Form 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, 2009


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

For the transition period from to

Commission File Number: 0-20100

BELDEN & BLAKE CORPORATION

(Exact name of registrant as specified in its charter)


Ohio		34-1686642
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)


1001 Fannin Street, Suite 800
Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

(713) 659-3500

(Registrant’s telephone number, including area code)

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

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


Large accelerated filer o		Accelerated filer o		Non-accelerated filer þ		Smallere porting company o

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

As of April 30, 2009, Belden & Blake Corporation had outstanding 1,534 shares of common stock, without par value, which is its only class of stock.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

BELDEN & BLAKE CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited, in thousands, except share data)


	March 31,			December 31,
	2009			2008

ASSETS
Current assets
Cash and cash equivalents	$	24,561		$	22,816
Accounts receivable (less accumulated provision for doubtful accounts: March 31, 2009 — $347; December 31, 2008 — $312)		11,846			19,244
Inventories		878			1,004
Deferred income taxes		2,758			7,946
Other current assets		236			332
Fair value of derivatives		2,683			430

Total current assets		42,962			51,772

Property and equipment, at cost
Oil and gas properties (successful efforts method)		737,784			735,398
Gas gathering systems		1,413			1,413
Land, buildings, machinery and equipment		2,838			2,836

		742,035			739,647
Less accumulated depreciation, depletion and amortization		133,506			124,175

Property and equipment, net		608,529			615,472
Fair value of derivatives		1,507			868
Other assets		1,343			1,352

	$	654,341		$	669,464

LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Accounts payable	$	2,180		$	3,570
Accrued expenses		14,433			19,251
Current portion of long-term liabilities		25,231			25,237
Fair value of derivatives		9,656			20,520

Total current liabilities		51,500			68,578

Long-term liabilities
Bank and other long-term debt		74,936			74,938
Senior secured notes		163,056			163,302
Subordinated promissory note — related party		28,303			27,623
Asset retirement obligations and other long-term liabilities		24,035			23,863
Fair value of derivatives		82,041			101,570
Deferred income taxes		138,168			133,039

Total long-term liabilities		510,539			524,335

Shareholder’s equity
Common stock: without par value; 3,000 shares authorized and 1,534 shares issued		—			—
Paid in capital		122,500			122,500
Accumulated deficit		(19,512	)		(32,754	)
Accumulated other comprehensive loss		(10,686	)		(13,195	)

Total shareholder’s equity		92,302			76,551

	$	654,341		$	669,464

See accompanying notes.

BELDEN & BLAKE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, in thousands)


	Three months ended			Three months ended
	March 31, 2009			March 31, 2008

Revenues
Oil and gas sales	$	15,016		$	31,368
Gas gathering and marketing		1,920			2,850
Other		174			89

		17,110			34,307

Expenses
Production expense		6,230			6,485
Production taxes		322			672
Gas gathering and marketing		1,686			2,338
Exploration expense		1,525			192
General and administrative expense		2,180			1,960
Depreciation, depletion and amortization		9,375			9,005
Accretion expense		331			339
Derivative fair value (gain) loss		(31,227	)		26,822

		(9,578	)		47,813

Operating income (loss)		26,688			(13,506	)

Other (income) expense
Interest expense		4,817			5,846
Other income, net		(67	)		(126	)

		4,750			5,720

Income (loss) before income taxes		21,938			(19,226	)
Provision (benefit) from income taxes		8,696			(7,592	)

Net income (loss)	$	13,242		$	(11,634	)

See accompanying notes.

BELDEN & BLAKE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited, in thousands)


	Three months ended			Three months ended
	March 31, 2009			March 31, 2008
Cash flows from operating activities:
Net income (loss)	$	13,242		$	(11,634	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		9,375			9,005
Accretion expense		331			339
Amortization of derivatives and other noncash hedging activities		(28,155	)		31,238
Exploration expense		625			192
Deferred income taxes		8,696			(7,592	)
Other non-cash items		1,373			(107	)
Change in operating assets and liabilities, net of effects of acquisition and disposition of businesses:
Accounts receivable and other operating assets		7,494			(4,823	)
Inventories		82			60
Accounts payable and accrued expenses		(6,433	)		(4,646	)

Net cash provided by operating activities		6,630			12,032

Cash flows from investing activities:
Proceeds from property and equipment disposals		746			1,821
Exploration expense		(625	)		(192	)
Additions to property and equipment		(3,838	)		(6,020	)
(Decrease) increase in other assets		(97	)		78

Net cash used in investing activities		(3,814	)		(4,313	)

Cash flows from financing activities:
Repayment of long-term debt and other obligations		(71	)		(2	)
Settlement of derivative liabilities recorded in purchase accounting		(1,000	)		(10,955	)

Net cash used in financing activities		(1,071	)		(10,957	)


Net increase (decrease) in cash and cash equivalents		1,745			(3,238	)
Cash and cash equivalents at beginning of period		22,816			16,014

Cash and cash equivalents at end of period	$	24,561		$	12,776

See accompanying notes.

BELDEN & BLAKE CORPORATION

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

March 31, 2009

(1) Basis of Presentation

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

The accompanying unaudited financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the period ended March 31, 2009 are not necessarily indicative of the results that may be expected for the year ended December 31, 2009. For further information, refer to the consolidated financial statements and footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2008.

(2) Derivatives and Hedging

Effective January 1, 2009, we adopted 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.

From time to time, we may enter into a combination of futures contracts, derivatives and fixed-price physical commodity contracts to manage our exposure to natural gas price, crude oil price or interest rate volatility and support our capital expenditure plans. Our derivative financial instruments take the form of swaps or collars. At March 31, 2009, our derivative contracts were comprised of natural gas swaps, natural gas basis differential swaps, crude oil swaps and interest rate swaps which were placed with major financial institutions that we believe are a minimal credit risk. All of our derivative instruments are currently accounted for as non-qualifying derivative contracts. The changes in fair value of non-qualifying derivative contracts are reported in expense in the consolidated statements of operations as derivative fair value (gain) loss.

During the first quarters of 2009 and 2008, net losses of $4.1 million ($2.5 million after tax) and $4.6 million ($2.8 million after tax), respectively, were reclassified from accumulated other comprehensive income to earnings. The value of open hedges in accumulated other comprehensive income decreased $4.1 million ($2.5 million after tax) in the first quarter of 2009 and decreased $4.6 million ($2.8 million after tax) in the first quarter of 2008. At March 31, 2009, the estimated net loss in accumulated other comprehensive income that is expected to be reclassified into earnings within the next 12 months is approximately $4.3 million after tax. At March 31, 2009, we have partially hedged our exposure to the variability in future cash flows through December 2013.

The following table reflects the natural gas and crude oil volumes and the weighted average prices under derivative contracts (including settled derivative contracts) at March 31, 2009:


	Natural Gas Swaps				Crude Oil Swaps				Natural Gas Basis Swaps
			NYMEX				NYMEX
			Price per				Price per				Basis
	Bbtu		Mmbtu		Mbbls		Bbl		Bbtu		Differential
Quarter Ending
June 30, 2009		2,382	$	4.25		48	$	29.42		2,093	$	0.337
September 30, 2009		2,382		4.28		48		29.24		2,116		0.337
December 31, 2009		2,382		4.47		48		29.09		2,116		0.337

		7,146	$	4.33		144	$	29.25		6,325	$	0.337

Year Ending
December 31, 2010		8,938	$	4.28		175	$	28.86		7,666	$	0.243
December 31, 2011		8,231		4.19		157		28.77		5,110		0.252
December 31, 2012		7,005		4.09		138		28.70		3,660		0.110
December 31, 2013		6,528		4.04		127		28.70		—		—

At March 31, 2009, we had interest rate swaps in place covering $80 million of our outstanding debt under the revolving credit facility that mature on September 30, 2010. The swaps provide 1-month LIBOR fixed rates at 4.07% plus the applicable margin.

At March 31, 2009 , the fair value of these derivatives was as follows:


	Asset Derivatives				Liability Derivatives
	March 31,		December 31,		March 31,			December 31,
	2009		2008		2009			2008
Oil and natural gas commodity contracts	$	4,190	$	1,298	$	(88,435	)	$	(118,547	)

Interest rate swaps		—		—		(3,262	)		(3,543	)

Total fair value	$	4,190	$	1,298	$	(91,697	)	$	(122,090	)


Location of derivatives on our consolidated balance sheet:

Derivative asset	$	2,683	$	430	$	—		$	—
Long–term derivative asset		1,507		868		—			—
Derivative liability		—		—		(9,656	)		(20,520	)
Long–term derivative liability		—		—		(82,041	)		(101,570	)

	$	4,190	$	1,298	$	(91,697	)	$	(122,090	)

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


	Three Months Ended
	March 31,
	2009			2008
The following amounts are recorded in Oil and gas sales:
Unrealized gains (losses):
Oil and natural gas commodity contracts	$	(4,079	)	$	(4,358	)

The following amounts are recorded in Interest expense:
Realized (gains) losses:
Interest rate swaps	$	—		$	197

The following are recorded in Derivative fair value (gain) loss:
Unrealized (gains) losses:
Oil and natural gas commodity contracts	$	(33,003	)	$	14,390
Interest rate swaps		(281	)		1,477

Total		(33,284	)		15,867

Realized (gains) losses:
Oil and natural gas commodity contracts		1,334			10,955
Interest rate swaps		723			—

Total		2,057			10,955

Derivative fair value (gain) loss	$	(31,227	)	$	26,822

(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 ended		Three months ended
(in thousands)	March 31, 2009		March 31, 2008
Cash paid during the period for:
Interest	$	7,776	$	9,433
Income taxes		—		—
Non-cash investing and financing activities:
Non-cash additions to property and equipment		1,952		2,771
Interest paid in-kind on subordinated promissory note		679		—

(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, 2009 and 2008.


	Three months ended		Three months ended
	March 31, 2009		March 31, 2008
Comprehensive income (loss):
Net income (loss)	$	13,242	$	(11,634	)
Other comprehensive income (loss), net of tax:
Unrealized gain in derivative fair value		—		(402	)
Reclassification adjustment for derivative (loss) gain reclassified into earnings		2,509		2,795

Change in accumulated other comprehensive income (loss)		2,509		2,393

	$	15,751	$	(9,241	)

(7) Related Party Transactions

We have a joint operating agreement with EnerVest Operating LLC (“EnerVest Operating”). In the first quarter of 2009, we recorded expenses of approximately $1.7 million for operating overhead fees, $1.6 million for field labor, vehicles and district office expense, $16,000 for drilling overhead fees and $520,000 for drilling labor costs related to this agreement. 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 in the first quarter of 2008 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, 2009 was $28.3 million. In lieu of cash payments, we have the option to make interest payments on the note by borrowing additional amounts against the note. We made a cash interest payment of $655,000 in the first quarter of 2008 to Capital C and borrowed an additional $679,000 against the note for the interest payment in the first quarter of 2009.

As of March 31, 2009, we owed EnerVest Operating $841,000 and EnerVest owed us $126,000.

(8) New Accounting Standards

In December 2007, the Financial Accounting Standards Board (“FASB”) issued SFAS No 141 (Revised 2007), Business Combinations (“SFAS No. 141(R)”) to replace SFAS No. 141, Business Combinations. SFAS No. 141(R) retains the purchase method of accounting used in business combinations but replaces SFAS 141 by establishing principles and requirements for the recognition and measurement of assets, liabilities and goodwill, including the requirement that most transaction and restructuring costs related to the acquisition be expensed. In addition, the statement requires disclosures to enable users to evaluate the nature and financial effects of the business combination. We adopted SFAS No. 141(R) on January 1, 2009, and there was no impact on our condensed 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. We adopted SFAS No. 160 on January 1, 2009, and there was no impact on our condensed consolidated financial statements.

(9) Fair Value Measurements

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, 2009 Using:

Quoted Prices in

Significant

Active Markets

Other

Significant

for Identical

Observable

Unobservable

Assets

Inputs

Total Carrying Value

(Level 1)

(Level 2)

(Level 3)

Derivative instruments

(87,507

)

—

(87,507

)

—

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.

(10) Asset Retirement Obligations

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


Balance as of December 31, 2008	$	23,885
Accretion expense		331
Liabilities incurred		6
Liabilities settled		(99	)
Revisions in estimated cash flows		—

Balance as of March 31, 2009	$	24,123

As of March 31, 2009 and December 31, 2008, $223,000 and $229,000, respectively, of our ARO is classified as current.

(11) Long-Term Debt and Subsequent Event

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

Effective April 9, 2009, the we entered into the Fourth Amendment, Waiver and Agreement related to the Amended Credit Agreement. The agreement was entered into to provide for certain waivers and modifications to the debt terms and covenants. This amendment was a direct result of the determination as of December 31, 2008, that we would not maintain compliance with certain financial covenants during 2009 and 2010. Accordingly, on April 9, 2009, our bank group waived the leverage ratio for the quarters ended March 31, 2009 and June 30, 2009 and amended the Amended Credit Agreement to increase the maximum leverage ratio to 5.375 : 1.0 through December 31, 2009, 5.25 : 1.0 at March 31, 2010 and 5.0 : 1.0 at June 30, 2010. The bank group also waived the interest coverage ratio as of June 30, 2009 and amended the Amended Credit Agreement to reduce our minimum interest coverage ratio to 2.0 : 1.0 through March 31, 2010 and 2.25 : 1.0 at June 30, 2010. Additionally, Capital C, our parent, has committed to the Company to provide financial support. Taking into consideration the amended financial covenants and the financial support from Capital C, we have projected that we will maintain compliance with such amended covenants for the next 12 months.

Additionally, the amendment provided that the borrowings under the Amended Credit Agreement bear interest (i) at the greater of the prime rate, an adjusted federal funds rate or an adjusted Eurodollar rate, plus an applicable margin ranging from 1.0% to 1.75% based on the aggregate principal amount outstanding under the Amended Credit Agreement, or, (ii) at our option, the Eurodollar base rate plus an applicable margin ranging from 2.5% to 3.25% based on the aggregate principal amount outstanding under the Amended Credit Agreement. The agreement was also amended for the following:

•

Set the Borrowing Base at $100 million.

•

Set the Borrowing Base redetermination dates to March 15^th and September 15^theach year.

•

Prohibit payment of dividends to our shareholder.

•

Prohibit Senior Secured Note repurchases by the Company.

•

Prohibit principal or cash interest payments on the Capital C Subordinated Note.

•

Prohibit borrowings to fund restructuring of the hedge agreements.

•

Require the pay down of the Amended Credit Agreement with certain proceeds of asset sales and equity contributions, of which $20 million is required to be paid by July 15, 2009.

•

Reduce the Borrowing Base by the amount of each repayment until the aggregate amount of such repayments is equal to $30 million.

•

Increase the percentage of the value of total proved reserves that is required to be mortgaged from 75% to 80% effective May 31, 2009.

At March 31, 2009, we were in compliance with our covenants under the Amended Credit Agreement.

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, 2008, 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.

Impact of the Current Financial and Credit Markets

The U.S. and other world economies are currently in a recession which could last well into 2009 and beyond. Additionally, the financial and credit markets are undergoing unprecedented disruptions. Many financial institutions have liquidity concerns prompting intervention from governments. Our exposure to the disruptions in the financial markets includes our credit facility and investments exposure.

Our credit facility extends through August 16, 2010. If the disruption in the financial markets continues for an extended period of time, replacement or amendment of the credit facility may be more expensive.

Current market conditions also elevate concerns about cash and cash equivalent investments, which at March 31, 2009 totaled $24.6 million. We have reviewed the creditworthiness of the banks and financial institutions with which we maintain investments, each of whom we believe to be creditworthy, as well as the securities underlying these investments.

We have reviewed the creditworthiness and believe our hedge counterpaties to be strong and creditworthy. However, current disruptions occurring in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair their ability to perform under the terms of the hedging contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

Additionally, oil and gas prices are also volatile as evidenced by the significant decline during 2008 and 2009. Continued lower commodity prices will reduce the Company’s cash flows from operations.

Results of Operations

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


	Three months ended
	March 31,
	2009		2008
Production
Gas (Mmcf)		3,177		3,311
Oil (Mbbls)		82		83
Total production (Mmcfe)		3,671		3,808

Average price (1)
Gas (per Mcf)	$	3.71	$	7.16
Oil (per Bbl)		39.20		92.56
Mcfe		4.09		8.24
Average costs (per Mcfe)
Production expense	$	1.70	$	1.70
Production taxes		0.09		0.18
Depletion		2.53		2.34


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


	Three months ended
	March 31,
	2009		2008
Gas (per Mcf)	$	5.00	$	8.48
Oil (per Bbl)		39.20		92.56
Mcfe		5.20		9.38

First Quarters of 2009 and 2008 Compared

Revenues

Net operating revenues decreased from $34.3 million in the first quarter of 2008 to $17.1 million in the first quarter of 2009. The decrease was primarily due to lower oil and gas sales revenues of $16.4 million.

Gas volumes sold decreased approximately 134,000 Mcf (4%) from 3.3 Bcf in the first quarter of 2008 to 3.2 Bcf in the first quarter of 2009 resulting in a decrease in gas sales revenues of approximately $960,000. Oil volumes sold decreased approximately 1,000 Bbls (1%) from 83,000 Bbls in the first quarter of 2008 to 82,000 Bbls in the first quarter of 2009 resulting in a decrease in oil sales revenues of approximately $50,000. The lower gas and oil volumes were primarily due to normal production declines of base wells in 2009, which were partially offset by production from new wells drilled in 2008.

The average price realized for our natural gas decreased $3.45 per Mcf from $7.16 in the first quarter of 2008 to $3.71 per Mcf in the first quarter of 2009, which decreased gas sales revenues by approximately $11.0 million. As a result of our qualified hedging and derivative financial instrument activities, gas sales revenues were lower by $4.1 million ($1.29 per Mcf) in the first quarter of 2009 and lower by $4.4 million ($1.32 per Mcf) in the first quarter of 2008 than if our gas price was not affected by derivative financial instruments. The average price realized for our oil decreased from $92.56 per Bbl in the first quarter of 2008 to $39.20 per Bbl in the first quarter of 2009, which decreased oil sales revenues by approximately $4.4 million.

Gas gathering and marketing revenues decreased approximately $930,000 due to a $688,000 decrease in gas marketing revenues and a $242,000 decrease in gas gathering revenues. The lower gas gathering and marketing revenues were primarily due to lower gas prices in the first quarter of 2009 compared to the first quarter of 2008.

Costs and Expenses

Production expense decreased from $6.5 million in the first quarter of 2008 to $6.2 million in the first quarter of 2009. The average production cost was $1.70 per Mcfe in the first quarter of 2008 and 2009. Production expenses were lower in the first quarter of 2009 primarily due to a decrease in well maintenance, employee expenses and gas processing fees, which were partially offset by an increase in gas compression fees.

Production taxes decreased $350,000 from $672,000 in the first quarter of 2008 to $322,000 in the first quarter of 2009. Average per unit production taxes decreased from $0.18 per Mcfe in the first quarter of 2008 to $0.09 per Mcfe in the first quarter of 2009. The decreased production taxes are primarily due to lower oil and gas prices in Michigan, where production taxes are based on a percentage of revenues, excluding the effects of hedging.

Exploration expense increased $1.3 million from $192,000 in the first quarter of 2008 to $1.5 million in the first quarter of 2009. This increase was primarily due to noncash write-off of costs related to expired undeveloped leases.

General and administrative expense increased $220,000 from $2.0 million in the first quarter of 2008 to $2.2 million in the first quarter of 2009. This increase was primarily due to an increase in the allowance for doubtful accounts in the first quarter of 2009.

Depreciation, depletion and amortization increased by $370,000 from $9.0 million in the first quarter of 2008 to $9.4 million in the first quarter of 2009. This increase was primarily due to an increase in depletion expense. Depletion expense increased $370,000 (4%) from $8.9 million in the first quarter of 2008 to $9.3 million in the first quarter of 2009 primarily due to an increase in the depletion rate. Depletion per Mcfe increased from $2.34 per Mcfe in the first quarter of 2008 to $2.53 per Mcfe in the first quarter of 2009. The increase was primarily due to a decrease in oil and gas reserves as of December 31, 2008.

Derivative fair value (gain) loss was a loss of $26.8 million in the first quarter of 2008 compared to a gain of $31.2 million in the first quarter of 2009 due to the fluctuation in oil and gas prices in the first quarter of 2008 and 2009. The derivative fair value (gain) loss reflects the changes in fair value of certain derivative instruments that are not designated or do not qualify as cash flow hedges and the cash settlements on those hedges.

Interest expense decreased $1.0 million from $5.8 million in the first quarter of 2008 to $4.8 million in the first quarter of 2009. This decrease was due to lower blended interest rates.

Income tax provision (benefit) increased from a benefit of $7.6 million in the first quarter of 2008 to a provision of $8.7 million in the first quarter of 2009. The increase was primarily due to an increase in income before income taxes. The increase in income before income taxes was primarily due to an increase in derivative fair value (gain) loss.

Liquidity and Capital Resources

Cash Flows

The primary sources of cash in the first quarter of 2009 were funds generated from operations. Funds used during this period were primarily used for operations, development expenditures and interest expense. Our liquidity and capital resources are closely related to and dependent upon the current prices paid for our oil and natural gas.

Our operating activities provided cash flows of $6.6 million during the first quarter of 2009 compared to $12.0 million in the first quarter of 2008. The decrease was primarily due to lower cash received for oil and gas sales revenues (net of hedging) partially offset by changes in working capital items of $10.6 million.

Cash flows used in investing activities were $3.8 million in the first quarter of 2009 compared to $4.3 million in the first quarter of 2008. The decrease was primarily due to a decrease in additions to property and equipment of $2.2 million partially offset by a decrease in the proceeds from property and equipment disposals of $1.1 million.

Cash flows used in financing activities decreased in the first quarter of 2009 primarily due to a $10.0 million decrease in the settlement of derivative liabilities.

Our current ratio at March 31, 2009 was 0.83 to 1. During the first quarter of 2009, the working capital increased $8.3 million from a deficit of $16.8 million at December 31, 2008 to a deficit of $8.5 million at March 31, 2009. The increase was primarily due to a decrease in the current liability related to the fair value of derivatives of $10.9 million, a decrease in accrued expenses of $4.8 million, an increase in cash of $1.7 million, a decrease in accounts payable of $1.4 million, and an increase in the current asset related to the fair value of derivatives of $2.2 million which was partially offset by a decrease in accounts receivable of $7.4 million and a decrease in the deferred tax asset of $5.2 million.

Capital Expenditures

During the first quarter of 2009, we spent approximately $3.8 million on our drilling activities and other capital expenditures. In the first quarter of 2009, we drilled 2 gross (1.3 net) wells, which were both completed as producers in the target formation.

We currently expect to spend approximately $15.0 million during 2009 on our drilling activities and other capital expenditures. We intend to finance our planned capital expenditures through our cash on hand and available operating cash flow. At March 31, 2009, we had cash of $24.6 million. The level of our future cash flow will depend on a number of factors including the demand for and price levels of oil and gas, the scope and success of our drilling activities and our ability to acquire additional producing properties. There can be no assurance that the future drilling of our proved undeveloped locations will provide adequate liquidity in the future.

Financing and Credit Facilities

•

Set the Borrowing Base at $100 million.

•

Set the Borrowing Base redetermination dates to March 15^th and September 15^theach year.

•

Prohibit payment of dividends to our shareholder.

•

Prohibit Senior Secured Note repurchases by the Company.

•

Prohibit principal or cash interest payments on the Capital C Subordinated Note.

•

Prohibit borrowings to fund restructuring of the hedge agreements.

•

Require the pay down of the Amended Credit Agreement with certain proceeds of asset sales and equity contributions, of which $20 million is required to be paid by July 15, 2009.

•

Reduce the Borrowing Base by the amount of each repayment until the aggregate amount of such repayments is equal to $30 million.

•

Increase the percentage of the value of total proved reserves that is required to be mortgaged from 75% to 80% effective May 31, 2009.

At March 31, 2009, we were in compliance with our covenants under the Amended Credit Agreement.

At March 31, 2009, we had $41.1 million of outstanding letters of credit and there was $99.9 million outstanding under the revolving credit agreement. As of April 9, 2009, following the amendment of the credit agreement, we had $94.9 million outstanding under the revolving credit agreement and $4.0 million of borrowing capacity available for general corporate purposes.

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

New Accounting Standards

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. We adopted SFAS No. 160 on January 1, 2009, and there was no impact on our condensed 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. We adopted the disclosure requirements of SFAS No. 161 on January 1, 2009.

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, 2009, we had an interest rate swap 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 $3.3 million at March 31, 2009. 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, 2009.

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, 2009, we had derivatives covering a portion of our oil and gas production from 2009 through 2013. Our oil and gas sales revenues included a net pre-tax loss of $4.4 million in the first three months of 2008 and a net pre-tax loss of $4.1 million in the first three months of 2009 on our qualified hedging activities.

If gas prices decreased $1.00 per Mcf, our gas sales revenues for the quarter would decrease by approximately $3.2 million. If the price of crude oil decreased $10.00 per Bbl, our oil sales revenues for the quarter would decrease by approximately $795,000. 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, 2009. This sensitivity analysis is based on our first quarter 2009 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, 2009:


	Natural Gas Swaps				Crude Oil Swaps				Natural Gas Basis Swaps
			NYMEX				NYMEX
			Price per				Price per				Basis
	Bbtu		Mmbtu		Mbbls		Bbl		Bbtu		Differential
Quarter Ending
June 30, 2009		2,382	$	4.25		48	$	29.42		2,093	$	0.337
September 30, 2009		2,382		4.28		48		29.24		2,116		0.337
December 31, 2009		2,382		4.47		48		29.09		2,116		0.337

		7,146	$	4.33		144	$	29.25		6,325	$	0.337

Year Ending
December 31, 2010		8,938	$	4.28		175	$	28.86		7,666	$	0.243
December 31, 2011		8,231		4.19		157		28.77		5,110		0.252
December 31, 2012		7,005		4.09		138		28.70		3,660		0.110
December 31, 2013		6,528		4.04		127		28.70		—		—

The fair value of our oil and gas swaps was a net liability of approximately $84.2 million as of March 31, 2009.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures

We have established and maintain a system of disclosure controls and procedures to provide reasonable assurances that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Based on the evaluation of our disclosure controls and procedures as of the end of the period covered by this report, the principal executive officer and principal financial officer of Belden & Blake Corporation have concluded that our disclosure controls and procedures as of March 31, 2009 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, 2009 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, 2008.

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.


	10.1			Fourth Amendment, Waiver and Agreement to the First Amended and Restated Credit and Guaranty Agreement dated as of August 16, 2005 (incorporated by reference from Exhibit 10.9 to our annual report on Form 10-K for the year ended December 31, 2008).

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

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

	+32.1			Section 1350 Certification of Chief Executive Officer.

	+32.2			Section 1350 Certification of Chief Financial Officer.


	BELDEN & BLAKE CORPORATION
Date: May 13, 2009	By:	/s/ Mark A. Houser
		Mark A. Houser
		Chief Executive Officer, Chairman of the Board of Directors and Director

Date: May 13, 2009	By:	/s/ James M. Vanderhider
		James M. Vanderhider
		President, Chief Financial Officer and Director (Principal Financial Officer)


Exhibit
No.		Description

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

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

	+32 .1	Section 1350 Certification of Chief Executive Officer.

	+32.2	Section 1350 Certification of Chief Financial Officer.

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	Page
PART I Financial Information		1

Item 1. Financial Statements (unaudited)		1

Balance Sheets as of March 31, 2009 and December 31, 2008		1

Statements of Operations: Three months ended March 31, 2009 and 2008		2

Statements of Cash Flows: Three months ended March 31, 2009 and 2008		3

Notes to Financial Statements		4

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		10

Item 3. Quantitative and Qualitative Disclosures About Market Risk		15

Item 4. Controls and Procedures		17

PART II Other Information

Item 1. Legal Proceedings		17

Item 1A. Risk Factors		17

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		17

Item 3. Defaults upon Senior Securities		17

Item 4. Submission of Matters to a Vote of Security Holders		17

Item 5. Other Information		17

Item 6. Exhibits		18

Signatures		19

Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2