Filed by Bowne Pure Compliance

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended June 30, 2008


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

For the transition period from _______________ to _______________

Commission File Number: 0-20100

BELDEN & BLAKE CORPORATION

(Exact name of registrant as specified in its charter)


Ohio		34-1686642

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

1001 Fannin Street, Suite 800
Houston, Texas		77002

(Address of principal executive offices)		(Zip Code)

(713) 659-3500
(Registrant’s telephone number, including area code)

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

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


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

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

As of July 31, 2008, Belden & Blake Corporation had outstanding 1,534 shares of common stock, without par value, which is its only class of stock.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

BELDEN & BLAKE CORPORATION

BALANCE SHEETS

(unaudited, in thousands, except number of shares)


	June 30,			December 31,
	2008			2007

ASSETS
Current assets
Cash and cash equivalents	$	20,056		$	16,014
Accounts receivable (less accumulated provision for doubtful accounts: June 30, 2008- $585; December 31, 2007 - $806)		28,589			18,071
Accounts receivable — related party		631			—
Inventories		999			1,084
Deferred income taxes		37,440			17,282
Other current assets		166			370
Fair value of derivatives		—			37

Total current assets		87,881			52,858

Property and equipment, at cost
Oil and gas properties (successful efforts method)		722,292			713,912
Gas gathering systems		1,308			1,308
Land, buildings, machinery and equipment		2,832			2,761

		726,432			717,981
Less accumulated depreciation, depletion and amortization		105,930			88,549

Property and equipment, net		620,502			629,432
Goodwill		90,076			90,076
Fair value of derivatives		124			29
Other assets		1,540			1,830

	$	800,123		$	774,225


LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Accounts payable	$	1,898		$	1,148
Accounts payable — related party		—			1,508
Accrued expenses		25,131			20,363
Current portion of long-term liabilities		378			367
Fair value of derivatives		94,665			43,696

Total current liabilities		122,072			67,082

Long-term liabilities
Bank and other long-term debt		99,942			99,947
Senior secured notes		163,780			164,240
Subordinated promissory note — related party		26,946			26,931
Asset retirement obligations and other long-term liabilities		22,714			22,164
Fair value of derivatives		254,772			192,661
Deferred income taxes		75,063			98,977

Total long-term liabilities		643,217			604,920

Shareholder’s equity
Common stock: without par value; 3,000 shares authorized and 1,534 shares issued		—			—
Paid in capital		125,000			125,000
Retained earnings		(74,351	)		(3,810	)
Accumulated other comprehensive loss		(15,815	)		(18,967	)

Total shareholder’s equity		34,834			102,223

	$	800,123		$	774,225

See accompanying notes.

BELDEN & BLAKE CORPORATION

STATEMENTS OF OPERATIONS

(unaudited, in thousands)


	Three months ended			Three months ended			Six months ended			Six months ended
	June 30, 2008			June 30, 2007			June 30, 2008			June 30, 2007
Revenues
Oil and gas sales	$	46,558		$	32,027		$	77,926		$	58,829
Gas gathering and marketing		3,528			2,774			6,378			5,394
Other		216			386			305			447

		50,302			35,187			84,609			64,670

Expenses
Production expense		6,493			6,456			12,978			12,259
Production taxes		924			642			1,596			1,193
Gas gathering and marketing		3,064			2,270			5,402			4,474
Exploration expense		367			303			559			1,028
Impairment of oil and gas properties		2,011			—			2,011			—
General and administrative expense		2,055			1,933			4,015			3,860
Depreciation, depletion and amortization		8,354			9,454			17,359			18,013
Accretion expense		349			319			688			630
Derivative fair value loss		118,404			3,985			145,226			46,141

		142,021			25,362			189,834			87,598

Operating (loss) income		(91,719	)		9,825			(105,225	)		(22,928	)

Other (income) expense
Interest expense		5,812			5,938			11,658			11,835
Other income, net		(104	)		(108	)		(230	)		(215	)

(Loss) income before income taxes		(97,427	)		3,995			(116,653	)		(34,548	)
(Benefit) provision for income taxes		(38,520	)		1,580			(46,112	)		(13,664	)

Net (loss) income	$	(58,907	)	$	2,415		$	(70,541	)	$	(20,884	)

See accompanying notes.

BELDEN & BLAKE CORPORATION

STATEMENTS OF CASH FLOWS

(unaudited, in thousands)


	Six months ended			Six months ended
	June 30, 2008			June 30, 2007
Cash flows from operating activities:
Net loss	$	(70,541	)	$	(20,884	)
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization		17,359			18,013
Accretion expense		688			630
Gain on disposal of property and equipment		—			(57	)
Amortization of derivatives and other non-cash hedging activities		149,807			49,108
Exploration expense		559			279
Deferred income taxes		(46,112	)		(13,664	)
Impairment of oil and gas properties		2,011			—
Other non-cash items		(233	)		1,159
Change in operating assets and liabilities
Accounts receivable and other current assets		(10,946	)		1,050
Inventories		107			(57	)
Accounts payable and accrued expenses		2,371			(167	)

Net cash provided by operating activities		45,070			35,410

Cash flows from investing activities:
Additions to property and equipment		(11,998	)		(11,203	)
Proceeds from property and equipment disposals		3,049			270
Exploration expense		(559	)		(279	)
Increase in other assets		78			(44	)

Net cash used in investing activities		(9,430	)		(11,256	)

Cash flows from financing activities:
Proceeds from revolving line of credit		—			4,500
Repayment of long-term debt and other obligations		(5	)		(21	)
Settlement of derivative liabilities recorded in purchase accounting		(31,593	)		(14,297	)
Dividends paid		—			(6,750	)

Net cash used in financing activities		(31,598	)		(16,568	)


Net increase in cash and cash equivalents		4,042			7,586
Cash and cash equivalents at beginning of period		16,014			5,927

Cash and cash equivalents at end of period	$	20,056		$	13,513

See accompanying notes.

BELDEN & BLAKE CORPORATION

NOTES TO FINANCIAL STATEMENTS

(unaudited)

June 30, 2008

(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. On August 16, 2005, the former partners of the direct parent of Belden & Blake Corporation (the “Company”), Capital C Energy Operations, L.P., a Delaware limited partnership (“Capital C”), completed the sale of all of the partnership interests in Capital C to certain institutional funds managed by EnerVest, Ltd. (“EnerVest”), a Houston-based privately held oil and gas operator and institutional funds manager (the “Transaction”).

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 June 30, 2008 are not necessarily indicative of the results that may be expected for the year ended December 31, 2008. For further information, refer to the financial statements and footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2007. Certain reclassifications have been made to previously reported amounts in order to conform to current year presentation. Such reclassifications do not effect earnings. Interest income is reported in “Other income, net” in the Statements of Operations. For the three and six months ended June 30, 2007 “Other income, net” has been adjusted to include $108,000 and $215,000, respectively, of interest income to conform with current year presentation. These amounts were previously recorded as “Other” revenue in our Statements of Operations. This reclassification had no material impact on total operating revenue, operating income or net income for the three and six months ended June 30, 2007.

(2) Derivatives and Hedging

From time to time, we may enter into a combination of futures contracts, commodity derivatives and fixed-price physical commodity contracts to manage our exposure to natural gas, crude oil or interest rate price volatility and support our capital expenditure plans. Our derivative financial instruments take the form of swaps or collars. At June 30, 2008, 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. Qualifying derivative financial instruments are designated as cash flow hedges. Changes in fair value of the derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time the hedged items impact earnings. The changes in fair value of non-qualifying derivative contracts will be reported in expense in the statements of operations as derivative fair value loss.

During the first six months of 2008 and 2007, net losses of $5.9 million ($3.5 million after tax) and $3.0 million ($1.8 million after tax), respectively, were reclassified from accumulated other comprehensive income to earnings. At June 30, 2008, the estimated net loss in accumulated other comprehensive income that is expected to be reclassified into earnings within the next 12 months is approximately $5.6 million. At June 30, 2008, 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 hedges (including settled hedges) at June 30, 2008:


	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
September 30, 2008		2,532		4.44		52		29.86		—		—
December 31, 2008		2,532		4.59		52		29.68		—		—

		5,064	$	4.52		104	$	29.77		—	$	—

Year Ending
December 31, 2009		9,529		4.43		191		29.34		3,650		0.345
December 31, 2010		8,938		4.28		175		28.86		3,650		0.325
December 31, 2011		8,231		4.19		157		28.77		3,285		0.325
December 31, 2012		7,005		4.09		138		28.70		—		—
December 31, 2013		6,528		4.04		127		28.70		—		—

At June 30, 2008, we had interest rate swaps in place for $80 million of our outstanding debt under our revolving credit facility that mature between September 16, 2008 and September 30, 2010. The swaps provide 1-month LIBOR fixed rates at 4.285% on $40 million and 5.160% on $40 million through September 16, 2008 and 4.07% on $80 million from September 2008 through September 2010, plus the applicable margin. The fair value of these interest rate swaps was an unrealized loss of $861,000 at June 30, 2008.

(3) Industry Segment Financial Information

We operate in one reportable segment, as an independent energy company engaged in producing oil and natural gas; exploring for and developing oil and gas reserves; acquiring and enhancing the economic performance of producing oil and gas properties; and marketing and gathering natural gas for delivery to intrastate and interstate gas transmission pipelines. Our operations are conducted entirely in the United States.

(4) Supplemental Disclosure of Cash Flow Information


	Six months ended			Six months ended
(in thousands)	June 30, 2008			June 30, 2007
Cash paid during the period for:
Interest	$	11,865		$	11,710
Income taxes		—			—
Non-cash investing and financing activities:
Non-cash additions to property and equipment		1,639			754
Non-cash additions to debt		(15	)		(623	)

(5) 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.

(6)

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 six-month periods ended June 30, 2008 and 2007.


	Six months ended			Six months ended
	June 30, 2008			June 30, 2007
Comprehensive income (loss):
Net loss	$	(70,541	)	$	(20,884	)
Other comprehensive income (loss), net of tax:
Unrealized (loss) gain in derivative fair value		391			(14	)
Reclassification adjustment for derivative (loss) gain reclassified into earnings		(3,543	)		(1,778	)

Change in accumulated other comprehensive (loss) income		(3,152	)		(1,792	)

	$	(73,693	)	$	(22,676	)

(7) Related Party Transactions

We have a joint operating agreement with EnerVest Operating LLC (“EnerVest Operating”). In the first six months of 2008, we recorded costs of approximately $3.2 million (as general and administrative expense) for operating overhead fees, $3.4 million (as production expense) for field labor, vehicles and district office expense, $123,000 (capitalized) for drilling overhead fees and $341,000 (capitalized) for drilling labor costs related to this agreement. We recorded costs of approximately $2.9 million for operating overhead fees, $3.7 million for field labor, vehicles and district office expense, $154,000 for drilling overhead fees and $552,000 for drilling labor costs in the first six months of 2007 related to this agreement. We have a Note in favor of our parent, Capital C in the maximum amount of $94 million. The amount due under the note at June 30, 2008 was $26.9 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 cash interest payments of $1.3 million in the first six months of 2008 and $616,000 in the first quarter of 2007 to Capital C. We borrowed $623,000 against the note for the interest payment in the second quarter of 2007.

(8) Impairment of Oil and Gas Properties

For the period ended June 30, 2008, we reviewed our oil and gas properties for impairment as prescribed by SFAS No. 144, 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 quarter to proved properties in the Utica Shale formation in Ohio.

(9) New Accounting Standards

In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, Fair Value Measurements, to provide guidance for using fair value to measure assets and liabilities. SFAS No. 157 was to be effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years; however, in February 2008, the FASB issued FASB Staff Position FAS 157–2, Effective Date of FASB Statement No. 157, which delayed the effective date of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis, for one year. We adopted SFAS No. 157 on January 1, 2008 for our financial assets and financial liabilities.

SFAS 157 establishes a valuation hierarchy for disclosure of the inputs to valuation used to measure fair value. This hierarchy prioritizes the inputs into the following three levels:

•

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

•

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

•

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

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

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

Fair Value Measurements at June 30, 2008

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

(349,314

)

—

(349,314

)

—

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.

We will adopt SFAS No. 157 on January 1, 2009 for our nonfinancial assets and nonfinancial liabilities, and we have not yet determined the impact, if any, on our consolidated financial statements.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. Unrealized gains and losses on items for which the fair value option has been selected are reported in earnings. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We have elected not to apply the provisions of SFAS No. 159.

In December 2007, the FASB issued SFAS No 141 (Revised 2007), Business Combinations (“SFAS No. 141(R)”) to significantly change the accounting for business combinations. Under SFAS No. 141(R), an acquiring entity will be required to recognize all the assets acquired and liabilities assumed in a transaction at the acquisition date fair value with limited exceptions and will change the accounting treatment for certain specific items, including:

•

acquisition costs will generally be expensed as incurred;

•

noncontrolling interests will be valued at fair value at the date of acquisition; and

•

liabilities related to contingent consideration will be recorded at fair value at the date of acquisition and subsequently remeasured each subsequent reporting period.

SFAS No. 141(R) is effective for fiscal years beginning after December 15, 2008. We will adopt SFAS No. 141(R) on January 1, 2009, and we have not yet determined the impact, if any, on our consolidated financial statements.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements – An Amendment of ARB No. 51, to establish new accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 requires the recognition of a noncontrolling interest (minority interest) as equity in the consolidated financial statements and separate from the parent’s equity. The amount of net income attributable to the noncontrolling interest will be included in consolidated net income on the face of the income statement. SFAS No. 160 clarifies that changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation are equity transactions if the parent retains its controlling financial interest. In addition, SFAS No. 160 requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS No. 160 also includes expanded disclosure requirements regarding the interests of the parent and its noncontrolling interest. SFAS No. 160 is effective for fiscal years beginning after December 15, 2008. We will adopt SFAS No. 160 on January 1, 2009, and we have not yet determined the impact, if any, on our consolidated financial statements.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133. SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities and how they affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 is effective for fiscal years and interim periods beginning after November 15, 2008. We will adopt SFAS No. 161 on January 1, 2009, and we have not yet determined the impact, if any, on our consolidated financial statements.

In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles. SFAS No. 162 identifies the sources for accounting principles and the framework for selecting the principles to be used in preparing financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States. SFAS No. 162 is effective 60 days following the Securities and Exchanges Commission’s approval of the Public Company Accounting Oversight Board Auditing amendments to AU Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.

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, 2007, under the Heading “Risk Factors” and in our other filings with the Securities and Exchange Commission (“SEC”). We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, changes in assumptions, or otherwise.

Results of Operations

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


	Three months ended June 30,				Six months ended June 30,
	2008		2007		2008		2007
Production
Gas (Mmcf)		3,282		3,437		6,594		6,732
Oil (Mbbls)		83		90		166		182
Total production (Mmcfe)		3,780		3,979		7,588		7,822

Average price (1)
Gas (per Mcf)	$	11.22	$	7.71	$	9.18	$	7.17
Oil (per Bbl)		117.08		61.31		104.84		58.22
Mcfe		12.32		8.05		10.27		7.52

Average costs (per Mcfe)
Production expense	$	1.72	$	1.62	$	1.71	$	1.57
Production taxes		0.24		0.16		0.21		0.15
Depletion		2.18		2.35		2.26		2.27


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


	Three months ended June 30,				Six months ended June 30,
	2008		2007		2008		2007
Gas (per Mcf)	$	11.47	$	7.93	$	9.97	$	7.61
Oil (per Bbl)		117.08		61.31		104.84		58.22
Mcfe		12.53		8.24		10.95		7.90

Results of Operations — Second Quarters of 2008 and 2007 Compared

Revenues

Operating revenues increased from $35.2 million in the second quarter of 2007 to $50.3 million in the second quarter of 2008. The increase in operating revenues was primarily due to higher oil and gas sales revenues of $14.5 million. The increased oil and gas sales revenues were primarily due to an increase of $16.1 million related to increased prices for oil and natural gas, which was partially offset by a $1.6 million decrease in revenues due to decreased production volumes.

Gas volumes sold were 3.3 Bcf in the second quarter of 2008, which was a decrease of 155 Mmcf (5%) compared to the second quarter of 2007. This decrease in gas volumes sold resulted in a decrease in gas sales revenues of approximately $1.2 million. Oil volumes sold decreased approximately 7,000 Bbls (8%) from 90,000 Bbls in the second quarter of 2007 to 83,000 Bbls in the second quarter of 2008 resulting in a decrease in oil sales revenues of approximately $450,000. The lower oil and gas sales volumes are primarily due to normal production declines which were partially offset by production from new wells drilled during 2007 and 2008.

The average price realized for our natural gas increased $3.51 per Mcf from $7.71 in the second quarter of 2007 to $11.22 per Mcf in the second quarter of 2008, which increased gas sales revenues by approximately $11.5 million. As a result of our hedging activities, gas sales revenues were lower by $819,000 ($0.25 per Mcf) in the second quarter of 2008 and lower by $765,000 ($0.22 per Mcf) in the second quarter of 2007 than if our gas price was not affected by derivative financial instruments. The average price realized for our oil increased from $61.31 per Bbl in the second quarter of 2007 to $117.08 per Bbl in the second quarter of 2008, which increased oil sales revenues by approximately $4.6 million.

Gas gathering and marketing revenues increased from $2.8 million in the second quarter of 2007 to $3.5 million in the second quarter of 2008. The increase was due to a $687,000 increase in gas marketing revenues and a $67,000 increase in gas gathering revenues as a result of higher average gas prices in the second quarter of 2008 compared to the second quarter of 2007.

Costs and Expenses

Production expense was $6.5 million in the second quarter of 2007 and 2008. The average production cost increased from $1.62 per Mcfe in the second quarter of 2007 to $1.72 per Mcfe in the second quarter of 2008. The increase in production cost per Mcfe was due to the lower volumes produced in 2008.

Production taxes increased $282,000 from $642,000 in the second quarter of 2007 to $924,000 in the second quarter of 2008. Average per unit production taxes increased from $0.16 per Mcfe in the second quarter of 2007 to $0.24 per Mcfe in the second quarter of 2008. The increased production taxes were primarily due to higher oil and gas sales revenues in Michigan in the second quarter of 2008 compared to the second quarter of 2007. In Michigan, production taxes are based on a percentage of revenues, excluding the effects of hedging.

Gas gathering and marketing expenses increased from $2.3 million in the second quarter of 2007 to $3.1 million in the second quarter of 2008. The increase was primarily due to a $694,000 increase in gas marketing expenses as a result of higher average gas prices in the second quarter of 2008 compared to the second quarter of 2007.

Exploration expense increased $64,000 from $303,000 in the second quarter of 2007 to $367,000 in the second quarter of 2008. The increase in exploration expense is primarily due to an increase in delay rental payments in the second quarter of 2008.

Impairment of oil and gas properties was $2.0 million in the second quarter of 2008 due to the impairment of properties in the Utica Shale formation in Ohio. There was no impairment of oil and gas properties in 2007.

General and administrative expense increased $122,000 from $1.9 million in the second quarter of 2007 to $2.1 million in the second quarter of 2008 primarily due to an increase in third party fees.

Depreciation, depletion and amortization decreased by $1.1 million from $9.5 million in the second quarter of 2007 to $8.4 million in the second quarter of 2008. This decrease was primarily due to a $1.1 million decrease in depletion expense. Depletion per Mcfe decreased from $2.35 per Mcfe in the second quarter of 2007 to $2.18 per Mcfe in the second quarter of 2008 due primarily to increased reserves volumes due to higher oil and gas prices at June 30, 2008.

Derivative fair value (gain) loss was a loss of $4.0 million in the second quarter of 2007 compared to a loss of $118.4 million in the second quarter of 2008. 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.

Interest expense decreased $126,000 from $5.9 million in the second quarter of 2007 to $5.8 million in the second quarter of 2008. This decrease in interest expense was due to lower blended interest rates, which were partially offset by the amortization of the fair value adjustments from purchase accounting on the Senior Secured Notes.

Income tax expense was a benefit of $38.5 million in the second quarter of 2008 compared to an expense of $1.6 million in the second quarter of 2007. The decrease is primarily due to a decrease in income before income taxes.

Results of Operations – Six Months of 2008 and 2007 Compared

Revenues

Operating revenues from oil and gas sales revenues increased from $64.7 million in the first six months of 2007 to $84.6 million in the first six months of 2008. The increase in operating revenues was primarily due to higher oil and gas sales revenues of $19.1 million. The increased revenues were primarily due to an increase of $21.0 million related to increased prices for oil and natural gas, which was partially offset by a $1.9 million decrease in revenues due to decreased production volumes.

Gas volumes sold were 6.6 Bcf in the first six months of 2008, which was a decrease of 138 Mmcf (2%) compared to the first six months of 2007. This decrease in gas volumes sold resulted in a decrease in gas sales revenues of approximately $990,000. Oil volumes sold decreased approximately 16,000 Bbls (9%) from 182,000 Bbls in the first six months of 2007 to 166,000 Bbls in the first six months of 2008 resulting in a decrease in oil sales revenues of approximately $930,000. The decrease in oil and gas sales volumes was primarily due to normal production declines, which were partially offset by production from new wells drilled in 2007 and 2008.

The average price realized for our natural gas increased $2.01 per Mcf from $7.17 in the first six months of 2007 to $9.18 per Mcf in the first six months of 2008, which increased gas sales revenues by approximately $13.3 million. As a result of our hedging activities, gas sales revenues were lower by $5.2 million ($0.79 per Mcf) in the first six months of 2008 and lower by $3.0 million ($0.44 per Mcf) in the first six months of 2007 than if our gas price was not affected by derivative financial instruments. The average price realized for our oil increased from $58.22 per Bbl in the first six months of 2007 to $104.84 per Bbl in the first six months of 2008, which increased oil sales revenues by approximately $7.7 million.

Gas gathering and marketing revenues increased from $5.4 million in the first six months of 2007 to $6.4 million in the first six months of 2008 due to a $832,000 increase in gas marketing revenues and a $152,000 increase in gas gathering revenues as a result of higher average gas prices in the first six months of 2008 compared to the first six months of 2007.

Costs and Expenses

Production expense increased from $12.3 million in the first six months of 2007 to $13.0 million in the first six months of 2008. The average production cost increased from $1.57 per Mcfe in the first six months of 2007 to $1.71 per Mcfe in the first six months of 2008. The increase in production expense was primarily due to increases in gas processing fees in Michigan and oilfield service costs. The increased in cost per Mcfe was due to cost increases and decreased production volumes.

Production taxes increased $403,000 from $1.2 million in the first six months of 2007 to $1.6 million in the first six months of 2008. Average per unit production taxes increased from $0.15 per Mcfe in the first six months of 2007 to $0.21 per Mcfe in the first six months of 2008. The increased production taxes are primarily due to higher oil and gas prices in the first six months of 2008 in Michigan, where production taxes are based on a percentage of revenues, excluding the effects of hedging.

Gas gathering and marketing expenses increased from $4.5 million in the first six months of 2007 to $5.4 million in the first six months of 2008, primarily due to a $854,000 increase in gas marketing expenses as a result of higher average gas prices in the first six months of 2008 compared to the first six months of 2007.

Exploration expense decreased $469,000 from $1.0 million in the first six months of 2007 to $559,000 in the first six months of 2008. This decrease in exploration expense is primarily due to the non-cash write off of costs related to undeveloped leases that expired in the first quarter of 2007.

Impairment of oil and gas properties was $2.0 million in the first six months of 2008 due to the impairment of properties in the Utica Shale formation in Ohio. There was no impairment of oil and gas properties in the first six months of 2007.

General and administrative expense increased from $3.9 million in the first six months of 2007 to $4.0 million in the first six months of 2008 primarily due to an increase in third party fees.

Depreciation, depletion and amortization decreased by $654,000 from $18.0 million in the first six months of 2007 to $17.4 million in the first six months of 2008. This decrease was primarily due to a $607,000 decrease in depletion expense due to the lower oil and gas sales volumes. Depletion per Mcfe was $2.27 per Mcfe in the first six months of 2007 and $2.26 in the first six months of 2008.

Derivative fair value loss was $46.1 million in the first six months of 2007 compared to $145.2 million in the first six months of 2008. The derivative fair value loss reflects the changes in fair value of certain derivative instruments that are not designated or do not qualify as cash flow hedges.

Interest expense decreased $177,000 from $11.8 million in the first six months of 2007 to $11.7 million in the first six months of 2008. This decrease in interest expense was due to lower blended interest rates, which were partially offset by the amortization of the fair value adjustments from purchase accounting on the Senior Secured Notes.

Income tax benefit increased from a benefit of $13.7 million for the first six months of 2007 to a benefit of $46.1 million for the first six months of 2008. The increase is primarily related to a increase in loss before taxes.

Liquidity and Capital Resources

Cash Flows

The primary sources of cash in the six-month period ended June 30, 2008 have been funds generated from operations. Funds used during this period were primarily used for operations, development expenditures, derivative settlements 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 $45.1 million during the first six months of 2008 compared to $35.4 million in the first six months of 2007. The increase was primarily due to an increase in cash received for oil and gas revenues (net of hedging) which was partially offset by a decrease in working capital items of $9.3 million.

Our investing activities used cash flows of $9.4 million during the first six months of 2008 compared to $11.3 million used in the first six months of 2007. The decrease is due an increase in cash received for property and equipment disposals of $3.0 million which was offset by an increase in capital expenditures of $795,000.

Cash flows used in financing activities increased $15.0 million in the first six months of 2008 primarily due to an increase of $17.3 million in derivative settlements and a decrease in proceeds from the revolving line of credit of $4.5 million which was offset by a decrease in dividends paid of $6.8 million.

Our current ratio at June 30, 2008 was 0.72 to 1. During the first six months of 2008, working capital decreased $20.0 million from a deficit of $14.2 million at December 31, 2007 to a deficit of $34.2 million at June 30, 2008. The decrease in working capital was primarily due to an increase of $51.0 million in the current liability related to the fair value of derivatives and an increase in accrued expenses of $4.8 million, which were partially offset by a $20.2 million increase in the current deferred tax asset, a $11.1 million increase in accounts receivable and a $4.0 million increase in cash.

Capital Expenditures

During the first six months of 2008, we spent approximately $13.4 million on our drilling activities and other capital expenditures. In the first six months of 2008, we drilled 52 gross (42.0 net) development wells and 2 gross (2.0 net) exploratory wells, all of which were completed as producing wells in the target formation.

We currently expect to spend approximately $38 million during 2008 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 June 30, 2008, we had cash of $20.1 million and approximately $12.6 million available under our revolving facility. The level of our future cash flow will depend on a number of factors including the demand for and price levels of oil and gas and the scope and success of our drilling activities. There can be no assurance that the future drilling of our proved undeveloped locations will provide adequate liquidity in the future.

Financing and Credit Facilities

At June 30, 2008, we had an Amended Credit Agreement comprised of a five-year $350 million revolving facility with a borrowing base of $113.4 million, of which $99.9 million was outstanding at June 30, 2008. 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 or an adjusted federal funds rate, plus an applicable margin ranging from 0% to 0.625% based on the aggregate principal amount outstanding under the Amended Credit Agreement, or, (ii) at our option, the Eurodollar base rate plus an applicable margin ranging from 1.125% to 2.125% based on the aggregate principal amount outstanding under the Amended Credit Agreement. The full amount borrowed under the Amended Credit Agreement will mature on August 16, 2010.

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

The Amended Credit Agreement contains covenants that will limit our ability to, among other things, incur or guarantee additional indebtedness; create liens; pay dividends on or repurchase stock; pay principal and interest on certain subordinated debt; make certain types of investments; sell assets or merge with another entity; pledge or otherwise encumber our capital stock; or enter into transactions with affiliates. The Amended Credit Agreement also requires compliance with customary financial covenants, including a minimum interest coverage ratio, a maximum leverage ratio and a minimum current ratio.

At June 30, 2008, the interest rate under our base rate option was 5.375%. Under our one-month LIBOR option, the rate was 4.365%. At June 30, 2008, we had $40.9 million of outstanding letters of credit. At June 30, 2008, there was $99.9 million outstanding under the revolving credit agreement. We had $12.6 million of borrowing capacity under our revolving facility available for general corporate purposes.

In connection with the Transaction, we executed a Note in favor of Capital C in the maximum principal amount of $94 million. Under the Note, Capital C loaned us $25 million. The Note accrues interest at a rate of 10% per annum and matures on August 16, 2012. We received a fairness opinion from an unrelated financial services firm with respect to the terms of the Note. Interest payments on the Note are due quarterly. In lieu of cash payments, we have the option to make interest payments on the Note by borrowing additional amounts against the Note. The Note has no prepayment penalty or premium and may be prepaid in whole or in part at any time. The Note is expressly subordinate to the our senior debt, which includes obligations under the Amended Credit Agreement, the J. Aron Swap and notes issued under our Indenture dated July 7, 2004 with BNY Midwest Trust Company, as indenture trustee.

New Accounting Standards

SFAS 157 establishes a valuation hierarchy for disclosure of the inputs to valuation used to measure fair value. This hierarchy prioritizes the inputs into the following three levels:

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

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

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

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

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

Fair Value Measurements at June 30, 2008

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

(349,314

)

—

(349,314

)

—

We will adopt SFAS No. 157 on January 1, 2009 for our nonfinancial assets and nonfinancial liabilities, and we have not yet determined the impact, if any, on our consolidated financial statements.

•

acquisition costs will generally be expensed as incurred;

•

noncontrolling interests will be valued at fair value at the date of acquisition; and

•

liabilities related to contingent consideration will be recorded at fair value at the date of acquisition and subsequently remeasured each subsequent reporting period.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

The interest rate risk relates to existing debt under our revolving facility as well as any new debt financing needed to fund capital requirements. We may manage our interest rate risk through the use of interest rate swaps to hedge the interest rate exposure associated with the credit agreement, whereby a portion of our floating rate exposure is exchanged for a fixed interest rate. A portion of our long-term debt consists of senior secured notes where the interest component is fixed. At June 30, 2008, we had interest rate swaps in place covering $80 million of our outstanding balance on the revolving credit agreement. The fair value of these interest rate swaps was an unrealized loss of $861,000 at June 30, 2008. If market interest rates for short-term borrowings increased 1%, the increase in interest expense in the first six months of 2008 would be approximately $100,000. This sensitivity analysis is based on our financial structure at June 30, 2008.

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 June 30, 2008, we had derivatives covering a portion of our oil and gas production from 2008 through 2013. Our oil and gas sales revenues included a net pre-tax loss of $3.0 million in the first six months of 2007 and a net pre-tax loss of $5.2 million in the first six months of 2008 on our qualified hedging activities.

Our oil and gas derivatives no longer qualify for cash flow hedge accounting. Therefore, changes in the fair value of the oil and gas derivatives are recorded in derivative fair value gain/loss. Deferred gains or losses on the gas derivatives are recognized as increases or decreases to gas sales revenues during the same periods in which the underlying forecasted transactions impact earnings. If gas prices decreased $1.00 per Mcf, our gas sales revenues for the first six months of 2008 would decrease by approximately $6.6 million. If the price of crude oil decreased $10.00 per Bbl, our oil sales revenues for the first six months of 2008 would decrease by approximately $1.7 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 six months of 2008 by approximately $2.2 million after considering the effects of the derivative contracts in place as of June 30, 2008. This sensitivity analysis is based on our first six months 2008 oil and gas sales volumes.

The following table reflects the natural gas and crude oil volumes and the weighted average prices under financial hedges (including settled hedges) at July 31, 2008, which has not changed since June 30, 2008:


	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
September 30, 2008		2,532		4.44		52		29.86		—		—
December 31, 2008		2,532		4.59		52		29.68		—		—

		5,064	$	4.52		104	$	29.77		—	$	—

Year Ending
December 31, 2009		9,529		4.43		191		29.34		3,650		0.345
December 31, 2010		8,938		4.28		175		28.86		3,650		0.325
December 31, 2011		8,231		4.19		157		28.77		3,285		0.325
December 31, 2012		7,005		4.09		138		28.70		—		—
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 $348.5 million as of June 30, 2008.

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 June 30, 2008 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 June 30, 2008 that materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

As of the date of this filing, there have been no changes from the risk factors previously disclosed in our “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007.

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

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

None.

Item 3. Defaults upon Senior Securities

None.

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

None.

Item 5. Other Information

None.


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.


	BELDEN & BLAKE CORPORATION
Date: August 11, 2008	By:	/s/ Mark A. Houser
		Mark A. Houser, Chief Executive Officer,
		Chairman of the Board of Directors and Director (Principal Executive Officer)

Date: August 11, 2008	By:	/s/ James M. Vanderhider
		James M. Vanderhider, President,
		Chief Financial Officer and Director (Principal Financial Officer)


Exhibit No.		Description

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.

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	Page
PART I Financial Information

Item 1. Financial Statements (unaudited)

Balance Sheets as of June 30, 2008 and December 31, 2007		1

Statements of Operations: Three and six months ended June 30, 2008 and 2007		2

Statements of Cash Flows: Six months ended June 30, 2008 and 2007		3

Notes to Financial Statements		4

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		8

Item 3. Quantitative and Qualitative Disclosures About Market Risk		16

Item 4. Controls and Procedures		18

PART II Other Information

Item 1. Legal Proceedings		18

Item 1A. Risk Factors		18

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		18

Item 3. Defaults Upon Senior Securities		18

Item 4. Submission of Matters to a Vote of Security Holders		18

Item 5. Other Information		18

Item 6. Exhibits		19

Signatures		20

Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2


*		Filed herewith.


*		Filed herewith.