Belden & Blake 10-Q 2006 Q2 Quarterly report

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 June 30, 2006

or

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

For the transition period from                                        to                                        

Commission File Number: 0-20100

BELDEN & BLAKE CORPORATION

(Exact name of registrant as specified in its charter)

Ohio	34-1686642
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
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 Yeso 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 filero Accelerated Filero Non-accelerated Filerþ

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

     As of July 31, 2006, Belden & Blake Corporation had outstanding 1,534 shares of common stock, without par value, which is its only class of stock.

BELDEN & BLAKE CORPORATION

INDEX

	Page
PART I Financial Information
Item 1. Financial Statements (unaudited)
Consolidated Balance Sheets as of June 30, 2006 and December 31, 2005		1
Consolidated Statements of Operations:
Three and six months ended June 30, 2006 (Successor Company)
Three and six months ended June 30, 2005 (Predecessor Company)		2
Consolidated Statements of Cash Flows:
Six months ended June 30, 2006 (Successor Company)
Six months ended June 30, 2005 (Predecessor 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		17
Item 4.     Controls and Procedures		19
PART II Other Information
Item 1.     Legal Proceedings		19
Item 1A. Risk Factors.		19
Item 4.     Submission of Matters to a Vote of Security Holders		19
Item 6.     Exhibits		20

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

BELDEN & BLAKE CORPORATION
CONSOLIDATED BALANCE SHEETS
(unaudited, in thousands, except share data)

	June 30,				December 31,
	2006				2005
ASSETS
Current assets
Cash and cash equivalents	$	8,681			$	8,172
Accounts receivable, net		17,503				25,225
Inventories		778				1,085
Deferred income taxes		16,188				25,752
Other current assets		198				349
Assets held for sale		3,646				—
Fair value of derivatives		481				174
Total current assets		47,475				60,757
Property and equipment, at cost
Oil and gas properties (successful efforts method)		680,689				661,094
Gas gathering systems		1,293				1,593
Land, buildings, machinery and equipment		3,057				6,795
		685,039				669,482
Less accumulated depreciation, depletion and amortization		32,952				14,456
Property and equipment, net		652,087				655,026
Goodwill		91,443				91,443
Fair value of derivatives		533		��		285
Other assets		2,414				2,607
	$	793,952			$	810,118
LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Accounts payable	$	7,595			$	5,314
Accrued expenses		24,127				28,496
Current portion of long-term liabilities		759				776
Fair value of derivatives		41,372				65,170
Total current liabilities		73,853				99,756
Long-term liabilities
Bank and other long-term debt		88,558				52,085
Senior secured notes		165,514				200,340
Subordinated promissory note — related party		25,000				25,000
Asset retirement obligations and other long-term liabilities		20,080				18,919
Fair value of derivatives		208,292				240,129
Deferred income taxes		98,810				84,490
Total long-term liabilities		606,254				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		7,194				9,063
Accumulated other comprehensive loss		(18,349	)			(44,664	)
Total shareholder’s equity		113,845				89,399
	$	793,952			$	810,118

See accompanying notes.

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BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, in thousands)

	Successor			Predecessor			Successor			Predecessor
	Company			Company			Company			Company
	Three months			Three months			Six months			Six months
	ended June 30,			ended June 30,			ended June 30,			ended June 30,
	2006			2005			2006			2005
Revenues
Oil and gas sales	$	36,212		$	27,999		$	77,150		$	55,920
Gas gathering and marketing		2,254			2,577			6,004			5,020
Other		193			110			298			217
		38,659			30,686			83,452			61,157
Expenses
Production expense		4,839			5,336			10,427			10,756
Production taxes		677			761			1,589			1,495
Gas gathering and marketing		1,663			2,313			4,946			4,419
Exploration expense		375			983			549			1,935
General and administrative expense		2,231			1,453			5,427			3,217
Franchise, property and other taxes		33			45			75			99
Depreciation, depletion and amortization		9,308			8,712			18,725			17,017
Accretion expense		304			327			596			582
Derivative fair value loss (gain)		6,186			(2,940	)		13,476			3,277
		25,616			16,990			55,810			42,797
Operating income		13,043			13,696			27,642			18,360
Other expense
Interest expense		5,639			5,945			11,307			11,775
Gain on early extinguishment of debt		(436	)		—			(436	)		—
Income before income taxes		7,840			7,751			16,771			6,585
Provision for income taxes		3,096			1,776			6,639			1,246
Net income	$	4,744		$	5,975		$	10,132		$	5,339

See accompanying notes.

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BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited, in thousands)

	Successor Company			Predecessor Company
	Six months ended			Six months ended
	June 30, 2006			June 30, 2005
Cash flows from operating activities:
Net income	$	10,132		$	5,339
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		18,725			17,017
Accretion expense		596			582
(Gain) loss on debt extinguishment and disposal of property and equipment		(436	)		51
Amortization of derivatives and other noncash hedging activities		4,075			5,014
Exploration expense		549			1,935
Deferred income taxes		6,639			1,246
Change in operating assets and liabilities, net of effects of acquisition and disposition of businesses:
Accounts receivable and other operating assets		7,874			2,935
Inventories		229			(58	)
Accounts payable and accrued expenses		(6,306	)		(617	)
Net cash provided by operating activities		42,077			33,444
Cash flows from investing activities:
Proceeds from property and equipment disposals		3,320			—
Exploration expense		(549	)		(1,935	)
Additions to property and equipment		(18,136	)		(14,788	)
Increase in other assets		(18	)		(29	)
Net cash used in investing activities		(15,383	)		(16,752	)
Cash flows from financing activities:
Repayment of senior secured facility — term loan		—			(500	)
Proceeds from revolving line of credit		48,476			—
Repayment of revolving line of credit		(12,000	)		—
Repayment of senior secured notes		(33,933	)		—
Repayment of long-term debt and other obligations		(22	)		(59	)
Settlement of derivative liabilities recorded in purchase accounting		(16,706	)		(13,767	)
Dividends paid		(12,000	)		—
Net cash used in financing activities		(26,185	)		(14,326	)
Net increase in cash and cash equivalents		509			2,366
Cash and cash equivalents at beginning of period		8,172			18,407
Cash and cash equivalents at end of period	$	8,681		$	20,773

See accompanying notes.

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BELDEN & BLAKE CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

June 30, 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 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 June 30, 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.

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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 immediately 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 or interest rate price volatility and support its capital expenditure plans. The Company’s derivative financial instruments take the form of swaps or collars. At June 30, 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 six months of 2006 and 2005, net losses of $13.0 million ($7.8 million after tax) and $10.4 million ($6.6 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 $30.7 million ($18.5 million after tax) in the first six months of 2006 and decreased $151.0 million ($95.0 million after tax) in the first six months of 2005. At June 30, 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 $3.5 million. At June 30, 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 June 30, 2006:

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	Natural Gas Swaps				Crude Oil Swaps
			NYMEX				NYMEX
			Price per				Price
Quarter Ending	Bbtu		Mmbtu		Mbbls		per Bbl
September 30, 2006		2,829	$	5.22		62	$	32.02
December 31, 2006		2,829		5.39		62		31.71
		5,658	$	5.30		124	$	31.87
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 June 30, 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 $1.0 million at June 30, 2006. We had no derivative financial instruments for managing interest rate risks in place as of June 30, 2005.

(3) Industry Segment Financial Information

     We operate in one reportable segment, as an independent energy company engaged in producing oil and natural gas; 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
	Company		Company
	Six months		Six months
	ended June 30,		ended June 30,
(in thousands)	2006		2005
Cash paid during the period for:
Interest	$	13,164	$	12,153
Income taxes		—		500
Non-cash investing and financing activities:
Non-cash additions to property and equipment		4,218		2,573

(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.

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     On July 28, 2006 the Company entered into an agreement to sell an office building in North Canton, Ohio. This building is classified as an asset held for sale on the June 30, 2006 balance sheet. The sale is expected to close in the third quarter of 2006.

(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 six-month periods ended June 30, 2006 and 2005.

	Successor		Predecessor I
	Company		Company
	Six months		Six months
	ended June 30,		ended June 30,
	2006		2005
Comprehensive income (loss):
Net income	$	10,132	$	5,339
Other comprehensive income (loss), net of tax:
Unrealized gain (loss) in derivative fair value		18,539		(94,982	)
Reclassification adjustment for derivative loss reclassified into earnings		7,776		6,554
Change in accumulated other comprehensive income (loss)		26,315		(88,428	)
Comprehensive income (loss)	$	36,447	$	(83,089	)

(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 $2.6 million for overhead fees, $3.5 million for field labor, vehicles and district office expense, $381,000 for drilling overhead fees and $588,000 for drilling labor costs in the first six months of 2006 related to this agreement. The Company also reimbursed EnerVest Operating for expenses of $332,000 in the first six months of 2006 related to the transition of accounting responsibilities from the Company to EnerVest Operating’s Charleston, West Virginia office.

     The Company paid approximately $211,000 to Opportune LLP in the first six months 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 partner with Opportune.

     The Company paid approximately $199,000 to PetroAcct LP in the first six months of 2006 for services related to the transition of accounting and information system responsibilities from the Company to EnerVest. A subsidiary of EnerVest owns 50% of PetroAcct.

(9) Bond Repurchase

     In June 2006, the Company repurchased a portion of the outstanding senior secured notes. The repurchased notes had a face value of $33.025 million and were repurchased at 102.75. A gain of $436,000 was recorded in connection with the transaction.

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,”

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“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

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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 primarily 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 when all wells in a property group are sold or abandoned. 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

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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 and 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 immediately 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 or interest rate price volatility and support our capital expenditure plans. Our derivative financial instruments take the form of swaps or collars. At June 30, 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.

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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 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 June 30,				Six months ended June 30,
	2006		2005		2006		2005
Production
Gas (Mmcf)		3,487		3,648		7,024		7,211
Oil (Mbbls)		91		95		189		177
Total production (Mmcfe)		4,035		4,216		8,160		8,275
Average price (1)
Gas (per Mcf)	$	8.65	$	6.70	$	9.29	$	6.85
Oil (per Bbl)		66.36		37.75		62.80		36.99
Mcfe		8.98		6.64		9.45		6.76
Average costs (per Mcfe)
Production expense	$	1.20	$	1.27	$	1.28	$	1.30
Production taxes		0.17		0.18		0.19		0.18
Depletion		2.24		1.91		2.23		1.90
Operating margin (per Mcfe)		7.61		5.19		7.98		5.28

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

	Three months ended June 30,				Six months ended June 30,
	2006		2005		2006		2005
Gas (per Mcf)	$	5.90	$	5.74	$	6.19	$	5.71
Oil (per Bbl)		66.36		36.23		62.80		35.25
Mcfe		6.60		5.78		6.78		5.73

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

Results of Operations — Second Quarters of 2006 and 2005 Compared

Revenues

     Operating revenues increased from $30.6 million in the second quarter of 2005 to $38.5 million in the second quarter of 2006. The increase in operating revenues was primarily due to higher oil and gas sales revenues of $8.2 million.

     Gas volumes sold were 3.5 Bcf (billion cubic feet) in the second quarter of 2006, which was a decrease of 161 Mmcf (4%) compared to the second quarter of 2005. This decrease in gas volumes sold resulted in a decrease in gas sales revenues of approximately $1.1 million. Oil volumes sold decreased

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approximately 4,000 Bbls (4%) from 95,000 Bbls in the second quarter of 2005 to 91,000 Bbls in the second quarter of 2006 resulting in a decrease in oil sales revenues of approximately $130,000. The lower oil and gas sales volumes are primarily due to normal production declines partially offset by production from new wells drilled during 2005 and 2006.

     The average price realized for our natural gas increased $1.95 per Mcf from $6.70 in the second quarter of 2005 to $8.65 per Mcf in the second quarter of 2006, which increased gas sales revenues by approximately $6.8 million. As a result of our hedging activities, gas sales revenues were increased by $5.2 million ($1.50 per Mcf) in the second quarter of 2006 and decreased by $1.1 million ($0.29 per Mcf) in the second quarter of 2005. The average price realized for our oil increased from $37.75 per Bbl in the second quarter of 2005 to $66.36 per Bbl in the second quarter of 2006, which increased oil sales revenues by approximately $2.6 million. As a result of our hedging activities, oil sales revenues were decreased by approximately $1.1 million ($12.00 per Bbl) in the second quarter of 2005. Our oil derivatives did not qualify for cash flow hedge accounting in the second quarter of 2006 and, therefore, did not affect oil sales revenues.

     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 $5.19 per Mcfe in the second quarter of 2005 to $7.61 per Mcfe in the second quarter of 2006. The average price increased $2.34 per Mcfe while production expense decreased $0.07 per Mcfe and production taxes decreased $0.01 per Mcfe in the second quarter of 2006 compared to the second quarter of 2005.

     Gas gathering and marketing revenues decreased from $2.6 million in the second quarter of 2005 to $2.3 million in the second quarter of 2006. The decrease was due to a $290,000 decrease in gas marketing revenues and a $33,000 decrease in gas gathering revenues primarily due to the decreased volumes discussed above.

Costs and Expenses

     Production expense decreased from $5.3 million in the second quarter of 2005 to $4.8 million in the second quarter of 2006. The average production cost decreased from $1.27 per Mcfe in the second quarter of 2005 to $1.20 per Mcfe in the second quarter of 2006. The decrease in production expense was primarily due to organizational changes implemented by EnerVest in the first quarter of 2006. In March 2006, we entered into a contract with EnerVest Operating for EnerVest to operate all of the oil and gas properties we operate. As a result, we pay an overhead fee to EnerVest to provide all operations management and administration related to the oil and gas properties. The overhead charges are classified as general and administrative expense. This has resulted in lower production expenses and higher general and administrative expenses compared to 2005.

     Production taxes decreased $84,000 from $761,000 in the second quarter of 2005 to $677,000 in the second quarter of 2006. Average per unit production taxes decreased from $0.18 per Mcfe in the second quarter of 2005 to $0.17 per Mcfe in the second quarter of 2006. The decreased production taxes were primarily due to lower oil and gas sales revenues in Michigan in the second quarter of 2006 compared to the second quarter of 2005. In Michigan, production taxes are based on a percentage of revenues, excluding the effects of hedging.

     Exploration expense decreased $608,000 (62%) from $983,000 in the second quarter of 2005 to $375,000 in the second quarter of 2006. This decrease in exploration expense is primarily due to the focus on development activities in the second quarter of 2006.

     General and administrative expense increased $778,000 (54%) from $1.5 million in the second quarter of 2005 to $2.2 million in the second quarter of 2006 primarily due to recording $1.3 million of overhead fees charged by EnerVest in the second quarter of 2006, which were partially offset by a $513,000 decrease in compensation-related expenses.

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     Depreciation, depletion and amortization increased by $596,000 from $8.7 million in the second quarter of 2005 to $9.3 million in the second quarter of 2006. This increase was primarily due to a $1.0 million increase in depletion expense, which was partially offset by a $293,000 decrease in amortization of loan costs. Depletion expense increased $1.0 million (12%) from $8.0 million in the second quarter of 2005 to $9.0 million in the second quarter of 2006 primarily due to a higher depletion rate per Mcfe. Depletion per Mcfe increased from $1.91 per Mcfe in the second quarter of 2005 to $2.24 per Mcfe in the second quarter of 2006, primarily due to a higher cost basis resulting from purchase accounting for the Transaction.

     Derivative fair value (gain) loss was a gain of $2.9 million in the second quarter of 2005 compared to a loss of $6.2 million in the second 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 $665,000 and $389,000 related to the ineffective portion of crude oil swaps and natural gas swaps qualifying for hedge accounting which were recorded in the second quarters of 2006 and 2005, respectively.

     Interest expense decreased $306,000 from $5.9 million in the second quarter of 2005 to $5.6 million in the second quarter of 2006. This decrease in interest expense was due to the amortization of the fair value adjustments from purchase accounting on the Senior Secured Notes, and was partially offset by higher blended interest rates.

     Income tax expense was $3.1 million in the second quarter of 2006 compared to $1.8 million in the second quarter of 2005. The increase is primarily related to a tax benefit of $1.1 million to adjust the recorded deferred tax account balances for Ohio during the second quarter of 2005 due to changes in Ohio tax law. On June 30, 2005, the State of Ohio enacted new tax legislation that will result in the elimination of the income and franchise tax over a four year period and it will be replaced with a gross receipts based tax.

Results of Operations — Six Months of 2006 and 2005 Compared

Revenues

     Operating revenues increased from $60.9 million in the first six months of 2005 to $83.2 million in the first six months of 2006. The increase in operating revenues was due to higher oil and gas sales revenues of $21.2 million and higher gas marketing and gathering revenues of $1.0 million.

     Gas volumes sold were 7.0 Bcf in the first six months of 2006, which was a decrease of 187 Mmcf (3%) compared to the first six months of 2005. This decrease in gas volumes sold resulted in a decrease in gas sales revenues of approximately $1.3 million. The decrease in gas volumes sold was primarily due to normal production declines, which was partially offset by production from new wells drilled in 2005 and 2006. Oil volumes sold increased approximately 12,000 Bbls (7%) from 177,000 Bbls in the first six months of 2005 to 189,000 Bbls in the first six months of 2006 resulting in a increase in oil sales revenues of approximately $440,000. The increase in oil volumes sold was primarily due to production from new wells drilled in 2005 and 2006, which was partially offset by normal production declines.

     The average price realized for our natural gas increased $2.44 per Mcf from $6.85 in the first six months of 2005 to $9.29 per Mcf in the first six months of 2006, which increased gas sales revenues by approximately $17.1 million. As a result of our hedging activities, gas sales revenues were increased by $9.4 million ($1.34 per Mcf) in the first six months of 2006 and decreased by $60,000 ($0.01 per Mcf) in the first six months of 2005. The average price realized for our oil increased from $36.99 per Bbl in the first six months of 2005 to $62.80 per Bbl in the first six months of 2006, which increased oil sales revenues by approximately $4.9 million. As a result of our hedging activities, oil sales revenues were decreased by approximately $2.0 million ($11.21 per Bbl) in the first six months of 2005. Our oil

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derivatives did not qualify for cash flow hedge accounting in the second quarter of 2006 and, therefore, did not affect oil sales revenues.

     The operating margin from oil and gas sales on a per unit basis increased from $5.28 per Mcfe in the first six months of 2005 to $7.98 per Mcfe in the first six months of 2006. The average price increased $2.69 per Mcfe and production expense decreased $0.02 per Mcfe while production taxes increased $0.01 per Mcfe in the first six months of 2006 compared to the first six months of 2005.

     Gas gathering and marketing revenues increased from $5.0 million in the first six months of 2005 to $6.0 million in the first six months of 2006 due to a $753,000 increase in gas marketing revenues and a $231,000 increase in gas gathering revenues as a result of higher average gas prices in the first six months of 2006 compared to the first six months of 2005.

Costs and Expenses

     Production expense decreased from $10.8 million in the first six months of 2005 to $10.4 million in the first six months of 2006. The average production cost decreased from $1.30 per Mcfe in the first six months of 2005 to $1.28 per Mcfe in the first six months of 2006. The decrease in production expense was primarily due to organizational changes implemented by EnerVest in the first quarter of 2006. In March 2006, we entered into a contract with EnerVest Operating for EnerVest to operate all of the oil and gas properties we operate. As a result, we pay a overhead fee to EnerVest to provide all operations management and administration related to the oil and gas properties. The overhead charges are classified as general and administrative expense. This has resulted in lower production expenses and higher general and administrative expenses compared to 2005.

     Production taxes increased $94,000 from $1.5 million in the first six months of 2005 to $1.6 million in the first six months of 2006. Average per unit production taxes increased from $0.18 per Mcfe in the first six months of 2005 to $0.19 per Mcfe in the first six months of 2006. The increased production taxes are primarily due to higher oil and gas prices in the first six months of 2006 in Michigan, where production taxes are based on a percentage of revenues, excluding the effects of hedging.

     Exploration expense decreased $1.4 million (72%) from $1.9 million in the first six months of 2005 to $549,000 in the first six months of 2006. This decrease in exploration expense is primarily due to the focus on development activities in the first six months of 2006.

     General and administrative expense increased $2.2 million (69%) from $3.2 million in the first six months of 2005 to $5.4 million in the first six months of 2006 primarily due to recording $2.6 million of overhead fees charged by EnerVest in the first six months of 2006. During the first six months of 2006, we also expensed approximately $942,000 for costs associated with the transition of accounting and administrative functions to EnerVest’s Charleston, West Virginia office and approximately $355,000 related to the restatements of our 2005 Form 10-K and Forms 10-Q. These increases were partially offset by a $1.5 million decrease in compensation related expenses.

     Depreciation, depletion and amortization increased by $1.7 million from $17.0 million in the first six months of 2005 to $18.7 million in the first six months of 2006. This increase was primarily due to a $2.5 million increase in depletion expense, which was partially offset by a $587,000 decrease in amortization of loan costs. Depletion expense increased $2.5 million (16%) from $15.7 million in the first six months of 2005 to $18.2 million in the first six months of 2006 primarily due to a higher depletion rate per Mcfe. Depletion per Mcfe increased from $1.90 per Mcfe in the first six months of 2005 to $2.23 per Mcfe in the first six months of 2006, primarily due to a higher cost basis resulting from purchase accounting for the Transaction.

     Derivative fair value loss was $3.3 million in the first six months of 2005 compared to $13.5 million in the first six months of 2006. The derivative fair value loss reflects the changes in fair value of

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certain derivative instruments that are not designated or do not qualify as cash flow hedges and $548,000 and $515,000 related to the ineffective portion of crude oil and natural gas swaps qualifying for hedge accounting which were recorded in the first six months of 2006 and 2005, respectively.

     Interest expense decreased $468,000 from $11.8 million in the first six months of 2005 to $11.3 million in the first six months of 2006. This decrease in interest expense was due to the amortization of the fair value adjustments from purchase accounting on the Senior Secured Notes, which was partially offset by higher blended interest rates.

     Income tax expense was $6.6 million for the first six months of 2006 compared to $1.2 million for the first six months of 2005. The increase is primarily related to an increase in income before income taxes and as a result of changes in the Ohio tax law. On June 30, 2005 the State of Ohio enacted new tax legislation that will result in the elimination of the income and franchise tax over a four year period and it will be replaced with a gross receipts based tax. As a result of the new tax structure, we recorded a tax benefit of $1.1 million to adjust the recorded deferred tax account balances for Ohio during the second quarter of 2005.

Liquidity and Capital Resources

Cash Flows

     The primary sources of cash in the six-month period ended June 30, 2006 have been funds generated from operations. Funds used during this period were primarily used for operations, development expenditures, derivative settlements, dividends 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 $42.0 million during the first six months of 2006 compared to $33.4 million in the first six months of 2005. The increase was primarily due to an increase in cash received for oil and gas revenues (net of hedging) offset by changes in working capital items of $463,000.

     Our investing activities used cash flows of $15.4 million during the first six months of 2006 compared to $16.8 million provided in the first six months of 2005. The decrease is due to an increase in cash received for property disposals of $3.3 million and lower exploration expense of $1.4 million, which were partially offset by an increase in capital expenditures.

     Cash flows used in financing activities increased $11.9 million in the first six months of 2006 primarily due to the payment of dividends.

     Our current ratio at June 30, 2006 was 0.64 to 1. During the first six months of 2006, working capital increased $12.6 million from a deficit of $39.0 million at December 31, 2005 to a deficit of $26.4 million at June 30, 2006. The increase in working capital was primarily due to a decrease in the current liability related to the fair value of derivatives of $23.8 million, a decrease in accounts payable and accrued expenses of $2.1 million and the recording of a $3.6 million asset held for sale as current, which was partially offset by a decrease in the current deferred tax asset of $9.6 million and a decrease in accounts receivable of $7.7 million.

Capital Expenditures

     During the first six months of 2006, we spent approximately $22.4 million on our drilling activities and other capital expenditures. In the first six months of 2006, we drilled 100 gross (94.5 net) development wells, all of which were successfully completed as producers in the target formation.

     We have 2 gross (1.5 net) exploratory Trenton Black River wells in Ohio that were drilled in the second quarter of 2005. The total cost to date is approximately $273,000, of which $26,000 was incurred in 2006 to secure additional leases. One of the wells has been completed and tested. We plan to drill two or three additional wells in the fourth quarter of 2006 to determine whether the reserves discovered will economically justify construction of a pipeline and compression facility. The second well will be completed and tested in the fourth quarter of 2006. If either well is determined to be dry, the cost will be written off to exploration expense.

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     We currently expect to spend approximately $43 million during 2006 on our drilling activities and other capital expenditures, which is an increase of approximately $7 million from our original plan. The additional expenditures are due to an increase in drilling and completion costs and additional drilling opportunities in a continued high oil and gas price environment. 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 June 30, 2006, we had cash of $8.7 million and approximately $840,000 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. There can be no assurance that the future drilling of our proved undeveloped locations will provide adequate liquidity in the future.

     At June 30, 2006, we had a $390 million credit facility (“Amended Credit Agreement”) comprised of a five-year $350 million revolving facility with a borrowing base of $90.25 million, of which $88.5 million was outstanding at June 30, 2006. On July 5, 2006, the borrowing base was increased to $113.4 million. The Amended Credit Agreement 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.

     In June 2006, the Company repurchased a portion of the outstanding senior secured notes. The repurchased notes had a face value of $33.025 million and were repurchased at 102.75. A gain of $436,000 was recorded in connection with the transaction.

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

     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 our capital stock; pay principal and interest on certain subordinated debt; make certain types of investments; sell assets or merge with another entity; pledge or otherwise encumber our capital stock; or enter into transactions with affiliates. The Amended Credit Agreement also requires compliance with customary financial covenants, including a minimum interest coverage ratio, a maximum leverage ratio and a minimum current ratio.

     At June 30, 2006, the interest rate under our base rate option was 8.875%. Under our one-month LIBOR option, the rate was 7.390%. At June 30, 2006, we had $40.9 million of outstanding letters of credit. At June 30, 2006, there was $88.5 million outstanding under the revolving credit agreement. We had $840,000 of borrowing capacity under our revolving facility available for general corporate purposes. As of June 30, 2006, we were in compliance with all financial covenants and requirements under the Amended Credit Agreement.

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

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

     The interest rate risk relates to existing debt under our revolving facility as well as any new debt financing needed to fund capital requirements. We may manage our interest rate risk through the use of interest rate swaps to hedge the interest rate exposure associated with the credit agreement, whereby a portion of our floating rate exposure is exchanged for a fixed interest rate. A portion of our long-term debt consists of senior secured notes where the interest component is fixed. At June 30, 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 $1.0 million at June 30, 2006. We had no derivative financial instruments for managing interest rate risks in place as of June 30, 2005. If market interest rates for short-term borrowings increased 1%, the increase in interest expense in the quarter would be approximately $121,000. This sensitivity analysis is based on our financial structure at June 30, 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 $661,000, after considering the effects of the hedging contracts in place at June 30, 2006. If the price of crude oil decreased $5.00 per Bbl, oil sales revenues for the quarter would decrease by $457,000. Our oil and gas sales revenues include a pre-tax gain of $9.4 million in the first six months of 2006 and a pre-tax loss of $2.0 million in the first six months of 2005 related to our hedging activities. At June 30, 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.

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

Quarter Ending	Natural Gas Swaps				Crude Oil Swaps
			NYMEX				NYMEX
			Price per				Price
	Bbtu		Mmbtu		Mbbls		per Bbl
September 30, 2006		2,829	$	5.22		62	$	32.02
December 31, 2006		2,829		5.39		62		31.71
		5,658	$	5.30		124	$	31.87
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.

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Item 4. Controls and Procedures

     As of the end of the quarterly period ended June 30, 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 June 30, 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.

     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

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

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

     None.

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Item 6. Exhibits.

     (a) Exhibits

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.

*Filed herewith.

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SIGNATURES

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

	BELDEN & BLAKE CORPORATION
Date:August 14, 2006	By:	/s/ Mark A. Houser
		Mark A. Houser, Chief Executive Officer, Chairman of the Board of Directors and Director
Date:August 14, 2006	By:	/s/ James M. Vanderhider
		James M. Vanderhider, President, Chief Financial Officer and Director (Principal Financial Officer)

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