BELDEN & BLAKE CORPORATION 10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the quarterly period ended September 30, 2007


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

For the transition period from to

Commission File Number: 0-20100

BELDEN & BLAKE CORPORATION

(Exact name of registrant as specified in its charter)


Ohio		34-1686642

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

1001 Fannin Street, Suite 800
Houston, Texas		77002

(Address of principal executive offices)		(Zip Code)

(713) 659-3500

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, 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 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 Noþ

As of October 31, 2007, Belden & Blake Corporation had outstanding 1,534 shares of common stock, without par value, which is its only class of stock.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

BELDEN & BLAKE CORPORATION

BALANCE SHEETS

(unaudited)

(in thousands, except share data)


	September 30,			December 31,
	2007			2006
ASSETS
Current assets
Cash and cash equivalents	$	13,490		$	5,927
Accounts receivable (less accumulated provision for doubtful accounts:		14,946			19,855
September 30, 2007- $522; December 31, 2006 - $1,271)
Inventories		812			885
Deferred income taxes		15,135			12,607
Other current assets		229			510
Fair value of derivatives		193			378

Total current assets		44,805			40,162

Property and equipment, at cost
Oil and gas properties (successful efforts method)		710,334			692,576
Gas gathering systems		1,305			1,305
Land, buildings, machinery and equipment		2,761			3,031

		714,400			696,912
Less accumulated depreciation, depletion and amortization		79,654			52,564

Property and equipment, net		634,746			644,348
Goodwill		90,076			90,076
Fair value of derivatives		—			193
Other assets		1,970			2,244

	$	771,597		$	777,023

LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Accounts payable	$	4,588		$	2,259
Accrued expenses		16,580			21,554
Current portion of long-term liabilities		276			408
Fair value of derivatives		38,268			27,576

Total current liabilities		59,712			51,797

Long-term liabilities
Bank and other long-term debt		99,949			95,454
Senior secured notes		164,463			165,106
Subordinated promissory note - related party		26,269			25,000
Asset retirement obligations and other long-term liabilities		21,473			20,627
Fair value of derivatives		166,143			160,011
Deferred income taxes		111,008			115,325

Total long-term liabilities		589,305			581,523

Shareholder’s equity
Common stock: without par value; 3,000 shares authorized and 1,534 shares issued and outstanding		—			—
Paid in capital		125,000			125,000
Retained earnings		17,896			41,262
Accumulated other comprehensive loss		(20,316	)		(22,559	)

Total shareholder’s equity		122,580			143,703

	$	771,597		$	777,023

See accompanying notes.

BELDEN & BLAKE CORPORATION

STATEMENTS OF OPERATIONS

(unaudited, in thousands)


	Three months ended			Three months ended			Nine months ended			Nine months ended
	September 30, 2007			September 30, 2006			September 30, 2007			September 30, 2006
Revenues
Oil and gas sales	$	27,086		$	38,559		$	85,915		$	115,709
Gas gathering and marketing		2,334			2,474			7,728			8,478
Other		10			196			672			494

		29,430			41,229			94,315			124,681

Costs and Expenses
Production expense		5,994			6,247			18,253			16,975
Production taxes		494			589			1,687			1,877
Gas gathering and marketing		1,957			1,946			6,431			6,892
Exploration expense		264			148			1,292			697
General and administrative expense		1,675			2,318			5,535			7,760
Depreciation, depletion and amortization		9,156			10,211			27,169			28,724
Accretion expense		328			314			958			910
Derivative fair value (gain) loss		(8,695	)		(43,235	)		37,446			(29,759	)

		11,173			(21,462	)		98,771			34,076

Operating income (loss)		18,257			62,691			(4,456	)		90,605

Other expense
Interest expense		6,002			6,091			17,837			17,670
Gain on early extinguishment of debt		—			—			—			(436	)

Income (loss) before income taxes		12,255			56,600			(22,293	)		73,371
Provision (benefit) for income taxes		4,987			22,405			(8,677	)		29,044

Net income (loss)	$	7,268		$	34,195		$	(13,616	)	$	44,327

See accompanying notes.

BELDEN & BLAKE CORPORATION

STATEMENTS OF CASH FLOWS

(unaudited)

(in thousands)


	Nine months ended			Nine months ended
	September 30, 2007			September 30, 2006
Cash flows from operating activities:
Net (loss) income	$	(13,616	)	$	44,327
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization		27,169			28,724
Accretion expense		958			910
Gain on disposal of property and equipment and debt extinguishment		(57	)		(472	)
Non-cash hedging activities		41,652			(46,144	)
Exploration expense		571			697
Deferred income taxes		(8,854	)		29,044
Other non-cash expense		1,665			315
Change in operating assets and liabilities
Accounts receivable and other current assets		5,000			6,854
Inventories		6			238
Accounts payable and accrued expenses		(3,326	)		(12,792	)

Net cash provided by operating activities		51,168			51,701

Cash flows from investing activities:
Additions to property and equipment		(17,265	)		(30,164	)
Proceeds from property and equipment disposals		270			6,891
Exploration expense		(571	)		(697	)
Increase in other assets		(44	)		(18	)

Net cash used in investing activities		(17,610	)		(23,988	)

Cash flows from financing activities:
Proceeds from revolving line of credit		6,500			55,376
Repayment of revolving line of credit		(2,000	)		(12,000	)
Repayment of secured notes		—			(33,933	)
Repayment of long-term debt and other obligations		(22	)		(23	)
Settlement of derivative liabilities recorded in purchase accounting		(20,723	)		(22,961	)
Dividends paid		(9,750	)		(17,250	)

Net cash used in financing activities		(25,995	)		(30,791	)


Net increase (decrease) in cash and cash equivalents		7,563			(3,078	)
Cash and cash equivalents at beginning of period		5,927			8,172

Cash and cash equivalents at end of period	$	13,490		$	5,094

See accompanying notes.

BELDEN & BLAKE CORPORATION

NOTES TO FINANCIAL STATEMENTS

(unaudited)

September 30, 2007

(1)

Basis of Presentation

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

The accompanying unaudited financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the period ended September 30, 2007 are not necessarily indicative of the results that may be expected for the year ended December 31, 2007. For further information, refer to the financial statements and footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2006. Certain reclassifications have been made to previously reported amounts in order to conform to current year presentation.

(2)

Derivatives and Hedging

From time to time, we may enter into a combination of futures contracts, commodity derivatives and fixed-price physical commodity contracts to manage our exposure to natural gas, crude oil or interest rate price volatility and support our capital expenditure plans. At September 30, 2007, our derivative contracts were comprised of natural gas swaps, crude oil swaps and interest rate swaps, which were placed with major financial institutions that we believe are a minimal credit risk. Qualifying interest rate derivative financial instruments are designated as cash flow hedges. Since July 1, 2006, our oil and gas derivative financial instruments are no longer designated as cash flow hedges. Changes in fair value of the derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time the hedged items impact earnings. The changes in fair value of non-qualifying derivative contracts will be reported in expense in the statements of operations as derivative fair value loss.

During the first nine months of 2007 and 2006, net losses of $3.9 million ($2.3 million after tax) and $5.8 million ($3.8 million after tax), respectively, were reclassified from accumulated other comprehensive income to earnings. At September 30, 2007, the estimated net loss in accumulated other comprehensive income that is expected to be reclassified into earnings within the next 12 months is approximately $5.6 million. At September 30, 2007, we have partially hedged our exposure to the variability in future cash flows generated from the sale of oil and natural gas 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 September 30, 2007:


	Natural Gas Swaps				Crude Oil Swaps
			NYMEX				NYMEX
			Price per				Price per
	Bbtu		Mmbtu		Mbbls		Bbl
Quarter Ending
December 31, 2007		2,686	$	4.91		56	$	30.44

Year Ending
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 September 30, 2007, we had interest rate swaps in place for $80 million of our outstanding debt under our revolving credit facility through September 16, 2008. The swaps provide 1-month LIBOR fixed rates at 4.285% on $40 million and 5.160% on $40 million, plus the applicable margin. The fair value of these interest rate swaps was an asset of $3,000 at September 30, 2007.

(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


	Nine months			Nine months
	ended			ended
	September 30,			September 30,
(in thousands)	2007			2006
Cash paid during the period for:
Interest	$	15,951		$	22,721
Income taxes		177			—
Non-cash investing and financing activities:
Non-cash additions to property and equipment		1,206			1,481
Non-cash additions to debt		(1,269	)		—

(5)

Contingencies

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

(6)

Comprehensive Income

Comprehensive income includes net income and certain items recorded directly to shareholder’s equity and classified as accumulated other comprehensive income. The table below summarizes comprehensive income and provides the components of the change in accumulated other comprehensive income for the nine month periods ended September 30, 2007 and 2006.


	Nine months ended			Nine months ended
	September 30, 2007			September 30, 2006
Comprehensive (loss) income:
Net (loss) income	$	(13,616	)	$	44,327
Other comprehensive (loss) income, net of tax:
Unrealized gain in derivative fair value		289			19,690
Reclassification adjustment for derivative (loss) gain reclassified into earnings		(2,532	)		3,774

Change in accumulated other comprehensive (loss) income		(2,243	)		23,464

Comprehensive (loss) income	$	(15,859	)	$	67,791

(7)

Long-Term Debt

Long-term debt consists of the following (in thousands):


	September 30, 2007		December 31, 2006
Senior secured notes	$	159,475	$	159,475
Bank revolving credit facility		99,876		95,376
Subordinated promissory note (related party)		26,269		25,000
Other		82		85

		285,702		279,936
Less current portion		9		7

Long-term debt		285,693		279,929
Fair value adjustment — senior secured notes		4,988		5,631

	$	290,681	$	285,560

Amended Credit Agreement

At September 30, 2007, we had a $390 million credit facility (“Amended Credit Agreement”) comprised of a five-year $350 million revolving facility with a base of $113.4 million, of which $99.9 million was outstanding at September 30, 2007. This facility is for working capital requirements and general corporate purposes, including the issuance of letters of credit; and a five year $40 million letter of credit facility that may be used only to provide credit support for our obligations under the hedge agreement and other hedge transactions. Borrowings under the Amended Credit Agreement bear interest (i) at the greater of the prime rate or an adjusted federal funds rate, plus an applicable margin ranging from 0% to 0.625% based on the aggregate principal amount outstanding under the Amended Credit Agreement, or, (ii) at our option, the Eurodollar base rate plus an applicable margin ranging from 1.125% to 2.125% based on the aggregate principal amount outstanding under the Amended Credit Agreement. The full amount borrowed under the Amended Credit Agreement will mature on August 16, 2010.

The obligations under the Amended Credit Agreement are secured by a first lien security interest

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

The Amended Credit Agreement contains covenants that will limit our ability to, among other things, incur or guarantee additional indebtedness; create liens; pay dividends on or repurchase stock; pay principal and interest on certain subordinated debt; make certain types of investments; sell assets or merge with another entity; pledge or otherwise encumber our capital stock; or enter into transactions with affiliates. The Amended Credit Agreement also requires compliance with customary financial covenants, including a minimum interest coverage ratio, a maximum leverage ratio and a minimum current ratio. On August 3, 2007, our bank group amended the Amended Credit Agreement to increase the maximum Leverage Ratio from 4.0 to 1.0 to 4.25 to 1.0 for the quarters ending on September 30, 2007 and December 31, 2007.

In connection with the Transaction, we executed a Subordinated Promissory Note (“Note”) in favor of Capital C in the maximum principal amount of $94 million. Under the Note, Capital C loaned us $25 million. The Note accrues interest at a rate of 10% per annum and matures on August 16, 2012. We received a fairness opinion from an unrelated financial services firm with respect to the terms of the Note. Interest payments on the Note are due quarterly. 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.

(8)

Related Party Transactions

We have a joint operating agreement with EnerVest Operating LLC (“EnerVest Operating”). We recorded costs of approximately $4.4 million (as general and administrative expense) for operating overhead fees, $5.6 million (as production expense) for field labor, vehicles and district office expense, $257,000 (capitalized) for drilling overhead fees and $780,000 (capitalized) for drilling labor costs in the first nine months of 2007 related to this agreement. We have a Note in favor of our parent, Capital C in the maximum amount of $94 million. The amount due under the note at September 30, 2007 was $26.3 million. In lieu of cash payments, we have the option to make interest payments on the note by borrowing additional amounts against the note. We made cash interest payments of $1.9 million in the first nine months of 2006 and $616,000 in the first quarter of 2007 to Capital C. We borrowed $623,000 and $646,000 against the note for the interest payments in the second and third quarters of 2007, respectively.

(9)

New Accounting Standards

In July 2006, the Financial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement 109” (“FIN 48”), which clarifies the accounting for uncertainty in tax positions taken or expected to be taken in a tax return, including issues relating to financial statement recognition and measurement. FIN 48 provides that the tax effects from an uncertain tax position can be recognized in the financial statements only if the position is “more-likely-than-not” to be sustained if the position were to be challenged by a taxing authority. The assessment of the tax position is based solely on the technical merits of the position, without regard to the likelihood that the tax position may be challenged. If an uncertain tax position meets the “more-likely-than-not” threshold, the largest amount of tax benefit that is more than 50 percent likely to be recognized upon ultimate settlement with the taxing authority is recorded. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. Consistent with the requirements of FIN 48, we adopted FIN 48 on January 1, 2007. The adoption of FIN 48 did not have a material impact on our financial statements.

FIN 48 requires us to evaluate whether any material tax position we have taken will more likely than not be sustained upon examination by the appropriate taxing authority. As we believe that all such material tax positions taken by us are supportable by existing laws and related interpretations, there are no material uncertain tax positions to consider in accordance with FIN 48.

Since we have no unrecognized tax benefits as of September 30, 2007, there is no potential impact on our effective tax rate.

To the extent penalties and interest would be assessed on any underpayment of income tax, such amounts have been accrued and classified as a component of income tax expense in the financial statements. This is an accounting policy election made by us that is a continuation of our historical policy and will continue to be consistently applied in the future. As of September 30, 2007, we have not accrued any interest and penalties related to unrecognized tax benefits.

We do not anticipate a significant change in the balance of unrecognized tax benefits within the next 12 months.

In September 2006, the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 157, Fair Value Measurements, to provide guidance for using fair value to measure assets and liabilities. SFAS No. 157 establishes a fair value hierarchy and clarifies the principle that fair value should be based on assumptions market participants would use when pricing the asset or liability. SFAS No. 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We will adopt SFAS No. 157 on January 1, 2008 and we have not yet determined the impact, if any, on our financial statements.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115. SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. Unrealized gains and losses on items for which the fair value option has been selected are reported in earnings. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We will adopt SFAS No. 159 on January 1, 2008, and we have not yet determined the impact, if any, on our financial statements.

(10)

Subsequent Event

In November 2007, we entered into basis differential swap contracts covering 10,000 Mmbtu per day of our gas sales volumes in 2009 and 2010 and 9,000 Mmbtu per day in 2011.

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

Forward-Looking Information

The information in this document includes forward-looking statements that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Statements preceded by, followed by or that otherwise include the statements “should,” “believe,” “expect,” “anticipate,” “intend,” “continue,” “estimate,” “plan,” “outlook,” “may,” “future,” “projection,” “likely,” “possible,” “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, 2006, under the Heading “Risk Factors”

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

Results of Operations

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


	Three months ended September 30,				Nine months ended September 30,
	2007		2006		2007		2006
Production
Gas (Mmcf)		3,310		3,582		10,042		10,606
Oil (Mbbls)		91		96		272		285
Total production (Mmcfe)		3,854		4,157		11,676		12,317
Average price (1)
Gas (per Mcf)	$	6.25	$	8.93	$	6.86	$	9.17
Oil (per Bbl)		70.75		68.63		62.39		64.76
Mcfe		7.03		9.28		7.36		9.39
Average costs (per Mcfe)
Production expense	$	1.56	$	1.50	$	1.56	$	1.38
Production taxes		0.13		0.14		0.14		0.15
Depletion		2.35		2.42		2.30		2.30
Oil and Gas operating margin (per Mcfe)		5.34		7.64		5.66		7.86

(1) The average prices presented above include non-cash amounts for hedge gains or losses related to purchase accounting for the Transaction which are being reclassified from accumulated other comprehensive income to oil and gas sales. Excluding these non-cash amounts from oil and gas sales revenues would result in the following average prices:


	Three months ended September 30,				Nine months ended September 30,
	2007		2006		2007		2006
Gas (per Mcf)	$	6.62	$	6.98	$	7.28	$	6.45
Oil (per Bbl)		70.75		68.63		62.39		64.76
Mcfe		7.35		7.60		7.72		7.06


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
Oil and Gas operating margin (per Mcfe) — average price less production expense and production taxes

Results of Operations — Third Quarters of 2007 and 2006 Compared
Revenues

Operating revenues decreased from $41.2 million in the third quarter of 2006 to $29.4 million in the third quarter of 2007. The decrease in operating revenues was primarily due to lower oil and gas sales revenues of $11.5 million.

Gas volumes sold were 3.3 Bcf (billion cubic feet) in the third quarter of 2007, which was a decrease of 272 Mmcf (8%) compared to the third quarter of 2006. This decrease in gas volumes sold resulted in a decrease in gas sales revenues of approximately $2.4 million. Oil volumes sold decreased approximately 5,000 Bbls (5%) from 96,000 Bbls in the third quarter of 2006 to 91,000 Bbls in the third quarter of 2007 resulting in a decrease in oil sales revenues of approximately $360,000. The lower oil and gas sales volumes were primarily due to normal production declines, a lower level of drilling activity in 2007, a gas

purchaser curtailment for pipeline repairs in Pennsylvania and a gas curtailment in Michigan due to a carbon dioxide processing plant being off-line in the third quarter of 2007. These decreases were partially offset by production from new wells drilled in 2007.

The average price realized for our natural gas decreased $2.68 per Mcf from $8.93 in the third quarter of 2006 to $6.25 per Mcf in the third quarter of 2007, which decreased gas sales revenues by approximately $8.9 million. As a result of our qualified effective hedging activities, gas sales revenues were lower by $1.2 million ($0.37 per Mcf) in the third quarter of 2007 and higher by $7.0 million ($1.95 per Mcf) in the third quarter of 2006 than if our gas price was not affected by derivative financial instruments. The average price realized for our oil increased from $68.63 per Bbl in the third quarter of 2006 to $70.75 per Bbl in the third quarter of 2007, which increased oil sales revenues by approximately $190,000.

The operating margin from oil and gas sales (oil and gas sales revenues less production expense and production taxes) on a per unit basis decreased from $7.64 per Mcfe in the third quarter of 2006 to $5.34 per Mcfe in the third quarter of 2007. The average price decreased $2.25 per Mcfe while production expense increased $0.06 per Mcfe and production taxes decreased $0.01 per Mcfe in the third quarter of 2007 compared to the third quarter of 2006.

Gas gathering and marketing revenues decreased from $2.5 million in the third quarter of 2006 to $2.3 million in the third quarter of 2007. The decrease was due to an $81,000 decrease in gas marketing revenues and a $59,000 decrease in gas gathering revenues as a result of lower average gas prices in the third quarter of 2007 compared to the third quarter of 2006.

Costs and Expenses

Production expense decreased from $6.2 million in the third quarter of 2006 to $6.0 million in the third quarter of 2007. The average production cost increased from $1.50 per Mcfe in the third quarter of 2006 to $1.56 per Mcfe in the third quarter of 2007. The increase in production expense on a per Mcfe basis was primarily due to the lower oil and gas sales volumes in the third quarter of 2007.

Production taxes decreased $95,000 from $589,000 in the third quarter of 2006 to $494,000 in the third quarter of 2007. Average per unit production taxes decreased from $0.14 per Mcfe in the third quarter of 2006 to $0.13 per Mcfe in the third quarter of 2007. The decreased production taxes were primarily due to lower oil and gas sales revenues in Michigan in the third quarter of 2007 compared to the third quarter of 2006. In Michigan, production taxes are based on a percentage of revenues, excluding the effects of hedging.

Exploration expense increased $116,000 from $148,000 in the third quarter of 2006 to $264,000 in the third quarter of 2007. This increase in exploration expense is primarily due to seismic expenses and the non-cash write off of costs related to undeveloped leases that expired in the quarter.

General and administrative expense decreased $643,000 from $2.3 million in the third quarter of 2006 to $1.7 million in the third quarter of 2007 primarily due to costs recorded in the third quarter of 2006 associated with the transition of accounting and administrative functions to EnerVest’s Charleston, West Virginia office.

Depreciation, depletion and amortization decreased by $1.0 million from $10.2 million in the third quarter of 2006 to $9.2 million in the third quarter of 2007 due to a decrease in depletion expense. Depletion per Mcfe decreased from $2.42 per Mcfe in the third quarter of 2006 to $2.35 per Mcfe in the third quarter of 2007. Depletion in the third quarter of 2007 was based on reserves as of June 30, 2007 which were relatively higher primarily due to higher natural gas prices as compared to reserves as of June 30, 2006.

Derivative fair value (gain) loss was a gain of $43.2 million in the third quarter of 2006 compared to a gain of $8.7 million in the third quarter of 2007. The derivative fair value (gain) loss reflects the changes in fair value of certain derivative instruments that are not designated or do not qualify as cash flow hedges and the ineffective portion of natural gas swaps through June 30, 2006.

Interest expense was $6.1 million in the third quarter of 2006 and $6.0 million in the third quarter 2007. The decrease is primarily due to lower blended interest rates in the third quarter of 2007 which were partially offset by higher outstanding borrowings.

Income tax expense was $5.0 million in the third quarter of 2007 compared to expense of $22.4 million in the third quarter of 2006. The decrease is primarily due to a decrease in income before income taxes.

Results of Operations — Nine Months of 2007 and 2006 Compared
Revenues

Operating revenues decreased from $124.7 million in the first nine months of 2006 to $94.3 million in the first nine months of 2007. The decrease in operating revenues was due to lower oil and gas sales revenues of $29.8 million.

Gas volumes sold were 10.0 Bcf in the first nine months of 2007, which was a decrease of 563 Mmcf (5%) compared to the first nine months of 2006. This decrease in gas volumes sold resulted in a decrease in gas sales revenues of approximately $5.2 million. Oil volumes sold decreased approximately 13,000 Bbls (5%) from 285,000 Bbls in the first nine months of 2006 to 272,000 Bbls in the first nine months of 2007 resulting in a decrease in oil sales revenues of approximately $840,000. The decrease in oil and gas sales volumes was primarily due to normal production declines, a lower level of drilling activity in 2007, a gas purchaser curtailment in the third quarter of 2007 for pipeline repairs in Pennsylvania and a gas curtailment in Michigan due to a carbon dioxide processing plant being off-line during the third quarter of 2007. These decreases were partially offset by production from new wells drilled in 2006 and 2007.

The average price realized for our natural gas decreased $2.31 per Mcf from $9.17 in the first nine months of 2006 to $6.86 per Mcf in the first nine months of 2007, which decreased gas sales revenues by approximately $23.2 million. As a result of our qualified effective hedging activities, gas sales revenues were lower by $4.2 million ($0.42 per Mcf) in the first nine months of 2007 and higher by $16.4 million ($1.54 per Mcf) in the first nine months of 2006 than if our gas price was not affected by derivative financial instruments. The average price realized for our oil decreased from $64.76 per Bbl in the first nine months of 2006 to $62.39 per Bbl in the first nine months of 2007, which decreased oil sales revenues by approximately $650,000.

The operating margin from oil and gas sales on a per unit basis decreased from $7.86 per Mcfe in the first nine months of 2006 to $5.66 per Mcfe in the first nine months of 2007. The average price decreased $2.03 per Mcfe and production expense increased $0.18 per Mcfe while production taxes decreased $0.01 per Mcfe in the first nine months of 2007 compared to the first nine months of 2006.

Gas gathering and marketing revenues decreased from $8.5 million in the first nine months of 2006 to $7.7 million in the first nine months of 2007 due to a $528,000 decrease in gas marketing revenues and a $222,000 decrease in gas gathering revenues as a result of lower average gas prices in the first nine months of 2007 compared to the first nine months of 2006.

Costs and Expenses

Production expense increased from $17.0 million in the first nine months of 2006 to $18.3 million in the first nine months of 2007. The average production cost increased from $1.38 per Mcfe in the first nine months of 2006 to $1.56 per Mcfe in the first nine months of 2007. The increase in production expense was primarily due to higher fuel costs, increases in labor and oilfield services costs and increased workover expense in the first nine months of 2007 due to limited service rig availability in the second quarter of 2006.

Production taxes decreased $190,000 from $1.9 million in the first nine months of 2006 to $1.7 million in the first nine months of 2007. Average per unit production taxes decreased from $0.15 per Mcfe in the first nine months of 2006 to $0.14 per Mcfe in the first nine months of 2007. The decreased production taxes are primarily due to lower oil and gas prices in the first nine months of 2007 in Michigan, where production taxes are based on a percentage of revenues, excluding the effects of hedging.

Exploration expense increased $595,000 from $697,000 in the first nine months of 2006 to $1.3 million in the first nine months of 2007. This increase in exploration expense is primarily due to the non-cash write off of costs related to undeveloped leases that expired in the first nine months of 2007.

General and administrative expense decreased $2.3 million from $7.8 million in the first nine months of 2006 to $5.5 million in the first nine months of 2007 primarily due to expenses related to the Transaction recorded in the first nine months of 2006. During the first nine months of 2006, we expensed approximately $1.0 million 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.

Depreciation, depletion and amortization decreased by $1.5 million from $28.7 million in the first nine months of 2006 to $27.2 million in the first nine months of 2007. This decrease was primarily due to a $1.4 million decrease in depletion expense due to the lower oil and gas sales volumes. Depletion per Mcfe was $2.30 per Mcfe in the first nine months of 2006 and 2007.

Derivative fair value (gain) loss was a gain of $29.8 million in the first nine months of 2006 compared to a loss of $37.4 million in the first nine months of 2007. The derivative fair value (gain) loss reflects the changes in fair value of certain derivative instruments that are not designated or do not qualify as cash flow hedges and the ineffective portion of natural gas swaps through June 30, 2006.

Interest expense increased $167,000 from $17.7 million in the first nine months of 2006 to $17.8 million in the first nine months of 2007. This increase in interest expense was due to higher outstanding borrowings.

Income tax expense was a benefit of $8.7 million for the first nine months of 2007 compared to an expense $29.0 million for the first nine months of 2006. The decrease is primarily related to a decrease in income before taxes.

Liquidity and Capital Resources

Cash Flows

The primary sources of cash in the nine month period ended September 30, 2007 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 $51.2 million during the first nine months of 2007 compared to $51.7 million in the first nine months of 2006. The decrease was primarily due to a decrease in cash received for oil and gas revenues (net of hedging) offset by changes in working capital items of $7.4 million.

Our investing activities used cash flows of $17.6 million during the first nine months of 2007 compared to $24.0 million in the first nine months of 2006. The decrease is due to a decrease in capital expenditures of $12.9 million offset by lower cash received for property and equipment disposals of $6.6 million.

Cash flows used in financing activities decreased $4.8 million in the first nine months of 2007 primarily due to a decrease of $7.5 million in dividends paid. In addition, we also had lower derivative settlements of $2.2 million and this was offset by a decrease in net borrowings of $4.9 million.

Our current ratio at September 30, 2007 was 0.75 to 1. During the first nine months of 2007, working capital decreased $3.3 million from a deficit of $11.6 million at December 31, 2006 to a deficit of $14.9 million at September 30, 2007. The decrease in working capital was primarily due to an increase of $10.7 million in the current liability related to the fair value of derivatives, a decrease in accounts receivable of $4.9 million, which were partially offset by a $7.6 million increase in cash and a $2.5 million increase in the current deferred tax asset and a decrease of $2.6 million in accrued expenses and accounts payable.

Capital Expenditures

During the first nine months of 2007, we spent approximately $17.7 million on our drilling activities and other capital expenditures. In the first nine months of 2007, we drilled 76 gross (74.5 net) development wells, all of which were successfully completed as producing wells in the target formation.

We currently expect to spend approximately $23 million during 2007 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 September 30, 2007, we had cash of $13.5 million and approximately $12.6 million available under our revolving facility. The level of our future cash flow will depend on a number of factors including the demand for and price levels of oil and gas, the scope and success of our drilling activities. There can be no assurance that the future drilling of our proved undeveloped locations will provide adequate liquidity in the future.

Financing and Credit Facilities

At September 30, 2007, we had an Amended Credit Agreement comprised of a five-year $350 million revolving facility with a base of $113.4 million, of which $99.9 million was outstanding at September 30, 2007. This facility is for working capital requirements and general corporate purposes, including the issuance of letters of credit; and a five year $40 million letter of credit facility that may be used only to provide credit support for our obligations under the hedge agreement and other hedge transactions. Borrowings under the Amended Credit Agreement bear interest (i) at the greater of the prime rate or an adjusted federal funds rate, plus an applicable margin ranging from 0% to 0.625% based on the aggregate principal amount outstanding under the Amended Credit Agreement, or, (ii) at our option, the Eurodollar base rate plus an applicable margin ranging from 1.125% to 2.125% based on the aggregate principal amount outstanding under the Amended Credit Agreement. The full amount borrowed under the Amended Credit Agreement will mature on August 16, 2010.

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

secured by a pledge of 100% of our capital stock held by Capital C, our parent.

The Amended Credit Agreement contains covenants that will limit our ability to, among other things, incur or guarantee additional indebtedness; create liens; pay dividends on or repurchase stock; pay principal and interest on certain subordinated debt; make certain types of investments; sell assets or merge with another entity; pledge or otherwise encumber our capital stock; or enter into transactions with affiliates. The Amended Credit Agreement also requires compliance with customary financial covenants, including a minimum interest coverage ratio, a maximum leverage ratio and a minimum current ratio. On August 3, 2007, our bank amended the Amended Credit Agreement to increase the maximum Leverage Ratio from 4.0 to 1.0 to 4.25 to 1.0 for the quarters ending on September 30, 2007 and December 31, 2007.

At September 30, 2007, the interest rate under our base rate option was 8.125%. Under our one-month LIBOR option, the rate was 7.635% for $6.5 million and 7.015% for $89.2 million. At September 30, 2007, we had $40.9 million of outstanding letters of credit. At September 30, 2007, there was $99.9 million outstanding under the revolving credit agreement. We had $12.6 million of borrowing capacity under our revolving facility available for general corporate purposes.

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

New Accounting Standards

In July 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement 109” (“FIN 48”), which clarifies the accounting for uncertainty in tax positions taken or expected to be taken in a tax return, including issues relating to financial statement recognition and measurement. FIN 48 provides that the tax effects from an uncertain tax position can be recognized in the financial statements only if the position is “more-likely-than-not” to be sustained if the position were to be challenged by a taxing authority. The assessment of the tax position is based solely on the technical merits of the position, without regard to the likelihood that the tax position may be challenged. If an uncertain tax position meets the “more-likely-than-not” threshold, the largest amount of tax benefit that is more than 50 percent likely to be recognized upon ultimate settlement with the taxing authority is recorded. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. Consistent with the requirements of FIN 48, we adopted FIN 48 on January 1, 2007. The adoption of FIN 48 did not have a material impact on our financial statements.

Since we have no unrecognized tax benefits as of September 30, 2007, there is no potential impact on our effective tax rate.

To the extent penalties and interest would be assessed on any underpayment of income tax, such amounts have been accrued and classified as a component of income tax expense in the financial

statements. This is an accounting policy election made by us that is a continuation of our historical policy and will continue to be consistently applied in the future. As of September 30, 2007, we have not accrued any interest and penalties related to unrecognized tax benefits.

We do not anticipate a significant change in the balance of unrecognized tax benefits within the next 12 months.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements, to provide guidance for using fair value to measure assets and liabilities. SFAS No. 157 establishes a fair value hierarchy and clarifies the principle that fair value should be based on assumptions market participants would use when pricing the asset or liability. SFAS No. 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We will adopt SFAS No. 157 on January 1, 2008 and we have not yet determined the impact, if any, on our financial statements.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

The interest rate risk relates to existing debt under our revolving facility as well as any new debt financing needed to fund capital requirements. We may manage our interest rate risk through the use of interest rate swaps to hedge the interest rate exposure associated with the credit agreement, whereby a portion of our floating rate exposure is exchanged for a fixed interest rate. A portion of our long-term debt consists of senior secured notes where the interest component is fixed. At September 30, 2007, we had interest rate swaps in place on $80 million of our outstanding debt under the revolving credit facility through September 16, 2008. The swaps provide a 1-month LIBOR fixed rates at 4.285% on $40 million and 5.160% on $40 million, plus the applicable margin. The fair value of these interest rate swaps was an asset of $3,000 at September 30, 2007. If market interest rates for short-term borrowings increased 1%, the increase in interest expense in the quarter would be approximately $50,000. This sensitivity analysis is based on our financial structure at September 30, 2007.

The commodity price risk relates to natural gas and crude oil produced, held in storage and marketed. Our financial results can be significantly impacted as commodity prices fluctuate widely in response to changing market forces. From time to time, we may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage our exposure to commodity price volatility. We employ a policy of partially hedging oil and gas production selling NYMEX-based commodity derivative contracts which are placed with major financial institutions that we believe are minimal credit risks. The contracts may take the form of futures contracts, swaps or options. At September 30, 2007, we had derivatives covering a portion of our oil and gas production from 2007 through 2013. Our oil and gas sales revenues included a net pre-tax gain of $16.4 million in the first nine months of 2006 and a net pre-tax loss of $4.2 million in the first nine months of 2007 on our qualified hedging activities.

We determined that as of August 15, 2005, our oil derivatives no longer qualify for cash flow hedge accounting and as of July 1, 2006, our gas derivatives no longer qualify for cash flow hedge accounting. From those dates forward, changes in the fair value of the oil and gas derivatives are recorded in derivative fair value gain/loss. Deferred gains or losses on the gas derivatives are recognized as increases or decreases to gas sales revenues during the same periods in which the underlying forecasted transactions impact earnings. If gas prices decreased $0.75 per Mcf, our gas sales revenues for the quarter would have decreased by approximately $2.5 million. If the price of crude oil decreased $7.00 per Bbl, our oil sales revenues for the quarter would have decreased by approximately $634,000. The impact of these price decreases on our cash flows would be significantly less than these amounts due to our oil and gas derivatives. Price decreases of $0.75 per Mcf and $7.00 per Bbl would have decreased cash flows from the sale of oil and gas for the quarter by approximately $705,000 after considering the effects of the derivative contracts in place as of September 30, 2007. This sensitivity analysis is based on our first nine months 2007 oil and gas sales volumes.

The following table reflects the natural gas and crude oil volumes and the weighted average prices under financial hedges (including settled hedges) at October 31, 2007:


	Natural Gas Swaps				Crude Oil Swaps
			NYMEX Price per				NYMEX Price per
	Bbtu		Mmbtu		Mbbls		Bbl
Quarter Ending
December 31, 2007		2,686	$	4.91		56	$	30.44

Year Ending
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 Mbbls — Thousand barrels		Mmbtu — Million British thermal units Bbtu — Billion British thermal units

The fair value of our oil and gas swaps was a net liability of approximately $204.2 million as of September 30, 2007.

At September 30, 2007, we had interest rate swaps in place on $80 million of our outstanding debt under the revolving credit facility through September 16, 2008. The swaps provide a 1-month LIBOR fixed rates at 4.285% on $40 million and 5.160% on $40 million, plus the applicable margin. At September 30, 2007, the fair value of the interest rate swaps represented a net unrealized gain of approximately $3,000.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We have established and maintain a system of disclosure controls and procedures to provide reasonable assurances that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Based on the evaluation of our disclosure controls and procedures as of the end of the period covered by this report, the principal executive officer and principal financial officer of Belden & Blake Corporation have concluded that our disclosure controls and procedures as of September 30, 2007 were effective, at a reasonable assurance level, in ensuring that the information required to be disclosed by us in reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.

Change in Internal Controls Over Financial Reporting

There have not been any changes in our internal controls over financial reporting that occurred during the quarterly period ended September 30, 2007 that materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

As of the date of this filing, there have been no changes from the risk factors previously disclosed in our “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2006.

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

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

None.

Item 3. Defaults upon Senior Securities

None.

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

None.

Item 5. Other Information

None.



	BELDEN & BLAKE CORPORATION

Date: November 14, 2007	By:	/s/ Mark A. Houser

		Mark A. Houser, Chief Executive Officer, Chairman of the Board of Directors and Director

Date: November 14, 2007	By:	/s/ James M. Vanderhinder

		James M. Vanderhider, President, Chief Financial Officer and Director (Principal Financial Officer)



Date: November 14, 2007	By:	/s/ Mark A. Houser

		Mark A. Houser, Chief Executive Officer, Chairman
		of the Board of Directors and Director



Date: November 14, 2007	By:	/s/ James M. Vanderhider

		James M. Vanderhider, President, Chief
		Financial Officer and Director



Date: November 14, 2007	By:	/s/ Mark A. Houser

		Mark A. Houser, Chief Executive Officer, Chairman
		of the Board of Directors and Director



Date: November 14, 2007	By:	/s/ James M. Vanderhider

		James M. Vanderhider, President and Chief
		Financial Officer

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	Page
PART I Financial Information

Item 1. Financial Statements (unaudited)

Balance Sheets as of September 30, 2007 and December 31, 2006		1

Statements of Operations: Three and nine months ended September 30, 2007 and September 30, 2006		2

Statements of Cash Flows: Nine months ended September 30, 2007 and September 30, 2006		3

Notes to Financial Statements		4

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk		15

Item 4. Controls and Procedures		17

PART II Other Information

Item 1. Legal Proceedings		17

Item 1A. Risk Factors		17

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

Item 3. Defaults Upon Senior Securities		17

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

Item 5. Other Information		17

Item 6. Exhibits		18

Signatures		19
EX-31.1
EX-31.2
EX-32.1
EX-32.2


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.

	1.		The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

	2.		The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


		(a) Exhibits


*		Filed herewith.