Belden & Blake Corporation 10-Q/A

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q/A

(Amendment No. 2)

(Mark One)

þ Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended March 31, 2005

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 incorporation or organization)		(I.R.S. Employer 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 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). o Yes þ No

As of April 30, 2005, Belden & Blake Corporation had outstanding 1,500 shares of common stock, without par value, which is its only class of stock.

Table of Contents

Amendment No. 2 Overview

We have filed amendments to our Annual Report on Form 10-K/A for the year ended December 31, 2004 and to our Quarterly Report on Form 10-Q/A for the quarter ended March 31, 2005 to amend and restate the financial statements and other financial information contained in these reports with respect to the accounting and disclosures for (1) the recognition of additional expense for the ineffective component of non-zero value derivatives designated as cash flow hedges, (2) the recognition of a derivative liability for certain derivative contracts that had settled but had not yet been paid, (3) the correction of an error in the recording of Accumulated Other Comprehensive Income related to settled cash flow hedges and (4) the adjustment to income taxes for the effect of the previously discussed corrections.

The information contained in this amendment, including the financial statements and the notes thereto, reflect only the adjustments described above and do not reflect events occurring after May 10, 2005, the date of the original filing of this Form 10-Q. In addition, currently–dated certifications from our Chief Executive Officer and our Chief Financial Officer have been included as exhibits to this Amendment. As discussed in Part I Item 4, management identified a control deficiency that constitutes as a material weakness. In addition, currently-dated certifications from our Chief Executive Officer and our Chief Financial Officer have been included as exhibits to this Amendment.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

BELDEN & BLAKE CORPORATION

CONSOLIDATED BALANCE SHEETS

(in thousands, except share data)


	March 31,			December 31,
	2005			2004
	(Restated)			(Restated)
	(unaudited)
ASSETS
Current assets
Cash and cash equivalents	$	15,388		$	18,407
Accounts receivable, net		15,710			18,667
Inventories		550			518
Deferred income taxes		18,729			11,169
Other current assets		1,271			1,101

Total current assets		51,648			49,862

Property and equipment, at cost
Oil and gas properties (successful efforts method)		520,792			514,242
Gas gathering systems		5,106			4,485
Land, buildings, machinery and equipment		7,796			7,720

		533,694			526,447
Less accumulated depreciation, depletion and amortization		24,861			16,917

Property and equipment, net		508,833			509,530
Other assets		11,076			11,461

	$	571,557		$	570,853

LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Accounts payable	$	5,141		$	3,796
Accrued expenses		16,413			23,445
Current portion of long-term liabilities		1,965			1,964
Fair value of derivatives		45,046			24,902

Total current liabilities		68,565			54,107

Long-term liabilities
Bank and other long-term debt		88,340			88,592
Senior secured notes		192,500			192,500
Asset retirement obligations and other long-term liabilities		14,704			14,390

		295,544			295,482

Fair value of derivatives		123,074			55,182
Deferred income taxes		83,148			108,994
Shareholder’s equity
Common stock: without par value; 1,500 shares authorized and issued		—			—
Paid in capital		77,500			77,500
Retained earnings		6,627			7,263
Accumulated other comprehensive loss		(82,901	)		(27,675	)

Total shareholder’s equity		1,226			57,088

	$	571,557		$	570,853

See accompanying notes.

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)
														(Restated)			(Restated)			(Restated)
Predecessor Company:
January 1, 2003						10,296		$	1,030		$	107,118		$	(148,332	)	$	(4,854	)	$	(45,038	)

Comprehensive (loss) income:
Net loss															(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 income (loss):
Net income															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 income																					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		—		—		—			—			—			—			—			—

Successor 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															(636	)					(636	)
Other comprehensive income (loss), net of tax:
Change in derivative fair value																		(58,146	)		(58,146	)
Reclassification adjustment for derivative (gain) loss reclassified into oil and gas sales																		2,920			2,920

Total comprehensive loss																					(55,862	)

March 31, 2005 (unaudited)		2	$	—		—		$	—		$	77,500		$	6,627		$	(82,901	)	$	1,226

See accompanying notes.

BELDEN & BLAKE CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited, in thousands)


	Successor			Predecessor
	Company			Company
	Three months			Three months
	ended March 31,			ended March 31,
	2005			2004
	(Restated)
Cash flows from operating activities:
Net (loss) income	$	(636	)	$	2,052
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization		8,305			4,947
Accretion expense		255			112
Loss on disposal of property and equipment		12			325
Amortization of derivatives and other noncash hedging activities		5,807			(697	)
Exploration expense		952			2,077
Deferred income taxes		(530	)		1,206
Stock-based compensation		—			19
Change in operating assets and liabilities, net of effects of acquisition and disposition of businesses:
Accounts receivable and other operating assets		2,787			(286	)
Inventories		8			(108	)
Accounts payable and accrued expenses		(5,648	)		2,822

Net cash provided by operating activities		11,312			12,469

Cash flows from investing activities:
Proceeds from property and equipment disposals		—			41
Exploration expense		(952	)		(2,077	)
Additions to property and equipment		(7,214	)		(8,024	)
(Increase) decrease in other assets		(14	)		144

Net cash used in investing activities		(8,180	)		(9,916	)

Cash flows from financing activities:
Repayment of senior secured facility — term loan		(250	)		—
Proceeds from revolving line of credit		—			42,366
Repayment of long-term debt and other obligations		(28	)		(44,488	)
Settlement of derivative liabilities recorded in purchase accounting		(5,873	)		—
Proceeds from stock options exercised		—			110
Repurchase of stock options		—			(283	)
Purchase of treasury stock		—			(25	)

Net cash used in financing activities		(6,151	)		(2,320	)

Net (decrease) increase in cash and cash equivalents		(3,019	)		233
Cash and cash equivalents at beginning of period		18,407			1,440

Cash and cash equivalents at end of period	$	15,388		$	1,673

See accompanying notes.

BELDEN & BLAKE CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Restated) (unaudited)

March 31, 2005

Restatement. As discussed under the heading “Amendment No. 2 Overview” on page 1, we have restated our financial statements and other financial information contained in our originally filed Annual Report on Form 10-K for the year ended December 31, 2004 and Quarterly Report on Form 10-Q for the quarter ended March 31, 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 loss of $483,000 ($314,000 net of tax) in the first quarter of 2004. Total revenue of $4.1 million was reclassified to discontinued operations in the first quarter of 2004. Historical information has been restated to remove the TBR and Arrow assets from continuing operations.

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 three-month period ended March 31, 2005, as amended, 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 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, 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 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 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 primarily take the form of swaps or collars. At March 31, 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 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 related to the Merger (referred to as non-zero value hedges). 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 and due to purchase accounting related to the Merger (referred to as non-zero value hedges). 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 and natural gas swaps are recorded as “Derivative fair value gain or loss.”

During the first three months of 2005 and 2004, a net loss of $4.7 million ($2.9 million after tax) and a net loss of $3.9 million ($2.5 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 $92.8 million ($58.1 million after tax) in the first three months of 2005 and decreased $10.3 million ($6.6 million after tax) in the first three months of 2004. At March 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 $20.5 million. At March 31, 2005, we have partially hedged our exposure to the variability in future cash flows through December 2013.

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


	Natural Gas Swaps				Natural Gas Collars				Crude Oil Swaps
			NYMEX				NYMEX Price per
			Price per				Mmbtu Floor/Cap				NYMEX Price
	Bbtu		Mmbtu		Bbtu		(1)		Mbbls		per Bbl
Quarter Ending
June 30, 2005		1,500	$	3.70		1,500	$	4.00 - 5.32		68	$	34.18
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

		4,500	$	3.70		4,500	$	4.00 - 5.32		202	$	33.74


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) Stock-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 March 31, 2004, resulted in a non-cash increase in compensation expense of $19,000. The successor company does not have any stock-based compensation.

(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

Successor

Predecessor

Company

Three months

ended March 31,

(in thousands)

2005

2004

Cash paid during the period for:

Interest

10,398

981

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 provides 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 will have no material adverse effect on our financial position, results of operations or cash flows.

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, 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 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.

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).

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 March 31, 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 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 related to the Merger (referred to as non–zero value hedges). 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 and due to purchase accounting related to the Merger (referred to as non-zero value hedges). 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 and natural gas swaps are recorded as “Derivative fair value gain or loss.”

Revenue Recognition

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

Asset Retirement Obligations

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 March 31, 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 March 31,
	2005		2004
	(Restated)
Production
Gas (Mmcf)		3,563		3,879
Oil (Mbbls)		83		97
Total production (Mmcfe)		4,059		4,458

Average price
Gas (per Mcf)	$	7.00	$	4.97
Oil (per Bbl)		36.12		32.05
Mcfe		6.88		5.02
Average costs (per Mcfe)
Production expense		1.34		1.21
Production taxes		0.18		0.15
Depletion		1.89		0.83
Operating margin (per Mcfe)		5.36		3.66


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

First Quarters of 2005 and 2004 Compared

Revenues

Net operating revenues increased from $24.9 million in the first quarter of 2004 to $30.4 million in the first quarter of 2005. The increase was due to higher oil and gas sales revenues of $5.6 million partially offset by lower gas gathering and marketing revenues of $140,000.

Gas volumes sold were 3.6 Bcf (billion cubic feet) in the first quarter of 2005, which was a decrease of 316 Mmcf (8%) compared to the first quarter of 2004. This decrease in gas volumes sold resulted in a decrease in gas sales revenues of approximately $1.6 million. Oil volumes sold decreased approximately 14,000 Bbls (14%) from 97,000 Bbls in the first quarter of 2004 to 83,000 Bbls in the first quarter of 2005 resulting in a decrease in oil sales revenues of approximately $440,000. 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 $2.03 per Mcf from $4.97 in the first quarter of 2004 to $7.00 per Mcf in the first quarter of 2005, which increased gas sales revenues by approximately $7.2 million. As a result of our hedging activities, gas sales revenues were increased by $1.0 million ($0.28 per Mcf) in the first quarter of 2005 and decreased by $3.5 million ($0.91 per Mcf) in the first quarter of 2004. The average price realized for our oil increased from $32.05 per Bbl in the first quarter of 2004 to $36.12 per Bbl in the first quarter of 2005, which increased oil sales revenues by approximately $340,000. As a result of our hedging activities, oil sales revenues were decreased by approximately $850,000 ($10.31 per Bbl) in the first 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 $3.66 per Mcfe in the first quarter of 2004 to

$5.36 per Mcfe in the first quarter of 2005. The average price increased $1.86 per Mcfe which was partially offset by an increase in production expense of $0.13 per Mcfe and an increase in production taxes of $0.03 per Mcfe in the first quarter of 2005 compared to the first quarter of 2004.

The decrease in gas gathering and marketing revenues was due to a $128,000 decrease in gas marketing revenues and a $12,000 decrease in gas gathering revenues. The lower gas gathering and marketing revenues resulted primarily from the lower gas volumes discussed above.

Costs and Expenses

Production expense was $5.4 million in the first quarter of 2004 and the first quarter of 2005. The average production cost increased from $1.21 per Mcfe in the first quarter of 2004 to $1.34 per Mcfe in the first quarter of 2005. The per unit increase was due to the lower volumes discussed above.

Production taxes increased $82,000 from $652,000 in the first quarter of 2004 to $734,000 in the first quarter of 2005. Average per unit production taxes increased from $0.15 per Mcfe in the first quarter of 2004 to $0.18 per Mcfe in the first 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 $397,000 (29%) from $1.3 million in the first quarter of 2004 to $1.0 million in the first quarter 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 $529,000 (43%) from $1.2 million in the first quarter of 2004 to $1.8 million in the first quarter of 2005 primarily due to $489,000 related to severance agreements with two former executives in the first quarter of 2005, an increase of $311,000 in audit and legal services related to our public filings and Sarbanes-Oxley efforts partially offset by $176,000 for strategic advisory services in the first quarter of 2004 related to the potential sale of the Company.

Depreciation, depletion and amortization increased by $3.7 million from $4.6 million in the first quarter of 2004 to $8.3 million in the first quarter of 2005. This increase was primarily due to an increase in depletion expense. Depletion expense increased $4.0 million (108%) from $3.7 million in the first quarter of 2004 to $7.7 million in the first quarter of 2005 primarily due to a higher depletion rate per Mcfe. Depletion per Mcfe increased from $0.83 per Mcfe in the first quarter of 2004 to $1.89 per Mcfe in the first quarter 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 $332,000 in the first quarter of 2004 compared to a loss of $6.2 million in the first 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 $126,000 related to the ineffective portion of crude oil swaps and natural gas hedges qualifying for hedge accounting which was recorded in the first quarter of 2005.

Interest expense decreased $242,000 from $6.1 million in the first quarter of 2004 to $5.8 million in the first quarter of 2005. This decrease was due to lower blended interest rates partially offset by an increase in average outstanding borrowings.

Income tax expense decreased $1.9 million from $1.4 million in the first quarter of 2004 to a benefit of $530,000 in the first quarter of 2005. The decrease was primarily due to a decrease in income from continuing operations before income taxes.

Discontinued operations relating to the TBR and Arrow asset sales resulted in a loss, net of tax, of $314,000 in the first quarter 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 three-month period ended March 31, 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 $11.3 million during the first three months of 2005 compared to $12.5 million in the first three months of 2004. The decrease of $1.2 million was primarily due to changes in working capital items of $5.3 million, partially offset by higher cash received for oil and gas sales revenues (net of hedging).

Cash flows used in investing activities were $8.2 million in the first three months of 2005 compared to $9.9 million in the first three months of 2004. The decrease was primarily due to a decrease in exploration expense of $1.1 million and an $810,000 decrease in capital expenditures in the first three months of 2005.

Cash flows used in financing activities increased in the first three months of 2005 primarily due to the settlement of derivative liabilities recorded in purchase accounting due to the Merger and lower debt repayment during the first three months of 2005.

Our current ratio at March 31, 2005 was 0.75 to 1. During the first three months of 2005, the working capital from continuing operations decreased $12.7 million from a deficit of $4.2 million at December 31, 2004 to a deficit of $16.9 million at March 31, 2005. The decrease was primarily due to a $20.1 million increase in the current liability for the fair value of derivatives, a $3.0 million decrease in cash and cash equivalents and a $3.0 million decrease in accounts receivable partially offset by a $7.0 million decrease in accrued expenses and a $7.6 million increase in the deferred income taxes asset. The decrease in accrued expenses was primarily due to a $4.6 million decrease in accrued interest expense.

Capital Expenditures

During the first three months of 2005, we spent approximately $7.3 million, including exploratory dry hole expense, on our drilling activities and other capital expenditures. In the first three months of 2005, we drilled 28 gross (27.3 net) development wells, all of which were successfully completed as producers in the target formation.

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 March 31, 2005, we had cash of $15.4 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 March 31, 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 March 31, 2005, the interest rate under our base rate option was 7.50%. Under our three month LIBOR option the rate was 5.80%. At March 31, 2005, we had $56.2 million of outstanding letters of credit. At March 31, 2005, there was no outstanding balance under the revolving credit agreement. Under the term facility the outstanding balance was $89.25 million. We had $13.8 million of borrowing capacity under our revolving facility available for general corporate purposes. As of March 31, 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 March 31, 2005 or 2004. If market interest rates for short-term borrowings increased 1%, the increase in interest expense in the first quarter would be approximately $223,000. This sensitivity analysis is based on our financial structure at March 31, 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 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 $281,000, after considering the effects of the hedging contracts in place at March 31, 2005. If the price of crude oil decreased $3.00 per Bbl, oil sales revenues for the quarter would decrease by $46,000, after considering the effects of the hedging contracts in place at March 31, 2005. We had net pre-tax gains on our hedging activities reported in oil and gas sales revenue of $152,000 in the first three months of 2005 and a net pre-tax loss of $3.5 million in the first three months of 2004. At March 31, 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 April 30, 2005:


	Natural Gas Swaps				Natural Gas Collars				Crude Oil Swaps
			NYMEX				NYMEX Price per
			Price per				Mmbtu Floor/Cap				NYMEX Price
	Bbtu		Mmbtu		Bbtu		(1)		Mbbls		per Bbl
Quarter Ending
June 30, 2005		1,500	$	3.70		1,500	$	4.00 - 5.32		68	$	34.18
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

		4,500	$	3.70		4,500	$	4.00 - 5.32		202	$	33.74


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.

Item 4. Controls and Procedures

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 March 31, 2005. Based on that evaluation and solely because of the material weakness in internal control over financial reporting discussed below, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were not effective in providing reasonable assurance that information required to be disclosed in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported as and when required and that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, in a manner that allows timely decisions regarding required disclosure. Notwithstanding the material weakness discussed below, our management has concluded that the financial statements included in this Form 10-Q/A fairly present in all material respects our financial position, results of operations and cash flows for the periods presented in conformity with generally accepted accounting principles.

Changes in Internal Control over Financial Reporting

Except as noted below, there were no changes in the internal control over financial reporting that occurred during the period ended March 31, 2005 that materially affected, or that are reasonably likely to materially affect, internal control over financial reporting.

Identification of Material Weakness in Internal Control over Financial Reporting

A material weakness is a control deficiency, or combination of control deficiencies, that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. Management and the Board of Directors have concluded that we did not maintain effective controls to ensure that hedge accounting was correctly applied pursuant to generally accepted accounting principles. Specifically, our accounting for certain hedging transactions did not meet the requirements of SFAS 133 and related interpretations in the following areas: (1) the recognition of additional expense for the ineffective component of non-zero value derivatives designated as cash flow hedges, (2) the recognition of a derivative liability for certain derivative contracts that had settled but had not yet been paid, (3) the correction of an error in the recording of Accumulated Other Comprehensive Income related to settled cash flow hedges and (4) the adjustment to income taxes for the effect of the previously discussed corrections.

This control deficiency resulted in the restatement of our consolidated financial statements for the years ended December 31, 2004, 2003 and 2002, the periods ended March 31, June 30, September 30 and December 31, 2004 and the period ended March 31, 2005. Accordingly, management determined that this control deficiency constituted a material weakness in internal control over financial reporting as of March 31, 2005.

Plans for Remediation

Management intends to remediate the material weakness in internal control over financial reporting and will report on its status when it files its Form 10-K for the year ending December 31, 2005. In particular, management intends to:

• revise our accounting policies and procedures for derivative accounting to meet the requirements of SFAS 133; and

• strengthen our internal knowledge base regarding hedge accounting with improved training and expertise.

By implementing these internal control improvements, management expects to remediate this material weakness in internal control over financial reporting.

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. We will continue to improve the design and effectiveness of its disclosure controls and procedures and internal control over financial reporting to the extent necessary in the future to provide senior management with timely access to such material information and to correct any deficiencies that may be discovered in the future.

PART II OTHER INFORMATION

Item 1. Legal Proceedings.

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

On February 14, 2005, Capital C approved by written consent in lieu of a meeting, a resolution naming Morris B. “Sam” Smith to our Board of Directors and increasing our Board’s membership from six to seven. The terms of office of our other directors, Gregory A. Beard, Michael Becci, Michael B. Hoffman, Pierre F. Lapeyre, Jr., David M. Leuschen and James A. Winne III, continued after February 14, 2005.


	Page
Amendment No. 2 Overview		1



PART I Financial Information

Item 1. Financial Statements

Consolidated Balance Sheets as of March 31, 2005 and December 31, 2004		2

Consolidated Statements of Operations:
Three months ended March 31, 2005 (Successor Company)
Three months ended March 31, 2004 (Predecessor Company)		3

Consolidated Statements of Shareholders’ Equity (Deficit):
Three months ended March 31, 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)		4

Consolidated Statements of Cash Flows:
Three months ended March 31, 2005 (Successor Company)
Three months ended March 31, 2004 (Predecessor Company)		5

Notes to Consolidated Financial Statements		6

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		10

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
Exhibit 31.1 Certification
Exhibit 31.2 Certification of CFO
Exhibit 32.1 Certification of CEO Section 906
Exhibit 32.2 Certification of CFO Section 906


	Successor			Predecessor
	Company			Company
	Three months			Three months
	ended March 31,			ended March 31,
	2005			2004
	(Restated)
Revenues
Oil and gas sales	$	27,921		$	22,362
Gas gathering and marketing		2,443			2,583
Other		107			129

		30,471			25,074

Expenses
Production expense		5,420			5,406
Production taxes		734			652
Gas gathering and marketing		2,106			2,232
Exploration expense		952			1,349
General and administrative expense		1,764			1,235
Franchise, property and other taxes		54			70
Depreciation, depletion and amortization		8,305			4,554
Accretion expense		255			95
Derivative fair value (gain) loss		6,217			(332	)

		25,807			15,261

Operating income		4,664			9,813

Other expense
Interest expense		5,830			6,072

(Loss) income from continuing operations before income taxes		(1,166	)		3,741
(Benefit) provision for income taxes		(530	)		1,375

(Loss) income from continuing operations		(636	)		2,366
Loss from discontinued operations, net of tax		—			(314	)

Net (loss) income	$	(636	)	$	2,052



	BELDEN & BLAKE CORPORATION
Date: March 30, 2006	By:	/s/ Mark A. Houser
		Mark A. Houser, Chief Executive Officer,
		Chairman of the Board of Directors and Director


Date: March 30, 2006	By:	/s/ James M.Vanderhider
		James M.Vanderhider, President and Chief Financial Officer



Date: March 30, 2006	By:	/s/ Mark A. Houser
		Mark A. Houser, Chief Executive Officer,
		Chairman of the Board of Directors and Director


þ	Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	For the quarterly period ended March 31, 2005


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

	—	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.

	•	revise our accounting policies and procedures for derivative accounting to meet the requirements of SFAS 133; and

	•	strengthen our internal knowledge base regarding hedge accounting with improved training and expertise.


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.


1.	I have reviewed this report on Form 10-Q/A for the quarterly period ended March 31, 2005 of Belden & Blake Corporation;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)), for the registrant and have:



Date: March 30, 2006	By:	/s/ James M. Vanderhider
		James M. Vanderhider, President and Chief Financial Officer

	1.	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

	2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.