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 March 31, 2010

or

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

For the transition period from                      to                     

Commission File Number: 0-20100

BELDEN & BLAKE CORPORATION

(Exact name of registrant as specified in its charter)

Ohio	34-1686642
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
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 definition of “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 April 30, 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 March 31, 2010 and December 31, 2009		1
Condensed Consolidated Statements of Operations: Three months ended March 31, 2010 and 2009		2
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		10
Item 3. Quantitative and Qualitative Disclosures About Market Risk		15
Item 4. Controls and Procedures		16
PART II Other Information
Item 1. Legal Proceedings		17
Item 1A. Risk Factors		17
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		18
Item 3. Defaults upon Senior Securities		18
Item 4. (Removed and Reserved)		18
Item 5. Other Information		18
Item 6. Exhibits		19
Signatures		20
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)

	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

See accompanying notes.

1

BELDEN & BLAKE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(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

See accompanying notes.

2

BELDEN & BLAKE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(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

See accompanying notes.

3

BELDEN & BLAKE CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2010

(1) Basis of Presentation

Unless the context requires otherwise or unless otherwise noted, when we use the terms “Belden & Blake,” “we,” “us,” “our” or the “Company,” we are referring to Belden & Blake Corporation and its predecessors. On August 16, 2005, the former partners of the direct parent of Belden & Blake Corporation, Capital C Energy Operations, L.P., a Delaware limited partnership (“Capital C”), completed the sale of all of the partnership interests in Capital C to certain institutional funds managed by EnerVest, Ltd. (“EnerVest”), a Houston-based privately held oil and gas operator and institutional funds manager.

The accompanying unaudited financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the period ended March 31, 2010 are not necessarily indicative of the results that may be expected for the year ended December 31, 2010. For further information, refer to the consolidated financial statements and footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2009.

(2) Derivatives and Hedging

From time to time, we may enter into a combination of futures contracts, derivatives and fixed-price physical commodity contracts to manage our exposure to natural gas price, crude oil price or interest rate volatility and support our capital expenditure plans. Our derivative financial instruments take the form of swaps or collars. At March 31, 2010, our derivative contracts were comprised of natural gas swaps, natural gas basis differential swaps, crude oil swaps and interest rate swaps which were placed with major financial institutions that we believe are a minimal credit risk. All of our derivative instruments are currently accounted for as non-qualifying derivative contracts. The changes in fair value of non-qualifying derivative contracts are reported in expense in the condensed consolidated statements of operations as derivative fair value gain.

We have certain derivative contracts that qualified for hedge accounting treatment in prior periods, as well as derivative contracts that were de-designated in prior periods. During the first quarters of 2010 and 2009, net losses of $3.3 million ($1.8 million after tax) and $4.1 million ($2.5 million after tax), respectively, were reclassified from accumulated other comprehensive loss to earnings. The value of open hedges in accumulated other comprehensive loss decreased $3.3 million ($1.8 million after tax) in the first quarter of 2010 and decreased $4.1 million ($2.5 million after tax) in the first quarter of 2009. At March 31, 2010, the estimated net loss in accumulated other comprehensive loss that is expected to be reclassified into earnings within the next 12 months is approximately $3.5 million after tax. At March 31, 2010, we have partially hedged our exposure to the variability in future cash flows through December 2013.

4

The following table reflects the natural gas and crude oil volumes and the weighted average prices under derivative contracts (including settled derivative contracts) at March 31, 2010:

	Natural Gas Swaps				Crude Oil Swaps				Natural Gas Basis Swaps
			NYMEX				NYMEX
			Price per				Price per				Basis
	Bbtu		Mmbtu		Mbbls		Bbl		Bbtu		Differential
Quarter Ending
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		—		—

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 March 31, 2010 , the fair value of these derivatives was as 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.

5

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

	Three Months Ended
	March 31,
	2010			2009
The following amounts are recorded in Oil and gas sales:
Unrealized losses:
Oil and natural gas commodity contracts	$	(3,309	)	$	(4,079	)
The following are recorded in Derivative fair value gain:
Unrealized (gains) losses:
Oil and natural gas commodity contracts	$	(28,779	)	$	(33,003	)
Interest rate swaps		388			(281	)
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	)

(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, accrued liabilities, long-term debt and derivatives. Our derivatives are recorded at fair value (see Notes 2 and 10). The carrying amount of our other financial instruments other than debt approximates fair value because of the short-term nature of the items. The carrying value of our debt, including our senior secured noted and subordinated promissory note, approximates fair value because the interest rates approximate current market rates.

(5) Supplemental Disclosure of Cash Flow Information

	Three months ended		Three months ended
(in thousands)	March 31, 2010		March 31, 2009
Cash paid during the period for:
Interest	$	8,494	$	7,776
Non-cash investing and financing activities:
Non-cash additions to property and equipment		185		1,952
Non-cash additions to debt		—		679

6

(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 for the three-month periods ended March 31, 2010 and 2009.

	Three months ended		Three months ended
	March 31, 2010		March 31, 2009
Comprehensive income:
Net income	$	19,100	$	13,242
Other comprehensive income, net of tax:
Reclassification adjustment for derivative loss reclassified into earnings, net of tax		1,798		2,509
Change in accumulated other comprehensive income		1,798		2,509
	$	20,898	$	15,751

(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).

7

In April 2010, the 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.

No other new accounting pronouncements issued or effective during the three months ended March 31, 2010 have had or are expected to have a material impact on our condensed consolidated financial statements.

(10) Fair Value Measurements

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

				Fair Value Measurements at 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	)	$	—

8

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

As the fair value of these derivatives is based on inputs using market prices obtained from independent brokers or determined using quantitative models that use as their basis readily observable market parameters that are actively quoted and can be validated through external sources, including third party pricing services, brokers and market transactions, we have categorized these derivatives as Level 2. We value these derivatives based on observable market data for similar instruments. This observable data includes the forward curve for commodity prices based on quoted market prices and prospective volatility factors related to changes in the forward curves and yield curves based on money market rates and interest rate swap data. Our estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty and cannot be determined with precision. There were no changes in valuation techniques or related inputs in the three months ended March 31, 2010.

(11) Asset Retirement Obligations

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

Balance as of December 31, 2009	$	23,083
Accretion expense		319
Liabilities incurred		—
Liabilities settled		—
Revisions in estimated cash flows		—
Balance as of March 31, 2010	$	23,402

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

(12) Long-Term Debt

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

On March 23, 2010, we entered into the Sixth Amendment to the Credit Agreement. The Credit Agreement was amended to (1) add 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 (4) make certain other amendments to the Credit Agreement. At March 31, 2010, we were in compliance with such financial covenants under the Amended Credit Agreement.

(13) Asset Dispositions

On March 31, 2010, we agreed to sell certain oil and natural gas assets for approximately $45.2 million. The sale is subject to certain conditions, including purchaser due diligence, and is expected to close by June 1, 2010. As of March 31, 2010 the recorded net book value of $2.0 million is classified as assets held for sale in the condensed consolidated balance sheet.

(14) Subsequent Events

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

9

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

Forward-Looking Information

The information in this document includes forward-looking statements that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Statements preceded by, followed by or that otherwise include the statements “should,” “believe,” “expect,” “anticipate,” “intend,” “continue,” “estimate,” “plan,” “outlook,” “may,” “future,” “projection,” “likely,” “possible,” “could” and variations of these statements and similar expressions are forward-looking statements as are any other statements relating to developments, events, occurrences, results, efforts or impacts. These forward-looking statements are based on current expectations and projections about future events. Forward-looking statements and the business prospects of Belden & Blake are subject to a number of risks and uncertainties which may cause our actual results in future periods to differ materially from the forward-looking statements contained herein. These risks and uncertainties include, but are not limited to, our access to capital, the market demand for and prices of oil and natural gas, our oil and gas production and costs of operation, results of our future drilling activities, the uncertainties of reserve estimates, general economic conditions, new legislation or regulatory changes, changes in accounting principles, policies or guidelines and environmental risks. These and other risks are described in our Annual Report on Form 10-K for the year ended December 31, 2009, under the Heading “Risk Factors”, 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.

10

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 March 31,
	2010		2009
Production
Gas (Mmcf)		2,603		3,177
Oil (Mbbls)		67		82
Total production (Mmcfe)		3,006		3,671
Average price (1)
Gas (per Mcf)	$	4.13	$	3.71
Oil (per Bbl)		73.28		39.20
Mcfe		5.22		4.09
Average costs (per Mcfe)
Production expense	$	1.65	$	1.70
Production taxes		0.11		0.09
Depletion		2.58		2.53

(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 March 31,
	2010		2009
Gas (per Mcf)	$	5.41	$	5.00
Oil (per Bbl)		73.28		39.20
Mcfe		6.32		5.20

First Quarters of 2010 and 2009 Compared

Revenues

Net operating revenues increased from $17.1 million in the first quarter of 2009 to $17.4 million in the first quarter of 2010. The increase was primarily due to higher oil and gas sales revenues of $673,000, partially offset by a $330,000 decrease in gas gathering and marketing revenues.

Gas volumes sold decreased approximately 574,000 Mcf (18%) from 3.2 Bcf in the first quarter of 2009 to 2.6 Bcf in the first quarter of 2010 resulting in a decrease in gas sales revenues of approximately $2.1 million. Oil volumes sold decreased approximately 15,000 Bbls (18%) from 82,000 Bbls in the first quarter of 2009 to 67,000 Bbls in the first quarter of 2010 resulting in a decrease in oil sales revenues of approximately $587,000. The lower gas and oil volumes were primarily due to the sale of our coalbed methane assets in Pennsylvania in July 2009 and the normal production declines of base wells in 2010, which were partially offset by production from new wells drilled in 2009.

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The average price realized for our natural gas increased $0.42 per Mcf from $3.71 in the first quarter of 2009 to $4.13 per Mcf in the first quarter of 2010, which increased gas sales revenues by approximately $1.1 million. As a result of our qualified hedging and derivative financial instrument activities, gas sales revenues were lower by $3.3 million ($1.28 per Mcf) in the first quarter of 2010 and lower by $4.1 million ($1.29 per Mcf) in the first quarter of 2009 than if our gas price was not affected by derivative financial instruments. The average price realized for our oil increased from $39.20 per Bbl in the first quarter of 2009 to $73.28 per Bbl in the first quarter of 2010, which increased oil sales revenues by approximately $2.3 million.

Gas gathering and marketing revenues decreased approximately $330,000 due to a $276,000 decrease in gas marketing revenues and a $54,000 decrease in gas gathering revenues. The lower gas gathering and marketing revenues were primarily due to lower gas volumes in the first quarter of 2010 compared to the first quarter of 2009.

Costs and Expenses

Production expense decreased from $6.2 million in the first quarter of 2009 to $5.0 million in the first quarter of 2010. The average production cost was $1.70 per Mcfe in the first quarter of 2009 and $1.65 in the first quarter of 2010. Production expenses were lower in the first quarter of 2010 primarily due to a decrease in well maintenance, employee expenses, gas processing fees and the sale of our coalbed methane assets in Pennsylvania, which were partially offset by an increase in gas compression fees.

Production taxes increased $13,000 from $322,000 in the first quarter of 2009 to $335,000 in the first quarter of 2010. Average per unit production taxes increased from $0.09 per Mcfe in the first quarter of 2009 to $0.11 per Mcfe in the first quarter of 2010. The increased production taxes are primarily due to higher oil and gas prices in Michigan, where production taxes are based on a percentage of revenues, excluding the effects of hedging, and the sale of our coalbed methane assets in Pennsylvania where there is no severance tax.

Exploration expense decreased $1.4 million from $1.5 million in the first quarter of 2009 to $141,000 in the first quarter of 2010. This decrease was primarily due to lower noncash write-off of costs related to expired undeveloped leases.

General and administrative expense decreased $348,000 from $2.2 million in the first quarter of 2009 to $1.8 million in the first quarter of 2010. This decrease was primarily due to a decrease in bad debt expense in the first quarter of 2010.

Depreciation, depletion and amortization decreased by $1.6 million from $9.4 million in the first quarter of 2009 to $7.8 million in the first quarter of 2010. This decrease was primarily due to a decrease in depletion expense. Depletion expense decreased $1.5 million (16%) from $9.3 million in the first quarter of 2009 to $7.8 million in the first quarter of 2010 primarily due to the lower gas and oil volumes discussed above. Depletion per Mcfe increased from $2.53 per Mcfe in the first quarter of 2009 to $2.58 per Mcfe in the first quarter of 2010. The increase was primarily due to a decrease in oil and gas reserves as of December 31, 2009.

Derivative fair value (gain) loss was a gain of $31.2 million in the first quarter of 2009 compared to a gain of $24.1 million in the first quarter of 2010 due to the fluctuation in oil and gas prices in the first quarters of 2009 and 2010. The derivative fair value (gain) loss reflects the changes in fair value of certain derivative instruments that are not designated or do not qualify as cash flow hedges and the cash settlements on those hedges.

Interest expense increased $157,000 from $4.8 million in the first quarter of 2009 to $5.0 million in the first quarter of 2010. This increase was due to higher blended interest rates partially offset by lower debt levels.

Income tax provision decreased from $8.7 million in the first quarter of 2009 to $577,000 in the first quarter of 2010. The decrease was primarily due to the elimination of the state of Ohio corporate income tax. The Ohio corporate income tax was replaced with a Commercial Activity Tax which is not considered an income tax under FASB Accounting Standards Codification (“ASC”) No. 740, Accounting for Income Taxes. As a result of the change in the Ohio state law, deferred tax amounts previously recorded were adjusted to reflect the change and resulted in a reduction of $6.8 million in income tax expense. The remaining decrease was primarily due to a decrease in income before income taxes and a lower effective tax rate as a result of the elimination of the Ohio corporate income tax in the first quarter of 2010.

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Liquidity and Capital Resources

Cash Flows

The primary sources of cash in the first quarter of 2010 were funds generated from operations. Funds used during this period were primarily used for operations, development expenditures and interest expense. Our liquidity and capital resources are closely related to and dependent upon the current prices paid for our oil and natural gas.

Our operating activities provided cash flows of $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.

Cash flows used in investing activities were $881,000 in the first quarter of 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.

Cash flows used in financing activities increased in the first quarter of 2010 primarily due to a $2.8 million decrease in the settlement of derivative liabilities.

Our current ratio at March 31, 2010 was 2.46 to 1. During the first quarter of 2010, the working capital increased $9.9 million from $28.2 million at December 31, 2009 to $38.1 million 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 accrued 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 the current asset related to the fair value of derivatives of $872,000, which were partially offset by a decrease in the deferred tax asset of $4.3 million and a decrease in cash of $2.4 million.

Capital Expenditures

During the first quarter of 2010, we spent approximately $669,000 on operational capital expenditures. In the first quarter of 2010, we had no drilling activity.

We currently expect to spend approximately $11.1 million during 2010 on our drilling activities and other capital expenditures. We intend to finance our planned capital expenditures through our cash on hand and available operating cash flow. At March 31, 2010, we had cash of $44.4 million. The level of our future cash flow will depend on a number of factors including the demand for and price levels of oil and gas, the scope and success of our drilling activities and our ability to acquire additional producing properties. There can be no assurance that the future drilling of our proved undeveloped locations will provide adequate liquidity in the future.

Financing and Credit Facilities

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

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On March 23, 2010, we entered into the Sixth Amendment to the Credit Agreement. The Credit Agreement was amended to (1) add 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 (4) make certain other amendments to the Credit Agreement. At March 31, 2010, we were in compliance with such financial covenants under the Amended Credit Agreement.

At March 31, 2010, we had an Amended Credit Agreement comprised of a five-year $100 million revolving facility with a borrowing base of $65 million, of which $43.9 million was outstanding at March 31, 2010. This facility is for working capital requirements and general corporate purposes, including the issuance of letters of credit; and a five year $40 million letter of credit facility that may be used only to provide credit support for our obligations under the hedge agreement and other hedge transactions. Borrowings under the Amended Credit Agreement bear interest (i) at the greater of the prime rate, an adjusted federal funds rate or an adjusted Eurodollar rate, plus an applicable margin ranging from 1.0% to 2.0% based on the aggregate principal amount outstanding under the Amended Credit Agreement, or, (ii) at our option, the Eurodollar base rate plus an applicable margin ranging from 2.5% to 3.50% based on the aggregate principal amount outstanding under the Amended Credit Agreement. The full amount borrowed under the Amended Credit Agreement will mature on August 16, 2011.

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

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Among other risks, we are exposed to interest rate and commodity price risks.

The interest rate risk relates to existing debt under our revolving credit facility as well as any new debt financing needed to fund capital requirements. We may manage our interest rate risk through the use of interest rate swaps to hedge the interest rate exposure associated with the credit agreement, whereby a portion of our floating rate exposure is exchanged for a fixed interest rate. A portion of our long-term debt consists of senior secured notes where the interest component is fixed. At March 31, 2010, we had an interest rate swap in place on $43.5 million of our outstanding debt under the revolving credit facility through September 30, 2013. The swap provides a 1-month LIBOR fixed rates at 4.10%, plus the applicable margin, on $43.5 million through September 2013. These interest rate swaps do not qualify for hedge accounting, therefore, all cash settles and changes in the fair value of these swaps are recorded in derivative fair value gain/loss. If market interest rates for short-term borrowings increased 1%, the increase in our quarterly interest expense would be approximately $109,000. The impact of this rate increase on our cash flows would be significantly less than this amount due to our interest rate swaps. If market interest rates increased 1% there would be no decrease in our cash flow. This sensitivity analysis is based on our financial structure at March 31, 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 March 31, 2010, we had derivatives covering a portion of our oil and gas production from 2010 through 2013. Our oil and gas sales revenues included a net pre-tax loss of $4.1 million in the first three months of 2009 and a net pre-tax loss of $3.3 million in the first three months of 2010 on our qualified hedging activities.

If gas prices decreased $1.00 per Mcf, our gas sales revenues for the quarter would decrease by approximately $2.6 million. If the price of crude oil decreased $10.00 per Bbl, our oil sales revenues for the quarter would decrease by approximately $672,000. 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 quarter by approximately $604,000 after considering the effects of the derivative contracts in place as of March 31, 2010. This sensitivity analysis is based on our first quarter 2010 oil and gas sales volumes.

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The following table reflects the natural gas and crude oil volumes and the weighted average prices under financial hedges (including settled hedges) at April 30, 2010:

	Natural Gas Swaps				Crude Oil Swaps				Natural Gas Basis Swaps
			NYMEX				NYMEX
			Price per				Price per				Basis
	Bbtu		Mmbtu		Mbbls		Bbl		Bbtu		Differential
Quarter Ending
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		—		—

The fair value of our oil and gas swaps was a net liability of approximately $55.9 million as of March 31, 2010.

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.

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 March 31, 2010 were effective, at a reasonable assurance level, in ensuring that the information required to be disclosed by us in reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.

Change in Internal Controls Over Financial Reporting

There have not been any changes in our internal controls over financial reporting that occurred during the quarterly period ended March 31, 2010 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

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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

Other 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, 2009.

The following risk factor in our Form 10-K for the year ending December 31, 2009, is revised as follows to include a description of action taken by the Environmental Protection Agency on March 23, 2010.

Climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand 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.

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

None.

Item 3. Defaults upon Senior Securities.

None.

Item 4. (Removed and Reserved)

Item 5. Other Information.

None.

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Item 6. Exhibits.

(a) Exhibits

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

+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.

+ Filed herewith

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SIGNATURES

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

	BELDEN & BLAKE CORPORATION
Date: May 12, 2010	By:	/s/ Mark A. Houser
		Mark A. Houser, Chief Executive Officer,
		Chairman of the Board of Directors and Director
Date: May 12, 2010	By:	/s/ James M. Vanderhider
		James M. Vanderhider, President,
		Chief Financial Officer and Director (Principal Financial Officer)

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