Form 10-Q

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, 2010


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.)

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, 2010, Belden & Blake Corporation had outstanding 1,534 shares of common stock, without par value, which is its only class of stock.

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,
	2010			2009

ASSETS
Current assets
Cash and cash equivalents	$	39,987		$	46,740
Accounts receivable (less accumulated provision for doubtful accounts: September 30, 2010 — $599; December 31, 2009 — $393)		11,955			11,821
Inventories		821			828
Deferred income taxes		2,799			8,272
Other current assets		72			183
Derivative asset		1,825			413

Total current assets		57,459			68,257

Property and equipment, at cost
Oil and gas properties (successful efforts method)		684,443			684,787
Gas gathering systems		1,245			1,275
Land, buildings, machinery and equipment		2,421			2,566

		688,109			688,628
Less accumulated depreciation, depletion and amortization		172,567			151,208

Property and equipment, net		515,542			537,420
Long-term derivative asset		280			478
Other assets		1,561			1,923

	$	574,842		$	608,078

LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Accounts payable	$	1,553		$	1,696
Accounts payable — related party		491			910
Accrued expenses		13,334			16,136
Current portion of long-term liabilities		580			238
Derivative liability		9,269			21,098

Total current liabilities		25,227			40,078

Long-term liabilities
Bank and other long-term debt		23,922			43,929
Senior secured notes		141,302			162,287
Subordinated promissory note — related party		32,039			30,491
Asset retirement obligations and other long-term liabilities		23,827			22,990
Long-term derivative liability		31,754			66,876
Deferred income taxes		147,438			137,286

Total long-term liabilities		400,282			463,859

Shareholder’s equity
Common stock: without par value; 3,000 shares authorized and 1,534 shares issued		—			—
Paid in capital		142,500			142,500
Retained earnings (deficit)		12,759			(29,978	)
Accumulated other comprehensive loss		(5,926	)		(8,381	)

Total shareholder’s equity		149,333			104,141

	$	574,842		$	608,078

See accompanying notes.

BELDEN & BLAKE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, in thousands)


	Three months			Three months			Nine months			Nine months
	ended			ended			ended			ended
	September 30,			September 30,			September 30,			September 30,
	2010			2009			2010			2009

Revenues
Oil and gas sales	$	15,109		$	15,336		$	46,462		$	46,198
Gas gathering and marketing		1,359			1,312			4,164			4,558
Other		131			374			424			743

		16,599			17,022			51,050			51,499

Expenses
Production expense		5,056			5,123			15,022			16,342
Production taxes		265			246			865			799
Gas gathering and marketing		1,358			1,247			3,912			4,196
Exploration expense		446			849			827			3,164
Impairment of oil and gas properties		1,565			(1,297	)		1,565			23,933
General and administrative expense		1,617			1,631			5,160			5,925
Depreciation, depletion and amortization		6,963			9,066			22,008			28,414
Accretion expense		336			319			981			989
Gain on sale of assets		(5,351	)		—			(33,836	)		—
Derivative fair value (gain) loss		(12,473	)		539			(36,695	)		(19,884	)

		(218	)		17,723			(20,191	)		63,878

Operating income (loss)		16,817			(701	)		71,241			(12,379	)

Other expense (income)
Gain on early extinguishment of debt		(1,006	)		—			(1,006	)		—
Interest expense		4,765			5,411			14,762			15,543
Other income, net		(24	)		(155	)		(75	)		(255	)

Income (loss) before income taxes		13,082			(5,957	)		57,560			(27,667	)
Provision (benefit) for income taxes		4,932			(2,341	)		14,823			(10,927	)

Net income (loss)	$	8,150		$	(3,616	)	$	42,737		$	(16,740	)

See accompanying notes.

BELDEN & BLAKE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited, in thousands)


	Nine months			Nine months
	ended			ended
	September 30,			September 30,
	2010			2009
Cash flows from operating activities:
Net income (loss)	$	42,737		$	(16,740	)
Adjustments to reconcile net inome (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		22,008			28,414
Accretion expense		981			989
Gain on sale of assets		(33,836	)		—
Amortization of derivatives and other non-cash hedging activities		(35,144	)		(16,640	)
Exploration expense		784			2,181
Deferred income taxes		14,059			(10,927	)
Impairment of oil and gas properties		1,565			23,933
Gain on early extinguishment of debt		(1,006	)		—
Other non-cash items		1,464			2,704
Change in operating assets and liabilities
Accounts receivable and other current assets		2,928			8,336
Inventories		(31	)		81
Accounts payable and accrued expenses		(4,563	)		(4,048	)

Net cash provided by operating activities		11,946			18,283

Cash flows from investing activities:
Additions to property and equipment		(3,332	)		(10,707	)
Proceeds from property and equipment disposals		33,759			17,403
Exploration expense		(784	)		(2,181	)
Increase in other assets		(70	)		(54	)

Net cash provided by investing activities		29,573			4,461

Cash flows from financing activities:
Repayment of long-term debt and other obligations		(20,151	)		(43,577	)
Repayment of senior subordinated notes		(19,175	)		—
Debt redetermination costs		(288	)		(1,470	)
Settlement of derivative liabilities recorded in purchase accounting		(8,658	)		(30	)
Capital contributions		—			7,500

Net cash used in financing activities		(48,272	)		(37,577	)


Net decrease in cash and cash equivalents		(6,753	)		(14,833	)
Cash and cash equivalents at beginning of period		46,740			22,816

Cash and cash equivalents at end of period	$	39,987		$	7,983

See accompanying notes.

BELDEN & BLAKE CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

September 30, 2010

(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, 2010 are not necessarily indicative of the results that may be expected for the year ended December 31, 2010. 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, 2009.

(2) Derivatives and Hedging

From time to time, we may enter into a combination of futures contracts, 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, 2010, 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 condensed 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 third quarters of 2010 and 2009, net losses of $650,000 ($406,000 after tax) and $921,000 ($557,000 after tax), respectively, were reclassified from accumulated other comprehensive loss to earnings. The value of open hedges in accumulated other comprehensive loss decreased $650,000 (406,000 after tax) in the third quarter of 2010 and decreased $921,000 ($557,000 after tax) in the third quarter of 2009. During the first nine months of 2010 and 2009, net losses of $4.3 million ($2.4 million after tax) and $5.6 million ($3.4 million after tax), respectively, were reclassified from accumulated other comprehensive income to earnings. The value of open hedges in accumulated other comprehensive income decreased $4.3 million ($2.4 million after tax) in the first nine months of 2010 and decreased $5.6 million ($3.4 million after tax) in the first nine months of 2009. At September 30, 2010, the estimated net loss in accumulated other comprehensive income that is expected to be reclassified into earnings within the next 12 months is approximately $2.8 million after tax. At September 30, 2010, we have partially reduced 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, 2010:


	Natural Gas Swaps				Crude Oil Swaps				Natural Gas Basis Swaps
			NYMEX				NYMEX
			Price per				Price per				Basis
	Bbtu		Mmbtu		Mbbls		Bbl		Bbtu		Differential
Quarter Ending
December 31, 2010		2,234	$	4.31		44	$	28.77		1,932	$	0.243
Year Ending
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, 2010, we had interest rate swaps in place through September 30, 2013 covering $23.5 million of our outstanding debt under the revolving credit facility, which currently matures on April 14, 2011. The swaps provide 1-month LIBOR fixed rates at 4.10% plus the applicable margin.

At September 30, 2010, the fair value of these derivatives was as follows:


	Asset Derivatives				Liability Derivatives
(in thousands)	September 30, 2010		December 31, 2009		September 30, 2010			December 31, 2009
Oil and natural gas commodity contracts	$	2,105	$	864	$	(38,905	)	$	(85,593	)
Interest rate swaps		—		27		(2,118	)		(2,381	)

Total fair value	$	2,105	$	891	$	(41,023	)	$	(87,974	)


Location of derivatives in our consolidated balance sheets:
Derivative asset	$	1,825	$	413	$	—		$	—
Long-term derivative asset		280		478		—			—
Derivative liability		—		—		(9,269	)		(21,098	)
Long-term derivative liability		—		—		(31,754	)		(66,876	)

	$	2,105	$	891	$	(41,023	)	$	(87,974	)

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,
(in thousands)	2010			2009			2010			2009
The following amounts are recorded in Oil and gas sales:
Unrealized losses:
Oil and natural gas commodity contracts	$	(650	)	$	(921	)	$	(4,302	)	$	(5,603	)


The following are recorded in Derivative fair value (gain) loss:
Unrealized (gains) losses:
Oil and natural gas commodity contracts	$	(15,640	)	$	647		$	(47,840	)	$	(21,569	)
Interest rate swaps		(1,388	)		(171	)		(236	)		(740	)

Total		(17,028	)		476			(48,076	)		(22,309	)

Realized (gains) losses:
Oil and natural gas commodity contracts		2,419			(600	)		8,401			293
Interest rate swaps		2,136			663			2,980			2,132

Total		4,555			63			11,381			2,425

Derivative fair value (gain) loss	$	(12,473	)	$	539		$	(36,695	)	$	(19,884	)

(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 bank and other long-term debt debt approximates fair value because the facility’s interest rate approximates current market rates. At December 31, 2009 our Senior Secured Notes due 2012 had a $159.5 million face amount and an approximate fair value of $148.3 million. At September 30, 2010 our Senior Secured Notes due 2012 had a $139.5 million face amount had an approximate fair value of $133.7 million.

(5) Supplemental Disclosure of Cash Flow Information


	Nine months ended			Nine months ended
(in thousands)	September 30, 2010			September 30, 2009
Cash paid during the period for:
Interest	$	17,144		$	17,062
Income taxes		764			—
Non-cash investing and financing activities:
Accrued additions to property and equipment		1,472			566
Non-cash additions to debt		(1,548	)		(2,118	)
Proceeds from sale of oil and natural gas properties recorded in accounts receivable		2,951			—

(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, 2010 and 2009.


	Three months		Three months			Nine months		Nine months
	ended		ended			ended		ended
	September 30,		September 30,			September 30,		September 30,
(in thousands)	2010		2009			2010		2009
Comprehensive income (loss):
Net income (loss)	$	8,150	$	(3,616	)	$	42,737	$	(16,740	)
Other comprehensive income (loss), net of tax:
Other items reclassified into earnings, net of tax		—		—			38		—
Reclassification adjustment for derivative loss reclassified into earnings, net of tax		406		557			2,417		3,429

Change in accumulated other comprehensive income (loss)		406		557			2,455		3,429

	$	8,556	$	(3,059	)	$	45,192	$	(13,311	)

(8) Related Party Transactions

We have a joint operating agreement with EnerVest Operating LLC (“EnerVest Operating”). In the third quarter of 2010, we recorded costs of approximately $1.4 million (as general and administrative expense) for operating overhead fees, $1.3 million (as production expense) for field labor, vehicles and district office expense, $25,000 for drilling and overhead fees and $198,000 (capitalized) for drilling labor costs related to this agreement. We recorded costs of approximately $1.4 million for operating overhead fees, $1.4 million for field labor, vehicles and district office expense, $54,000 (capitalized) for drilling overhead fees and $203,000 for drilling labor costs in the third quarter of 2009 related to this agreement. In the first nine months of 2010, we recorded costs of approximately $4.1 million (as general and administrative expense) for operating overhead fees, $3.9 million (as production expense) for field labor, vehicles and district office expense, $25,000 for drilling and overhead fees and $580,000 (capitalized) for drilling labor costs related to this agreement. We recorded costs of approximately $4.7 million for operating overhead fees, $4.4 million for field labor, vehicles and district office expense, $81,000 for drilling overhead fees and $948,000 for drilling labor costs in the first nine months of 2009 related to this agreement.

We have a subordinated promissory note in favor of our parent, Capital C in the maximum amount of $94.0 million. The amount outstanding under the note at September 30, 2010 was $32.0 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 paid cash of $752,000 and borrowed $1.5 million against the note for interest payments in the first nine months of 2010 and borrowed of $2.1 million against the note in the first nine months of 2009.

As of September 30, 2010, we owed EnerVest $662,000 and EnerVest Operating owed us $150,000.

(9) Impairment of Oil and Gas Properties

For the periods ended September 30, 2010 and 2009, we reviewed our oil and gas properties for impairment as prescribed by ASC 360-10, Accounting for the Impairment or Disposal of Long-Lived Assets. As a result of this evaluation, we recorded an impairment of $23.9 million during 2009 to our coalbed methane properties in Pennsylvania. In 2010, we recorded a $1.6 million impairment to our Oriskany properties in Pennsylvania.

(10) New Accounting Standards

In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-06, Fair Value Measurements and Disclosures (Topic 820), which provides amendments to Topic 820 and requires new disclosures for (i) transfers between Levels 1, 2 and 3 and the reasons for such transfers and (ii) activity in Level 3 fair value measurements to show separate information about purchases, sales, issuances and settlements. In addition, ASU 2010-06 amends Topic 820 to clarify existing disclosures around the disaggregation level of fair value measurements and disclosures for the valuation techniques and inputs utilized (for Level 2 and Level 3 fair value measurements). The provisions in ASU 2010-06 are applicable to interim and annual reporting periods beginning subsequent to December 15, 2009, with the exception of Level 3 disclosures of purchases, sales, issuances and settlements, which will be required in reporting periods beginning after December 15, 2010. The adoption of ASU 2010-06 did not impact our operating results, financial position or cash flows, but did impact our disclosures on fair value measurements (see Note 11).

No other new accounting pronouncements issued or effective during the nine months ended September 30, 2010 have had or are expected to have a material impact on our unaudited condensed consolidated financial statements.

(11) Fair Value Measurements

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, 2010 Using:
				Quoted Prices in		Significant
				Active Markets		Other			Significant
				for Identical		Observable			Unobservable
(in thousands)	Total Carrying Value			Assets (Level 1)		Inputs (Level 2)			Inputs (Level 3)
Derivative assets:
Oil and natural gas commodity contracts	$	2,105		$	—	$	2,105		$	—

Derivative liabilities:
Oil and natural gas commodity contracts	$	(38,905	)	$	—	$	(38,905	)	$	—
Interest rate swaps		(2,118	)		—		(2,118	)		—

Total deriviative liabilities	$	(41,023	)	$	—	$	(41,023	)	$	—


				Fair Value Measurements at December 31, 2009 Using:
				Quoted Prices in		Significant
				Active Markets		Other			Significant
				for Identical		Observable			Unobservable
(in thousands)	Total Carrying Value			Assets (Level 1)		Inputs (Level 2)			Inputs (Level 3)
Derivative assets:
Oil and natural gas commodity contracts	$	864		$	—	$	864		$	—
Interest rate swaps		27			—		27			—

Total deriviative assets	$	891		$	—	$	891		$	—


Derivative liabilities:
Oil and natural gas commodity contracts	$	(85,593	)	$	—	$	(85,593	)	$	—
Interest rate swaps		(2,381	)		—		(2,381	)		—

Total deriviative liabilities	$	(87,974	)	$	—	$	(87,974	)	$	—

Our derivatives consist of over-the-counter (“OTC”) contracts which are not traded on a public exchange. These derivatives 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 derivatives 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 derivatives as Level 2. We value these derivatives based on observable market data for similar instruments. This observable data includes the forward curve for commodity prices based on quoted market prices and prospective volatility factors related to changes in the forward curves and yield curves based on money market rates and interest rate swap data. 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 months ended September 30, 2010.

Proved oil and gas properties with a carrying value of $2.2 million were written down to their fair value of $615,000, resulting in a pretax impairment charge of $1.6 million in the third quarter of 2010. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis include our estimate of future natural gas and crude oil prices, production costs, development expenditures, anticipated production of proved reserves, appropriate risk adjusted discount rates and other relevant data.

(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, 2009	$	23,083
Accretion expense		981
Liabilities incurred		9
Liabilities settled		(87	)
Revisions in estimated cash flows		—

Balance as of September 30, 2010	$	23,986

As of September 30, 2010 and December 31, 2009, $229,000 of our ARO is classified as current.

(13) Divestitures

On June 14, 2010, we sold certain oil and natural gas properties for $30.6 million and recorded a gain on the sale of $28.5 million.

On July 1, 2010, we sold unproved oil and natural gas properties for $6.1 million and recorded a gain on the sale of $5.3 million. We received $3.2 million at closing and received $2.9 million on October 29, 2010. The $2.9 million is included in “Accounts receivable” in our unaudited condensed consolidated balance sheet as of September 30, 2010.

(14) Debt

On August 3, 2010, we reduced our outstanding bank debt by $20.0 million. As of September 30, 2010 we have $23.9 million of outstanding bank debt.

At September 30, 2010, we had an Amended Credit Agreement comprised of a five-year $90 million revolving facility with a borrowing base of $55 million, of which $23.9 million was outstanding at September 30, 2010. 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 3.50% based on the aggregate principal amount outstanding under the Amended Credit Agreement. The full amount borrowed under the Amended Credit Agreement will mature on April 14, 2012.

On August 25, 2010, we entered into the Seventh Amendment to Credit Agreement. The Credit Agreement was amended to (1) extend the termination date to April 14, 2012, (2) extend the hedge letter of credit termination date to April 14, 2012, (3) decrease the aggregate amount of the revolving commitments to $90 million, (4) decrease the borrowing base to $55 million and (5) make certain other amendments to the Credit Agreement.

On September 2, 2010, we repurchased a portion of the outstanding senior secured notes. The repurchased notes had a face value of $20.0 million and were repurchased at 95.875. A gain of $1.0 million was recorded in connection with the transaction.

(15) Subsequent Events

The company has determined that there are no subsequent events which require recognition or disclosure in these condensed consolidated financial statements through the date the 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, 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, 2009, 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 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,
	2010		2009		2010		2009
Production
Gas (Mmcf)		2,416		2,941		7,507		9,288
Oil (Mbbls)		69		83		205		246
Total production (Mmcfe)		2,829		3,440		8,739		10,762

Average price (1)
Gas (per Mcf)	$	4.23	$	3.39	$	4.21	$	3.58
Oil (per Bbl)		70.89		64.51		72.23		52.61
Mcfe		5.34		4.46		5.32		4.29

Average costs (per Mcfe)
Production expense	$	1.79	$	1.49	$	1.72	$	1.52
Production taxes		0.09		0.07		0.10		0.07
Depletion		2.44		2.61		2.49		2.61


(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 June 30,				Nine months ended June 30,
	2010		2009		2010		2009
Gas (per Mcf)	$	4.50	$	3.70	$	4.79	$	4.19
Oil (per Bbl)		70.89		64.51		72.23		52.61
Mcfe		5.57		4.73		5.81		4.81

Results of Operations — Third Quarters of 2010 and 2009 Compared

Revenues

Operating revenues decreased from $17.0 million in the third quarter of 2009 to $16.6 million in the third quarter of 2010. The decrease in operating revenues was primarily due to lower oil and gas sales revenues of $227,000.

Gas volumes sold were 2.4 Bcf in the third quarter of 2010, which was a decrease of 526 Mmcf (18%) compared to the third quarter of 2009. This decrease in gas volumes sold resulted in a decrease in gas sales revenues of approximately $1.8 million. Oil volumes sold decreased approximately 14,000 Bbls (17%) from 83,000 Bbls in the third quarter of 2009 to 69,000 Bbls in the third quarter of 2010 resulting in a decrease in oil sales revenues of approximately $900,000. The lower oil and gas sales volumes are primarily due to normal production decline of our wells and the effect of reduced drilling in 2009 and 2010.

The average price realized for our natural gas increased $0.84 per Mcf from $3.39 in the third quarter of 2009 to $4.23 per Mcf in the third quarter of 2010, which increased gas sales revenues by approximately $2.0 million. As a result of our qualified hedging and derivative financial instrument activities, gas sales revenues were lower by $650,000 ($0.27 per Mcf) in the third quarter of 2010 and lower by $921,000 ($0.31 per Mcf) in the third quarter of 2009 than if our gas price was not affected by derivative financial instruments. The average price realized for our oil increased from $64.51 per Bbl in the third quarter of 2009 to $70.89 per Bbl in the third quarter of 2010, which increased oil sales revenues by approximately $440,000.

Gas gathering and marketing revenues increased from $1.3 million in the third quarter of 2009 to $1.4 million in the third quarter of 2010. The increase was due to a $62,000 increase in gas marketing revenues, partially offset by a $15,000 decrease in gas gathering revenues as a result of lower gas volumes in the third quarter of 2010 compared to the third quarter of 2009.

Costs and Expenses

Production expense was $5.1 million in the third quarter of 2009 and 2010. The average production cost increased from $1.49 per Mcfe in the third quarter of 2009 to $1.79 per Mcfe in the third quarter of 2010 due to the decrease in volumes and consistent costs.

Production taxes increased $19,000 from $246,000 in the third quarter of 2009 to $265,000 in the third quarter of 2010. Average per unit production taxes increased from $0.07 per Mcfe in the third quarter of 2009 to $0.09 per Mcfe in the third quarter of 2010. The increased production taxes were primarily due to higher oil and gas prices in Michigan in the third quarter of 2010 compared to the third quarter of 2009. In Michigan, production taxes are based on a percentage of revenues, excluding the effects of hedging.

Gas gathering and marketing expenses increased from $1.2 million in the third quarter of 2009 to $1.4 million in the third quarter of 2010. The increase was primarily due to the higher cost of gas purchases due to higher gas prices in the third quarter of 2010 compared to the third quarter of 2009, partially offset by lower gas volumes.

Exploration expense decreased $403,000 from $849,000 in the third quarter of 2009 to $446,000 in the third quarter of 2010. The decrease in exploration expense was primarily due to a reduced level of seismic activity.

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. In the third quarter of 2010, we recorded an impairment of $1.6 million to our Oriskany properties in Pennsylvania.

General and administrative expense was $1.6 million in the third quarter of 2009 and 2010.

Depreciation, depletion and amortization decreased by $2.1 million from $9.1 million in the third quarter of 2009 to $7.0 million in the third quarter of 2010. This decrease was due to a $2.1 million decrease in depletion expense because of lower volumes and a lower depletion rate per Mcfe. Depletion per Mcfe decreased from $2.61 per Mcfe in the third quarter of 2009 to $2.44 per Mcfe in the third quarter of 2010 primarily due to increased reserves volumes due to higher oil and gas prices in 2010.

Derivative fair value (gain) loss was a gain of $12.5 million in the third quarter of 2010 compared to a loss of $539,000 in the third quarter of 2009. The derivative fair value (gain) loss reflects the changes in fair value of certain derivative instruments that are not designated or do not qualify as cash flow hedges. During the three months ended September 30, 2010 and 2009, we made cash payments of $4.6 million and $63,000, respectively, to our counterparties as the contract prices for our derivatives were less than the underlying market price for that period.

Gain on sale of assets was $5.4 million in the third quarter of 2010 due to the sale of oil and gas properties in July 2010. There was no gain on the sale of assets in the third quarter of 2009.

Gain on early extinguishment of debt was $1.0 million in the third quarter of 2010 due to the repurchase of our Senior Secured Notes at a discount to book value. There was no gain on early extinguishment of debt in the third quarter of 2009.

Interest expense decreased $646,000 from $5.4 million in the third quarter of 2009 to $4.8 million in the third quarter of 2010. This decrease in interest expense was primarily due to lower debt levels.

Income tax expense was $4.9 million in the third quarter of 2010 compared to an income tax benefit of $2.3 million in the third quarter of 2009. The change in income tax expense was primarily due to an increase in income before income taxes. The increase in income before income taxes was primarily due to the increase in derivative fair value gain, the gain on the sale of oil and gas properties in July 2010, the decrease in depreciation, depletion and amortization expense, which were partially offset by the increase in the impairment of oil and gas properties.

Results of Operations — Nine Months of 2010 and 2009 Compared

Revenues

Operating revenues decreased from $51.5 million in the first nine months of 2009 to $51.1 million in the first nine months of 2010. Oil and gas sales revenues increased $264,000, gas gathering and marketing revenues decreased $394,000 and other revenues decreased 319,000 from the first nine months of 2009 to the first nine months of 2010.

Gas volumes sold were 7.5 Bcf in the first nine months of 2010, which was a decrease of 1.8 Bcf (19%) compared to the first nine months of 2009. This decrease in gas volumes sold resulted in a decrease in gas sales revenues of approximately $6.4 million. Oil volumes sold decreased approximately 41,000 Bbls (16%) from 246,000 Bbls in the first nine months of 2009 to 205,000 Bbls in the first nine months of 2010 resulting in a decrease in oil sales revenues of approximately $2.1 million. The lower oil and gas sales volumes are primarily due to the sale of our coalbed methane properties in Pennsylvania in July 2009, normal production decline of our wells and the effect of reduced drilling in 2009 and 2010.

The average price realized for our natural gas increased $0.63 per Mcf from $3.58 in the first nine months of 2009 to $4.21 per Mcf in the first nine months of 2010, which increased gas sales revenues by approximately $4.7 million. As a result of our qualified hedging and derivative financial instrument activities, gas sales revenues were lower by $4.3 million ($0.57 per Mcf) in the first nine months of 2010 and lower by $5.6 million ($0.60 per Mcf) in the first nine months of 2009 than if our gas price was not affected by derivative financial instruments. The average price realized for our oil increased from $52.61 per Bbl in the first nine months of 2009 to $72.23 per Bbl in the first nine months of 2010, which increased oil sales revenues by approximately $4.0 million.

Gas gathering and marketing revenues decreased from $4.6 million in the first nine months of 2009 to $4.2 million in the first nine months of 2010 due to a $290,000 decrease in gas marketing revenues and an $104,000 decrease in gas gathering revenues as a result of lower gas volumes in the first nine months of 2010 compared to the first nine months of 2009.

Costs and Expenses

Production expense decreased from $16.3 million in the first nine months of 2009 to $15.0 million in the first nine months of 2010. The decrease in production expense was primarily due to the sale of our coalbed methane properties, which was partially offset by higher operating expenses associated with several Marcellus shale wells completed in late 2009. These wells were sold in the June 2010 asset sale discussed in Note 13. The average production cost increased from $1.52 per Mcfe in the first nine months of 2009 to $1.72 per Mcfe in the first nine months of 2010 primarily due to the decrease in volumes partially offset by lower costs.

Production taxes increased from $799,000 in the first nine months of 2009 to $865,000 in the first nine months of 2010. Average per unit production taxes increased from $0.07 per Mcfe in the first nine months of 2009 to $0.10 per Mcfe in the first nine months of 2010. The increased production taxes are primarily due to higher oil and gas prices in the first nine months of 2010 in Michigan, where production taxes are based on a percentage of revenues, excluding the effects of hedging.

Gas gathering and marketing expenses decreased from $4.2 million in the first nine months of 2009 to $3.9 million in the first nine months of 2010, primarily due to a $252,000 decrease in gas marketing expenses as a result of lower gas volumes in the first nine months of 2010 compared to the first nine months of 2009.

Exploration expense decreased $2.3 million from $3.2 million in the first nine months of 2009 to $827,000 in the first nine months of 2010. The decrease in exploration expense was primarily due to a decrease in expired lease expense, a lower level of seismic activity and lower delay rental expense.

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. In the first nine months of 2010 we recorded an impairment of $1.6 million to our Oriskany properties in Pennsylvania.

General and administrative expense decreased from $5.9 million in the first nine months of 2009 to $5.2 million in the first nine months of 2010. This decrease was primarily due to reduced overhead fees paid to EnerVest, primarily as a result of the sale of the Pennsylvania coalbed methane properties in July 2009, and lower legal and technical consulting fees paid to third parties.

Depreciation, depletion and amortization decreased by $6.4 million from $28.4 million in the first nine months of 2009 to $22.0 million in the first nine months of 2010. This decrease was due to a $6.4 million decrease in depletion expense, which was primarily due to a decrease in oil and gas volumes sold in the first nine months of 2010. Depletion per Mcfe decreased from $2.61 per Mcfe in the first nine months of 2009 to $2.49 in the first nine months of 2010 primarily due to increased reserves volumes due to higher oil and gas prices in 2010.

Derivative fair value (gain) loss was a gain of $36.7 million in the first nine months of 2010 and a gain of $19.9 million in the first nine months of 2009. The derivative fair value (gain) loss reflects the changes in fair value of open derivative instruments and the monthly cash settlements with our counterparties related to derivatives that matured during the period that are not designated or do not qualify as cash flow hedges. During the nine months ended September 30, 2010 and 2009, we made cash payments of $11.4 million and $2.4 million, respectively, to our counterparties as the contract prices for our derivatives were less than the underlying market price for that period.

Gain on sale of assets was $33.8 million in the first nine months of 2010 primarily due to the sale of oil and gas properties in June and July of 2010. There was no gain on the sale of assets in the first nine months of 2009.

Gain on early extinguishment of debt was $1.0 million in the first nine months of 2010 due to the repurchase of our Senior Secured Notes at a discount to book value. There was no gain on early extinguishment of debt in the first nine months of 2009.

Interest expense decreased $781,000 from $15.5 million in the first nine months of 2009 to $14.8 million in the first nine months of 2010. This decrease in interest expense was primarily due to lower debt levels.

Income tax expense was $14.8 million in the first nine months of 2010 compared to an income tax benefit of $10.9 million in the first nine months of 2009. The change in income tax expense was primarily due to an increase in income before income taxes, partially offset by the elimination of the state of Ohio corporate income tax. The Ohio corporate income tax was replaced with a Commercial Activity Tax which is not considered an income tax under FASB Accounting Standards Codification (“ASC”) No. 740, Accounting for Income Taxes. As a result of the change in the Ohio state law, deferred tax amounts previously recorded were adjusted to reflect the change and resulted in a reduction of $6.8 million in income tax expense. The increase in income before income taxes was primarily due to the gain on the sale of oil and gas properties in June 2010, the decrease in depreciation, depletion and amortization expense and the increase in derivative fair value gain, which were partially offset by the decrease 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, 2010 have been funds generated from the sale of assets and from our operating activities. Funds used during this period were primarily used for operating activities, debt reduction and the settlement of derivatives.

Our operating activities provided cash flows of $11.9 million during the first nine months of 2010 compared to $18.3 million in the first nine months of 2009. The decrease was primarily due to a decrease in the change in working capital items of $6.0 million.

Our investing activities provided cash flows of $29.6 million during the first nine months of 2010 compared to $4.5 million in the first nine months of 2009. The change was due to an increase in proceeds from property and equipment disposals of $16.4 million, a decrease in capital expenditures of $7.4 million and a decrease in exploration expense of $1.4 million. We sold Pennsylvania coalbed methane properties in 2009 for $16.7 million and sold undeveloped acreage in Pennsylvania and Ohio in 2010 for $36.8 million, $33.8 million of which was received as of September 30, 2010.

Our financing activities used cash flows of $48.3 million during the first nine months of 2010 compared to $37.6 million in the first nine months of 2009. The change was primarily due to an increase of $8.6 million in derivative settlements and a decrease in capital contributions of $7.5 million, partially offset by a $4.3 million decrease in the repayment of debt. In the first nine months of 2009 we paid down $43.5 million on our credit facility. In 2010, we paid down $20.0 million on our credit facility and repurchased $20.0 million of our bonds for $19.2 million.

Our current ratio at September 30, 2010 was 2.28 to 1. Working capital increased $4.0 million from $28.2 million at December 31, 2009 to $32.2 million at September 30, 2010. The increase in working capital was primarily due to an $11.8 million decrease in the current liabilities related to the fair value of derivatives, a decrease in accrued expenses of $2.8 million and a $1.4 million increase in the current asset related to the fair value of derivatives which were partially offset by a $6.8 million decrease in cash and a decrease of $5.5 million in the current deferred tax asset.

Capital Expenditures

During the first nine months of 2010, we spent approximately $3.3 million on our drilling activities and other capital expenditures. In the third quarter of 2010, we drilled 1 gross (0.5 net) exploratory well which was a dry hole and 11 gross (11.0 net) development wells which were all completed as producing wells. We also performed major workovers on 17 wells during the first nine months of 2010. We plan to drill approximately 27 gross (27.0 net) development wells and 3 gross (1.5 net) exploratory wells and perform major workovers on 6 additional wells in the fourth quarter of 2010.

We currently expect to spend approximately $13 million during 2010 on our drilling activities and other capital expenditures. We intend to finance our planned capital expenditures through our cash on hand and operating cash flow. At September 30, 2010, we had cash of $40.0 million and approximately $30.3 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

In 2005, we amended and restated our then existing credit agreement, by entering into a First Amended and Restated Credit and Guaranty Agreement (“Amended Credit Agreement”) by and among us and BNP Paribas, as sole lead arranger, sole book runner, syndication agent and administrative agent. The Amended Credit Agreement provides for loans and other extensions of credit to be made to us. The obligations under the Amended Credit Agreement are secured by substantially all of our assets.

On August 3, 2010, we reduced our outstanding bank debt by $20.0 million. As of September 30, 2010 we have $23.9 million of outstanding bank debt.

In August 2005, 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. 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 the Fourth Amendment to our 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 (the “Hedges”) with J. Aron under a master agreement and related confirmations and documentation (collectively, the “Hedge Agreement”) and notes issued under our Indenture dated July 7, 2004 with BNY Midwest Trust Company, as indenture trustee (“Senior Secured Notes”).


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 credit 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, 2010, we had an interest rate swap in place on $23.5 million of our outstanding debt under the revolving credit facility through September 30, 2013. The swap provides a 1-month LIBOR fixed rates at 4.10%, plus the applicable margin, on $23.5 million through September 2013. These interest rate swaps do not qualify for hedge accounting, therefore, all cash settles and changes in the fair value of these swaps are recorded in derivative fair value gain/loss. If market interest rates for short-term borrowings increased 1%, the increase in our interest expense for the first nine months of 2010 would be approximately $279,000. The impact of this rate increase on our cash flows would be significantly less than this amount due to our interest rate swaps. If market interest rates increased 1% there would be no decrease in our cash flow. This sensitivity analysis is based on our financial structure at September 30, 2010.

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, 2010, we had derivatives covering a portion of our oil and gas production from 2010 through 2013. Our oil and gas sales revenues included a net pre-tax loss of $4.3 million in the first nine months of 2010 and a net pre-tax loss of $650,000 in the third quarter of 2010 on our qualified hedging activities.

If gas prices decreased $.50 per Mcf, our gas sales revenues for the first nine months of 2010 would decrease by approximately $3.8 million. If the price of crude oil decreased $10.00 per Bbl, our oil sales revenues for the first nine months of 2010 would decrease by approximately $2.1 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 $.50 per Mcf and $10.00 per Bbl would decrease cash flows from the sale of oil and gas for the first nine months of 2010 by approximately $1.1 million after considering the effects of the derivative contracts in place as of September 30, 2010. This sensitivity analysis is based on the first nine months of 2010 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, 2010, which has not changed since September 30, 2010:


	Natural Gas Swaps				Crude Oil Swaps				Natural Gas Basis Swaps
			NYMEX				NYMEX
			Price per				Price per				Basis
	Bbtu		Mmbtu		Mbbls		Bbl		Bbtu		Differential
Quarter Ending
December 31, 2010		2,234	$	4.31		44	$	28.77		1,932	$	0.243
Year Ending
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 $36.8 million as of September 30, 2010.


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, 2010 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, 2010 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, 2009.

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.		(Removed and Reserved)


Item 5.		Other Information

None.


Item 6.		Exhibits.

The exhibits listed below are filed or furnished as part of this report:


10.1		Seventh Amendment to Credit Agreement dated August 25, 2010 (Incorporated by reference from Exhibit 10.1 to the Belden & Blake Corporation current report on Form 8-K filed with the SEC on August 26, 2010).
31.1	*	Certification of Principal Executive Officer of Belden & Blake Corporation as required by Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934
31.2	*	Certification of Principal Financial Officer of Belden & Blake Corporation as required by Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934
32.1	*	Certification of Chief Executive Officer of Belden & Blake Corporation pursuant to 18 U.S.C. Section 1350.
32.2	*	Certification of Chief Financial Officer of Belden & Blake Corporation pursuant to 18 U.S.C. Section 1350.


*		Filed herewith.


	Page

PART I Financial Information

Item 1. Financial Statements (unaudited)

Condensed Consolidated Balance Sheets as of September 30, 2010 and December 31, 2009		1

Condensed Consolidated Statements of Operations: Three and nine months ended September 30, 2010 and 2009		2

Condensed Consolidated Statements of Cash Flows: Nine months ended September 30, 2010 and 2009		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		17

Item 4. Controls and Procedures		18

PART II Other Information

Item 1. Legal Proceedings		19

Item 1A. Risk Factors		19

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		19

Item 3. Defaults Upon Senior Securities		19

Item 4. (Removed and Reserved)		19

Item 5. Other Information		19

Item 6. Exhibits		19

Signatures		20

Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2


	BELDEN & BLAKE CORPORATION
Date: November 12, 2010	By:	/s/ Mark A. Houser
		Mark A. Houser, Chief Executive Officer
		(Principal Executive Officer)


Date: November 12, 2010	By:	/s/ James M. Vanderhider
		James M. Vanderhider, President,
		Chief Financial Officer (Principal Financial Officer)

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