UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2006

or

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

For the transition period from                                         to                                          

Commission File Number: 0-20100

BELDEN & BLAKE CORPORATION

(Exact name of registrant as specified in its charter)

Ohio	34-1686642
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
First City Tower
1001 Fannin Street, Suite 800
Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)

(713) 659-3500

(Registrant’s telephone number, including area code)

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. þ Yes    o No

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

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

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

     As of October 31, 2006, Belden & Blake Corporation had outstanding 1,534 shares of common stock, without par value, which is its only class of stock.

BELDEN & BLAKE CORPORATION

INDEX

	Page
PART I Financial Information
Item 1. Financial Statements (unaudited)
Consolidated Balance Sheets as of September 30, 2006 and December 31, 2005		1
Consolidated Statements of Operations for the three months ended September 30, 2006 and 2005:
Successor Company for the three months ended September 30, 2006; for the Successor Company 46 day period from August 16, 2005 to September 30, 2005; and the Predecessor Company 46 day period from July 1, 2005 to August 15, 2005		2
Consolidated Statements of Operations for the nine months ended September 30, 2006 and 2005:
Successor Company for the nine months ended September 30, 2006; for the Successor Company 46 day period from August 16, 2005 to September 30, 2005; and the Predecessor Company 227 day period from January 1, 2005 to August 15, 2005		3
Consolidated Statements of Cash Flows for the nine months ended September 30, 2006 and 2005:
Successor Company for the nine months ended September 30, 2006; for the Successor Company 46 day period from August 16, 2005 to September 30, 2005; and the Predecessor Company 227 day period from January 1, 2005 to August 15, 2005		4
Notes to Consolidated Financial Statements		5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		9
Item 3. Quantitative and Qualitative Disclosures About Market Risk		16
Item 4. Controls and Procedures		18
PART II Other Information
Item 1. Legal Proceedings		18
Item 1A. Risk Factors		18
Item 4. Submission of Matters to a Vote of Security Holders		18
Item 6. Exhibits		19
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

BELDEN & BLAKE CORPORATION

CONSOLIDATED BALANCE SHEETS

(unaudited, in thousands, except share data)

	September 30,			December 31,
	2006			2005
ASSETS
Current assets
Cash and cash equivalents	$	5,094		$	8,172
Accounts receivable, net		18,334			25,225
Inventories		769			1,085
Deferred income taxes		11,410			25,752
Other current assets		387			349
Fair value of derivatives		1,353			174
Total current assets		37,347			60,757
Property and equipment, at cost
Oil and gas properties (successful efforts method)		689,904			661,094
Gas gathering systems		1,293			1,593
Land, buildings, machinery and equipment		3,037			6,795
		694,234			669,482
Less accumulated depreciation, depletion and amortization		43,157			14,456
Property and equipment, net		651,077			655,026
Goodwill		91,443			91,443
Fair value of derivatives		184			285
Other assets		2,348			2,607
	$	782,399		$	810,118
LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Accounts payable	$	4,538		$	5,314
Accrued expenses		17,961			28,496
Current portion of long-term liabilities		766			776
Fair value of derivatives		28,771			65,170
Total current liabilities		52,036			99,756
Long-term liabilities
Bank and other long-term debt		95,456			52,085
Senior secured notes		165,312			200,340
Subordinated promissory note — related party		25,000			25,000
Asset retirement obligations and other long-term liabilities		20,424			18,919
Fair value of derivatives		172,529			240,129
Deferred income taxes		111,702			84,490
Total long-term liabilities		590,423			620,963
Shareholder’s equity
Common stock: without par value; 3,000 shares authorized and 1,534 shares issued		—			—
Paid in capital		125,000			125,000
Retained earnings		36,140			9,063
Accumulated other comprehensive loss		(21,200	)		(44,664	)
Total shareholder’s equity		139,940			89,399
	$	782,399		$	810,118

See accompanying notes.

1

BELDEN & BLAKE CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, in thousands)

				Three Months Ended September 30, 2005
						Predecessor
	Successor Company					Company
				For the 46 Day Period		For the 46 Day Period
	Three Months Ended			From August 16, 2005 to		From July 1, 2005 to
	September 30, 2006			September 30, 2005		August 15, 2005
Revenues
Oil and gas sales	$	31,576		$	20,956	$	15,481
Gas gathering and marketing		2,474			1,625		1,419
Other		196			81		67
		34,246			22,662		16,967
Expenses
Production expense		5,959			3,284		2,667
Production taxes		877			524		406
Gas gathering and marketing		1,946			1,441		1,209
Exploration expense		148			379		490
General and administrative expense		2,460			422		648
Depreciation, depletion and amortization		10,314			4,528		4,248
Accretion expense		314			149		163
Derivative fair value (gain) loss		(50,218	)		7,982		4,981
Transaction expenses		—			—		7,535
		(28,200	)		18,709		22,347
Operating income (loss)		62,446			3,953		(5,380	)
Other expense
Interest expense		5,846			2,903		3,010
Income (loss) before income taxes		56,600			1,050		(8,390	)
Provision (benefit) for income taxes		22,405			390		(2,732	)
Net income (loss)	$	34,195		$	660	$	(5,658	)

See accompanying notes.

2

BELDEN & BLAKE CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, in thousands)

				Nine Months Ended September 30, 2005
						Predecessor
	Successor Company					Company
				For the 46 Day		For the 227 Day
				Period From		Period From
	Nine Months Ended			August 16, 2005 to		January 1, 2005 to
	September 30, 2006			September 30, 2005		August 15, 2005
Revenues
Oil and gas sales	$	108,726		$	20,956	$	71,400
Gas gathering and marketing		8,478			1,625		6,439
Other		494			81		284
		117,698			22,662		78,123
Expenses
Production expense		16,386			3,284		13,423
Production taxes		2,466			524		1,901
Gas gathering and marketing		6,892			1,441		5,629
Exploration expense		697			379		2,424
General and administrative expense		7,962			422		3,964
Depreciation, depletion and amortization		29,039			4,528		21,265
Accretion expense		910			149		745
Derivative fair value (gain) loss		(36,742	)		7,982		8,258
Transaction expenses		—			—		7,535
		27,610			18,709		65,144
Operating income		90,088			3,953		12,979
Other expense
(Gain) on early extinguishment of debt		(436	)		—		—
Interest expense		17,153			2,903		14,786
Income (loss) before income taxes		73,371			1,050		(1,807	)
Provision (benefit) for income taxes		29,044			390		(1,487	)
Net income (loss)	$	44,327		$	660	$	(320	)

See accompanying notes.

3

BELDEN & BLAKE CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited, in thousands)

				Nine Months Ended September 30, 2005
							Predecessor
	Successor Company						Company
				For the 46 Day			For the 227 Day
				Period From			Period From
	Nine Months Ended			August 16, 2005 to			January 1, 2005 to
	September 30, 2006			September 30, 2005			August 15, 2005
Cash flows from operating activities:
Net income (loss)	$	44,327		$	660		$	(320	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		29,039			4,528			21,265
Accretion of asset retirement obligation		910			149			745
(Gain) loss on debt extinguishment of debt and disposal of property and equipment		(472	)		(21	)		86
Amortization of derivatives and other noncash hedging activities		(46,144	)		7,717			12,344
Exploration expense		697			379			2,424
Deferred income taxes		29,044			390			(1,487	)
Stock-based compensation		—			—			2,586
Change in operating assets and liabilities, net of effects of acquisition and disposition of businesses:
Accounts receivable and other operating assets		6,854			(1,459	)		213
Inventories		238			(571	)		(85	)
Accounts payable and accrued expenses		(12,792	)		3,427			(8,845	)
Net cash provided by operating activities		51,701			15,199			28,926
Cash flows from investing activities:
Proceeds from property and equipment disposals		6,891			21			5
Exploration expense		(697	)		(379	)		(2,424	)
Additions to property and equipment		(30,164	)		(4,942	)		(17,177	)
Increase in other assets		(18	)		(11	)		(34	)
Net cash used in investing activities		(23,988	)		(5,311	)		(19,630	)
Cash flows from financing activities:
Proceeds from senior secured facility		—			—			57,000
Proceeds from revolving line of credit		55,376			—			—
Repayment of revolving line of credit		(12,000	)		—			—
Proceeds from subordinated promissory note		—			—			25,000
Debt issue costs		—			—			(2,120	)
Settlement of derivative liabilities recorded in purchase accounting		(22,961	)		(7,040	)		(20,440	)
Repayment of senior secured facility — term loan		—			—			(89,500	)
Repayment of senior secured facility		—			(5,000	)		—
Repayment of senior secured notes		(33,933	)		—			—
Repayment of long-term debt and other obligations		(23	)		(3	)		(84	)
Dividends paid		(17,250	)		—			—
Equity contribution		—			—			9,000
Net cash used in financing activities		(30,791	)		(12,043	)		(21,144	)
Net decrease in cash and cash equivalents		(3,078	)		(2,155	)		(11,848	)
Cash and cash equivalents at beginning of period		8,172			6,559			18,407
Cash and cash equivalents at end of period	$	5,094		$	4,404		$	6,559

See accompanying notes.

4

BELDEN & BLAKE CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

September 30, 2006

(1) Change in Control, 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.

     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 periods subsequent to August 15, 2005 are presented on the Company’s new basis of accounting, while the results of operations for prior period reflect the historical results of the predecessor company. The “Successor Company” refers to the period from August 16, 2005 and forward. The “Predecessor Company” refers to the period from July 7, 2004 through August 15, 2005.

     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, 2006 are not necessarily indicative of the results that may be expected for the year ended December 31, 2006. 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, 2005. Certain reclassifications have been made to conform to the current presentation.

(2) Derivatives and Hedging

     As a result of the adoption of SFAS 133 in 2001, the Company recognizes all derivative financial instruments as either assets or liabilities at fair value. Derivative instruments that are not cash flow hedges must be adjusted to fair value through net income (loss). Under the provisions of SFAS 133, changes in the fair value of derivative instruments that are fair value hedges are offset against changes in the fair value of the hedged assets, liabilities, or firm commitments, through net income (loss). Changes in the fair value of derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time as the hedged items impact earnings. Ineffective portions of a derivative instrument’s change in fair value are immediately recognized in net income (loss). Deferred gains and losses on terminated hedges will be recognized as increases or decreases to oil and gas revenues or interest expense during the same periods in which the underlying forecasted transactions impact earnings.

5

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. Hedge accounting is discontinued prospectively if the Company determines that a derivative is no longer highly effective as a hedge or if the Company decides to discontinue the hedging relationship.

     From time to time the Company may enter into a combination of futures contracts, commodity derivatives and fixed-price physical commodity contracts to manage its exposure to natural gas price, crude oil price or interest rate volatility and support its capital expenditure plans. The Company’s derivative financial instruments take the form of swaps or collars. At September 30, 2006, the Company’s derivative contracts were comprised of natural gas swaps, crude oil swaps and interest rate swaps, which were placed with major financial institutions that the Company believes are a minimal credit risk. Qualifying derivative financial instruments are designated as cash flow hedges. Changes in fair value of the derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time the hedged items impact earnings. The changes in fair value of non-qualifying derivative contracts will be reported in expense in the consolidated statements of operations as derivative fair value gain or loss.

     The Company uses New York Mercantile Exchange (“NYMEX”) based commodity derivative contracts to hedge natural gas, because the Company’s natural gas production is sold pursuant to NYMEX-based sales contracts. Beginning July 7, 2004, the Company has ineffectiveness on the natural gas swaps due to purchase accounting, which created non-zero value derivatives at the time of the Merger. The Company had collar agreements that could not be redesignated as cash flow hedges because these collars were not effective due to unrealized losses at the date of the Merger. These collars qualified and were designated as cash flow hedges from their inception through the period prior to the Merger. Although these collars were not deemed to be effective hedges in accordance with the provisions of SFAS 133, the Company retained these instruments as protection against changes in commodity prices and the Company continued to record the mark-to-market adjustments on these natural gas collars, through 2005, in the Company’s income statement. The Company’s NYMEX crude oil swaps were highly effective and were designated as cash flow hedges through August 16, 2005. The Company had ineffectiveness on the crude oil swaps because the oil is sold locally at a posted price which is different from the NYMEX price. At August 16, 2005, the Company’s oil swaps no longer qualified for cash flow hedge accounting because the assessment of effectiveness indicated that they may not be highly effective on an on-going basis. This occurred due to the application of purchase accounting to the derivatives, which created non-zero value derivatives at 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, the ineffective portion of the natural gas swaps since July 7, 2004 and the changes in the fair values of the natural gas swaps since July 1, 2006 are recorded as derivative fair value gain or loss. As of July 1, 2006, we determined that our gas swaps were no longer highly effective and, therefore, could no longer be designated as cash flow hedges.

     During the first nine months of 2006 and 2005, net losses of $5.8 million ($3.8 million after tax) and $18.1 million ($12.4 million after tax), respectively, were reclassified from accumulated other comprehensive income to earnings. At September 30, 2006, the estimated net loss in accumulated other comprehensive income that is expected to be reclassified into earnings within the next 12 months is approximately $915,000. At September 30, 2006, we have partially hedged our exposure to the variability in future cash flows from oil and gas sales through December 2013.

6

     The following table reflects the natural gas and crude oil volumes and the weighted average prices under financial hedges (including settled hedges) at September 30, 2006:

	Natural Gas Swaps				Crude Oil Swaps
			NYMEX				NYMEX
			Price per				Price per
Quarter Ending	Bbtu		Mmbtu		Mbbls		Bbl
December 31, 2006		2,829	$	5.39		62	$	31.71
Year Ending
December 31, 2007		10,745	$	4.97		227	$	30.91
December 31, 2008		10,126		4.64		208		29.96
December 31, 2009		9,529		4.43		191		29.34
December 31, 2010		8,938		4.28		175		28.86
December 31, 2011		8,231		4.19		157		28.77
December 31, 2012		7,005		4.09		138		28.70
December 31, 2013		6,528		4.04		127		28.70

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

     At September 30, 2006, we had interest rate swaps in place on $80 million of our outstanding debt under our revolving credit facility through September 16, 2008. The swaps provide 1-month LIBOR fixed rates at 4.285% on $40 million and 5.160% on $40 million plus the applicable margin.

(3) 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.

(4) Supplemental Disclosure of Cash Flow Information

	Successor
	Company		Predecessor Company
			For The 46 Day		For The 227 Day
	Nine months		Period From		Period From
	ended		August 16, to		January 1, to
(in thousands)	September 30, 2006		September 30, 2005		August 15, 2005
Cash paid during the period for:
Interest	$	22,721	$	1,367	$	20,803
Income taxes		—		—		500
Non-cash investing and financing activities:
Non-cash additions to property and equipment		1,481		3,487		(682	)

(5) Contingencies

     The Company is involved in several lawsuits arising in the ordinary course of business. The Company believes that the result of such proceedings, individually or in the aggregate, will not have a material adverse effect on the Company’s financial position or the results of operations.

(6) Dispositions

     On March 31, 2006, we sold our interests in 13 Oriskany wells and the associated gas gathering system for approximately $3.3 million, which approximated the net carrying value of such assets.

7

     In August, 2006, we closed on the sale of our office building in North Canton, Ohio. Net proceeds from the sale were approximately $3.5 million, which was the carrying value of the property.

(7) Comprehensive Income

     Comprehensive income includes net income and certain items recorded directly to shareholder’s equity and classified as other comprehensive income. The table below summarizes comprehensive income and provides the components of the change in accumulated other comprehensive income for the nine month periods ended September 30, 2006 and 2005.

	Successor
	Company		Predecessor Company
			For the 46 Day			For the 227 Day
	Nine months		Period From			Period From
	ended		August 16, 2005 to			January 1, 2005
	September 30, 2006		September 30, 2005			to August 15, 2005
Comprehensive income (loss):
Net income	$	44,327	$	660		$	(320	)
Other comprehensive income (loss), net of tax:
Unrealized gain (loss) in derivative fair value		19,690		(32,138	)		(140,614	)
Reclassification adjustment for derivative loss reclassified into earnings		3,774		439			11,925
Change in accumulated other comprehensive income (loss)		23,464		(31,699	)		(128,689	)
Comprehensive income (loss)	$	67,791	$	(31,039	)	$	(129,009	)

(8) Related Party Transactions

     On March 15, 2006, the Company entered into a joint operating agreement with EnerVest Operating LLC (“EnerVest Operating”). The Company recorded expenses of approximately $4.0 million for overhead fees, $5.1 million for field labor, vehicles and district office expense, $617,000 for drilling overhead fees and $904,000 for drilling labor costs in the first nine months of 2006 related to this agreement. The Company also reimbursed EnerVest Operating for expenses of $332,000 in the first nine months of 2006 related to the transition of accounting responsibilities from the Company to EnerVest Operating’s Charleston, West Virginia office.

     The Company paid approximately $211,000 to Opportune LLP in the first nine months of 2006 for consulting services related to the Company’s amended filings and the 2005 Form 10-K. John Vanderhider, brother of James Vanderhider, the Company’s President and Chief Financial Officer, is a partner with Opportune.

     The Company paid approximately $196,000 to PetroAcct LP in the first nine months of 2006 for services related to the transition of accounting and information system responsibilities from the Company to EnerVest Operating. A subsidiary of EnerVest Management Partners, Ltd owns 50% of PetroAcct.

8

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, 2005, 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.

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 periods subsequent to July 7, 2004 and August 15, 2005 are each presented on a new basis of accounting.

     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 Company periods. These higher charges are expected to continue in subsequent accounting periods.

9

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

	Three months ended September 30,				Nine months ended September 30,
	2006		2005		2006		2005
Production
Gas (Mmcf)		3,582		3,633		10,606		10,844
Oil (Mbbls)		96		87		285		264
Total production (Mmcfe)		4,157		4,155		12,317		12,430
Average price (1)
Gas (per Mcf)	$	6.98	$	8.74	$	8.51	$	7.48
Oil (per Bbl)		68.63		53.80		64.76		42.52
Mcfe		7.60		8.77		8.83		7.43
Average costs (per Mcfe)
Production expense	$	1.43	$	1.43	$	1.33	$	1.34
Production taxes		0.21		0.22		0.20		0.20
Depletion		2.42		2.00		2.30		1.93
Operating margin (per Mcfe)		5.96		7.12		7.30		5.89

(1) The average prices presented above include non-cash amounts related to purchase accounting for the Merger and the Transaction. Excluding these non-cash amounts from oil and gas sales revenues would result in the following average prices:

	Three months ended September 30,				Nine months ended September 30,
	2006		2005		2006		2005
Gas (per Mcf)	$	6.98	$	7.31	$	6.45	$	6.25
Oil (per Bbl)		68.63		53.27		64.76		41.18
Mcfe		7.60		7.51		6.29		6.32

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 2006 and 2005 Compared

Revenues

     Operating revenues decreased from $39.5 million in the third quarter of 2005 to $34.1 million in the third quarter of 2006. The decrease in operating revenues was due to lower oil and gas sales revenues of $4.9 million and lower gas gathering and marketing revenues of $570,000.

     Gas volumes sold were 3.6 Bcf (billion cubic feet) in the third quarter of 2006, which was a decrease of 51 Mmcf (1%) compared to the third quarter of 2005. This decrease in gas volumes sold resulted in a decrease in gas sales revenues of approximately $450,000. Oil volumes sold increased approximately 9,000 Bbls (10%) from 87,000 Bbls in the third quarter of 2005 to 96,000 Bbls in the third quarter of 2006 resulting in an increase in oil sales revenues of approximately $480,000. The lower gas sales volumes are primarily due to normal production declines partially offset by production from new wells drilled during 2006. The higher oil sales volumes are primarily due to production from new wells drilled during 2006 in the Clarendon formation in Pennsylvania, which was partially offset by normal production declines.

     The average price realized for our natural gas decreased $1.76 per Mcf from $8.74 in the third quarter of 2005 to $6.98 per Mcf in the third quarter of 2006, which decreased gas sales revenues by approximately $6.3 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. The average price realized for our oil increased

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from $53.80 per Bbl in the third quarter of 2005 to $68.63 per Bbl in the third quarter of 2006, which increased oil sales revenues by approximately $1.4 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. Our oil and gas derivatives did not qualify for cash flow hedge accounting in the third quarter of 2006 and, therefore, did not affect oil and gas sales revenues.

     The operating margin from oil and gas sales (oil and gas sales revenues less production expense and production taxes) on a per unit basis decreased from $7.12 per Mcfe in the third quarter of 2005 to $5.96 per Mcfe in the third quarter of 2006. The average price decreased $1.17 per Mcfe while production taxes decreased $0.01 per Mcfe in the third quarter of 2006 compared to the third quarter of 2005. Production expense per Mcfe was consistent for both three month periods.

     Gas gathering and marketing revenues decreased from $3.0 million in the third quarter of 2005 to $2.5 million in the third quarter of 2006. The decrease was primarily due to a $559,000 decrease in gas marketing revenues due to lower gas prices in the third quarter of 2006.

Costs and Expenses

     Production expense was consistent at $6.0 million in the third quarters of 2005 and 2006. The average production cost was also consistent at $1.43 per Mcfe for both three month periods. Production expense in the third quarter of 2005 included $644,000 ($0.16 per Mcfe) related to the cost of oil sold from inventory. Production expense in the third quarter of 2006 increased primarily due to well work that was deferred from the second quarter of 2006 due to service rig availability in Michigan, general cost increases and the recording of $210,000 of costs related to an audit of expenses charged in Michigan.

     Production taxes decreased $53,000 from $930,000 in the third quarter of 2005 to $877,000 in the third quarter of 2006. Average per unit production taxes decreased from $0.22 per Mcfe in the third quarter of 2005 to $0.21 per Mcfe in the third quarter of 2006. The decreased production taxes were primarily due to lower gas sales revenues in Michigan in the third quarter of 2006 compared to the third quarter of 2005. In Michigan, production taxes are based on a percentage of revenues, excluding the effects of hedging.

     Exploration expense decreased $721,000 from $869,000 in the third quarter of 2005 to $148,000 in the third quarter of 2006. This decrease in exploration expense is primarily due to decreases in compensation related expenses and the focus on development activities in the third quarter of 2006.

     General and administrative expense increased $1.4 million from $1.1 million in the third quarter of 2005 to $2.5 million in the third quarter of 2006 primarily due to recording $1.4 million of overhead fees charged by EnerVest in the third quarter of 2006. In March 2006, we entered into a contract with EnerVest Operating for EnerVest to operate all of the oil and gas properties we operate. As a result, we pay an overhead fee to EnerVest to provide all operations management and administration related to the oil and gas properties. The overhead charges are classified as general and administrative expense.

     Depreciation, depletion and amortization increased by $1.5 million from $8.8 million in the third quarter of 2005 to $10.3 million in the third quarter of 2006. This increase was primarily due to a $1.8 million increase in depletion expense, which was partially offset by a $145,000 decrease in amortization of loan costs. Depletion expense increased from $8.3 million in the third quarter of 2005 to $10.1 million in the third quarter of 2006 primarily due to a higher depletion rate per Mcfe. Depletion per Mcfe increased from $2.00 per Mcfe in the third quarter of 2005 to $2.42 per Mcfe in the third quarter of 2006, primarily due to a higher cost basis resulting from purchase accounting for the Transaction.

     Derivative fair value (gain) loss was a loss of $13.0 million in the third quarter of 2005 compared to a gain of $50.2 million in the third quarter of 2006. The derivative fair value (gain) loss reflects the changes in fair value of certain derivative instruments that are not designated or do not qualify as cash

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flow hedges and $681,000 related to the ineffective portion of crude oil swaps and natural gas swaps qualifying for hedge accounting which were recorded in the third quarter of 2005. Beginning in the third quarter of 2006 the gas swaps no longer qualified for derivative accounting and all changes in fair value during that time were recorded in the derivative fair value (gain) loss.

     Interest expense decreased $67,000 from $5.9 million in the third quarter of 2005 to $5.8 million in the third quarter of 2006. This decrease in interest expense was primarily due to lower blended interest rates, partially offset by higher average debt outstanding.

     Income tax expense was $22.4 million in the third quarter of 2006 compared to a $2.3 million income tax benefit in the third quarter of 2005. The increase is primarily related to an increase in income before income taxes and a tax benefit of $1.1 million to adjust the recorded deferred tax account balances for Ohio during the third quarter of 2005 due to changes in Ohio tax. 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.

Results of Operations – Nine Months of 2006 and 2005 Compared
Revenues

     Operating revenues increased from $100.4 million in the first nine months of 2005 to $117.2 million in the first nine months of 2006. The increase in operating revenues was primarily due to higher oil and gas sales revenues of $16.4 million.

     Gas volumes sold were 10.6 Bcf in the first nine months of 2006, which was a decrease of 238 Mmcf (2%) compared to the first nine months of 2005. This decrease in gas volumes sold resulted in a decrease in gas sales revenues of approximately $1.8 million. The decrease in gas volumes sold was primarily due to normal production declines, which was partially offset by production from new wells drilled in 2006. Oil volumes sold increased approximately 21,000 Bbls (8%) from 264,000 Bbls in the first nine months of 2005 to 285,000 Bbls in the first nine months of 2006 resulting in an increase in oil sales revenues of approximately $890,000. The increase in oil volumes sold was primarily due to production from new wells drilled during 2006 in the Clarendon formation in Pennsylvania, which was partially offset by normal production declines.

     The average price realized for our natural gas increased $1.03 per Mcf from $7.48 in the first nine months of 2005 to $8.51 per Mcf in the first nine months of 2006, which increased gas sales revenues by approximately $10.9 million. As a result of our hedging activities, gas sales revenues were increased by $9.4 million ($0.89 per Mcf) in the first nine months of 2006 and decreased by $2.0 million ($0.19 per Mcf) in the first nine months of 2005. The average price realized for our oil increased from $42.52 per Bbl in the first nine months of 2005 to $64.76 per Bbl in the first nine months of 2006, which increased oil sales revenues by approximately $6.3 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. Our oil derivatives did not qualify for cash flow hedge accounting following the Transaction and, therefore, did not affect oil sales revenues in the first nine months of 2006. As of July 1, 2006, we determined that our gas derivatives no longer qualified for cash flow hedge accounting and, therefore, do not affect gas sales revenues from that date forward.

     The operating margin from oil and gas sales on a per unit basis increased from $5.89 per Mcfe in the first nine months of 2005 to $7.30 per Mcfe in the first nine months of 2006. The average price increased $1.40 per Mcfe and production expense decreased $0.01 per Mcfe while production taxes per Mcfe remained consistent in the first nine months of 2006 compared to the first nine months of 2005.

     Gas gathering and marketing revenues increased from $8.1 million in the first nine months of 2005 to $8.5 million in the first nine months of 2006 due to a $194,000 increase in gas marketing revenues and a $220,000 increase in gas gathering revenues as a result of higher average gas prices in the

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first nine months of 2006 compared to the first nine months of 2005.

Costs and Expenses

     Production expense decreased from $16.7 million in the first nine months of 2005 to $16.4 million in the first nine months of 2006. The average production cost decreased from $1.34 per Mcfe in the first nine months of 2005 to $1.33 per Mcfe in the first nine months of 2006. The decrease in production expense was primarily due to the impact of purchase accounting for oil inventory. In the first nine months of 2005 and 2006, we recorded $595,000 and $332,000, respectively, related to the cost of oil sold from inventory.

     Production taxes increased $41,000 from $2.4 million in the first nine months of 2005 to $2.5 million in the first nine months of 2006. Average per unit production taxes were $0.20 per Mcfe in the first nine months of 2005 and the first nine months of 2006.

     Exploration expense decreased $2.1 million from $2.8 million in the first nine months of 2005 to $697,000 in the first nine months of 2006. This decrease in exploration expense is primarily due to decreases in compensation related expenses and the focus on development activities in the first nine months of 2006.

     General and administrative expense increased $3.6 million from $4.4 million in the first nine months of 2005 to $8.0 million in the first nine months of 2006 primarily due to recording $4.0 million of overhead fees charged by EnerVest in the first nine months of 2006 which were partially offset by a $1.9 million decrease in compensation related expenses. In March 2006, we entered into a contract with EnerVest Operating for EnerVest to operate all of the oil and gas properties we operate. As a result, we pay an overhead fee to EnerVest to provide all operations management and administration related to the oil and gas properties. The overhead charges are classified as general and administrative expense. During the first nine months of 2006, we also expensed approximately $1.0 million for costs associated with the transition of accounting and administrative functions to EnerVest’s Charleston, West Virginia office and approximately $355,000 related to the restatements of our 2005 Form 10-K and Forms 10-Q.

     Depreciation, depletion and amortization increased by $3.2 million from $25.8 million in the first nine months of 2005 to $29.0 million in the first nine months of 2006. This increase was primarily due to a $4.3 million increase in depletion expense, which was partially offset by a $732,000 decrease in amortization of loan costs. Depletion expense increased from $24.0 million in the first nine months of 2005 to $28.3 million in the first nine months of 2006 primarily due to a higher depletion rate per Mcfe. Depletion per Mcfe increased from $1.93 per Mcfe in the first nine months of 2005 to $2.30 per Mcfe in the first nine months of 2006, primarily due to a higher cost basis resulting from purchase accounting for the Transaction.

     Derivative fair value (gain) loss was a loss of $16.2 million in the first nine months of 2005 compared to a gain of $36.7 million in the first nine months of 2006. The derivative fair value loss reflects the changes in fair value of certain derivative instruments that are not designated or do not qualify as cash flow hedges and $1.2 million and $548,000 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 2005 and 2006, respectively. Beginning in the third quarter of 2006 the gas swaps no longer qualified for derivative accounting and all changes in fair value during that time were recorded in the derivative fair value (gain) loss.

     Interest expense decreased $536,000 from $17.7 million in the first nine months of 2005 to $17.2 million in the first nine months of 2006. This decrease in interest expense was due to the amortization of the fair value adjustments from purchase accounting on the Senior Secured Notes, which was partially offset by higher average debt outstanding.

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     Income tax expense was $29.0 million for the first nine months of 2006 compared to a $1.1 million income tax benefit for the first nine months of 2005. The increase is primarily related to an increase in income before income taxes and as a result of changes in the Ohio tax law. On June 30, 2005 the State of Ohio enacted new tax legislation that will result in the elimination of the income and franchise tax over a four year period and it will be replaced with a gross receipts based tax. As a result of the new tax structure, we recorded a tax benefit of $1.1 million to adjust the recorded deferred tax account balances for Ohio during the third quarter of 2005.

Liquidity and Capital Resources

Cash Flows

     The primary sources of cash in the nine-month period ended September 30, 2006 have been funds generated from operations. Funds used during this period were primarily used for operations, development expenditures, derivative settlements, dividends and interest expense. Our liquidity and capital resources are closely related to and dependent upon the current prices paid for our oil and natural gas.

     Our operating activities provided cash flows of $51.8 million during the first nine months of 2006 compared to $44.1 million in the first nine months of 2005. The increase was primarily due to an increase in cash received for oil and gas revenues (net of hedging) and by changes in working capital items of $1.6 million.

     Our investing activities used cash flows of $24.0 million during the first nine months of 2006 compared to $24.9 million provided in the first nine months of 2005. The increase is due to an increase in cash received for property disposals of $6.9 million and lower exploration expense of $2.1 million, which were partially offset by an increase in capital expenditures of $8.0 million.

     Cash flows used in financing activities decreased $2.4 million in the first nine months of 2006 compared to the first nine months of 2005, primarily due to a $55.9 million increase in borrowings under the credit facility, which was partially offset by the repayment of $33.9 million of our senior secured notes and the payment of $17.3 million in dividends.

     Our current ratio at September 30, 2006 was 0.72 to 1. During the first nine months of 2006, working capital increased $24.3 million from a deficit of $39.0 million at December 31, 2005 to a deficit of $14.7 million at September 30, 2006. The increase in working capital was primarily due to a decrease in the current liability related to the fair value of derivatives of $36.4 million and a decrease in accounts payable and accrued expenses of $11.3 million, which was partially offset by a decrease in the current deferred tax asset of $14.3 million and a decrease in accounts receivable of $6.9 million.

Capital Expenditures

     During the first nine months of 2006, we spent approximately $32 million on our drilling activities and other capital expenditures. In the first nine months of 2006, we drilled 150 gross (141.7 net) development wells, all of which were successfully completed as producers in the target formation.

     We have 2 gross (1.5 net) exploratory Trenton Black River wells in Ohio that were drilled in the second quarter of 2005. The total cost to date is approximately $294,000, of which $47,000 was incurred in 2006 to secure additional leases. During the third quarter of 2006, upon further analysis of the play area and well test data, we classified the reserves discovered in one of the wells as proved. We have identified several offset drilling locations and plan to drill two or three additional wells in early 2007. Production facilities will be constructed after the potential for the field is determined. We plan to complete and test the second well during the fourth quarter of 2006. If this well is determined to be dry, the cost will be written off to exploration expense.

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     We currently expect to spend approximately $40 million during 2006 on our drilling activities and other capital expenditures. We intend to finance our planned capital expenditures through our cash on hand, available operating cash flow and borrowings under our revolving credit facility. At September 30, 2006, we had cash of $5.1 million and approximately $17.1 million available under our revolving facility. The level of our future cash flow will depend on a number of factors including the demand for and price levels of oil and gas, and the scope and success of our drilling activities. There can be no assurance that the future drilling of our proved undeveloped locations will provide additional liquidity in the future.

     At September 30, 2006, we had a $390 million credit facility (“Amended Credit Agreement”) comprised of a five-year $350 million revolving facility with a borrowing base of $113.4 million, of which $95.4 million was outstanding at September 30, 2006. Our borrowing base was increased from $90.25 million to $113.4 million on July 5, 2006 and reaffirmed on November 9, 2006. The Amended Credit Agreement 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.

     In June 2006, the Company repurchased a portion of the outstanding senior secured notes. The repurchased notes had a face value of $33.025 million and were repurchased at 102.75. A gain of $436,000 was recorded in the second quarter of 2006 in connection with the transaction.

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

     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 our capital stock; pay principal and interest on certain subordinated debt; make certain types of investments; sell assets or merge with another entity; pledge or otherwise encumber our capital stock; or enter into transactions with affiliates. The Amended Credit Agreement also requires compliance with customary financial covenants, including a minimum interest coverage ratio, a maximum leverage ratio and a minimum current ratio.

     At September 30, 2006, the interest rate under our base rate option was 8.625%. Under our one-month LIBOR option, the rate was 7.205%. At September 30, 2006, we had $40.9 million of outstanding letters of credit. At September 30, 2006, there was $95.4 million outstanding under the revolving credit agreement. We had $17.1 million of borrowing capacity under our revolving facility available for general corporate purposes. As of September 30, 2006, we were in compliance with all financial covenants and requirements under the Amended Credit Agreement.

     In connection with the Transaction, we executed a Subordinated Promissory Note (“Note”) in favor of Capital C, our parent, in the maximum principal amount of $94 million. Under the Note, Capital C loaned $25 million to us. 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. Interest payments on the Note are due quarterly. In lieu of cash payments, we have 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 our senior debt, which includes obligations under the Amended Credit

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Agreement, the J. Aron Swap and notes issued under our 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. If market interest rates for short-term borrowings increased 1%, the increase in interest expense in the quarter would be approximately $38,000. This sensitivity analysis is based on our financial structure at September 30, 2006.

     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 $3.6 million. If the price of crude oil decreased $5.00 per Bbl, oil sales revenues for the quarter would decrease by $479,000. Our oil and gas sales revenues include a pre-tax gain of $9.4 million in the first nine months of 2006 and a pre-tax loss of $4.6 million in the first nine months of 2005 related to our hedging activities. At September 30, 2006, we had hedges on a portion of our oil and gas production for the remainder of 2006 through 2013. This sensitivity analysis is based on our 2006 oil and gas sales volumes.

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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, 2006:

	Natural Gas Swaps				Crude Oil Swaps
							NYMEX
			NYMEX				Price per
Quarter Ending	Bbtu		Price per Mmbtu		Mbbls		Bbl
December 31, 2006		2,829	$	5.39		62	$	31.71
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 fair value of our oil and gas swaps was a net liability of approximately $200 million as of September 30, 2006.

     At September 30, 2006, we had interest rate swaps in place on $80 million of our outstanding debt under our revolving credit facility through September 16, 2008. The swaps provide 1-month LIBOR fixed rates at 4.285% on $40 million and 5.160% on $40 million, plus the applicable margin. The fair value of the interest rate swaps was approximately $412,000 as of September 30, 2006.

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Item 4. Controls and Procedures

          As of the end of the quarterly period ended September 30, 2006, Mark A. Houser, our Chief Executive Officer, and James M. Vanderhider, our Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer believe that:

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

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

Internal Controls Over Financial Reporting

          There has not been any change in our internal control over financial reporting that occurred during our quarterly period ended September 30, 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II OTHER INFORMATION

Item 1. Legal Proceedings.

          We are involved in several lawsuits arising in the ordinary course of business. We believe that the result of such proceedings, individually or in the aggregate, will not have a material adverse effect on our financial position or the results of operations.

Item 1A. Risk Factors

          There have been no material changes since December 31, 2005.

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

          None.

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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.

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SIGNATURES

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

	BELDEN & BLAKE CORPORATION
Date: November 13, 2006	By:	/s/ Mark A. Houser
		Mark A. Houser, Chief Executive Officer,
		Chairman of the Board of Directors and Director
Date: November 13, 2006	By:	/s/ James M. Vanderhider
		James M. Vanderhider, President,
		Chief Financial Officer and Director (Principal Financial Officer)

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