Belden & Blake Corp. 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, 2006


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.)

First City Tower 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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large Accelerated filer o Accelerated Filer o Non-accelerated Filer þ

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, 2006, 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

CONSOLIDATED BALANCE SHEETS

(unaudited, in thousands, except share data)


	March 31,			December 31,
	2006			2005
ASSETS
Current assets
Cash and cash equivalents	$	14,459		$	8,172
Accounts receivable, net		22,253			25,225
Inventories		769			1,085
Deferred income taxes		9,726			25,752
Other current assets		299			349
Fair value of derivatives		333			174

Total current assets		47,839			60,757

Property and equipment, at cost
Oil and gas properties (successful efforts method)		667,463			661,094
Gas gathering systems		1,228			1,593
Land, buildings, machinery and equipment		6,800			6,795

		675,491			669,482
Less accumulated depreciation, depletion and amortization		23,840			14,456

Property and equipment, net		651,651			655,026
Goodwill		91,443			91,443
Fair value of derivatives		470			285
Other assets		2,519			2,607

	$	793,922		$	810,118

LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Accounts payable	$	6,827		$	5,314
Accrued expenses		29,635			28,496
Current portion of long-term liabilities		776			776
Fair value of derivatives		44,263			65,170

Total current liabilities		81,501			99,756

Long-term liabilities
Bank and other long-term debt		53,083			52,085
Senior secured notes		200,108			200,340
Subordinated promissory note — related party		25,000			25,000
Asset retirement obligations and other long-term liabilities		19,396			18,919
Fair value of derivatives		214,057			240,129
Deferred income taxes		88,033			84,490

Total long-term liabilities		599,677			620,963

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		7,951			9,063
Accumulated other comprehensive loss		(20,207	)		(44,664	)

Total shareholder’s equity		112,744			89,399

	$	793,922		$	810,118

See accompanying notes.

BELDEN & BLAKE CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, in thousands)


	Successor		Predecessor I
	Company		Company
	Three months		Three months
	ended March 31,		ended March 31,
	2006		2005
Revenues
Oil and gas sales	$	40,938	$	27,921
Gas gathering and marketing		3,750		2,443
Other		105		107

		44,793		30,471
Expenses
Production expense		5,588		5,420
Production taxes		912		734
Gas gathering and marketing		3,283		2,106
Exploration expense		174		952
General and administrative expense		3,196		1,764
Franchise, property and other taxes		42		54
Depreciation, depletion and amortization		9,417		8,305
Accretion expense		292		255
Derivative fair value (gain) loss		7,290		6,217

		30,194		25,807

Operating income		14,599		4,664

Other expense
Interest expense		5,668		5,830

Income (loss) before income taxes		8,931		(1,166	)
Provision (benefit) for income taxes		3,543		(530	)

Net income (loss)	$	5,388	$	(636	)

See accompanying notes.

BELDEN & BLAKE CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited, in thousands)


	Successor			Predecessor I
	Company			Company
	Three months			Three months
	ended March 31,			ended March 31,
	2006			2005
Cash flows from operating activities:
Net (loss) income	$	5,388		$	(636	)
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization		9,417			8,305
Accretion expense		292			255
Loss on disposal of property and equipment		—			12
Amortization of derivatives and other noncash hedging activities		3,106			5,807
Exploration expense		174			952
Deferred income taxes		3,543			(530	)
Change in operating assets and liabilities, net of effects of acquisition and disposition of businesses:
Accounts receivable and other operating assets		3,023			2,787
Inventories		238			8
Accounts payable and accrued expenses		1,570			(5,648	)

Net cash provided by operating activities		26,751			11,312

Cash flows from investing activities:
Proceeds from property and equipment disposals		3,320			—
Exploration expense		(174	)		(952	)
Additions to property and equipment		(8,141	)		(7,214	)
(Increase) decrease in other assets		(18	)		(14	)

Net cash used in investing activities		(5,013	)		(8,180	)

Cash flows from financing activities:
Repayment of senior secured facility — term loan		—			(250	)
Proceeds from revolving line of credit		13,000			—
Repayment of revolving line of credit		(12,000	)		—
Repayment of long-term debt and other obligations		(4	)		(28	)
Settlement of derivative liabilities recorded in purchase accounting		(9,947	)		(5,873	)
Dividends		(6,500	)		—

Net cash used in financing activities		(15,451	)		(6,151	)


Net (decrease) increase in cash and cash equivalents		6,287			(3,019	)
Cash and cash equivalents at beginning of period		8,172			18,407

Cash and cash equivalents at end of period	$	14,459		$	15,388

See accompanying notes.

BELDEN & BLAKE CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

March 31, 2006

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

On July 7, 2004, the Company, Capital C, and Capital C Ohio, Inc., an Ohio corporation and a wholly owned subsidiary of Capital C (“Merger Sub”), completed a merger pursuant to which Merger Sub was merged with and into the Company (the “Merger”), with the Company surviving the Merger as a wholly owned subsidiary of Capital C. The Merger resulted in a change in control of the Company. The general partner of Capital C was controlled by Carlyle/Riverstone Global Energy and Power Fund II, L.P until the Transaction on August 16, 2005.

The Transaction and Merger were each accounted for as a purchase effective August 16, 2005 and July 7, 2004, respectively. The Transaction and Merger resulted in a new basis of accounting reflecting estimated fair values for assets and liabilities at August 16, 2005 and July 7, 2004. Accordingly, the financial statements for the periods subsequent to August 15, 2005 are presented on the Company’s new basis of accounting, while the results of operations for prior period reflect the historical results of the predecessor company. The “Successor Company” refers to the period from August 16, 2005 and forward. The “Predecessor I Company” refers to the period from July 7, 2004 through August 15, 2005.

The accompanying unaudited consolidated 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 Successor Company for the period ended March 31, 2006 are not necessarily indicative of the results that may be expected for the year ended December 31, 2006. 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, 2005. Certain reclassifications have been made to conform to the current presentation.

(2) Derivatives and Hedging

As a result of the adoption of SFAS 133 in 2001, the Company recognizes all derivative financial instruments as either assets or liabilities at fair value. Derivative instruments that are not cash flow hedges must be adjusted to fair value through net income (loss). Under the provisions of SFAS 133, changes in the fair value of derivative instruments that are fair value hedges are offset against changes in the fair value of the hedged assets, liabilities, or firm commitments, through net income (loss). Changes in the fair value of derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time as the hedged items impact earnings. Ineffective portions of a derivative instrument’s change in fair value are immediately recognized in net income (loss). Deferred gains and losses on terminated hedges will be recognized as increases or decreases to oil and gas revenues or interest expense during the same periods in which the underlying forecasted transactions impact earnings. If there is a

discontinuance of a cash flow hedge because it is probable that the original forecasted transaction will not occur, deferred gains or losses are recognized in earnings immediately.

The relationship between the hedging instruments and the hedged items must be highly effective in achieving the offset of changes in fair values or cash flows attributable to the hedged risk, both at the inception of the contract and on an ongoing basis. The Company assesses effectiveness at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. Hedge accounting is discontinued prospectively if the Company determines that a derivative is no longer highly effective as a hedge or if the Company decides to discontinue the hedging relationship.

From time to time the Company may enter into a combination of futures contracts, commodity derivatives and fixed-price physical commodity contracts to manage its exposure to natural gas, crude oil price or interest rate volatility and support its capital expenditure plans. The Company’s derivative financial instruments take the form of swaps or collars. At March 31, 2006, the Company’s derivative contracts were comprised of natural gas swaps, crude oil swaps and an interest rate swap, which were placed with major financial institutions that the Company believes 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.

The Company uses New York Mercantile Exchange (“NYMEX”) based commodity derivative contracts to hedge natural gas, because the Company’s natural gas production is sold pursuant to NYMEX-based sales contracts. Beginning July 7, 2004, the Company has ineffectiveness on the natural gas swaps due to purchase accounting, which created non-zero value derivatives at the time of the Merger. The Company had collar agreements that could not be redesignated as cash flow hedges because these collars were not effective due to unrealized losses at the date of the Merger. These collars qualified and were designated as cash flow hedges from their inception through the period prior to the Merger. Although these collars were not deemed to be effective hedges in accordance with the provisions of SFAS 133, the Company retained these instruments as protection against changes in commodity prices and the Company continued to record the mark-to-market adjustments on these natural gas collars, through 2005, in the Company’s income statement. The Company’s NYMEX crude oil swaps were highly effective and were designated as cash flow hedges through August 16, 2005. The Company had ineffectiveness on the crude oil swaps because the oil is sold locally at a posted price which is different from the NYMEX price. At August 16, 2005, the Company’s oil swaps no longer qualified for cash flow hedge accounting because the assessment of effectiveness indicated that they may not be highly effective on an on-going basis. This occurred due to the application of purchase accounting to the derivatives, which created non-zero value derivatives at the time of the Transaction. The changes in the fair values of the natural gas collars since July 7, 2004, the changes in fair value of the oil swaps subsequent to August 15, 2005, the ineffective portion of the crude oil swaps through August 15, 2005 and the ineffective portion of the natural gas swaps since July 7, 2004 are recorded as “Derivative fair value gain or loss.”

During the first three months of 2006 and 2005, net losses of $9.9 million ($6.0 million after tax) and $4.7 million ($2.9 million after tax), respectively, were reclassified from accumulated other comprehensive income to earnings. The fair value of open hedges in accumulated other comprehensive income decreased $30.5 million ($18.5 million after tax) in the first quarter of 2006 and decreased $92.8 million ($58.1 million after tax) in the first quarter of 2005. At March 31, 2006, the estimated net gain in accumulated other comprehensive income that is expected to be reclassified into earnings within the next 12 months is approximately $1.7 million. At March 31, 2006, we have partially hedged our exposure to the variability in future cash flows through December 2013.

The following table reflects the natural gas and crude oil volumes and the weighted average prices under financial hedges (including settled hedges) at March 31, 2006:


	Natural Gas Swaps				Crude Oil Swaps
			NYMEX				NYMEX
			Price per				Price per
Quarter Ending	Bbtu		Mmbtu		Mbbls		Bbl
June 30, 2006		2,829		5.24		62		32.35
September 30, 2006		2,829		5.22		62		32.02
December 31, 2006		2,829		5.39		62		31.71

		8,487	$	5.28		186	$	32.03

Year Ending
December 31, 2007		10,745	$	4.97		227	$	30.91
December 31, 2008		10,126		4.64		208		29.96
December 31, 2009		9,529		4.43		191		29.34
December 31, 2010		8,938		4.28		175		28.86
December 31, 2011		8,231		4.19		157		28.77
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

At March 31, 2006, the Company had an interest rate swap in place for $40 million that matures on September 16, 2008. The swap provides a 1-month LIBOR fixed rate at 4.285% plus the applicable margin. The fair value of this interest rate swap was an asset of $803,000 at March 31,2006. We had no derivative financial instruments for managing interest rate risks in place as of March 31, 2005.

(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


	Successor		Predecessor I
	Company		Company
	Three months		Three months
	ended March 31,		ended March 31,
	2006		2005
(in thousands)
Cash paid during the period for:
Interest	$	9,822	$	10,398
Income taxes		—		500
Non-cash investing and financing activities:
Non-cash additions to property and equipment		954		1,021

(5) Contingencies

The Company is involved in several lawsuits arising in the ordinary course of business. The Company believes that the result of such proceedings, individually or in the aggregate, will not have a material adverse effect on the Company’s financial position or the results of operations.

(6) Dispositions

On March 31, 2006, we sold our interests in 13 Oriskany wells and the associated gas gathering system for approximately $3.3 million which approximated the net carrying value of such assets.

(7) Comprehensive Income

Comprehensive income includes net income and certain items recorded directly to shareholder’s equity and classified as other comprehensive income. The table below summarizes comprehensive income and provides the components of the change in accumulated other comprehensive income for the three-month periods ended March 31, 2006 and 2005.


	Successor		Predecessor I
	Company		Company
	Three months		Three months
	ended March 31,		ended March 31,
	2006		2005
Comprehensive income (loss):
Net income (loss)	$	5,389	$	(636	)
Other comprehensive income (loss), net of tax:
Unrealized gain (loss) in derivative fair value		18,460		(58,146	)
Reclassification adjustment for derivative loss reclassified into earnings		5,997		2,920

Change in accumulated other comprehensive income (loss)		24,457		(55,226	)

Comprehensive income (loss)	$	29,846	$	(55,862	)

(8) Related Party Transactions

On March 15, 2006, the Company entered into a joint operating agreement with EnerVest Operating LLC (“EnerVest Operating”). The Company recorded expenses of approximately $1.3 million for COPAS overhead fees, $1.7 million for field labor, vehicles and district office expense, $134,000 for COPAS drilling overhead fees and $262,000 for drilling labor costs in the first quarter of 2006 related to this agreement. The Company also reimbursed EnerVest Operating for expenses of $203,000 in the first quarter of 2006 related to the transition of accounting responsibilities from the Company to EnerVest Operating’s Charleston, West Virginia office.

The Company paid approximately $166,000 to Opportune LLP in the first quarter of 2006 for consulting services related to the Company’s amended filings and the 2005 Form 10-K. John Vanderhider, brother of James Vanderhider, the Company’s President and Chief Financial Officer, is a consultant with Opportune.

The Company paid approximately $98,000 to PetroAcct LP in the first quarter of 2006 for services related to the transition of accounting and information system responsibilities from the Company to EnerVest Operating. A subsidiary of EnerVest Management Partners, Ltd owns 50% of PetroAcct.

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,” “will,” “continue,” “estimate,” “plan,” “outlook,” “may,” “future,” “projection,” “likely,” “possible,” “would,” “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, 2005, 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.

CRITICAL ACCOUNTING POLICIES

We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the United States (“GAAP”) and SEC guidance. See the “Notes to Consolidated Financial Statements” included in “Item 8. Financial Statements and Supplementary Data” in our Annual Report on Form 10-K for the year ended December 31, 2005, filed with the SEC for a more comprehensive discussion of our significant accounting policies. GAAP requires information in financial statements about the accounting principles and methods used and the risks and uncertainties inherent in significant estimates including choices between acceptable methods. Following is a discussion of our most critical accounting policies.

Successful Efforts Method of Accounting

The accounting for and disclosure of oil and gas producing activities requires our management to choose between GAAP alternatives and to make judgments about estimates of future uncertainties.

We use the “successful efforts” method of accounting for oil and gas producing activities as opposed to the alternate acceptable “full cost” method. Under the successful efforts method, property acquisition and development costs and certain productive exploration costs are capitalized while non-productive exploration costs, which include certain geological and geophysical costs, exploratory dry hole costs and costs of carrying and retaining undeveloped properties, are expensed as incurred. The geological and geophysical costs include costs for salaries and benefits of our personnel in those areas and other third party costs. The costs of carrying and retaining undeveloped properties include salaries and benefits of our land department personnel, delay rental payments made on new and existing leases, ad valorem taxes on existing leases and the cost of previously capitalized leases that are written off because the leases were dropped or expired. Exploratory dry hole costs include the costs associated with drilling an exploratory well that has been determined to be a dry hole.

The major difference between the successful efforts method of accounting and the full cost method is under the full cost method of accounting, such exploration costs and expenses are capitalized as assets, pooled with the costs of successful wells and charged against the net income (loss) of future periods as a component of depletion expense.

Oil and Gas Reserves

Our estimated proved developed and estimated proved undeveloped reserves are all located within the Appalachian and Michigan Basins in the United States. There are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. In addition, estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are expected to change as future information becomes available. Material revisions of reserve estimates may occur in the future, development and production of the oil and gas reserves may not occur in the periods assumed and actual prices realized and actual costs incurred may vary significantly from assumptions used. Estimated proved reserves represent estimated quantities of natural gas and oil that geological and engineering data

demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. Estimated proved developed reserves are estimated proved reserves expected to be recovered through wells and equipment in place and under operating methods being used at the time the estimates were made. The accuracy of a reserve estimate is a function of:

	•		the quality and quantity of available data;

	•		the interpretation of that data;

	•		the accuracy of various mandated economic assumptions; and

	•		the judgment of the persons preparing the estimate.

Capitalization, Depreciation, Depletion and Impairment of Long-Lived Assets

See the “Successful Efforts Method of Accounting” discussion above. Capitalized costs related to estimated proved properties are depleted using the unit-of-production method. Depreciation, depletion and amortization of proved oil and gas properties are calculated on the basis of estimated recoverable reserve quantities. These estimates can change based on economic or other factors. No gains or losses are recognized upon the disposition of oil and gas properties except in extraordinary transactions. Sales proceeds are credited to the carrying value of the properties. Maintenance and repairs are expensed, and expenditures which enhance the value of properties are capitalized.

Unproved oil and gas properties are stated at cost and consist of undeveloped leases. These costs are assessed periodically to determine whether their value has been impaired, and if impairment is indicated, the costs are charged to expense.

Gas gathering systems are stated at cost. Depreciation expense is computed using the straight-line method over 15 years.

Property and equipment are stated at cost. Depreciation of non-oil and gas properties is computed using the straight-line method over the useful lives of the assets ranging from 3 to 15 years for machinery and equipment and 30 to 40 years for buildings. When assets other than oil and gas properties are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is reflected in income for the period. The cost of maintenance and repairs is expensed as incurred, and significant renewals and betterments are capitalized.

Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the sum of the expected future undiscounted cash flows is less than the carrying amount of the asset, a loss is recognized for the difference between the fair value and the carrying amount of the asset. Fair value is determined based on management’s outlook of future oil and natural gas prices and estimated future cash flows to be generated by the assets, discounted at a market rate of interest. Impairment of unproved properties is based on the estimated fair value of the property.

Derivatives and Hedging

Our financial results and cash flows can be significantly impacted as commodity prices fluctuate widely in response to changing market conditions. Under the provisions of SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, we recognize all derivative financial instruments as either assets or liabilities at fair value. The changes in fair value of derivative instruments not designated as cash flow hedges are reported in expense in the consolidated statements of operations as derivative fair value (gain) loss. Changes in the fair value of derivative instruments that are fair value hedges are offset against changes in the fair value of the hedged assets, liabilities, or firm commitments, through net income (loss). Changes in the fair value of derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time as the hedged items impact earnings.

Ineffective portions of a derivative instrument’s change in fair value are immediately recognized in net income (loss). Deferred gains and losses on terminated hedges are recognized as increases or decreases in oil and gas revenues or interest expense during the same periods in which the underlying forecasted transactions are recognized in net income (loss). If there is a discontinuance of a cash flow hedge because it is probable that the original forecasted transaction will not occur, deferred gains or losses are recognized in earnings immediately.

The relationship between hedging instruments and the hedged items must be highly effective in achieving the offset of changes in fair values or cash flows attributable to the hedged risk, both at inception of the contract on an ongoing basis. We assess effectiveness at least quarterly based on the relative changes in fair value between the derivative contract and the hedged item over time. We discontinue hedge accounting prospectively if we determine that a derivative is no longer highly effective as a hedge or if we decide to discontinue the hedging relationship.

From time to time we may enter into a combination of futures contracts, commodity derivatives and fixed-price physical commodity contracts to manage our exposure to natural gas, crude oil 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, 2006, our derivative contracts were comprised of natural gas swaps, crude oil swaps and an interest rate swap, which were placed with major financial institutions that we believe have a minimal credit risk. Qualifying derivative financial instruments are designated as cash flow hedges.

We use NYMEX-based commodity derivative contracts to hedge natural gas, because our natural gas production is sold pursuant to NYMEX-based sales contracts. Beginning July 7, 2004, we have ineffectiveness on the natural gas swaps due to purchase accounting, which created non-zero value derivatives at the time of the Merger. We had collar agreements that could not be redesignated as cash flow hedges because these collars were not effective due to unrealized losses at the date of the Merger. These collars qualified and were designated as cash flow hedges from their inception through the period prior to the Merger. Although these collars were not deemed to be effective hedges in accordance with the provisions of SFAS 133, we retained these instruments as protection against changes in commodity prices and we recorded the mark-to-market adjustments on these natural gas collars, through 2005, in our income statement. Our NYMEX crude oil swaps were highly effective and were designated as cash flow hedges through August 16, 2005. We had ineffectiveness on the crude oil swaps because the oil is sold locally at a posted price which is different from the NYMEX price. At August 16, 2005, our oil swaps no longer qualified for cash flow hedge accounting because the assessment of effectiveness indicated that they may not be highly effective on an on-going basis. This occurred due to the application of purchase accounting to the derivatives, which created non-zero value derivatives at the time of the Transaction. The changes in the fair values of the natural gas collars since July 7, 2004, the changes in fair value of the oil swaps subsequent to August 15, 2005, the ineffective portion of the crude oil swaps through August 15, 2005 and the ineffective portion of the natural gas swaps since July 7, 2004 are recorded as “Derivative fair value gain or loss.”

Revenue Recognition

Oil and gas production revenue is recognized as production and delivery take place. Oil and gas marketing revenues are recognized when title passes.

Asset Retirement Obligations

Under the provisions of SFAS 143, “Accounting for Asset Retirement Obligations,” we recognize a liability for the fair value of our asset retirement obligations associated with our tangible, long-lived assets. The majority of our asset retirement obligations recorded relate to the plugging and abandonment (excluding salvage value) of our oil and gas properties. Subsequent to the adoption of SFAS 143, there has been no significant current period activity with respect to additional retirement obligations, settled obligations, accretion expense and revisions of estimated cash flows.

Results of Operations

The Transaction and Merger were accounted for as purchases effective August 16, 2005 and July 7, 2004, respectively. The Transaction and Merger resulted in a new basis of accounting reflecting estimated fair values for assets and liabilities at August 16, 2005 and July 7, 2004, respectively. Accordingly, the financial statements for the periods subsequent to July 7, 2004 and August 15, 2005 are each presented on a new basis of accounting.

The allocation of the purchase price at fair value resulted in a significant increase in the book value of our assets. The increase in the book value of assets resulted in materially higher charges for depreciation, depletion and amortization in the Successor Company and Predecessor I Company periods. These higher charges are expected to continue in subsequent accounting periods.

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,
	2006		2005
Production
Gas (Mmcf)		3,537		3,563
Oil (Mbbls)		98		83
Total production (Mmcfe)		4,126		4,059

Average price
Gas (per Mcf)	$	9.92	$	7.00
Oil (per Bbl)		59.48		36.12
Mcfe		9.92		6.88
Average costs (per Mcfe)
Production expense	$	1.35	$	1.34
Production taxes		0.22		0.18
Depletion		2.22		1.89
Operating margin (per Mcfe)		8.35		5.36


Mmcf — Million cubic feet	Mbbls — Thousand barrels	Mmcfe — Million cubic feet of natural gas equivalent
Mcf — Thousand cubic feet	Bbl — Barrel	Mcfe — Thousand cubic feet of natural gas equivalent
Operating margin (per Mcfe) — average price less production expense and production taxes

First Quarters of 2006 and 2005 Compared

Revenues

Net operating revenues increased from $30.4 million in the first quarter of 2005 to $44.7 million in the first quarter of 2006. The increase was due to higher oil and gas sales revenues of $13.0 million and higher gas gathering and marketing revenues of $1.3 million.

Gas volumes sold were 3.5 Bcf (billion cubic feet) in the first quarter of 2006 and the first quarter of 2005. Oil volumes sold increased approximately 15,000 Bbls (19%) from 83,000 Bbls in the first quarter of 2005 to 98,000 Bbls in the first quarter of 2006 resulting in a increase in oil sales revenues of approximately $550,000. The higher oil volumes were due to additional oil production from new wells drilled in 2005, partially offset by normal production declines.

The average price realized for our natural gas increased $2.92 per Mcf from $7.00 in the first quarter of 2005 to $9.92 per Mcf in the first quarter of 2006, which increased gas sales revenues by approximately $10.3 million. As a result of our hedging activities, gas sales revenues were increased by

$4.2 million ($1.18 per Mcf) in the first quarter of 2006 and increased by $1.0 million ($0.28 per Mcf) in the first quarter of 2005. The average price realized for our oil increased from $36.12 per Bbl in the first quarter of 2005 to $59.48 per Bbl in the first quarter of 2006, which increased oil sales revenues by approximately $2.3 million.

The operating margin from oil and gas sales (oil and gas sales revenues less production expense and production taxes) on a per unit basis increased from $5.36 per Mcfe in the first quarter of 2005 to $8.35 per Mcfe in the first quarter of 2006. The average price increased $3.04 per Mcfe which was partially offset by an increase in production expense of $0.01 per Mcfe and an increase in production taxes of $0.04 per Mcfe in the first quarter of 2006 compared to the first quarter of 2005.

The increase in gas gathering and marketing revenues was due to a $1.0 million increase in gas marketing revenues and a $264,000 increase in gas gathering revenues. The higher gas gathering and marketing revenues were primarily due to higher gas prices in the first quarter of 2006 compared to the first quarter of 2005.

Costs and Expenses

Production expense was $5.4 million in the first quarter of 2005 and $5.6 million in the first quarter of 2006. The average production cost increased from $1.34 per Mcfe in the first quarter of 2005 to $1.35 per Mcfe in the first quarter of 2006. Production expense in the first quarter of 2006 increased by $332,000 ($0.08 per Mcfe) due to recording the cost associated with the selling of purchased oil inventory as a result of purchase accounting for the Transaction and due to higher fuel costs and general cost increases. In March 2006, we entered into a contract with EnerVest Operating for EnerVest to operate all of the company-operated oil and gas properties. As a result, we pay a COPAS overhead fee to EnerVest to provide all operations management and administration related to the oil and gas properties. The COPAS overhead charges are classified as general and administrative expense. This will result in lower production expenses and higher general and administrative expenses over time.

Production taxes increased $178,000 from $734,000 in the first quarter of 2005 to $912,000 in the first quarter of 2006. Average per unit production taxes increased from $0.18 per Mcfe in the first quarter of 2005 to $0.22 per Mcfe in the first quarter of 2006. 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 $778,000 (82%) from $952,000 in the first quarter of 2005 to $174,000 in the first quarter of 2006. This decrease is primarily due to the focus on development activities in the current period.

General and administrative expense increased $1.4 million (81%) from $1.8 million in the first quarter of 2005 to $3.2 million in the first quarter of 2006 primarily due to recording $1.3 million of COPAS overhead fees charged by EnerVest in the first quarter of 2006 and costs incurred related to the restatement of prior period financial statements. We also expensed approximately $600,000 in the first quarter of 2006 for costs associated with the transition of accounting and administrative functions to EnerVest’s Charleston West Virginia office. This was partially offset by $489,000 recorded in the first quarter of 2005 related to severance payments made to former executives.

Depreciation, depletion and amortization increased by $1.1 million from $8.3 million in the first quarter of 2005 to $9.4 million in the first quarter of 2006. This increase was primarily due to an increase in depletion expense. Depletion expense increased $1.5 million (19%) from $7.7 million in the first quarter of 2005 to $9.2 million in the first quarter of 2006 primarily due to a higher depletion rate per Mcfe. Depletion per Mcfe increased from $1.89 per Mcfe in the first quarter of 2005 to $2.22 per Mcfe in the first quarter of 2006, primarily due to a higher cost basis resulting from purchase accounting for the Transaction.

Derivative fair value (gain) loss was a loss of $6.2 million in the first quarter of 2005 compared to a loss of $7.3 million in the first quarter of 2006. 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 a credit of $117,000 related to the ineffective portion of natural gas swaps qualifying for hedge accounting which was recorded in the first quarter of 2006.

Interest expense decreased $162,000 from $5.8 million in the first quarter of 2005 to $5.7 million in the first quarter of 2006. This decrease was due to amortization of the fair value adjustments from purchase accounting on the Senior Secured Notes, partially offset by higher blended interest rates.

Income tax expense increased $4.1 million from a benefit of $530,000 in the first quarter of 2005 to an expense of $3.5 million in the first quarter of 2006. The increase was primarily due to an increase in income before income taxes.

Liquidity and Capital Resources

Cash Flows

The primary sources of cash in the first quarter of 2006 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 $26.8 million during the first quarter of 2006 compared to $11.3 million in the first quarter of 2005. The increase of $15.5 million was primarily due to higher cash received for oil and gas sales revenues (net of hedging), and changes in working capital items of $7.7 million.

Cash flows used in investing activities were $5.0 million in the first quarter of 2006 compared to $8.2 million in the first quarter of 2005. The decrease was primarily due to an increase in proceeds from asset disposals of $3.3 million, a decrease in exploration expense of $778,000 partially offset by a $927,000 increase in capital expenditures in the first quarter of 2006.

Cash flows used in financing activities increased in the first quarter of 2006 primarily due to an increase in dividends of $6.5 million and a $4.1 million increase in the settlement of derivative liabilities recorded in purchase accounting due to the Merger and the Transaction.

Our current ratio at March 31, 2006 was 0.59 to 1. During the first quarter of 2006, the working capital increased $5.3 million from a deficit of $39.0 million at December 31, 2005 to a deficit of $33.7 million at March 31, 2006. The increase was primarily due to a decrease in the current liability related to the fair value of derivatives of $20.9 million, an increase in cash of $6.3 million partially offset by a decrease in the current deferred tax asset of $16.0 million, a decrease in accounts receivable of $3.0 million and an increase in accrued expenses and accounts payable of $2.7 million.

Capital Expenditures

During the first quarter of 2006, we spent approximately $9.6 million on our drilling activities and other capital expenditures. In the first quarter of 2006, we drilled 45 gross (44.3 net) development wells, all of which were successfully completed as producers in the target formation.

We currently expect to spend approximately $36 million during 2006 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,

2006, we had cash of $14.5 million and approximately $26.4 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.

At March 31, 2006, we had a $390 million credit facility (“Amended Credit Agreement”) comprised of a five-year $350 million revolving facility with an initial borrowing base of $80.25 million, of which $53 million was outstanding at March 31, 2006. In April 2006, the borrowing base was increased to $90.25 million. This facility is for working capital requirements and general corporate purposes, including the issuance of letters of credit; and a five year $40 million letter of credit facility that may be used only to provide credit support for our obligations under the hedge agreement and other hedge transactions. Borrowings under the Amended Credit Agreement bear interest (i) at the greater of the prime rate or an adjusted federal funds rate, plus an applicable margin ranging from 0% to 0.625% based on the aggregate principal amount outstanding under the Amended Credit Agreement, or, (ii) at the Company’s 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 the assets of the Company. The obligations under the Amended Credit Agreement are further secured by a pledge of 100% of the capital stock of the Company held by Capital C, the Company’s parent.

The Amended Credit Agreement contains covenants that will limit the ability of the Company to, among other things, incur or guarantee additional indebtedness; create liens; pay dividends on or repurchase stock of the Company or its subsidiaries; pay principal and interest on certain subordinated debt; make certain types of investments; sell assets or merge with another entity; pledge or otherwise encumber the capital stock of the Company or its subsidiaries; 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, 2006, the interest rate under our base rate option was 7.875%. Under our one-month LIBOR option, the rate was 6.3775%. At March 31, 2006, we had $40.9 million of outstanding letters of credit. At March 31, 2006, there was $53 million outstanding under the revolving credit agreement. We had $26.4 million of borrowing capacity under our revolving facility available for general corporate purposes. As of March 31, 2006, we were in compliance with all financial covenants and requirements under the existing credit facilities.

In connection with the Transaction, the Company 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 $25 million to the Company. 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, the Company has 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 Company’s senior debt, which includes obligations under the Amended Credit Agreement, the J. Aron Swap and notes issued under the Company’s Indenture dated July 7, 2004 with BNY Midwest Trust Company, as indenture trustee.

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, 2006, we had an interest rate swap on $40 million of our revolving loan outstanding on our credit agreement. The fair value of this interest rate swap was an asset of $803,000 at March 31, 2006. We had no derivative financial instruments for managing interest rate risks in place as of March 31, 2005. If market interest rates for short-term borrowings increased 1%, the increase in interest expense in the quarter would be approximately $33,000. This sensitivity analysis is based on our financial structure at March 31, 2006.

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 production sold locally at a posted price and gas production sold under NYMEX-based contracts by selling NYMEX-based commodity derivative contracts which are placed with major financial institutions that we believe are minimal credit risks. Historically, there has been a high correlation between the posted price and NYMEX. The contracts may take the form of futures contracts, swaps or options. If NYMEX gas prices decreased $1.00 per Mcf, our gas sales revenues for the quarter would decrease by $709,000, after considering the effects of the hedging contracts in place at March 31, 2006. If the price of crude oil decreased $5.00 per Bbl, oil sales revenues for the quarter would decrease by $490,000, after considering the effects of the hedging contracts in place at March 31, 2006. We had net pre-tax gains on our hedging activities reported in oil and gas sales revenue of $4.2 million in the first three months of 2006 and $152,000 in the first three months of 2005. At March 31, 2006, we had hedges on a portion of our oil and gas production for the remainder of 2006 through 2013. This sensitivity analysis is based on our 2006 oil and gas sales volumes and assumes the NYMEX gas price would be above the ceiling in 2006 listed in the table below.

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, 2006:


	Natural Gas Swaps				Crude Oil Swaps
			NYMEX				NYMEX
			Price per				Price per
Quarter Ending	Bbtu		Mmbtu		Mbbls		Bbl
June 30, 2006		2,829		5.24		62		32.35
September 30, 2006		2,829		5.22		62		32.02
December 31, 2006		2,829		5.39		62		31.71

		8,487	$	5.28		186	$	32.03

Year Ending
December 31, 2007		10,745	$	4.97		227	$	30.91
December 31, 2008		10,126		4.64		208		29.96
December 31, 2009		9,529		4.43		191		29.34
December 31, 2010		8,938		4.28		175		28.86
December 31, 2011		8,231		4.19		157		28.77
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 proximity of our properties in the Appalachian and Michigan Basins to large commercial and industrial natural gas markets has generally resulted in premium wellhead gas prices compared with the prices of NYMEX futures contracts for gas delivered at the Henry Hub in Louisiana. Monthly spot natural gas prices in our market areas are typically $0.15 to $0.60 higher per Mcf than comparable NYMEX prices. Our average price received for crude oil is typically $3.00 to $3.50 per barrel below the NYMEX price per barrel.

Item 4. Controls and Procedures

As of the end of the quarterly period ended March 31, 2006, Mark A. Houser, our Chief Executive Officer, and James M. Vanderhider, our Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer believe that:

•

our disclosure controls and procedures were effective in ensuring that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 was recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and

•

our disclosure controls and procedures were effective in ensuring that material information required to be disclosed by us in the report we file or submit under the Securities Exchange Act of 1934 was accumulated and communicated to our management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Internal Controls Over Financial Reporting

There has not been any change in our internal control over financial reporting that occurred during our quarterly period ended March 31, 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II OTHER INFORMATION

Item 1. Legal Proceedings.

Item 1A. Risk Factors

There have been no material changes since December 31, 2005.

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

None.


	Page
PART I Financial Information

Item 1. Financial Statements (unaudited)

Consolidated Balance Sheets as of March 31, 2006 and December 31, 2005		1

Consolidated Statements of Operations:
Three months ended March 31, 2006 (Successor Company)
Three months ended March 31, 2005 (Predecessor I Company)		2

Consolidated Statements of Cash Flows:
Three months ended March 31, 2006 (Successor Company)
Three months ended March 31, 2005 (Predecessor I Company)		3

Notes to Consolidated Financial Statements		4

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		7

Item 3. Quantitative and Qualitative Disclosures About Market Risk		14

Item 4. Controls and Procedures		17

PART II Other Information

Item 1. Legal Proceedings		17

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

Item 6. Exhibits		18
EX-31.1 302 CEO Certification
EX-31.2 302 CFO Certification
EX-32.1 906 CEO Certification
EX-32.2 906 CFO Certification


31.1*		Certification of Principal Executive Officer of Belden & Blake Corporation as required by Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934
31.2*		Certification of Principal Financial Officer of Belden & Blake Corporation as required by Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934
32.1*		Certification of Chief Executive Officer of Belden & Blake Corporation pursuant to 18 U.S.C. Section 1350.
32.2*		Certification of Chief Financial Officer of Belden & Blake Corporation pursuant to 18 U.S.C. Section 1350.


	BELDEN & BLAKE CORPORATION
Date: May 17, 2006	By:	/s/ Mark A. Houser
		Mark A. Houser, Chief Executive Officer, Chairman of the Board of Directors and Director


Date: May 17, 2006	By:	/s/ James M. Vanderhider
		James M. Vanderhider, President, Chief Financial Officer and Director (Principal Financial Officer)

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents