UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended September 30, 2009


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

For the transition period from ________________________ to _______________________

Commission File Number: 0-20100

BELDEN & BLAKE CORPORATION

(Exact name of registrant as specified in its charter)


Ohio		34-1686642

(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

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. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

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


Large accelerated filer o		Accelerated filer o		Non-accelerated filer þ		Smaller reporting company o

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, 2009, 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)

Condensed Consolidated Balance Sheets as of September 30, 2009 and December 31, 2008		1

Condensed Consolidated Statements of Operations: Three and nine months ended September 30, 2009 and 2008		2

Condensed Consolidated Statements of Cash Flows: Nine months ended September 30, 2009 and 2008		3

Notes to Condensed Consolidated Financial Statements		4

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		11

Item 3. Quantitative and Qualitative Disclosures About Market Risk		19

Item 4. Controls and Procedures		21

PART II Other Information

Item 1. Legal Proceedings		21

Item 1A. Risk Factors		21

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		21

Item 3. Defaults Upon Senior Securities		21

Item 4. Submission of Matters to a Vote of Security Holders		21

Item 5. Other Information		21

Item 6. Exhibits		22

Signatures		23

Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

PART I. FINANCIAL INFORMATION


Item 1.	Financial Statements

BELDEN & BLAKE CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited, in thousands, except share data)


	September 30,			December 31,
	2009			2008

ASSETS
Current assets
Cash and cash equivalents	$	7,983		$	22,816
Accounts receivable (less accumulated provision for doubtful accounts: September 30, 2009 — $353; December 31, 2008 — $312)		11,188			19,244
Inventories		845			1,004
Deferred income taxes		7,404			7,946
Other current assets		52			332
Derivative asset		988			430

Total current assets		28,460			51,772

Property and equipment, at cost
Oil and gas properties (successful efforts method)		691,334			735,398
Gas gathering systems		1,317			1,413
Land, buildings, machinery and equipment		2,562			2,836

		695,213			739,647
Less accumulated depreciation, depletion and amortization		142,569			124,175

Property and equipment, net		552,644			615,472
Long-term derivative asset		480			868
Other assets		2,173			1,352

	$	583,757		$	669,464

LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Accounts payable	$	4,649		$	3,570
Accrued expenses		12,963			19,251
Current portion of long-term liabilities		211			25,237
Derivative liability		19,708			20,520

Total current liabilities		37,531			68,578

Long-term liabilities
Bank and other long-term debt		56,431			74,938
Senior secured notes		162,548			163,302
Subordinated promissory note — related party		29,741			27,623
Asset retirement obligations and other long-term liabilities		22,743			23,863
Long-term derivative liability		80,244			101,570
Deferred income taxes		123,778			133,039

Total long-term liabilities		475,485			524,335

Shareholder’s equity
Common stock: without par value; 3,000 shares authorized and 1,534 shares issued		—			—
Paid in capital		130,000			122,500
Retained deficits		(49,494	)		(32,754	)
Accumulated other comprehensive loss		(9,765	)		(13,195	)

Total shareholder’s equity		70,741			76,551

	$	583,757		$	669,464

See accompanying notes.

BELDEN & BLAKE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, in thousands)


	Three months ended			Three months ended			Nine months ended			Nine months ended
	September 30, 2009			September 30, 2008			September 30, 2009			September 30, 2008
Revenues
Oil and gas sales	$	15,336		$	41,765		$	46,198		$	119,691
Gas gathering and marketing		1,312			3,571			4,558			9,949
Other		374			127			743			432

		17,022			45,463			51,499			130,072
Expenses
Production expense		5,123			6,565			16,342			19,543
Production taxes		246			895			799			2,491
Gas gathering and marketing		1,247			2,819			4,196			8,221
Exploration expense		849			1,614			3,164			2,173
Impairment of oil and gas properties		(1,297	)		—			23,933			2,011
General and administrative expense		1,631			2,225			5,925			6,240
Depreciation, depletion and amortization		9,066			8,517			28,414			25,876
Accretion expense		319			359			989			1,047
Derivative fair value loss (gain)		539			(134,829	)		(19,884	)		10,397

		17,723			(111,835	)		63,878			77,999

Operating (loss) income		(701	)		157,298			(12,379	)		52,073

Other (income) expense
Interest expense		5,411			5,753			15,543			17,411
Other income, net		(155	)		(119	)		(255	)		(349	)

(Loss) income before income taxes		(5,957	)		151,664			(27,667	)		35,011
(Benefit) provision for income taxes		(2,341	)		59,959			(10,927	)		13,847

Net (loss) income	$	(3,616	)	$	91,705		$	(16,740	)	$	21,164

See accompanying notes.

BELDEN & BLAKE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited, in thousands)


	Nine months ended			Nine months ended
	September 30, 2009			September 30, 2008
Cash flows from operating activities:
Net (loss) income	$	(16,740	)	$	21,164
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization		28,414			25,876
Accretion expense		989			1,047
Amortization of derivatives and other non-cash hedging activities		(16,640	)		16,685
Exploration expense		2,181			1,788
Deferred income taxes		(10,927	)		13,847
Impairment of oil and gas properties		23,933			2,011
Other non-cash items		2,704			21
Change in operating assets and liabilities
Accounts receivable and other current assets		8,336			(2,321	)
Inventories		81			127
Accounts payable and accrued expenses		(4,048	)		(569	)

Net cash provided by operating activities		18,283			79,676

Cash flows from investing activities:
Additions to property and equipment		(10,707	)		(18,722	)
Proceeds from property and equipment disposals		17,403			3,049
Exploration expense		(2,181	)		(1,788	)
(Increase) decrease in other assets		(54	)		77

Net cash provided by (used in) investing activities		4,461			(17,384	)

Cash flows from financing activities:
Repayment of long-term debt and other obligations		(43,577	)		(7	)
Debt redetermination costs		(1,470	)		—
Settlement of derivative liabilities recorded in purchase accounting		(30	)		(51,360	)
Capital contributions		7,500			—
Dividends paid		—			(2,500	)

Net cash used in financing activities		(37,577	)		(53,867	)


Net (decrease) increase in cash and cash equivalents		(14,833	)		8,425
Cash and cash equivalents at beginning of period		22,816			16,014

Cash and cash equivalents at end of period	$	7,983		$	24,439

See accompanying notes.

BELDEN & BLAKE CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

September 30, 2009

(1) Basis of Presentation

Unless the context requires otherwise or unless otherwise noted, when we use the terms “Belden & Blake,” “we,” “us,” “our” or the “Company,” we are referring to Belden & Blake Corporation and its predecessors. On August 16, 2005, the former partners of the direct parent of Belden & Blake Corporation, 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, Ltd. (“EnerVest”), a Houston-based privately held oil and gas operator and institutional funds manager.

The accompanying unaudited 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 period ended September 30, 2009 are not necessarily indicative of the results that may be expected for the year ended December 31, 2009. For further information, refer to the financial statements and footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2008.

Correction of an Error to Previously Issued Condensed Consolidated Financial Statements

Subsequent to the issuance of the quarterly report on Form 10-Q for the period ended June 30, 2009, the Company determined that the impairment recorded on our coalbed methane properties in Pennsylvania, which were sold on July 10, 2009, had not been properly adjusted to include the impact of certain assets and liabilities, including the asset retirement obligations that were conveyed in the transaction as disclosed in Note 13 on the Form 10-Q for the period ended June 30, 2009. As a result, prior period amounts have been corrected in the current period, which resulted in a reduction in the impairment of oil and gas properties of $1.3 million on a pre tax basis, and $784,000 on a post tax basis. The Company does not believe that the correction of this error is material to the Company’s condensed consolidated financial statements for the quarterly period ended September 30, 2009, or to the condensed consolidated financial statements for the prior quarterly period ended June 30, 2009.

(2) Derivatives and Hedging

Effective January 1, 2009, we adopted new FASB accounting guidance regarding disclosures about derivative instruments and hedging activities that requires enhanced disclosures about an entity’s derivative and hedging activities and how they affect an entity’s financial position, financial performance and cash flows.

From time to time, we may enter into a combination of futures contracts, commodity derivatives and fixed-price physical commodity contracts to manage our exposure to natural gas price, crude oil price or interest rate volatility and support our capital expenditure plans. Our derivative financial instruments take the form of swaps or collars. At September 30, 2009, our derivative contracts were comprised of natural gas swaps, natural gas basis differential swaps, crude oil swaps and interest rate swaps which were placed with major financial institutions that we believe are a minimal credit risk. All of our derivative instruments are currently accounted for as non-qualifying derivative contracts. The changes in fair value of non-qualifying derivative contracts are reported in expense in the consolidated statements of operations as derivative fair value (gain) loss.

We have certain derivative contracts that qualified for hedge accounting treatment in prior periods, as well as derivative contracts that were de designated in prior periods. During the three month period ended September 30, 2009 and 2008, accumulated other comprehensive income decreased $921,000 ($557,000 after tax) and $1.2 million ($703,000 after tax), respectively. During the nine month period ended September 30, 2009 and 2008, accumulated other comprehensive income decreased $5.6 million ($3.4 million after tax) and $7.4 million ($4.5 million after tax), respectively. All such amounts were reclassified into earnings during the respective periods. At September 30, 2009, the estimated net loss in accumulated other comprehensive income that is expected to be reclassified into earnings within the next 12 months is approximately $4.0 million after tax. At September 30, 2009, we have partially hedged our exposure to the variability in future cash flows through December 2013.

The following table reflects the natural gas and crude oil volumes and the weighted average prices under financial derivative contracts (including settled derivative contracts) at September 30, 2009:


	Natural Gas Swaps				Crude Oil Swaps				Natural Gas Basis Swaps
			NYMEX				NYMEX				Basis
	Bbtu		Price per Mmbtu		Mbbls		Price per Bbl		Bbtu		Differential
Quarter Ending
December 31, 2009		2,382	$	4.47		48	$	29.09		2,116	$	0.34

Year Ending
December 31, 2010		8,938	$	4.28		175	$	28.86		7,665	$	0.243
December 31, 2011		8,231		4.19		157		28.77		5,110		0.252
December 31, 2012		7,005		4.09		138		28.70		3,660		0.110
December 31, 2013		6,528		4.04		127		28.70		—		—

At September 30, 2009, we had interest rate swaps in place through September 30, 2013 covering $43.5 million of our outstanding debt under the revolving credit facility, which currently matures on August 16, 2011. The swaps provide 1-month LIBOR fixed rates of 4.10%, plus the applicable margin.

At September 30, 2009, the fair value of these derivatives was as follows:


	Asset Derivatives				Liability Derivatives
	September 30, 2009		December 31, 2008		September 30, 2009			December 31, 2008
Oil and natural gas commodity contracts	$	1,468	$	1,298	$	(97,151	)	$	(118,547	)
Interest rate swaps		—		—		(2,801	)		(3,543	)

Total fair value	$	1,468	$	1,298	$	(99,952	)	$	(122,090	)


Location of derivatives in our consolidated balance sheets:

Derivative asset	$	988	$	430	$	—		$	—
Long-term derivative asset		480		868		—			—
Derivative liability		—		—		(19,708	)		(20,520	)
Long-term derivative liability		—		—		(80,244	)		(101,570	)

	$	1,468	$	1,298	$	(99,952	)	$	(122,090	)

The net amount due under these derivative contracts may become due and payable if our Amended Credit Agreement or our senior secured notes become due and payable due to an event of default.

The following table presents the impact of derivatives and their location within the statement of operations:


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
The following amounts are recorded in Oil and gas sales:
Unrealized losses:
Oil and natural gas commodity contracts	$	(921	)	$	(1,163	)	$	(5,603	)	$	(6,340	)


The following amounts are recorded in Interest expense:
Realized losses:
Interest rate swaps	$	—		$	391		$	—		$	1,009


The following are recorded in Derivative fair value loss (gain):
Unrealized (gains) losses:
Oil and natural gas commodity contracts	$	647		$	(154,479	)	$	(21,569	)	$	(41,405	)
Interest rate swaps		(171	)		403			(740	)		323

Total		476			(154,076	)		(22,309	)		(41,082	)

Realized (gains) losses:
Oil and natural gas commodity contracts		(600	)		19,247			293			51,479
Interest rate swaps		663			—			2,132			—

Total		63			19,247			2,425			51,479

Derivative fair value loss (gain)	$	539		$	(134,829	)	$	(19,884	)	$	10,397

(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) Fair Value of Financial Instruments

Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, long-term debt and derivatives. Our derivatives are recorded at fair value (see Notes 2 and 11). The carrying amount of our other financial instruments other than debt approximates fair value because of the short-term nature of the items. The carrying value of our debt, including our senior secured notes and subordinated promissory note, approximates fair value because the interest rates approximates current market rates.

(5) Supplemental Disclosure of Cash Flow Information


	Nine months ended			Nine months ended
(in thousands)	September 30, 2009			September 30, 2008
Cash paid during the period for:
Interest	$	18,182		$	21,372
Income taxes		—			—
Non-cash investing and financing activities:
Accrued additions to property and equipment		566			2,392
Non-cash additions to debt		(2,118	)		(15	)

(6) Contingencies

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

(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 (loss) for the three and nine month periods ended September 30, 2009 and 2008.


	Three months ended			Three months ended			Nine months ended			Nine months ended
	September 30, 2009			September 30, 2008			September 30, 2009			September 30, 2008
Comprehensive (loss) income:
Net (loss) income	$	(3,616	)	$	91,705		$	(16,740	)	$	21,164
Other comprehensive income (loss), net of tax:
Unrealized gain in derivative fair value		—			18			—			409
Reclassification adjustment for derivative loss reclassified into earnings		(556	)		(939	)		(3,429	)		(4,482	)

Change in accumulated other comprehensive loss		(556	)		(921	)		(3,429	)		(4,073	)

	$	(4,172	)	$	90,784		$	(20,169	)	$	17,091

(8) Related Party Transactions

We have a joint operating agreement with EnerVest Operating LLC (“EnerVest Operating”). In the third quarter of 2009, we recorded costs of approximately $1.4 million (as general and administrative expense) for operating overhead fees, $1.4 million (as production expense) for field labor, vehicles and district office expense, $54,000 (capitalized) for drilling overhead fees and $203,000 (capitalized) for drilling labor costs related to this agreement. We recorded costs of approximately $1.7 million for operating overhead fees, $1.7 million for field labor, vehicles and district office expense, $71,000 for drilling overhead fees and $283,000 for drilling labor costs in the third quarter of 2008 related to this agreement. In the first nine months of 2009, we recorded costs of approximately $4.7 million (as general and administrative expense) for operating overhead fees, $4.4 million (as production expense) for field labor, vehicles and district office expense, $81,000 (capitalized) for drilling overhead fees and $948,000 (capitalized) for drilling labor costs related to this agreement. We recorded costs of approximately $4.9 million for operating overhead fees, $5.1 million for field labor, vehicles and district office expense, $194,000 for drilling overhead fees and $624,000 for drilling labor costs in the first nine months of 2008 related to this agreement.

We have a note in favor of our parent, Capital C in the maximum amount of $94 million. The amount due under the note at September 30, 2009 was $29.7 million. In lieu of cash payments, we have the option to make interest payments on the note by borrowing additional amounts against the note. We borrowed $2.1 million against the note for interest payments in the first nine months of 2009 and made cash payments of $2.0 million in the first nine months of 2008 to Capital C.

As of September 30, 2009, we owed EnerVest $690,000 and EnerVest Operating owed us $401,000. These amounts are included in accounts payable on the condensed consolidated balance sheet.

(9) Impairment of Oil and Gas Properties

For the periods ended September 30, 2009 and 2008, we reviewed our oil and gas properties for impairment as prescribed by FASB accounting guidance related to the accounting for the impairment or disposal of long-lived assets. As a result of this evaluation, we recorded an impairment of $2.0 million during the second quarter of 2008 to proved properties in the Utica Shale formation in Ohio. In the second quarter of 2009, we recorded an impairment of $25.2 million to our coalbed methane properties in Pennsylvania. In the third quarter of 2009, we corrected the amount recorded in the second quarter of 2009 by reducing it by $1.3 million (see Note 1).

(10) New Accounting Standards

In December 2007, the FASB issued new accounting guidance regarding the accounting for business combinations. This new guidance retains the acquisition method of accounting used in business combinations and establishes principles and requirements for the recognition and measurement of assets, liabilities and goodwill, including the requirement that most transaction and restructuring costs related to the acquisition be expensed. In addition, this guidance requires disclosures to enable users to evaluate the nature and financial effects of the business combination. We adopted this new guidance on January 1, 2009.

In March 2008, the FASB issued new accounting guidance requiring enhanced disclosures about an entity’s derivative and hedging activities and their effect on an entity’s financial position, financial performance and cash flows. This new guidance is effective for fiscal years and interim periods beginning after November 15, 2008. We adopted the new accounting guidance on January 1, 2009 (see Note 2).

In December 2008, the SEC published Modernization of Oil and Gas Reporting, a revision to its oil and natural gas reporting disclosures. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (i) report the independence and qualifications of its reserves preparer or auditor; (ii) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (iii) report oil and natural gas reserves using an average price based upon the prior 12 month period rather than year end prices. The new disclosure requirements are effective for registration statements filed on or after January 1, 2010, and for annual reports on Forms 10-K and 20-F for fiscal years ending on or after December 31, 2009. We will adopt the new disclosure requirements for our Form 10-K for the year ending December 31, 2009.

In April 2009, the FASB issued new accounting guidance to require disclosures about the fair value of financial instruments for interim reporting periods of publicly traded companies as well as in annual financial statements. This new guidance is effective for interim or financial periods ending after June 15, 2009. We adopted this new guidance in our interim period ended June 30, 2009 (see Notes 2 and 11).

In May 2009, the FASB issued new accounting guidance to establish standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. This new guidance is effective for interim or financial periods ending after June 15, 2009. We adopted this new guidance in our interim period ended June 30, 2009 (see Note 13).

In June 2009, the FASB issued The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principle (the “Codification”). On September 15, 2009, the Codification became the source of authoritative U.S. generally accepted accounting principles (“GAAP”) recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative GAAP for SEC registrants. The Codification has superseded all then existing non-SEC accounting and reporting standards. All other non grandfathered non-SEC accounting literature not included in the Codification has become non authoritative.

No other new accounting pronouncements issued or effective during the nine months ended September 30, 2009 have had or are expected to have a material impact on our condensed consolidated financial statements.

(11) Fair Value Measurements

FASB accounting guidance establishes a valuation hierarchy for disclosure of the inputs to valuation used to measure fair value. This hierarchy prioritizes the inputs into the following three levels:

• Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.

• Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration.

• Level 3 inputs are unobservable inputs based on our own assumptions used to measure assets and liabilities at fair value.

A financial asset or liability’s classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement.

The following table presents the fair value hierarchy table for our assets and liabilities that are required to be measured at fair value on a recurring basis:

Fair Value Measurements at September 30, 2009 Using:

Quoted Prices in

Significant

Active Markets

Other

Significant

for Identical

Observable

Unobservable

Assets

Inputs

Total Carrying Value

(Level 1)

(Level 2)

(Level 3)

Derivative instruments

(98,484

)

—

(98,484

)

—

Our derivative instruments consist of over-the-counter (“OTC”) contracts which are not traded on a public exchange. These derivative instruments are indexed to active trading hubs for the underlying commodity, and are OTC contracts commonly used in the energy industry and offered by a number of financial institutions and large energy companies.

As the fair value of these derivative instruments is based on inputs using market prices obtained from independent brokers or determined using quantitative models that use as their basis readily observable market parameters that are actively quoted and can be validated through external sources, including third-party pricing services, brokers and market transactions, we have categorized these derivative instruments as Level 2.

Our estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty and cannot be determined with precision. There were no changes in valuation techniques or related inputs in the three or nine months ended September 30, 2009.

(12) Asset Retirement Obligations

If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be made, we record an asset retirement obligation (“ARO”) and capitalize the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis. The changes in the aggregate ARO are as follows:


Balance as of December 31, 2008	$	23,885
Accretion expense		989
Liabilities incurred		13
Liabilities settled		(2,077	)
Revisions in estimated cash flows		—

Balance as of September 30, 2009	$	22,810

As of September 30, 2009 and December 31, 2008, $202,000 and $229,000, respectively, of our ARO is classified as current.

(13) Subsequent Event

On October 23, 2009, we received an equity contribution from our parent in the amount $12.5 million which was used to repay $12.5 million under our Amended Credit Agreement on October 26, 2009.

On November, 6 2009, we completed the sale of undeveloped acreage in Bradford County, Pennsylvania for approximately $35.8 million.

We evaluated subsequent events through November 12, 2009, the date of our condensed consolidated financial statements were issued.

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,” “continue,” “estimate,” “plan,” “outlook,” “may,” “future,” “projection,” “likely,” “possible,” “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, including current economic and financial market crisis, 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, 2008, 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.

Impact of the Current Financial and Credit Markets

The U.S. and other world economies have been in a recession which has lasted well into 2009 and economic conditions remain uncertain. Additionally, the financial and credit markets are undergoing unprecedented disruptions. Many financial institutions have liquidity concerns prompting intervention from governments. Our exposure to the disruptions in the financial markets includes our credit facility and investments exposure.

Our credit facility extends through August 16, 2011. If the disruption in the financial markets continues for an extended period of time, replacement or amendment of the credit facility may be more expensive.

We have reviewed the creditworthiness and believe our hedge counterparties to be strong and creditworthy. However, current disruptions occurring in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair their ability to perform under the terms of the hedging contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

While oil and gas prices have strengthened in recent months, they remain unstable and are expected to be volatile in the future. Continued lower commodity prices will reduce the Company’s cash flows from operations.

Results of Operations

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,
	2009		2008		2009		2008
Production
Gas (Mmcf)		2,941		3,308		9,288		9,902
Oil (Mbbls)		83		80		246		246
Total production (Mmcfe)		3,440		3,789		10,762		11,377
Average price (1)
Gas (per Mcf)	$	3.39	$	9.83	$	3.58	$	9.40
Oil (per Bbl)		64.51		115.10		52.61		108.19
Mcfe		4.46		11.02		4.29		10.52
Average costs (per Mcfe)
Production expense	$	1.49	$	1.73	$	1.52	$	1.72
Production taxes		0.07		0.24		0.07		0.22
Depletion		2.61		2.22		2.61		2.25


(1)		The average prices presented above include non-cash amounts related to derivative contracts. 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,
	2009		2008		2009		2008
Gas (per Mcf)	$	3.70	$	10.18	$	4.19	$	10.04
Oil (per Bbl)		64.51		115.10		52.61		108.19
Mcfe		4.73		11.33		4.81		11.08

Results of Operations — Third Quarters of 2009 and 2008 Compared

Revenues

Operating revenues decreased from $45.5 million in the third quarter of 2008 to $17.0 million in the third quarter of 2009. The decrease in operating revenues was primarily due to lower oil and gas sales revenues of $26.4 million and lower gas gathering and marketing revenues of $2.3 million. The decreased oil and gas sales revenues were primarily due to a decrease of $23.2 million related to lower prices for oil and natural gas and a $3.6 million decrease due to lower gas sales volumes.

Gas volumes sold were 2.9 Bcf in the third quarter of 2009, which was a decrease of 367 Mmcf (11%) compared to the third quarter of 2008. This decrease in gas volumes sold resulted in a decrease in gas sales revenues of approximately $3.6 million. Oil volumes sold increased approximately 3,000 Bbls (4%) from 80,000 Bbls in the third quarter of 2008 to 83,000 Bbls in the third quarter of 2009 resulting in an increase in oil sales revenues of approximately $330,000. The lower gas sales volumes are primarily due to normal production declines and the sale of the coalbed methane assets in Pennsylvania which are partially offset by production from new wells drilled and wells reworked during 2008 and 2009.

The average price realized for our natural gas decreased $6.44 per Mcf from $9.83 in the third quarter of 2008 to $3.39 per Mcf in the third quarter of 2009, which reduced gas sales revenues by approximately $19.0 million. As a result of our qualified hedging and derivative financial instrument activities, gas sales revenues were lower by $921,000 ($0.31 per Mcf) in the third quarter of 2009 and lower by $1.2 million ($0.35 per Mcf) in the third quarter of 2008 than if our gas price was not affected by derivative financial instruments. The average price realized for our oil decreased from $115.10 per Bbl in the third quarter of 2008 to $64.51 per Bbl in the third quarter of 2009, which reduced oil sales revenues by approximately $4.2 million.

Gas gathering and marketing revenues decreased from $3.6 million in the third quarter of 2008 to $1.3 million in the third quarter of 2009. The decrease was due to a $1.7 million decrease in gas marketing revenues and a $600,000 decrease in gas gathering revenues as a result of lower average gas prices in the third quarter of 2009 compared to the third quarter of 2008.

Costs and Expenses

Production expense decreased $1.5 million from $6.6 million in the third quarter of 2008 to $5.1 million in the third quarter of 2009. The average production cost decreased from $1.73 per Mcfe in the third quarter of 2008 to $1.49 per Mcfe in the third quarter of 2009. The decrease in production expense was due to decreases in labor costs, gas processing costs, well work activity, the sale of the coalbed methane assets in Pennsylvania and general decreases in third party service costs.

Production taxes decreased $649,000 from $895,000 in the third quarter of 2008 to $246,000 in the third quarter of 2009. Average per unit production taxes decreased from $0.24 per Mcfe in the third quarter of 2008 to $0.07 per Mcfe in the third quarter of 2009. The decreased production taxes were primarily due to lower oil and gas prices in Michigan in the third quarter of 2009 compared to the third quarter of 2008. In Michigan, production taxes are based on a percentage of revenues, excluding the effects of hedging.

Gas gathering and marketing expenses decreased from $2.8 million in the third quarter of 2008 to $1.2 million in the third quarter of 2009. The decrease was primarily due to a $1.7 million decrease in gas marketing expenses as a result of lower average gas prices in the third quarter of 2009 compared to the third quarter of 2008.

Exploration expense decreased $765,000 from $1.6 million in the third quarter of 2008 to $849,000 in the third quarter of 2009. The decrease in exploration expense was primarily due to a decrease in dry hole expense.

Impairment of oil and gas properties was a credit of $1.3 million in the third quarter of 2009 due to an adjustment to the impairment of coalbed methane properties in Pennsylvania properties which was recorded in the second quarter of 2009. These properties were sold in the third quarter of 2009.

General and administrative expense decreased $594,000 from $2.2 million in the third quarter of 2008 to $1.6 million in the third quarter of 2009. The decrease was primarily due to lower overhead fees incurred to EverVest and lower franchise tax expense.

Depreciation, depletion and amortization increased by $549,000 from $8.5 million in the third quarter of 2008 to $9.1 million in the third quarter of 2009. This increase was primarily due to a $560,000 increase in depletion expense. Depletion per Mcfe increased from $2.22 per Mcfe in the third quarter of 2008 to $2.61 per Mcfe in the third quarter of 2009, primarily due to decreased reserves volumes at June 30, 2009 due to lower oil and gas prices.

Derivative fair value loss (gain) was a loss of $539,000 in the third quarter of 2009 compared to a gain of $134.8 million in the third quarter of 2008. The derivative fair value loss (gain) reflects the changes in fair value of certain derivative instruments that are not designated or do not qualify as cash flow hedges. The change was due to the fluctuation of oil and gas prices during those periods.

Interest expense decreased $342,000 from $5.8 million in the third quarter of 2008 to $5.4 million in the third quarter of 2009. This decrease in interest expense was primarily due to lower debt levels partially offset by higher blended interest rates.

Income tax expense was a benefit of $2.3 million in the third quarter of 2009 compared to expense of $60.0 million in the third quarter of 2008. The change in income tax expense was primarily due to a decrease in income before income taxes. The decrease in income before income taxes was primarily due to the change in the derivative fair value loss (gain) and the decrease in oil and gas sales revenues.

Results of Operations — Nine Months of 2009 and 2008 Compared

Revenues

Operating revenues decreased from $130.1 million in the first nine months of 2008 to $51.5 million in the first nine months of 2009. The decrease in operating revenues was primarily due to lower oil and gas sales revenues of $73.5 million and lower gas gathering and marketing revenues of $5.4 million. The decreased oil and gas sales revenues were due to a decrease of $67.7 million related to lower prices for oil and natural gas and a $5.8 million decrease in revenues due to lower gas sales volumes.

Gas volumes sold were 9.3 Bcf in the first nine months of 2009, which was a decrease of 613 Mmcf (6%) compared to the 9.9 Bcf sold in the first nine months of 2008. This decrease in gas volumes sold resulted in a decrease in gas sales revenues of approximately $5.8 million. Oil volumes sold were 246,000 Bbls in the first nine months of 2008 and 2009. The decrease in gas sales volumes was primarily due to normal production declines and the sale of the coalbed methane assets in Pennsylvania, which were partially offset by production from new wells drilled and wells reworked in 2008 and 2009.

The average price realized for our natural gas decreased $5.82 per Mcf from $9.40 in the first nine months of 2008 to $3.58 per Mcf in the first nine months of 2009, which reduced gas sales revenues by approximately $54.1 million. As a result of our qualified hedging and derivative financial instrument activities, gas sales revenues were lower by $5.6 million ($0.61 per Mcf) in the first nine months of 2009 and lower by $6.3 million ($0.64 per Mcf) in the first nine months of 2008 than if our gas price was not affected by derivative financial instruments. The average price realized for our oil decreased from $108.19 per Bbl in the first nine months of 2008 to $52.61 per Bbl in the first nine months of 2009, which reduced oil sales revenues by approximately $13.6 million.

Gas gathering and marketing revenues decreased from $9.9 million in the first nine months of 2008 to $4.6 million in the first nine months of 2009 due to a $4.2 million decrease in gas marketing revenues and a $1.2 million decrease in gas gathering revenues as a result of lower average gas prices in the first nine months of 2009 compared to the first nine months of 2008.

Costs and Expenses

Production expense decreased from $19.5 million in the first nine months of 2008 to $16.3 million in the first nine months of 2009. The average production cost decreased from $1.72 per Mcfe in the first nine months of 2008 to $1.52 per Mcfe in the first nine months of 2009. The decrease in production expense was primarily due to decreases in labor costs, gas processing costs, well work activity, the sale of the coalbed methane assets in Pennsylvania and general decreases in third party service costs.

Production taxes decreased from $2.5 million in the first nine months of 2008 to $799,000 in the first nine months of 2009. Average per unit production taxes decreased from $0.22 per Mcfe in the first nine months of 2008 to $0.07 per Mcfe in the first nine months of 2009. The decreased production taxes are primarily due to lower oil and gas prices in the first nine months of 2009 in Michigan, where production taxes are based on a percentage of revenues, excluding the effects of hedging.

Gas gathering and marketing expenses decreased $4.0 million from $8.2 million in the first nine months of 2008 to $4.2 million in the first nine months of 2009, primarily due to a $4.2 million decrease in gas marketing expenses as a result of lower average gas prices in the first nine months of 2009 compared to the first nine months of 2008.

Exploration expense increased $1.0 million from $2.2 million in the first nine months of 2008 to $3.2 million in the first nine months of 2009. The increase in exploration expense was primarily due to the noncash write-off of costs related to expired undeveloped leases in the first quarter of 2009, higher lease rental expense and seismic costs related to the evaluation of Knox formation drilling potential on recently acquired acreage in Ohio.

Impairment of oil and gas properties was $2.0 million in the first nine months of 2008 due to the impairment of properties in the Utica Shale formation in Ohio. Impairment of oil and gas properties was $23.9 million in the first nine months of 2009 due to the impairment of coalbed methane properties in Pennsylvania which were sold in the third quarter of 2009.

General and administrative expense decreased from $6.2 million in the first nine months of 2008 to $5.9 million in the first nine months of 2009. This decrease was primarily due to lower third party service fees, lower overhead fees paid to EnerVest and lower franchise tax expense, which was partially offset by higher bad debt expense.

Depreciation, depletion and amortization increased by $2.5 million from $25.9 million in the first nine months of 2008 to $28.4 million in the first nine months of 2009. This increase was primarily due to a $2.6 million increase in depletion expense, which was primarily due to a decrease in reserves volumes at June 30, 2009 due to lower oil and gas prices. Depletion per Mcfe increased from $2.25 per Mcfe in the first nine months of 2008 to $2.61 in the first nine months of 2009.

Derivative fair value loss (gain) was a gain of $19.9 million in the first nine months of 2009 compared to a loss of $10.4 million in the first nine months of 2008. The derivative fair value loss (gain) reflects the changes in fair value of certain derivative instruments that are not designated or do not qualify as cash flow hedges. The change was due to the fluctuation of oil and gas prices during those periods.

Interest expense decreased $1.9 million from $17.4 million in the first nine months of 2008 to $15.5 million in the first nine months of 2009. This decrease in interest expense was primarily due to lower blended interest rates and lower debt levels.

Income tax expense was a benefit of $10.9 million in the first nine months of 2009 compared to expense of $13.8 million in the first nine months of 2008. The change in income tax expense was primarily due to a decrease in income before income taxes. The decrease in income before income taxes was primarily due to the change in the derivative fair value loss (gain), lower oil and gas sales revenues and an increase in the impairment of oil and gas properties.

Liquidity and Capital Resources

Cash Flows

The primary sources of cash in the nine month period ended September 30, 2009 have been funds generated from operations and proceeds from asset sales. Funds used during this period were primarily used for operations, development expenditures, debt repayment and interest expense. Our liquidity and capital resources are closely related to and dependent upon the current prices paid for our oil and gas.

Our operating activities provided cash flows of $18.3 million during the first nine months of 2009 compared to $79.7 million in the first nine months of 2008. The decrease was primarily due to a decrease in oil and gas revenues (net of hedging) which was partially offset by an increase in the change in working capital items of $7.1 million.

Our investing activities provided cash flows of $4.5 million during the first nine months of 2009 compared to $17.4 million used in the first nine months of 2008. The increase was due to a decrease in capital expenditures of $8.0 million and an increase in cash received for property and equipment disposals of $14.4 million.

Cash flows used in financing activities decreased $16.3 million in the first nine months of 2009 from $53.9 million in the first nine months of 2008 to $37.6 million in the first nine months of 2009. The decrease was primarily due to a decrease of $51.3 million in derivative settlements and an increase in capital contributions of $7.5 million which was partially offset by an increase in the repayment of long term debt of $43.6 million and an increase in debt financing costs of $1.5 million.

Our current ratio at September 30, 2009 was 0.76 to 1. During the first nine months of 2009, working capital increased $7.7 million from a deficit of $16.8 million at December 31, 2008 to a deficit of $9.1 million at September 30, 2009. The increase in working capital was primarily due to a decrease in the current portion of long term liabilities of $25.0 million, a decrease in accrued expenses of $6.3 million, which was partially offset by a $14.8 million decrease in cash, a $8.0 million decrease in accounts receivable and an increase in accounts payable of $1.1 million.

Capital Expenditures

During the first nine months of 2009, we spent approximately $10.7 million on our drilling activities and other capital expenditures. In the first nine months of 2009, we drilled 3 gross (1.7 net) wells, which were all completed as producing wells in the target formation. We also performed major workovers on 15 wells during the first nine months of 2009.

We currently expect to spend approximately $12.7 million during 2009 on our drilling activities and other capital expenditures. We intend to finance our planned capital expenditures through our cash on hand and available operating cash flow. At September 30, 2009, we had cash of $8.0 million and approximately $7.5 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 and workover activities. There can be no assurance that the future drilling of our proved undeveloped locations will provide adequate liquidity in the future.

Financing and Credit Facilities

On September 25, 2009, Belden & Blake Corporation entered into the Fifth Amendment to Credit Agreement. The Credit Agreement was amended to (1) reduce the borrowing base to $65 million, (2) extend the termination date by one year to August 16, 2011, (3) decrease the aggregate amount of the revolving commitments to $100 million, and (4) make certain other amendments to the Credit Agreement.

At September 30, 2009, we had an Amended Credit Agreement comprised of a five-year $100 million revolving facility with a borrowing base of $65 million, of which $56.4 million was outstanding at September 30, 2009. On October 23, 2009, we received an equity contribution from our parent in the amount of $12.5 million which was used to repay $12.5 million under our Amended Credit Agreement on October 26, 2009. 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, an adjusted federal funds rate or an adjusted Eurodollar rate, plus an applicable margin ranging from 1.0% to 2.0% based on the aggregate principal amount outstanding under the Amended Credit Agreement, or, (ii) at our option, the Eurodollar base rate plus an applicable margin ranging from 2.5% to 3.5% 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, 2011.

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

The Amended Credit Agreement contains covenants that will limit or prohibit our ability to, among other things, incur or guarantee additional indebtedness; create liens; pay dividends on or repurchase 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.

Changes in oil and gas prices significantly affect our revenues, financial condition, cash flows and borrowing capacity. Markets for oil and gas have historically been volatile and we expect this trend to continue. Prices for oil and gas may fluctuate in response to changes in supply and demand, market uncertainty, seasonal, political and other factors beyond our control. We are unable to accurately predict the prices we will receive for our oil and gas. Accordingly, any significant or sustained declines in oil and gas prices will materially adversely affect our financial condition, operating results, liquidity and ability to obtain additional financing or to refinance our Amended Credit Agreement upon maturity. Continued or prolonged low oil and gas prices may also result in non-compliance with our financial covenants in our Amended Credit Agreement. If we were not in compliance with the covenants in a future period, an event of default may occur which could cause all outstanding debt under the Amended Credit Agreement, the senior secured notes and our derivative contracts to be due and payable. We expect to maintain compliance with the covenants through 2009 and 2010.

At September 30, 2009, we were in compliance with our covenants under the Amended Credit Agreement.

At September 30, 2009, we had $41.1 million of outstanding letters of credit. At September 30, 2009, there was $56.4 million outstanding under the revolving credit agreement. We had $7.5 million of borrowing capacity under our revolving facility available for general corporate purposes.

In connection with our entry into the Amended Credit Agreement, we executed a Subordinated Promissory Note (“Subordinated Note”) in favor of Capital C in the maximum principal amount of $94 million. Under the Subordinated Note, Capital C loaned $25 million to us on August 16, 2005. As of September 30, 2009, the current amount due under the Subordinated Note was $29.7 million. The Subordinated Note accrues interest at a rate of 10% per annum and matures on August 16, 2012. In lieu of cash payments, we have the option to make interest payments on the Subordinated Note by borrowing additional amounts against the Subordinated Note. The Subordinated Note has no prepayment penalty or premium and may be prepaid in whole or in part at any time. Pursuant to our Amended Credit Agreement cash payments for principal or interest on the Subordinated Note are prohibited. The Subordinated Note is subordinate to our senior debt, which includes obligations under the Amended Credit Agreement, a long-term hedging program with J. Aron under a master agreement and related confirmations and documentation and senior secured notes issued under our Indenture dated July 7, 2004 with BNY Midwest Trust Company, as indenture trustee.

New Accounting Standards

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, 2009, we had interest rate swaps in place covering $43.5 million of our outstanding balance on the revolving credit agreement. The fair value of these interest rate swaps was an unrealized loss of $2.8 million at September 30, 2009. If market interest rates for short-term borrowings increased 1%, the increase in interest expense in the first nine months of 2009 would be approximately $603,000. The impact of the interest rate increase on our cash flows would be significantly less than this amount due to the interest rate swaps in place. The impact of the interest rate increase would reduce our cash flows by approximately $94,000. This sensitivity analysis is based on our financial structure at September 30, 2009.

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 and gas production selling NYMEX-based commodity derivative contracts which are placed with major financial institutions that we believe are minimal credit risks. The contracts may take the form of futures contracts, swaps or options. At September 30, 2009, we had derivatives covering a portion of our oil and gas production from 2009 through 2013. Our oil and gas sales revenues included a net pre-tax loss of $1.2 million in the third quarter of 2008 and a net pre-tax loss of $921,000 in the third quarter of 2009 relating to hedges which previously qualified for hedge accounting and were subsequently de-designated. Our oil and gas sales revenues included a net pre-tax loss of $6.3 million in the first nine months of 2008 and a net pre-tax loss of $5.6 million in the first nine months of 2009 on our qualified hedging activities.

If gas prices decreased $1.00 per Mcf, our gas sales revenues for the first nine months of 2009 would decrease by approximately $9.3 million. If the price of crude oil decreased $10.00 per Bbl, our oil sales revenues for the first nine months of 2009 would decrease by approximately $2.5 million. The impact of these price decreases on our cash flows would be significantly less than these amounts due to our oil and gas derivatives. Price decreases of $1.00 per Mcf and $10.00 per Bbl would decrease cash flows from the sale of oil and gas for the first nine months of 2009 by approximately $3.2 million after considering the effects of the derivative contracts in place as of September 30, 2009. This sensitivity analysis is based on our first nine months 2009 oil and gas sales volumes.

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, 2009, which has not changed since September 30, 2009:


	Natural Gas Swaps				Crude Oil Swaps				Natural Gas Basis Swaps
			NYMEX				NYMEX				Basis
	Bbtu		Price per Mmbtu		Mbbls		Price per Bbl		Bbtu		Differential
Quarter Ending
December 31, 2009		2,382	$	4.47		48	$	29.09		2,116	$	0.34

Year Ending
December 31, 2010		8,938	$	4.28		175	$	28.86		7,665	$	0.243
December 31, 2011		8,231		4.19		157		28.77		5,110		0.252
December 31, 2012		7,005		4.09		138		28.70		3,660		0.110
December 31, 2013		6,528		4.04		127		28.70		—		—

The fair value of our oil and gas swaps was a net liability of approximately $95.7 million as of September 30, 2009.

At September 30, 2009, we had interest rate swaps in place covering $43.5 million of our outstanding debt under the revolving credit facility. On September 29, 2009, we amended the existing swaps to cover $43.5 million of our outstanding debt through September 30, 2013. The amended swaps provide 1-month LIBOR fixed rates of 4.10%, plus the applicable margin. The fair value of these interest rate swaps was an unrealized loss of $2.8 million at September 30, 2009.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We have established and maintain a system of disclosure controls and procedures to provide reasonable assurances that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Based on the evaluation of our disclosure controls and procedures as of the end of the period covered by this report, the principal executive officer and principal financial officer of Belden & Blake Corporation have concluded that our disclosure controls and procedures as of September 30, 2009 were effective, at a reasonable assurance level, in ensuring that the information required to be disclosed by us in reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.

Change in Internal Controls Over Financial Reporting

There have not been any changes in our internal controls over financial reporting that occurred during the quarterly period ended September 30, 2009 that materially affected, or are reasonably likely to materially affect, our internal controls 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

As of the date of this filing, there have been no changes from the risk factors previously disclosed in our “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2008.

These risks and uncertainties are not the only ones facing us and there may be additional matters that we are unaware of or that we currently consider immaterial. All of these could adversely affect our business, financial condition, results of operations and cash flows.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults upon Senior Securities

None.

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

None.

Item 5. Other Information

None.

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.

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 12, 2009	By:	/s/ Mark A. Houser
		Mark A. Houser, Chief Executive Officer,
		Chairman of the Board of Directors and Director (Principal Executive Officer)

Date: November 12, 2009	By:	/s/ James M. Vanderhider
		James M. Vanderhider, President,
		Chief Financial Officer and Director (Principal Financial Officer)

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

BELDEN & BLAKE CORP /OH/ 10-Q