	5.80	$	8.57
Oil (per Bbl)		28.06		35.47		46.37
Mcfe		4.89		5.82		8.46
Average costs (per Mcfe)
Production expense		1.16		1.35		1.42
Production taxes		0.14		0.16		0.22
Depletion		0.85		1.35		2.01
Operating margin (per Mcfe)		3.59		4.31		6.82


Mmcf — Million cubic feet	Mmcfe — Million cubic feet equivalent
Mbbl — Thousand barrels	Mcf — Thousand cubic feet	Bbl — Barrel
Mcfe — Thousand cubic feet equivalent

Operating margin (per Mcfe) — average price less production expense and production taxes

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 2005, we drilled 120 gross (117.2 net) development wells and one gross (1.0 net) exploratory well to shallow, highly developed formations in our operating area. We also drilled two gross (1.5 net) exploratory wells to the Trenton Black River (“TBR”) formation in Ohio. The results of this drilling activity are shown in the table on page 6.

In 2006, we expect to spend approximately $36 million on development drilling and other capital expenditures. We expect to drill approximately 160 gross (156.4 net) wells. In 2006, we plan to spend substantially all of our drilling capital expenditures on shallow, highly developed formations.

We were a pioneer in CBM development and production in Pennsylvania, and we presently own a 100% working interest in 169 CBM gas wells in Indiana, Westmoreland and Fayette counties. CBM wells in this area range in depth from 1,200 to 1,500 feet and typically encounter three to six unmined coal seams. With approximately 69,600 gross (69,400 net) CBM acres currently under lease in Pennsylvania, we believe the CBM may contribute significantly to our drilling portfolio. We plan to drill 30 gross (30.0 net) CBM wells in 2006.

The Antrim Shale formation, the principal shallow formation in the Michigan Basin, is characterized by high formation water production in the early years of a well’s productive life with water production decreasing over time. Antrim Shale wells produce natural gas that typically climbs to peak rates of 60 Mcf to 125 Mcf per day over a three to 12 month period as the producing formation becomes less water saturated. Production generally holds flat for several months, followed by initial annual decline rates of 10% to 25% that decrease over time to 5% or less. Average well lives are 20 years or more. We plan to drill 30 gross (27.6 net) wells to the Antrim Shale formation in 2006.

In addition to our CBM and Antrim drilling, we also plan to drill 40 gross (38.8 net) wells to the Medina formation, 40 gross (40.0 net) wells to the Clarendon formation in Pennsylvania and 20 gross (20.0 net) wells to the Clinton formation in Ohio during 2006.

Certain 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		3,000 - 5,500	$	210 - 265
Pennsylvania:
Coalbed Methane		1,100 - 1,700		170 - 210
Clarendon		1,100 - 2,000		75 - 95
Medina		5,000 - 6,300		240 - 345
Michigan:
Antrim		700 - 2,000		180 - 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 and TBR 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
	2003		2004		2005		2003 ⁽¹⁾		2004		2005 ⁽²⁾
Productive:
Gross		82		100		120		—		—		2
Net		75.7		92.1		117.2		—		—		2.0
Dry:
Gross		—		1		—		5		5		1
Net		—		1.0		—		3.3		3.8		1.0
Wells in progress:
Gross		—		—		—		—		1		1
Net		—		—		—		—		1.0		0.5


⁽¹⁾		Includes one well that was classified as a well in progress in 2002.

⁽²⁾		Includes one well (dry hole) that was classified as a well in progress in 2004.

Disposition of Assets

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

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

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

Employees

As of February 28, 2006, we had 134 full-time employees, including 118 oil and gas exploration and production employees and 11 general and administrative employees and 5 executive officers. Our management and technical staff in the categories above included five petroleum engineers and two geologists.

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.

Customers

Each of the following customers accounted for 10% or more of our consolidated revenues during 2005: WPS Energy Services, National Fuel Gas and Exelon Energy.

Regulation

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

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

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

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

Federal Regulation of Sales and Transportation of Crude Oil. Our sales of crude oil and condensate are not currently regulated and are made at market prices. In a number of instances, however, the ability to transport and sell such

products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. Certain regulations implemented by the FERC in recent years could result in an increase in the cost of pipeline transportation service. We do not believe, however, that these regulations affect us any differently than other producers.

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

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

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

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

We currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the exploration and production of oil and gas. Hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of 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 restrict the emission of air pollutants from many sources, including equipment we use such as compressors to transport natural gas in our pipelines. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur costs in order to remain in compliance.

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

The Oil Pollution Act of 1990, as amended, also known as the “OPA,” pertains to the prevention of and response to spills or discharges of hazardous substances or oil into navigable water of the United States. The OPA imposes strict, joint and several liability on responsible parties for oil removal costs and a variety of public and private damages, including natural resource damages. Regulations under the OPA and the Clean Water Act also require certain owners and operators of facilities that store or otherwise handle oil, such as ours, to prepare and implement spill prevention, control, and countermeasure, or “SPCC,” plans and spill response plans relating to possible discharges of oil into surface waters. Our SPCC plans have been updated to comply with the current regulations. We continue to monitor rapid changes in rules and requirements at both the federal and state level regarding spill prevention. We cannot assure you that costs that may be necessary for compliance with these SPCC and comparable state requirements will not be material.

Producing Well Data

As of December 31, 2005, we owned interests in 4,254 gross (3,307 net) producing oil and gas wells and operated approximately 3,712 wells, including wells operated for third parties. By operating a high percentage of our properties, we are able to control expenses, capital allocation and the timing of development activities in the areas in which we operate. In the fourth quarter of 2005, our net production was approximately 46.5 Mmcfe per day consisting of 40.4 Mmcf of natural gas and 1,022 Bbls of oil per day.

The following table summarizes by state our productive wells at December 31, 2005:


	December 31, 2005
	Gas Wells				Oil Wells				Total
State	Gross		Net		Gross		Net		Gross		Net
Ohio		1,033		876		679		609		1,712		1,485
Pennsylvania		1,223		1,112		92		92		1,315		1,204
New York		28		17		—		—		28		17
Michigan		1,180		597		19		4		1,199		601

		3,464		2,602		790		705		4,254		3,307

Acreage Data

The following table summarizes by state our gross and net developed and undeveloped acreage at December 31, 2005:


	December 31, 2005
	Developed Acreage				Undeveloped Acreage				Total Acreage
State	Gross		Net		Gross		Net		Gross		Net
Ohio		187,551		177,984		21,786		20,303		209,337		198,287
Pennsylvania		209,564		182,100		118,301		94,974		327,865		277,074
New York		14,305		12,568		38,458		20,323		52,763		32,891
Michigan		61,332		41,289		41,573		38,484		102,905		79,773
Indiana		40		40		9,672		9,619		9,712		9,659

		472,792		413,981		229,790		183,703		702,582		597,684

Developed acreage includes 296,065 gross (265,903 net) acres of undrilled acreage held by production.

Item 1A. RISK FACTORS

Our business activities are subject to significant hazards and risks, including those described below. If any of these events should occur, our business, financial condition, liquidity or results of operations could be materially adversely affected. 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 (the “Hedges”) with J. Aron and Company (“J. Aron”) under a master agreement and related confirmations and documentation (collectively, the “Hedge Agreement”). We anticipate the Hedges will cover approximately 68% of the expected 2006 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; or

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

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

If our revenues were to decrease due to lower oil and natural gas prices, decreased production or other reasons, and if we could not obtain capital through our credit facilities or otherwise, our ability to execute our development plans, replace our reserves or maintain our production levels could be greatly limited. Our current development plans will require us to make large capital expenditures for the exploitation and development of our natural gas properties. Historically, we have funded our capital expenditures through a combination of funds generated internally from sales of production or properties, the issuance of equity, long-term debt financing and short-term financing arrangements. We cannot assure you, however, that our business will generate sufficient cash flow from operations or that future borrowings will be available to us under our Amended Credit Agreement and the $40 million letter of credit facility (collectively, the “Senior Facilities”) in an amount sufficient to enable us to pay our indebtedness, including the Senior Secured Notes (“Notes”) or to fund our other liquidity needs. We may need to refinance all or a portion of our indebtedness, including the Notes on or before maturity. We cannot assure you that we will be able to refinance any of our indebtedness, including our new Senior Facilities and the Notes, on commercially reasonable terms or at all. Future cash flows and the availability of financing will be subject to a number of variables, such as:

•

the success of our projects in the Appalachian and Michigan basins;

	•		our success in locating and producing new reserves;

	•		the level of production from existing wells; and

	•		prices of oil and natural gas.

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

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

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

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

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

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

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

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

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

Information concerning our reserves and future net revenues is uncertain.

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

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

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

At December 31, 2005, approximately 19% of our estimated proved reserves were proved undeveloped. Estimation of proved undeveloped reserves and proved developed non-producing reserves is nearly always based on analogy to existing wells rather than the performance data used to estimate producing reserves. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. Production revenues from estimated proved developed non-producing reserves will not be realized until some time in the future. The reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of our reserves and the costs associated with these reserves in accordance with industry standards, these estimated costs may not be accurate, development may not occur as scheduled and actual results may not be as estimated.

Analysts and investors should not construe the present value of future net reserves, or PV-10, as the current market value of the estimated oil and natural gas reserves attributable to our properties. We have based the estimated discounted future net cash flows from estimated proved reserves on prices and costs as of the date of the estimate, in accordance with applicable regulations, whereas actual future prices and costs may be materially higher or lower. Many factors will affect actual future net cash flows, including:

	•		the amount and timing of actual production;

	•		supply and demand for natural gas;

	•		curtailments or increases in consumption by natural gas purchasers; and

	•		changes in governmental regulations or taxation.

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

Our exploitation and development drilling activities may not be successful.

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

	•		unexpected drilling conditions;

	•		pressure or irregularities in formations;

	•		equipment failures or accidents;

	•		ability to hire and train personnel for drilling and completion services;

	•		adverse weather conditions;

	•		compliance with governmental requirements; and

	•		shortages or delays in the availability of drilling rig services and the delivery of equipment.

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

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

Our acquisition activities may not be successful.

As part of our growth strategy, we may make additional acquisitions of businesses and properties. However, suitable acquisition candidates may not be available on terms and conditions we find acceptable, and acquisitions pose substantial risks to our business, financial condition and results of operations. In pursuing acquisitions, we compete with other companies, many of which have greater financial and other resources to acquire attractive companies and properties. Even if future acquisitions are completed, the following are some of the risks associated with acquisitions:

	•		some of the acquired businesses or properties may not produce revenues, earnings or cash flow at anticipated levels;

	•		we may assume liabilities that were not disclosed or that exceed our estimates;

	•		we may be unable to integrate acquired businesses successfully and realize anticipated economic, operational and other benefits in a timely manner, which could result in substantial costs and delays or other operational, technical or financial problems;

	•		acquisitions could disrupt our ongoing business, distract management, divert resources and make it difficult to maintain our current business standards, controls and procedures; and

	•		we may incur additional debt related to future acquisitions.

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

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

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

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

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

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

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

covered by insurance (for example losses resulting from pollution and environmental risks, which are not fully insurable) could have a material adverse effect on our financial condition and results of operations.

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

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

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

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

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

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

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

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

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

Our structure may present conflicts of interest.

Our sole shareholder, Capital C, is owned by institutional funds managed by EnerVest. Messrs. Houser, Vanderhider and Walker 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 L.L.C. (“EnerVest Operating”), a subsidiary 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 Senior Facilities, as well as the Hedges and the indenture relating to the Notes, restrict our current and future operations, particularly our ability to respond to industry or economic changes or to take certain actions.

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

	•		incur additional debt;

	•		pay dividends and make investments, loans or advances;

	•		incur capital expenditures;

	•		create liens;

	•		use the proceeds from sales of assets and capital stock;

	•		enter into sale and leaseback transactions;

	•		enter into transactions with affiliates;

	•		transfer all or substantially all of our assets; and

	•		enter into merger or consolidation transactions.

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

	•		a minimum interest coverage ratio;

	•		a maximum total leverage ratio; and

	•		a minimum current ratio.

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

	•		incur additional indebtedness;

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

	•		make investments;

	•		create liens or other encumbrances; and

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

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

Item 1B. UNRESOLVED STAFF COMMENTS

None.

Item 3. LEGAL PROCEEDINGS

In February 2000, four individuals filed a suit in Chautauqua County, New York on their own behalf and on the behalf of others similarly situated, seeking damages for the alleged difference between the amount of lease royalties actually paid and the amount of royalties that allegedly should have been paid. Other natural gas producers in New York were served with similar complaints. On October 10, 2005, we were granted a summary judgment that dismissed all claims. The plaintiff has filed a notice of appeal and now has nine months to file their brief. We believe the complaint is without merit and are defending the complaint vigorously. Although the outcome is still uncertain, we believe the action will not have a material adverse effect on our financial position, results of operations or cash flows. We no longer own the wells that are subject to the suit.

In April 2002, we were notified of a claim by an overriding royalty interest owner in Michigan alleging the underpayment of royalty resulting from disputes as to the interpretation of the terms of several farmout agreements. On July 6, 2004, a suit was filed in Otsego County, Michigan by affiliates of Merit Energy Company, the successor in interest to these royalty interests, alleging substantially the same underpayments. We made a settlement payment of $615,000 in April 2005 and amended the farmout agreements.

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, 2006, were held by Capital C.

Dividends

We paid cash dividends of $8.5 million in the fourth quarter of 2005. No dividends were paid on our Common Stock prior to the fourth quarter of 2005. We expect to continue to pay dividends on a monthly basis.

Equity Compensation Plan Information:

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. No options were granted during 2005 and as of December 31, 2005, no options were outstanding under the plan. We have no intentions to grant any options under the plan.

Item 6. SELECTED FINANCIAL DATA

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


																			Successor
	Predecessor II Company												Predecessor I Company						Company
										For the 188 Day			For the 178 Day			For the 227 Day			For the 138 Day
										Period from			Period from July			Period From			Period from
										January 1, 2004			7, 2004 to			January 1, 2005			August 16, 2005
	As of or for the Years Ended December 31,									to July 6, 2004			December 31,			to August 15,			to December 31,
(in thousands)	2001			2002⁽²⁾			2003⁽¹⁾⁽²⁾			⁽²⁾			2004			2005			2005
Continuing Operations:
Revenues	$	110,732		$	105,338		$	95,414		$	50,822		$	62,401		$	78,123		$	76,671
Depreciation, depletion and amortization		25,132			21,339			18,098			9,089			17,527			21,265			14,341
Impairment of oil and gas properties		1,398			—			896			—			—			—			—
Income (loss) from continuing operations before cumulative effect of change in accounting principle		7,200			8,935			5,960			(18,869	)		7,263			(320	)		17,563
Balance sheet data:													As of 12/31/2004						As of 12/31/2005

Working capital (deficit) from continuing operations		10,236			(7,914	)		(8,168	)					(4,907	)					(38,999	)
Oil and gas properties and gathering systems, net		220,389			211,776			224,631						502,765						648,417
Total assets		306,089			264,091			285,930						570,853						810,118
Long-term debt, less current portion		284,745			251,959			272,637						281,396						277,648
Total shareholders’ (deficit) equity		(28,572	)		(45,038	)		(58,418	)					57,088						89,399


⁽¹⁾		See Note 2 to the Consolidated Financial Statements. The cumulative effect of change in accounting principle, net of tax, was $2.4 million.

⁽²⁾		See Note 5 to the Consolidated Financial Statements for information on discontinued operations.

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

Overview

We are an Ohio corporation wholly owned by Capital C Energy Operations, LP, a Delaware limited partnership (“Capital C”). Capital C acquired us pursuant to a merger completed on July 7, 2004 (the “Merger”). On August 16, 2005, Capital C was acquired by institutional funds managed by EnerVest Management Partners, 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”).

At December 31, 2005, our total estimated proved reserves were 278 Bcfe. Natural gas comprised approximately 89% of our estimated proved reserves, and 81% of our estimated proved reserves were classified as proved developed. Substantially all of our reserves are located in shallow, highly developed formations with long-lived, stable production profiles. At December 31, 2005 our conventional Appalachian properties accounted for 52% of our estimated proved reserves, while the Michigan properties and our Appalachian coalbed methane properties (“CBM”) accounted for 42% and 6%, respectively.

In connection with the Transaction, our existing indebtedness was refinanced. The principal elements of the refinancing included entering into the $390 million Amended Credit Agreement, providing for a revolving facility with a borrowing base of $80.25 million and a $40 million letter of credit facility (collectively, the “Senior Facilities”), and our issuance of a $25 million Subordinated Promissory Note.

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

Our financial results and cash flows can be significantly impacted as commodity prices fluctuate in response to changing market conditions. We use derivative instruments on a significant portion of our oil and natural gas production to reduce the volatility of oil and natural gas prices and to protect cash flow available for our development drilling program. In connection with the acquisition by Capital C, at the effective time of the Merger, we became a party to a long-term hedging program (the “Hedges”) with J. Aron under a master agreement and related confirmations and documentation (collectively, the “Hedge Agreement”) as required by the Senior Facilities and the indenture governing the Notes, we will maintain such Hedges with J. Aron or its successor permitted assigns. We anticipate that the Hedges will cover approximately 68% of the expected 2006 through 2013 production from our current estimated proved reserves and will range from 64% to 76% of such expected production in any year.

The average price realized for our natural gas, inclusive of qualified effective hedges, increased $2.77 per Mcf to $8.57 per Mcf in 2005 compared to $5.80 per Mcf in 2004. The average price realized for our natural gas increased from $4.92 per Mcf in 2003 to $5.80 per Mcf in 2004. The monthly average settle for natural gas trading on the NYMEX increased from $5.39 per Mmbtu in 2003 to $6.14 per Mmbtu in 2004 and to $8.62 per Mmbtu (million British thermal units) in 2005. 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 (“British thermal unit”) content of our gas. During 2005, our average per unit gas prices (excluding the effects of hedging) in Appalachia and Michigan were $0.65 and $0.15, respectively, higher than the average NYMEX monthly settle price for 2005. The remainder of the difference is due to fixed price contracts and our hedging activities during these periods. Our average realized price for oil, inclusive of qualified effective hedges, increased from $28.06 per Bbl in 2003 to $35.47 per Bbl in 2004 and $46.37 per Bbl in 2005.

CRITICAL ACCOUNTING POLICIES

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

Successful Efforts Method of Accounting

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

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

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

Oil and Gas Reserves

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

	—		the quality and quantity of available data;

	—		the interpretation of that data;

	—		the accuracy of various mandated economic assumptions; and

	—		the judgment of the persons preparing the estimate.

Our estimated proved reserve information for the 2004 Predecessor II Company period ended July 6, 2004 and the 2005 Predecessor I Company period ended August 15, 2005, is based on our internal engineering estimates. Our estimated proved reserve information for all other periods included in this Annual Report is based on estimates prepared by independent petroleum consultants. Estimates prepared by others may be higher or lower than these estimates.

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

See the “Successful Efforts Method of Accounting” discussion above. Capitalized costs related to estimated proved properties are depleted using the unit-of-production method. Depreciation, depletion and amortization of proved oil and gas properties are calculated on the basis of estimated recoverable reserve quantities. These estimates can change based on

economic or other factors. No gains or losses are recognized upon the disposition of oil and gas properties except in extraordinary transactions. Sales proceeds are credited to the carrying value of the properties. Maintenance and repairs are expensed, and expenditures which enhance the value of properties are capitalized.

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

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

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

Derivatives and Hedging

Our financial results and cash flows can be significantly impacted as commodity prices fluctuate widely in response to changing market conditions. Under the provisions of SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, we recognize all derivative financial instruments as either assets or liabilities at fair value. The changes in fair value of derivative instruments not designated as 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 fair value hedges are offset against changes in the fair value of the hedged assets, liabilities, or firm commitments, through net income (loss). Changes in the fair value of derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time as the hedged items impact earnings. 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 are recognized as increases or decreases in oil and gas revenues during the same periods in which the underlying forecasted transactions are recognized in net income (loss). If there is a discontinuance of a cash flow hedge because it is probable that the original forecasted transaction will not occur, deferred gains or losses are recognized in earnings immediately.

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 on an ongoing basis. We assess effectiveness at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. We discontinue hedge accounting prospectively if we determine that a derivative is no longer highly effective as a hedge or if we decide to discontinue the hedging relationship.

From time to time we may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage our exposure to natural gas or crude oil price volatility and support our capital expenditure plans. Our derivative financial instruments take the form of swaps or collars. At December 31, 2005, our derivative contracts were comprised of natural gas swaps, crude oil swaps and an interest rate swap, 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 have ineffectiveness on the natural gas swaps due to purchase accounting, which created non-zero value derivatives at the time of the Merger. We had collar agreements that could not be redesignated as cash flow hedges because these collars were not effective due to unrealized losses at the date of the Merger. These collars qualified and were designated as cash flow hedges from their inception through the Predecessor II Company period ended July 6, 2004. Although these collars were not deemed to be effective hedges in accordance with the provisions of SFAS 133, we retained these instruments as protection against changes in commodity prices and we recorded the mark-to-market adjustments on these natural gas collars, through 2005, in our income statement. Our NYMEX crude oil swaps were highly effective and were designated as cash flow hedges through August 16, 2005. We

had ineffectiveness on the crude oil swaps because the oil is sold locally at a posted price which is different from the NYMEX price. At August 16, 2005, our oil swaps no longer qualified for cash flow hedge accounting because the assessment of effectiveness indicated that they may not be highly effective on an on-going basis. This occurred due to the application of purchase accounting to the derivatives, which created non-zero value derivatives at the time of the Transaction. The changes in the fair values of the natural gas collars since July 7, 2004, the changes in fair value of the oil swaps subsequent to August 15, 2005, the ineffective portion of the crude oil swaps through August 15, 2005 and the ineffective portion of the natural gas swaps since July 7, 2004 are recorded as “Derivative fair value gain or loss.”

Revenue Recognition

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

Asset Retirement Obligations

On January 1, 2003, we adopted SFAS 143, “Accounting for Asset Retirement Obligations.” SFAS 143 amends SFAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” which requires us to recognize a liability for the fair value of our asset retirement obligations associated with its tangible, long-lived assets. The majority of our asset retirement obligations recorded relate to the plugging and abandonment (excluding salvage value) of our oil and gas properties. The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect adjustment to record a $4.0 million increase in long-term asset retirement obligation liabilities, a $621,000 increase in current asset retirement obligation liabilities, a $3.2 million increase in the carrying value of oil and gas assets, a $5.2 million decrease in accumulated depreciation, depletion and amortization and a $1.4 million increase in deferred income tax liabilities. The net effect of adoption was to record a gain of $2.4 million, net of tax, as a cumulative effect of a change in accounting principle in our consolidated statement of operations in the first quarter of 2003.

Subsequent to the adoption of SFAS 143, there has been no significant current period activity with respect to additional retirement obligations, settled obligations, accretion expense and revisions of estimated cash flows. The asset retirement obligations increased as a result of purchase accounting for the Merger in 2004 and the Transaction in 2005, primarily due to a lower discount rate, revised estimates of asset lives on certain oil and gas wells and additional wells having been drilled. The unaudited pro forma income from continuing operations for the year ended December 31, 2002 was $4.3 million and has been prepared to give effect to the adoption of SFAS 143 as if it had been adopted on January 1, 2002. Assuming retroactive application of the change in accounting principle as of January 1, 2002, liabilities would have increased approximately $6 million.

At December 31, 2005, 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, 2005 and 2004 is as follows (in thousands):


	Successor									Predecessor II
	Company			Predecessor I Company						Company
	For The 138 Day						For The 178 Day
	Period From			For the 227 Day			Period From July			For The 188 Day
	August 16, 2005 to			Period From			7, 2004 to			Period From
	December 31,			January 1, 2005 to			December 31,			January 1, 2004 to
	2005			August 15, 2005			2004			July 6, 2004
Beginning asset retirement obligations	$	18,884		$	14,942		$	14,274		$	4,595
Liabilities incurred		173			142			101			9
Liabilities settled		(75	)		(239	)		(85	)		(30	)
Accretion expense		407			745			633			195
Revisions in estimated cash flows		—			—			19			24

Ending asset retirement obligations	$	19,389		$	15,590		$	14,942		$	4,793

New Accounting Pronouncements

In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment.” SFAS 123(R) revises SFAS 123, “Accounting for Stock-Based Compensation,” and focuses on accounting for share-based payments for services by employer to employee. SFAS 123(R) requires companies to expense the fair value of employee stock options and other equity-based compensation at the grant date. SFAS 123(R) does not require a certain type of valuation model and either a binomial or Black-Scholes model may be used. The provisions of SFAS 123(R) are effective for financial statements for fiscal periods ending after June 15, 2005.

SFAS 123(R) must be adopted no later than January 1, 2006 and permits public companies to adopt its requirements using one of two methods:

	•		A “modified prospective” method in which compensation cost is recognized beginning with the effective date based on the requirements of SFAS 123(R) for all share-based payments granted after the adoption date and based on the requirements of SFAS 123 for all awards granted to employees prior to the effective date of SFAS 123(R) that remain unvested on the adoption date.

	•		A “modified retrospective” method which includes the requirements of the modified prospective method described above, but also permits entities to restate either all prior periods presented or prior interim periods of the year of adoption based on the amounts previously recognized under SFAS 123 for purposes of pro forma disclosures.

We adopted the provisions of SFAS 123(R) on January 1, 2006 using the modified prospective method.

As permitted by SFAS 123, we accounted for share-based payments to employees prior to January 1, 2006 using the intrinsic value method prescribed by Accounting Principles Board Opinion No. (APB) 25 and related interpretations. As such, we generally did not recognize compensation expense associated with employee stock option grants. We have not issued stock options to employees since 2004. Consequently, the adoption of SFAS 123(R)’s fair value method will not have a significant impact on our future results of operations or financial position.

In April 2005, the FASB issued FSP FAS 19-1. FSP FAS 19-1 amended SFAS 19, to allow continued capitalization of exploratory well costs beyond one year from the completion of drilling under circumstances where the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. FSP FAS 19-1 also amended SFAS 19 to require enhanced disclosures of suspended exploratory well costs in the notes to the consolidated financial statements. We adopted the new requirements during the second quarter of 2005. See Note 2 for additional information regarding our exploratory well costs. The adoption of FSP FAS 19-1 did not impact our consolidated financial position or results of operations.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143” (“FIN 47”). FIN 47 clarifies that conditional asset retirement obligations meet the definition of liabilities and should be recognized when incurred if their fair values can be reasonably estimated. The interpretation was adopted by us on December 31, 2005. The adoption of FIN 47 had no impact on our financial position or results of operations.

Results of Operations

As a result of the Merger in 2004 and the Transaction in 2005, the results of operations for the periods subsequent to July 6, 2004 and August 15, 2005 are not necessarily comparable to those prior to July 7, 2004 and August 16, 2005. The following table combines the Predecessor II Company 188 day period ended July 6, 2004 with the Predecessor I Company 178 day period ended December 31, 2004 for purposes of the discussion of 2004 results. The table also combines the Predecessor I Company 227 day period ended August 15, 2005 with the Successor Company 138 day period ended December 31, 2005 for purposes of the discussion of 2005 results. The results for the combined periods may not be indicative of the future results of the Successor Company. 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,
	2005				2004					2003
Revenues
Oil and gas sales	$	141,354	91.3	%	$	102,089		90.2	%	$	84,610		88.7	%
Gas gathering and marketing		12,990	8.4			9,980		8.8			10,538		11.0
Other		450	0.3			1,154		1.0			266		0.3

		154,794	100.0			113,223		100.0			95,414		100.0

Expenses
Production expense		23,800	15.3			23,756		21.1			20,017		20.9
Production taxes		3,672	2.4			2,767		2.4			2,449		2.6
Gas gathering and marketing		11,110	7.2			9,101		8.0			9,570		10.0
Exploration expense		3,653	2.4			5,970		5.3			6,849		7.2
General and administrative expense		5,290	3.4			6,323		5.6			4,559		4.8
Franchise, property and other taxes		194	0.1			167		0.1			202		0.2
Depreciation, depletion and amortization		35,606	23.0			26,616		23.5			18,098		19.0
Impairment of oil and gas properties		—	—			—		—			896		0.9
Accretion expense		1,152	0.7			828		0.7			343		0.4
Derivative fair value (gain) loss		13,312	8.6			2,409		2.1			(319	)	(0.3	)
Transaction expense		7,542	4.9			26,001		23.0			—		—

		105,331	68.0			103,938		91.8			62,664		65.7

Operating income		49,463	32.0			9,285		8.2			32,750		34.3
Other expense
Interest expense		23,312	15.1			24,061		21.3			23,580		24.7

Income (loss) from continuing operations before income taxes and cumulative effect of change in accounting principle		26,151	16.9			(14,776	)	(13.1	)		9,170		9.6
Provision (benefit) for income taxes		8,908	5.8			(3,170	)	(2.8	)		3,210		3.4

Income (loss) from continuing operations before cumulative effect of change in accounting principle		17,243	11.1			(11,606	)	(10.3	)		5,960		6.2
Income (loss) from discontinued operations, net of tax		—	—			28,868		25.5			(10,681	)	(11.2	)

Income (loss) before cumulative effect of change in accounting principle		17,243	11.1			17,262		15.2			(4,721	)	(5.0	)
Cumulative effect of change in accounting principle, net of tax		—	—			—		—			2,397		2.5

Net income (loss)	$	17,243	11.1	%	$	17,262		15.2	%	$	(2,324	)	(2.5	)%

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

Production, Sales Prices and Costs

The following table sets forth certain information regarding our net oil and natural gas production, revenues and expenses for the years indicated. This table includes continuing operations only. The average prices shown in the table include the effects of our qualified effective hedging activities.


	Year Ended December 31,
	2005		2004		2003
Production
Gas (Mmcf)		14,560		15,267		14,834
Oil (Mbbl)		358		381		413
Total production (Mmcfe)		16,708		17,553		17,311
Average price
Gas (per Mcf)	$	8.57	$	5.80	$	4.92
Oil (per Bbl)		46.37		35.47		28.06
Mcfe		8.46		5.82		4.89
Average costs (per Mcfe)
Production expense		1.42		1.35		1.16
Production taxes		0.22		0.16		0.14
Depletion		2.01		1.35		0.85
Operating margin (per Mcfe)		6.82		4.31		3.59


Mmcf — Million cubic feet	Mmcfe — Million cubic feet equivalent	Bbl — Barrel
Mbbl — Thousand barrels	Mcf — Thousand cubic feet

Operating margin (per Mcfe) — average price less production expense and production taxes

2005 Compared to 2004

Revenues

Net operating revenues increased from $112.1 million in 2004 to $154.3 million in 2005. The increase was due to higher gas sales revenues of $36.2 million, higher oil sales revenues of $3.1 million and higher gas gathering and marketing revenues of $3.0 million.

Gas volumes sold decreased 707 Mmcf (5%) from 15.3 Bcf in 2004 to 14.6 Bcf in 2005 resulting in a decrease in gas sales revenues of approximately $4.1 million. Oil volumes sold decreased approximately 23,000 Bbls (6%) from 381,000 Bbls in 2004 to 358,000 Bbls in 2005 resulting in a decrease in oil sales revenues of approximately $800,000. The lower gas sales and oil sales volumes are due to normal production declines partially offset by production from new wells drilled in 2005 .

The average price realized for our natural gas increased $2.77 per Mcf to $8.57 per Mcf in 2005 compared to 2004, which increased gas sales revenues by approximately $40.3 million. As a result of our qualified effective hedging activities, gas sales revenues were lower by $6.6 million ($0.46 per Mcf) in 2005 and lower by $9.8 million ($0.64 per Mcf) in 2004 than if our gas was not hedged. The average price realized for our oil increased from $35.47 per Bbl in 2004 to $46.37 per Bbl in 2005, which increased oil sales revenues by approximately $3.9 million. As a result of our qualified effective hedging activities, oil sales revenues were lower by approximately $2.5 million ($7.00 per Bbl) in 2005 and lower by $1.1 million ($2.91 per Bbl) in 2004 than if our oil was not hedged.

The operating margin from oil and gas sales on a per unit basis increased from $4.31 per Mcfe in 2004 to $6.82 per Mcfe in 2005. The average price increased $2.64 per Mcfe which was partially offset by an increase in production expense of $0.07 per Mcfe and an increase in production taxes of $0.06 per Mcfe in 2005 compared to 2004. Production expense increased approximately $0.06 per Mcfe in 2004 and $0.08 per Mcfe in 2005 due to recording the cost of selling purchased oil inventory as a result of purchase accounting for the Merger and the Transaction.

The increase in gas gathering and marketing revenues was due to a $2.1 million increase in gas marketing revenues and a $916,000 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 higher margins on a gathering system in Pennsylvania.

Costs and Expenses

Production expense was $23.8 million in 2004 and 2005. The average production cost increased from $1.35 per Mcfe in 2004 to $1.42 per Mcfe in 2005 due to lower oil and gas sales volumes in 2005. Production expense increased by $975,000 ($0.06 per Mcfe) in 2004 and by $1.3 million ($0.08 per Mcfe) in 2005 due to recording the cost associated with the selling of purchased oil inventory as a result of purchase accounting for the Merger in 2004 and the Transaction in 2005. Oil inventory was recorded at fair value of approximately $31.88 per Bbl as of July 7, 2004 and $60.50 per Bbl as of August 16, 2005. Production expense in 2004 included $1.6 million ($0.09 per Mcfe) of non-cash stock-based compensation expense. Production expense in 2005 was effected by higher fuel costs and general cost increases.

We entered into an operating agreement with EnerVest Operating effective October 1, 2005. Under the terms of the agreement, we will pay EnerVest Operating a Council of Petroleum Accountants Societies (COPAS) overhead fee to cover certain production and administrative costs. Production expense in 2005 included $642,000 in COPAS overhead charges from EnerVest Operating, which offset operating cost reductions following the Transaction. We expect these overhead charges to result in an increase in production expense and a decrease in our general and administrative expense in the future.

Production taxes increased $905,000 from $2.8 million in 2004 to $3.7 million in 2005, primarily due to higher oil and gas prices in Michigan, where production taxes are based on a percentage of revenues, excluding the effects of hedging. Average per unit production taxes increased from $0.16 per Mcfe in 2004 to $0.22 per Mcfe in 2005, primarily due to the increase in the selling price of natural gas in 2005, excluding the effects of hedging.

Exploration expense decreased $2.3 million (39%) from $6.0 million in 2004 to $3.7 million in 2005 primarily due to decreases in exploratory dry hole expense, expired lease expense and compensation-related expenses. We have decreased exploration activity in order to focus our drilling efforts on lower risk developmental drilling. However, we expect to continue to incur exploration expense for costs related to our ongoing operations, which are classified as exploration expense under the successful efforts method of accounting.

General and administrative expense decreased $1.0 million (16%) from 2004 to 2005 primarily due to $1.5 million of non-cash stock-based compensation expense recorded in 2004.

Depreciation, depletion and amortization increased by $9.0 million from $26.6 million in 2004 to $35.6 million in 2005. This increase was primarily due to an increase in depletion expense. Depletion expense increased $9.9 million (42%) from $23.6 million in 2004 to $33.5 million in 2005 due to a higher depletion rate per Mcfe. Depletion per Mcfe increased from $1.35 per Mcfe in 2004 to $2.01 per Mcfe in 2005, primarily due to a higher cost basis resulting from purchase accounting for the Transaction on August 16, 2005.

Derivative fair value gain/loss was a loss of $2.4 million in 2004 compared to a loss of $13.3 million in 2005. The derivative fair value gain/loss reflects the changes in fair value of certain derivative instruments that are not designated or do not qualify as cash flow hedges, the ineffective portion of crude oil swaps through August 15, 2005 and the ineffective portion of natural gas swaps as a result of purchase accounting.

Transaction expenses of $26.0 million related to the Merger and $7.5 million related to the Transaction were recorded in the Predecessor II Company and Predecessor I Company periods, respectively. These expenses include severance and retention payments made to employees, unamortized loan costs written off, temporary financing facility costs, costs of the consent solicitation process for our $225 million Senior Subordinated Notes due 2007 (the “9-7/8% Notes”) and buyer and seller investment banking fees, professional fees and other transaction expenses.

Interest expense decreased $749,000 (3%) from $24.1 million in 2004 to $23.3 million in 2005. This decrease was due to lower blended interest rates which were partially offset by an increase in average outstanding borrowings.

We had income tax expense of $8.9 million in 2005 compared to an income tax benefit of $3.2 million in 2004. The increase in income tax expense was primarily due to an increase in the net income before income taxes in the 2005 period compared to the 2004 period along with a higher effective tax rate in the 2005 period. The effective tax rate was higher in the

2005 period due to certain nondeductible transaction-related expenses in the 2004 period which reduced the 2004 rate.

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

2004 Compared to 2003

Revenues

Net operating revenues increased from $95.1 million in 2003 to $112.1 million in 2004. The increase was due to higher gas sales revenues of $15.5 million and higher oil sales revenues of $1.9 million partially offset by lower gas gathering and marketing revenues of $558,000.

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

The average price realized for our natural gas increased $0.88 per Mcf to $5.80 per Mcf in 2004 compared to 2003, which increased gas sales revenues by approximately $13.4 million. As a result of our qualified effective hedging activities, gas sales revenues were lower by $9.8 million ($.64 per Mcf) in 2004 and lower by $10.3 million ($.69 per Mcf) in 2003 than if our gas was not hedged. The average price realized for our oil increased from $28.06 per Bbl in 2003 to $35.47 per Bbl in 2004, which increased oil sales revenues by approximately $2.8 million. As a result of our qualified effective hedging activities, oil sales revenues were lower by approximately $1.1 million ($2.91 per Bbl) in 2004 than if our oil was not hedged. The operating margin from oil and gas sales on a per unit basis increased from $3.59 per Mcfe in 2003 to $4.31 per Mcfe in 2004. The average price increased $0.93 per Mcfe, which was partially offset by an increase in production expense of $0.19 per Mcfe in 2004 compared to 2003. Approximately $0.06 per Mcfe of the increase in production expense was due to recording the cost of selling purchased oil inventory as a result of purchase accounting for the Merger.

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

Costs and Expenses

Production expense increased $3.8 million (19%) from $20.0 million in 2003 to $23.8 million in 2004 primarily due to an increase in labor resulting from continued well development activities, an increased focus on production and compressor optimization, a general increase in fuel and power costs and $1.6 million of additional non-cash stock-based compensation expense recorded in 2004 to reflect the increased value of our stock. Production expense was also increased in the second half of 2004 due to recording approximately $975,000 in cost associated with the selling of purchased oil inventory as a result of purchase accounting for the Merger. Oil inventory was recorded at fair value of approximately $31.88 per Bbl as of July 1, 2004. The average production cost increased from $1.16 per Mcfe in 2003 to $1.35 per Mcfe in 2004. The per unit increase was primarily due to the higher costs discussed above partially offset by certain fixed costs spread over greater volumes in 2004. Purchase accounting and the non-cash stock-based compensation expense were responsible for $0.06 and $0.09 per Mcfe of the per unit increase, respectively.

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

Exploration expense decreased $879,000 (13%) from $6.8 million in 2003 to $6.0 million in 2004 primarily due to decreases in expired lease expense, seismic expense and exploratory dry hole expense partially offset by additional non-cash

stock-based compensation expense recorded in 2004. We have decreased exploration activity in order to focus our drilling efforts on lower risk developmental drilling. However, we expect to continue to incur exploration expense for costs related to our ongoing operations which are classified as exploration expense under the successful efforts method of accounting. See Note 2 to the Consolidated Financial Statements.

General and administrative expense increased $1.8 million (39%) from 2003 to 2004 primarily due to management fees and reimbursements of $641,000 paid, respectively, to Capital C and Legend Natural Gas, LP (“Legend”) and $1.5 million of additional non-cash stock-based compensation expense recorded in 2004 to reflect the increased value of our stock.

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

Derivative fair value gain/loss was a gain of $319,000 in 2003 compared to a loss of $2.4 million in 2004. The derivative fair value gain/loss reflects the changes in fair value of certain derivative instruments that are not designated or do not qualify as cash flow hedges and $1.1 million related to the ineffective portion of crude oil swaps and natural gas swaps qualifying for hedge accounting which was recorded in 2004.

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

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

Income tax expense decreased $6.4 million from a tax provision of $3.2 million in 2003 to a benefit of $3.2 million in 2004. The decrease was primarily due to a decrease in income from continuing operations before income taxes coupled with a lower effective tax rate in 2004. The effective tax rate was reduced due to certain nondeductible transaction-related expenses in the 2004 period, which reduced the 2004 rate. This was partially offset by an increase in the tax rate from a benefit of $1.5 million recorded in the Predecessor I Company period. This benefit was the result of a change in the effective state tax rate due to the merger of two of our subsidiaries into Belden & Blake Corporation on December 30, 2004.

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

Liquidity and Capital Resources

Cash Flows

We expect that our primary sources of cash in 2006 will be from funds generated from operations, from borrowings under the Senior Facilities and from the sale of non-strategic assets. Based on our current level of operations, we believe our cash flow from operations, available cash and available borrowings under our Senior Facilities, will be adequate to meet our future liquidity needs for the foreseeable future. At February 28, 2006, we had approximately $23.4 million available under our revolving facility.

The primary sources of cash in the year ended December 31, 2005 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, interest expense, Transaction expenses and repayment of debt. Our liquidity and capital resources are closely related to and dependent upon the current prices paid for our oil and natural gas.

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


	Year Ended December 31,
	2005			2004			Change
				(in millions)
Cash provided by operating activities	$	91.3		$	31.2		$	60.1
Cash (used in) provided by investing activities		(32.5	)		36.5			(69.0	)
Cash (used in) financing activities		(69.0	)		(50.7	)		(18.3	)


Net increase or decrease in cash and cash equivalents	$	(10.2	)	$	17.0		$	(27.2	)

Our operating activities provided cash flows of $91.3 million during 2005 compared to $31.2 million in 2004. The increase was primarily due to the $41.6 million increases in sales revenues and a decrease of $18.5 million in Transaction costs in 2005 compared to 2004.

Cash flows used in investing activities were $32.5 million in 2005 compared to cash flows provided by investing activities of $36.5 in 2004. This decrease was due to proceeds from disposition of businesses of $72.5 million in 2004, which was partially offset by a decrease in exploration expense of $3.7 million.

Cash flows used in financing activities in 2005 were $69.0 million compared to $50.7 million in 2004. This increase was primarily due to the sale of common stock for $77.5 million in 2004, an increase in the settlement of derivative liabilities recorded in purchase accounting of $42.8 million and a net decrease in debt-related cash flows of $12.4 million, partially offset by merger-related payments to shareholders and option holders of $113.7 million in 2004.

During 2005, our working capital decreased $34.1 million from a deficit of $4.9 million at December 31, 2004 to a deficit of $39.0 million at December 31, 2005. The decrease was primarily due to an increase in the current liability for fair value of derivatives of $40.3 million, an increase in accrued expenses of $5.1 million and a decrease in cash of $10.2 million. This was offset by an increase in the deferred income tax asset of $14.6 million and an increase in accounts receivable of $6.6 million.

Capital Expenditures

The table below sets forth our total capital expenditures for each of the years ending December 31, 2005, 2004 and 2003.


	Year Ended December 31,
	2005		2004		2003
			(in millions)
Total capital expenditures
Drilling including exploratory dry hole expense	$	26	$	21	$	20
Production enhancements and field improvements		2		3		3
Leasehold acreage		1		1		—
Other capital expenditures		—		—		1

Total	$	29	$	25	$	24

During 2005, we spent approximately $29 million, including exploratory dry hole expense, on our drilling and other capital expenditures. In 2005, we drilled 120 gross (117.2 net) development wells, all of which were successfully completed as producers in the target formation. We also drilled three gross (2.5 net) exploratory wells of which two wells were completed as producers and one well is still being evaluated. One exploratory well drilled in 2004 was classified as a dry hole in 2005 and well cost of approximately $200,000 was expensed.

We plan to spend approximately $36 million during 2006 on our drilling activities and other capital expenditures. We intend to finance our planned capital expenditures through our cash on hand, available cash flow, borrowings under our revolving credit facility and, to a lesser extent, the sale of non-strategic assets. At December 31, 2005, and at February 28, 2006, we had approximately $27.4 million and $23.4 million, respectively, available under our revolving facility. The level of our future cash flow will depend on a number of factors including the demand for and price levels of oil and gas, the scope and success of our drilling activities and our ability to acquire additional producing properties. There can be no assurance that the future drilling of our proved undeveloped locations will provide adequate liquidity in the future.

Financing and Credit Facilities

Senior Secured Notes due 2012

We have $192.5 million of our Notes outstanding as of December 31, 2005. 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. 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 $192.5 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 Senior Facilities. The 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 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

Partners, L.P., as sole lead arranger, sole book runner, syndication agent and administrative agent, and General Electric Capital Corporation and National City Bank, as co-documentation agents, by entering into a First Amended and Restated Credit and Guaranty Agreement (“Amended Credit Agreement”) by and among us and BNP Paribas, as sole lead arranger, sole book runner, syndication agent and administrative agent. The Amended Credit Agreement provides for loans and other extensions of credit to be made to us up to a maximum aggregate principal amount of $390 million. The obligations under the Amended Credit Agreement are secured by substantially all of our assets.

The Amended Credit Agreement provides for a revolving credit line in the aggregate principal amount of $350 million and a hedge letter of credit facility in the aggregate principal amount of $40 million. Borrowings under the Amended Credit Agreement may not exceed the borrowing base, which was initially set at $80.25 million, of which $57 million was drawn at closing on August 16, 2005. At December 31, 2005, the outstanding balance was $52 million. This agreement was amended on September 27, 2005 to reduce the percentage of the value of total proved reserves that is required to be mortgaged from 75% to 70%. J.P. Morgan Chase and Amegy Bank became members of the bank group in September 2005.

Borrowings under the Amended Credit Agreement bear interest (i) at the greater of the prime rate or an adjusted federal funds rate, plus an applicable margin ranging from 0% to 0.625% based on the aggregate principal amount outstanding under the Amended Credit Agreement, or, (ii) at the Company’s option, the Eurodollar base rate plus an applicable margin ranging from 1.125% to 2.125% based on the aggregate principal amount outstanding under the Amended Credit Agreement. The full amount borrowed under the Amended Credit Agreement will mature on August 16, 2010.

The obligations under the Amended Credit Agreement are secured by a first lien security interest in substantially all of our assets. The obligations under the Amended Credit Agreement are further secured by a pledge of 100% of our capital stock held by Capital C, our parent.

The Amended Credit Agreement contains covenants that will limit our ability to, among other things, incur or guarantee additional indebtedness; create liens; pay dividends on or repurchase our stock; pay principal and interest on certain subordinated debt; make certain types of investments; sell assets or merge with another entity; pledge or otherwise encumber our capital stock; or enter into transactions with affiliates. The Amended Credit Agreement also requires compliance with customary financial covenants, including a minimum interest coverage ratio, a maximum leverage ratio and a minimum current ratio. As of December 31, 2005, we were in compliance with all financial covenants and requirements under the existing credit facilities.

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 (“Note”) in favor of Capital C in the maximum principal amount of $94 million. Under the Note, Capital C loaned $25 million to us on August 16, 2005. The 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 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 interest payments in 2005 were paid in cash. The Note has no prepayment penalty or premium and may be prepaid in whole or in part at any time. The Note is expressly subordinate to our senior debt, which includes obligations under the Amended Credit Agreement, the J. Aron Swap and notes issued under our Indenture dated July 7, 2004 with BNY Midwest Trust Company, as indenture trustee (“Senior Secured Notes”).

ISDA Master Agreement

In connection with the Transaction, we amended and restated the Schedule and Credit Support Annex to our International Swap Dealers Association (“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.

Derivative Instruments

The Hedges

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

On July 7, 2004, the date of the Merger, we became a party to long-term commodity hedges (the “Hedges”) with J. Aron pursuant to a master agreement and related confirmations and documentation (collectively, the “Hedge Agreement”.) We anticipate that the Hedges will cover approximately 68% of the expected 2006 through 2013 production from our current estimated proved reserves and will range from 64% to 76% 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 Notes remains outstanding. The Hedges are documented under a standard ISDA agreement with customized credit terms, designed to mitigate the liquidity pressures in a high commodity price environment. The initial collateral requirements and ongoing margin requirements (based on market movements) are satisfied by letters of credit issued under the Senior Facilities, with an aggregate capitalization of $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 Senior Facilities and the Notes and, to the extent our obligations exceed such letters of credit, such obligations are secured by a second-priority lien on the same assets securing the Senior Facilities and the Notes. We may enter into crude oil and natural gas hedges with parties other than J. Aron, which hedges may be secured by the letters of credit issued under the Senior Facilities and by a second-priority lien on the same assets securing the Senior Facilities and the Notes.

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

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

Our financial results and cash flows can be significantly impacted as commodity prices fluctuate widely in response to changing market conditions. Accordingly, we may modify our fixed price contract and financial hedging positions by entering into new transactions. The following tables reflect the natural gas and crude oil volumes and the weighted average prices under financial hedges (including settled hedges) at December 31, 2005. We have not entered into any additional hedging transactions since December 31, 2005.


	Natural Gas Swaps				Crude Oil Swaps
			NYMEX
			Price per		Estimated		NYMEX
Quarter Ending	Bbtu		Mmbtu		Mbbls		Price per Bbl
March 31, 2006		2,829	$	6.14		63	$	32.71
June 30, 2006		2,829		5.24		62		32.35
September 30, 2006		2,829		5.22		62		32.02
December 31, 2006		2,829		5.39		62		31.71

		11,316	$	5.50		249	$	32.20

Year Ending
December 31, 2007		10,745	$	4.97		227	$	30.91
December 31, 2008		10,126		4.64		208		29.96
December 31, 2009		9,529		4.43		191		29.34
December 31, 2010		8,938		4.28		175		28.86
December 31, 2011		8,231		4.19		157		28.77
December 31, 2012		7,005		4.09		138		28.70
December 31, 2013		6,528		4.04		127		28.70


Mcf — Thousand cubic feet	Mmbtu – Million British thermal units	Bbl — Barrel
Mmcf — Million cubic feet	Bbtu – Billion British thermal units	Mbbls – Thousand barrels

At December 31, 2005, the fair value of futures contracts covering 2006 through 2013 oil and gas production represented an unrealized loss of $305.3 million. Commodity prices have decreased since December 31, 2005 and, as a result, the fair value of our hedges as of February 28, 2006 was an unrealized loss of approximately $243.9 million.

At December 31, 2005 we had an interest rate swap in place for $40 million that matures on September 16, 2008. The swap provides a
1-month LIBOR fixed rate of 4.287% plus the applicable margin. At December 31, 2005, the fair value of the interest rate swap represented an unrealized gain of $459,000.

Inflation and Changes in Prices

The average price realized for our natural gas increased from $4.92 per Mcf in 2003 to $5.80 per Mcf in 2004, then increased to $8.57 in 2005. The average price realized for our oil increased from $28.06 per Bbl in 2003 to $35.47 per Bbl in 2004 and increased to $46.37 per Bbl in 2005. These prices reflect average prices for oil and gas sales of our continuing operations. The prices include the effect of our qualified effective oil and gas hedging activity.

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

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

Contractual Obligations

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

The following table summarizes our contractual obligations at December 31, 2005.


	Payments Due by Period
Contractual Obligations at			Less than 1
December 31, 2005	Total		Year		1 - 3 Years		4 - 5 Years		After 5 Years
	(in thousands)
Long-term debt	$	269,592	$	7	$	14	$	52,017	$	217,554
Fixed-rate interest		134,139		19,352		38,702		38,699		37,386
Capital lease obligations		106		77		29		—		—
Operating leases		6,431		3,324		2,821		286		—

Total contractual cash obligations	$	410,268	$	22,760	$	41,566	$	91,002	$	254,940

In addition to the items above, we have a severance plan and a change of control plan. See “Executive Compensation – Employment and Severance Agreements” in Item 11 of this Annual Report. We have entered into joint operating agreements, area of mutual interest agreements and joint venture agreements with other companies. These agreements may include drilling commitments or other obligations in the normal course of business. We also have asset retirement obligations of $19.4 million as of December 31, 2005, primarily due to the obligation to plug and abandon our wells, and a liability of $305.3 million for the fair value of our crude oil and natural gas swaps as of December 31, 2005.

The following table summarizes our commercial commitments at December 31, 2005.


	Total		Amount of Commitment Expiration Per Period
Commercial Commitments at	Amounts		Less than 1
December 31, 2005	Committed		Year		1 - 3 Years		4 - 5 Years		Over 5 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.

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

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements.

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, 2005, we had an interest rate swap in place covering $40 million of our outstanding balance on the revolving credit facility. This swap provides us with a 1-month LIBOR fixed interest rate of 4.287%, plus the applicable margin, until September 16, 2008. We had no derivative financial instruments for managing interest rate risks in place as of December 31, 2004 and 2003. If market interest rates for short-term borrowings increased 1%, the increase in our annual interest expense would be approximately $120,000. This sensitivity analysis is based on our financial structure at December 31, 2005.

The commodity price risk relates to our natural gas and crude oil produced, held in storage and marketed. Our financial results can be significantly impacted as commodity prices fluctuate widely in response to changing market forces. From time to time we may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage our exposure to commodity price volatility. The fixed-price physical contracts generally have terms of a year or more. We employ a policy of hedging gas production sold under NYMEX-based

contracts by selling NYMEX-based commodity derivative contracts which are placed with major financial institutions that we believe are minimal credit risks. The contracts may take the form of futures contracts, swaps or options. If NYMEX gas prices decreased $0.50 per Mcf, our gas sales revenues would decrease by $1.6 million, after considering the effects of the hedging contracts in place at December 31, 2005. At December 31, 2005 we had hedges on a portion of our oil production from 2006 through 2013. If the price of crude oil decreased $3.00 per Bbl, oil sales revenue for the year would decrease by $300,000. We had net pre-tax losses on our hedging activities of $9.1 million in 2005 and $10.9 million in 2004. This sensitivity analysis is based on our 2005 oil and gas sales volumes.

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

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

On November 2, 2005, we dismissed Ernst & Young LLP (“Ernst & Young”) as our independent registered public accounting firm. Our full Board of Directors, also functioning as our Audit Committee, approved the dismissal of Ernst & Young.

Ernst & Young’s reports on our financial statements for the two most recent fiscal years ended December 31, 2004 and 2003 contained no adverse opinion or disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope or accounting principle.

During our two most recent fiscal years ended December 31, 2004 and 2003 and through November 2, 2005, there were no disagreements with Ernst & Young on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which disagreement(s), if not resolved to the satisfaction of Ernst & Young, would have caused Ernst & Young to make reference to the subject matter of the disagreement(s) in Ernst & Young’s reports.

During our two most recent fiscal years ended December 31, 2004 and 2003 and through November 2, 2005, there were no “reportable events,” as defined in Item 304(a)(1)(v) of Regulation S-K.

Effective November 2, 2005, our Board of Directors, also functioning as our Audit Committee, appointed Deloitte & Touche LLP (“Deloitte & Touche”) as our independent registered public accounting firm. Deloitte & Touche was not consulted by us on any matter described in Item 304(a)(2) of Regulation S-K during the years ended December 31, 2004 and 2003, or through November 2, 2005 (the date Deloitte & Touche was engaged).

Item 9A. CONTROLS AND PROCEDURES

Material Weakness Previously Disclosed

As discussed in our 2004 Annual Report on Form 10-K, as amended, we did not maintain effective disclosure controls as of December 21, 2004 to ensure that hedge accounting was correctly applied pursuant to generally accepted accounting principles. The remedial actions implemented in 2005 related to these material weaknesses are described below.

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer and our Chief Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures as of December 31, 2005. As discussed below, we have made various changes in our internal controls which we believe remediate the material weaknesses previously identified by the company. We are relying on those changes in internal controls as an integral part of our disclosure controls and procedures. Based upon the results of the evaluation of our disclosure controls and procedures and based upon our reliance on these revised internal controls, management, including our Chief Executive Officer and our Chief Financial Officer, concluded that our disclosure controls and procedures were effective as of December 31, 2005.

Changes in Internal Control over Financial Reporting

PART III

Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Our executive officers and directors and their respective positions and ages of as of March 5, 2006 were as follows:


Name	Age		Position
Mark A. Houser		44	Chief Executive Officer and Chairman of the Board of Directors

James M. Vanderhider		47	President, Chief Financial Officer and Director

Kenneth Mariani		44	Senior Vice President, Chief Operating Officer and Director

Patricia A. Harcourt		42	Vice President Administration

Frederick J. Stair		46	Vice President and Corporate Controller

Matthew Coeny		35	Director

John B. Walker		60	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 five members, each of whom will hold office until our next annual shareholder meeting. The business experience of each executive officer and director is summarized below.

Mark A. Houser. On August 16, 2005, Mr. Houser was appointed our Chief Executive Officer and Chairman of the Board of Directors. Mr. Houser is Executive Vice President and Chief Operating Officer of EnerVest Management Partners, Ltd. Prior to joining EnerVest in May of 1999, he was Vice President, United States Exploration and Production, for Occidental Petroleum Corporation (“Oxy”), where he helped lead Oxy’s reorganization of its domestic reserve base, including the successful $3.65 billion acquisition of the Elk Hills Navel Petroleum Reserve. Mr. Houser began his career as an engineer with Kerr-McGee Corporation. In 1989 he joined Canadian Occidental Petroleum, Ltd. (now Nexen) where he held positions of increasing responsibility, including Vice President — Corporate Planning and Investor Relations in Calgary and Vice President — Exploration for CXY Energy, Canadian Oxy’s United States subsidiary. He holds a petroleum engineering degree from Texas A&M University and MBA from Southern Methodist University.

Mr. Houser serves on the Board of Directors of North American Prospect Expo (NAPE) and the Louisiana Independent Oil & Gas Association (LIOGA) and serves on the industry board of the Texas A&M Department of Petroleum Engineering. Mr. Houser is also a member of the Society of Petroleum Engineers and the Independent Petroleum Association of America (IPAA). He also serves on the Administrative Board of Chapelwood United Methodist Church.

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.

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 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.

Patricia A. Harcourt. Ms. Harcourt has been our Vice President of Administration since January 2003. Previously she served as Director of Administration from 2001 to 2003 and Director of Corporate Communications from 1994 to 2001. She joined us in 1988 as Investor Relations Coordinator. Prior to joining us, Ms. Harcourt was employed by Austin Powder Company as Employee Relations Administrator. She received her Bachelor of Arts degree in Communications from Bowling Green State University. She has 18 years of experience in the oil and gas industry and is a member of the National Investor Relations Institute and the Society for Human Resource Management.

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

Matthew Coeny. On August 16, 2005, Mr. Coeny was elected to our Board of Directors. Mr. Coeny is a Director of Citigroup Private Equity (“CPE”). CPE is a business unit of Citigroup Inc. (“Citigroup”) and is responsible for private equity investments, mezzanine debt investments and private equity partnership commitments on behalf of Citigroup affiliates and clients. Since joining CPE in 2000, he has participated in the evaluation, due diligence and execution of investments in a variety of industries. Prior to joining CPE, Mr. Coeny worked in Citigroup’s Investment Banking Division where he participated in numerous advisory and capital raising transactions. Prior to joining Citigroup in 1996, he was a Senior Consultant in KPMG’s Corporate Transactions practice. Mr. Coeny received a Bachelor of Science degree in Finance and Accounting from New York University.

John B. Walker. On August 16, 2005, Mr. Walker was elected to our Board of Directors. Mr. Walker is President and Chief Executive Officer of EnerVest. Prior to founding EnerVest, Mr. Walker was President and Chief Operating Officer of Torch Energy. During his tenure, Torch’s assets grew from $200 million to $1 billion. At Torch, Mr. Walker was responsible for the creation of Nuevo Energy Company and its initial public offering on the New York Stock Exchange. Prior to that, Mr. Walker created Walker Energy Partners, an America Stock Exchange Company, which raised $136 million and participated in over 1,000 wells. Mr. Walker was selected by Institutional Investor as an “All American” energy analyst for six years in a row. He holds a BBA with honors from Texas Tech University and a MBA with distinction from New York University.

Mr. Walker served as Chairman of the Independent Petroleum Association of America from 2003 to 2005. In May 2000, he was recognized with the IPAA’s Leadership award for his contributions to the industry and in 2001, received the Silver Beaver Award from the Boy Scouts. He is also a member of the Natural Gas Council and National Petroleum Council and serves, or has served, on the boards of the Houston Producers’ Forum, Houston Petroleum Club, Offshore Energy Center and Texas Independent Producers and Royalty Owners Association.

Audit Committee

Item 11. EXECUTIVE COMPENSATION

The following table shows annual and long-term compensation for services in all capacities during the fiscal years ended December 31, 2005, 2004 and 2003 of our Chief Executive Officers and our other four most highly compensated executive officers.

Summary Compensation Table


										Long-Term
										Compensation
										Awards
	Annual Compensation									No. of Shares
								Other Annual		Underlying		All Other
Name and Principal Position	Year		Salary		Bonus			Compensation		Options/SARs		Compensation ⁽⁵⁾
Mark A. Houser ⁽¹⁾		2005	$	—	$	—		$	—		—	$	—
Chief Executive Officer and Chairman of the Board

James A. Winne III ⁽²⁾		2005		155,769		56,250			—		—		1,550,696	⁽⁶⁾
Former Chief Executive Officer		2004		41,666		56,250			—		—		1,250
and Chairman of the Board

Michael Becci ⁽³⁾		2005		155,769		56,250			—		—		1,550,696	⁽⁶⁾
Former President and		2004		41,666		56,250			—		—		1,083
Chief Operating Officer

Robert W. Peshek ⁽⁴⁾		2005		203,061		5,000			—		—		410,713	⁽⁷⁾
Former Senior Vice President		2004		185,891		634,600	⁽⁸⁾		—		—		10,250
and Chief Financial Officer		2003		178,924		63,108			—		—		10,000

Frederick J. Stair		2005		125,948		20,000			—		—		256,169	⁽⁷⁾
Vice President and		2004		113,406		50,000			—		—		10,250
Corporate Controller		2003		109,392		23,000			—		—		5,532

Patricia A. Harcourt		2005		99,069		3,669			—		—		201,563	⁽⁷⁾
Vice President of		2004		94,777		366,308	⁽⁸⁾						10,250
Administration		2003		89,623		31,500							5,799


(1)		Mr. Houser was appointed Chairman and Chief Executive Officer on August 16, 2005 when the partners of Belden & Blake Corporation’s direct parent company, Capital C Energy Operations, L.P. (“Capital C”) completed the sale of all the partnership interests in Capital C to certain institutional funds managed by EnerVest Management Partners, Ltd. Mr. Houser did not receive any remuneration from Belden & Blake Corporation during 2005.

(2)		Mr. Winne was our Chief Executive Officer and Chairman of the Board from December 16, 2004 until he resigned from his position on August 16, 2005.

(3)		Mr. Becci was our President and Chief Operating Officer from December 16, 2004 until he resigned from his position on August 16, 2005.

(4)		Mr. Peshek resigned from his position effective October 6, 2005.

(5)		Primarily represents contributions of cash to our 401(k) Profit Sharing Plan for the account of the named executive officer, unless otherwise indicated.

(6)		Reflects a severance payment of $250,000 made to each indicated executive officer during 2005 pursuant to applicable severance agreements, and a payment of $1,293,196 made to each indicated executive officer during 2005 on the sale of common shares awarded to such officers pursuant to closing documents on the sale of all of the partnership interests in Capital C to institutional funds managed by EnerVest Management Partners, Ltd. effective August 16, 2005. Reimbursement of 401(k) contributions of $7,500 each are also included.

(7)		Includes the following amounts paid in 2006 pursuant to our 1999 Change in Control Protection Plan for Key Employees for the indicated executive officers: Peshek — $400,000, Stair — $250,000 and Harcourt — $190,800.

(8)		Includes amounts paid during 2005 under our Retention Plan dated February 12, 2004 for Mr. Peshek $549,600 and to Ms. Harcourt $366,308.

Compensation of Directors

Our directors are not compensated. We have no outside directors.

Employment and Severance Agreements

In February 2004, we entered into a retention plan effective until December 31, 2006, for certain executive officers that provided for a retention bonus payable six months after a change of control event (as defined in the plan). The purpose of the plan was to promote a stable management team during the period preceding and immediately following a potential change of control event. Under the plan, Mr. Peshek and Ms. Harcourt each received a retention bonus (as defined in the plan). As a result of the Merger, the plan was terminated on January 6, 2005 after retention payments were made to plan participants.

Under our 1999 Severance Pay Plan, all employees whose employment is terminated by us without “cause” (as defined therein) are eligible to receive severance benefits ranging from four weeks to twenty-four months, depending on their years of service and position with the Company.

We have a 1999 Change in Control Protection Plan for Key Employees providing severance benefits for such employees if, within two years following a change in control, in general, their employment is terminated by us without “cause” (as defined therein) or if they resign in response to a substantial reduction in duties, responsibilities, position, a reduction in compensation or a material reduction in medical benefits or a change of more than 40 miles in the location of their place of work as defined in the agreement. Such benefits range from twelve months to twenty-four months, depending on their position with us. As a result of the Transaction, Messrs. Peshek and Stair and Ms. Harcourt have received or will receive payments under the Plan.

Compensation Committee Interlocks and Insider Participation

After the Merger with Capital C, we do not have a compensation committee. During 2005, the following officers and employees (current and former) of the Company participated in our Board’s deliberations concerning executive officer compensation: Messrs. Winne and Becci.

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

On August 16, 2005, the former partners of Capital C completed the sale of all of the partnership interests in Capital C to certain institutional funds managed by EnerVest Management Partners, Ltd. (“EnerVest”). EnerVest incurred and was reimbursed by us $1.1 million for transaction costs. This amount was recorded as an accrued expense at December 31, 2005 and was paid in January 2006.

On March 15, 2006, we entered into a joint operating agreement with EnerVest Operating L.L.C. (“EnerVest Operating”), a subsidiary of EnerVest. The joint operating agreement was effective October 1, 2005 and resulted in expense to us of $642,000 in 2005. This amount was recorded as an accrued expense at December 31, 2005.

As of December 31, 2005, we owed EnerVest $1.1 million and EnerVest Operating $642,000.

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, 2005 was $25 million. Interest payments of $945,000 were made in 2005 and were paid in cash.

Messrs. Houser, Vanderhider and Mariani are officers and directors of the Company and they are officers and equity owners of EnerVest. Mr. Walker is a director of the Company and an officer and equity owner 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, Mariani and Walker.

From July 7, 2004 through August 15, 2005 Carlyle/Riverstone controlled and had a majority interest in Capital C, our sole shareholder. Capital C received a fee from us in 2004 of approximately $1.4 million in connection with the Merger. We also reimbursed Capital C $61,323 in 2004 for costs they incurred related to the Merger. We paid Carlyle/Riverstone $492,277 for costs they incurred in 2004 on our behalf, of which $471,790 was third party legal fees related to the Merger. We reimbursed Carlyle/Riverstone $91,490 for expenses in 2005.

We were a party to a management services agreement with Capital C beginning on July 7, 2004, pursuant to which Frost W. Cochran, W. Mac Jensen and B. Dee Davis provided certain management and advisory services to us for a quarterly fee of $250,000 plus reimbursement of expenses. These services included general management supervision and oversight, in the capacity as officers of Belden & Blake; financial advisory services; evaluation of potential acquisitions and other business opportunities; and strategic consulting services. This agreement was terminated effective December 20, 2004. The total amount paid in 2004 pursuant to this agreement was approximately $526,136.

We reimbursed Legend for expenses incurred in connection with services provided on our behalf. In 2004, we paid Legend approximately $208,000 for salary and bonus for James A. Winne III and Michael Becci, and approximately $38,000 for reimbursement of other Legend expenses related to our company’s activities. In 2005, we paid Legend approximately $85,000 for reimbursement of other Legend expenses related to our company’s activities. During 2005, we paid Messrs. Winne and Becci directly, as employees of the Company, rather than reimbursing Legend.

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Ernst & Young served as our independent auditor for the year ended December 31, 2004. On November 2, 2005, the Board replaced Ernst & Young with Deloitte & Touche as our independent auditor. Aggregate fees for professional services provided to us by Ernst & Young and Deloitte & Touche for the years ended December 31, 2005 and 2004 were as follows:


	December 31,
	2005		2004
Audit fees	$	824,338	$	637,000
Audit-related fees		—		—
Tax fees		35,800		110,000
All other fees		1,590		2,663

	$	861,728	$	749,663

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. In 2004, audit services also included the audit of Ward Lake Drilling, audit services in connection with the consent solicitation of our 9-7/8% Notes and audit services in connection with the preparation of our Registration Statement on Form S-4 related to our Notes and refinancing in connection with the Merger. In 2005, audit services included services in connection with the amended filings of our 2004 Form 10-K/A and the three Forms 10-Q/A for the 2005 quarterly periods. Tax fees included tax compliance and tax planning. 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.

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 book runner, sole syndication agent and administrative agent (incorporated by reference to Exhibit 10.1 to Belden & Blake’s 8-K filed on August 22, 2005)

10.3		Priority Lien Pledge and Security Agreement, dated as of July 7, 2004, between Belden & Blake Corporation, The Canton Oil & Gas Company, Ward Lake Drilling, Inc. and Wells Fargo Bank, N.A., as Collateral Trustee, incorporated by reference to Exhibit 10.3 to Belden & Blake Corporation’s Form 8-K dated July 7, 2004 (as amended).

10.4		Parity Lien Pledge and Security Agreement, dated as of July 7, 2004, between Belden & Blake Corporation, The Canton Oil & Gas Company, Ward Lake Drilling, Inc. and Wells Fargo Bank, N.A., as Collateral Trustee, incorporated by reference to Exhibit 10.4 to Belden & Blake Corporation’s Form 8-K dated July 7, 2004 (as amended).

10.5		Priority Lien Pledge Agreement, dated as of July 7, 2004, between Capital C Energy Operations, LP and Wells Fargo Bank, N.A., as Collateral Trustee, incorporated by reference to Exhibit 10.5 to Belden & Blake Corporation’s Form 8-K dated July 7, 2004 (as amended).

10.6		Parity Lien Pledge Agreement, dated as of July 7, 2004, between Capital C Energy Operations, LP and Wells Fargo Bank, N.A., as Collateral Trustee, incorporated by reference to Exhibit 10.6 to Belden & Blake Corporation’s Form 8-K dated July 7, 2004 (as amended).

10.7		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).

10.8		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)


No.		Description

10.9		Termination and Release Agreement, dated as of July 7, 2004, by and among Belden & Blake Corporation, The Canton Oil & Gas Company, Ward Lake Drilling, Inc., Ableco Finance LLC and Wells Fargo Foothill, Inc., incorporated by reference to Exhibit 10.10 to Belden & Blake Corporation’s Form 8-K dated July 7, 2004 (as amended).

10.10		Belden & Blake Corporation Retention Plan, incorporated by reference to Exhibit 10.1 to Belden & Blake Corporation’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2004.

10.11		Change in Control Severance Pay Plan for Key Employees of Belden & Blake Corporation dated August 12, 1999, incorporated by reference to Exhibit 10.7 to Belden & Blake Corporation’s Annual Report on Form 10-K for the year ended December 31, 1999.

10.12		Amendment No. 1 of Belden & Blake Corporation 1999 Change in Control Protection Plan Key Employees dated as of February 26, 2002, incorporated by reference to Exhibit 10.7 (a) to Belden & Blake Corporation’s Annual Report on Form 10-K for the year ended December 31, 2002.

10.13		Amendment No. 2 of the Belden & Blake Corporation 1999 Change in Control Protection Plan for Key Employees dated as of October 23, 2002, incorporated by reference to Exhibit 10.7(b) to the Belden & Blake Corporation’s Annual Report on Form 10-K for the year ended December 31, 2002.

10.14		Severance Pay Plan for Employees of Belden & Blake Corporation dated August 12, 1999, incorporated by reference to Exhibit 10.8 to Belden & Blake Corporation’s Annual Report on Form 10-K for the year ended December 31, 1999.

10.15		Amendment 1 to the Belden & Blake Corporation 1999 Severance Pay Plan dated as of May 29, 2000, incorporated by reference to Exhibit 10.8 (a) to Belden & Blake Corporation’s Annual Report on Form 10-K for the year ended December 31, 2002.

10.16		Amendment 2 to the Belden & Blake Corporation 1999 Severance Pay Plan dated as of September 12, 2002, incorporated by reference to Exhibit 10.8 (b) to the Belden & Blake Corporation’s Annual Report on Form 10-K for the year ended December 31, 2002.

10.17		Severance Release Agreement dated February 11, 2005 by and between Belden & Blake Corporation and R. Mark Hackett, incorporated by reference to Exhibit 10.1 to Belden & Blake Corporation’s Form 8-K dated February 11, 2005.

10.18		Severance Release Agreement dated February 18, 2005 by and between Belden & Blake Corporation and Richard R. Hoffman, incorporated by reference to Exhibit 10.1 to Belden & Blake Corporation’s Form 8-K dated February 18, 2005.

10.19		Directors’ Fees for Outside Directors effective February 14, 2005

10.20		Amended and restated employment agreement dated July 1, 2004 by and between Belden & Blake Corporation and John L. Schwager.

10.21		Waiver of certain rights to payments or benefits by and between Belden & Blake Corporation and John L. Schwager.

10.22		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)

10.23		Contingent Value Agreement, dated August 16, 2005, by and among, James A. Winne III, Michael Becci, Capital C Energy, LP, Capital C Energy Partners, L.P., EnerVest BB, L.P., EnerVest BB GP LLC and Belden & Blake Corporation (incorporated by reference to Exhibit 10.7 to Belden & Blake’s 8-K filed on August 22, 2005)

10.24		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)

10.25*		First Amendment to Credit Agreement, dated as of September 27, 2005, by and among Belden & Blake Corporation and BNP Paribas.

10.26*		Operating Agreement dated October 1, 2005, by and between Belden & Blake Corporation and EnerVest Operating L.L.C.

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.

16		Letter regarding change in certifying accountant (incorporated by reference to Exhibit 16.1 Belden & Blake’s 8-K filed on November 8, 2005).

23.1*		Consent of Independent Registered Public Accounting Firm

23.2*		Consent of Independent Registered Public Accounting Firm

31.1*		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

BELDEN & BLAKE CORPORATION
INDEX TO CONSOLIDATED
FINANCIAL STATEMENTS AND SCHEDULES

Item 15(a) (1) and (2)


	Page
CONSOLIDATED FINANCIAL STATEMENTS
Reports of Independent Registered Public Accounting Firms		F-2/3
Consolidated Balance Sheets as of December 31, 2005 (Successor Company) and December 31, 2004 (Predecessor I Company)		F-4
Consolidated Statements of Operations:
138 day period from August 16, 2005 to December 31, 2005 (Successor Company) 227 day period from January 1, 2005 to August 15, 2005 (Predecessor I Company) 178 day period from July 7, 2004 to December 31, 2004 (Predecessor I Company) 188 day period from January 1, 2004 to July 6, 2004 (Predecessor II Company) Year ended December 31, 2003 (Predecessor II Company)		F-5
Consolidated Statements of Shareholder’s Equity (Deficit):
138 day period from August 16, 2005 to December 31, 2005 (Successor Company) 227 day period from January 1, 2005 to August 15, 2005 (Predecessor I Company) 178 day period from July 7, 2004 to December 31, 2004 (Predecessor I Company) 188 day period from January 1, 2004 to July 6, 2004 (Predecessor II Company) Year ended December 31, 2003 (Predecessor II Company)		F-6
Consolidated Statements of Cash Flows:
138 day period from August 16, 2005 to December 31, 2005 (Successor Company) 227 day period from January 1, 2005 to August 15, 2005 (Predecessor I Company) 178 day period from July 7, 2004 to December 31, 2004 (Predecessor I Company) 188 day period from January 1, 2004 to July 6, 2004 (Predecessor II Company) Year ended December 31, 2003 (Predecessor II Company)		F-7
Notes to Consolidated Financial Statements		F-8

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 Stockholders of

Belden & Blake Corporation

Houston, Texas

We have audited the accompanying consolidated balance sheet of Belden & Blake Corporation and subsidiaries (the “Company”) as of December 31, 2005, and the related consolidated statements of operations, shareholder’s equity (deficit), and cash flows for the one hundred thirty-eight day period from August 16, 2005 to December 31, 2005 (Successor Company) and for the two hundred twenty-seven day period from January 1, 2005 to August 15, 2005 (Predecessor I Company). These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audit.

We conducted our audit 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 audit 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 audit provides a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2005, and the results of its operations and its cash flows for the one hundred thirty-eight day period from August 16, 2005 to December 31, 2005 (Successor Company) and for the two hundred twenty-seven day period from January 1, 2005 to August 15, 2005 (Predecessor I Company) in conformity with accounting principles generally accepted in the United States of America.

DELOITTE & TOUCHE LLP

Houston, Texas

April 6, 2006

F - 2

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholder and Board of Directors
Belden & Blake Corporation

We have audited the accompanying consolidated balance sheets of Belden & Blake Corporation (“Company”) as of December 31, 2004 and the related consolidated statements of operations, shareholders’ equity (deficit), and cash flows for the one hundred seventy-eight day period ended December 31, 2004, the one hundred eighty-eight day period ended July 6, 2004, and the year ended December 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule 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. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audit 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, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Belden & Blake Corporation at December 31, 2004 and the consolidated results of their operations and their cash flows for the one hundred seventy-eight day period ended December 31, 2004, the one hundred eighty-eight day period ended July 6, 2004, and the year ended December 31, 2003, in conformity with U.S. generally accepted accounting principles.

As explained in Note 1 to the consolidated financial statements, in 2003 the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations.

Ernst & Young LLP

Cleveland, Ohio
February 11, 2006

F - 3

BELDEN & BLAKE CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)


	Successor			Predecessor I
	Company			Company
	December 31,
	2005			2004
ASSETS
Current assets
Cash and cash equivalents	$	8,172		$	18,407
Accounts receivable, net		25,225			18,667
Inventories		1,085			518
Deferred income taxes		25,752			11,169
Other current assets		349			439
Fair value of derivatives		174			—

Total current assets		60,757			49,200

Property and equipment, at cost
Oil and gas properties (successful efforts method)		661,094			514,904
Gas gathering systems		1,593			4,485
Land, buildings, machinery and equipment		6,795			7,720

		669,482			527,109
Less accumulated depreciation, depletion and amortization		14,456			16,917

Property and equipment, net		655,026			510,192
Goodwill		91,443			—
Fair value of derivatives		285			—
Other assets		2,607			11,461

	$	810,118		$	570,853

LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Accounts payable	$	5,314		$	3,796
Accrued expenses		28,496			23,445
Current portion of long-term liabilities		776			1,964
Fair value of derivatives		65,170			24,902

Total current liabilities		99,756			54,107

Long-term liabilities
Bank and other long-term debt		52,085			88,592
Senior secured notes		200,340			192,500
Subordinated promissory note — related party		25,000			—
Asset retirement obligations and other long-term liabilities		18,919			14,390
Fair value of derivatives		240,129			55,182
Deferred income taxes		84,490			108,994

Total long-term liabilities		620,963			459,658

Shareholder’s equity
Common stock: without par value Predecessor: 1,500 shares authorized and issued at December 31, 2004; Successor: 3,000 shares authorized; 1,534 shares issued at December 31, 2005		—			—
Additional paid in capital		125,000			77,500
Retained earnings		9,063			7,263
Accumulated other comprehensive loss		(44,664	)		(27,675	)

Total shareholder’s equity		89,399			57,088

	$	810,118		$	570,853

See accompanying notes.

F - 4

BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands)


	Successor Company		Predecessor I Company					Predecessor II Company
			For the 227 Day			For the 178 Day
	For the 138 Day		Period From			Period from		For the 188 Day
	Period From August		January 1, 2005			July 7, 2004 to		Period from			Year ended
	16, 2005 to		to August 15,			December 31,		January 1, 2004			December 31,
	December 31, 2005		2005			2004		to July 6, 2004			2003
Revenues
Oil and gas sales	$	69,954	$	71,400		$	56,782	$	45,307		$	84,610
Gas gathering and marketing		6,551		6,439			4,923		5,057			10,538
Other		166		284			696		458			266

		76,671		78,123			62,401		50,822			95,414

Expenses
Production expense		10,377		13,423			11,634		12,122			20,017
Production taxes		1,771		1,901			1,467		1,300			2,449
Gas gathering and marketing		5,481		5,629			4,522		4,579			9,570
Exploration expense		1,229		2,424			2,750		3,220			6,849
General and administrative expense		1,455		3,835			2,651		3,672			4,559
Franchise, property and other taxes		65		129			52		115			202
Depreciation, depletion and amortization		14,341		21,265			17,527		9,089			18,098
Impairment of oil and gas properties		—		—			—		—			896
Accretion expense		407		745			633		195			343
Derivative fair value (gain) loss		5,054		8,258			371		2,038			(319	)
Transaction expense		7		7,535			—		26,001			—

		40,187		65,144			41,607		62,331			62,664

Operating income (loss)		36,484		12,979			20,794		(11,509	)		32,750

Other expense
Interest expense		8,526		14,786			11,877		12,184			23,580

Income (loss) from continuing operations before income taxes and cumulative effect of change in accounting principle		27,958		(1,807	)		8,917		(23,693	)		9,170
Provision (benefit) for income taxes		10,395		(1,487	)		1,654		(4,824	)		3,210

Income (loss) from continuing operations before cumulative effect of change in accounting principle		17,563		(320	)		7,263		(18,869	)		5,960
Income (loss) from discontinued operations, net of tax		—		—			—		28,868			(10,681	)

Income (loss) before cumulative effect of change in accounting principle		17,563		(320	)		7,263		9,999			(4,721	)
Cumulative effect of change in accounting principle, net of tax		—		—			—		—			2,397

Net income (loss)	$	17,563	$	(320	)	$	7,263	$	9,999		$	(2,324	)

See accompanying notes.

F - 5

BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY (DEFICIT)
(in thousands)


	Successor Company				Predecessor I Company					Predecessor II Company												Accumulated Other			Total
	Common		Common		Common			Common		Common			Common			Paid in			Equity			Comprehensive			Equity
	Shares		Stock		Shares			Stock		Shares			Stock			Capital			(Deficit)			Income			(Deficit)
Predecessor II Company:
January 1, 2003		—	$	—		—		$	—		10,296		$	1,030		$	107,118		$	(148,332	)	$	(4,854	)	$	(45,038	)
Comprehensive income (loss):
Net income																				(2,324	)					(2,324	)
Other comprehensive income (loss), net of tax:
Change in derivative fair value																							(18,124	)		(18,124	)
Reclassification adjustment for derivative (gain) loss reclassified into oil and gas sales																							6,543			6,543

Total comprehensive loss																										(13,905	)

Stock options exercised											120			12			108									120
Stock-based compensation																	326									326
Repurchase of stock options																	(48	)								(48	)
Tax benefit of repurchase of stock options and stock options exercised																	170									170
Treasury stock											(20	)		(2	)		(41	)								(43	)

December 31, 2003		—		—		—			—		10,396			1,040			107,633			(150,656	)		(16,435	)		(58,418	)
Comprehensive (loss) income:
Net loss																				9,999						9,999
Other comprehensive income (loss), net of tax:
Change in derivative fair value																							(11,174	)		(11,174	)
Reclassification adjustment for derivative (gain) loss reclassified into oil and gas sales																							5,512			5,512

Total comprehensive loss																										4,337

Stock options exercised											65			6			105									111
Stock-based compensation																	1,097									1,097
Repurchase of stock options																	(283	)								(283	)
Tax benefit of repurchase of stock options and stock options exercised																	116									116
Treasury stock											(6	)		(1	)		(28	)								(29	)
Redemption of common stock											(10,455	)		(1,045	)		(108,640	)		140,657			22,097			53,069

July 6, 2004											—			—			—			—			—			—
Predecessor I Company:
Sale of common stock						2											77,500									77,500
Comprehensive income (loss):
Net income																				7,263						7,263
Other comprehensive income (loss), net of tax:
Change in derivative fair value																							(35,221	)		(35,221	)
Reclassification adjustment for derivative (gain) loss reclassified into oil and gas sales																							7,546			7,546

Total comprehensive loss																										(20,412	)

December 31, 2004		—		—		2			—		—			—			77,500			7,263			(27,675	)		57,088
Comprehensive income (loss):
Net loss																				(320	)					(320	)
Other comprehensive income (loss), net of tax:
Change in derivative fair value																							(140,613	)		(140,613	)
Reclassification adjustment for derivative (gain) loss reclassified into oil and gas sales																							11,888			11,888

Total comprehensive loss																										(129,045	)
Stock-based compensation																	2,586									2,586
Redemption of common stock						(2	)										(80,086	)		(6,943	)		156,400			69,371
Equity adjustment due to purchase accounting		2															116,000									116,000
Equity contribution																	9,000									9,000

August 16, 2005		2		—		—			—		—			—			125,000			—			—		$	125,000
Successor Company:
Comprehensive income (loss):
Net income																				17,563						17,563
Other comprehensive income (loss), net of tax:
Change in derivative fair value																							(55,654	)		(55,654	)
Reclassification adjustment for derivative (gain) loss reclassified into oil and gas sales																							10,990			10,990

Total comprehensive loss																										(27,101	)
Dividends																				(8,500	)					(8,500	)

December 31, 2005		2	$	—		—		$	—		—		$	—		$	125,000		$	9,063		$	(44,664	)	$	89,399

See accompanying notes.

F - 6

BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)


	Successor Company			Predecessor I Company						Predecessor II Company
	For the 138 Day			For the 227 Day			For the 178 Day			For the 188 Day
	Period From August			Period From			Period From July			Period From
	16, 2005 to December			January 1, 2005 to			7, to December 31,			January 1, to July			Year ended
	31, 2005			August 15, 2005			2004			6, 2004			December 31, 2003
Cash flows from operating activities:
Net income (loss)	$	17,563		$	(320	)	$	7,263		$	9,999		$	(2,324	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		14,341			21,265			17,527			9,723			19,357
Impairment of oil and gas properties		—			—			—			—			5,774
Accretion expense		407			745			633			221			365
(Gain) loss on sale of businesses		—			—			—			(45,223	)		69
Loss on disposal of property and equipment		57			86			18			375			1,452
Amortization of derivatives and other noncash hedging activities		9,511			12,344			937			2,037			(3,456	)
Exploration expense		1,229			2,424			2,750			4,639			16,882
Deferred income taxes		10,395			(1,487	)		1,829			10,802			(2,546	)
Stock-based compensation		—			2,586			—			3,990			326
Cumulative effect of change in accounting principle, net of tax		—			—			—			—			(2,397	)
Change in operating assets and liabilities, net of effects of acquisition and disposition of businesses:
Accounts receivable and other operating assets		(1,421	)		213			(304	)		(900	)		(3,969	)
Inventories		484			(85	)		394			79			62
Accounts payable and accrued expenses		9,813			(8,845	)		4,234			184			(2,204	)

Net cash provided by (used in) operating activities		62,379			28,926			35,281			(4,074	)		27,391

Cash flows from investing activities:
Acquisition of businesses		—			—			—			—			(4,841	)
Disposition of businesses, net of cash		—			—			—			72,464			816
Proceeds from property and equipment disposals		21			5			125			247			2,997
Exploration expense		(1,229	)		(2,424	)		(2,750	)		(4,639	)		(16,882	)
Additions to property and equipment		(11,640	)		(17,177	)		(12,008	)		(18,103	)		(29,878	)
(Increase) decrease in other assets		(26	)		(34	)		(35	)		1,218			(120	)

Net cash (used in) provided by investing activities		(12,874	)		(19,630	)		(14,668	)		51,187			(47,908	)

Cash flows from financing activities:
Proceeds from senior secured notes		—			—			—			192,500			—
Proceeds from senior secured facility — term loan		—			—			—			100,000			—
Proceeds from senior secured facility		37,000			57,000			—			—			—
Sale of common stock		—			—			—			77,500			—
Proceeds from subordinated promissory note		—			25,000			—			—			—
Repayment of senior subordinated notes		—			—			(1,040	)		(223,960	)		—
Dividends and payment to shareholders and optionholders		(8,500	)		—			—			(113,674	)		—
Settlement of derivative liabilities recorded in purchase accounting		(34,360	)		(20,440	)		(12,007	)		—			—
Debt issue costs		(27	)		(2,120	)		—			(11,700	)		(250	)
Repayment of senior secured facility — term loan		—			(89,500	)		(10,500	)		—			—
Repayment of senior secured facility		(42,000	)		—			—			—			—
Proceeds from revolving line of credit		—			—			—			146,636			195,859
Repayment of long-term debt and other obligations		(5	)		(84	)		(126	)		(194,187	)		(175,573	)
Equity contribution		—			9,000			—			—			—
Proceeds from stock options exercised		—			—			—			111			120
Repurchase of stock options		—			—			—			(283	)		122
Purchase of treasury stock		—			—			—			(29	)		(43	)


Net cash (used in) provided by financing activities		(47,892	)		(21,144	)		(23,673	)		(27,086	)		20,235


Net (decrease) increase in cash and equivalents		1,613			(11,848	)		(3,060	)		20,027			(282	)

Cash and cash equivalents at beginning of period		6,559			18,407			21,467			1,440			1,722


Cash and cash equivalents at end of period	$	8,172		$	6,559		$	18,407		$	21,467		$	1,440

See accompanying notes.

F - 7

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 Management Partners, 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 those dates. Accordingly, the financial statements for the period subsequent to August 15, 2005 are presented on the Company’s new basis of accounting, while the results of operations for prior periods reflect the historical results of the two predecessor companies. Vertical black lines are presented to separate the financial statements of the two predecessor companies and the successor company. The “Successor Company” refers to the period from August 16, 2005 and forward. The “Predecessor I Company” refers to the period from July 7, 2004 through August 15, 2005. The “Predecessor II Company” refers to the period prior to July 7, 2004.

The aggregate value of the total equity consideration paid for the Transaction was $125 million, which includes $116 million paid to former shareholders and a $9 million equity contribution paid to the Company. The table below summarizes the allocation of the Transaction’s purchase price based on the acquisition date fair values of the assets acquired and the liabilities assumed.


	(in thousands)
Net working capital, including cash of $8,290	$	4,201
Oil and gas properties		652,569
Goodwill		91,443
Other assets		11,454
Derivative liability		(258,417	)
Other non-current liabilities		(18,733	)
Net deferred income tax liabilities		(74,748	)
Long-term debt		(282,769	)

Cash equity contribution	$	125,000

F - 8

Goodwill represents the excess of the purchase price over the estimated fair value of the assets acquired net of the fair value of liabilities assumed in the acquisition. The recorded goodwill is not deductible for tax purposes.

The principal factors that contributed to the purchase price that resulted in goodwill are as follows:

	•		Cost savings and operational synergies of the Company when combined with the other operations managed by EnerVest. These savings include the elimination of duplicative facilities, reduction of personnel and operating and development costs through the management of a larger asset base.

	•		The affiliation with EnerVest, an acquisition-focused company, coupled with the enhanced presence in the Appalachian and Michigan basins with EnerVest’s other operations, provides the opportunity to create value by high grading investment opportunities and identifying new investment opportunities.

	•		The going-concern value of the Company, including its experienced workforce.

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 the Company has only one reporting unit the reporting unit used for testing will be the entire company. The fair value of the reporting unit is determined and compared to the book value of that reporting unit. If the fair value of the reporting unit is less than the book value (including goodwill) then goodwill is reduced to its fair value and the amount of the writedown is charged to earnings.

The fair value of the reporting unit will be based on estimates of future net cash flows from proved reserves and from future exploration for and development of unproved reserves. Downward revisions of estimated reserves or production, increases in estimated future costs or decreases in oil and gas prices could lead to an impairment of all or a portion of goodwill in future periods.

In connection with the Transaction, the Company entered into Compensation Agreements (“Compensation Agreements”), each on substantially similar terms, with James A. Winne III, the Company’s former Chairman of the Board and Chief Executive Officer, and Michael Becci, the Company’s former President and Chief Operating Officer. The Compensation Agreements provided for a severance payment equal to $250,000 and the issuance of 17.1037 shares of common stock in the Company, payable to each of Messrs. Winne and Becci promptly upon the Transaction. In exchange for their severance payments, Messrs. Winne and Becci resigned as officers and directors of the Company effective August 16, 2005. This was reported as compensation expense of $3.1 million and included in the transaction expenses in the Predecessor I Company period ending August 15, 2005.

The Company entered into a Contingent Value Agreement (“Contingent Value Agreement”) with the former partners of Capital C, Messrs. Becci and Winne, and the EnerVest funds that purchased Capital C. Under the Contingent Value Agreement, if properties are contributed to a publicly traded partnership or a publicly traded royalty trust (“MLP”), then the Company has agreed to pay the following aggregate amount to the former partners of Capital C, and Messrs. Becci and Winne:

F - 9

	•		20% of the difference between the value received for the assets upon transfer to a MLP and the book value of the assets, if the transfer occurs within one year following the Transaction; and

	•		10% of the difference between the value received for the assets upon transfer to a MLP and the book value of the assets, if the transfer occurs in the second year following the Transaction.

The Company does not intend to contribute assets to a publicly traded partnership, publicly traded royalty trust or MLP at this time.

The Company incurred transaction costs associated with the Transaction of $7.5 million including $2.6 million of stock compensation expense and $500,000 of severance costs. These costs were expensed in the Predecessor I Company period ended August 15, 2005. The Company also capitalized $2.1 million of debt financing costs and recorded obligations of $5.5 million in purchase accounting including $4.2 million of severance cost and $1.2 million of acquisition costs incurred by EnerVest.

Following are unaudited pro forma results of operations as if the Transaction occurred at the beginning of 2004 and 2005 (in thousands):


	Year ended December 31,
	2005		2004
Total revenues	$	154,794	$	113,223
Income (loss) from continuing operations		20,317		(280	)

The unaudited pro forma information presented above assumes the transaction-related expenses were incurred prior to the period presented and does not purport to be indicative of the results that actually would have been obtained if the Transaction had been consummated at the beginning of 2004 and is not intended to be a projection of future results or trends.

(2) Business and Significant Accounting Policies

Business

F - 10

The Company operates in the oil and gas industry. The Company’s 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 the Company’s working capital and results of operations.

Principles of Consolidation and Financial Presentation

The accompanying consolidated financial statements include the financial statements of the Company and its subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. Certain reclassifications have been made to conform to the presentation in 2004.

Use of Estimates in the Financial Statements

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts. Significant estimates used in the preparation of the Company’s 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

The Company uses the “successful efforts” method of accounting for its 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 geological and geophysical costs include costs for salaries and benefits of the Company’s personnel in those areas and other third party costs. The costs of carrying and retaining undeveloped properties include salaries and benefits of the Company’s land department personnel, delay rental payments made on new and existing leases, ad valorem taxes on existing leases and the cost of previously capitalized leases 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 extraordinary 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.

F - 11

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. Impairments recorded in 2003 were $475,000 which reduced the book value of unproved oil and gas properties to their estimated fair value. No impairments were recorded in 2004 and 2005.

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

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 2003, the Company recorded $421,000 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. No impairments were recorded in 2004 and 2005.

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, the Company recorded goodwill associated with the Transaction which resulted in goodwill of $91.4 million at December 31, 2005. The Company had no goodwill at December 31, 2004. 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 fourth quarter of 2005, the Company performed its annual assessment of impairment of the goodwill and determined that there was no impairment.

At December 31, 2005 and 2004, the Company had $2.0 million and $10.9 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 $1.2 million, $1.4 million and $1.2 million for the years ended December 31, 2005, 2004 and 2003, respectively. At December 31, 2005, the amortization of deferred debt issuance costs in the next five years is as follows: $424,000 in each of the next four years (2006 through 2009) and $270,000 in 2010.

Revenue Recognition

F - 12

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

Income Taxes

The Company uses 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

The fair value of the Company’s stock options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for the Predecessor II Company periods ended July 6, 2004, and December 31, 2003 respectively: risk-free interest rates of 3.6% and 3.7%; volatility factor of the expected market price of the Company’s common stock of near zero; dividend yield of zero; and a weighted-average expected life of the option of seven years. There were no stock options granted in the Predecessor I Company 178 day period ended December 31, 2004 or in the year 2005.

The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company’s stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management’s opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its stock options.

For purposes of the pro forma disclosures required by SFAS 123, the estimated fair value of the options is amortized to expense over the options’ vesting period. The changes in net income or loss as if the Company had applied the fair value provisions of SFAS 123 for the Predecessor II Company periods ended July 6, 2004 and December 31, 2003 were not material. There were no outstanding stock options or activity in the Successor Company period ended December 31, 2005.

The changes in share value and the vesting of shares are reported as adjustments to compensation expense. The change in share value in the Predecessor II Company periods ended July 6, 2004 and December 31, 2003 resulted in an increase in compensation expense of $4.0 million and $325,000, respectively.

In connection with the closing of the Transaction, the Company issued approximately 34 shares

F - 13

of common stock to Messrs. Winne and Becci. The shares were purchased from them at the closing of the Transaction. These shares were reported as compensation expense of $2.6 million and included in the transaction expenses in the Predecessor I Company period ending August 15, 2005.

Derivatives and Hedging

As a result of the adoption of SFAS 133 in 2001, the Company recognizes all derivative financial instruments as either assets or liabilities at fair value. Derivative instruments that are not hedges must be adjusted to fair value through net income (loss). Under the provisions of SFAS 133, changes in the fair value of derivative instruments that are fair value hedges are offset against changes in the fair value of the hedged assets, liabilities, or firm commitments, through net income (loss). Changes in the fair value of derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time as the hedged items impact earnings. 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 6.

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. The Company assesses 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 the Company determines that a derivative is no longer highly effective as a hedge or if the Company decides to discontinue the hedging relationship.

Asset Retirement Obligations

On January 1, 2003, the Company adopted SFAS 143, “Accounting for Asset Retirement Obligations.” SFAS 143 amends SFAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies” which requires the Company to recognize a liability for the fair value of its asset retirement obligations associated with its tangible, long-lived assets. The majority of the Company’s asset retirement obligations relate to the plugging and abandonment (excluding salvage value) of the Company’s oil and gas properties. At January 1, 2003, there were no assets legally restricted for purposes of settling asset retirement obligations. The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect adjustment to record a $4.0 million increase in long-term asset retirement obligation liabilities, a $621,000 increase in current asset retirement obligation liabilities, a $3.2 million increase in the carrying value of oil and gas assets, a $5.2 million decrease in accumulated depreciation, depletion and amortization and a $1.4 million increase in deferred income tax liabilities. The net effect of adoption was to record a gain of $2.4 million, net of tax, as a cumulative effect of a change in accounting principle in the Company’s consolidated statement of operations in the first quarter of 2003.

A reconciliation of the Company’s liability for plugging and abandonment costs for the year ended December 31, 2005 and 2004 is as follows (in thousands):

F - 14


	Successor									Predecessor II
	Company			Predecessor I Company						Company
	For The 138 Day			For the 227 Day			For The 178 Day
	Period From			Period From			Period From July 7,			For The 188 Day Period
	August 16, 2005 to			January 1, 2005 to			2004 to December 31,			From January 1, 2004
	December 31, 2005			August 15, 2005			2004			to July 6, 2004
Beginning asset retirement obligations	$	18,884		$	14,942		$	14,274		$	4,595
Liabilities incurred		173			142			101			9
Liabilities settled		(75	)		(239	)		(85	)		(30	)
Accretion expense		407			745			633			195
Revisions in estimated cash flows		—			—			19			24

Ending asset retirement obligations	$	19,389		$	15,590		$	14,942		$	4,793

(3) New Accounting Pronouncements

In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment.” SFAS 123(R) revises SFAS 123, “Accounting for Stock-Based Compensation”, and focuses on accounting for share-based payments for services by employer to employee. The statement requires companies to expense the fair value of employee stock options and other equity-based compensation at the grant date. The statement does not require a certain type of valuation model and either a binomial or Black-Scholes model may be used. The provisions of SFAS 123(R) are effective for financial statements for fiscal periods ending after June 15, 2005.

SFAS 123(R) must be adopted no later than January 1, 2006 and permits public companies to adopt its requirements using one of two methods:

	•		A “modified prospective” method in which compensation cost is recognized beginning with the effective date based on the requirements of SFAS 123(R) for all share-based payments granted after the adoption date and based on the requirements of SFAS 123 for all awards granted to employees prior to the effective date of SFAS 123(R) that remain unvested on the adoption date; or

	•		A “modified retrospective” method which includes the requirements of the modified prospective method described above, but also permits entities to restate either all prior periods presented or prior interim periods of the year of adoption based on the amounts previously recognized under SFAS 123 for purposes of pro forma disclosures.

The Company adopted the provisions of SFAS 123(R) on January 1, 2006 using the modified prospective method.

As permitted by SFAS 123, the Company accounted for share-based payments to employees prior to January 1, 2006 using the intrinsic value method prescribed by APB 25 and related interpretations. As such, the Company generally did not recognize compensation expense associated with employee stock option grants. In 2004, all outstanding stock options were expensed due to the merger on July 7, 2004. The Successor Company and Predecessor I Company did not have any stock options.

F - 15

In April 2005, the FASB issued FSP FAS 19-1. FSP FAS 19-1 amended SFAS 19, to allow continued capitalization of exploratory well costs beyond one year from the completion of drilling under circumstances where the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. FSP FAS 19-1 also amended SFAS 19 to require enhanced disclosures of suspended exploratory well costs in the notes to the consolidated financial statements. The Company adopted the new requirements during the second quarter of 2005. See Note 2 for additional information regarding the Company’s exploratory well costs. The adoption of FSP FAS 19-1 did not impact the Company’s consolidated financial position or results of operations.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143” (“FIN 47”). FIN 47 clarifies that conditional asset retirement obligations meet the definition of liabilities and should be recognized when incurred if their fair values can be reasonably estimated. The interpretation was adopted by the Company on December 31, 2005. The adoption of FIN 47 had no impact on the Company’s financial position or results of operations.

(4) Acquisitions

In February 2003, the Company purchased reserves in certain wells that it operates in Michigan for $3.8 million in cash. These properties were subject to a prior monetization transaction of the Section 29 tax credits which the Company entered into in 1996. The Company had the option to purchase these properties beginning in 2003. The Company previously held a production payment on these properties including a 75% reversionary interest in certain future production. The Company purchased those reserve volumes beyond its currently held production payment along with the 25% reversionary interest not owned. The estimated volumes acquired were 4.4 Bcf (billion cubic feet) of estimated proved developed producing gas reserves.

(5) Dispositions and Discontinued Operations

On June 25, 2004, the Company completed a sale of substantially all of its Trenton Black River (“TBR”) assets to Fortuna Energy Inc., a wholly owned subsidiary of Talisman Energy Inc. The assets sold included working interests in wells, natural gas gathering lines and oil and gas leases. The assets are located primarily in New York, Pennsylvania, Ohio and West Virginia. The TBR assets accounted for approximately 5 Bcfe (Billion cubic feet equivalent) of the Company’s estimated proved reserves as of December 31, 2003.

The sale resulted in proceeds of approximately $68.2 million. The proceeds were used to pay down the Company’s existing revolving credit facility. As a result of the disposition of the TBR geographical/geological pools, the Company recorded a gain of approximately $46.6 million ($29.8 million net of tax) in June 2004. According to SFAS 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the disposition of this group of wells is classified as discontinued operations.

In April 2004, the Company decided to dispose of its Arrow Oilfield Service Company (“Arrow”) assets. The Company sold the Michigan assets of Arrow in May 2004 and sold the Ohio and Pennsylvania assets of Arrow in June 2004. The two Arrow asset sales resulted in proceeds of approximately $4.2 million. As a result of the disposition of all of its Arrow assets, the Company recorded a loss of approximately $1.4 million ($864,000 net of tax) in the second quarter of 2004. According to SFAS 144, the disposition of the Arrow assets is classified as discontinued operations.

The Company allocates interest expense to operating areas based on the proportionate share of net assets of the area to the Company’s consolidated net assets. The amounts of interest expense allocated to income (loss) from discontinued operations for the years ended December 31, 2004 and 2003 was $907,000 and $2.0 million, respectively.

F - 16

Revenues and income (loss) from discontinued operations are as follows (in thousands):


	Predecessor II Company
	188 Day
	Period from
	January 1,			Year ended
	2004 to July 6,			December 31,
	2004			2003
Revenue from discontinued operations	$	7,294		$	13,698

(Loss) income from operations of discontinued businesses		(43	)		(16,368	)
(Benefit) provision for income taxes		(17	)		(5,731	)

		(26	)		(10,637	)

Income (loss) on sale of discontinued businesses		45,223			(69	)
Income tax provision (benefit)		16,329			(25	)

		28,894			(44	)

Income (loss) from discontinued operations, net of tax	$	28,868		$	(10,681	)

(6) Derivatives and Hedging

From time to time the Company may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage its exposure to natural gas or crude oil price volatility and support its capital expenditure plans. The Company’s derivative financial instruments take the form of swaps or collars. At December 31, 2005, the Company’s derivative contracts were comprised of natural gas swaps, crude oil swaps and an interest rate swap, which were placed with major financial institutions that the Company believes 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.

The Company uses New York Mercantile Exchange (“NYMEX”) based commodity derivative contracts to hedge natural gas, because the Company’s natural gas production is sold pursuant to NYMEX-based sales contracts. Beginning July 7, 2004, the Company has ineffectiveness on the natural gas swaps due to purchase accounting, which created non-zero value derivatives at the time of the Merger. The Company had collar agreements that could not be redesignated as cash flow hedges because these collars were not effective due to unrealized losses at the date of the Merger. These collars qualified and were designated as cash flow hedges from their inception through the Predecessor II Company period ended July 6, 2004. Although these collars were not deemed to be effective hedges in accordance with the provisions of SFAS 133, the Company retained these instruments as protection against changes in commodity prices and the Company continued to record the mark-to-market adjustments on these natural gas collars, through 2005, in the Company’s income statement. The Company’s NYMEX crude oil swaps were highly effective and were designated as cash flow hedges through August 16, 2005. The Company had ineffectiveness on the crude oil swaps because the oil is sold locally at a posted price which is different from the NYMEX price. At August 16, 2005, the Company’s 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

F - 17

the time of the Transaction. The changes in the fair values of the natural gas collars since July 7, 2004, the changes in fair value of the oil swaps subsequent to August 15, 2005, the ineffective portion of the crude oil swaps through August 15, 2005 and the ineffective portion of the natural gas swaps since July 7, 2004 are recorded as “Derivative fair value gain or loss.”

During 2005 and 2004, net losses of $34.0 million ($22.9 million after tax) and $20.8 million ($13.1 million after tax), respectively, were reclassified from accumulated other comprehensive income to earnings. The fair value of open hedges in accumulated other comprehensive income decreased $291.9 million ($196.6 million after tax) in 2005 and increased $74.0 million ($46.4 million after tax) in 2004. At December 31, 2005, the estimated net loss in accumulated other comprehensive income that is expected to be reclassified into earnings within the next 12 months is approximately $11.3 million. At December 31, 2005, the Company has partially hedged its exposure to the variability in future cash flows through December 2013.

The following table reflects the natural gas and crude oil volumes and the weighted average prices under financial hedges (including settled hedges) at December 31, 2005:


	Natural Gas Swaps
			NYMEX		Crude Oil Swaps
			Price per		Estimated		NYMEX
Quarter Ending	Bbtu		Mmbtu		Mbbls		Price per Bbl
March 31, 2006		2,829	$	6.14		63	$	32.71
June 30, 2006		2,829		5.24		62		32.35
September 30, 2006		2,829		5.22		62		32.02
December 31, 2006		2,829		5.39		62		31.71

		11,316	$	5.50		249	$	32.20


Year Ending
December 31, 2007	10,745	$	4.97	227	$	30.91
December 31, 2008	10,126		4.64	208		29.96
December 31, 2009	9,529		4.43	191		29.34
December 31, 2010	8,938		4.28	175		28.86
December 31, 2011	8,231		4.19	157		28.77
December 31, 2012	7,005		4.09	138		28.70
December 31, 2013	6,528		4.04	127		28.70


Bbl – Barrel			Mmbtu – Million British thermal units
Mbbls – Thousand barrels			Bbtu – Billion British thermal units

At December 31, 2005 the Company had an interest rate swap in place for $40 million that matures on September 16, 2008. The swap provides a 1-month LIBOR fixed rate at 4.287% plus the applicable margin.

F - 18

(8)

Long-Term Debt

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


	Successor		Predecessor I
	Company		Company
	December 31,
	2005		2004
Senior secured term facility	$	—	$	89,500
Senior secured notes		192,500		192,500
Bank revolving credit facility		52,000		—
Subordinated promissory note (related party)		25,000		—
Other		92		97

		269,592		282,097
Less current portion		7		1,005

Long-term debt		269,585		281,092
Fair value adjustment — senior secured notes		7,840		—

Senior Secured Notes due 2012

The Company has $192.5 million of its Senior Secured Notes (“Notes”) outstanding as of December 31, 2005. 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. Subsequent accretion of the premium reduced this amount to $200.3 million at December 31, 2005. The fair value adjustment of $7.8 million is shown separately in the table above. The accretion of $341,000 was recorded as a reduction of interest expense in 2005. 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 $192.5 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 the Company’s obligations under the Senior Facilities (defined herein after). The Notes are subject to redemption at the Company’s option at specific redemption prices.


July 15, 2008	104.375	%
July 15, 2009	102.188	%
July 15, 2010 and thereafter	100.000	%

The Notes are governed by an indenture (the “Indenture”), which contains certain covenants that limit the Company’s ability to incur additional indebtedness and issue stock, pay dividends, make distributions, make investments, make certain other restricted payments, enter into certain transactions with affiliates, dispose of certain assets, incur liens securing indebtedness of any kind other than permitted liens and engage in mergers and consolidations.

Amended Credit Agreement

On August 16, 2005, the Company amended and restated its existing $170 million Credit Agreement, dated as of July 7, 2004 and amended as of July 22, 2004, by and among the Company, as borrower, the various lenders named therein, Goldman Sachs Credit Partners, L.P., as sole lead arranger, sole book runner, syndication agent and administrative agent, and General Electric Capital Corporation and National City Bank, as co-documentation agents, 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

F - 20

Amended Credit Agreement provides for loans and other extensions of credit to be made to the Company up to a maximum aggregate principal amount of $390 million. The obligations under the Amended Credit Agreement are secured by substantially all of the assets of the Company. J.P. Morgan Chase and Amegy Bank were added to the bank group in September 2005.

The Amended Credit Agreement provides for a revolving credit line in the aggregate principal amount of $350 million and a hedge letter of credit facility in the aggregate principal amount of $40 million (collectively, the “Senior Facilities”). Borrowings under the Amended Credit Agreement may not exceed the borrowing base, which was initially set at $80.25 million, of which $57 million was drawn at closing on August 16, 2005. At December 31, 2005, the outstanding balance was $52 million.

The obligations under the Amended Credit Agreement are secured by a first lien security interest in substantially all of the assets of the Company. The obligations under the Amended Credit Agreement are further secured by a pledge of 100% of the capital stock of the Company held by Capital C, the Company’s parent. This agreement was amended on September 27, 2005 to reduce the percentage of the value of total proved reserves that is required to be mortgaged from 75% to 70%.

The Amended Credit Agreement contains covenants that will limit the ability of the Company to, among other things, incur or guarantee additional indebtedness; create liens; pay dividends on or repurchase stock of the Company or its subsidiaries; pay principal and interest on certain subordinated debt; make certain types of investments; sell assets or merge with another entity; pledge or otherwise encumber the capital stock of the Company or its subsidiaries; 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. As of December 31, 2005, the Company was in compliance with all financial covenants and requirements under the existing credit facilities.

Borrowings under the revolving credit line will be used by the Company 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 the Company’s obligations under the J. Aron Swap (defined hereinafter).

In connection with the Company’s entry into the Amended Credit Agreement, the Company executed a Subordinated Promissory Note (“Note”) in favor of Capital C in the maximum principal amount of $94 million. Under the Note, Capital C loaned $25 million to the Company on August 16, 2005. The Note accrues interest at a rate of 10% per annum and matures on August 16, 2012. The Company 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, the Company has the option to make interest payments on the Note by borrowing additional amounts against the Note. The interest payments in 2005 were paid in cash. The Note has no prepayment penalty or premium and may be prepaid in whole or in part at any time. The Note is expressly subordinate to the Company’s senior debt, which includes obligations under the Amended Credit Agreement, the J. Aron Swap and notes issued under the Company’s Indenture dated July 7, 2004 with BNY Midwest Trust Company, as indenture trustee (“Senior Secured Notes”).

F - 21

ISDA Master Agreement

The Company amended and restated the Schedule and Credit Support Annex to its International Swap Dealers Association (“ISDA”) Master Agreement, dated as of June 30, 2004, by and between the Company and J. Aron & Company (“J. Aron Swap”), pursuant to which the Company has 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, 2005, the aggregate long-term debt maturing in the next five years is as follows: $7,000 (2006); $7,000 (2007); $8,000 (2008); $8,000 (2009) and $269.6 million (2010 and thereafter). The Company's term loan facility requires mandatory prepayments annually based on the calculation of excess cash flow, as defined in the agreement.

(9)

Leases

The Company leases certain computer equipment, vehicles, natural gas compressors and office space under noncancelable agreements with lease periods of one to five years. Rent expense amounted to $1.3 million in the Successor Company 138 day period ended December 31, 2005, $2.1 million in the Predecessor I Company 227 day period ended August 15, 2005, $1.7 million for the Predecessor I Company 178 day period ended December 31, 2004, and $2.9 million and $2.4 million for the Predecessor II Company 188 day period ended July 6, 2004 and the year ended December 31, 2003, respectively.

The Company also leases certain computer equipment accounted for as capital leases. Property and equipment includes $273,000 of computer equipment under capital leases at December 31, 2005 and 2004. Accumulated depreciation for such equipment includes approximately $176,000 and $60,000 at December 31, 2005 and 2004, respectively.

Future minimum commitments under leasing arrangements as of December 31, 2005 were as follows:


	Operating		Capital
As of December 31, 2005	Leases		Leases
	(in thousands)
2006	$	3,354	$	70
2007		2,314		36
2008		507		2
2009		216		—
2010		70		—

Total minimum rental payments	$	6,461		108

Less amount representing interest				2

Present value of net minimum rental payments				106
Less current portion				77

Long-term capitalized lease obligations			$	29

(10)

Stock Option Plans

F - 22

(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):


	Successor
	Company		Predecessor I Company
	For the 138		For the 227			For the 178			Predecessor II Company
	Day Period		Day Period			Day Period			For the 188
	from August		from January			from July 7,			Day Period
	16, 2005 to		1, 2005 to			2004 to			from January			Year ended
	December 31,		August 15,			December 31,			1, 2004 to July			December 31,
	2005		2005			2004			6, 2004			2003
Current
Federal	$	—	$	—		$	(29	)	$	(379	)	$	—
State		—		—			(146	)		(791	)		—

		—		—			(175	)		(1,170	)		—
Deferred
Federal		9,470		(302	)		3,914			(4,173	)		3,111
State		925		(1,185	)		(2,085	)		519			99

		10,395		(1,487	)		1,829			(3,654	)		3,210

Total	$	10,395	$	(1,487	)	$	1,654		$	(4,824	)	$	3,210

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:


	Successor
	Company			Predecessor I Company
	For the 138			For the 227			For the 178			Predecessor II Company
	Day Period			Day Period			Day Period			For the 188
	from August			from January			from July 7,			Day Period
	16, 2005 to			1, 2005 to			2004 to			from January			Year ended
	December 31,			August 15,			December 31,			1, 2004 to July			December 31,
	2005			2005			2004			6, 2004			2003
Statutory federal income tax rate		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%
Increases (reductions) in taxes resulting from:
State income taxes, net of federal tax benefit		2.2			42.6			(16.3	)		0.7			0.7
Transaction related expenses								—			(15.4	)
Permanent differences		—			2.0			(0.1	)		—			—
Other, net		—			2.7			—			—			(0.7	)

Effective income tax rate for the period		37.2	%		82.3	%		18.6	%		20.3	%		35.0	%

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. On December 30, 2004, the Company merged its two subsidiaries, The Canton Oil & Gas Company and Ward Lake Drilling, Inc., into Belden & Blake Corporation. As a result of the mergers, the Company’s effective tax rate on deferred taxes changed. As a result, a $1.5 million state tax benefit was recorded in the 2004 Predecessor I Company period.

F - 24

On June 30, 2005 the State of Ohio enacted new tax legislation that will result in the elimination of the income and franchise tax over a four year period and it will be replaced with a gross receipts based tax. As a result of the new tax structure, the Company recorded a tax benefit of $1.1 million to adjust the recorded deferred tax account balances for Ohio during 2005.

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


	December 31,			December 31,
	2005			2004
Deferred income tax liabilities:
Property and equipment, net	$	207,238		$	157,539
Other, net		188			2,128

Total deferred income tax liabilities		207,426			159,667
Deferred income tax assets:
Accrued expenses		882			776
Asset retirement obligations		7,066			5,607
Fair value of derivatives		113,599			31,023
Net operating loss carryforwards		35,317			23,865
Senior Secured Notes		2,913			—
Tax credit carryforwards		1,250			1,412
Other, net		503			550
Valuation allowance		(12,842	)		(1,391	)

Total deferred income tax assets		148,688			61,842

Net deferred income tax liability	$	58,738		$	97,825


Long-term liability	$	84,490		$	108,994
Current asset		(25,752	)		(11,169	)

Net deferred income tax liability	$	58,738		$	97,825

At December 31, 2005, the Company had approximately $61 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. The Company also had state net operating losses aggregating $273 million, which expire between 2007 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. The Company does not believe the application of Section 382 hinders its ability to utilize the federal net operating losses and, accordingly, no valuation allowance has been recorded. The valuation allowance of $12.8 million relates to certain state net operating loss carryforwards which the Company estimates would expire before they could be used. The Company has alternative minimum tax credit carryforwards of approximately $1.3 million, which have no expiration date. The Company has approximately $1.6 million of statutory depletion carryforwards, which have no expiration date.

(12)

Profit Sharing and Retirement Plans

The Company has a non-qualified profit sharing arrangement under which the Company contributes discretionary amounts determined by the compensation committee of the Company’s Board of Directors based on attainment of performance targets. Amounts are allocated to substantially all employees based on relative compensation. The Company expensed $417,000 for the Successor Company 138 day period ended December 31, 2005, $96,000 for the Predecessor I Company 227 day period ended August 15, 2005, $428,000 for the Predecessor I Company 178 day period ended December 31, 2004, and $544,000 and $1.3 million for the Predecessor II Company 188 day period ended

F - 25

July 6, 2004 and the year ended December 31, 2003, respectively, for contributions to the profit sharing plan and discretionary bonuses. All amounts were paid in cash.

As of December 31, 2005, the Company has a qualified defined contribution plan (a 401(k) plan) covering substantially all of the employees of the Company. Eligible employees may make voluntary contributions which the Company matches $1.00 for every $1.00 contributed up to 4% of an employee’s annual compensation and a $0.50 match for every $1.00 contributed up to the next 2% of compensation. Retirement plan expense amounted to $83,000 for the Successor Company 138 day period ended December 31, 2005, $255,000 for the Predecessor I Company 227 day period ended August 15, 2005, $121,000 for the Predecessor I Company 178 day period ended December 31, 2004, and $237,000 and $433,000 for the Predecessor II Company 188 day period ended July 6, 2004 and the year ended December 31, 2003, respectively.

(13)

Commitments and Contingencies

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

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 its financial position, results of operations or cash flows.

Environmental costs, if any, are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed as incurred. Expenditures that extend the life of the related property or reduce or prevent future environmental contamination are capitalized. Liabilities related to environmental matters are only recorded when an environmental assessment and/or remediation obligation is probable and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash payments for the liability are fixed or reliably determinable. At December 31, 2005, no significant environmental remediation obligation exists which is expected to have a material effect on the Company’s financial position, results of operations or cash flows.

F - 26

(14) Supplemental Disclosure of Cash Flow Information


	Successor
	Company			Predecessor I Company					Predecessor II Company
	138 Day			227 Day
	Period from			Period from		178 Day			188 Day
	August 16,			January 1,		Period from			Period from
	2005 to			2005 to		July 7, 2004			January 1,		Year ended
	December			August 15,		to December			2004 to July		December
	31, 2005			2005		31, 2004			6, 2004		31, 2003
(in thousands)
Cash paid during the period for:
Interest	$	2,433		$	21,885	$	4,508		$	12,686	$	25,427
Income taxes, net of refunds		(163	)		500		(25	)		—		172
Non-cash investing and financing activities:
Acquisition of assets in exchange for long-term liabilities		—			—		137			—		136
Cumulative effect of change in accounting principle, net of tax		—			—		—			—		2,397

(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 $192.5 million (face amount) of the Company’s Senior Secured Notes due 2012 had an approximate fair value of $196.4 million at December 31, 2005 based on quoted market prices.

From time to time the Company 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. The Company employs a policy of hedging gas production sold under NYMEX-based contracts by selling NYMEX-based commodity derivative contracts. The Company’s 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 the Company believes are minimal credit risks. At December 31, 2005, the Company’s derivative contracts consisted of natural gas swaps, crude oil swaps and interest rate swaps. Qualifying derivative contracts are designated as cash flow hedges. The Company incurred pre-tax losses on its oil and gas hedging activities of $9.1 million, $10.9 million, and $10.3 million in 2005, 2004 and 2003, respectively . The Company incurred pre-tax losses on its interest rate derivatives of $32,000 in 2005. At December 31, 2005, the fair value of futures contracts covering 2006 through 2013 oil and gas production represented an unrealized loss of $305.3 million. At December 31, 2005, the fair value of the Company’s interest rate contract covering 2006 through September 2008 represented an unrealized gain of $459,000.

(16)

Related Party Transactions

On August 16, 2005, the former partners of Capital C completed the sale of all of the partnership interests in Capital C to certain institutional funds managed by EnerVest Management Partners, Ltd. (“EnerVest”). EnerVest incurred and was reimbursed by the Company $1.1 million for transaction costs. This amount was recorded as an accrued expense at December 31, 2005 and was paid in January 2006.

On March 15, 2006, the Company 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 the Company of $642,000 in 2005. This amount was recorded as an accrued expense at December 31, 2005.

As of December 31, 2005, the Company owed EnerVest $1.1 million and EnerVest Operating $642,000.

In connection with the Transaction, the Company executed a subordinated promissory note in favor of the Company’s parent, Capital C in the maximum amount of $94 million. Under the note, Capital C loaned $25 million to the Company on August 16, 2005. The note accrues interest at 10% per year and matures on August 16, 2012. The Company 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, the Company has 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, 2005 was $25 million. Interest payments of $945,000 were made in 2005 and were paid in cash.

Messrs. Houser, Vanderhider and Mariani are officers and directors of the Company and they are officers and equity owners of EnerVest and EnerVest Operating. Mr. Walker is a director of the Company and an officer and equity owner of EnerVest and EnerVest Operating. The institutional funds that are managed by EnerVest and own the Company’s direct parent, Capital C, also hold other investments in oil and gas assets and operations. The Company can give no assurance that conflicts of interest will not arise for corporate opportunities. Also, the Company can give no assurance that conflicts will not arise with respect to the time and attention devoted to the Company by Messrs. Houser, Vanderhider, Mariani and Walker.

From July 7, 2004 through August 15, 2005, Carlyle/Riverstone controlled and had a majority interest in Capital C, the Company’s sole shareholder. Capital C received a fee from the Company in 2004 of approximately $1.4 million in connection with the Merger. The Company also reimbursed Capital C $61,323 in 2004 for costs they incurred related to the Merger. The Company paid Carlyle/Riverstone $492,277 for costs they incurred in 2004 on the Company’s behalf, of which $471,790 was third party legal fees related to the Merger. The Company reimbursed Carlyle/Riverstone $91,490 for expenses in 2005.

The Company was a party to a management services agreement with Capital C beginning on July 7, 2004, pursuant to which Frost W. Cochran, W. Mac Jensen and B. Dee Davis provided certain management and advisory services to the Company for a quarterly fee of $250,000 plus reimbursement of expenses. These services included general management supervision and oversight, in the capacity as officers of Belden & Blake; financial advisory services; evaluation of potential acquisitions and other business opportunities; and strategic consulting services. This agreement was terminated effective December 20, 2004. The total amount paid in 2004 pursuant to this agreement was approximately $526,136.

The Company reimbursed Legend Natural Gas, LP (“Legend”) for expenses incurred in connection with services provided on the Company’s behalf. In 2004, the Company paid Legend approximately $208,000 for salary and bonus for James A. Winne III and Michael Becci, and approximately $38,000 for reimbursement of other Legend expenses related to the Company’s activities. In 2005, the Company paid Legend approximately $85,000 for reimbursement of other Legend expenses related to the Company’s activities. During 2005, the Company paid Messrs. Winne and Becci directly, as employees of the Company, rather than reimbursing Legend.

F - 27

(18)

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.


	Successor
	Company		Predecessor I Company				Predecessor II Company
	138 Day		227 Day
	Period from		Period from		178 Day		188 Day
	August 15,		January 1,		Period from		Period from
	2005 to		2005 to		July 7, 2004 to		January 1,
	December 31,		August 15,		December 31,		2004 to July 6,		December 31,
	2005		2005		2004		2004		2003
(in thousands)
Acquisition costs:
Proved properties	$	33	$	16	$	106	$	—	$	3,923
Unproved properties		118		317		229		286		1,430
Developmental costs		7,893		18,558		11,357		9,688		16,440
Exploratory costs		1,229		2,424		2,750		2,717		6,849
Estimated asset retirement obligations incurred		174		142		101		9		268

Estimated Proved Oil and Gas Reserves (Unaudited)

The Company’s estimated proved developed and estimated proved undeveloped reserves are all located within the United States. The Company cautions 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, 2005, 2004 and 2003 have been prepared by Wright & Company, Inc., independent petroleum consultants. The estimated proved reserve information for the 2004 Predecessor II Company 188 day period ended July 6, 2004 and the 2005 Predecessor I Company 227 day period ended August 15, 2005, is based on the Company’s internal engineering estimates.

F - 29

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


	Successor Company						Predecessor I Company						Predecessor II Company						Total
	Oil			Gas			Oil			Gas			Oil			Gas			Oil			Gas
	(Mbbl)⁽¹⁾			(Mmcf) ⁽²⁾			(Mbbl)⁽¹⁾			(Mmcf) ⁽²⁾			(Mbbl)⁽¹⁾			(Mmcf) ⁽²⁾			(Mbbl)⁽¹⁾			(Mmcf) ⁽²⁾			Mmcfe ⁽³⁾
December 31, 2002														6,574			335,518			6,574			335,518			374,962
Extensions and discoveries														—			1,437			—			1,437			1,437
Purchase of reserves in place														—			8,988			—			8,988			8,988
Sale of reserves in place														(1	)		(41	)		(1	)		(41	)		(47	)
Revisions of previous estimates														16			(12,976	)		16			(12,976	)		(12,880	)
Production														(413	)		(14,837	)		(413	)		(14,837	)		(17,315	)

December 31, 2003		—			—			—			—			6,176			318,089			6,176			318,089			355,145
Extensions and discoveries								51			1,005			—			1,245			51			2,250			2,556
Purchase of reserves in place								—			1,319			—			—			—			1,319			1,319
Capital C merger								6,117			320,637			(6,117	)		(320,637	)
Revisions of previous estimates								(397	)		(64,065	)		130			9,000			(267	)		(55,065	)		(56,667	)
Production								(192	)		(7,570	)		(189	)		(7,697	)		(381	)		(15,267	)		(17,553	)

December 31, 2004		—			—			5,579			251,326			—			—			5,579			251,326			284,800
Extensions and discoveries		32			2,037			3			3,532									35			5,569			5,779
Purchase of reserves in place		—			1,586			—			690									—			2,276			2,276
EnerVest transaction		5,552			249,335			(5,552	)		(249,335	)								—			—			—
Revisions of previous estimates		(232	)		(794	)		186			2,863									(46	)		2,069			1,793
Production		(142	)		(5,484	)		(216	)		(9,076	)								(358	)		(14,560	)		(16,710	)

December 31, 2005		5,210			246,680			—			—			—			—			5,211			246,680			277,938


Proved developed reserves
December 31, 2003														3,809			207,842			3,809			207,842			230,696

December 31, 2004								3,448			200,231									3,448			200,231			220,919

December 31, 2005		3,822			203,443															3,822			203,443			226,375


⁽¹⁾		Thousand barrels

⁽²⁾		Million cubic feet

⁽³⁾		Million cubic feet equivalent, barrels are converted to Mcfe based on one barrel of oil to six Mcf of natural gas equivalent.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)

The following tables, which present a standardized measure of discounted future net cash flows and changes therein relating to estimated proved oil and gas reserves, are presented pursuant to SFAS No. 69. In computing this data, assumptions other than those required by the FASB could produce different results. Accordingly, the data should not be construed as representative of the fair market value of the Company’s 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.

F - 30

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


				Predecessor
	Successor			I Company			Predecessor
	Company			December 31,			II Company
	2005			2004			2003
				(in thousands)
Estimated future cash inflows (outflows)
Revenues from the sale of oil and gas	$	2,726,170		$	1,854,119		$	2,152,092
Production costs		(639,366	)		(534,781	)		(470,604	)
Development costs		(128,933	)		(126,750	)		(168,301	)

Future net cash flows before income taxes		1,957,871			1,192,588			1,513,187
Future income taxes		(651,594	)		(397,606	)		(505,243	)

Future net cash flows		1,306,277			794,982			1,007,944
10% timing discount		(760,513	)		(449,270	)		(608,767	)

Standardized measure of discounted future net cash flows	$	545,764		$	345,712		$	399,177

At December 31, 2005, 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 weighted average prices for the total estimated proved reserves at December 31, 2005 were $9.83 per Mcf (thousand cubic feet) of natural gas and $57.64 per barrel of oil. The Company does not include its natural gas and crude oil hedging financial instruments, consisting of swaps and collars, in the determination of its oil and gas reserves.

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


	Successor
	Company			Predecessor I Company						Predecessor II Company
	138 Day Period			227 Day Period			178 Day			188 Day
	From August 16,			From January			Period from			Period from
	2005 to			1, 2005 to			July 7, 2004 to			January 1,			Year ended
	December 31,			August 15,			December 31,			2004 to July 6,			December
	2005			2005			2004			2004			31, 2003
Beginning of year	$	575,512		$	345,712		$	372,686		$	399,177		$	332,819
Sale of oil and gas, net of production costs		(60,103	)		(56,391	)		(33,710	)		(34,019	)		(63,672	)
Extensions and discoveries, less related estimated future development and production costs		6,422			11,608			2,671			1,311			1,867
Previously estimated development costs incurred during the period		8,503			16,667			9,634			6,237			25,095
Purchase of reserves in place less estimated future production costs		3,014			1,504			1,927			—			10,193
Sale of reserves in place less estimated future production costs		—			—			—			—			(60	)
Changes in estimated future development costs		(13,903	)		(13,356	)		38,637			(9,666	)		(26,714	)
Revisions of previous quantity estimates		(6,964	)		13,150			(131,431	)		17,391			(23,353	)
Net changes in prices and production costs		(28,924	)		367,871			(5,961	)		(11,867	)		127,759
Change in income taxes		20,419			(142,102	)		32,981			(21,141	)		(29,072	)
Accretion of 10% timing discount		33,060			31,857			28,483			28,751			47,959
Changes in production rates (timing) and other		8,728			(1,008	)		29,795			(3,488	)		(3,644	)

End of period	$	545,764		$	575,512		$	345,712		$	372,686		$	399,177

F - 31


			Percentage of
Five Percent Shareholders	Number of Shares		Shares
Capital C Energy Operations, LP ⁽¹⁾
First City Tower, 1001 Fanin Street, Suite 800
Houston, Texas 77002		1,534		100.0	%


No.		Description

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.

99.1*		Belden and Blake Corporation Audit Committee Charter as Amended and Approved by the Audit Committee and Board of Directors on March 27, 2006.


/s/ Mark A. Houser Mark A. Houser	Chief Executive Officer Chairman of the Board of Directors and Director (Principal Executive Officer)	April 5, 2006 Date

/s/ James M. Vanderhider James M. Vanderhider	President, Chief Financial Officer and Director (Principal Financial Officer)	April 5, 2006 Date

/s/ Frederick J. Stair Frederick J. Stair	Vice President and Corporate Controller (Principal Accounting Officer)	April 5, 2006 Date

/s/ Kenneth Mariani Kenneth Mariani	Senior Vice President, Chief Operating Officer and Director	April 5, 2006 Date

/s/ Matthew Coeny Matthew Coeny	Director	April 5, 2006 Date

/s/ John B. Walker John B. Walker	Director	April 5, 2006 Date

	•		Revised our accounting procedures for derivative accounting by correcting how we calculate our journal entries related to derivative instruments and hedge accounting.

	•		Implemented a reconciliation calculation for our hedges to help ensure proper financial statement recognition of hedge accounts.

	•		Engaged a consulting firm to assist us in reviewing our approach to derivative instruments and hedge accounting.


⁽¹⁾		EnerVest Management Partners, Ltd., controls Capital C Energy Operations, L.P. and is therefore also deemed to be a beneficial owner of the 1,534 shares (100%) of our Common Stock. The address of EnerVest Management Partners, Ltd., is First City Tower, 1001 Fannin Street, Suite 800, Houston, Texas 77002.


				Weighted
				Average
	Number of			Exercise
	Shares			Price
Balance at January 1, 2003		684,456		$	1.09
Granted		77,500			2.14
Forfeitures		(781	)		0.30
Exercised or put		(144,854	)		0.83

Balance at December 31, 2003		616,321			1.29
Granted		17,500			3.97
Forfeitures		(7,500	)		2.14
Exercised or put		(137,478	)		0.84
Surrendered at Merger		(488,843	)		1.49

Balance at December 31, 2004		—
Granted		—
Forfeitures		—
Exercised or put		—

Balance at December 31, 2005		—

Options exercisable at December 31, 2005		—


	Predecessor I Company								Successor Company
									For the 46
						For the 46			Day Period
						Day Period			From
						From July 1,			August 16,
						2005 to			2005 to
						August 15,			September
	First			Second		2005			30, 2005		Fourth
2005
Operating revenues	$	30,364		$	30,576	$	16,900		$	22,581	$	53,924
Gross profit		12,793			12,426		7,850			12,384		30,857
Net (loss) income		(636	)		5,975		(5,658	)		660		16,903


							Predecessor I Company
	Predecessor II Company						For the 86
				For the 97			Day Period
				Day Period			from July 7,
				from April			2004 to
				1, 2004 to			September
	First			July 6, 2004			30, 2004		Fourth
2004
Operating revenues	$	24,945		$	25,419		$	27,794	$	33,911
Gross profit		10,682			10,977			9,606		14,147
Income (loss) from continuing operations		2,366			(21,235	)		380		6,883
(Loss) income from discontinued operations, net of tax		(314	)		29,182			—		—
Net income		2,052			7,947			380		6,883