Belden & Blake 10-Q 2010 Q2 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 June 30, 2010

or

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

For the transition period from                    to                    

Commission File Number: 0-20100

BELDEN & BLAKE CORPORATION

(Exact name of registrant as specified in its charter)

Ohio	34-1686642
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer 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.Yesþ Noo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).Yeso Noo

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 July 31, 2010, 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)
Condensed Consolidated Balance Sheets as of June 30, 2010 and December 31, 2009		1
Condensed Consolidated Statements of Operations: Three and six months ended June 30, 2010 and 2009		2
Condensed Consolidated Statements of Cash Flows: Six months ended June 30, 2010 and 2009		3
Notes to Condensed Consolidated Financial Statements		4
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		10
Item 3. Quantitative and Qualitative Disclosures About Market Risk		16
Item 4. Controls and Procedures		17
PART II Other Information
Item 1. Legal Proceedings		17
Item 1A. Risk Factors		18
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		18
Item 3. Defaults Upon Senior Securities		18
Item 4. (Removed and Reserved)		18
Item 5. Other Information		18
Item 6. Exhibits		18
Signatures		19
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

BELDEN & BLAKE CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited, in thousands, except share data)

	June 30,			December 31,
	2010			2009
ASSETS
Current assets
Cash and cash equivalents	$	80,807		$	46,740
Accounts receivable (less accumulated provision for doubtful accounts: June 30, 2010 — $583; December 31, 2009 — $393)		10,122			11,821
Inventories		821			828
Deferred income taxes		5,047			8,272
Assets held for sale		763			—
Other current assets		487			183
Derivative asset		668			413
Total current assets		98,715			68,257
Property and equipment, at cost
Oil and gas properties (successful efforts method)		683,354			684,787
Gas gathering systems		1,245			1,275
Land, buildings, machinery and equipment		2,421			2,566
		687,020			688,628
Less accumulated depreciation, depletion and amortization		165,604			151,208
Property and equipment, net		521,416			537,420
Long-term derivative asset		438			478
Other assets		1,500			1,923
	$	622,069		$	608,078
LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Accounts payable	$	1,331		$	1,696
Accounts payable — related party		448			910
Accrued expenses		16,017			16,136
Current portion of long-term liabilities		238			238
Derivative liability		14,092			21,098
Total current liabilities		32,126			40,078
Long-term liabilities
Bank and other long-term debt		43,924			43,929
Senior secured notes		161,748			162,287
Subordinated promissory note — related party		31,251			30,491
Asset retirement obligations and other long-term liabilities		23,538			22,990
Long-term derivative liability		43,098			66,876
Deferred income taxes		145,606			137,286
Total long-term liabilities		449,165			463,859
Shareholder’s equity
Common stock: without par value; 3,000 shares authorized and 1,534 shares issued		—			—
Paid in capital		142,500			142,500
Retained earnings (deficit)		4,609			(29,978	)
Accumulated other comprehensive loss		(6,331	)		(8,381	)
Total shareholder’s equity		140,778			104,141
	$	622,069		$	608,078

See accompanying notes.

1

BELDEN & BLAKE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited, in thousands)

	Three months			Three months			Six months			Six months
	ended June 30,			ended June 30,			ended June 30,			ended June 30,
	2010			2009			2010			2009
Revenues
Oil and gas sales	$	15,664		$	15,846		$	31,353		$	30,862
Gas gathering and marketing		1,215			1,326			2,805			3,246
Other		155			195			293			369
		17,034			17,367			34,451			34,477
Expenses
Production expense		4,997			4,989			9,966			11,219
Production taxes		265			231			600			553
Gas gathering and marketing		1,140			1,263			2,554			2,949
Exploration expense		240			790			381			2,315
Impairment of oil and gas properties		—			25,230			—			25,230
General and administrative expense		1,711			2,114			3,543			4,294
Depreciation, depletion and amortization		7,196			9,973			15,045			19,348
Accretion expense		326			339			645			670
Gain on sale assets		(28,485	)		—			(28,485	)		—
Derivative fair value (gain) loss		(147	)		10,804			(24,222	)		(20,423	)
		(12,757	)		55,733			(19,973	)		46,155
Operating income (loss)		29,791			(38,366	)		54,424			(11,678	)
Other expense (income)
Interest expense		5,023			5,315			9,997			10,132
Other income, net		(33	)		(33	)		(51	)		(100	)
Income (loss) before income taxes		24,801			(43,648	)		44,478			(21,710	)
Provision (benefit) for income taxes		9,314			(17,282	)		9,891			(8,586	)
Net income (loss)	$	15,487		$	(26,366	)	$	34,587		$	(13,124	)

See accompanying notes.

2

BELDEN & BLAKE CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited, in thousands)

	Six months			Six months
	ended June 30,			ended June 30,
	2010			2009
Cash flows from operating activities:
Net income (loss)	$	34,587		$	(13,124	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		15,045			19,348
Accretion expense		645			670
Gain on disposal of oil and gas properties		(28,485	)		—
Amortization of derivatives and other non-cash hedging activities		(21,249	)		(17,740	)
Exploration expense		344			1,345
Deferred income taxes		9,891			(8,586	)
Impairment of oil and gas properties		—			25,230
Other non-cash items		(48	)		2,144
Change in operating assets and liabilities
Accounts receivable and other current assets		2,158			7,747
Inventories		(31	)		60
Accounts payable and accrued expenses		(1,034	)		(2,629	)
Net cash provided by operating activities		11,823			14,465
Cash flows from investing activities:
Additions to property and equipment		(1,804	)		(6,743	)
Proceeds from property and equipment disposals		30,581			746
Exploration expense		(344	)		(1,345	)
Increase in other assets		(71	)		(57	)
Net cash provided by (used in) investing activities		28,362			(7,399	)
Cash flows from financing activities:
Repayment of long-term debt and other obligations		(72	)		(15,074	)
Debt financing costs		—			(350	)
Settlement of derivative liabilities recorded in purchase accounting		(6,046	)		(302	)
Net cash used in financing activities		(6,118	)		(15,726	)
Net increase (decrease) in cash and cash equivalents		34,067			(8,660	)
Cash and cash equivalents at beginning of period		46,740			22,816
Cash and cash equivalents at end of period	$	80,807		$	14,156

See accompanying notes.

3

BELDEN & BLAKE CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

June 30, 2010

(1) Basis of Presentation

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

The accompanying unaudited financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the period ended June 30, 2010 are not necessarily indicative of the results that may be expected for the year ended December 31, 2010. 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, 2009.

(2) Derivatives and Hedging

From time to time, we may enter into a combination of futures contracts, derivatives and fixed-price physical commodity contracts to manage our exposure to natural gas price, crude oil price or interest rate volatility and support our capital expenditure plans. Our derivative financial instruments take the form of swaps or collars. At June 30, 2010, our derivative contracts were comprised of natural gas swaps, natural gas basis differential swaps, crude oil swaps and interest rate swaps which were placed with major financial institutions that we believe are a minimal credit risk. All of our derivative instruments are currently accounted for as non-qualifying derivative contracts. The changes in fair value of non-qualifying derivative contracts are reported in expense in the condensed consolidated statements of operations as derivative fair value gain.

We have certain derivative contracts that qualified for hedge accounting treatment in prior periods, as well as derivative contracts that were de-designated in prior periods. During the second quarters of 2010 and 2009, net losses of $343,000 ($214,000 after tax) and $603,000 ($365,000 after tax), respectively, were reclassified from accumulated other comprehensive loss to earnings. The value of open hedges in accumulated other comprehensive loss decreased $342,000 ($214,000 after tax) in the second quarter of 2010 and decreased $603,000 ($365,000 after tax) in the second quarter of 2009. During the first six months of 2010 and 2009, net losses of $3.7 million ($2.0 million after tax) and $4.7 million ($2.8 million after tax), respectively, were reclassified from accumulated other comprehensive income to earnings. The value of open hedges in accumulated other comprehensive income decreased $3.7 million ($2.0 million after tax) in the first six months of 2010 and decreased $4.7 million ($2.8 million after tax) in the first six months of 2009. At June 30, 2010, the estimated net loss in accumulated other comprehensive income that is expected to be reclassified into earnings within the next 12 months is approximately $3.1 million after tax. At June 30, 2010, we have partially hedged our exposure to the variability in future cash flows through December 2013.

4

The following table reflects the natural gas and crude oil volumes and the weighted average prices under financial derivative contracts (including settled derivative contracts) at June 30, 2010:

	Natural Gas Swaps				Crude Oil Swaps				Natural Gas Basis Swaps
			NYMEX				NYMEX
			Price per				Price per				Basis
Quarter Ending	Bbtu		Mmbtu		Mbbls		Bbl		Bbtu		Differential
September 30, 2010		2,234	$	4.12		44	$	28.82		1,932	$	0.243
December 31, 2010		2,234		4.31		44		28.77		1,932		0.243
		4,468	$	4.22		88	$	28.80		3,864	$	0.243
Year Ending
December 31, 2011		8,231	$	4.19		157	$	28.77		5,110	$	0.252
December 31, 2012		7,005		4.09		138		28.70		3,660		0.110
December 31, 2013		6,528		4.04		127		28.70		—		—

At June 30, 2010, we had interest rate swaps in place through September 30, 2013 covering $43.5 million of our outstanding debt under the revolving credit facility, which currently matures on August 16, 2011. The swaps provide 1-month LIBOR fixed rates at 4.10% plus the applicable margin.

At June 30, 2010, the fair value of these derivatives was as follows:

	Asset Derivatives				Liability Derivatives
(in thousands)	June 30, 2010		December 31, 2009		June 30, 2010			December 31, 2009
Oil and natural gas commodity contracts	$	1,106	$	864	$	(53,684	)	$	(85,593	)
Interest rate swaps		—		27		(3,506	)		(2,381	)
Total fair value	$	1,106	$	891	$	(57,190	)	$	(87,974	)
Location of derivatives in our consolidated balance sheets:
Derivative asset	$	668	$	413	$	—		$	—
Long-term derivative asset		438		478		—			—
Derivative liability		—		—		(14,092	)		(21,098	)
Long-term derivative liability		—		—		(43,098	)		(66,876	)
	$	1,106	$	891	$	(57,190	)	$	(87,974	)

The net amount due under these derivative contracts may become due and payable if our Amended Credit Agreement or our senior secured notes become due and payable due to an event of default.

5

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(in thousands)	2010			2009			2010			2009
The following amounts are recorded in Oil and gas sales:
Unrealized losses:
Oil and natural gas commodity contracts	$	(343	)	$	(603	)	$	(3,652	)	$	(4,682	)
The following are recorded in Derivative fair value loss (gain):
Unrealized (gains) losses:
Oil and natural gas commodity contracts	$	(3,422	)	$	10,790		$	(32,200	)	$	(22,213	)
Interest rate swaps		765			(290	)		1,152			(571	)
Total		(2,657	)		10,500			(31,048	)		(22,784	)
Realized (gains) losses:
Oil and natural gas commodity contracts		2,087			(442	)		5,982			892
Interest rate swaps		423			746			844			1,469
Total		2,510			304			6,826			2,361
Derivative fair value loss (gain)	$	(147	)	$	10,804		$	(24,222	)	$	(20,423	)

(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) Fair Value of Financial Instruments

Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, long-term debt and derivatives. Our derivatives are recorded at fair value (see Notes 2 and 11). The carrying amount of our other financial instruments other than debt approximates fair value because of the short-term nature of the items. The carrying value of our debt approximates fair value because the facility’s interest rate approximates current market rates.

(5) Supplemental Disclosure of Cash Flow Information

	Six months			Six months
	ended June 30,			ended June 30,
(in thousands)	2010			2009
Cash paid during the period for:
Interest	$	8,923		$	8,951
Non-cash investing and financing activities:
Accrued additions to property and equipment		361			520
Non-cash additions to debt		(760	)		(1,383	)

6

(6) 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.

(7) Comprehensive Income

Comprehensive income includes net income and certain items recorded directly to shareholder’s equity and classified as other comprehensive income. The table below summarizes comprehensive income and provides the components of the change in accumulated other comprehensive income (loss) for the six-month periods ended June 30, 2010 and 2009.

	Three months		Three months			Six months		Six months
	ended June 30,		ended June 30,			ended June 30,		ended June 30,
	2010		2009			2010		2009
Comprehensive income (loss):
Net income (loss)	$	15,487	$	(26,366	)	$	34,587	$	(13,124	)
Other comprehensive income (loss), net of tax:
Other items reclassified into earnings, net of tax		38		—			38		42
Reclassification adjustment for derivative loss reclassified into earnings, net of tax		214		364			2,012		2,831
Change in accumulated other comprehensive income (loss)		252		364			2,050		2,873
	$	15,739	$	(26,002	)	$	36,637	$	(10,251	)

(8) Related Party Transactions

We have a joint operating agreement with EnerVest Operating LLC (“EnerVest Operating”). In the second quarter of 2010, we recorded costs of approximately $1.4 million (as general and administrative expense) for operating overhead fees, $1.3 million (as production expense) for field labor, vehicles and district office expense and $172,000 (capitalized) for drilling labor costs related to this agreement. We recorded costs of approximately $1.6 million for operating overhead fees, $1.4 million for field labor, vehicles and district office expense, $11,000 (capitalized) for drilling overhead fees and $225,000 for drilling labor costs in the second quarter of 2009 related to this agreement. In the first six months of 2010, we recorded costs of approximately $2.7 million (as general and administrative expense) for operating overhead fees, $2.7 million (as production expense) for field labor, vehicles and district office expense and $400,000 (capitalized) for drilling labor costs related to this agreement. We recorded costs of approximately $3.3 million for operating overhead fees, $3.0 million for field labor, vehicles and district office expense, $27,000 for drilling overhead fees and $745,000 for drilling labor costs in the first six months of 2009 related to this agreement.

We have a subordinated promissory note in favor of our parent, Capital C in the maximum amount of $94 million. The amount outstanding under the note at June 30, 2010 was $31.3 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 paid cash of $752,000 and borrowed $760,000 against the note for interest payments in the first six months of 2010 and borrowed of $1.4 million against the note in the first six months of 2009.

As of June 30, 2010, we owed EnerVest $651,000 and EnerVest Operating owed us $211,000.

(9) Impairment of Oil and Gas Properties

For the periods ended June 30, 2010 and 2009, we reviewed our oil and gas properties for impairment as prescribed by ASC 360-10, Accounting for the Impairment or Disposal of Long-Lived Assets. As a result of this evaluation, we recorded an impairment of $25.2 million during the second quarter of 2009 to our coalbed methane properties in Pennsylvania. No impairment was recorded in 2010.

7

(10) New Accounting Standards

In April 2010, the FASB issued ASU No. 2010-14,Accounting for Extractive Activities — Oil & Gas: Amendments to Paragraph 932-10-S99-1,to amend paragraph 932-10-S99-1 due to SEC Release No. 33-8995 [FR 78],Modernization of Oil and Gas Reporting.

No other new accounting pronouncements issued or effective during the six months ended June 30, 2010 have had or are expected to have a material impact on our condensed consolidated financial statements.

(11) Fair Value Measurements

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 June 30, 2010 Using:
				Quoted Prices in		Significant
				Active Markets		Other			Significant
				for Identical		Observable			Unobservable
				Assets		Inputs			Inputs
	Total Carrying Value			(Level 1)		(Level 2)			(Level 3)
Derivative assets:
Oil and natural gas commodity contracts	$	1,106		$	—	$	1,106		$	—
Derivative liabilities:
Oil and natural gas commodity contracts	$	(53,684	)	$	—	$	(53,684	)	$	—
Interest rate swaps		(3,506	)		—		(3,506	)		—
Total derivative liabilities	$	(57,190	)	$	—	$	(57,190	)	$	—

				Fair Value Measurements at December 31, 2009 Using:
				Quoted Prices in		Significant
				Active Markets		Other			Significant
				for Identical		Observable			Unobservable
				Assets		Inputs			Inputs
	Total Carrying Value			(Level 1)		(Level 2)			(Level 3)
Derivative assets:
Oil and natural gas commodity contracts	$	864		$	—	$	864		$	—
Interest rate swaps		27			—		27			—
Total derivative assets	$	891		$	—	$	891		$	—
Derivative liabilities:
Oil and natural gas commodity contracts	$	(85,593	)	$	—	$	(85,593	)	$	—
Interest rate swaps		(2,381	)		—		(2,381	)		—
Total derivative liabilities	$	(87,974	)	$	—	$	(87,974	)	$	—

Our derivatives consist of over-the-counter (“OTC”) contracts which are not traded on a public exchange. These derivatives 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.

8

As the fair value of these derivatives 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 derivatives as Level 2. We value these derivatives based on observable market data for similar instruments. This observable data includes the forward curve for commodity prices based on quoted market prices and prospective volatility factors related to changes in the forward curves and yield curves based on money market rates and interest rate swap data. Our estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty and cannot be determined with precision. There were no changes in valuation techniques or related inputs in the three months ended June 30, 2010.

(12) 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, 2009	$	23,083
Accretion expense		645
Liabilities incurred		—
Liabilities settled		(31	)
Revisions in estimated cash flows		—
Balance as of June 30, 2010	$	23,697

As of June 30, 2010 and December 31, 2009, $229,000 of our ARO is classified as current.

(13) Divestitures

On June 14, 2010, we sold certain oil and natural gas properties for $30.6 million and recorded a gain on the sale of $28.5 million.

(14) Subsequent Event

On July 1, 2010, we sold certain oil and natural gas properties in the Appalachian Basin for $6.3 million. We received $3.2 million at the closing and will receive the remainder of the proceeds, subject to certain conditions, including purchaser due diligence, on or before November 1, 2010. These oil and natural gas properties are classified as “Assets held for sale” in our unaudited condensed consolidated balance sheet.

On August 3, 2010 we reduced the amount outstanding under our revolving credit agreement by $20.0 million. In conjunction with the debt reduction we reduced the notional amount of our interest rate swap by $20 million at a cost of $2.0 million.

We evaluated subsequent events for appropriate accounting and disclosure through the date these condensed consolidated financial statements were issued.

9

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

Forward-Looking Information

The information in this document includes forward-looking statements that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Statements preceded by, followed by or that otherwise include the statements “should,” “believe,” “expect,” “anticipate,” “intend,” “continue,” “estimate,” “plan,” “outlook,” “may,” “future,” “projection,” “likely,” “possible,” “could” and variations of these statements and similar expressions are forward-looking statements as are any other statements relating to developments, events, occurrences, results, efforts or impacts. These forward-looking statements are based on current expectations and projections about future events. Forward-looking statements and the business prospects of Belden & Blake are subject to a number of risks and uncertainties which may cause our actual results in future periods to differ materially from the forward-looking statements contained herein. These risks and uncertainties include, but are not limited to, our access to capital, the market demand for and prices of oil and natural gas, our oil and gas production and costs of operation, results of our future drilling activities, the uncertainties of reserve estimates, general economic conditions, new legislation or regulatory changes, changes in accounting principles, policies or guidelines and environmental risks. These and other risks are described in our Annual Report on Form 10-K for the year ended December 31, 2009, 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.

10

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 June 30,				Six months ended June 30,
	2010		2009		2010		2009
Production
Gas (Mmcf)		2,489		3,170		5,092		6,347
Oil (Mbbls)		69		80		136		163
Total production (Mmcfe)		2,904		3,652		5,910		7,322
Average price (1)
Gas (per Mcf)	$	4.28	$	3.63	$	4.20	$	3.67
Oil (per Bbl)		72.53		54.01		72.90		46.52
Mcfe		5.39		4.34		5.30		4.21
Average costs (per Mcfe)
Production expense	$	1.72	$	1.37	$	1.69	$	1.53
Production taxes		0.09		0.06		0.10		0.08
Depletion		2.45		2.70		2.52		2.62

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

	Three months ended June 30,				Six months ended June 30,
	2010		2009		2010		2009
Gas (per Mcf)	$	4.42	$	3.82	$	4.92	$	4.41
Oil (per Bbl)		72.53		54.01		72.90		46.52
Mcfe		5.51		4.50		5.92		4.85

Results of Operations — Second Quarters of 2010 and 2009 Compared

Revenues

Operating revenues decreased from $17.4 million in the second quarter of 2009 to $17.0 million in the second quarter of 2010. The decrease in operating revenues was due to lower oil and gas sales revenues of $182,000 and lower gas gathering and marketing revenues of $111,000.

Gas volumes sold were 2.5 Bcf in the second quarter of 2010, which was a decrease of 681 Mmcf (21%) compared to the second quarter of 2009. This decrease in gas volumes sold resulted in a decrease in gas sales revenues of approximately $2.5 million. Oil volumes sold decreased approximately 11,000 Bbls (14%) from 80,000 Bbls in the second quarter of 2009 to 69,000 Bbls in the second quarter of 2010 resulting in a decrease in oil sales revenues of approximately $600,000. The lower oil and gas sales volumes are primarily due to the sale of our coalbed methane properties in Pennsylvania in July 2009, normal production decline of the wells, reduced drilling in 2009 and no drilling in 2010.

The average price realized for our natural gas increased $0.65 per Mcf from $3.63 in the second quarter of 2009 to $4.28 per Mcf in the second quarter of 2010, which increased gas sales revenues by approximately $1.6 million. As a result of our qualified hedging and derivative financial instrument activities, gas sales revenues were lower by $343,000 ($0.14 per Mcf) in the second quarter of 2010 and lower by $603,000 ($0.19 per Mcf) in the second quarter of 2009 than if our gas price was not affected by derivative financial instruments. The average price realized for our oil increased from $54.01 per Bbl in the second quarter of 2009 to $72.53 per Bbl in the second quarter of 2010, which increased oil sales revenues by approximately $1.3 million.

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Gas gathering and marketing revenues decreased from $1.3 million in the second quarter of 2009 to $1.2 million in the second quarter of 2010. The decrease was due to a $76,000 decrease in gas marketing revenues and a $35,000 decrease in gas gathering revenues as a result of lower gas volumes in the second quarter of 2010 compared to the second quarter of 2009.

Costs and Expenses

Production expense was $5.0 million in the second quarter of 2009 and 2010. Cost decreases from the sale of the coalbed methane properties were offset by higher operating expenses associated with several Marcellus shale wells completed in late 2009. These wells were sold in the June 2010 asset sale discussed in Note 13. The average production cost increased from $1.37 per Mcfe in the second quarter of 2009 to $1.72 per Mcfe in the second quarter of 2010 due to the decrease in volumes and stable costs.

Production taxes increased $34,000 from $231,000 in the second quarter of 2009 to $265,000 in the second quarter of 2010. Average per unit production taxes increased from $0.06 per Mcfe in the second quarter of 2009 to $0.09 per Mcfe in the second quarter of 2010. The increased production taxes were primarily due to higher oil and gas prices in Michigan in the second quarter of 2010 compared to the second quarter of 2009. In Michigan, production taxes are based on a percentage of revenues, excluding the effects of hedging.

Gas gathering and marketing expenses decreased from $1.3 million in the second quarter of 2009 to $1.1 million in the second quarter of 2010. The decrease was primarily due to lower gas volumes in the second quarter of 2010 compared to the second quarter of 2009.

Exploration expense decreased $550,000 from $790,000 in the second quarter of 2009 to $240,000 in the second quarter of 2010. The decrease in exploration expense was primarily due to a reduced level of seismic activity and lower delay rentals as a result of the sale of our coalbed methane properties in July 2009.

Impairment of oil and gas properties was $25.2 million in the second quarter of 2009 due to the impairment of coalbed methane properties in Pennsylvania.

General and administrative expense decreased $403,000 from $2.1 million in the second quarter of 2009 to $1.7 million in the second quarter of 2010. The decrease was primarily due to reduced overhead fees paid to EnerVest, primarily as a result of the sale of the coalbed methane properties, and lower legal and technical consulting fees paid to third parties.

Depreciation, depletion and amortization decreased by $2.8 million from $10.0 million in the second quarter of 2009 to $7.2 million in the second quarter of 2010. This decrease was due to a $2.8 million decrease in depletion expense because of lower volumes and a lower depletion rate per Mcfe. Depletion per Mcfe decreased from $2.70 per Mcfe in the second quarter of 2009 to $2.45 per Mcfe in the second quarter of 2010 primarily due to increased reserves volumes due to higher oil and gas prices at June 30, 2010.

Derivative fair value (gain) loss was a gain of $147,000 in the second quarter of 2010 compared to a loss of $10.8 million in the second quarter of 2009. The derivative fair value (gain) loss reflects the changes in fair value of certain derivative instruments that are not designated or do not qualify as cash flow hedges.

Gain on sale of assets was $28.5 million in the second quarter of 2010 due to the sale of oil and gas properties in June 2010. There was no gain on the sale of assets in the second quarter of 2009.

Interest expense decreased $292,000 from $5.3 million in the second quarter of 2009 to $5.0 million in the second quarter of 2010. This decrease in interest expense was primarily due to lower debt levels.

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Income tax expense was $9.3 million in the second quarter of 2010 compared to an income tax benefit of $17.3 million in the second quarter of 2009. The change in income tax expense was primarily due to an increase in income before income taxes. The increase in income before income taxes was primarily due to the gain on the sale of oil and gas properties in June 2010, the decrease in depreciation, depletion and amortization expense and the increase in derivative fair value gain, which were partially offset by the decrease in the impairment of oil and gas properties.

Results of Operations — Six Months of 2010 and 2009 Compared

Revenues

Operating revenues were $34.5 million in the first six months of 2009 and 2010. Oil and gas sales revenues increased $491,000 and gas gathering and marketing revenues decreased $441,000 from the first six months of 2009 to the first six months of 2010.

Gas volumes sold were 5.1 Bcf in the first six months of 2010, which was a decrease of 1.3 Bcf (20%) compared to the first six months of 2009. This decrease in gas volumes sold resulted in a decrease in gas sales revenues of approximately $4.6 million. Oil volumes sold decreased approximately 27,000 Bbls (16%) from 163,000 Bbls in the first six months of 2009 to 136,000 Bbls in the first six months of 2010 resulting in a decrease in oil sales revenues of approximately $1.2 million. The lower oil and gas sales volumes are primarily due to the sale of our coalbed methane properties in Pennsylvania in July 2009, normal production decline of the wells, reduced drilling in 2009 and no drilling in 2010.

The average price realized for our natural gas increased $0.53 per Mcf from $3.67 in the first six months of 2009 to $4.20 per Mcf in the first six months of 2010, which increased gas sales revenues by approximately $2.7 million. As a result of our qualified hedging and derivative financial instrument activities, gas sales revenues were lower by $3.7 million ($0.72 per Mcf) in the first six months of 2010 and lower by $4.7 million ($0.74 per Mcf) in the first six months of 2009 than if our gas price was not affected by derivative financial instruments. The average price realized for our oil increased from $46.52 per Bbl in the first six months of 2009 to $72.90 per Bbl in the first six months of 2010, which increased oil sales revenues by approximately $3.6 million.

Gas gathering and marketing revenues decreased from $3.2 million in the first six months of 2009 to $2.8 million in the first six months of 2010 due to a $352,000 decrease in gas marketing revenues and an $89,000 decrease in gas gathering revenues as a result of lower gas volumes in the first six months of 2010 compared to the first six months of 2009.

Costs and Expenses

Production expense decreased from $11.2 million in the first six months of 2009 to $10.0 million in the first six months of 2010. The decrease in production expense was primarily due to the sale of our coalbed methane properties, which was partially offset by higher operating expenses associated with several Marcellus shale wells completed in late 2009. These wells were sold in the June 2010 asset sale discussed in Note 13. The average production cost increased from $1.53 per Mcfe in the first six months of 2009 to $1.69 per Mcfe in the first six months of 2010 primarily due to the decrease in volumes partially offset by lower costs.

Production taxes increased from $553,000 in the first six months of 2009 to $600,000 in the first six months of 2010. Average per unit production taxes increased from $0.08 per Mcfe in the first six months of 2009 to $0.10 per Mcfe in the first six months of 2010. The increased production taxes are primarily due to higher oil and gas prices in the first six months of 2010 in Michigan, where production taxes are based on a percentage of revenues, excluding the effects of hedging.

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Gas gathering and marketing expenses decreased from $2.9 million in the first six months of 2009 to $2.6 million in the first six months of 2010, primarily due to a $323,000 decrease in gas marketing expenses as a result of lower gas volumes in the first six months of 2010 compared to the first six months of 2009.

Exploration expense decreased $1.9 million from $2.3 million in the first six months of 2009 to $381,000 in the first six months of 2010. The decrease in exploration expense was primarily due to a decrease in expired lease expense, a lower level of seismic activity and lower delay rental expense.

Impairment of oil and gas properties was $25.2 million in the first six months of 2009 due to the impairment of coalbed methane properties in Pennsylvania.

General and administrative expense decreased from $4.3 million in the first six months of 2009 to $3.5 million in the first six months of 2010. This decrease was primarily due to reduced overhead fees paid to EnerVest, primarily as a result of the sale of the Pennsylvania coalbed methane properties in July 2009, and lower legal and technical consulting fees paid to third parties.

Depreciation, depletion and amortization decreased by $4.3 million from $19.3 million in the first six months of 2009 to $15.0 million in the first six months of 2010. This decrease was due to a $4.3 million decrease in depletion expense, which was primarily due to a decrease in oil and gas volumes sold in the first six months of 2010. Depletion per Mcfe decreased from $2.62 per Mcfe in the first six months of 2009 to $2.52 in the first six months of 2010 primarily due to increased reserves volumes due to higher oil and gas prices at June 30, 2010.

Derivative fair value (gain) loss was a gain of $24.2 million in the first six months of 2010 and a gain of $20.4 million in the first six months of 2009. The derivative fair value (gain) loss reflects the changes in fair value of certain derivative instruments that are not designated or do not qualify as cash flow hedges.

Gain on sale of assets was $28.5 million in the first six months of 2010 due to the sale of oil and gas properties in June 2010. There was no gain on the sale of assets in the first six months of 2009.

Interest expense decreased $135,000 from $10.1 million in the first six months of 2009 to $10.0 million in the first six months of 2010. This decrease in interest expense was primarily due to lower debt levels.

Income tax expense was $9.9 million in the first six months of 2010 compared to an income tax benefit of $8.6 million in the first six months of 2009. The change in income tax expense was primarily due to an increase in income before income taxes, partially offset by the elimination of the state of Ohio corporate income tax. The Ohio corporate income tax was replaced with a Commercial Activity Tax which is not considered an income tax under FASB Accounting Standards Codification (“ASC”) No. 740, Accounting for Income Taxes. As a result of the change in the Ohio state law, deferred tax amounts previously recorded were adjusted to reflect the change and resulted in a reduction of $6.8 million in income tax expense. The increase in income before income taxes was primarily due to the gain on the sale of oil and gas properties in June 2010, the decrease in depreciation, depletion and amortization expense and the increase in derivative fair value gain, which were partially offset by the decrease in the impairment of oil and gas properties.

Liquidity and Capital Resources

Cash Flows

The primary sources of cash in the six month period ended June 30, 2010 have been funds generated from the sale of non-strategic assets and from our operating activities. Funds used during this period were primarily used for operating activities, interest expense and the settlement of derivatives.

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Our operating activities provided cash flows of $11.8 million during the first six months of 2010 compared to $14.5 million in the first six months of 2009. The decrease was primarily due to a decrease in the change in working capital items of $4.1 million which was partially offset by a decrease in production expense of $1.2 million and a decrease in general and administrative expense of $751,000.

Our investing activities provided cash flows of $28.4 million during the first six months of 2010 compared to $7.4 million used in the first six months of 2009. The change was due to an increase in proceeds from property and equipment disposals of $29.8 million, a decrease in capital expenditures of $4.9 million and a decrease in exploration expense of $1.0 million.

Cash flows used in financing activities decreased $9.6 million in the first six months of 2010 primarily due to a decrease in the repayment of long term debt of $15.0 million which was partially offset by an increase of $5.7 million in derivative settlements.

Our current ratio at June 30, 2009 was 3.07 to 1. During the first six months of 2010, working capital increased $38.4 million from $28.2 million at December 31, 2009 to $66.6 million at June 30, 2010. The increase in working capital was primarily due to an increase in cash of $34.1 million and a decrease of $7.0 million in the current liability related to the fair value of derivatives which were partially offset by a $1.7 million decrease in accounts receivable and a $3.2 million decrease in the current deferred tax asset.

Capital Expenditures

During the first six months of 2010, we spent approximately $1.8 million on our drilling activities and other capital expenditures. We did not drill any wells in the first six months of 2010. Most of our capital expenditures in the first half of 2010 were in preparation for our drilling program which will commence in the third quarter. We performed major workovers on 11 wells during the first six months of 2010. We plan to drill approximately 61 gross (61.0 net) development wells and 8 gross (4.0 net) exploratory wells and perform major workovers on 10 additional wells in the second half of 2010.

We currently expect to spend approximately $20 million during 2010 on our drilling activities and other capital expenditures. We intend to finance our planned capital expenditures through our cash on hand and available operating cash flow. At June 30, 2010, we had cash of $80.8 million and approximately $20.3 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 and workover 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

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

On March 23, 2010, we entered into the Sixth Amendment to the Credit Agreement. The Credit Agreement was amended to (1) add a maximum senior secured leverage ratio of 2.00 : 1.00, (2) eliminate the maximum leverage ratio beginning December 31, 2009, (3) amend the minimum interest coverage ratio to 1.75 : 1.0 and (4) make certain other amendments to the Credit Agreement. At June 30, 2010, we were in compliance with such financial covenants under the Amended Credit Agreement.

At June 30, 2010, we had an Amended Credit Agreement comprised of a five-year $100 million revolving facility with a borrowing base of $65 million, of which $43.9 million was outstanding at June 30, 2010. 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, an adjusted federal funds rate or an adjusted Eurodollar rate, plus an applicable margin ranging from 1.0% to 2.0% based on the aggregate principal amount outstanding under the Amended Credit Agreement, or, (ii) at our option, the Eurodollar base rate plus an applicable margin ranging from 2.5% to 3.50% 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, 2011.

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

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 credit facility as well as any new debt financing needed to fund capital requirements. We may manage our interest rate risk through the use of interest rate swaps to hedge the interest rate exposure associated with the credit agreement, whereby a portion of our floating rate exposure is exchanged for a fixed interest rate. A portion of our long-term debt consists of senior secured notes where the interest component is fixed. At June 30, 2010, we had an interest rate swap in place on $43.5 million of our outstanding debt under the revolving credit facility through September 30, 2013. The swap provides a 1-month LIBOR fixed rates at 4.10%, plus the applicable margin, on $43.5 million through September 2013. These interest rate swaps do not qualify for hedge accounting, therefore, all cash settles and changes in the fair value of these swaps are recorded in derivative fair value gain/loss. If market interest rates for short-term borrowings increased 1%, the increase in our interest expense for the first six months of 2010 would be approximately $219,000. The impact of this rate increase on our cash flows would be significantly less than this amount due to our interest rate swaps. If market interest rates increased 1% there would be no decrease in our cash flow. This sensitivity analysis is based on our financial structure at June 30, 2010.

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 June 30, 2010, we had derivatives covering a portion of our oil and gas production from 2010 through 2013. Our oil and gas sales revenues included a net pre-tax loss of $3.7 million in the first six months of 2010 and a net pre-tax loss of $343,000 million in the second quarter of 2010 on our qualified hedging activities.

If gas prices decreased $1.00 per Mcf, our gas sales revenues for the first six months of 2010 would decrease by approximately $5.1 million. If the price of crude oil decreased $10.00 per Bbl, our oil sales revenues for the first six months of 2010 would decrease by approximately $1.4 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 six months of 2010 by approximately $1.1 million after considering the effects of the derivative contracts in place as of June 30, 2010. This sensitivity analysis is based on the first six months of 2010 oil and gas sales volumes.

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The following table reflects the natural gas and crude oil volumes and the weighted average prices under financial hedges (including settled hedges) at July 31, 2010, which has not changed since June 30, 2010:

	Natural Gas Swaps				Crude Oil Swaps				Natural Gas Basis Swaps
			NYMEX				NYMEX
			Price per				Price per				Basis
Quarter Ending	Bbtu		Mmbtu		Mbbls		Bbl		Bbtu		Differential
September 30, 2010		2,234	$	4.12		44	$	28.82		1,932	$	0.243
December 31, 2010		2,234		4.31		44		28.77		1,932		0.243
		4,468	$	4.22		88	$	28.80		3,864	$	0.243
Year Ending
December 31, 2011		8,231	$	4.19		157	$	28.77		5,110	$	0.252
December 31, 2012		7,005		4.09		138		28.70		3,660		0.110
December 31, 2013		6,528		4.04		127		28.70		—		—

The fair value of our oil and gas swaps was a net liability of approximately $52.6 million as of June 30, 2010.

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 June 30, 2010 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 June 30, 2010 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.

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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, 2009.

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. (Removed and Reserved)

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.

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SIGNATURES

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

	BELDEN & BLAKE CORPORATION
Date: August 12, 2010	By:	/s/ Mark A. Houser
		Mark A. Houser, Chief Executive Officer,
		Chairman of the Board of Directors and Director (Principal Executive Officer)
Date: August 12, 2010	By:	/s/ James M. Vanderhider
		James M. Vanderhider, President,
		Chief Financial Officer and Director (Principal Financial Officer)

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