UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

þ Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the quarterly period ended June 30, 2005

or

o Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from ________________________ to _______________________

Commission File Number:          0-20100

BELDEN & BLAKE CORPORATION

(Exact name of registrant as specified in its charter)

Ohio	34-1686642
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
5200 Stoneham Road
North Canton, Ohio	44720
(Address of principal executive offices)	(Zip Code)

(330) 499-1660

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report.)

     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. þ Yes o No

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

As of July 31, 2005, Belden & Blake Corporation had outstanding 1,500 shares of common stock,
without par value, which is its only class of stock.

BELDEN & BLAKE CORPORATION

INDEX

	Page
PART I Financial Information
Item 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2005 and December 31, 2004		1
Consolidated Statements of Operations: Three and six months ended June 30, 2005 (Successor Company) Three and six months ended June 30, 2004 (Predecessor Company)		2
Consolidated Statements of Shareholders’ Equity (Deficit): Six months ended June 30, 2005 (Successor Company) 178 day period from July 7, 2004 to December 31, 2004 (Successor Company) 188 day period From January 1, 2004 to July 6, 2004 (Predecessor Company) and the year ended December 31, 2003 (Predecessor Company)		3
Consolidated Statements of Cash Flows: Six months ended June 30, 2005 (Successor Company) Six months ended June 30, 2004 (Predecessor Company)		4
Notes to Consolidated Financial Statements		5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		8
Item 3. Quantitative and Qualitative Disclosures About Market Risk		17
Item 4. Controls and Procedures		19
PART II Other Information
Item 1. Legal Proceedings		19
Item 4. Submission of Matters to a Vote of Security Holders		19
Item 6. Exhibits		20
EX-3.1 Amended and Restated Articles of Incorporation
EX-3.2 Amended and Restated Code of Regulations
EX-31.1 Certification
EX-31.2 Certification
EX-32.1 Certification
EX-32.2 Certification

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

	June 30,			December 31,
	2005			2004
	(unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	20,773		$	18,407
Accounts receivable, net		15,477			18,667
Inventories		616			518
Deferred income taxes		14,839			10,558
Other current assets		1,356			1,101
Total current assets		53,061			49,251
Property and equipment, at cost
Oil and gas properties (successful efforts method)		528,110			514,242
Gas gathering systems		5,104			4,485
Land, buildings, machinery and equipment		7,902			7,720
		541,116			526,447
Less accumulated depreciation, depletion and amortization		33,135			16,917
Property and equipment, net		507,981			509,530
Other assets		10,692			11,461
	$	571,734		$	570,242
LIABILITIES AND SHAREHOLDER’S (DEFICIT) EQUITY
Current liabilities
Accounts payable	$	4,208		$	3,796
Accrued expenses		22,325			23,445
Current portion of long-term liabilities		1,945			1,964
Fair value of derivatives		36,633			23,252
Total current liabilities		65,111			52,457
Long-term liabilities
Bank and other long-term debt		88,088			88,592
Senior secured notes		192,500			192,500
Asset retirement obligations and other long-term liabilities		15,000			14,390
		295,588			295,482
Fair value of derivatives		172,803			55,182
Deferred income taxes		62,682			108,994
Shareholder’s (deficit) equity
Common stock without par value; 1,500 shares authorized and issued		—			—
Paid in capital		77,500			77,500
(Deficit) retained earnings		(805	)		890
Accumulated other comprehensive loss		(101,145	)		(20,263	)
Total shareholder’s (deficit) equity		(24,450	)		58,127
	$	571,734		$	570,242

See accompanying notes.

1

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

	Successor			Predecessor		Successor			Predecessor
	Company			Company		Company			Company
	Three months ended June 30,					Six months ended June 30,
	2005			2004		2005			2004
Revenues
Oil and gas sales	$	24,369		$	22,945	$	47,430		$	45,307
Gas gathering and marketing		2,577			2,474		5,020			5,057
Other		110			329		217			458
		27,056			25,748		52,667			50,822
Expenses
Production expense		5,336			5,545		10,756			10,951
Production taxes		761			648		1,495			1,300
Gas gathering and marketing		2,313			2,300		4,419			4,533
Exploration expense		983			1,369		1,935			2,717
General and administrative expense		1,453			1,265		3,217			2,500
Franchise, property and other taxes		45			45		99			115
Depreciation, depletion and amortization		8,712			4,535		17,017			9,089
Accretion expense		327			100		582			195
Derivative fair value (gain) loss		(2,105	)		11		6,095			(321	)
		17,825			15,818		45,615			31,079
Operating income		9,231			9,930		7,052			19,743
Other expense
Interest expense		5,945			6,112		11,775			12,184
Income (loss) from continuing operations before income taxes		3,286			3,818		(4,723	)		7,559
Provision (benefit) for income taxes		77			1,240		(3,028	)		2,615
Income (loss) from continuing operations		3,209			2,578		(1,695	)		4,944
Income from discontinued operations, net of tax		—			28,941		—			28,627
Net income (loss)	$	3,209		$	31,519	$	(1,695	)	$	33,571

See accompanying notes.

2

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

																	Accumulated
	Successor Company				Predecessor Company												Other			Total
	Common		Common		Common			Common			Paid in			Equity			Comprehensive			Equity
	Shares		Stock		Shares			Stock			Capital			(Deficit)			Income			(Deficit)
Predecessor Company:
January 1, 2003						10,296		$	1,030		$	107,118		$	(148,332	)	$	(4,461	)	$	(44,645	)
Comprehensive (loss) income:
Net loss															(2,324	)					(2,324	)
Other comprehensive income (loss), net of tax:
Change in derivative fair value																		(17,439	)		(17,439	)
Reclassification adjustment for derivative (gain) loss reclassified into oil and gas sales																		6,543			6,543
Total comprehensive loss																					(13,220	)
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	)		(15,357	)		(57,340	)
Comprehensive income (loss):
Net income															9,999						9,999
Other comprehensive income (loss), net of tax:
Change in derivative fair value																		(11,180	)		(11,180	)
Reclassification adjustment for derivative (gain) loss reclassified into oil and gas sales																		5,512			5,512
Total comprehensive income																					4,331
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			21,025			51,997
July 6, 2004		—		—		—			—			—			—			—			-
Successor Company:
Sale of common stock		2										77,500									77,500
Comprehensive income (loss):
Net income															890						890
Other comprehensive income (loss), net of tax:
Change in derivative fair value																		(28,919	)		(28,919	)
Reclassification adjustment for derivative (gain) loss
reclassified into oil and gas sales																		8,656			8,656
Total comprehensive loss																					(19,373	)
December 31, 2004		2		—		—			—			77,500			890			(20,263	)		58,127
Comprehensive income (loss):
Net loss															(1,695	)					(1,695	)
Other comprehensive income (loss), net of tax:
Change in derivative fair value																		(89,430	)		(89,430	)
Reclassification adjustment for derivative (gain) loss reclassified into oil and gas sales																		8,548			8,548
Total comprehensive loss																					(82,577	)
June 30, 2005 (unaudited)		2	$	—		—		$	—		$	77,500		$	(805	)	$	(101,145	)	$	(24,450	)

See accompanying notes.

3

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

	Successor			Predecessor
	Company			Company
	Six months ended June 30,
	2005			2004
Cash flows from operating activities:
Net (loss) income	$	(1,695	)	$	33,571
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization		17,017			9,723
Accretion		582			221
Gain on sale of businesses		—			(44,998	)
Loss on disposal of property and equipment		51			375
Amortization of derivatives and other noncash hedging activities		2,555			(549	)
Exploration expense		1,935			4,128
Deferred income taxes		(3,028	)		15,410
Stock-based compensation		—			1,097
Change in operating assets and liabilities, net of effects of acquisition and disposition of businesses:
Accounts receivable and other operating assets		2,935			(4,599	)
Inventories		(58	)		79
Accounts payable and accrued expenses		(617	)		1,464
Net cash provided by operating activities		19,677			15,922
Cash flows from investing activities:
Disposition of businesses, net of cash		—			72,682
Proceeds from property and equipment disposals		—			247
Exploration expense		(1,935	)		(4,128	)
Additions to property and equipment		(14,788	)		(18,039	)
Decrease (increase) in other assets		(29	)		1,218
Net cash (used in) provided by investing activities		(16,752	)		51,980
Cash flows from financing activities:
Proceeds from revolving line of credit		—			140,679
Repayment of long-term debt and other obligations		(59	)		(164,335	)
Repayment of senior secured facility — term loan		(500	)		—
Debt issue costs		—			131
Proceeds from stock options exercised		—			111
Repurchase of stock options		—			(283	)
Purchase of treasury stock		—			(29	)
Net cash used in financing activities		(559	)		(23,726	)
Net increase in cash and cash equivalents		2,366			44,176
Cash and cash equivalents at beginning of period		18,407			1,440
Cash and cash equivalents at end of period	$	20,773		$	45,616

See accompanying notes.

4

BELDEN & BLAKE CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

June 30, 2005

(1) Basis of Presentation

     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 (“Successor Company”) and its predecessor. On July 7, 2004, the Company, Capital C Energy Operations, LP, a Delaware limited partnership (“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 is controlled by Carlyle/Riverstone Global Energy and Power Fund II, L.P.

     The Merger was accounted for as a purchase effective July 7, 2004. The Merger resulted in a new basis of accounting reflecting estimated fair values for assets and liabilities at that date. Accordingly, the financial statements for the period subsequent to July 6, 2004 are presented on the Company’s new basis of accounting, while the results of operations for prior periods reflect the historical results of the predecessor company. A vertical black line is presented to separate the financial statements of the predecessor and successor companies.

     In the second quarter of 2004, we sold substantially all of our Trenton Black River (“TBR”) assets and our Arrow Oilfield Service Company (“Arrow”) assets. According to Statement of Financial Accounting Standards No. (SFAS) 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” the dispositions were classified as discontinued operations. Discontinued operations relating to the TBR and Arrow asset sales resulted in a gain of $45.0 million ($28.6 million net of tax) in the first six months of 2004.

     The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the successor company for the six-month period ended June 30, 2005 are not necessarily indicative of the results that may be expected for the year ended December 31, 2005. For further information, refer to the consolidated financial statements and footnotes included in Amendment No. 1 to our Annual Report on Form 10-K for the year ended December 31, 2004, as amended. Certain reclassifications have been made to conform to the current presentation.

(2) Derivatives and Hedging

     Our financial results and cash flows can be significantly impacted as commodity prices fluctuate widely in response to changing market conditions. As a result of the adoption of SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” we recognize all derivative financial instruments as either assets or liabilities at fair value. Derivative instruments that are not hedges must be adjusted to fair value through net income (loss). Under the provisions of SFAS 133, changes in the fair value of derivative instruments that are fair value hedges are offset against changes in the fair value of the hedged

5

assets, liabilities, or firm commitments, through net income (loss). Changes in the fair value of derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time as the hedged items are recognized in net income (loss). 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 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 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. Ongoing assessments of hedge effectiveness will include verifying and documenting that the critical terms of the hedge and forecasted transaction do not change. We measure effectiveness at least on a quarterly basis.

     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 primarily take the form of swaps or collars. At June 30, 2005, our derivative contracts were comprised of natural gas swaps and collars and crude oil swaps, which were placed with a major financial institution that we believe is a minimal credit risk. Qualifying derivative financial instruments are designated as cash flow hedges. 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 (gain) loss.

     We consider our natural gas swaps to be highly effective and expect there will be no ineffectiveness to be recognized in net income (loss) since the critical terms of the hedging instruments and the hedged forecasted transactions are the same. We have not experienced ineffectiveness on our natural gas swaps because we use New York Mercantile Exchange (“NYMEX”) based commodity derivative contracts to hedge on the same basis as our natural gas production is sold (NYMEX-based sales contracts). We have collar agreements that could not be redesignated as cash flow hedges because these collars were not effective due to unrealized losses at the date of the Merger. These collars qualified and were designated as cash flow hedges from their inception through the predecessor company period ended July 6, 2004. Although these collars are not deemed to be effective hedges in accordance with the provisions of SFAS 133, we have retained these instruments as protection against changes in commodity prices and we will continue to record the mark-to-market adjustments on these natural gas collars, through 2005, in our income statement. Our NYMEX crude oil swaps are highly effective and were designated as cash flow hedges. We have ineffectiveness on the crude oil swaps because the oil is sold locally at a posted price which is different from the NYMEX price. Historically there has been a high correlation between the posted price and NYMEX. The changes in the fair values of the natural gas collars and the ineffective portion of the crude oil swaps are recorded as “Derivative fair value (gain) loss.”

     During the first six months of 2005 and 2004, net losses of $13.6 million ($8.5 million after tax) and $8.7 million ($5.5 million after tax), respectively, were reclassified from accumulated other comprehensive income to earnings. The fair value of open hedges decreased $142.0 million ($88.4 million after tax) in the first six months of 2005 and decreased $17.6 million ($11.2 million after tax) in the first six months of 2004. At June 30, 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 $23.0 million. At June 30, 2005, we have partially hedged our exposure to the variability in future cash flows through December 2013.

6

     The following table reflects the natural gas and crude oil volumes and the weighted average prices under financial hedges (including settled hedges) at June 30, 2005:

	Natural Gas Swaps				Natural Gas Collars				Crude Oil Swaps
			NYMEX				NYMEX Price
			Price per				per Mmbtu		Estimated		NYMEX
Quarter Ending	Bbtu		Mmbtu		Bbtu		Floor/Cap (1)		Mbbls		Price per Bbl
September 30, 2005		1,500	$	3.70		1,500	$	4.00-5.32		67	$	33.72
December 31, 2005		1,500		3.70		1,500		4.00 - 5.32		67		33.31
		3,000	$	3.70		3,000	$	4.00-5.32		134	$	33.52
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

⁽¹⁾ The NYMEX price per Mmbtu floor/cap for the natural gas collars in 2005 assume the monthly NYMEX settles at $3.10 per Mmbtu or higher. If the monthly NYMEX settles at less than $3.10 per Mmbtu then the NYMEX price per Mmbtu will be the NYMEX settle plus $0.90.

(3) Based Compensation

     We measure expense associated with stock-based compensation under the provisions of Accounting Principles Board Opinion No. (APB) 25, “Accounting for Stock Issued to Employees” and its related interpretations. Under APB 25, no compensation expense is required to be recognized upon the issuance of stock options to key employees as the exercise price of the option is equal to the market price of the underlying common stock at the date of grant.

     For purposes of the pro forma disclosures required by SFAS 123, “Accounting for Stock Based Compensation,” 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 we had applied the fair value provisions of SFAS 123 for the predecessor company for the three-month ended March 31, 2004 were not material. The successor company does not have any stock options.

     The changes in share value and the vesting of shares are reported as adjustments to compensation expense. The vesting of shares in the predecessor company quarter ended June 30, 2004, resulted in a non-cash increase in compensation expense of $1.1 million. The successor company does not have any stock-based compensation.

7

(4) Industry Segment Financial Information

     We operate in one reportable segment, as an independent energy company engaged in producing oil and natural gas; exploring for and developing oil and gas reserves; acquiring and enhancing the economic performance of producing oil and gas properties; and marketing and gathering natural gas for delivery to intrastate and interstate gas transmission pipelines. Our operations are conducted entirely in the United States.

(5) Supplemental Disclosure of Cash Flow Information

	Six months ended June 30,
(in thousands)	2005		2004
Cash paid during the period for:
Interest	$	12,153	$	12,158
Income taxes		500		—

(6) Contingencies

     In April 2002, we were notified of a claim by an overriding royalty owner in Michigan alleging the underpayment of royalties 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 the successor in interest to these royalty interests, alleging substantially the same underpayments. In April 2005, we entered into a settlement agreement that provided for a payment to the royalty owner of an amount approximately equal to the amount accrued at March 31, 2005 and an increase in the future overriding royalty percentage in several wells. The result had no material adverse effect on our financial position, results of operations or cash flows.

(7) Subsequent Events

     On July 5, 2005, Belden & Blake announced that the partners of its direct parent company, Capital C, have entered into an agreement to sell all of the partnership interests in Capital C to affiliates of EnerVest Management Partners, Ltd., a privately held oil and gas operator and institutional funds manager (“EnerVest”), which would result in Belden & Blake becoming indirectly wholly owned by affiliates of EnerVest.

     On July 18, 2005, Belden & Blake commenced a tender offer (“Tender Offer”) and consent solicitation (“Consent Solicitation”), previously announced, to purchase for cash any and all of its outstanding $192,500,000 aggregate principal amount of 8.75% Senior Secured Notes due 2012 (the “Securities”). The Tender Offer and Consent Solicitation is being conducted in conjunction with the acquisition of the parent company of Belden & Blake by EnerVest. The Tender Offer is conditioned on the closing of the proposed sale, which is expected to occur on August 16, 2005. The Tender Offer expires on August 15, 2005.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Forward-Looking Information

     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,

8

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 in our Annual Report on Form 10-K for the year ended December 31, 2004, as amended, 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.

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” in our Annual Report on Form 10-K for the year ended December 31, 2004, as amended, filed with the SEC 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

9

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.

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

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

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

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

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

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

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Derivatives and Hedging

     Our financial results and cash flows can be significantly impacted as commodity prices fluctuate widely in response to changing market conditions. Under the provisions of SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, we recognize all derivative financial instruments as either assets or liabilities at fair value. The changes in fair value of derivative instruments not qualifying for designation as cash flow hedges are reported in expense in the consolidated statements of operations as derivative fair value (gain) loss. Changes in the fair value of derivative instruments that are fair value hedges are offset against changes in the fair value of the hedged assets, liabilities, or firm commitments, through net income (loss). Changes in the fair value of derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time as the hedged items are recognized in net income (loss).

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

     From time to time we may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage our exposure to natural gas or oil price volatility and support our capital expenditure plans. Our derivative financial instruments primarily take the form of swaps or collars. At June 30, 2005, our derivative contracts were comprised of natural gas swaps and collars and crude oil swaps, which were placed with a major financial institution that we believe is a minimal credit risk. Qualifying derivative financial instruments are designated as cash flow hedges.

     We consider our natural gas swaps to be highly effective and expect there will be no ineffectiveness to be recognized in net income (loss) since the critical terms of the hedging instruments and the hedged forecasted transactions are the same. We have not experienced ineffectiveness on our natural gas swaps because we use NYMEX-based commodity derivative contracts to hedge on the same basis as our natural gas production is sold (NYMEX-based sales contracts). We have collar agreements that could not be redesignated as cash flow hedges because these collars were not effective due to unrealized losses at the date of the Merger. These collars qualified and were designated as cash flow hedges from their inception through the predecessor company period ended July 6, 2004. Although these collars are not deemed to be effective hedges in accordance with the provisions of SFAS 133, we have retained these instruments as protection against changes in commodity prices and we will continue to record the mark-to-market adjustments on these natural gas collars, through 2005, in our income statement. Our NYMEX crude oil swaps are highly effective and were designated as cash flow hedges. We have ineffectiveness on the crude oil swaps because the oil is sold locally at a posted price which is different from the NYMEX price. Historically, there has been a high correlation between the posted price and NYMEX. The changes in the fair values of the natural gas collars and the ineffective portion of the crude oil swaps are recorded as “Derivative fair value (gain) or loss.”

Revenue Recognition

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

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Asset Retirement Obligations

     Under the provisions of SFAS 143, “Accounting for Asset Retirement Obligations,” we recognize a liability for the fair value of our asset retirement obligations associated with our 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. Subsequent to the adoption of SFAS 143, there has been no significant current period activity with respect to additional retirement obligations, settled obligations, accretion expense and revisions of estimated cash flows. The asset retirement obligations increased as a result of purchase accounting for the Merger, primarily due to a lower discount rate and revised estimates of asset lives on certain oil and gas wells.

Results of Operations

     The Merger was completed on July 7, 2004 and was accounted for as a purchase effective July 7, 2004. The Merger resulted in a new basis of accounting reflecting estimated fair values for assets and liabilities at that date. Accordingly, the financial statements for the period subsequent to July 6, 2004 are presented on the Company’s new basis of accounting, while the results of operations for prior periods reflect the historical results of the predecessor company. A vertical black line is presented to separate the financial statements of the predecessor and successor companies.

     The allocation of the purchase price at fair value resulted in a significant increase in the book value of our assets. The increase in the book value of assets resulted in materially higher charges for depreciation, depletion and amortization in the successor company period ended June 30, 2005. These higher charges are expected to continue in subsequent accounting periods.

     The following Management’s Discussion and Analysis is based on the results of operations from continuing operations, unless otherwise noted. Accordingly, discontinued operations have been excluded. The following table sets forth certain information regarding our net oil and natural gas production, revenues and expenses for the periods indicated:

	Three months ended June 30,				Six months ended June 30,
	2005		2004		2005		2004
Production
Gas (Mmcf)		3,648		3,818		7,211		7,697
Oil (Mbbls)		95		92		177		189
Total production (Mmcfe)		4,216		4,370		8,275		8,828
Average price
Gas (per Mcf)	$	5.74	$	5.17	$	5.71	$	5.07
Oil (per Bbl)		36.23		34.94		35.25		33.46
Mcfe		5.78		5.25		5.73		5.13
Average costs (per Mcfe)
Production expense		1.27		1.27		1.30		1.24
Production taxes		0.18		0.15		0.18		0.15
Depletion		1.91		0.84		1.90		0.83
Operating margin (per Mcfe)		4.33		3.83		4.25		3.74

Mmcf — Million cubic feet	Mbbls — Thousand barrels	Mmcfe — Million cubic feet of natural gas equivalent
Mcf — Thousand cubic feet	Bbl — Barrel	Mcfe — Thousand cubic feet of natural gas equivalent
Operating margin (per Mcfe) — average price less production expense and production taxes

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Results of Operations — Second Quarters of 2005 and 2004 Compared
Revenues

     Net operating revenues increased from $25.4 million in the second quarter of 2004 to $26.9 million in the second quarter of 2005. The increase was due to higher oil and gas sales revenues of $1.4 million.

     Gas volumes sold were 3.6 Bcf (billion cubic feet) in the second quarter of 2005, which was a decrease of 170 Mmcf (4%) compared to the second quarter of 2004. This decrease in gas volumes sold resulted in a decrease in gas sales revenues of approximately $880,000. Oil volumes sold increased approximately 3,000 Bbls (3%) from 92,000 Bbls in the second quarter of 2004 to 95,000 Bbls in the second quarter of 2005 resulting in an increase in oil sales revenues of approximately $90,000. The lower gas sales volumes are primarily due to normal production declines partially offset by production from new wells drilled during 2004 and 2005.

     The average price realized for our natural gas increased $0.57 per Mcf from $5.17 in the second quarter of 2004 to $5.74 per Mcf in the second quarter of 2005, which increased gas sales revenues by approximately $2.1 million. As a result of our hedging activities, gas sales revenues were decreased by $4.5 million ($1.25 per Mcf) in the second quarter of 2005 and decreased by $4.9 million ($1.28 per Mcf) in the second quarter of 2004. The average price realized for our oil increased from $34.94 per Bbl in the second quarter of 2004 to $36.23 per Bbl in the second quarter of 2005, which increased oil sales revenues by approximately $120,000. As a result of our hedging activities, oil sales revenues were decreased by approximately $1.3 million ($13.53 per Bbl) in the second quarter of 2005.

     The operating margin from oil and gas sales (oil and gas sales revenues less production expense and production taxes) on a per unit basis increased from $3.83 per Mcfe in the second quarter of 2004 to $4.33 per Mcfe in the second quarter of 2005. The average price increased $0.53 per Mcfe which was partially offset by an increase in production taxes of $0.03 per Mcfe in the second quarter of 2005 compared to the second quarter of 2004.

     The increase in gas gathering and marketing revenues was due to a $22,000 increase in gas marketing revenues and a $81,000 increase in gas gathering revenues. The higher gas gathering and marketing revenues resulted primarily from higher gas prices.

Costs and Expenses

     Production expense was $5.5 million in the second quarter of 2004 compared to $5.3 million in the second quarter of 2005. The average production cost was $1.27 per Mcfe in the second quarter of 2004 and the second quarter of 2005.

     Production taxes increased $113,000 from $648,000 in the second quarter of 2004 to $761,000 in the second quarter of 2005. Average per unit production taxes increased from $0.15 per Mcfe in the second quarter of 2004 to $0.18 per Mcfe in the second quarter of 2005. The increased production taxes are 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.

     Exploration expense decreased $385,000 (28%) from $1.4 million in the second quarter of 2004 to $1.0 million in the second quarter of 2005. This decrease is primarily due to decreases in employment and compensation related expense.

     General and administrative expense increased $188,000 (15%) from $1.3 million in the second

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quarter of 2004 to $1.5 million in the second quarter of 2005 primarily due to an increase of $371,000 in audit and legal services related to our public filings and Sarbanes-Oxley efforts partially offset by $292,000 of non-cash stock-based compensation expense in the second quarter of 2004 to reflect the increased value of the predecessor company’s stock.

     Depreciation, depletion and amortization increased by $4.2 million from $4.5 million in the second quarter of 2004 to $8.7 million in the second quarter of 2005. This increase was primarily due to an increase in depletion expense. Depletion expense increased $4.3 million (119%) from $3.7 million in the second quarter of 2004 to $8.0 million in the second quarter of 2005 primarily due to a higher depletion rate per Mcfe. Depletion per Mcfe increased from $0.84 per Mcfe in the second quarter of 2004 to $1.91 per Mcfe in the second quarter of 2005, primarily due to a higher cost basis resulting from purchase accounting for the Merger.

     Derivative fair value (gain) loss was a loss of $11,000 in the second quarter of 2004 compared to a gain of $2.1 million in the second quarter of 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 and $1.1 million related to the ineffective portion of crude oil swaps qualifying for hedge accounting which was recorded in the second quarter of 2005.

     Interest expense decreased $167,000 from $6.1 million in the second quarter of 2004 to $5.9 million in the second quarter of 2005. This decrease was due to lower blended interest rates partially offset by an increase in average outstanding borrowings.

     Income tax expense was $77,000 in the second quarter of 2005 compared to $1.2 million in the second quarter of 2004. The decrease is primarily related to a lower effective tax rate in the second quarter of 2005 due to the changes in Ohio tax law. On June 30, 2005 the State of Ohio enacted new tax legislation that will result in the elimination of the income and franchise tax over a four year period and it will be replaced with a gross receipts based tax. As a result of the new tax structure we recorded a tax benefit of $1.1 million to adjust the recorded deferred tax account balances for Ohio during the second quarter of 2005.

     Discontinued operations relating to the TBR and Arrow asset sales resulted in a gain, net of tax, of $28.9 million in the second quarter of 2004. The TBR and Arrow assets were sold in the second quarter of 2004.

Results of Operations — Six Months of 2005 and 2004 Compared
Revenues

     Net operating revenues increased from $50.4 million in the first six months of 2004 to $52.5 million in the first six months of 2005. The increase was due to higher oil and gas sales revenues of $2.1 million.

     Gas volumes sold were 7.2 Bcf in the first six months of 2005, which was a decrease of 487 Mmcf (6%) compared to the first six months of 2004. This decrease in gas volumes sold resulted in a decrease in gas sales revenues of approximately $2.5 million. Oil volumes sold decreased approximately 12,000 Bbls (6%) from 189,000 Bbls in the first six months of 2004 to 177,000 Bbls in the first six months of 2005 resulting in a decrease in oil sales revenues of approximately $370,000. The lower oil and gas sales volumes are primarily due to normal production declines partially offset by production from new wells drilled during 2004 and 2005.

     The average price realized for our natural gas increased $0.64 per Mcf from $5.07 in the first six

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months of 2004 to $5.71 per Mcf in the first six months of 2005, which increased gas sales revenues by approximately $4.6 million. As a result of our hedging activities, gas sales revenues were decreased by $8.2 million ($1.14 per Mcf) in the first six months of 2005 and decreased by $8.4 million ($1.10 per Mcf) in the first six months of 2004. The average price realized for our oil increased from $33.46 per Bbl in the first six months of 2004 to $35.25 per Bbl in the first six months of 2005, which increased oil sales revenues by approximately $320,000. As a result of our hedging activities, oil sales revenues were decreased by approximately $2.3 million ($12.96 per Bbl) in the first six months of 2005.

     The operating margin from oil and gas sales on a per unit basis increased from $3.74 per Mcfe in the first six months of 2004 to $4.25 per Mcfe in the first six months of 2005. The average price increased $0.64 per Mcfe which was partially offset by an increase in production expense of $0.06 per Mcfe and an increase in production taxes of $0.03 per Mcfe in the first six months of 2005 compared to the first six months of 2004.

     The decrease in gas gathering and marketing revenues was due to a $106,000 decrease in gas marketing revenues partially offset by a $69,000 increase in gas gathering revenues.

Costs and Expenses

     Production expense was $11.0 million in the first six months of 2004 and $10.8 million in the first six months of 2005. The average production cost increased from $1.24 per Mcfe in the first six months of 2004 to $1.30 per Mcfe in the first six months of 2005. The per unit increase was due to the lower volumes discussed above.

     Production taxes increased $195,000 from $1.3 million in the first six months of 2004 to $1.5 million in the first six months of 2005. Average per unit production taxes increased from $0.15 per Mcfe in the first six months of 2004 to $0.18 per Mcfe in the first six months of 2005. The increased production taxes are 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.

     Exploration expense decreased $782,000 (29%) from $2.7 million in the first six months of 2004 to $1.9 million in the first six months of 2005. This decrease is primarily due to lower expired lease expense and decreases in employment and compensation related expense.

     General and administrative expense increased $717,000 (29%) from $2.5 million in the first six months of 2004 to $3.2 million in the first six months of 2005 primarily due to $489,000 related to severance agreements with two former executives in the first quarter of 2005, an increase of $603,000 in audit and legal services related to our public filings and Sarbanes-Oxley efforts partially offset by $296,000 of non-cash stock-based compensation expense in the first six months of 2004 to reflect the increased value of the predecessor company’s stock.

     Depreciation, depletion and amortization increased by $7.9 million from $9.1 million in the first six months of 2004 to $17.0 million in the first six months of 2005. This increase was primarily due to an increase in depletion expense. Depletion expense increased $8.3 million (113%) from $7.4 million in the first six months of 2004 to $15.7 million in the first six months of 2005 primarily due to a higher depletion rate per Mcfe. Depletion per Mcfe increased from $0.83 per Mcfe in the first six months of 2004 to $1.90 per Mcfe in the first six months of 2005, primarily due to a higher cost basis resulting from purchase accounting for the Merger.

     Derivative fair value (gain) loss was a gain of $321,000 in the first six months of 2004 compared to a loss of $6.1 million in the first six months of 2005. The derivative fair value (gain) loss reflects the

15

changes in fair value of certain derivative instruments that are not designated or do not qualify as cash flow hedges and $3.7 million related to the ineffective portion of crude oil swaps qualifying for hedge accounting which was recorded in the first six months of 2005.

     Interest expense decreased $409,000 from $12.2 million in the first six months of 2004 to $11.8 million in the first six months of 2005. This decrease was due to lower blended interest rates partially offset by an increase in average outstanding borrowings.

     Income tax was a benefit of $3.0 million for the first six months of 2005 compared to income tax expense of $2.6 million for the first six months of 2004. The decrease is primarily related to a decrease in income from continuing operations before income taxes and as a result of changes in the Ohio tax law. On June 30, 2005 the State of Ohio enacted new tax legislation that will result in the elimination of the income and franchise tax over a four year period and it will be replaced with a gross receipts based tax. As a result of the new tax structure we recorded a tax benefit of $1.1 million to adjust the recorded deferred tax account balances for Ohio during the second quarter of 2005.

     Discontinued operations relating to the TBR and Arrow asset sales resulted in a gain, net of tax, of $28.6 million in the first six months of 2004. The TBR and Arrow assets were sold in the second quarter of 2004.

Liquidity and Capital Resources

Cash Flows

     The primary sources of cash in the six-month period ended June 30, 2005 have been funds generated from operations. Funds used during this period were primarily used for operations, exploration and development expenditures and interest expense. Our liquidity and capital resources are closely related to and dependent upon the current prices paid for our oil and natural gas.

     Our operating activities provided cash flows of $19.7 million during the first six months of 2005 compared to $15.9 million in the first six months of 2004. The increase was primarily due to higher oil and gas margins (net of hedging) of $2.1 million and changes in working capital items of $5.3 million partially offset by a $3.5 million increase in cash settlements of derivative instruments that do not qualify as cash flow hedges in derivative fair value (gain) loss.

     Our investing activities used cash flows of $16.8 million during the first six months of 2005 compared to $52.0 million provided in the first six months of 2004. In the first six months of 2004 the TBR and Arrow asset sales provided cash flows of $72.7 million. In the first six months of 2005 capital expenditures decreased $3.3 million, exploration expense decreased $2.2 million and the change in other assets decreased $1.2 million compared to the first six months of 2004.

     Cash flows used in financing activities decreased $23.2 million in the first six months of 2005 primarily due to lower debt repayment during the first six months of 2005.

     Our current ratio at June 30, 2005 was 0.81 to 1. During the first six months of 2005, the working capital from continuing operations decreased $8.9 million from a deficit of $3.2 million at December 31, 2004 to a deficit of $12.1 million at June 30, 2005. The decrease was primarily due to a $13.4 million increase in the current liability for the fair value of derivatives and a $3.2 million decrease in accounts receivable partially offset by a $4.3 million increase in the deferred income taxes asset and a $2.4 million increase in cash and cash equivalents.

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Capital Expenditures

     During the first six months of 2005, we spent approximately $13.0 million, including exploratory dry hole expense, on our drilling activities and other capital expenditures. In the first six months of 2005, we drilled 58 gross (55.8 net) development wells, all of which have been or are expected to be successfully completed as producers in the target formation. This cost excludes approximately $500,000 related to wells in progress as of June 30, 2005, including approximately $220,000 to drill 2 gross (1.5 net) exploratory Trenton Black River wells in Ohio during the second quarter. If these wells are determined to be dry holes, their cost will be charged to exploration expense in subsequent periods.

     We currently expect to spend approximately $36 million during 2005 on our drilling activities, including exploratory dry hole expense, and other capital expenditures. We intend to finance our planned capital expenditures through our cash on hand, available cash flow, borrowings under our revolving credit facility and, to a lesser extent, the sale of non-strategic assets. At June 30, 2005, we had cash of $20.8 million and approximately $13.8 million available under our revolving facility. The level of our future cash flow will depend on a number of factors including the demand for and price levels of oil and gas, the scope and success of our drilling activities and our ability to acquire additional producing properties. There can be no assurance that the future drilling of our proved undeveloped locations will provide adequate liquidity in the future.

     At June 30, 2005, we had a $170 million credit facility comprised of: a seven year $100 million term facility; a six year $30 million revolving facility for working capital requirements and general corporate purposes, including the issuance of letters of credit; and a six year $40 million letter of credit facility that may be used only to provide credit support for our obligations under the hedge agreement and other hedge transactions. At June 30, 2005, the interest rate under our base rate option was 8.00%. Under our three month LIBOR option the rate was 6.21%. At June 30, 2005, we had $56.2 million of outstanding letters of credit. At June 30, 2005, there was no outstanding balance under the revolving credit agreement. Under the term facility the outstanding balance was $89 million. We had $13.8 million of borrowing capacity under our revolving facility available for general corporate purposes. As of June 30, 2005, we were in compliance with all financial covenants and requirements under the existing credit facilities.

Item 3. 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 facility as well as any new debt financing needed to fund capital requirements. We may manage our interest rate risk through the use of interest rate swaps to hedge the interest rate exposure associated with the credit agreement, whereby a portion of our floating rate exposure is exchanged for a fixed interest rate. A portion of our long-term debt consists of senior secured notes where the interest component is fixed. We had no derivative financial instruments for managing interest rate risks in place as of June 30, 2005 or 2004. If market interest rates for short-term borrowings increased 1%, the increase in interest expense in the second quarter would be approximately $223,000. This sensitivity analysis is based on our financial structure at June 30, 2005.

     The commodity price risk relates to 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. We employ a policy of partially hedging oil production sold locally at a

17

posted price and 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. Historically, there has been a high correlation between the posted price and NYMEX. 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 for the quarter would decrease by $324,000, after considering the effects of the hedging contracts in place at June 30, 2005. If the price of crude oil decreased $3.00 per Bbl, oil sales revenues for the quarter would decrease by $82,000, after considering the effects of the hedging contracts in place at June 30, 2005. We had net pre-tax losses on our hedging activities of $5.8 million in the first six months of 2005 and $4.9 million in the first six months of 2004. At June 30, 2005, we had hedges on a portion of our oil and gas production for the remainder of 2005 through 2013. This sensitivity analysis is based on our 2005 oil and gas sales volumes and assumes the NYMEX gas price would be above the ceiling in 2005 listed in the table below.

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

	Natural Gas Swaps				Natural Gas Collars				Crude Oil Swaps
			NYMEX				NYMEX Price
			Price per				per Mmbtu		Estimated		NYMEX
Quarter Ending	Bbtu		Mmbtu		Bbtu		Floor/Cap (1)		Mbbls		Price per Bbl
September 30, 2005		1,500	$	3.70		1,500	$	4.00-5.32		67	$	33.72
December 31, 2005		1,500		3.70		1,500		4.00 - 5.32		67		33.31
		3,000	$	3.70		3,000	$	4.00-5.32		134	$	33.52
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

⁽¹⁾ The NYMEX price per Mmbtu floor/cap for the natural gas collars in 2005 assume the monthly NYMEX settles at $3.10 per Mmbtu or higher. If the monthly NYMEX settles at less than $3.10 per Mmbtu then the NYMEX price per Mmbtu will be the NYMEX settle plus $0.90.

     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 prices of NYMEX futures contracts for gas delivered at the Henry Hub in Louisiana. Monthly spot natural gas prices in our market areas are typically $0.15 to $0.60 higher per Mcf than comparable NYMEX prices. Our average price received for crude oil is typically $3.00 to $3.50 per barrel below the NYMEX price per barrel.

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Item 4. Controls and Procedures

     As of the end of the quarterly period ended June 30, 2005, James A. Winne III, our Chief Executive Officer, and Robert W. Peshek, our Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer believe that:

• our disclosure controls and procedures were effective in ensuring that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 was recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and

• our disclosure controls and procedures were effective in ensuring that material information required to be disclosed by us in the report we file or submit under the Securities Exchange Act of 1934 was accumulated and communicated to our management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Internal Controls Over Financial Reporting

     There has not been any change in our internal control over financial reporting that occurred during our quarterly period ended June 30, 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II     OTHER INFORMATION

Item 1. Legal Proceedings.

     In April 2002, we were notified of a claim by an overriding royalty owner in Michigan alleging the underpayment of royalties 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 the successor in interest to these royalty interests, alleging substantially the same underpayments. In April 2005, we entered into a settlement agreement that provided for a payment to the royalty owner of an amount approximately equal to the amount accrued at March 31, 2005 and an increase in the future overriding royalty percentage in several wells. The result had no material adverse effect on our financial position, results of operations or cash flows.

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

     On June 14, 2005, Capital C approved by written consent in lieu of an annual meeting (i) the increase of the number of directors constituting our Board from seven to eight, (ii) the re-election of Gregory A. Beard, Michael Becci, Michael B. Hoffman, Pierre F. Lapeyre, Jr., David M. Leuschen, Morris B. “Sam” Smith and James A. Winne III to the Board and (iii) the election of Stewart “Chip” Cureton, Jr. as a new non-employee member of the Board of Directors. Mr. Cureton will receive compensation of $40,000 per year and a Board meeting fee of $2,000 per meeting. Mr. Cureton is a limited partner of Capital C Energy Partners, L.P., which owns a minority interest in Capital C.

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Item 6. Exhibits.

(a) Exhibits

3.1*	Amended and Restated Articles of Incorporation of Belden & Blake Corporation (fka Belden & Blake Energy Corporation).
3.2*	Amended and Restated Code of Regulations of Belden & Blake Corporation.
31.1*	Certification of Principal Executive Officer of Belden & Blake Corporation as required by Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934.
31.2*	Certification of Principal Financial Officer of Belden & Blake Corporation as required by Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934.
32.1*	Certification of Chief Executive Officer of Belden & Blake Corporation pursuant to 18 U.S.C. Section 1350.
32.2*	Certification of Chief Financial Officer of Belden & Blake Corporation pursuant to 18 U.S.C. Section 1350.

*Filed herewith.

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SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	BELDEN & BLAKE CORPORATION
Date:  August 11, 2005	By:	/s/ James A. Winne III
		James A. Winne III, Chief Executive Officer,
		Chairman of the Board of Directors and Director
Date:  August 11, 2005	By:	/s/ Robert W. Peshek
		Robert W. Peshek, Senior Vice President
		and Chief Financial Officer

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