Belden & Blake 10Q 2008 Q3 Quarterly report

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, 2008


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

For the transition period from to

Commission File Number: 0-20100

BELDEN & BLAKE CORPORATION

(Exact name of registrant as specified in its charter)


Ohio		34-1686642

(State or other jurisdiction of		(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 Yeso No

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


Large accelerated filero		Accelerated filero		Non-accelerated filerþ		Smaller reporting companyo

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 October 31, 2008, 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)

Balance Sheets as of September 30, 2008 and December 31, 2007		1

Statements of Operations: Three and nine months ended September 30, 2008 and 2007		2

Statements of Cash Flows: Nine months ended September 30, 2008 and 2007		3

Notes to Financial Statements (unaudited)		4

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk		19

Item 4. Controls and Procedures		20

PART II Other Information

Item 1. Legal Proceedings		20

Item 1A. Risk Factors		20

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		21

Item 3. Defaults Upon Senior Securities		21

Item 4. Submission of Matters to a Vote of Security Holders		21

Item 5. Other Information		21

Item 6. Exhibits		21

Signatures		22

Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

BELDEN & BLAKE CORPORATION

BALANCE SHEETS
(unaudited, in thousands, except number of shares)


	September 30,			December 31,
	2008			2007

ASSETS
Current assets
Cash and cash equivalents	$	24,439		$	16,014
Accounts receivable (less accumulated provision for doubtful accounts: September 30, 2008 — $526; December 31, 2007 — $806)		20,649			18,071
Inventories		979			1,084
Deferred income taxes		16,201			17,282
Other current assets		113			370
Fair value of derivatives		12			37

Total current assets		62,393			52,858

Property and equipment, at cost
Oil and gas properties (successful efforts method)		729,358			713,912
Gas gathering systems		1,351			1,308
Land, buildings, machinery and equipment		2,832			2,761

		733,541			717,981
Less accumulated depreciation, depletion and amortization		114,446			88,549

Property and equipment, net		619,095			629,432
Goodwill		90,076			90,076
Fair value of derivatives		85			29
Other assets		1,435			1,830

	$	773,084		$	774,225


LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Accounts payable	$	2,829		$	1,148
Accounts payable — related party		667			1,508
Accrued expenses		21,346			20,363
Current portion of long-term liabilities		341			367
Fair value of derivatives		40,976			43,696

Total current liabilities		66,159			67,082

Long-term liabilities
Bank and other long-term debt		99,940			99,947
Senior secured notes		163,543			164,240
Subordinated promissory note — related party		26,946			26,931
Asset retirement obligations and other long-term liabilities		23,129			22,164
Fair value of derivatives		153,997			192,661
Deferred income taxes		114,410			98,977

Total long-term liabilities		581,965			604,920

Shareholder’s equity
Common stock: without par value; 3,000 shares authorized and 1,534 shares issued		—			—
Paid in capital		122,500			125,000
Retained earnings/deficit		17,354			(3,810	)
Accumulated other comprehensive loss		(14,894	)		(18,967	)

Total shareholder’s equity		124,960			102,223

	$	773,084		$	774,225

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, 2008			September 30, 2007			September 30, 2008			September 30, 2007
Revenues
Oil and gas sales	$	41,765		$	27,086		$	119,691		$	85,915
Gas gathering and marketing		3,571			2,334			9,949			7,728
Other		127			(139	)		432			308

		45,463			29,281			130,072			93,951

Expenses
Production expense		6,565			5,994			19,543			18,253
Production taxes		895			494			2,491			1,687
Gas gathering and marketing		2,819			1,957			8,221			6,431
Exploration expense		1,614			264			2,173			1,292
Impairment of oil and gas properties		—			—			2,011			—
General and administrative expense		2,225			1,675			6,240			5,535
Depreciation, depletion and amortization		8,517			9,156			25,876			27,169
Accretion expense		359			328			1,047			958
Derivative fair value (gain) loss		(134,829	)		(8,695	)		10,397			37,446

		(111,835	)		11,173			77,999			98,771

Operating income (loss)		157,298			18,108			52,073			(4,820	)

Other expense (income)
Interest expense		5,753			6,002			17,411			17,837
Other income, net		(119	)		(149	)		(349	)		(364	)

Income (loss) before income taxes		151,664			12,255			35,011			(22,293	)
Provision (benefit) for income taxes		59,959			4,987			13,847			(8,677	)

Net income (loss)	$	91,705		$	7,268		$	21,164		$	(13,616	)

See accompanying notes.

BELDEN & BLAKE CORPORATION

STATEMENTS OF CASH FLOWS
(unaudited, in thousands)


	Nine months ended			Nine months ended
	September 30, 2008			September 30, 2007
Cash flows from operating activities:
Net income (loss)	$	21,164		$	(13,616	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		25,876			27,169
Accretion expense		1,047			958
Gain on disposal of property and equipment		—			(57	)
Amortization of derivatives and other non-cash hedging activities		16,685			41,652
Exploration expense		1,788			571
Deferred income taxes		13,847			(8,854	)
Impairment of oil and gas properties		2,011			—
Other non-cash items		21			1,665
Change in operating assets and liabilities
Accounts receivable and other current assets		(2,321	)		5,000
Inventories		127			6
Accounts payable and accrued expenses		(569	)		(3,326	)

Net cash provided by operating activities		79,676			51,168

Cash flows from investing activities:
Additions to property and equipment		(18,722	)		(17,265	)
Proceeds from property and equipment disposals		3,049			270
Exploration expense		(1,788	)		(571	)
Decrease (increase) in other assets		77			(44	)

Net cash used in investing activities		(17,384	)		(17,610	)

Cash flows from financing activities:
Proceeds from revolving line of credit		—			6,500
Repayment of revolving credit line		—			(2,000	)
Repayment of long-term debt and other obligations		(7	)		(22	)
Settlement of derivative liabilities recorded in purchase accounting		(51,360	)		(20,723	)
Dividends paid		(2,500	)		(9,750	)

Net cash used in financing activities		(53,867	)		(25,995	)


Net increase in cash and cash equivalents		8,425			7,563
Cash and cash equivalents at beginning of period		16,014			5,927

Cash and cash equivalents at end of period	$	24,439		$	13,490

See accompanying notes.

BELDEN & BLAKE CORPORATION

NOTES TO FINANCIAL STATEMENTS
(unaudited)

September 30, 2008

(1) Basis of Presentation

Unless the context requires otherwise or unless otherwise noted, when we use the terms “Belden & Blake,” “we,” “us,” “our” or the “Company,” we are referring to Belden & Blake Corporation. On August 16, 2005, the former partners of our direct parent, 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, 2008 are not necessarily indicative of the results that may be expected for the year ended December 31, 2008. For further information, refer to the financial statements and footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2007. Certain reclassifications have been made to previously reported amounts in order to conform to current year presentation. Such reclassifications do not effect earnings. Interest income is reported in “Other income, net” in the Statements of Operations. For the three and nine months ended September 30, 2007 “Other income, net” has been adjusted to include $149,000 and $364,000, respectively, of interest income to conform with current year presentation. These amounts were previously recorded as “Other” revenue in our Statements of Operations. This reclassification had no material impact on total operating revenue, operating income or net income for the three and nine months ended September 30, 2007.

(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. Our derivative financial instruments take the form of swaps or collars. At September 30, 2008, our derivative contracts were comprised of natural gas swaps, natural gas basis differential swaps, crude oil swaps and interest rate swaps, which were placed with major financial institutions. 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 statements of operations as derivative fair value loss.

During the first nine months of 2008 and 2007, net losses of $7.4 million ($4.5 million after tax) and $3.9 million ($2.5 million after tax), respectively, were reclassified from accumulated other comprehensive income to earnings. At September 30, 2008, the estimated net loss in accumulated other comprehensive income that is expected to be reclassified into earnings within the next 12 months is approximately $5.3 million. At September 30, 2008, we have partially hedged our exposure to the variability in future cash flows through December 2013.

The following table reflects the natural gas and crude oil volumes and the weighted average prices under financial hedges (including settled hedges) at September 30, 2008:


	Natural Gas Swaps				Crude Oil Swaps				Natural Gas Basis Swaps
			NYMEX				NYMEX
			Price per				Price per				Basis
	Bbtu		Mmbtu		Mbbls		Bbl		Bbtu		Differential
Quarter Ending
December 31, 2008		2,532		4.59		52		29.68		—		—

		2,532	$	4.59		52	$	29.68		—	$	—

Year Ending
December 31, 2009		9,529		4.43		191		29.34		3,650		0.345
December 31, 2010		8,938		4.28		175		28.86		3,650		0.325
December 31, 2011		8,231		4.19		157		28.77		3,285		0.325
December 31, 2012		7,005		4.09		138		28.70		—		—
December 31, 2013		6,528		4.04		127		28.70		—		—

At September 30, 2008, we had an interest rate swap in place for $80 million of our outstanding debt under our revolving credit facility that matures on September 30, 2010. The swap provides a 1-month LIBOR fixed rate at 4.07% on $80 million from September 2008 through September 2010, plus the applicable margin. The fair value of this interest rate swap was an unrealized loss of $902,000 at September 30, 2008.

(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 ended			Nine months ended
(in thousands)	September 30, 2008			September 30, 2007
Cash paid during the period for:
Interest	$	21,372		$	15,951
Income taxes		—			177
Non-cash investing and financing activities:
Non-cash additions to property and equipment		2,392			1,206
Non-cash additions to debt		(15	)		(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 other comprehensive income. The table below summarizes comprehensive income and provides the components of the change in accumulated other comprehensive income (loss) for the nine-month periods ended September 30, 2008 and 2007.


	Nine months ended			Nine months ended
	September 30, 2008			September 30, 2007
Comprehensive income (loss):
Net income (loss)	$	21,164		$	(13,616	)
Other comprehensive income (loss), net of tax:
Unrealized gain in derivative fair value		409			289
Reclassification adjustment for derivative (loss) gain reclassified into earnings		(4,482	)		(2,532	)

Change in accumulated other comprehensive income (loss)		(4,073	)		(2,243	)

	$	17,091		$	(15,859	)

(7) Related Party Transactions

We have a joint operating agreement with EnerVest Operating LLC (“EnerVest Operating”). In the first nine months of 2008, we recorded costs of approximately $4.9 million (as general and administrative expense) for operating overhead fees, $5.1 million (as production expense) for field labor, vehicles and district office expense, $194,000 (capitalized) for drilling overhead fees and $624,000 (capitalized) for drilling labor costs related to this agreement. We recorded costs of approximately $4.4 million for operating overhead fees, $5.6 million for field labor, vehicles and district office expense, $257,000 for drilling overhead fees and $780,000 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, 2008 was $26.9 million. In lieu of cash payments, we have the option to make interest payments on the note by borrowing additional amounts against the note. We made cash interest payments of $2.0 million in the first nine months of 2008 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.

(8) Impairment of Oil and Gas Properties

For the period ended September 30, 2008, we reviewed our oil and gas properties for impairment as prescribed by SFAS No.��144, Accounting for the Impairment or Disposal of Long-Lived Assets. As a result of this evaluation no impairment was recorded during the current quarter. We recorded an impairment of $2.0 million during the second quarter of 2008 to proved properties in the Utica Shale formation in Ohio.

(9) New Accounting Standards

In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, Fair Value Measurements, to provide guidance for using fair value to measure assets and liabilities. SFAS No. 157 was to be effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years; however, in February 2008, the FASB issued FASB Staff Position FAS 157-2, Effective Date of FASB Statement No. 157, which delayed the effective date of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis, for one year. We adopted SFAS No. 157 on January 1, 2008 for our financial assets and financial liabilities (see Note 10). We will adopt SFAS No. 157 on January 1, 2009 for our nonfinancial assets and nonfinancial liabilities, and we have not yet determined the impact, if any, on our consolidated financial statements.

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

In December 2007, the FASB issued SFAS No 141 (Revised 2007), Business Combinations (“SFAS No. 141(R)”) to significantly change the accounting for business combinations. Under SFAS No. 141(R), an acquiring entity will be required to recognize all the assets acquired and liabilities assumed in a transaction at the acquisition date fair value with limited exceptions and will change the accounting treatment for certain specific items, including:

• acquisition costs will generally be expensed as incurred;

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

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

SFAS No. 141(R) is effective for fiscal years beginning after December 15, 2008. We will adopt SFAS No. 141(R) on January 1, 2009, and we have not yet determined the impact, if any, on our consolidated financial statements.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — An Amendment of ARB No. 51, to establish new accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 requires the recognition of a noncontrolling interest (minority interest) as equity in the consolidated financial statements and separate from the parent’s equity. The amount of net income attributable to the noncontrolling interest will be included in consolidated net income on the face of the income statement. SFAS No. 160 clarifies that changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation are equity transactions if the parent retains its controlling financial interest. In addition, SFAS No. 160 requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated. SFAS No. 160 also includes expanded disclosure requirements regarding the interests of the parent and its noncontrolling interest. SFAS No. 160 is effective for fiscal years beginning after December 15, 2008. We will adopt SFAS No. 160 on January 1, 2009, and we have not yet determined the impact, if any, on our consolidated financial statements.

In March 2008, the FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133.SFAS No. 161 requires enhanced disclosures about an entity’s derivative and hedging activities and how they affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 is effective for fiscal years and interim periods beginning after November 15, 2008. We will adopt SFAS No. 161 on January 1, 2009, and we have not yet determined the impact, if any, on our consolidated financial statements.

In May 2008, the FASB issued SFAS No. 162,The Hierarchy of Generally Accepted Accounting Principles.SFAS No. 162 identifies the sources for accounting principles and the framework for selecting the principles to be used in preparing financial statements of nongovernmental entities that are presented in conformity with generally accepted accounting principles (GAAP) in the United States. SFAS No. 162 is effective 60 days following the Securities and Exchanges Commission’s approval of the Public Company Accounting Oversight Board Auditing amendments to AU Section 411,The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles.

(10) Fair Value Measurements

SFAS 157 establishes a valuation hierarchy for disclosure of the inputs to valuation used to measure fair value. This hierarchy prioritizes the inputs into the following three levels:

• Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.

• Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration.

• Level 3 inputs are unobservable inputs based on our own assumptions used to measure assets and liabilities at fair value.

A financial asset or liability’s classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement.

The following table presents the fair value hierarchy table for our assets and liabilities that are required to be measured at fair value on a recurring basis:

Fair Value Measurements at September 30, 2008 Using:

Quoted Prices in

Significant

Active Markets

Other

Significant

for Identical

Observable

Unobservable

Assets

Inputs

Total Carrying Value

(Level 1)

(Level 2)

(Level 3)

Derivative instruments

(194,876

)

—

(194,876

)

—

Our derivative instruments consist of over-the-counter (“OTC”) contracts which are not traded on a public exchange. These derivative instruments are indexed to active trading hubs for the underlying commodity, and are OTC contracts commonly used in the energy industry and offered by a number of financial institutions and large energy companies.

As the fair value of these derivative instruments is based on inputs using market prices obtained from independent brokers or determined using quantitative models that use as their basis readily observable market parameters that are actively quoted and can be validated through external sources, including third-party pricing services, brokers and market transactions, we have categorized these derivative instruments as Level 2.

(11) Asset Retirement Obligations

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


Balance as of December 31, 2007	$	22,264
Accretion expense		1,047
Liabilities incurred		174
Liabilities settled		(259	)
Revisions in estimated cash flows		43

Balance as of September 30, 2008	$	23,269

As of September 30, 2008 and December 31, 2007, $333,000 and $359,000, respectively, of our ARO is classified as current.

(12) Dividends

On July 31, 2008, the board of directors of the Company declared and paid a $2.5 million dividend to its stockholder of record on July 31, 2008.

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

Forward-Looking Information

The information in this document includes forward-looking statements that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Statements preceded by, followed by or that otherwise include the statements “should,” “believe,” “expect,” “anticipate,” “intend,” “continue,” “estimate,” “plan,” “outlook,” “may,” “future,” “projection,” “likely,” “possible,” “could” and variations of these statements and similar expressions are forward-looking statements as are any other statements relating to developments, events, occurrences, results, efforts or impacts. These forward-looking statements are based on current expectations and projections about future events. Forward-looking statements and the business prospects of Belden & Blake are subject to a number of risks and uncertainties which may cause our actual results in future periods to differ materially from the forward-looking statements contained herein. These risks and uncertainties include, but are not limited to, our access to capital, the market demand for and prices of oil and natural gas, the effect of the current turmoil in the financial markets our oil and gas production and costs of operation, results of our future drilling activities, the uncertainties of reserve estimates, general economic conditions, including the possibility of an economic recession in 2008 and 2009, new legislation or regulatory changes, changes in accounting principles, policies or guidelines and environmental risks. These and other risks are described in our Annual Report on Form 10-K for the year ended December 31, 2007, under the Heading “Risk Factors” and in our other filings with the Securities and Exchange Commission (“SEC”). We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, changes in assumptions, or otherwise.

Business Environment

We are an independent energy company engaged in the exploitation, development, production, operation and acquisition of oil and natural gas properties. Our operations are focused in the Appalachian Basin in Ohio, Pennsylvania and New York and in the Antrim Shale Formation in the Michigan Basin. Our results of operations, which will fluctuate from quarter to quarter based on, are dependent upon, among other things:

• the prices at which we will sell our oil and natural gas production;

• our hedges of our oil and gas production;

• the amount of oil and natural gas we produce; and

• the level of our operating and administrative costs.

Oil and natural gas prices have been, and are expected to be, volatile. Prices for oil and natural gas declined substantially during the three months ended September 30, 2008, and are expected to fluctuate widely in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of factors beyond our control. Factors affecting the price of oil include the lack of excess productive capacity, geopolitical activities, worldwide supply disruptions, worldwide economic conditions, weather conditions, actions taken by the Organization of Petroleum Exporting Countries and the value of the U.S. dollar in international currency markets. Factors affecting the price of natural gas include North American weather conditions, industrial and consumer demand for natural gas, storage levels of natural gas and the availability and accessibility of natural gas deposits in North America.

We are a party to derivative instruments which reduce the impact of oil and natural gas price volatility on our cash flows. As of September 30, 2008, we have entered into derivative instruments for 2009, 2010 and 2011 covering approximately 68%, 62% and 59%, respectively, of our total proved reserves. By removing a significant portion of our price volatility on our future oil and natural gas production, we have mitigated, but not eliminated, the potential effects of changing oil and natural gas prices on our cash flows from operations for those periods. If a global recession occurs, commodity prices may be depressed for an extended period of time, which could alter our drilling and exploration plans.

The primary factors affecting our production levels are the success of our drilling program and our inventory of drilling prospects. In addition, we face the challenge of natural production declines. As initial reservoir pressures are depleted, production from a given well decreases. We attempt to overcome this natural decline by drilling to find additional reserves. Our future growth will depend on our ability to continue to add reserves in excess of production. We will maintain our focus on costs to add reserves through drilling as well as the costs necessary to produce such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. Any delays in drilling, completion or connection to gathering lines of our new wells will negatively impact our production, which may have an adverse effect on our revenues and, as a result, cash available for distribution.

Higher oil and natural gas prices have led to higher demand for drilling rigs, operating personnel and field supplies and services, and have caused increases in the costs of these goods and services. We focus our efforts on increasing oil and natural gas reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future cash flows from operations are dependent on our ability to manage our overall cost structure.

The financial markets are undergoing unprecedented disruptions. Many financial institutions have liquidity concerns prompting intervention from governments. Our exposure to the disruptions in the financial markets includes our credit facilities, investments and hedge counterparty exposure.

Our revolving credit facility is committed until 2010. If the disruption in the financial markets continues for an extended period of time, replacement of our credit facility may be more expensive. In addition, the borrowing base under our credit facility is subject to periodic review by our lenders. Difficulties in the credit markets may cause the banks to be more restrictive when re-calculating our borrowing base.

Our cash investments, which total approximately $24 million are with financial institutions that are insured or are securities guaranteed by the federal government.

Our primary hedge counterparty is J. Aron & Co., a subsidiary of Goldman Sachs & Co. Our hedges are currently significantly below market prices for oil and natural gas. If commodity prices were to fall below the prices of our hedges, a default by J. Aron could adversely affect us.

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,
	2008		2007		2008		2007
Production
Gas (Mmcf)		3,308		3,310		9,902		10,042
Oil (Mbbls)		80		91		246		272
Total production (Mmcfe)		3,789		3,854		11,377		11,676

Average price (1)
Gas (per Mcf)	$	9.83	$	6.25	$	9.40	$	6.86
Oil (per Bbl)		115.10		70.75		108.19		62.39
Mcfe		11.02		7.03		10.52		7.36
Average costs (per Mcfe)
Production expense	$	1.73	$	1.56	$	1.72	$	1.56
Production taxes		0.24		0.13		0.22		0.14
Depletion		2.22		2.35		2.25		2.30


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


	Three months ended September 30,				Nine months ended September 30,
	2008		2007		2008		2007
Gas (per Mcf)	$	10.18	$	6.62	$	10.04	$	7.28
Oil (per Bbl)		115.10		70.75		108.19		62.39
Mcfe		11.33		7.35		11.08		7.72

Results of Operations — Third Quarters of 2008 and 2007 Compared

Revenues

Operating revenues increased from $29.3 million in the third quarter of 2007 to $45.5 million in the third quarter of 2008. The increase in operating revenues was primarily due to higher oil and gas sales revenues of $14.7 million. The increased oil and gas sales revenues were primarily due to an increase of $15.4 million related to increased prices for oil and natural gas, which was partially offset by a $749,000 decrease in revenues due to decreased production volumes.

Gas volumes sold were 3.3 Bcf in the third quarter of 2007 and 2008. Oil volumes sold decreased approximately 11,000 Bbls (11%) from 91,000 Bbls in the third quarter of 2007 to 80,000 Bbls in the third quarter of 2008 resulting in a decrease in oil sales revenues of approximately $735,000. The lower oil and gas sales volumes are primarily due to normal production declines which were partially offset by production from new wells drilled during 2007 and 2008.

The average price realized for our natural gas production increased $3.58 per Mcf from $6.25 in the third quarter of 2007 to $9.83 per Mcf in the third quarter of 2008, which increased gas sales revenues by approximately $11.9 million. As a result of our hedging activities, gas sales revenues were lower by $1.2 million ($0.35 per Mcf) in the third quarter of 2008 and lower by $1.2 million ($0.37 per Mcf) in the third quarter of 2007 than if our gas price was not affected by derivative financial instruments. The average price realized for our oil production increased from $70.75 per Bbl in the third quarter of 2007 to $115.10 per Bbl in the third quarter of 2008, which increased oil sales revenues by approximately $3.6 million.

Gas gathering and marketing revenues increased from $2.3 million in the third quarter of 2007 to $3.6 million in the third quarter of 2008. The increase was due to a $864,000 increase in gas marketing revenues and a $373,000 increase in gas gathering revenues as a result of higher average gas prices in the third quarter of 2008 compared to the third quarter of 2007.

Costs and Expenses

Production expense increased $571,000 from $6.0 million in the third quarter of 2007 to $6.6 million the third quarter of 2008. The average production cost increased from $1.56 per Mcfe in the third quarter of 2007 to $1.73 per Mcfe in the third quarter of 2008. The increase in production expense was primarily due to increases in gas processing fees and compression expense in Michigan. The increase in cost per Mcfe was due to cost increases and decreased production volumes.

Production taxes increased $401,000 from $494,000 in the third quarter of 2007 to $895,000 in the third quarter of 2008. Average per unit production taxes increased from $0.13 per Mcfe in the third quarter of 2007 to $0.24 per Mcfe in the third quarter of 2008. The increased production taxes were primarily due to higher oil and gas sales revenues in Michigan in the third quarter of 2008 compared to the third quarter of 2007. In Michigan, production taxes are based on a percentage of revenues, excluding the effects of hedging.

Gas gathering and marketing expenses increased from $2.0 million in the third quarter of 2007 to $2.8 million in the third quarter of 2008. The increase was primarily due to a $872,000 increase in gas marketing expenses as a result of higher average gas prices in the third quarter of 2008 compared to the third quarter of 2007.

Exploration expense increased $1.4 million from $264,000 in the third quarter of 2007 to $1.6 million in the third quarter of 2008. The increase in exploration expense is primarily due to an increase in dry hole expense, seismic expense and expired lease expense in the third quarter of 2008.

General and administrative expense increased $550,000 from $1.7 million in the third quarter of 2007 to $2.2 million in the third quarter of 2008 primarily due to an increase in franchise taxes, bad debt expense and operating overhead fees paid to EverVest .

Depreciation, depletion and amortization decreased by $639,000 from $9.2 million in the third quarter of 2007 to $8.5 million in the third quarter of 2008. This decrease was primarily due to a $635,000 decrease in depletion expense. Depletion per Mcfe decreased from $2.35 per Mcfe in the third quarter of 2007 to $2.22 per Mcfe in the third quarter of 2008 due primarily to increased reserves volumes due to higher oil and gas prices at June 30, 2008, the date of our mid-year reserve report.

Derivative fair value (gain) loss was a gain of $8.7 million in the third quarter of 2007 and a gain of $134.8 million in the third quarter of 2008. The derivative fair value (gain) loss reflects the changes in fair value of certain derivative instruments that are not designated or do not qualify as cash flow hedges.

Interest expense decreased $249,000 from $6.0 million in the third quarter of 2007 to $5.8 million in the third quarter of 2008. This decrease in interest expense was due to lower blended interest rates, which were partially offset by the amortization of the fair value adjustments from purchase accounting on the Senior Secured Notes.

Income tax expense was an expense of $60.0 million in the third quarter of 2008 compared to an expense of $5.0 million in the third quarter of 2007. The increase is primarily due to an increase in income before income taxes. The income taxes for 2008 and 2007 are all deferred.

Results of Operations — Nine Months of 2008 and 2007 Compared

Revenues

Operating revenues increased from $94.0 million in the first nine months of 2007 to $130.1 million in the first nine months of 2008. The increase in operating revenues was primarily due to higher oil and gas sales revenues of $33.8 million. The increased revenues were primarily due to an increase of $36.4 million related to increased prices for oil and natural gas, which was partially offset by a $2.6 million decrease in revenues due to decreased production volumes.

Gas volumes sold were 9.9 Bcf in the first nine months of 2008, which was a decrease of 141 Mmcf (1%) compared to the first nine months of 2007. This decrease in gas volumes sold resulted in a decrease in gas sales revenues of approximately $965,000. Oil volumes sold decreased approximately 26,000 Bbls (10%) from 272,000 Bbls in the first nine months of 2007 to 246,000 Bbls in the first nine months of 2008 resulting in a decrease in oil sales revenues of approximately $1.6 million. The decrease in oil and gas sales volumes was primarily due to normal production declines, which were partially offset by production from new wells drilled in 2007 and 2008.

The average price realized for our natural gas increased $2.54 per Mcf from $6.86 in the first nine months of 2007 to $9.40 per Mcf in the first nine months of 2008, which increased gas sales revenues by approximately $25.1 million. As a result of our hedging activities, gas sales revenues were lower by $6.3 million ($0.64 per Mcf) in the first nine months of 2008 and lower by $4.2 million ($0.42 per Mcf) in the first nine months of 2007 than if our gas price was not affected by derivative financial instruments. The average price realized for our oil production increased from $62.39 per Bbl in the first nine months of 2007 to $108.19 per Bbl in the first nine months of 2008, which increased oil sales revenues by approximately $11.3 million.

Gas gathering and marketing revenues increased from $7.7 million in the first nine months of 2007 to $9.9 million in the first nine months of 2008 due to a $1.7 million increase in gas marketing revenues and a $525,000 increase in gas gathering revenues as a result of higher average gas prices in the first nine months of 2008 compared to the first nine months of 2007.

Costs and Expenses

Production expense increased from $18.3 million in the first nine months of 2007 to $19.5 million in the first nine months of 2008. The average production cost increased from $1.56 per Mcfe in the first nine months of 2007 to $1.72 per Mcfe in the first nine months of 2008. The increase in production expense was primarily due to increases in gas processing fees and compression expense in Michigan along with higher oilfield service costs. The increase in cost per Mcfe was due to cost increases and decreased production volumes.

Production taxes increased $804,000 from $1.7 million in the first nine months of 2007 to $2.5 million in the first nine months of 2008. Average per unit production taxes increased from $0.14 per Mcfe in the first nine months of 2007 to $0.22 per Mcfe in the first nine months of 2008. The increased production taxes are primarily due to higher oil and gas prices in the first nine months of 2008 in Michigan, where production taxes are based on a percentage of revenues, excluding the effects of hedging.

Gas gathering and marketing expenses increased from $6.4 million in the first nine months of 2007 to $8.2 million in the first nine months of 2008, primarily due to a $1.7 million increase in gas marketing expenses as a result of higher average gas prices in the first nine months of 2008 compared to the first nine months of 2007.

Exploration expense increased $881,000 from $1.3 million in the first nine months of 2007 to $2.2 million in the first nine months of 2008. This increase in exploration expense is primarily due to an increase in dry hole expense and seismic expense.

Impairment of oil and gas properties was $2.0 million in the first nine months of 2008 due to the impairment of properties in the Utica Shale formation in Ohio. There was no impairment of oil and gas properties in the first nine months of 2007.

General and administrative expense increased from $5.5 million in the first nine months of 2007 to $6.2 million in the first nine months of 2008 primarily due to an increase in operating overhead fees paid to EnerVest and an increase in third party fees.

Depreciation, depletion and amortization decreased by $1.3 million from $27.2 million in the first nine months of 2007 to $25.9 million in the first nine months of 2008. This decrease was primarily due to a $1.3 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 2007 and $2.25 in the first nine months of 2008.

Derivative fair value (gain) loss was a loss of $37.4 million in the first nine months of 2007 compared to a loss of $10.4 million in the first nine months of 2008. The derivative fair value loss reflects the changes in fair value of certain derivative instruments that are not designated or do not qualify as cash flow hedges.

Interest expense decreased $426,000 from $17.8 million in the first nine months of 2007 to $17.4 million in the first nine months of 2008. This decrease in interest expense was due to lower blended interest rates, which were partially offset by the amortization of the fair value adjustments from purchase accounting on the Senior Secured Notes.

Income tax provision (benefit) increased from a benefit of $8.7 million for the first nine months of 2007 to an expense of $13.8 million for the first nine months of 2008. The increase is primarily related to an increase in income before taxes. The income taxes for 2008 and 2007 are all deferred.

Liquidity and Capital Resources

We have recently experienced unprecedented disruptions in the U.S. capital markets which, if they continue, are likely to have an adverse effect on our ability to finance our growth strategy. Please see “Risk Factors” contained in Part II, Item 1A herein.

If the disruption in the financial markets continues for an extended period of time, replacement of our Amended Credit Agreement may be more expensive. In addition, the borrowing base under our Amended Credit Agreement is subject to periodic review by our lenders. Difficulties in the credit markets may cause the banks to be more restrictive when redetermining our borrowing base.

Cash Flows

The primary sources of cash in the nine-month period ended September 30, 2008 have been funds generated from operations. Funds used during this period were primarily used for operations, development expenditures, derivative settlements and interest expense. Our liquidity and capital resources are closely related to and dependent upon the prices we receive for our oil and natural gas production.

Our operating activities provided cash flows of $79.7 million during the first nine months of 2008 compared to $51.2 million in the first nine months of 2007. The increase was primarily due to an increase in cash received for oil and gas sales (net of hedging) which was partially offset by a decrease in working capital items of $4.4 million.

Our investing activities used cash flows of $17.4 million during the first nine months of 2008 compared to $17.6 million used in the first nine months of 2007. The increase was due to an increase in capital expenditures of $1.5 million and an increase in exploration expense of $1.2 million which was offset by an increase in cash received for property and equipment disposals of $2.8 million.

Cash flows used in financing activities increased $27.9 million in the first nine months of 2008 primarily due to an increase of $30.6 million in derivative settlements and a decrease in net proceeds from the revolving line of credit of $4.5 million which was offset by a decrease in dividends paid of $7.3 million.

Our current ratio at September 30, 2008 was 0.94 to 1. During the first nine months of 2008, working capital increased $10.4 million from a deficit of $14.2 million at December 31, 2007 to a deficit of $3.8 million at September 30, 2008. The increase in working capital was primarily due to an increase in cash of $8.4 million, a decrease in the current liability related to the fair value of derivatives of $2.7 million and an increase in accounts receivable of $2.6 million, which were partially offset by a decrease in the current deferred tax asset of $1.1 million and an increase in accrued expenses of $1.0 million.

Capital Expenditures

During the first nine months of 2008, we spent approximately $21.1 million on our drilling activities and other capital expenditures. In the first nine months of 2008, we drilled 82 gross (68.0 net) development wells and 6 gross (6.0 net) exploratory wells. All of the development wells were completed as producing wells in the target formation. Two exploratory wells were completed as producing wells in the target formation. Four exploratory wells were classified as dry holes and well cost of approximately $619,000 was expensed.

We currently expect to spend approximately $27 million during 2008 on our drilling activities and other capital expenditures. Due to delays in obtaining drilling permits in Pennsylvania and recent declines in oil and natural gas prices, we have reduced our 2008 expenditures related to drilling and other capital projects by approximately $11 million. We intend to finance our planned capital expenditures through our cash on hand and available operating cash flow. At September 30, 2008, we had cash of $24.4 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 and 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, 2008, we had an Amended Credit Agreement comprised of a five-year $350 million revolving facility with a borrowing base of $113.4 million, of which $99.9 million was outstanding at September 30, 2008. This facility is for working capital requirements and general corporate purposes, including the issuance of letters of credit; and a five year $40 million letter of credit facility that may be used only to provide credit support for our obligations under the hedge agreement and other hedge transactions. Borrowings under the 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. As of September 30, 2008, we were in compliance with all financial covenants and requirements under the existing credit facilities.

At September 30, 2008, the interest rate under our base rate option was 5.375%. Under our one-month LIBOR option, the rate was 5.585%. At September 30, 2008, we had $40.9 million of outstanding letters of credit. At September 30, 2008, there was $99.9 million outstanding under the revolving credit agreement. We had $12.6 million of borrowing capacity under our revolving facility available for general corporate purposes.

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 September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, Fair Value Measurements, to provide guidance for using fair value to measure assets and liabilities. SFAS No. 157 was to be effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years; however, in February 2008, the FASB issued FASB Staff Position FAS 157-2, Effective Date of FASB Statement No. 157, which delayed the effective date of SFAS No. 157 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis, for one year. We adopted SFAS No. 157 on January 1, 2008 for our financial assets and financial liabilities. We will adopt SFAS No. 157 on January 1, 2009 for our nonfinancial assets and nonfinancial liabilities, and we have not yet determined the impact, if any, on our consolidated financial statements.

• acquisition costs will generally be expensed as incurred;

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

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

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, 2008, we had an interest rate swap in place covering $80 million of our outstanding balance on the revolving credit agreement. The fair value of this interest rate swap was an unrealized loss of $902,000 at September 30, 2008. If market interest rates for short-term borrowings increased 1%, the increase in interest expense in the first nine months of 2008 would be approximately $149,000. This sensitivity analysis is based on our financial structure at September 30, 2008.

The commodity price risk relates to natural gas and crude oil produced, held in storage and marketed. Our financial results can be significantly impacted as commodity prices fluctuate widely in response to changing market forces. From time to time, we may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage our exposure to commodity price volatility. We employ a policy of partially hedging oil and gas production selling NYMEX-based commodity derivative contracts which are placed with major financial institutions that we believe are minimal credit risks. The contracts may take the form of futures contracts, swaps or options. At September 30, 2008, we had derivatives covering a portion of our oil and gas production from 2008 through 2013. Our oil and gas sales revenues included a net pre-tax loss of $4.2 million in the first nine months of 2007 and a net pre-tax loss of $6.3 million in the first nine months of 2008 on our qualified hedging activities.

Our oil and gas derivatives no longer qualify for cash flow hedge accounting. Therefore, changes in the fair value of the oil and gas derivatives are recorded in derivative fair value gain/loss. Deferred gains or losses on the gas derivatives are recognized as increases or decreases to gas sales revenues during the same periods in which the underlying forecasted transactions impact earnings. If gas prices decreased $1.00 per Mcf, our gas sales revenues for the first nine months of 2008 would decrease by approximately $9.9 million. If the price of crude oil decreased $10.00 per Bbl, our oil sales revenues for the first nine months of 2008 would decrease by approximately $2.5 million. The impact of these price decreases on our cash flows would be significantly less than these amounts due to our oil and gas derivatives. Price decreases of $1.00 per Mcf and $10.00 per Bbl would decrease cash flows from the sale of oil and gas for the first nine months of 2008 by approximately $3.2 million after considering the effects of the derivative contracts in place as of September 30, 2008. This sensitivity analysis is based on our first nine months 2008 oil and gas sales volumes.

The following table reflects the natural gas and crude oil volumes and the weighted average prices under financial hedges (including settled hedges) at October 31, 2008, which has not changed since September 30, 2008:


	Natural Gas Swaps				Crude Oil Swaps				Natural Gas Basis Swaps
			NYMEX
			Price per				NYMEX				Basis
	Bbtu		Mmbtu		Mbbls		Price per Bbl		Bbtu		Differential
Quarter Ending
December 31, 2008		2,532		4.59		52		29.68		—		—

		2,532	$	4.59		52	$	29.68		—	$	—

Year Ending
December 31, 2009		9,529		4.43		191		29.34		3,650		0.345
December 31, 2010		8,938		4.28		175		28.86		3,650		0.325
December 31, 2011		8,231		4.19		157		28.77		3,285		0.325
December 31, 2012		7,005		4.09		138		28.70		—		—
December 31, 2013		6,528		4.04		127		28.70		—		—

The fair value of our oil and gas swaps was a net liability of approximately $194.0 million as of September 30, 2008.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We have established and maintain a system of disclosure controls and procedures to provide reasonable assurances that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Based on the evaluation of our disclosure controls and procedures as of the end of the period covered by this report, the principal executive officer and principal financial officer of Belden & Blake Corporation have concluded that our disclosure controls and procedures as of September 30, 2008 were effective, at a reasonable assurance level, in ensuring that the information required to be disclosed by us in reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.

Change in Internal Controls Over Financial Reporting

There have not been any changes in our internal controls over financial reporting that occurred during the quarterly period ended September 30, 2008 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, we continue to be subject to the risk factors previously disclosed in our “Risk Factors” in the 2007 Annual Report on Form 10-K, as well as the following risk factor:

Oil and natural gas prices have recently declined substantially. If there is a sustained economic downturn or recession in the United States or globally, oil and natural gas prices may continue to fall and may become and remain depressed for a long period of time, which may adversely affect our results of operations.

Many economists are predicting that the United States will experience an economic downturn or a recession. The reduced economic activity associated with an economic downturn or recession may reduce the demand for, and so the prices we receive for, our oil and natural gas production. A sustained reduction in the prices we receive for our oil and natural gas production will have a material adverse effect on our results of operations. Because we have hedged the prices we will receive for a substantial portion of our oil and natural gas production through 2013, the effects on us of a decline in oil and natural gas prices over the near term will be mitigated.

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.

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.

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: November 13, 2008	By:	/s/ Mark A. Houser
		Mark A. Houser, Chief Executive Officer,
		Chairman of the Board of Directors and Director (Principal Executive Officer)

Date: November 13, 2008	By:	/s/ James M. Vanderhider
		James M. Vanderhider, President,
		Chief Financial Officer and Director (Principal Financial Officer)

EXHIBIT INDEX


Exhibit
No.			Description
	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.

Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	8th grade Good

Belden & Blake Inactive 10-Q2008 Q3 Quarterly report

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