UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended ~~September~~March 3031, ~~2009~~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 incorporation or organization)		(I.R.S. Employer Identification No.)
(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)

(Former name, former address and former fiscal year, if changed since last report.)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 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, or a non-accelerated filer or a smaller reporting company. See ~~definitions~~definition of “~~large~~ accelerated filer,” “large 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~~April 3130, ~~2009~~2010, 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 Balance Sheets as of March 31, 2010 and December 31, 2009		1
Condensed Consolidated Statements of Operations: Three and nine months ended September 30, 2009 and 2008		2
Condensed Consolidated Statements of Operations: Three months ended March 31, 2010 and 2009		2
Condensed Consolidated Statements of Cash Flows: Nine months ended September 30, 2009 and 2008		3
Condensed Consolidated Statements of Cash Flows: Three months ended March 31, 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		1110
Item 3. Quantitative and Qualitative Disclosures About Market Risk		1915
Item 4. Controls and Procedures		2116
PART II Other Information
Item 1. Legal Proceedings		2117
Item 1A. Risk Factors		2117
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		2118
Item 3. Defaults Upon Senior Securities		21
Item 3. Defaults upon Senior Securities		18
Item 4. Submission of Matters to a Vote of Security Holders		21
Item 4. (Removed and Reserved)		18
Item 5. Other Information		2118
Item 6. Exhibits		2219
Signatures		2320
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)

(unaudited, in thousands, except share data)


	March 31,			December 31,
	2010			2009

ASSETS
Current assets
Cash and cash equivalents	$	44,359		$	46,740
Accounts receivable (less accumulated provision for doubtful accounts: March 31, 2010 - $529; December 31, 2009 - $393)		11,533			11,821
Inventories		881			828
Deferred income taxes		3,946			8,272
Assets held for sale		2,031			—
Other current assets		150			183
Fair value of derivatives		1,285			413

Total current assets		64,185			68,257

Property and equipment, at cost
Oil and gas properties (successful efforts method)		682,860			684,787
Gas gathering systems		1,245			1,275
Land, buildings, machinery and equipment		2,421			2,566

		686,526			688,628
Less accumulated depreciation, depletion and amortization		158,444			151,208

Property and equipment, net		528,082			537,420
Fair value of derivatives		787			478
Other assets		1,746			1,923

	$	594,800		$	608,078

LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Accounts payable	$	1,252		$	1,696
Accounts payable — related party		447			910
Accrued expenses		12,333			16,136
Current portion of long-term liabilities		238			238
Fair value of derivatives		11,779			21,098

Total current liabilities		26,049			40,078

Long-term liabilities
Bank and other long-term debt		43,927			43,929
Senior secured notes		162,020			162,287
Subordinated promissory note — related party		30,491			30,491
Asset retirement obligations and other long-term liabilities		23,277			22,990
Fair value of derivatives		48,949			66,876
Deferred income taxes		135,048			137,286

Total long-term liabilities		443,712			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
Accumulated deficit		(10,878	)		(29,978	)
Accumulated other comprehensive loss		(6,583	)		(8,381	)

Total shareholder’s equity		125,039			104,141

	$	594,800		$	608,078

	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)

(unaudited, in thousands)


	Three months ended			Three months ended
	March 31, 2010			March 31, 2009
Revenues
Oil and gas sales	$	15,689		$	15,016
Gas gathering and marketing		1,590			1,920
Other		138			174

		17,417			17,110

Expenses
Production expense		4,969			6,230
Production taxes		335			322
Gas gathering and marketing		1,414			1,686
Exploration expense		141			1,525
General and administrative expense		1,832			2,180
Depreciation, depletion and amortization		7,849			9,375
Accretion expense		319			331
Derivative fair value gain		(24,075	)		(31,227	)

		(7,216	)		(9,578	)

Operating income		24,633			26,688

Other (income) expense
Interest expense		4,974			4,817
Other income, net		(18	)		(67	)

		4,956			4,750

Income before income taxes		19,677			21,938
Provision for income taxes		577			8,696

Net income	$	19,100		$	13,242

	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)

(unaudited, in thousands)


	Three months ended			Three months ended
	March 31, 2010			March 31, 2009

Cash flows from operating activities:
Net income	$	19,100		$	13,242
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		7,849			9,375
Accretion expense		319			331
Amortization of derivatives and other noncash hedging activities		(21,291	)		(28,155	)
Exploration expense		141			625
Deferred income taxes		577			8,696
Other non-cash items		(8	)		1,373
Change in operating assets and liabilities, net of effects of acquisition and disposition of businesses:
Accounts receivable and other operating assets		321			7,494
Inventories		(56	)		82
Accounts payable and accrued expenses		(4,622	)		(6,433	)

Net cash provided by operating activities		2,330			6,630

Cash flows from investing activities:
Proceeds from property and equipment disposals		—			746
Exploration expense		(141	)		(625	)
Additions to property and equipment		(669	)		(3,838	)
Decrease in other assets		(71	)		(97	)

Net cash used in investing activities		(881	)		(3,814	)

Cash flows from financing activities:
Repayment of long-term debt and other obligations		(3	)		(71	)
Settlement of derivative liabilities recorded in purchase accounting		(3,827	)		(1,000	)

Net cash used in financing activities		(3,830	)		(1,071	)


Net (decrease) increase in cash and cash equivalents		(2,381	)		1,745
Cash and cash equivalents at beginning of period		46,740			22,816

Cash and cash equivalents at end of period	$	44,359		$	24,561

	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 UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~(unaudited)~~March 31, 2010

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~~March 3031, ~~2009~~2010 are not necessarily indicative of the results that ~~may~~ may be expected for the year ended December 31, ~~2009~~2010. For further information, refer to the consolidated financial statements and footnotes included in our Annual Report on Form 10-K for the year ended December 31, ~~2008~~2009.

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,~~From ~~2009~~time to time, we ~~adopted~~may ~~new~~enter ~~FASB~~into ~~accounting~~a ~~guidance~~combination of futures contracts, derivatives and ~~regarding~~fixed-price ~~disclosures~~physical ~~about~~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 March 31, 2010, our derivative contracts were comprised of natural gas swaps, natural gas basis differential swaps, crude oil swaps and ~~hedging~~interest ~~activities~~rate swaps which were placed with major financial institutions that ~~requires~~we ~~enhanced~~believe ~~disclosures~~are ~~about~~a anminimal ~~entity’s~~credit risk. All of our derivative ~~and~~instruments ~~hedging~~are ~~activities~~currently ~~and~~accounted ~~how~~for ~~they~~as non-qualifying ~~affect~~derivative ancontracts. ~~entity’s~~The changes in fair value of non-qualifying derivative ~~financial~~contracts ~~position,~~are ~~financial~~reported ~~performance~~in ~~and~~expense ~~cash~~in ~~flows~~the condensed consolidated statements of operations as derivative fair value gain.

~~From~~We ~~time~~have tocertain ~~time,~~derivative wecontracts ~~may~~that ~~enter~~qualified ~~into~~for ahedge ~~combination~~accounting oftreatment ~~futures~~in ~~contracts~~prior periods, ~~commodity~~as ~~derivatives and~~well ~~fixed-price~~as ~~physical~~derivative ~~commodity~~ contracts tothat ~~manage~~were ~~our~~de-designated ~~exposure~~in toprior ~~natural~~periods. ~~gas~~During ~~price~~the first quarters of 2010 and 2009, ~~crude~~net ~~oil price~~losses orof ~~interest~~$3.3 million ~~rate~~($1.8 million ~~volatility~~after tax) and ~~support~~$4.1 million ~~our~~($2.5 million ~~capital~~after ~~expenditure~~tax), ~~plans.~~respectively, ~~Our~~were ~~derivative~~reclassified from accumulated other ~~financial~~comprehensive ~~instruments~~loss ~~take~~to ~~the~~earnings. ~~form~~The value of ~~swaps~~open orhedges ~~collars.~~in Ataccumulated ~~September 30,~~other ~~2009,~~comprehensive ~~our derivative~~loss ~~contracts~~decreased ~~were~~$3.3 million ~~comprised~~($1.8 million ofafter ~~natural~~tax) ~~gas~~in ~~swaps,~~the ~~natural~~first ~~gas~~quarter ~~basis~~of ~~differential~~2010 ~~swaps,~~and ~~crude~~decreased ~~oil~~$4.1 ~~swaps~~million ~~and~~($2.5 million ~~interest~~after ~~rate~~tax) ~~swaps~~in ~~which~~the ~~were~~first ~~placed~~quarter ~~with~~of ~~major~~2009. ~~financial~~At ~~institutions~~March 31, ~~that~~2010, wethe ~~believe~~estimated ~~are~~net aloss ~~minimal~~in ~~credit~~accumulated ~~risk.~~other ~~All~~comprehensive ofloss ~~our~~that ~~derivative~~is ~~instruments~~expected ~~are~~to ~~currently~~be ~~accounted~~reclassified ~~for~~into asearnings ~~non-qualifying~~within ~~derivative~~the ~~contracts.~~next ~~The~~12 months ~~changes~~is inapproximately ~~fair~~$3.5 million ~~value~~after oftax. ~~non-qualifying~~At ~~derivative contracts~~March 31, ~~are~~2010, ~~reported~~we inhave partially ~~expense~~hedged inour ~~the~~exposure ~~consolidated~~to ~~statements~~the ofvariability ~~operations~~in asfuture ~~derivative~~cash ~~fair value~~flows ~~(gain)~~through December ~~loss~~2013.

~~We have~~The ~~certain~~following ~~derivative~~table ~~contracts~~reflects ~~that qualified for hedge accounting treatment in prior periods, as well as derivative contracts that were de designated in prior periods. During~~ the ~~three~~natural ~~month~~gas ~~period ended September 30, 2009~~ and ~~2008,~~crude ~~accumulated~~oil ~~other~~volumes ~~comprehensive income decreased $921,000 ($557,000 after tax)~~ and ~~$1.2 million ($703,000 after tax), respectively. During~~ the ~~nine~~weighted ~~month period~~average ~~ended~~prices ~~September 30,~~under ~~2009~~derivative ~~and~~contracts ~~2008, accumulated other comprehensive income decreased $5.6 million~~ (~~$3.4 million after~~including ~~tax)~~settled ~~and~~derivative ~~$7.4 million ($4.5 million after tax~~contracts), ~~respectively.~~at ~~All such amounts were reclassified into earnings during the respective periods. At September~~March 3031, ~~2009,~~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 $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
			Price per				Price per				Basis
	Bbtu		Mmbtu		Mbbls		Bbl		Bbtu		Differential
Quarter Ending
June 30, 2010		2,234	$	4.11		44	$	28.88		1,911	$	0.243
September 30, 2010		2,234		4.12		44		28.82		1,932		0.243
December 31, 2010		2,234		4.31		44		28.77		1,932		0.243

		6,702	$	4.18		132	$	28.82		5,775	$	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		—		—

	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 March 31, 2010, 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 at 4.10% plus the applicable margin.

At ~~September~~ March 3031, ~~2009,~~2010 ~~we had interest rate swaps in place through September 30~~, ~~2013 covering $43.5 million of our outstanding debt under~~ the ~~revolving~~fair ~~credit~~value ~~facility, which currently matures on August 16, 2011. The swaps provide 1-month LIBOR fixed rates~~ of ~~4.10%,~~these ~~plus~~derivatives ~~the~~was ~~applicable~~as ~~margin.~~follows:


	Asset Derivatives				Liability Derivatives
	March 31, 2010		December 31, 2009		March 31, 2010			December 31, 2009
Oil and natural gas commodity contracts	$	2,072	$	864	$	(57,986	)	$	(85,593	)
Interest rate swaps		—		27		(2,742	)		(2,381	)

Total fair value	$	2,072	$	891	$	(60,728	)	$	(87,974	)


Location of derivatives in our consolidated balance sheet:
Derivative asset	$	1,285	$	413	$	—		$	—
Long-term derivative asset		787		478		—			—
Derivative liability		—		—		(11,779	)		(21,098	)
Long-term derivative liability		—		—		(48,949	)		(66,876	)

	$	2,072	$	891	$	(60,728	)	$	(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.

AtThe ~~September 30,~~following ~~2009,~~table presents the ~~fair~~impact ~~value~~ of ~~these~~ derivatives ~~was~~and astheir ~~follows~~location within the statements of operations:

	Asset Derivatives						Liability Derivatives
	Three Months Ended
	September 30, 2009			December 31, 2008			September 30, 2009			December 31, 2008
	March 31,
Oil and natural gas commodity contracts	$	1,468		$	1,298		$	(97,151	)	$	(118,547	)
	2010			2009
Interest rate swaps		—			—			(2,801	)		(3,543	)
The following amounts are recorded in Oil and gas sales:
Total fair value	$	1,468		$	1,298		$	(99,952	)	$	(122,090	)
Unrealized losses:
Location of derivatives in our consolidated balance sheets:
Oil and natural gas commodity contracts	$	(3,309	)	$	(4,079	)
Derivative asset	$	988		$	430		$	—		$	—
The following are recorded in Derivative fair value gain:
Long-term derivative asset		480			868			—			—
Unrealized (gains) losses:
Derivative liability		—			—			(19,708	)		(20,520	)
Oil and natural gas commodity contracts	$	(28,779	)	$	(33,003	)
Long-term derivative liability		—			—			(80,244	)		(101,570	)
Interest rate swaps		388			(281	)
	$	1,468		$	1,298		$	(99,952	)	$	(122,090	)
Total		(28,391	)		(33,284	)
Realized losses:
Oil and natural gas commodity contracts		3,895			1,334
Interest rate swaps		421			723
Total		4,316			2,057
Derivative fair value gain	$	(24,075	)	$	(31,227	)

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~~ fair value (see Notes 2 and 1110). The carrying amount of our other financial instruments other than ~~debt~~ debt approximates fair value because of the short-term nature of the items. The carrying value of ~~our~~ our debt, including our senior secured ~~notes~~noted and subordinated promissory note, approximates fair ~~value~~ value because the interest rates ~~approximates~~approximate current market rates.

(5) Supplemental Disclosure of Cash Flow Information

	Nine months ended			Nine months ended
	Three months ended			Three months ended
(in thousands)	~~September~~March 3031, ~~2009~~2010			~~September~~March 3031, ~~2008~~2009
Cash paid during the period for:
Interest	$	188,~~182~~494		$	217,~~372~~776
Income taxes		—			—
Non-cash investing and financing activities:
Accrued additions to property and equipment		566			2,392
Non-cash additions to property and equipment		185			1,952
Non-cash additions to debt		~~(2,118~~—	)		~~(15~~679	)

(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~~March 3031, ~~2009~~2010 and ~~2008~~2009.

	Three months ended			Three months ended			~~Nine months ended~~			~~Nine months ended~~
	September 30, 2009			September 30, 2008			September 30, 2009			September 30, 2008
	March 31, 2010			March 31, 2009
Comprehensive (loss) income:
Comprehensive income:
Net (loss) income	$	(3,616	)	$	91,705		$	(16,740	)	$	21,164
Net income	$	19,100		$	13,242
Other comprehensive income (loss), net of tax:
Other comprehensive income, net of tax:
Unrealized gain in derivative fair value		—			18			—			409
Reclassification adjustment for derivative loss reclassified into earnings, net of tax		1,798			2,509
Reclassification adjustment for derivative loss reclassified into earnings		(556	)		(939	)		(3,429	)		(4,482	)
Change in accumulated other comprehensive income		1,798			2,509
Change in accumulated other comprehensive loss		(556	)		(921	)		(3,429	)		(4,073	)
	$	20,898		$	15,751
	$	(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 first quarter of 2010, we recorded expenses of approximately $1.4 million for operating overhead fees, $1.4 million for field labor, vehicles and district office expense and $228,000 for drilling labor costs related to this agreement. We recorded expenses of approximately $1.7 million for operating overhead fees, $1.6 million for field labor, vehicles and district office expense, $16,000 for drilling overhead fees and $520,000 for drilling labor costs in the first quarter 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 million. The note accrues interest at 10% per year and matures on August 16, 2012. The amount due under the note at March 31, 2010 was $30.5 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 made a cash interest payment of $752,000 in the first quarter of 2010 to Capital C, and borrowed an additional $679,000 against the note for the interest payment in the first quarter of 2009.

As of March 31, 2010, EnerVest Operating owed us $164,000 and we owed EnerVest $608,000.

(9) 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 10).

~~(8)~~In April ~~Related~~2010, ~~Party~~the ~~Transactions~~FASB issued ASU No. 2010-14, Accounting for Extractive Activities — Oil & Gas: Amendments to Paragraph 932-10-S99-1, to amend paragraph 932-10-S99-1 due to SEC Release No. 33-8995 [FR 78], Modernization of Oil and Gas Reporting.

WeNo ~~have~~other anew ~~joint~~accounting ~~operating~~pronouncements ~~agreement~~issued ~~with~~or ~~EnerVest~~effective ~~Operating~~during ~~LLC (“EnerVest Operating”). In~~ the ~~third~~ ~~quarter~~three 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 ofended ~~2009, we~~March ~~recorded costs of approximately $4.7 million (as general and administrative expense) for operating overhead fees~~31, ~~$4.4 million~~2010 ~~(as~~have ~~production~~had ~~expense)~~or ~~for~~are ~~field~~expected ~~labor, vehicles and district office expense, $81,000 (capitalized) for drilling overhead fees and $948,000 (capitalized) for drilling labor costs related~~ to ~~this~~have ~~agreement.~~a Wematerial ~~recorded~~impact ~~costs~~on ofour ~~approximately~~condensed ~~$4.9 million~~consolidated ~~for~~financial ~~operating overhead fees, $5~~statements.~~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~~(10) ~~million.~~Fair ~~The amount~~Value ~~due under the note at September 30, 2009 was $29.7 million. In lieu of cash payments, we~~Measurements 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.

AsThe offollowing ~~September 30,~~table ~~2009,~~presents wethe ~~owed~~fair ~~EnerVest~~value ~~$690,000~~hierarchy ~~and~~table ~~EnerVest~~for ~~Operating~~our ~~owed~~assets usand liabilities ~~$401,000.~~that ~~These~~are ~~amounts~~required ~~are~~to ~~included~~be inmeasured ~~accounts~~at ~~payable~~fair value on ~~the~~a ~~condensed~~recurring ~~consolidated balance~~basis: ~~sheet.~~

(9) Impairment of Oil and Gas Properties


				Fair Value Measurements at March 31, 2010 Using:
				Quoted Prices in		Significant
				Active Markets		Other			Significant
	Total			for Identical		Observable			Unobservable
	Carrying			Assets		Inputs			Inputs
	Value			(Level 1)		(Level 2)			(Level 3)
Derivative assets:
Oil and natural gas commodity contracts	$	2,072		$	—	$	2,072		$	—

Derivative liabilities:
Oil and natural gas commodity contracts	$	(57,986	)		—	$	(57,986	)		—
Interest rate swaps		(2,742	)		—		(2,742	)		—

Total derivative liabilities	$	(60,728	)	$	—	$	(60,728	)	$	—


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

Total derivative assets	$	891		$	—	$	891		$	—


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

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

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.

InOur ~~April 2009,~~derivatives ~~the~~consist ~~FASB~~of ~~issued new accounting guidance to require disclosures about~~ over-the ~~fair~~-counter ~~value~~(“OTC”) ofcontracts ~~financial~~which ~~instruments~~are ~~for~~not ~~interim reporting periods of publicly~~ traded ~~companies~~on asa ~~well~~public asexchange. inThese ~~annual~~derivatives ~~financial~~are ~~statements.~~indexed ~~This~~to ~~new~~active ~~guidance~~trading ishubs ~~effective~~ for ~~interim~~the ~~or financial~~underlying ~~periods ending after June 15~~commodity, ~~2009.~~and Weare ~~adopted~~OTC ~~this~~contracts ~~new~~commonly ~~guidance~~used in ~~our~~the ~~interim~~energy ~~period~~industry ~~ended~~and ~~June 30,~~offered ~~2009~~by ~~(see~~a ~~Notes~~number 2of financial institutions and ~~11)~~large energy companies.

InAs ~~May 2009,~~ the ~~FASB~~fair ~~issued~~value ~~new~~of ~~accounting~~these ~~guidance~~derivatives tois ~~establish~~based ~~standards~~on ofinputs ~~accounting~~using ~~for and~~market ~~disclosure~~prices ofobtained ~~events~~from independent ~~that~~brokers ~~occur~~or ~~after~~determined ~~the~~using ~~balance~~quantitative ~~sheet~~models ~~date~~that ~~but~~use ~~before~~as ~~financial~~their ~~statements~~basis readily ~~are~~observable ~~issued~~market orparameters that are ~~available~~actively toquoted and can be ~~issued~~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 ~~new~~observable ~~guidance~~data isincludes ~~effective~~the forward curve for ~~interim~~commodity orprices based ~~financial~~on quoted market prices and prospective volatility factors related to changes in the forward ~~periods~~curves ~~ending~~and ~~after~~yield ~~June 15,~~curves ~~2009~~based on money market rates and interest rate swap data. WeOur ~~adopted~~estimates ~~this~~of fair ~~new~~value ~~guidance~~have been determined at discrete points in ~~our~~time ~~interim~~based ~~period~~on ~~ended~~relevant ~~June~~market data. These ~~30,~~estimates ~~2009~~involve ~~(see~~uncertainty ~~Note~~and ~~13)~~cannot be determined with precision. There were no changes in valuation techniques or related inputs in the three months ended March 31, 2010.

~~In June 2009, the FASB issued The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principle~~ (~~the “Codification”~~11)~~. On September~~ ~~15,~~Asset ~~2009,~~Retirement ~~the~~Obligations 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.

NoIf ~~other~~a ~~new~~reasonable ~~accounting~~estimate ~~pronouncements~~of ~~issued~~the fair value of an obligation to perform site reclamation, dismantle facilities or ~~effective~~plug ~~during~~and abandon wells can be made, we record an asset retirement obligation (“ARO”) and capitalize the ~~nine~~asset ~~months~~retirement ~~ended~~cost in oil and natural gas properties in ~~September 30,~~the ~~2009~~period ~~have~~in ~~had~~which orthe ~~are~~retirement ~~expected~~obligation is incurred. After recording these amounts, the ARO is accreted to ~~have~~its afuture ~~material~~estimated ~~impact~~value onusing ~~our~~an ~~condensed~~assumed ~~consolidated~~cost of funds and the additional ~~financial~~capitalized ~~statements~~costs are depreciated on a unit-of-production basis. The changes in the aggregate ARO are as follows:

(11) Fair Value Measurements


Balance as of December 31, 2009	$	23,083
Accretion expense		319
Liabilities incurred		—
Liabilities settled		—
Revisions in estimated cash flows		—

Balance as of March 31, 2010	$	23,402

~~FASB accounting~~As ~~guidance~~of ~~establishes~~March 31, a2010 ~~valuation~~and ~~hierarchy~~December 31, ~~for~~2009, ~~disclosure~~$229,000 of ~~the~~our ~~inputs~~ARO tois ~~valuation~~classified ~~used~~as ~~to measure fair value~~current. ~~This hierarchy prioritizes the inputs into the following three levels:~~

~~• Level 1 inputs are quoted prices~~ (~~unadjusted~~12) inLong-Term ~~active markets for identical assets or~~Debt ~~liabilities.~~

~~• Level~~In 22005, ~~inputs~~we ~~are~~amended ~~quoted~~and ~~prices~~restated ~~for~~our ~~similar~~then ~~assets~~existing credit agreement, by entering into a First Amended and ~~liabilities~~Restated inCredit ~~active~~and ~~markets~~Guaranty orAgreement (“Amended Credit Agreement”) by and among us and ~~inputs~~BNP ~~that~~Paribas, ~~are~~as ~~observable~~sole ~~for~~lead ~~the~~arranger, ~~asset~~sole orbook ~~liability~~runner, ~~either~~syndication ~~directly~~agent orand ~~indirectly~~administrative ~~through~~agent. The ~~market~~Amended Credit Agreement provides for loans and other extensions of credit to be made to us. ~~corroboration~~The obligations under the Amended Credit Agreement are secured by substantially all of our assets.

•On March ~~Level~~23, 32010, ~~inputs~~we ~~are~~entered ~~unobservable~~into ~~inputs~~the ~~based~~Sixth onAmendment ~~our~~to ~~own~~the ~~assumptions~~Credit ~~used~~Agreement. The Credit Agreement was amended to ~~measure~~(1) add ~~assets~~a maximum senior secured leverage ratio of 2.00 : 1.00, (2) eliminate the maximum leverage ratio beginning December 31, 2009, (3) amend the minimum interest coverage ratio to 1.75 : 1.0 and ~~liabilities~~(4) make atcertain ~~fair~~other ~~value~~amendments to the Credit Agreement. At March 31, 2010, we were in compliance with such financial covenants under the Amended Credit Agreement.

A(13) Asset ~~financial asset or liability’s classification within the hierarchy is determined based on~~Dispositions ~~the lowest level input that is significant to the fair value measurement.~~

~~The~~On March 31, ~~following~~2010, ~~table~~we ~~presents~~agreed ~~the~~to ~~fair~~sell ~~value~~certain ~~hierarchy~~oil ~~table~~and ~~for~~natural ~~our~~gas assets ~~and~~for ~~liabilities~~approximately $45.2 million. ~~that~~The ~~are~~sale is subject to certain conditions, including purchaser due diligence, and ~~required~~is expected to beclose ~~measured~~by atJune 1, ~~fair~~2010. As of March 31, 2010 the recorded net book value onof a$2.0 million ~~recurring~~is ~~basis:~~classified as assets held for sale in the condensed consolidated balance sheet.

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

)

—

(14) Subsequent Events

The company has determined that there are no subsequent events which require recognition or disclosure in these condensed consolidated financial statements.

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~~2009, under the Heading “Risk Factors”, in this Form 10-Q 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~~10

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,
	Three months ended March 31,
	2009		2008		2009		2008
	2010		2009
Production
Gas (Mmcf)		2,~~941~~603		3,~~308~~177		~~9,288~~		~~9,902~~
Oil (Mbbls)		8367		8082		~~246~~		~~246~~
Total production (Mmcfe)		3,~~440~~006		3,~~789~~671		~~10,762~~		~~11,377~~
Average price (1)
Gas (per Mcf)	$	34.3913	$	93.8371	$	~~3.58~~	$	~~9.40~~
Oil (per Bbl)		6473.5128		~~115~~39.1020		~~52.61~~		~~108.19~~
Mcfe		45.4622		114.0209		~~4.29~~		~~10.52~~
Average costs (per Mcfe)
Production expense	$	1.4965	$	1.7370	$	~~1.52~~	$	~~1.72~~
Production taxes		0.0711		0.2409		~~0.07~~		~~0.22~~
Depletion		2.6158		2.2253		~~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,
	Three months ended March 31,
	2009		2008		2009		2008
	2010		2009
Gas (per Mcf)	$	35.7041	$	105.1800	$	~~4.19~~	$	~~10.04~~
Oil (per Bbl)		6473.5128		~~115~~39.1020		~~52.61~~		~~108.19~~
Mcfe		46.7332		115.3320		~~4.81~~		~~11.08~~

~~Results~~First ~~of Operations — Third~~ Quarters of ~~2009~~2010 and ~~2008~~2009 Compared

Revenues

~~Operating~~Net operating revenues ~~decreased~~increased from $4517.51 million in the ~~third~~first quarter of ~~2008~~2009 to $17.~~0 million~~4 million in the ~~third~~first quarter of ~~2009~~2010. The ~~decrease~~increase ~~in operating revenues~~ was primarily due to ~~lower~~higher 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~~673,000, ~~related~~partially tooffset ~~lower~~by ~~prices for oil and natural gas and~~ a $~~3.6 million~~330,000 decrease ~~due~~in ~~to lower~~ gas ~~sales~~gathering ~~volumes~~and marketing revenues.

Gas volumes sold ~~were~~decreased 2approximately 574,000 Mcf (18%) from 3.92 Bcf in the ~~third~~first quarter of 2009, ~~which~~to ~~was~~2.6 aBcf ~~decrease~~in ~~of 367 Mmcf (11%) compared to~~ the ~~third~~first quarter of ~~2008.~~2010 ~~This~~resulting ~~decrease~~ in ~~gas volumes sold resulted in~~ a decrease in gas sales revenues of approximately $32.61 million. Oil volumes sold ~~increased~~ decreased approximately 315,000 Bbls (418%) from 8082,000 Bbls in the ~~third~~first quarter of ~~2008~~2009 to 8367,000 Bbls in the ~~third~~ first quarter of ~~2009~~2010 resulting in ana decrease ~~increase~~ in oil sales revenues of approximately $~~330~~587,000. The lower gas ~~sales~~and oil volumes ~~are~~ were primarily due to ~~normal production declines and~~ the sale of ~~the~~ our coalbed methane assets in Pennsylvania in July 2009 and the normal production declines of base wells in 2010, which ~~are~~were partially offset by production from new wells drilled ~~and~~in ~~wells reworked during 2008 and~~ 2009.

1211

The average price realized for our natural gas ~~decreased~~increased $60.4442 per Mcf from $93.8371 in the ~~third~~first quarter of ~~2008~~2009 to $34.3913 per Mcf in the ~~third~~first quarter of ~~2009~~2010, which ~~reduced~~increased gas sales revenues by approximately $191.01 million. As a result of our qualified hedging and derivative financial instrument activities, gas sales revenues were lower by $~~921,000~~3.3 million ($01.3128 per Mcf) in the ~~third~~first quarter of ~~2009~~2010 and lower by $14.21 million ($01.3529 per Mcf) in the ~~third~~first quarter of ~~2008~~2009 than if our gas price was not affected by derivative financial instruments. The average price realized for our oil ~~decreased~~increased from $~~115~~39.1020 per Bbl in the ~~third~~first quarter of ~~2008~~2009 to $6473.5128 per Bbl in the ~~third~~ first quarter of ~~2009~~2010, which ~~reduced~~ increased oil sales revenues by approximately $4.2.3 million.

Gas gathering and marketing revenues decreased ~~from~~approximately $~~3.6 million~~330,000 ~~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~~ 276,000 decrease in gas marketing revenues and a $~~600~~54,000 decrease in gas gathering revenues. asThe alower ~~result~~gas gathering ofand marketing revenues were primarily due to lower ~~average~~ gas ~~prices~~volumes in the ~~third~~first quarter of 2010 ~~2009~~ compared to the ~~third~~first quarter of ~~2008~~2009.

Costs and Expenses

Production expense decreased ~~$1.5 million~~ from $6.62 million in the ~~third~~first quarter of ~~2008~~2009 to $5.10 million in the ~~third~~first quarter of ~~2009~~2010. The average production cost ~~decreased~~was ~~from~~ $1.7370 per Mcfe in the ~~third~~first quarter of 2009 ~~2008~~and to $1.4965 ~~per Mcfe~~ in the ~~third~~first quarter of ~~2009~~2010. ~~The~~Production ~~decrease~~expenses were lower in the first quarter ~~production~~of ~~expense~~2010 ~~was~~primarily due to ~~decreases~~a decrease in ~~labor~~well ~~costs~~maintenance, ~~gas~~employee ~~processing costs~~expenses, ~~well~~gas ~~work~~processing ~~activity,~~fees and the sale of ~~the~~our coalbed methane assets in Pennsylvania, ~~and~~which ~~general~~were ~~decreases~~partially inoffset ~~third~~by ~~party~~an ~~service~~increase ~~costs~~in gas compression fees.

Production taxes ~~decreased~~increased $~~649~~13,000 from $~~895~~322,000 in the ~~third~~first quarter of ~~2008~~2009 to $~~246~~335,000 in the ~~third~~first quarter of ~~2009~~2010. Average per unit production taxes ~~decreased~~increased from $0.2409 per Mcfe in the ~~third~~first quarter of ~~2008~~2009 to $0.0711 per Mcfe in the ~~third~~first quarter of ~~2009~~2010. The ~~decreased~~increased production taxes ~~were~~are primarily due to ~~lower~~higher oil and gas prices in Michigan, inwhere ~~the~~production ~~third~~taxes ~~quarter~~are based on a percentage of ~~2009 compared~~revenues, toexcluding the ~~third~~effects ~~quarter~~ of ~~2008.~~hedging, Inand ~~Michigan,~~the ~~production~~sale ~~taxes~~of ~~are~~our ~~based~~coalbed onmethane assets ain ~~percentage~~Pennsylvania ~~of revenues,~~where ~~excluding~~there ~~the~~is ~~effects~~no ofseverance ~~hedging~~tax.

~~Gas~~Exploration ~~gathering~~expense ~~and marketing expenses~~ decreased $1.4 million from $21.85 million in the ~~third~~first quarter of ~~2008 to~~2009 to $~~1.2 million~~141,000 in the ~~third~~first quarter of ~~2009~~2010. ~~The~~This decrease was primarily due to ~~a $1.7 million decrease in gas marketing expenses as a result of~~ lower ~~average~~noncash ~~gas prices in the third quarter of~~write-off ~~2009~~of ~~compared~~costs related to ~~the~~expired ~~third~~undeveloped ~~quarter of 2008~~leases.

~~Exploration~~General and administrative expense decreased $~~765~~348,000 from $12.62 million in the ~~third~~first quarter of ~~2008~~2009 to $~~849,000~~1.8 million in the ~~third~~first quarter of ~~2009~~2010. ~~The~~This decrease ~~in exploration expense~~ was primarily due to a decrease in ~~dry~~bad ~~hole~~debt expense in the first quarter of 2010.

~~Impairment~~Depreciation, ofdepletion ~~oil~~ and ~~gas~~amortization ~~properties~~decreased ~~was~~by a$1.6 million ~~credit~~from $9.4 million in the first quarter of 2009 to $17.38 million in the ~~third~~first quarter of ~~2009~~2010. This decrease was primarily due to ana ~~adjustment~~decrease toin depletion expense. Depletion expense decreased $1.5 million (16%) from $9.3 million in the ~~impairment~~first quarter of ~~coalbed~~2009 ~~methane~~to ~~properties~~$7.8 million in ~~Pennsylvania~~the ~~properties~~first quarter of 2010 primarily due to ~~which~~the ~~was~~lower ~~recorded~~gas inand oil volumes discussed above. Depletion per Mcfe increased from $2.53 per Mcfe in the ~~second~~first quarter of 2009. ~~These~~to ~~properties~~$2.58 ~~were~~per ~~sold~~Mcfe in the ~~third~~first quarter of 2010. The increase was primarily due to a decrease in oil and gas reserves as of December 31, 2009.

~~General~~Derivative ~~and~~fair ~~administrative~~value ~~expense~~(gain) loss ~~decreased~~was ~~$594,000~~a ~~from~~gain of $231.2 million in the ~~third~~first quarter of ~~2008~~2009 compared to a gain of $124.61 million in the ~~third~~first quarter of 2010 due to the fluctuation in oil and gas prices in the first quarters of 2009 and 2010. The ~~decrease~~derivative ~~was~~fair ~~primarily~~value ~~due~~(gain) loss toreflects the ~~lower~~changes in fair value of certain derivative instruments that are not designated or do not ~~overhead~~qualify ~~fees~~as ~~incurred~~cash toflow ~~EverVest~~hedges and ~~lower~~the ~~franchise~~cash ~~tax~~settlements ~~expense~~on those hedges.

~~Depreciation,~~Interest ~~depletion~~expense ~~and amortization~~ increased by $~~549~~157,000 from $84.58 million in the ~~third~~ first quarter of ~~2008~~2009 to $95.1 0 million in the ~~third~~first quarter of ~~2009~~2010. This increase was ~~primarily~~ due to ~~a $560,000~~higher ~~increase~~blended ininterest ~~depletion expense. Depletion per Mcfe increased from $2.22 per Mcfe in the~~rates ~~third~~partially ~~quarter~~offset ofby ~~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~~debt ~~and gas prices~~levels.

~~Derivative~~Income ~~fair~~tax ~~value~~provision ~~loss~~decreased ~~(gain)~~from $8.7 ~~was~~million ain ~~loss~~the first quarter of 2009 to $~~539~~577,000 in the ~~third~~first quarter of ~~2009~~2010. ~~compared to~~The adecrease ~~gain~~was ofprimarily ~~$134.8 million~~due into the ~~third~~elimination ~~quarter~~of the state of ~~2008~~Ohio corporate income tax. The Ohio ~~derivative~~corporate ~~fair~~income ~~value~~tax ~~loss~~was replaced with a Commercial Activity Tax which is not considered an income tax under FASB Accounting Standards Codification (~~gain~~“ASC”) No. 740, Accounting for Income ~~reflects~~Taxes. As a result of the ~~changes~~change in ~~fair~~the ~~value~~Ohio ofstate ~~certain~~law, ~~derivative~~deferred ~~instruments~~tax ~~that~~amounts ~~are~~previously ~~not~~recorded were ~~designated~~adjusted orto ~~do not~~reflect ~~qualify~~the aschange ~~cash~~and ~~flow~~resulted ~~hedges~~in a reduction of $6.8 million in income tax expense. The ~~change~~remaining decrease was primarily due to a decrease in income before income taxes and a lower effective tax rate as a result of the ~~fluctuation~~elimination of ~~oil~~the ~~and~~Ohio ~~gas~~corporate ~~prices~~income ~~during~~tax in the ~~those~~first ~~periods~~quarter of 2010.

1312

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~~first ~~month~~quarter ~~period~~of ~~ended~~2010 ~~September 30,~~were ~~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 natural gas.

15Our operating activities provided cash flows of $2.3 million during the first quarter of 2010 compared to $6.6 million in the first quarter of 2009. The decrease was primarily due to changes in working capital items of $5.5 million.

~~Table~~Cash flows used in investing activities were $881,000 in the first quarter of ~~Contents~~2010 compared to $3.8 million in the first quarter of 2009. The decrease was primarily due to a decrease in additions to property and equipment of $3.2 million and a decrease in the proceeds from property and equipment disposals of $746,000.

~~Our~~Cash ~~operating activities provided cash~~ flows ofused ~~$18.3 million~~in ~~during~~financing ~~the~~activities ~~first~~increased ~~nine months of 2009 compared to $79.7 million~~ in the first ~~nine~~quarter ~~months~~ of ~~2008.~~2010 ~~The decrease was~~ primarily due to to a $2.8 million decrease in ~~oil and gas revenues (net of hedging) which was partially offset by an increase~~ in the ~~change~~settlement ~~in working capital items~~ of $7derivative liabilities.~~1 million.~~

Our ~~investing~~current ~~activities~~ratio ~~provided~~at ~~cash~~March 31, ~~flows~~2010 ofwas $42.~~5 million~~46 ~~during~~to 1. During the first ~~nine~~quarter ~~months~~ of 2010, the ~~2009~~working ~~compared~~capital toincreased $179.49 million ~~used~~from in$28.2 million ~~the~~at ~~first~~December 31, ~~nine~~2009 ~~months~~to of$38.1 million ~~2008~~at March 31, 2010. The increase was primarily due to a decrease in the current liability related to the fair value of derivatives of $9.3 million, a decrease in ~~capital~~accrued ~~expenditures~~expenses of $3.8 million, an increase in assets held for sale of $2.0 million, a decrease in accounts payable $907,000 and an increase in ~~cash~~the ~~received~~current ~~for~~asset ~~property~~related ~~and~~to the fair value of derivatives of $872,000, which were ~~equipment~~partially ~~disposals~~offset by a decrease in the deferred tax asset of $144.3 million and a decrease in cash of $2.4 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~~quarter ~~months~~ of ~~2009~~2010, we spent approximately $~~10.7 million~~669,000 on ~~our~~operational ~~drilling activities and other~~ capital expenditures. In the first ~~nine~~quarter ~~months~~ of ~~2009~~2010, we ~~drilled~~had 3no ~~gross (1.7~~drilling ~~net) wells, which were all completed as producing wells in the target formation~~activity. ~~We also~~ ~~performed major workovers on 15 wells during the first nine months of 2009.~~

We currently expect to spend approximately $1211.71 million during ~~2009~~2010 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~~March 3031, ~~2009~~2010, we had cash of $844.04 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 activities and our ~~workover~~ability ~~activities~~to acquire additional producing properties. There can be no assurance that the future drilling of our proved undeveloped locations will provide adequate liquidity in the future.

Financing and Credit Facilities

OnIn ~~September 25~~2005, ~~2009,~~we ~~Belden~~amended &and ~~Blake~~restated ~~Corporation~~our ~~entered~~then ~~into~~existing ~~the~~credit ~~Fifth~~agreement, ~~Amendment~~by toentering ~~Credit~~into a First ~~Agreement.~~Amended ~~The~~and Restated Credit ~~Agreement~~and ~~was~~Guaranty ~~amended~~Agreement to (~~1) reduce~~“Amended ~~the~~Credit ~~borrowing~~Agreement”) ~~base~~by toand ~~$65 million,~~among ~~(2)~~us and ~~extend~~BNP ~~the~~Paribas, ~~termination~~as ~~date~~sole bylead ~~one~~arranger, ~~year~~sole tobook ~~August 16~~runner, ~~2011,~~syndication ~~(3) decrease~~agent ~~the~~and ~~aggregate~~administrative ~~amount of~~agent. ~~the~~The ~~revolving~~Amended ~~commitments~~Credit toAgreement ~~$100 million,~~provides ~~and~~for ~~(4) make~~loans ~~certain~~and other ~~amendments~~extensions of credit to be made to us. The obligations under the Amended Credit Agreement are secured by substantially all of our assets.

~~At September 30, 2009, we had an Amended Credit Agreement comprised of a five-year $100~~13 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~~On ~~obligations~~March 23, ~~under~~2010, we entered into the ~~Amended~~Sixth Amendment to the Credit Agreement. ~~are~~The ~~secured~~Credit Agreement bywas aamended ~~first~~to ~~lien~~(1) add ~~security interest~~a inmaximum ~~substantially~~senior ~~all~~secured ofleverage ~~our~~ratio ~~assets~~of 2.00 ~~The~~: ~~obligations~~1.00, ~~under~~(2) eliminate the ~~Amended~~maximum ~~Credit~~leverage ~~Agreement~~ratio ~~are~~beginning December 31, 2009, (3) amend the minimum interest ~~further~~coverage ~~secured~~ratio byto a1.75 ~~pledge~~: of1.0 ~~100%~~and of(4) make ~~our~~certain ~~capital~~other ~~stock~~amendments ~~held~~to bythe ~~Capital~~Credit CAgreement. At March 31, ~~our~~2010, ~~parent~~we were in compliance with such financial covenants under the Amended Credit Agreement.

~~The~~At March 31, 2010, we had an Amended Credit Agreement ~~contains~~comprised ~~covenants~~of ~~that~~a ~~will~~five-year ~~limit~~$100 million revolving orfacility ~~prohibit~~with ~~our~~a ~~ability~~borrowing tobase of $65 million, of which $43.9 million was outstanding at ~~among~~March 31, ~~other~~2010. ~~things~~This facility is for working capital requirements and general corporate purposes, including ~~incur~~the orissuance ~~guarantee~~of ~~additional~~letters ~~indebtedness~~of credit; ~~create~~and ~~liens;~~a ~~pay~~five ~~dividends~~year on$40 million orletter of credit facility ~~repurchase~~that ~~stock;~~may ~~pay~~be ~~principal~~used only to provide credit support for our obligations under the hedge agreement and other ~~interest~~hedge ontransactions. ~~certain~~Borrowings ~~subordinated~~under ~~debt;~~the ~~make~~Amended ~~certain~~Credit ~~types~~Agreement ofbear interest (i) at the ~~investments;~~greater ~~sell~~of ~~assets~~the orprime ~~merge~~rate, ~~with~~an ~~another~~adjusted ~~entity;~~federal ~~pledge~~funds rate or ~~otherwise~~an ~~encumber~~adjusted ~~our~~Eurodollar ~~capital~~rate, plus an ~~stock;~~applicable ormargin ~~enter~~ranging ~~into~~from ~~transactions~~1.0% ~~with~~to ~~affiliates~~2.0% ~~The~~based on the aggregate principal amount outstanding under the Amended Credit Agreement, ~~also~~or, ~~requires~~(ii) at our option, the Eurodollar base rate plus an ~~compliance~~applicable ~~with~~margin ~~customary~~ranging ~~financial~~from ~~covenants,~~2.5% ~~including~~to a3.50% ~~minimum~~based ~~interest~~on ~~coverage~~the ~~ratio,~~aggregate aprincipal amount outstanding ~~maximum~~under ~~leverage~~the ~~ratio~~Amended ~~and~~Credit aAgreement. ~~minimum~~The ~~current~~full ~~ratio~~amount borrowed under the Amended Credit Agreement will mature on August 16, 2011.

~~Changes~~In inconnection ~~oil~~with ~~and~~our ~~gas~~entry ~~prices~~into ~~significantly~~the ~~affect~~Amended ~~our~~Credit ~~revenues~~Agreement, ~~financial~~we ~~condition,~~executed ~~cash~~a Subordinated ~~flows~~Promissory ~~and~~Note ~~borrowing~~(“Subordinated ~~capacity.~~Note”) ~~Markets~~in ~~for~~favor ~~oil~~of ~~and~~Capital ~~gas~~C ~~have~~in ~~historically~~the ~~been~~maximum ~~volatile~~principal ~~and~~amount weof ~~expect~~$94 ~~this~~million. ~~trend~~Under tothe ~~continue.~~Subordinated ~~Prices~~Note, ~~for~~Capital ~~oil~~C ~~and~~loaned ~~gas~~$25 million ~~may~~to ~~fluctuate~~us inon ~~response~~August 16, to2005. ~~changes~~The Subordinated inNote ~~supply~~accrues ~~and demand,~~interest ~~market~~at ~~uncertainty,~~a ~~seasonal,~~rate ~~political~~of ~~and~~10% ~~other~~per ~~factors~~annum ~~beyond~~and ~~our~~matures ~~control.~~on WeAugust 16, ~~are~~2012. ~~unable~~In tolieu ~~accurately~~of ~~predict~~cash ~~the~~payments, ~~prices~~ we ~~will~~have ~~receive~~the ~~for~~option ~~our~~to ~~oil~~make ~~and~~interest ~~gas.~~payments ~~Accordingly,~~on ~~any~~the ~~significant or~~Subordinated ~~sustained~~Note ~~declines~~by borrowing inadditional ~~oil~~amounts ~~and~~against ~~gas~~the ~~prices~~Subordinated ~~will~~Note. ~~materially~~The ~~adversely~~Subordinated ~~affect~~Note ~~our~~has ~~financial~~no ~~condition,~~prepayment ~~operating~~penalty ~~results,~~or ~~liquidity~~premium and ~~ability~~may tobe ~~obtain~~prepaid ~~additional~~in ~~financing~~whole or toin ~~refinance our~~part ~~Amended~~at ~~Credit~~any ~~Agreement~~time. ~~upon~~Pursuant ~~maturity.~~to ~~Continued~~the Fourth orAmendment ~~prolonged~~to ~~low~~our ~~oil~~credit ~~and~~agreement ~~gas~~cash ~~prices~~payments ~~may~~for ~~also result~~principal inor ~~non-compliance~~interest ~~with~~on ~~our~~the Subordinated ~~financial~~Note ~~covenants~~are inprohibited. ~~our~~The ~~Amended~~Subordinated ~~Credit~~Note ~~Agreement.~~is Ifsubordinate weto ~~were not~~our insenior ~~compliance~~debt, ~~with~~which includes ~~the~~obligations ~~covenants~~under inthe aAmended ~~future~~Credit ~~period~~Agreement, ana ~~event~~long-term ofhedging ~~default~~program ~~may~~(the ~~occur which could~~“Hedges”) ~~cause~~with ~~all~~J. ~~outstanding~~Aron ~~debt~~ under ~~the~~a ~~Amended~~master ~~Credit~~agreement ~~Agreement,~~and ~~the~~related ~~senior~~confirmations ~~secured notes~~ and ~~our~~documentation (collectively, ~~derivative~~the ~~contracts~~“Hedge toAgreement”) beand ~~due~~notes ~~and~~issued ~~payable.~~under Weour ~~expect~~Indenture todated ~~maintain~~July 7, ~~compliance~~2004 with ~~the~~BNY ~~covenants~~Midwest ~~through~~Trust ~~2009~~Company, ~~and~~as ~~2010~~indenture trustee (“Senior Secured Notes”).

~~At September 30, 2009, we were in compliance with our covenants under the Amended Credit~~14 ~~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

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.


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~~ 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~~ March 3031, ~~2009~~2010, we had an interest rate ~~swaps~~swap in place ~~covering~~on $43.5 million of our ~~outstanding~~ ~~balance~~outstanding ondebt under the revolving credit ~~agreement~~facility through September 30, 2013. The ~~fair~~swap ~~value~~provides a of1-month ~~these~~LIBOR ~~interest~~fixed ~~rate~~rates ~~swaps~~at ~~was~~4.10%, ~~an unrealized~~plus ~~loss~~the ofapplicable margin, on $243.85 million at through September 302013. These interest rate swaps do not qualify for hedge accounting, ~~2009~~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 quarterly interest expense ~~in the first nine months of 2009~~ would be approximately $~~603~~109,000. The impact of ~~the~~this ~~interest~~ rate increase on our cash flows would be significantly less than this amount due to ~~the~~our interest rate swaps ~~in place~~. ~~The~~If ~~impact of the~~market interest ~~rate~~rates ~~increase~~increased 1% there would ~~reduce~~be ~~our~~no ~~cash~~decrease ~~flows~~in byour ~~approximately~~cash ~~$94,000~~flow. This sensitivity ~~analysis~~ analysis is based on our financial structure at ~~September~~March 3031, ~~2009~~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~~March 3031, ~~2009~~2010, we had derivatives covering a portion of our ~~oil~~ oil and gas production from ~~2009~~2010 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 $64.31 million in the first ~~nine~~three months of ~~2008~~2009 and a net pre-tax loss of $53.6 3 million in the first ~~nine~~three months of ~~2009~~2010 on our qualified hedging activities.

If gas prices decreased $1.00 per Mcf, our gas sales revenues for the ~~first~~quarter ~~nine months of 2009~~ would decrease by approximately $92.36 million. If the price of crude oil decreased $10.00 per Bbl, our oil sales revenues for the ~~first~~quarter ~~nine months of 2009~~ would decrease by approximately $2672,000.~~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~~quarter ~~nine months of 2009~~ by approximately $~~3.2 million~~604,000 after considering the effects of the derivative contracts in place as of ~~September~~ March 3031, ~~2009~~2010. This sensitivity analysis is based on our first ~~nine~~quarter ~~months~~2010 ~~2009~~ oil and gas sales volumes.

1915

The following table reflects the natural gas and crude oil volumes and the weighted average prices under financial hedges (including settled hedges) at ~~October~~April ~~31, 2009, which has not changed since September~~ 30, ~~2009~~2010:

	Natural Gas Swaps				Crude Oil Swaps				Natural Gas Basis Swaps
			NYMEX				NYMEX				~~Basis~~
	Bbtu		Price per Mmbtu		Mbbls		Price per Bbl		Bbtu		Differential
			Price per				Price per				Basis
	Bbtu		Mmbtu		Mbbls		Bbl		Bbtu		Differential
Quarter Ending
December 31, 2009		2,382	$	4.47		48	$	29.09		2,116	$	0.34
June 30, 2010		2,234	$	4.11		44	$	28.88		1,911	$	0.243
September 30, 2010		2,234		4.12		44		28.82		1,932		0.243
December 31, 2010		2,234		4.31		44		28.77		1,932		0.243
		6,702	$	4.18		132	$	28.82		5,775	$	0.243
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 $9555.7 9 million as of ~~September~~March 3031, ~~2009~~2010.

At ~~September~~March 3031, ~~2009~~2010, we had interest rate swaps in place ~~covering~~through September 30, 2013 covering $43.5 million of our outstanding debt under the revolving credit facility~~. On September 29~~, ~~2009,~~which wecurrently ~~amended the~~matures ~~existing~~on ~~swaps to cover $43.5~~August ~~million of our outstanding debt through September 30~~16, ~~2013~~2011. The ~~amended~~ swaps provide 1-month LIBOR fixed rates ofat 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~~March 3031, ~~2009~~2010 were effective, at a reasonable assurance level, in 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~~March 3031, ~~2009~~2010 that has materially affected, or ~~are~~is 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

AsOther than as described in this item 1A, as of the date of this filing, there have been no significant 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~~ 2009.

~~These~~The ~~risks~~following ~~and~~risk ~~uncertainties~~factor ~~are~~in ~~not~~our ~~the~~Form ~~only~~10-K ~~ones~~for ~~facing~~the usyear ~~and~~ending ~~there~~December 31, ~~may~~2009, beis ~~additional~~revised ~~matters~~as ~~that~~follows weto ~~are~~include ~~unaware~~a description of oraction ~~that~~taken weby ~~currently~~the ~~consider~~Environmental ~~immaterial.~~Protection ~~All~~Agency ofon ~~these could~~March ~~adversely affect our business~~23, ~~financial condition, results of operations and cash flows~~2010.

~~Item 2.~~Climate ~~Unregistered~~change ~~Sales~~legislation or regulations restricting emissions of ~~Equity~~GHGs ~~Securities~~could result in increased operating costs and ~~Use~~reduced ofdemand ~~Proceeds~~for the oil and natural gas we produce.

On December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal CAA. Accordingly, the EPA has proposed two sets of regulations that would require a reduction in emissions of GHGs from motor vehicles and could trigger permit review for GHG emissions from certain stationary sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States beginning in 2011 for emissions occurring in 2010. On March 23, 2010, the EPA announced that it will be proposing a rule to extend this reporting obligation to oil and gas facilities, including onshore and offshore oil and natural gas production facilities, which may include facilities we operate.

On June 26, 2009, the House of Representatives passed the ACESA which would establish an economy wide cap and trade program to reduce U.S. emissions of GHGs, including carbon dioxide and methane. ACESA would require a 17% reduction in GHG emissions from 2005 levels by 2020 and just over an 80% reduction of such emissions by 2050. Under this legislation, the EPA would issue a capped and steadily declining number of tradable emissions allowances authorizing emissions of GHGs into the atmosphere. These reductions would be expected to cause the cost of allowances to escalate significantly over time. The net effect of ACESA will be to impose increasing costs on the combustion of carbon based fuels such as oil, refined petroleum products and natural gas. The U.S. Senate has begun work on its own legislation for restricting domestic GHG emissions and the Obama Administration has indicated its support for legislation to reduce GHG emissions through an emission allowance system. At the state level, more than one third of the states, either individually or through multistate regional initiatives, already have begun implementing legal measures to reduce emissions of GHGs. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGS associated with our operations or could adversely affect demand for the oil and natural gas that we produce.

These risks and uncertainties in our Form 10-K and this Form 10-Q 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~~(Removed ofand ~~Matters to a Vote of Security Holders~~ Reserved)


Item 5.		Other Information.

None.

~~Item 5. Other Information~~18

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.

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

* Filed herewith.


	+31.1			Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.

	+31.2			Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.

	+32.1			Section 1350 Certification of Chief Executive Officer.

	+32.2			Section 1350 Certification of Chief Financial Officer.

22 + 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
Date: May 12, 2010	By:	/s/ Mark A. Houser
		Mark A. Houser, Chief Executive Officer,
		Chairman of the Board of Directors and Director (Principal Executive Officer)
		Chairman of the Board of Directors and Director
Date: November 12, 2009	By:	/s/ James M. Vanderhider
Date: May 12, 2010	By:	/s/ James M. Vanderhider
		James M. Vanderhider, President,
		Chief Financial Officer and Director (Principal Financial Officer)

2320

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

Table of Contents

Table of Contents

Filing Compare · BELDEN & BLAKE CORP /OH/