Belden & Blake 10-Q

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, 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 incorporation or organization)		(I.R.S. Employer Identification No.)

1001 Fannin Street, Suite 800 Houston, Texas		77002

(Address of principal executive offices)		(Zip Code)

(713) 659-3500

(Registrant’s telephone number, including area code)

(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. 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 the 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
		(Do not check if a smaller reporting company)

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, 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 share data)


	March 31,			December 31,
	2008			2007
ASSETS
Current assets
Cash and cash equivalents	$	12,776		$	16,014
Accounts receivable (less accumulated provision for doubtful accounts:		22,971			18,071
March 31, 2008 - $681; December 31, 2007 - $806)
Inventories		1,049			1,084
Deferred income taxes		25,770			17,282
Other current assets		293			370
Fair value of derivatives		—			37

Total current assets		62,859			52,858

Property and equipment, at cost
Oil and gas properties (successful efforts method)		719,525			713,912
Gas gathering systems		1,308			1,308
Land, buildings, machinery and equipment		2,826			2,761

		723,659			717,981
Less accumulated depreciation, depletion and amortization		97,578			88,549

Property and equipment, net		626,081			629,432
Goodwill		90,076			90,076
Fair value of derivatives		90			29
Other assets		1,646			1,830

	$	780,752		$	774,225

LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Accounts payable	$	1,429		$	1,148
Accounts payable — related party		291			1,508
Accrued expenses		18,129			20,363
Current portion of long-term liabilities		372			367
Fair value of derivatives		65,159			43,696

Total current liabilities		85,380			67,082

Long-term liabilities
Bank and other long-term debt		99,945			99,947
Senior secured notes		164,012			164,240
Subordinated promissory note — related party		26,946			26,931
Asset retirement obligations and other long-term liabilities		22,502			22,164
Fair value of derivatives		187,556			192,661
Deferred income taxes		101,429			98,977

Total long-term liabilities		602,390			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		(15,444	)		(3,810	)
Accumulated other comprehensive loss		(16,574	)		(18,967	)

Total shareholder’s equity		92,982			102,223

	$	780,752		$	774,225

See accompanying notes.

BELDEN & BLAKE CORPORATION

STATEMENTS OF OPERATIONS
(unaudited, in thousands)


	Three months			Three months
	ended March 31,			ended March 31,
	2008			2007
Revenues
Oil and gas sales	$	31,368		$	26,802
Gas gathering and marketing		2,850			2,620
Other		89			61

		34,307			29,483

Expenses
Production expense		6,485			5,803
Production taxes		672			551
Gas gathering and marketing		2,338			2,204
Exploration expense		192			725
General and administrative expense		1,960			1,927
Depreciation, depletion and amortization		9,005			8,559
Accretion expense		339			311
Derivative fair value loss		26,822			42,156

		47,813			62,236

Operating loss		(13,506	)		(32,753	)

Other (income) expense
Interest expense		5,846			5,897
Other income, net		(126	)		(107	)

		5,720			5,790

Loss before income taxes		(19,226	)		(38,543	)
Benefit from income taxes		(7,592	)		(15,244	)

Net loss	$	(11,634	)	$	(23,299	)

See accompanying notes.

BELDEN & BLAKE CORPORATION

STATEMENTS OF CASH FLOWS
(unaudited, in thousands)


	Three months			Three months
	ended March 31,			ended March 31,
	2008			2007
Cash flows from operating activities:
Net loss	$	(11,634	)	$	(23,299	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		9,005			8,559
Accretion expense		339			311
Amortization of derivatives and other noncash hedging activities		31,238			44,434
Exploration expense		192			161
Deferred income taxes		(7,592	)		(15,244	)
Other non-cash expense		(107	)		354
Change in operating assets and liabilities, net of effects of acquisition and disposition of businesses:
Accounts receivable and other operating assets		(4,823	)		1,515
Inventories		60			(155	)
Accounts payable and accrued expenses		(4,646	)		(4,448	)

Net cash provided by operating activities		12,032			12,188

Cash flows from investing activities:
Proceeds from property and equipment disposals		1,821			—
Exploration expense		(192	)		(161	)
Additions to property and equipment		(6,020	)		(6,234	)
Decrease (increase) in other assets		78			(57	)

Net cash used in investing activities		(4,313	)		(6,452	)

Cash flows from financing activities:
Proceeds from revolving line of credit		—			4,500
Repayment of long-term debt and other obligations		(2	)		(2	)
Settlement of derivative liabilities recorded in purchase accounting		(10,955	)		(4,924	)
Dividends		—			(5,250	)

Net cash used in financing activities		(10,957	)		(5,676	)


Net (decrease) increase in cash and cash equivalents		(3,238	)		60
Cash and cash equivalents at beginning of period		16,014			5,927

Cash and cash equivalents at end of period	$	12,776		$	5,987

See accompanying notes.

BELDEN & BLAKE CORPORATION

NOTES TO FINANCIAL STATEMENTS
(unaudited)

March 31, 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 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 Management Partners, 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 March 31, 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 consolidated financial statements and footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2007.

(2)

Derivatives and Hedging

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 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, 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 consolidated statements of operations as derivative fair value loss.

During the first quarters of 2008 and 2007, net losses of $4.6 million ($2.8 million after tax) and $2.2 million ($1.3 million after tax), respectively, were reclassified from accumulated other comprehensive income to earnings. The value of open hedges in accumulated other comprehensive income decreased $4.6 million ($2.8 million after tax) in the first quarter of 2008 and decreased $2.2 million ($1.3 million after tax) in the first quarter of 2007. At March 31, 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 $6.0 million after tax. At March 31, 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 derivative contracts (including settled derivative contracts) at March 31, 2008:


	Natural Gas Swaps				Crude Oil Swaps				Natural Gas Basis Swaps
			NYMEX
			Price per				NYMEX				Basis
Quarter Ending	Bbtu		Mmbtu		Mbbls		Price per Bbl		Bbtu		Differential
June 30, 2008		2,531	$	4.45		52	$	30.04		—	$	—
September 30, 2008		2,532		4.44		52		29.86		—		—
December 31, 2008		2,532		4.59		52		29.68		—		—

		7,595	$	4.49		156	$	29.86		—	$	—


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 March 31, 2008, we had interest rate swaps in place covering $80 million of our outstanding debt under the 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 2008 and 4.07% on $80 million from September 2008 through September 2010, plus the applicable margin. At March 31, 2008, the fair value of the interest rate swaps represented an unrealized loss of $2.9 million.

(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


	Three months		Three months
	ended March 31,		ended March 31,
	2008		2007
(in thousands)
Cash paid during the period for:
Interest	$	9,433	$	9,628
Income taxes		—		—
Non-cash investing and financing activities:
Non-cash additions to property and equipment		1,476		(286	)

(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 three-month periods ended March 31, 2008 and 2007.


	Three months			Three months
	ended March			ended March
	31, 2008			31, 2007
Comprehensive income (loss):

Net loss	$	(11,634	)	$	(23,299	)

Other comprehensive income (loss), net of tax:

Unrealized gain in derivative fair value		(402	)		117

Reclassification adjustment for derivative (loss) gain reclassified into earnings		2,795			(1,315	)

Change in accumulated other comprehensive (loss) income		2,393			(1,198	)

	$	(9,241	)	$	(24,497	)

(7)

Related Party Transactions

We have a joint operating agreement with EnerVest Operating LLC (“EnerVest Operating”). In the first quarter of 2008, we recorded expenses of approximately $1.5 million for operating overhead fees, $1.8 million for field labor, vehicles and district office expense, $56,000 for drilling overhead fees and $145,000 for drilling labor costs related to this agreement. We recorded expenses of approximately $1.4 million for operating overhead fees, $1.9 million for field labor, vehicles and district office expense, $107,000 for drilling overhead fees and $356,000 for drilling labor costs in the first quarter of 2007 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 amount due under the note at March 31, 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 $616,000 and $655,000 in the first quarters of 2007 and 2008, respectively, to Capital C.

(8)

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 March 31, 2008

Quoted Prices in

Significant

Active Markets

Other

Unobservable

for Identical

Observable

Inputs

Assets

Inputs

Total Carrying Value

(Level 1)

(Level 2)

(Level 3)

Derivative instruments

(252,625

)

—

(252,625

)

—

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:

	o		acquisition costs will generally be expensed as incurred;

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

	o		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.

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 March 31,
	2008		2007
Production
Gas (Mmcf)		3,311		3,295
Oil (Mbbls)		83		91
Total production (Mmcfe)		3,808		3,843

Average price (1)
Gas (per Mcf)	$	7.16	$	6.61
Oil (per Bbl)		92.56		55.16
Mcfe		8.24		6.97
Average costs (per Mcfe)
Production expense	$	1.70	$	1.51
Production taxes		0.18		0.14
Depletion		2.34		2.21


(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 March 31,
	2008		2007
Gas (per Mcf)	$	8.48	$	7.27
Oil (per Bbl)		92.56		55.16
Mcfe		9.38		7.55

First Quarters of 2008 and 2007 Compared

Revenues

Net operating revenues increased from $29.6 million in the first quarter of 2007 to $34.4 million in the first quarter of 2008. The increase was primarily due to higher oil and gas sales revenues of $4.6 million.

Gas volumes sold were 3.3 Bcf in the first quarter of 2007 and 2008. Oil volumes sold decreased approximately 8,000 Bbls (9%) from 91,000 Bbls in the first quarter of 2007 to 83,000 Bbls in the first quarter of 2008 resulting in a decrease in oil sales revenues of approximately $470,000. The lower oil volumes were primarily due to normal production declines of base wells in 2008 and increased volumes in the first quarter of 2007 from new wells drilled in the fourth quarter of 2006, which were partially offset by production from new wells drilled in 2007. The flat gas volumes were primarily due to normal production declines offset by new wells drilled in 2007.

The average price realized for our natural gas increased $0.55 per Mcf from $6.61 in the first quarter of 2007 to $7.16 per Mcf in the first quarter of 2008, which increased gas sales revenues by approximately $1.8 million. As a result of our qualified hedging and derivative financial instrument

activities, gas sales revenues were lower by $4.4 million ($1.32 per Mcf) in the first quarter of 2008 and lower by $2.2 million ($0.67 per Mcf) in the first quarter of 2007 than if our gas price was not affected by derivative financial instruments. The average price realized for our oil increased from $55.16 per Bbl in the first quarter of 2007 to $92.56 per Bbl in the first quarter of 2008, which increased oil sales revenues by approximately $3.1 million.

Gas gathering and marketing revenues increased approximately $230,000 due to a $145,000 increase in gas marketing revenues and a $85,000 increase in gas gathering revenues. The higher gas gathering and marketing revenues were primarily due to higher gas prices in the first quarter of 2008 compared to the first quarter of 2007.

Costs and Expenses

Production expense increased from $5.8 million in the first quarter of 2007 to $6.5 million in the first quarter of 2008. The average production cost increased from $1.51 per Mcfe in the first quarter of 2007 to $1.70 per Mcfe in the first quarter of 2008. Production expenses in the first quarter of 2008 were higher primarily due to increases in gas processing fees in Michigan, labor and oilfield services costs and well workovers.

Production taxes increased $121,000 from $551,000 in the first quarter of 2007 to $672,000 in the first quarter of 2008. Average per unit production taxes increased from $0.14 per Mcfe in the first quarter of 2007 to $0.18 per Mcfe in the first quarter of 2008. 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.

Exploration expense decreased $533,000 from $725,000 in the first quarter of 2007 to $192,000 in the first quarter of 2008. This decrease is primarily due to noncash write-off of costs related to undeveloped leases that expired during the first quarter of 2007.

General and administrative expense increased $33,000 from $1.9 million in the first quarter of 2007 to $2.0 million in the first quarter of 2008.

Depreciation, depletion and amortization increased by $446,000 from $8.6 million in the first quarter of 2007 to $9.0 million in the first quarter of 2008. This increase was primarily due to an increase in depletion expense. Depletion expense increased $395,000 (5%) from $8.5 million in the first quarter of 2007 to $8.9 million in the first quarter of 2008 primarily due to an increase in the depletion rate. Depletion per Mcfe increased from $2.21 per Mcfe in the first quarter of 2007 to $2.34 per Mcfe in the first quarter of 2008. The increase was primarily due to increased development costs in 2008.

Derivative fair value (gain) loss was a loss of $42.2 million in the first quarter of 2007 compared to a loss of $26.8 million in the first quarter of 2008, which is net of a $31.7 million gain associated with the adoption of SFAS 157 in 2008 as discussed in Note 8. 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 $51,000 from $5.9 million in the first quarter of 2007 to $5.8 million in the first quarter of 2008. This decrease was due to lower blended interest rates partially offset by an increase in outstanding debt.

Income tax benefit decreased from a benefit of $15.2 million in the first quarter of 2007 to a benefit of $7.6 million in the first quarter of 2008. The decrease was primarily due to a decrease in the loss before income taxes.

Liquidity and Capital Resources

Cash Flows

The primary sources of cash in the first quarter of 2008 were funds generated from operations. Funds used during this period were primarily used for operations, development expenditures, interest expense and dividends. 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 $12.4 million during the first quarter of 2008 compared to $12.2 million in the first quarter of 2007. The increase was primarily due to higher cash received for oil and gas sales revenues (net of hedging) partially offset by changes in working capital items of $6.1 million.

Cash flows used in investing activities were $4.6 million in the first quarter of 2008 compared to $6.5 million in the first quarter of 2007. The decrease was primarily due to a increase in proceeds from asset disposals of $1.8 million.

Cash flows used in financing activities increased in the first quarter of 2008 primarily due to a $6.0 million increase in the settlement of derivative liabilities and a $4.5 million decrease in borrowings from the revolving line of credit, which were partially offset by a decrease in dividends of $5.3 million.

Our current ratio at March 31, 2008 was 0.74 to 1. During the first quarter of 2008, the working capital decreased $8.3 million from a deficit of $14.2 million at December 31, 2007 to a deficit of $22.5 million at March 31, 2008. The decrease was primarily due to an increase in the current liability related to the fair value of derivatives of $21.5 million and a decrease in cash of $3.2 million which was partially offset by an increase in the current deferred tax asset of $8.5 million, an increase in accounts receivable of $4.9 million and a decrease in accrued expenses and accounts payable of $3.2 million.

Capital Expenditures

During the first quarter of 2008, we spent approximately $7.4 million on our drilling activities and other capital expenditures. In the first quarter of 2008, we drilled 24 gross (19.1 net) development wells, all of which were successfully completed as producers in the target formation.

We currently expect to spend approximately $36.7 million during 2008 on our drilling activities and other capital expenditures. We intend to finance our planned capital expenditures through our cash on hand, available operating cash flow and borrowings under our revolving credit facility. At March 31, 2008, we had cash of $12.8 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, 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

At March 31, 2008, we had a $390 million credit facility (“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 March 31, 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 Credit Agreement bear interest at the greater of the (i) 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 our 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 March 31, 2008, the interest rate under our base rate option was 5.625%. Under our one-month LIBOR option, the rate was 4.553%. At March 31, 2008, we had $40.9 million of outstanding letters of credit. At March 31, 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. The borrowing base is subject to redetermination semi-annually and at certain other times as provided by the Amended Credit Agreement. As of March 31, 2008, we were in compliance with all financial covenants and requirements under the existing credit facilities.

In connection with the Transaction, we executed a Subordinated Promissory Note (“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. The amount due under the note at March 31, 2008 was $26.9 million. We made cash interest payments of $616,000 and $655,000 in the first quarters of 2007 and 2008, respectively, to Capital C.

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 March 31, 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

(252,625

)

—

(252,625

)

—

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.

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.

o acquisition costs will generally be expensed as incurred;

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

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

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.

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 March 31, 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 a liability of $2.9 million at March 31, 2008. If market interest rates for short-term borrowings increased 1%, the increase in interest expense in the quarter would be approximately $50,000. This sensitivity analysis is based on our financial structure at March 31, 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 March 31, 2008, we had derivatives covering a portion of our oil and gas production from 2007 through 2013. Our oil and gas sales revenues included a net pre-tax loss of $2.2 million in the first three months of 2007 and a net pre-tax loss of $4.4 million in the first three months of 2008 on our qualified hedging activities.

We determined that as of August 15, 2005, our oil derivatives no longer qualify for cash flow hedge accounting and as of July 1, 2006, our gas derivatives no longer qualify for cash flow hedge accounting. From those dates forward, 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 quarter would decrease by approximately $3.3 million. If the price of crude oil decreased $10.00 per Bbl, our oil sales revenues for the quarter would decrease by approximately $827,000. 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 $1.1 million after considering the effects of the derivative contracts in place as of March 31, 2008. This sensitivity analysis is based on our first quarter 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 April 30, 2008:


	Natural Gas Swaps				Crude Oil Swaps				Natural Gas Basis Swaps
			NYMEX
			Price per				NYMEX
Quarter Ending	Bbtu		Mmbtu		Mbbls		Price per Bbl		Bbtu		Basis Differential
June 30, 2008		2,531	$	4.45		52	$	30.04		—	$	—
September 30, 2008		2,532		4.44		52		29.86		—		—
December 31, 2008		2,532		4.59		52		29.68		—		—

		7,595	$	4.49		156	$	29.86		—	$	—


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		—		—


		Bbl – Barrel		Mmbtu – Million British thermal units
		Mbbls – Thousand barrels		Bbtu – Billion British thermal units

The fair value of our oil and gas swaps was a net liability of approximately $249.8 million as of March 31, 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 March 31, 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 March 31, 2008 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II OTHER INFORMATION

Item 1. Legal Proceedings.

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

Item 1A. Risk Factors

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, 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.


	BELDEN & BLAKE CORPORATION
Date: May 14, 2008	By:	/s/ Mark A. Houser
		Mark A. Houser, Chief Executive Officer,
		Chairman of the Board of Directors and Director


Date: May 14, 2008	By:	/s/ James M. Vanderhider
		James M. Vanderhider, President, Chief
		Financial Officer and Director (Principal Financial Officer)

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		Page
PART I Financial Information

Item 1. Financial Statements (unaudited)

Balance Sheets as of March 31, 2008 and December 31, 2007		1

Statements of Operations:
Three months ended March 31, 2008 and 2007		2

Statements of Cash Flows:
Three months ended March 31, 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		14

Item 4. Controls and Procedures		16

PART II Other Information

Item 1. Legal Proceedings		16

Item 1A. Risk Factors		16

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		16

Item 3. Defaults upon Senior Securities		16

Item 4. Submission of Matters to a Vote of Security Holders		16

Item 5. Other Information		16

Item 6. Exhibits		17

Signatures		18
EX-31.1
EX-31.2
EX-32.1
EX-32.2


+		Filed herewith