Belden & Blake 10-Q/A

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q/A
(Amendment No. 1)

(Mark One)


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


[ ]		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. [X] Yes [ ] No

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). [ ] Yes [X] No

As of October 31, 2005, Belden & Blake Corporation had outstanding 1,534 shares of common stock, without par value, which is its only class of stock.

CONSOLIDATED BALANCE SHEETS

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


	Successor Company			Predecessor I Company
	September 30,			December 31,
	2005			2004
	(As Restated, See Note 2)			(As Restated, See Note 2)
ASSETS
Current assets
Cash and cash equivalents	$	4,404		$	18,407
Accounts receivable, net		23,467			18,667
Inventories		1,323			518
Deferred income taxes		38,207			11,169
Other current assets		1,562			1,101

Total current assets		68,963			49,862
Property and equipment, at cost
Oil and gas properties (successful efforts method)		657,068			514,242
Gas gathering systems		1,765			4,485
Land, buildings, machinery and equipment		6,815			7,720

		665,648			526,447
Less accumulated depreciation, depletion and amortization		4,568			16,917

Property and equipment, net		661,080			509,530
Goodwill		92,427			—
Other assets		2,904			11,461

	$	825,374		$	570,853

LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Accounts payable	$	4,464		$	3,796
Accrued expenses		24,729			23,445
Current portion of long-term liabilities		653			1,964
Fair value of derivatives		95,036			24,902

Total current liabilities		124,882			54,107
Long-term liabilities
Bank and other long-term debt		52,087			88,592
Senior secured notes		200,681			192,500
Subordinated promissory note-related party		25,000			—
Asset retirement obligations and other long-term liabilities		19,712			14,390
Fair value of derivatives		214,828			55,182
Deferred income taxes		94,223			108,994

		606,531			459,658
Shareholder’s equity
Common stock without par value: Successor; 3,000 shares authorized; 1,534 issued; Predecessor; 1,500 shares authorized and issued		—			—
Paid in capital		125,000			77,500
Retained earnings		660			7,263
Accumulated other comprehensive loss		(31,699	)		(27,675	)

Total shareholder’s equity		93,961			57,088

	$	825,374		$	570,853

See accompanying notes.

CONSOLIDATED STATEMENTS OF OPERATIONS

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


	Three Months Ended September 30, 2005					Three Months Ended September 30, 2004
									Predecessor II
	Successor Company		Predecessor I Company						Company
	For the 46 Day		For the 46 Day			For the 86 Day			For the 6 Day
	Period From		Period From			Period From			Period From
	August 16, 2005 to		July 1, 2005 to			July 7, 2004 to			July 1, 2004 to
	September 30, 2005		August 15, 2005			September 30, 2004			July 6, 2004
	(As Restated See Note 2)		(As Restated See Note 2)			(As Restated See Note 2)
Revenues
Oil and gas sales	$	20,956	$	15,481		$	25,615		$	—
Gas gathering and marketing		1,625		1,419			2,179			—
Other		81		67			550			—

		22,662		16,967			28,344			—
Expenses
Production expense		3,284		2,667			5,500			1,171
Production taxes		524		406			650			—
Gas gathering and marketing		1,441		1,209			2,026			46
Exploration expense		379		490			1,334			503
General and administrative expense		381		618			1,100			1,172
Franchise, property and other taxes		41		30			67			—
Depreciation, depletion and amortization		4,528		4,248			8,611			—
Accretion expense		149		163			134			—
Derivative fair value loss		7,982		4,981			2,968			2,359
Transaction expenses		—		7,535			—			26,001

		18,709		22,347			22,390			31,252

Operating income (loss)		3,953		(5,380	)		5,954			(31,252	)
Other expense
Interest expense		2,903		3,010			6,143			—

Income (loss) from continuing operations before income taxes		1,050		(8,390	)		(189	)		(31,252	)
Provision (benefit) for income taxes		390		(2,732	)		(569	)		(7,439	)

Income (loss) from continuing operations		660		(5,658	)		380			(23,813	)
Income from discontinued operations, net of tax		—		—			—			241

Net income (loss)	$	660	$	(5,658	)	$	380		$	(23,572	)

See accompanying notes.

CONSOLIDATED STATEMENTS OF OPERATIONS

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


	Nine Months Ended September 30, 2005					Nine Months Ended September 30, 2004
									Predecessor II
	Successor Company		Predecessor I Company						Company
	For the 46 Day		For the 227 Day			For the 86 Day			For the 188 Day
	Period From		Period From			Period From			Period From
	August 16, 2005 to		January 1, 2005 to			July 7, 2004 to			January 1, 2004 to
	September 30, 2005		August 15, 2005			September 30, 2004			July 6, 2004
	(As Restated See Note 2)		(As Restated See Note 2)			(As Restated See Note 2)
Revenues
Oil and gas sales	$	20,956	$	71,400		$	25,615		$	45,307
Gas gathering and marketing		1,625		6,439			2,179			5,057
Other		81		284			550			458

		22,662		78,123			28,344			50,822
Expenses
Production expense		3,284		13,423			5,500			12,122
Production taxes		524		1,901			650			1,300
Gas gathering and marketing		1,441		5,629			2,026			4,579
Exploration expense		379		2,424			1,334			3,220
General and administrative expense		381		3,835			1,100			3,672
Franchise, property and other taxes		41		129			67			115
Depreciation, depletion and amortization		4,528		21,265			8,611			9,089
Accretion expense		149		745			134			195
Derivative fair value loss		7,982		8,258			2,968			2,038
Transaction expenses		—		7,535			—			26,001

		18,709		65,144			22,390			62,331

Operating income (loss)		3,953		12,979			5,954			(11,509	)
Other expense
Interest expense		2,903		14,786			6,143			12,184

Income (loss) from continuing operations before income taxes		1,050		(1,807	)		(189	)		(23,693	)
Provision (benefit) for income taxes		390		(1,487	)		(569	)		(4,824	)

Income (loss) from continuing operations		660		(320	)		380			(18,869	)
Income from discontinued operations, net of tax		—		—			—			28,868

Net income (loss)	$	660	$	(320	)	$	380		$	9,999

See accompanying notes.

CONSOLIDATED STATEMENTS OF CASH FLOWS

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


	Nine Months Ended September 30, 2005						Nine Months Ended September 30, 2004
										Predecessor II
	Successor Company			Predecessor I Company						Company
	For the 46 Day			For the 227 Day			For the 86 Day			For the 188 Day
	Period From			Period From			Period From			Period From
	August 16, 2005 to			January 1, 2005 to			July 7, 2004 to			January 1, 2004 to
	September 30, 2005			August 15, 2005			September 30, 2004			July 6, 2004
	(As Restated See Note 2)			(As Restated See Note 2)			(As Restated See Note 2)
Cash flows from operating activities:
Net income (loss)	$	660		$	(320	)	$	380		$	9,999
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		4,528			21,265			8,611			9,723
Accretion		149			745			134			221
Gain on sale of businesses		—			—			—			(45,223	)
(Gain) loss on disposal of property and equipment		(21	)		86			37			375
Amortization of derivatives and other noncash hedging activities		7,717			12,344			1,845			2,037
Exploration expense		379			2,424			1,334			4,639
Deferred income taxes		390			(1,487	)		(569	)		10,802
Stock-based compensation		—			2,586			—			3,990
Change in operating assets and liabilities, net of effects of acquisition and disposition of businesses:
Accounts receivable and other operating assets		(1,459	)		213			3,422			(900	)
Inventories		(571	)		(85	)		112			79
Accounts payable and accrued expenses		3,427			(8,845	)		(993	)		678

Net cash provided by (used in) operating activities		15,199			28,926			14,313			(3,580	)
Cash flows from investing activities:
Disposition of businesses, net of cash		—			—			—			72,464
Proceeds from property and equipment disposals		21			5			117			247
Exploration expense		(379	)		(2,424	)		(1,334	)		(4,639	)
Additions to property and equipment		(4,942	)		(17,177	)		(4,482	)		(18,597	)
(Increase) decrease in other assets		(11	)		(34	)		(18	)		1,218

Net cash (used in) provided by investing activities		(5,311	)		(19,630	)		(5,717	)		50,693
Cash flows from financing activities:
Proceeds from senior secured notes		—			—			—			192,500
Proceeds from senior secured facility — term loan		—			—			—			100,000
Proceeds from senior secured facility		—			57,000			—			—
Sale of common stock		—			—			—			77,500
Proceeds from subordinated promissory note		—			25,000			—			—
Repayment of senior subordinated notes		—			—			(1,040	)		(223,960	)
Payment to shareholders and optionholders		—			—			—			(113,674	)
Debt issue costs		—			(2,120	)		—			(11,700	)
Settlement of derivative liabilities recorded in purchase accounting		(7,040	)		(20,440	)		(2,824	)
Repayment of senior secured facility — term loan		—			(89,500	)		(250	)		—
Repayment of senior secured facility		(5,000	)		—			—
Proceeds from revolving line of credit		—			—			—			146,636
Repayment of long-term debt and other obligations		(3	)		(84	)		—			(194,187	)
Equity contribution		—			9,000			—			—
Proceeds from stock options exercised		—			—			—			111
Repurchase of stock options		—			—			—			(283	)
Purchase of treasury stock		—			—			—			(29	)

Net cash used in financing activities		(12,043	)		(21,144	)		(4,114	)		(27,086	)

Net (decrease) increase in cash and cash equivalents		(2,155	)		(11,848	)		4,482			20,027
Cash and cash equivalents at beginning of period		6,559			18,407			21,467			1,440

Cash and cash equivalents at end of period	$	4,404		$	6,559		$	25,949		$	21,467

See accompanying notes.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

September 30, 2005

(1) Change in Control Transaction, Merger and 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 predecessors. On August 16, 2005, the former partners of the direct parent of Belden & Blake Corporation (“Company”), Capital C Energy Operations, L.P., a Delaware limited partnership (“Capital C”), completed the sale of all of the partnership interests in Capital C to certain institutional funds managed by EnerVest Management Partners, Ltd. (“EnerVest”), a Houston-based privately held oil and gas operator and institutional funds manager (the “Transaction”). The Transaction resulted in a change in control of the Company (“Change in Control”).

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

The Transaction and Merger were each accounted for as a purchase effective August 16, 2005 and July 7, 2004, respectively. The Transaction and Merger resulted in a new basis of accounting reflecting estimated fair values for assets and liabilities at August 16, 2005 and July 7, 2004. Accordingly, the financial statements for the period subsequent to August 15, 2005 are presented on the Company’s new basis of accounting, while the results of operations for prior periods reflect the historical results of the two

predecessor companies. Vertical black lines are presented to separate the financial statements of the two predecessor companies and the successor company. The “Successor Company” refers to the period from August 16, 2005 and forward. The “Predecessor I Company” refers to the period from July 7, 2004 through August 15, 2005. The “Predecessor II Company” refers to the period prior to July 7, 2004.

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


	(in thousands)
Net working capital, including cash of $8,290	$	3,811
Oil and gas properties		652,569
Goodwill		92,427
Other assets		11,319
Derivative liability		(258,417	)
Other non-current liabilities		(19,693	)
Net deferred income tax liabilities		(74,247	)
Long-term debt		(282,769	)

Equity contribution	$	125,000

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

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

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

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

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

SFAS No. 142, Goodwill and Other Intangible Assets requires that intangible assets with indefinite lives, including goodwill, be evaluated on an annual basis for impairment or more frequently if an event occurs or circumstances change could potentially result in an impairment.

The impairment test requires the allocation of goodwill and all other assets and liabilities to reporting units. As the Company has only one reporting unit the reporting unit used for testing will be the entire company. The fair value of the

reporting unit is determined and compared to the book value of that reporting unit. If the fair value of the reporting unit is less than the book value (including goodwill) then goodwill is reduced to its fair value and the amount of the writedown is charged to earnings.

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

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

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

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

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

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

The Company’s management team remained with the Company following the Change in Control Transaction with the exception of James A. Winne III, who resigned as Chairman of the Board of Directors and Chief Executive Officer of the Company, and Michael Becci, who resigned as director, President and Chief Operating Officer of the Company. Upon consummation of the Transaction, all of the members of the board of directors of the Company resigned on August 16, 2005 and Capital C replaced the board with John B. Walker, James M. Vanderhider, Mark A. Houser, Ken Mariani and Matthew Coeny. Each such individual shall serve a term ending on the date of the annual meeting of shareholders to be held in 2006.

On August 16, 2005, the board of directors of the Company appointed Mark A. Houser as Chairman and Chief Executive Officer and James M. Vanderhider as President and Chief Operating Officer. On October 3, 2005, James M. Vanderhider resigned as Chief Operating Officer and the Board of Directors of the Company appointed Ken Mariani as its Senior Vice President and Chief Operating Officer. On October 6, 2005, Robert W. Peshek resigned as Senior Vice President and Chief Financial Officer and the Board of Directors of the Company appointed James M. Vanderhider as its Chief Financial Officer.

We incurred transaction costs associated with the Transaction of $7.5 million including $500,000 of severance costs. These costs were expensed in the predecessor I company period ended August 15, 2005.

We also capitalized $2.1 million of debt financing costs and recorded obligations of $5.5 million in purchase accounting including $4.2 million of severance cost and $1.2 million of acquisition costs incurred by EnerVest.

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


	Nine months ended September 30,
	2005		2004
Total revenues	$	100,785	$	79,166
Income (loss) from continuing operations		3,842		(6,257	)

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

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 $45.2 million ($28.9 million net of tax) in the first nine 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 period ended September 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 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)

Restatements

Subsequent to the issuance of the Company’s financial statements for the quarter ended September 30, 2005, the Company determined that the financial statements contained errors, as stated, relating to the accounting for: (A) the ineffective component of non-zero value derivatives designated as cash flow hedges, (B) a derivative liability for certain derivative contracts that had settled but had not yet been paid, (C) accumulated other comprehensive income related to settled cash flow hedges, and (D) the purchase price allocation related to the Transaction, as discussed in the following paragraphs.

(A) Ineffective component of non-zero value derivatives designated as cash flow hedges. Non-zero value derivatives resulted from allocating purchase price to the derivatives in conjunction with the purchase transaction on August 16, 2005 discussed in Note 1. The Company previously did not correctly report the ineffectiveness of the non-zero value cash flow hedges in the financial statements subsequent to the merger on July 7, 2004 and the purchase transaction on August 16, 2005. The ineffectiveness of the derivative should have been recorded as an adjustment to the derivative fair value gain/loss in the consolidated statements of operations and as financing activities in the consolidated statements of cash flows. The adjustment to correct this error resulted in losses for the three months and nine months ended September 30, 2005 of $3.5 million and $668,000, respectively, which are recorded in derivative fair value gain/loss.

(B) Derivative liability for certain derivative contracts that had settled but had not yet been paid. The Company did not record a liability for derivative financial instruments that settled prior to month end, but were paid subsequent to month end. The adjustment to correct this error resulted in an increase in the derivative fair value liability at September 30, 2005 was $9.4 million. For qualifying derivatives, the adjustment was recorded in Accumulated Other Comprehensive Income. For non-qualifying derivatives, the adjustment was recorded in derivative fair value gain/loss.

(C) Accumulated other comprehensive income related to settled cash flow hedges. The Company did not properly record revenues for derivative liabilities established in purchase accounting that settled. This error occurred due to an incorrect calculation in the net change in accumulated other comprehensive income relating to cash flow hedges beginning at the date of the merger on July 7, 2004. The adjustment to correct this error resulted in an increase in non-cash oil and gas revenues for the three months and nine months ended September 30, 2005 of $6.7 million and $15.2 million respectively, with offsetting adjustments to accumulated other comprehensive income.

(D) Purchase Price Allocation Adjustment. We now have better estimates due to more information related to the purchase price allocation for the Transaction discussed in Note 1, which resulted in a decrease to prepaid expenses of $582,000, a decrease to current deferred income tax asset of $93,000, an increase in long-term deferred tax liabilities of $2.3 million, a decrease in accrued expenses of $736,000, an increase in goodwill of $3.2 million and an increase in other long-term assets of $27,000.

The Company also corrected the classification of the settlement of derivatives recorded in purchase accounting in the Consolidated Statement of Cash Flows from operating activities to financing activities.

As a result, the accompanying unaudited condensed consolidated financial statements have been restated from the amounts previously reported to correct these errors.


	Nine Months Ended September 30, 2005
	Successor Company				Predecessor I Company
	For the 46 Day Period From August 16, 2005 to				For the 227 Day Period From January 1, 2005 to
STATEMENT OF OPERATIONS:	September 30, 2005				August 15, 2005
	As Previously Reported		As Restated		As Previously Reported			As Restated
Oil and gas sales	$	16,620	$	20,956	$	60,576		$	71,400
Total revenue		18,326		22,662		67,299			78,123
Derivative fair value loss		3,263		7,982		12,307			8,258
Total operating expense		13,990		18,709		69,193			65,144
Operating income (loss)		4,336		3,953		(1,894	)		12,979
Income (loss) from continuing operations before income taxes		1,433		1,050		(16,680	)		(1,807	)
Provision (benefit) for income taxes		524		390		(7,011	)		(1,487	)
Income (loss) from continuing operations		909		660		(9,669	)		(320	)
Net income (loss)		909		660		(9,669	)		(320	)


	Nine Months Ended September 30, 2004
	Predecessor I Company						Predecessor II Company
	For the 86 Day Period From July 7, 2004 to						For the 188 Day Period From January 1, 2004 to
STATEMENT OF OPERATIONS:	September 30, 2004						July 6, 2004
	As Previously Reported			As Restated			As Previously Reported			As Restated
Oil and gas sales	$	21,896		$	25,615		$	45,307		$	45,307
Total revenue		24,625			28,344			50,822			50,822
Derivative fair value loss		4,016			2,968			2,038			2,038
Total operating expense		23,438			22,390			62,331			62,331
Operating income (loss)		1,187			5,954			(11,509	)		(11,509	)
Income (loss) from continuing operations before income taxes		(4,956	)		(189	)		(23,693	)		(23,693	)
Provision (benefit) for income taxes		(2,314	)		(569	)		(4,824	)		(4,824	)
Income (loss) from continuing operations		(2,642	)		380			(18,869	)		(18,869	)
Net income (loss)		(2,642	)		380			9,999			9,999


	Three Months Ended September 30, 2005
	Successor Company				Predecessor I Company
	For the 46 Day Period From August 16, 2005 to				For the 46 Day Period From July 1, 2005 to
STATEMENT OF OPERATIONS:	September 30, 2005				August 15, 2005
	As Previously Reported		As Restated		As Previously Reported			As Restated
Oil and gas sales	$	16,620	$	20,956	$	13,146		$	15,481
Total revenue		18,326		22,662		14,632			16,967
Derivative fair value loss		3,263		7,982		6,212			4,981
Total operating expense		13,990		18,709		23,578			22,347
Operating income (loss)		4,336		3,953		(8,946	)		(5,380	)
Income (loss) from continuing operations before income taxes		1,433		1,050		(11,956	)		(8,390	)
Provision (benefit) for income taxes		524		390		(3,983	)		(2,732	)
Income (loss) from continuing operations		909		660		(7,973	)		(5,658	)
Net income (loss)		909		660		(7,973	)		(5,658	)


	Three Months Ended September 30, 2004
	Predecessor I Company						Predecessor II Company
	For the 86 Day Period From July 7, 2004 to						For the 6 Day Period From July 1, 2004 to
STATEMENT OF OPERATIONS:	September 30, 2004						July 6, 2004
	As Previously Reported			As Restated			As Previously Reported			As Restated
Oil and gas sales	$	21,896		$	25,615		$	—		$	—
Total revenue		24,625			28,344			—			—
Derivative fair value loss		4,016			2,968			2,359			2,359
Total operating expense		23,438			22,390			31,252			31,252
Operating income (loss)		1,187			5,954			(31,252	)		(31,252	)
Income (loss) from continuing operations before income taxes		(4,956	)		(189	)		(31,252	)		(31,252	)
Provision (benefit) for income taxes		(2,314	)		(569	)		(7,439	)		(7,439	)
Income (loss) from continuing operations		(2,642	)		380			(23,813	)		(23,813	)
Net income (loss)		(2,642	)		380			(23,572	)		(23,572	)


	Nine Months Ended September 30, 2005
	Successor Company						Predecessor I Company
	For the 46 Day Period From August 16, 2005 to						For the 227 Day Period From January 1, 2005 to
	September 30, 2005						August 15, 2005
STATEMENT OF CASH FLOWS:	As Previously Reported			As Restated			As Previously Reported			As Restated

Net income (loss)	$	909		$	660		$	(9,669	)	$	(320	)
Amortization of derivatives and other noncash hedging activities		(288	)		7,717			7,359			12,344
Deferred income taxes		524			390			(7,011	)		(1,487	)
Accounts receivable and other operating assets		(877	)		(1,459	)		(369	)		213
Net cash provided by (used in) operating activities		8,159			15,199			8,486			28,926
Settlement of derivatives					(7,040	)					(20,440	)
Net cash used in financing activities		(5,003	)		(12,043	)		(704	)		(21,144	)


	Nine Months Ended September 30, 2004
	Predecessor I Company						Predecessor II Company
	For the 86 Day Period From July 7, 2004 to						For the 188 Day Period From January 1, 2004 to
	September 30, 2004						July 6, 2004
STATEMENT OF CASH FLOWS:	As Previously Reported			As Restated			As Previously Reported			As Restated

Net income (loss)	$	(2,642	)	$	380		$	9,999		$	9,999
Amortization of derivatives and other noncash hedging activities		3,788			1,845			2,037			2,037
Deferred income taxes		(2,314	)		(569	)		10,802			10,802
Net cash provided by (used in) operating activities		11,489			14,313			(3,580	)		(3,580	)
Settlement of derivatives					(2,824	)
Net cash used in financing activities		(1,290	)		(4,114	)		(27,086	)		(27,086	)

(3) Long-Term Debt


	Successor Company		Predecessor I Company
	September 30, 2005		December 31, 2004
Long-term debt consists of the following (in thousands)
Bank Revolving Credit facility	$	52,000	$	—
Senior secured facility		—		89,500
Senior secured notes		200,681		192,500
Subordinated promissory note (related party)		25,000		—
Other		93		97

		277,774		282,097
Less current portion		6		1,005

Long-term debt	$	277,768	$	281,092

Amended Credit Agreement

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

The Amended Credit Agreement provides for a revolving credit line in the aggregate principal amount of $350 million and a hedge letter of credit facility in the aggregate principal amount of $40 million. Borrowings under the Amended Credit Agreement may not exceed the borrowing base, which was initially set at $80.25 million, of which $57 million was drawn at closing on August 16, 2005. At September 30, 2005, the outstanding balance was $52 million.

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

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

The Amended Credit Agreement contains covenants that will limit the ability of the Company to, among other things, incur or guarantee additional indebtedness; create liens; pay dividends on or repurchase stock of the Company or its subsidiaries; pay principal and interest on certain subordinated debt; make certain types of investments; sell assets or merge with another entity; pledge or otherwise encumber the capital stock of the Company or its subsidiaries; or enter into transactions with affiliates. The Amended Credit Agreement also requires compliance with customary financial covenants, including a minimum interest coverage ratio, a maximum leverage ratio and a minimum current ratio. As of September 30, 2005, we were in compliance with all financial covenants and requirements under the existing credit facilities. See note 1 for discussion on the waiver received in relation to the amendments.

Borrowings under the revolving credit line will be used by the Company for general corporate purposes, including refinancing of existing indebtedness. In accordance with the terms of the Amended Credit Agreement, letters of credit issued under the hedge letter of credit commitment and any related borrowings are to be used solely to secure payment of the Company’s obligations under the J. Aron Swap (defined hereinafter).

In connection with the Company’s entry into the Amended Credit Agreement, the Company executed a Subordinated Promissory Note (“Note”) in favor of Capital C in the maximum principal amount of $94 million. Under the Note, Capital C loaned $25 million to the Company on August 16, 2005. The Note accrues interest at a rate of 10% per annum and matures on August 16, 2012. We received a fairness opinion from an unrelated financial services firm with respect to the terms of the Note made on August 16, 2005. Interest payments on the Note are due quarterly commencing September 30, 2005. In lieu of cash payments, the Company has the option to make interest payments on the Note by borrowing additional amounts against the Note. The interest payment on September 30, 2005 was paid in cash. The Note has no prepayment penalty or premium and may be prepaid in whole or in part at any time. The Note is expressly subordinate to the Company’s senior debt, which includes obligations under the Amended Credit Agreement, the J. Aron Swap (defined hereinafter) and notes issued under the Company’s Indenture dated July 7, 2004 with BNY Midwest Trust Company, as indenture trustee (“Senior Secured Notes”).

On August 16, 2005 the Company repaid the amounts outstanding under the term facility, which was a component of the $170 million Credit Agreement previously described, with cash borrowed under the Amended Credit Agreement.

ISDA Master Agreement

The Company amended and restated the Schedule and Credit Support Annex to its ISDA Master Agreement, dated as of June 30, 2004, by and between the Company and J. Aron & Company (“J. Aron Swap”), pursuant to which the Company has agreed, from time to time, to enter into cash-settled hedge transactions with J. Aron & Company, as hedge counterparty, in connection with various gas and oil commodity derivatives transactions. The amendments to the J. Aron Swap conform the terms of the Schedule and Credit Support Annex to the terms of the Amended Credit Agreement, change certain covenants and reduce the maximum amount of the letter of credit securing the hedge obligations from $55 million to $40 million. See note 1 for discussion on the waiver received in relation to the amendments.

Senior Secured Notes

The Company has 8.75% Senior Secured Notes outstanding with a principal amount of $192.5 million. As a result of the application of purchase accounting, the notes were recorded as a liability based on the estimated fair value of $200.7 million on the Transaction date.

The Transaction resulted in a change of control of the Company under the indenture governing the Senior Secured Notes. The Company commenced a tender offer for the Senior Secured Notes, as required under the indenture, on August 26, 2005. The tender offer expired on October 12, 2005 with no notes tendered.

(4) Derivatives and Hedging

The Company's 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 designated as 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 by changes in the fair value of the hedged assets, liabilities, or firm commitments that are attributable to the hedged risk, through net income (loss). Changes in the fair value of derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time as the hedged items impact earnings. Ineffective portions of a derivative instrument’s change in fair value are immediately recognized in net income (loss). Deferred gains and losses on terminated commodity hedges will be recognized as increases or decreases to oil and gas revenues during the same periods in which the underlying forecasted transactions 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. The Company assesses effectiveness at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. The Company discontinues hedge accounting prospectively if it determines that a derivative is no longer highly effective as a hedge or if it decides to discontinue the hedging relationship.

From time to time the Company 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 capital expenditure plans. The Company's derivative financial instruments take the form of swaps or collars. At September 30, 2005, the Company's derivative contracts were comprised of natural gas swaps and collars and crude oil swaps, which were placed with a major financial institution that it believes 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 are reported in expense in the consolidated statements of operations as derivative fair value loss.

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

During the first nine months of 2005 and 2004, net losses of $18.1 million ($12.4 million after tax) and $13.2 million ($8.4 million after tax), respectively, were reclassified from accumulated other

comprehensive income to earnings as the contracts settled. The fair value of open hedges in accumulated other comprehensive income decreased $255.1 million ($173.9 million after tax) in the first nine months of 2005 and decreased $64.0 million ($40.6 million after tax) in the first nine months of 2004. At September 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 $20.8 million. At September 30, 2005, the Company has partially hedged its exposure to the variability in future cash flows through December 2013.

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


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

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 assumes 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.

In September 2005, the Company entered into an interest rate swap that matures on September 16, 2008. The Company will pay a fixed 1-month LIBOR rate of 4.285% on the notional amount of $40 million and receive a variable rate based on LIBOR. This is designated as a cash flow hedge and qualifies for the shortcut method.

(5) Stock-Based Compensation

The Company measures 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 if the exercise price of the option is equal to the market price of the underlying common stock at the date of grant.

For the nine months ended September 30, 2004, all outstanding stock options were expensed due to the Merger on July 7, 2004. The Successor Company and Predecessor I company did not have any stock options.

The changes in share value of common stock and the vesting of shares are reported as adjustments to compensation expense. The changes in share value and the vesting of shares in the predecessor II company period ended July 6, 2004, resulted in a non-cash increase in compensation expense of $4.0 million. The successor company and predecessor I company did not have any stock-based compensation.

In connection with the closing of the Transaction, the Company issued approximately 34 shares of common stock to Messrs. Winne and Becci. The shares were purchased from them at the closing of the Transaction. These shares were reported as compensation expense of $2.6 million and included in the transaction expenses in the Predecessor I Company Period ended August 15, 2005.

(6) 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.

(7) Supplemental Disclosure of Cash Flow Information

Successor

Predecessor I

Predecessor II

Company

For The 46 Day

For The 227 Day

For The 91 Day

For The 188 Day

Period From

August 16, to

January 1, to

July 2, to

January 1, to

September 30,

August 15,

September 30,

July 6,

(in thousands)

2005

2004

Cash paid during the period for:

Interest

1,367

20,803

1,668

14,759

Income taxes

—

500

—

(8) Contingencies

In April 2002, the Company was 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, the Company 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 the Company's financial position, results of operations or cash flows.

(9) Related Party Transactions

In connection with the Company’s entry into the Amended Credit Agreement, the Company executed a Subordinated Promissory Note in favor of Capital C in the maximum principal amount of $94 million. Under the Note, Capital C loaned $25 million to the Company on August 16, 2005. The Note accrues interest at a rate of 10% per annum and matures on August 16, 2012. The Company received a fairness opinion from an unrelated financial services firm with respect to the terms of the Note made on August 16, 2005. Interest payments on the Note are due quarterly commencing September 30, 2005. In lieu of cash payments, the Company has the option to make interest payments on the Note by borrowing additional

amounts against the Note. The interest payment on September 30, 2005 was paid in cash. The Note has no prepayment penalty or premium and may be prepaid in whole or in part at any time. The Note is expressly subordinate to the Company’s senior debt, which includes obligations under the Amended Credit Agreement, the J. Aron Swap and notes issued under the Company’s Indenture dated July 7, 2004 with BNY Midwest Trust Company, as indenture trustee. See Note 3.

In connection with the Transaction the Company has a payable due to EnerVest in the amount of $1.3 million at September 30, 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, 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 proved 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 by changes in the fair value of the hedged assets, liabilities, or firm commitments that were attributable to the hedged risk, through net income (loss). Changes in the fair value of derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time as the hedged items impact earnings.

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

From time to time we may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage our exposure to natural gas or oil price volatility and support our capital expenditure plans. Our derivative financial instruments primarily take the form of swaps or collars. At September 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 use NYMEX-based commodity derivative contracts to hedge natural gas, because our natural gas production is sold pursuant to NYMEX-based sales contracts. Beginning July 7, 2004, we have ineffectiveness on the natural gas swaps due to purchase accounting, which created non-zero value derivatives at the time of the Merger. We 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 were highly effective and were designated as cash flow hedges through August 16, 2005. We had ineffectiveness on the crude oil swaps because the oil is sold locally at a posted price, which is different from the NYMEX price. At August 16, 2005, our oil swaps no longer qualify for cash flow hedge accounting because the assessment of effectiveness indicated that they may not be highly effective on an on-going basis. This occurred due to the application of purchase accounting to the derivatives, which created non-zero value derivatives at the time of the Transaction. The changes in the fair values of the natural gas collars since July 7, 2004, the changes in fair value of the oil swaps subsequent to August 15, 2005, the ineffective portion of the crude oil swaps through August 15, 2005 and the ineffective portion of the natural gas swaps since July 7, 2004 are recorded as “Derivative fair value gain or loss.”

Revenue Recognition

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

Asset Retirement Obligations

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 Transaction and Merger, primarily due to a lower discount rate and revised estimates of asset lives on certain oil and gas wells.

Results of Operations

The Transaction and Merger were accounted for as purchases effective August 16, 2005 and July 7, 2004, respectively. The Transaction and Merger resulted in a new basis of accounting reflecting estimated fair values for assets and liabilities at August 16, 2005 and July 7, 2004, respectively. Accordingly, the financial statements for the period subsequent to August 15, 2005 are presented on the Company’s new basis of accounting, while the results of operations for prior periods reflect the historical results of the two predecessor companies. Vertical black lines are presented to separate the financial statements of the two predecessor companies and the successor company.

The 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 and Predecessor I Company periods. 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 and gives effect to the restatement discussed in Note 2. 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 September 30,				Nine months ended September 30,
	2005		2004		2005		2004
	(Restated)		(Restated)		(Restated)		(Restated)
Production
Gas (Mmcf)		3,633		3,795		10,844		11,492
Oil (Mbbls)		87		93		264		282
Total production (Mmcfe)		4,155		4,355		12,430		13,183
Average price
Gas (per Mcf)	$	8.74	$	5.85	$	7.48	$	5.33
Oil (per Bbl)		53.80		36.60		42.52		34.50
Mcfe		8.77		5.88		7.43		5.38
Average costs (per Mcfe)
Production expense		1.43		1.53		1.34		1.34
Production taxes		0.22		0.15		0.20		0.15
Depletion		2.00		1.83		1.93		1.16
Operating margin (per Mcfe)		7.12		4.20		5.89		3.89


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

Results of Operations — Third Quarters of 2005 and 2004 Compared

Revenues

Net operating revenues increased from $27.8 million in the third quarter of 2004 to $39.5 million in the third quarter of 2005. The increase was due to higher oil and gas sales revenues of $10.8 million and higher gas gathering and marketing revenues of $865,000.

Gas volumes sold were 3.6 Bcf (billion cubic feet) in the third quarter of 2005, which was a decrease of 162 Mmcf (4%) compared to the third quarter of 2004. This decrease in gas volumes sold resulted in a decrease in gas sales revenues of approximately $950,000. Oil volumes sold decreased approximately 6,000 Bbls (7%) from 93,000 Bbls in the third quarter of 2004 to 87,000 Bbls in the third quarter of 2005, resulting in a decrease in oil sales revenues of approximately $230,000. The lower 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 $2.89 per Mcf from $5.85 in the third quarter of 2004 to $8.74 per Mcf in the third quarter of 2005, which increased gas sales revenues by approximately $10.5 million. As a result of our hedging activities, gas sales revenues were decreased by $2.0 million ($0.55 per Mcf) in the third quarter of 2005 and decreased by $447,000 ($0.12 per Mcf) in the third quarter of 2004. The average price realized for our oil increased from $36.60 per Bbl in the third quarter of 2004 to $53.80 per Bbl in the third quarter of 2005, which increased oil sales revenues by approximately $1.5 million. As a result of our hedging activities, oil sales revenues were decreased by approximately $520,000 ($5.98 per Bbl) in the third quarter of 2005 and decreased by $361,000 ($3.87 per Bbl) in the third quarter of 2004.

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 $4.20 per Mcfe in the third quarter of 2004 to $7.12 per Mcfe in the third quarter of 2005. The average price increased $2.89 per Mcfe and the average production expense decreased $0.10 per Mcfe, which were partially offset by an increase in production taxes of $0.07 per Mcfe in the third quarter of 2005 compared to the third quarter of 2004.

The increase in gas gathering and marketing revenues was due to a $656,000 increase in gas marketing revenues and a $209,000 increase in gas gathering revenues. The higher gas gathering and marketing revenues resulted primarily from higher gas prices.

Costs and Expenses

Production expense was $6.7 million in the third quarter of 2004 compared to $6.0 million in the third quarter of 2005. The average production cost was $1.53 per Mcfe in the third quarter of 2004 and $1.43 per Mcfe in the third quarter of 2005. Production expense includes non-cash expenses of $1.2 million related to stock compensation expense in the third quarter of 2004 and costs of oil sold from inventory of $644,000 in the third quarter of 2005. The average production cost after adjustment for these non-cash items was $1.25 per Mcfe in the third quarter of 2004 and $1.28 per Mcfe in the third quarter of 2005.

Production taxes increased $280,000 from $650,000 in the third quarter of 2004 to $930,000 in the third quarter of 2005. Average per unit production taxes increased from $0.15 per Mcfe in the third quarter of 2004 to $0.22 per Mcfe in the third 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 $968,000 (53%) from $1.8 million in the third quarter of 2004 to $869,000 in the third quarter of 2005. This decrease is primarily due to lower land leasing and expired lease expense and decreases in employment and compensation related expense.

General and administrative expense decreased $1.3 million (56%) from $2.3 million in the third quarter of 2004 to $1.0 million in the third quarter of 2005 primarily due to $1.2 million of stock compensation expense recorded in the third quarter of 2004 related to the Merger.

Depreciation, depletion and amortization increased by $165,000 from $8.6 million in the third quarter of 2004 to $8.8 million in the third quarter of 2005. This increase was primarily due to an increase in depletion expense. Depletion expense increased $322,000 (4%) from $8.0 million in the third quarter of 2004 to $8.3 million in the third quarter of 2005 primarily due to a higher depletion rate per Mcfe. Depletion per Mcfe increased from $1.83 per Mcfe in the third quarter of 2004 to $2.00 per Mcfe in the third quarter of 2005, primarily due to a higher cost basis resulting from purchase accounting for the Merger in 2004 and the Transaction in 2005.

Derivative fair value (gain) loss was a loss of $5.3 million in the third quarter of 2004 compared to a loss of $13.0 million in the third 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 $523,000 and $681,000 related to the ineffective portion of crude oil and natural gas swaps qualifying for hedge accounting which were recorded in the third quarters of 2004 and 2005, respectively.

Transaction expenses were recorded in the Predecessor I Company and Predecessor II Company Periods. These expenses include severance and retention payments accrued or made to employees, unamortized loan costs written off, temporary financing facility costs, costs of the consent solicitation process for our $225

million Senior Subordinated Notes due 2007 and buyer and seller investment banking fees, professional fees and other transaction related expenses.

Interest expense decreased $229,000 from $6.1 million in the third quarter of 2004 to $5.9 million in the third quarter of 2005. This decrease was due to lower average outstanding borrowings.

There was an income tax benefit of $2.3 million in the third quarter of 2005 compared to a benefit of $8.0 million in the third quarter of 2004. The decrease in the income tax benefit was primarily due to a decrease in the loss from continuing operations before income taxes in the 2005 period compared to the 2004 period, partially offset by a higher effective tax rate in the 2005 period. The effective tax rate was higher in the 2005 period due to certain nondeductible transaction-related expenses in the 2004 period which reduced the 2004 rate.

Results of Operations — Nine Months of 2005 and 2004 Compared

Revenues

Net operating revenues increased from $78.2 million in the first nine months of 2004 to $100.4 million in the first nine months of 2005. The increase was due to higher oil and gas sales revenues of $21.4 million and higher gas gathering and marketing revenues of $828,000.

Gas volumes sold were 10.8 Bcf in the first nine months of 2005, which was a decrease of 648 Mmcf (6%) compared to the first nine months of 2004. This decrease in gas volumes sold resulted in a decrease in gas sales revenues of approximately $3.5 million. Oil volumes sold decreased approximately 18,000 Bbls (6%) from 282,000 Bbls in the first nine months of 2004 to 264,000 Bbls in the first nine months of 2005 resulting in a decrease in oil sales revenues of approximately $610,000. 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 $2.15 per Mcf from $5.33 in the first nine months of 2004 to $7.48 per Mcf in the first nine months of 2005, which increased gas sales revenues by approximately $23.3 million. As a result of our hedging activities, gas sales revenues were decreased by $2.0 million ($0.19 per Mcf) in the first nine months of 2005 and decreased by $8.9 million ($0.77 per Mcf) in the first nine months of 2004. The average price realized for our oil increased from $34.50 per Bbl in the first nine months of 2004 to $42.52 per Bbl in the first nine months of 2005, which increased oil sales revenues by approximately $2.1 million. As a result of our hedging activities, oil sales revenues were decreased by approximately $2.5 million ($9.49 per Bbl) in the first nine months of 2005 and decreased by $361,000 ($1.28 per Bbl) in the first nine months of 2004.

The operating margin from oil and gas sales on a per unit basis increased from $3.89 per Mcfe in the first nine months of 2004 to $5.89 per Mcfe in the first nine months of 2005. The average price increased $2.05 per Mcfe, which was partially offset by an increase in production taxes of $0.05 per Mcfe in the first nine months of 2005 compared to the first nine months of 2004.

The increase in gas gathering and marketing revenues was due to a $550,000 increase in gas marketing revenues and a $278,000 increase in gas gathering revenues. The higher gas gathering and marketing revenues resulted primarily from higher gas prices.

Costs and Expenses

Production expense was $17.6 million in the first nine months of 2004 and $16.7 million in the first nine months of 2005. The average production cost was $1.34 per Mcfe in the first nine months of

2004 and 2005. Production expense includes non-cash expenses of $1.6 million related to stock compensation expense in the first nine months of 2004 and costs of oil sold from inventory of $595,000 in the first nine months of 2005. The average production cost after adjustment for these non-cash items was $1.21 per Mcfe in the first nine months of 2004 and $1.30 per Mcfe in the first nine months of 2005. The increase in the per Mcfe production expense was primarily due to the decreased volumes discussed above.

Production taxes increased $475,000 from $2.0 million in the first nine months of 2004 to $2.4 million in the first nine months of 2005. Average per unit production taxes increased from $0.15 per Mcfe in the first nine months of 2004 to $0.20 per Mcfe in the first nine 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 $1.8 million (38%) from $4.6 million in the first nine months of 2004 to $2.8 million in the first nine months of 2005. This decrease is primarily due to lower land leasing and expired lease expense and decreases in employment and compensation related expense.

General and administrative expense decreased $557,000 (12%) from $4.8 million in the first nine months of 2004 to $4.2 million in the first nine months of 2005 primarily due to $1.5 million of non-cash stock compensation expense recorded in the first nine months of 2004 partially offset by $489,000 related to severance agreements with two former executives in the first quarter of 2005 and an increase of $603,000 in audit and legal services related to our public filings and Sarbanes-Oxley efforts in the first nine months of 2005.

Depreciation, depletion and amortization increased $8.1 million (46%) from $17.7 million in the first nine months of 2004 to $25.8 million in the first nine months of 2005. This increase was primarily due to an increase in depletion expense. Depletion expense increased $8.7 million (57%) from $15.3 million in the first nine months of 2004 to $24.0 million in the first nine months of 2005 primarily due to a higher depletion rate per Mcfe. Depletion per Mcfe increased from $1.16 per Mcfe in the first nine months of 2004 to $1.93 per Mcfe in the first nine months of 2005, primarily due to a higher cost basis resulting from purchase accounting for the Merger in 2004 and the Transaction in 2005.

Derivative fair value (gain) loss was a loss of $5.0 million in the first nine months of 2004 compared to a loss of $16.2 million in the first nine months 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 $523,000 and $1.2 million related to the ineffective portion of crude oil and natural gas swaps qualifying for hedge accounting, which were recorded in the first nine months of 2004 and 2005, respectively.

Interest expense decreased $638,000 from $18.3 million in the first nine months of 2004 to $17.7 million in the first nine months of 2005. This decrease was due to lower blended interest rates partially offset by an increase in average outstanding borrowings.

There was an income tax benefit of $1.1 million for the first nine months of 2005 compared to a benefit of $5.4 million for the first nine months of 2004. The decrease in the income tax benefit was primarily related to a decrease in the loss from continuing operations before income taxes, partially offset by a higher effective tax rate in the 2005 period. The effective tax rate was higher in the 2005 period due to certain nondeductible transaction-related expenses in the 2004 period which reduced the 2004 rate and a change in the Ohio tax law in the 2005 period. 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. This benefit increased the effective tax rate during the 2005 period.

Discontinued operations relating to the TBR and Arrow asset sales resulted in a gain, net of tax, of $28.9 million in the first nine 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 nine month period ended September 30, 2005 were funds generated from operations and the Transaction. Funds used during this period were primarily used for operations, exploration and development expenditures, debt costs, interest expense and transaction costs. Our liquidity and capital resources are closely related to and dependent upon the current prices paid for our oil and natural gas.

The cash flow activities for the Transaction are reflected in the predecessor period in the statement of cash flows. The equity contribution and the changes in debt are reflected in the opening cash balances of the successor company. The activity in the successor period reflects the normal operational cash flows of the successor company after the Transaction was completed.

EnerVest has advised the Company that it endeavors to achieve a high rate of return for its institutional investors on its investment in the Company. Consistent with that investment goal, the Company anticipates that it will make dividends of cash flows not necessary to meet operating and capital requirements, consistent with the terms of the various agreements governing payment of dividends, including the indenture.

Our operating activities provided cash flows of $44.1 million during the first nine months of 2005 compared to $10.7 million in the first nine months of 2004. The increase was primarily due to higher cash received for oil and gas revenues (net of hedging) in 2005, lower transaction costs in 2005, partially offset by an increase in working capital in 2005.

Our investing activities used cash flows of $24.9 million during the first nine months of 2005 compared to $45.0 million provided in the first nine months of 2004. In the first nine months of 2004 the TBR and Arrow asset sales provided cash flows of $72.7 million.

Cash flows used in financing activities decreased $2.0 million in the first nine months of 2005 primarily due to the settlement of derivative liabilities recorded in purchase accounting due to the Merger and the Transaction partially offset by the refinancing and capitalization in connection with the Merger and the Transaction.

Our current ratio at September 30, 2005 was 0.55 to 1. During the first nine months of 2005, the working capital decreased $51.7 million from a deficit of $4.2 million at December 31, 2004 to a deficit of $55.9 million at September 30, 2005. The decrease was primarily due to a $70.1 million increase in the current liability for the fair value of derivatives and a $14.0 million decrease in cash partially offset by a $27.0 million increase in the deferred income taxes asset and a $4.8 million increase in accounts receivable.

Capital Expenditures

During the first nine months of 2005, we spent approximately $25 million, including exploratory dry hole expense, on our drilling activities and other capital expenditures. In the first nine months of 2005, we drilled 107 gross (104.6 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 $679,000 related to wells in progress as of September 30, 2005, including approximately $242,000 to drill 2 gross (1.5 net) exploratory Trenton Black River wells in Ohio during the second quarter of 2005. 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 $34 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 and borrowings under our revolving credit facility. At September 30, 2005, we had cash of $4.4 million and approximately $27.0 million available under our revolving credit 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 September 30, 2005, we had a $390 million credit facility comprised of a five-year $350 million revolving facility with an initial borrowing base of $80.25 million, of which $52 million was outstanding at September 30, 2005. This facility is for working capital requirements and general corporate purposes, including the issuance of letters of credit; and a five 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. Borrowings under the Amended Credit Agreement bear interest (i) at the greater of the prime rate or an adjusted federal funds rate, plus an applicable margin ranging from 0% to 0.625% based on the aggregate principal amount outstanding under the Amended Credit Agreement, or, (ii) at the Company’s option, the Eurodollar base rate plus an applicable margin ranging from 1.125% to 2.125% based on the aggregate principal amount outstanding under the Amended Credit Agreement. The full amount borrowed under the Amended Credit Agreement will mature on August 16, 2010.

Borrowings under the revolving credit line may be used by the Company for general corporate purposes, including refinancing of existing indebtedness. In accordance with the terms of the Amended Credit Agreement, letters of credit issued under the hedge letter of credit commitment and any related borrowings are to be used solely to secure payment of the Company’s obligations under the J. Aron Swap.

At September 30, 2005, the interest rate under our base rate option was 6.875%. Under our one-month LIBOR option the rate was 5.425%. At September 30, 2005, we had $41.2 million of outstanding letters of credit. At September 30, 2005, there was $52 million outstanding under the revolving credit agreement. We had $27.0 million of borrowing capacity under our revolving facility available for general corporate purposes. As of September 30, 2005, we were in compliance with all financial covenants and requirements under the existing credit facilities.

In connection with the Transaction, the Company executed a Subordinated Promissory Note (“Note”) in favor of Capital C in the maximum principal amount of $94 million. Under the Note, Capital C loaned $25 million to the Company. The Note accrues interest at a rate of 10% per annum and matures

on August 16, 2012. We received a fairness opinion from an unrelated financial services firm with respect to the terms of the Note made on August 16, 2005. Interest payments on the Note are due quarterly commencing September 30, 2005. In lieu of cash payments, the Company has the option to make interest payments on the Note by borrowing additional amounts against the Note. The Note has no prepayment penalty or premium and may be prepaid in whole or in part at any time. The Note is expressly subordinate to the Company’s senior debt, which includes obligations under the Amended Credit Agreement, the J. Aron Swap and notes issued under the Company’s Indenture dated July 7, 2004 with BNY Midwest Trust Company, as indenture trustee.

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. At September 30, 2005, we had an interest rate swap on $40 million of our revolving loan outstanding on our credit agreement. The fair value of this interest rate swap was $224,000 at September 30, 2005. We had no derivative financial instruments for managing interest rate risks in place as of September 30, 2004. If market interest rates for short-term borrowings increased 1%, the increase in interest expense in the quarter would be approximately $30,000. This sensitivity analysis is based on our financial structure at September 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 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 $1.00 per Mcf, our gas sales revenues for the quarter would decrease by $633,000, after considering the effects of the hedging contracts in place at September 30, 2005. If the price of crude oil decreased $5.00 per Bbl, oil sales revenues for the quarter would decrease by $97,000, after considering the effects of the hedging contracts in place at September 30, 2005. We had net pre-tax losses on our hedging activities reported in oil and gas sales revenue of $4.6 million in the first nine months of 2005 and $9.2 million in the first nine months of 2004. At September 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 October 31, 2005:


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

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

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 September 30, 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. 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

There were no changes in the internal control over financial reporting that occurred during the period ended September 30, 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 errors and (5) a change in our initial purchase price allocation, including deferred taxes.

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

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

Ÿ 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.

See the disclosure in the Company’s prior 10-Q for the quarterly period ended June 30, 2005, as amended, filed with the SEC.

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

On July 26, 2005, Capital C approved by written consent in lieu of an annual meeting the increase in the number of shares the Company is authorized to have outstanding from 1,500 to 3,000.

Item 6. Exhibits.

(a) Exhibits



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.


	Page
Amendment No. 1 Overview		1
PART I Financial Information
Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2005 (Successor Company) (unaudited) and December 31, 2004 (Predecessor I Company)		2
Consolidated Statements of Operations (unaudited) for the three months ended September 30, 2005 and 2004:
Successor Company for the 46 day period from August 16, 2005 to September 30, 2005; the Predecessor I Company 46 day period from July 1, 2005 to August 15, 2005 and 86 day period from July 7, 2004 to September 30, 2004; and the Predecessor II Company 6 day period from July 1, 2004 to July 6, 2004		3
Consolidated Statements of Operations (unaudited) for the nine months ended September 30, 2005 and 2004:
Successor Company for the 46 day period from August 16, 2005 to September 30, 2005; the Predecessor I Company 227 day period from January 1, 2005 to August 15, 2005 and 86 day period from July 7, 2004 to September 30, 2004; and the Predecessor II Company 188 day period from January 1, 2004 to July 6, 2004		4
Consolidated Statements of Cash Flows (unaudited) for the nine months ended:
Successor Company for the 46 day period from August 16, 2005 to September 30, 2005; the Predecessor I Company 227 day period from January 1, 2005 to August 15, 2005 and 86 day period from July 7, 2004 to September 30, 2004; and the Predecessor II Company 188 day period from January 1, 2004 to July 6, 2004		5
Notes to Consolidated Financial Statements )		6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		19
Item 3. Quantitative and Qualitative Disclosures About Market Risk		29
Item 4. Controls and Procedures		30
PART II Other Information
Item 1. Legal Proceedings		31
Item 4. Submission of Matters to a Vote of Security Holders		31
Item 6. Exhibits		31
Exhibit 31.1 Certification of CEO
Exhibit 31.2 Certification of CFO
Exhibit 32.1 Certification of CEO Section 906
Exhibit 32.2 Certification of CFO Section 906


	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, Chief Financial Officer and Director

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

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

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

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

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

	•		the 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.