UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

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

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

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

Indicate by check mark whether the registrant 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). Yes o No o

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 definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o		Accelerated filer o		Non-accelerated filer þ		Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

As of April 30, 2011, 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 March 31, 2011 and December 31, 2010			1
Condensed Consolidated Statements of Operations: Three months ended March 31, 2011 and 2010			2
Condensed Consolidated Statements of Cash Flows: Three months ended March 31, 2011 and 2010			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			18
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			19
Signatures			20
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

PART I. FINANCIAL INFORMATION

Item 1.		Financial Statements

BELDEN & BLAKE CORPORATION

		March 31,				December 31,
		2011				2010
ASSETS
Current assets
Cash and cash equivalents		$	33,173			$	35,941
Accounts receivable (less accumulated provision for doubtful accounts: March 31, 2011 — $482; December 31, 2010 — $452)			9,168				9,913
Inventories			835				832
Deferred income taxes			5,303				4,266
Other current assets			148				209
Fair value of derivatives			497				794
Total current assets			49,124				51,955
Property and equipment, at cost
Oil and gas properties (successful efforts method)			703,193				701,790
Gas gathering systems			1,239				1,239
Land, buildings, machinery and equipment			2,420				2,421
			706,852				705,450
Less accumulated depreciation, depletion and amortization			187,206				179,947
Property and equipment, net			519,646				525,503
Fair value of derivatives			74				47
Other assets			1,445				1,517
		$	570,289			$	579,022
LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Accounts payable		$	2,567			$	2,120
Accounts payable — related party			520				1,523
Accrued expenses			15,234				22,417
Current portion of long-term liabilities			143				143
Fair value of derivatives			14,601				12,141
Total current liabilities			33,065				38,344
Long-term liabilities
Bank and other long-term debt			23,916				23,919
Senior secured notes			140,806				141,056
Subordinated promissory note — related party			33,656				32,846
Asset retirement obligations and other long-term liabilities			24,921				24,637
Fair value of derivatives			29,548				30,201
Deferred income taxes			140,121				140,137
Total long-term liabilities			392,968				392,796
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			4,843				10,168
Accumulated other comprehensive loss			(3,087	)			(4,786	)
Total shareholder’s equity			144,256				147,882
		$	570,289			$	579,022

See accompanying notes.

BELDEN & BLAKE CORPORATION

		Three months ended				Three months ended
		March 31, 2011				March 31, 2010
Revenues
Oil and gas sales		$	14,177			$	15,689
Gas gathering and marketing			1,419				1,590
Other			87				138
			15,683				17,417
Expenses
Production expense			5,594				4,969
Production taxes			285				335
Gas gathering and marketing			1,456				1,414
Exploration expense			500				141
General and administrative expense			1,618				1,832
Depreciation, depletion and amortization			7,262				7,849
Accretion expense			340				319
Gain on sale of property			(2,424	)			—
Derivative fair value loss (gain)			4,096				(24,075	)
			18,727				(7,216	)
Operating (loss) income			(3,044	)			24,633
Other (income) expense
Interest expense			4,369				4,974
Other income, net			(11	)			(18	)
			4,358				4,956
(Loss) income before income taxes			(7,402	)			19,677
(Benefit) provision for income taxes			(2,077	)			577
Net (loss) income		$	(5,325	)		$	19,100

See accompanying notes.

BELDEN & BLAKE CORPORATION

		Three months ended				Three months ended
		March 31, 2011				March 31, 2010
Cash flows from operating activities:
Net (loss) income		$	(5,325	)		$	19,100
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			7,262				7,849
Accretion expense			340				319
Gain on sale of property			(2,424	)
Amortization of derivatives and other noncash hedging activities			6,508				(21,291	)
Exploration expense			500				141
Deferred income taxes			(2,077	)			577
Other non-cash items			703				(8	)
Change in operating assets and liabilities, net of effects of acquisition and disposition of businesses:
Accounts receivable and other operating assets			806				321
Inventories			(3	)			(56	)
Accounts payable and accrued expenses			(3,820	)			(4,622	)
Net cash provided by operating activities			2,470				2,330
Cash flows from investing activities:
Proceeds from property and equipment disposals			2,424				—
Exploration expense			(500	)			(141	)
Additions to property and equipment			(5,324	)			(669	)
Decrease in other assets			(71	)			(71	)
Net cash used in investing activities			(3,471	)			(881	)
Cash flows from financing activities:
Repayment of long-term debt and other obligations			(59	)			(3	)
Settlement of derivative liabilities recorded in purchase accounting			(1,708	)			(3,827	)
Net cash used in financing activities			(1,767	)			(3,830	)
Net decrease in cash and cash equivalents			(2,768	)			(2,381	)
Cash and cash equivalents at beginning of period			35,941				46,740
Cash and cash equivalents at end of period		$	33,173			$	44,359

See accompanying notes.

BELDEN & BLAKE CORPORATION

March 31, 2011

(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 March 31, 2011 are not necessarily indicative of the results that may be expected for the year ended December 31, 2011. For further information, refer to the consolidated financial statements and footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2010.

(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 March 31, 2011, 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 loss (gain).

In May 2011, we entered into transactions which increased the fixed price to be received on approximately 50% of our existing oil swaps covering (i) 52,416 barrels for the remainder of 2011 from $28.77 per barrel to $105.00 per barrel, (ii) 68,964 barrels for 2012 from $28.70 per barrel to $105.00 per barrel, and (iii) 63,564 barrels for 2013 from $28.70 to $102.00 per barrel. As consideration for such increases in the fixed price of such swaps, we made a payment of $14.1 million to the hedge counterparty.

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 first quarters of 2011 and 2010, net losses of $2.7 million ($1.7 million after tax) and $3.3 million ($1.8 million after tax), respectively, were reclassified from accumulated other comprehensive loss to earnings. The value of open hedges in accumulated other comprehensive loss decreased $2.7 million ($1.7 million after tax) in the first quarter of 2011 and decreased $3.3 million ($1.8 million after tax) in the first quarter of 2010. At March 31, 2011, the estimated net loss in accumulated other comprehensive loss that is expected to be reclassified into earnings within the next 12 months is approximately $2.0 million after tax. At March 31, 2011, 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 derivative contracts (including settled derivative contracts) at March 31, 2011:

		Natural Gas Swaps								Crude Oil Swaps
						NYMEX								NYMEX				Natural Gas Basis Swaps
						Price per								Price per								Basis
		Bbtu				Mmbtu				Mbbls				Bbl				Bbtu				Differential
Quarter Ending
June 30, 2011			2,057			$	4.00				50			$	46.33				1,943			$	0.196
September 30, 2011			2,058				4.01				51				46.47				1,964				0.196
December 31, 2011			2,058				4.26				51				46.47				1,964				0.196
			6,173			$	4.09				152			$	46.42				5,871			$	0.196
Year Ending
December 31, 2012			7,005			$	4.09				184			$	47.83				6,991			$	0.086
December 31, 2013			6,528				4.04				164				45.33

At March 31, 2011, we had interest rate swaps in place through September 30, 2013 covering $23.5 million of our outstanding debt under the revolving credit facility, which currently matures on April 14, 2012. The swaps provide 1-month LIBOR fixed rates at 4.10% plus the applicable margin.

At March 31, 2011, the fair value of these derivatives was as follows (in thousands):

		Asset Derivatives								Liability Derivatives
		March 31, 2011				December 31, 2010				March 31, 2011				December 31, 2010
Oil and natural gas commodity contracts		$	571			$	841			$	(42,465	)		$	(40,560	)
Interest rate swaps			—				—				(1,684	)			(1,782	)
Total fair value		$	571			$	841			$	(44,149	)		$	(42,342	)
Location of derivatives in our consolidated balance sheet:
Derivative asset		$	497			$	794			$	—			$	—
Long-term derivative asset			74				47				—				—
Derivative liability			—				—				(14,601	)			(12,141	)
Long-term derivative liability			—				—				(29,548	)			(30,201	)
		$	571			$	841			$	(44,149	)		$	(42,342	)

The net amount due under these derivative contracts may become due and payable if our Credit Agreement or our Senior Secured Notes become due and payable due to an event of default.

The following table presents the impact of derivatives and their location within the statements of operations (in thousands):

		Three Months Ended
		March 31,
		2011				2010
The following amounts are recorded in oil and gas sales:
Unrealized losses:
Oil and natural gas commodity contracts		$	(2,721	)		$	(3,309	)
The following are recorded in derivative fair value loss (gain):
Unrealized losses (gains):
Oil and natural gas commodity contracts		$	2,267			$	(28,779	)
Interest rate swaps			(98	)			388
Total			2,169				(28,391	)
Realized losses:
Oil and natural gas commodity contracts			1,701				3,895
Interest rate swaps			226				421
Total			1,927				4,316
Derivative fair value loss (gain)		$	4,096			$	(24,075	)

(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, accrued liabilities, long-term debt and derivatives. Our derivatives are recorded at fair value (see Notes 2 and 10). The carrying amount of our other financial instruments other than debt approximates fair value because of the short-term nature of the items. The recorded amounts of outstanding bank and other long-term debt approximate fair value because interest rates are based on LIBOR or the prime rate or due to the short maturities. The $139.5 million (face amount) of our Senior Secured Notes due 2012 had an approximate fair value of $139.5 million at March 31, 2011 based on quoted market prices.

(5) Supplemental Disclosure of Cash Flow Information

		Three months ended				Three months ended
(in thousands)		March 31, 2011				March 31, 2010
Cash paid during the period for:
Interest		$	6,678			$	8,494
Non-cash investing and financing activities:
Non-cash additions to property and equipment			3,689				185
Non-cash additions to debt			810				—

(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 (Loss) Income

Comprehensive income includes net income and certain items recorded directly to shareholder’s equity and classified as other comprehensive income. The table below summarizes comprehensive income and provides the components of the change in accumulated other comprehensive income for the three-month periods ended March 31, 2011 and 2010 (in thousands).

		Three months ended				Three months ended
		March 31, 2011				March 31, 2010
Comprehensive (loss) income:
Net (loss) income		$	(5,325	)		$	19,100
Other comprehensive income, net of tax:
Reclassification adjustment for derivative loss reclassified into earnings, net of tax			1,698				1,798
Change in accumulated other comprehensive income			1,698				1,798
		$	(3,627	)		$	20,898

(8) Related Party Transactions

We have a joint operating agreement with EnerVest Operating LLC (“EnerVest Operating”). In the first quarter of 2011, we recorded expenses of approximately $1.4 million for operating overhead fees, $1.4 million for field labor, vehicles and district office expense and $558,000 for drilling labor costs related to this agreement. We recorded expenses of approximately $1.4 million for operating overhead fees, $1.4 million for field labor, vehicles and district office expense and $228,000 for drilling labor costs in the first quarter of 2010 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 note accrues interest at 10% per year and matures on August 16, 2012. The amount due under the note at March 31, 2011 was $33.7 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 borrowed $810,000 against the note for the interest payments in the first quarter of 2011, and made a cash interest payment of $752,000 in the first quarter of 2010.

As of March 31, 2011, EnerVest Operating owed us $203,000 and we owed EnerVest $722,000.

(9) New Accounting Standards

No new accounting pronouncements issued or effective during the three months ended March 31, 2011 have had or are expected to have a material impact on our unaudited condensed consolidated financial statements.

(10) Fair Value Measurements

Recurring Basis

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 (in thousands):

						Fair Value Measurements 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)
At March 31, 2011
Commodity contracts		$	(41,894	)			—			$	(41,894	)			—
Interest rate swaps			(1,684	)			—				(1,684	)			—
Total derivative liabilities		$	(43,578	)			—			$	(43,578	)			—
At December 31, 2010:
Commodity contracts		$	(39,719	)			—			$	(39,719	)			—
Interest rate swaps			(1,782	)			—				(1,782	)			—
Total derivative liabilities		$	(41,501	)			—			$	(41,501	)			—

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.

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 March 31, 2011.

(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 (in thousands):

Balance as of December 31, 2010		$	24,701
Accretion expense			340
Liabilities incurred			1
Liabilities settled			(58	)
Revisions in estimated cash flows			—
Balance as of March 31, 2011		$	24,984

As of March 31, 2011 and December 31, 2010, $133,000 of our ARO is classified as current.

(12) Long-Term Debt

We have Senior Secured Notes that mature on July 15, 2012. Interest is payable semi-annually on January 15 and July 15 of each year at 8.75% based on the face amount of $139.5 million (for an effective rate of 7.946% based on the fair value on the Transaction date). The Senior Secured Notes are secured on a second-priority lien on the same assets subject to the liens securing our obligations under the Credit Agreement.

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

At March 31, 2011, we were in compliance with financial covenants under the Credit Agreement.

(13) Subsequent Events

In April 2011, we provided the notice required by the Senior Secured Notes to redeem all of such notes at a price of 100% of the principal amount plus accrued but unpaid interest. As of March 31, 2011, $139.5 million principal amount of Senior Secured Notes was outstanding. We expect the redemption to occur on May 24, 2011. The redemption will result in a gain on the early extinguishment of debt of approximately $1.3 million. The financial statements have not been adjusted to give effect to such extinguishment.

In May 2011, we entered into transactions which increased the fixed price to be received on approximately 50% of our existing oil swaps covering (i) 52,416 barrels for the remainder of 2011 from $28.77 per barrel to $105.00 per barrel, (ii) 68,964 barrels for 2012 from $28.70 per barrel to $105.00 per barrel, and (iii) 63,564 barrels for 2013 from $28.70 to $102.00 per barrel. As consideration for such increases in the fixed price of such swaps, we made a payment of $14.1 million to the hedge counterparty.

There are no other subsequent events which require recognition or disclosure in these condensed consolidated financial statements.

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

Forward-Looking Information

This Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act (each a “forward-looking statement”). These forward-looking statements relate to, among other things, the following:

	•		our future financial and operating performance and results;
	•		our business strategy;
	•		our estimated net proved reserves and standardized measure;
	•		market prices;
	•		our future derivative activities; and
	•		our plans and forecasts.

We have based these forward-looking statements on our current assumptions, expectations and projections about future events.

The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “may,” “likely” and similar expressions, and the negative thereof, are intended to identify forward-looking statements. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. We do not undertake any obligation to update or revise publicly any forward-looking statements, except as required by law. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations in this Form 10-Q including, but not limited to:

	•		fluctuations in prices of oil and natural gas;
	•		significant disruptions in the financial markets;
	•		future capital requirements and availability of financing;
	•		uncertainty inherent in estimating our reserves;
	•		risks associated with drilling and operating wells;
	•		discovery, acquisition, development and replacement of oil and natural gas reserves;
	•		cash flows and liquidity;
	•		timing and amount of future production of oil and natural gas;
	•		availability of drilling and production equipment;
	•		marketing of oil and natural gas;
	•		developments in oil and natural gas producing countries;

	•		competition;
	•		general economic conditions;
	•		governmental regulations;
	•		receipt of amounts owed to us by purchasers of our production and counterparties to our derivative financial instrument contracts;
	•		hedging decisions, including whether or not to enter into derivative financial instruments;
	•		events similar to those of September 11, 2001;
	•		actions of third party co-owners of interest in properties in which we also own an interest;
	•		fluctuations in interest rates and the value of the U.S. dollar in international currency markets; and
	•		our ability to effectively integrate companies and properties that we acquire.

All of our forward-looking information is subject to risks and uncertainties that could cause actual results to differ materially from the results expected. Although it is not possible to identify all factors, these risks and uncertainties include the risk factors and the timing of any of those risk factors identified in the “Risk Factors” section in our Annual Report on Form 10-K for the year ended December 31, 2010. 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.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for oil and natural gas. Declines in oil or natural gas prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower oil or natural gas prices also may reduce the amount of oil or natural gas that we can produce economically. A decline in oil and/or natural gas prices could have a material adverse effect on the estimated value and estimated quantities of our oil and natural gas reserves, our ability to fund our operations and our financial condition, cash flows, results of operations and access to capital. Historically, oil and natural gas prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

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 March 31,
		2011				2010
Production
Gas (Mmcf)			2,497				2,603
Oil (Mbbls)			68				67
Total production (Mmcfe)			2,903				3,006
Average price (1)
Gas (per Mcf)		$	3.27			$	4.13
Oil (per Bbl)			89.01				73.28
Mcfe			4.88				5.22
Average costs (per Mcfe)
Production expense		$	1.93			$	1.65
Production taxes			0.10				0.11
Depletion			2.49				2.58

		Three months ended March 31,
		2011				2010
Gas (per Mcf)		$	4.36			$	5.41
Oil (per Bbl)			89.01				73.28
Mcfe			5.82				6.32

First Quarters of 2011 and 2010 Compared

Revenues

Net operating revenues decreased from $17.4 million in the first quarter of 2010 to $15.7 million in the first quarter of 2011. The decrease was primarily due to lower oil and gas sales revenues of $1.5 million and lower gas gathering and marketing revenues of $171,000.

Gas volumes sold decreased approximately 106,000 Mcf (4%) from 2.6 Bcf in the first quarter of 2010 to 2.5 Bcf in the first quarter of 2011 resulting in a decrease in gas sales revenues of approximately $440,000. Oil volumes sold increased approximately 500 Bbls (1%) from 67,000 Bbls in the first quarter of 2010 to 67,500 Bbls in the first quarter of 2011 resulting in an increase in oil sales revenues of approximately $33,000. The lower gas volumes were primarily due to the normal production declines of base wells in 2010, which was partially offset by production from new wells drilled in 2010 and additional working interest acquired in our Michigan wells during the fourth quarter of 2010. The higher oil volumes were primarily due to production from new wells drilled in 2010 and maintenance work performed in the first quarter of 2011, which was partially offset by normal production declines.

The average price realized for our natural gas decreased $0.86 per Mcf from $4.13 in the first

quarter of 2010 to $3.27 per Mcf in the first quarter of 2011, which decreased gas sales revenues by approximately $2.1 million. As a result of our previously qualified effective hedging activities, gas sales revenues were lower by $2.7 million ($1.09 per Mcf) in the first quarter of 2011 and lower by $3.3 million ($1.28 per Mcf) in the first quarter of 2010 than if our gas was not hedged. The average price realized for our oil increased from $73.28 per Bbl in the first quarter of 2010 to $89.01 per Bbl in the first quarter of 2011, which increased oil sales revenues by approximately $1.1 million.

Gas gathering and marketing revenues decreased approximately $171,000 from $1.6 million in the first quarter of 2010 to $1.4 million in the first quarter of 2011 due to a $29,000 decrease in gas marketing revenues and a $142,000 decrease in gas gathering revenues. The lower gas gathering and marketing revenues were primarily due to lower gas volumes and lower natural gas prices in the first quarter of 2011 as compared to the first quarter of 2010.

Costs and Expenses

Production expense increased from $5.0 million in the first quarter of 2010 to $5.6 million in the first quarter of 2011. The average production cost was $1.65 per Mcfe in the first quarter of 2010 and $1.93 in the first quarter of 2011. Production expenses were higher in the first quarter of 2011 primarily due to an increase in well maintenance expense to take advantage of higher oil prices and the additional working interest acquired in our Michigan wells during the fourth quarter of 2010.

Production taxes decreased $50,000 from $335,000 in the first quarter of 2010 to $285,000 in the first quarter of 2011. Average per unit production taxes decreased from $0.11 per Mcfe in the first quarter of 2010 to $0.10 per Mcfe in the first quarter of 2011. The decreased production taxes are primarily due to lower gas prices in Michigan, where production taxes are based on a percentage of revenues, excluding the effects of hedging.

Exploration expense increased $359,000 from $141,000 in the first quarter of 2010 to $500,000 in the first quarter of 2011. This increase was primarily due to an increase in seismic expenditures related to our Knox formation drilling plans.

General and administrative expense decreased $214,000 from $1.8 million in the first quarter of 2010 to $1.6 million in the first quarter of 2011. This decrease was primarily due to a decrease in bad debt expense in the first quarter of 2011.

Depreciation, depletion and amortization decreased by $587,000 from $7.8 million in the first quarter of 2010 to $7.3 million in the first quarter of 2011. This decrease was primarily due to a decrease in depletion expense. Depletion expense decreased $545,000 (7%) from $7.8 million in the first quarter of 2010 to $7.2 million in the first quarter of 2011 primarily due to the lower gas volumes discussed above. Depletion per Mcfe decreased from $2.58 per Mcfe in the first quarter of 2010 to $2.49 per Mcfe in the first quarter of 2011. The decrease in depletion per Mcfe was primarily due to an increase in our oil and gas reserves as of December 31, 2010 due to higher oil and gas prices compared to December 31, 2009.

Gain on sale of assets was $2.4 million in the first quarter of 2011 due to the sale of undeveloped oil and gas properties in Pennsylvania.

Derivative fair value (gain) loss was a loss of $4.1 million in the first quarter of 2011 compared to a gain of $24.1 million in the first quarter of 2010 due to the fluctuation in oil and gas prices in the first quarters of 2010 and 2011. The derivative fair value (gain) loss reflects the changes in fair value of certain derivative instruments that are not designated or do not qualify as cash flow hedges and the cash settlements on those hedges.

Interest expense decreased $605,000 from $5.0 million in the first quarter of 2010 to $4.4 million

in the first quarter of 2011. This decrease was primarily due to lower debt levels in 2011.

Income tax provision decreased from a tax provision of $577,000 in the first quarter of 2010 to a tax benefit of $2.1 million in the first quarter of 2011. The decrease was primarily due to a decrease in income before income taxes as a result of a decrese in the derivative fair value gain. This was partially offset by a higher effective tax rate as a result of an increase in the valuation allowance.

Liquidity and Capital Resources

Cash Flows

The primary sources of cash in the first quarter of 2011 were funds generated from operations. Funds used during this period were primarily used for operations, development expenditures and interest expense. Our liquidity and capital resources are closely related to and dependent upon the current prices paid for our oil and natural gas.

Our operating activities provided cash flows of $2.5 million during the first quarter of 2011 compared to $2.3 million in the first quarter of 2010. The increase was primarily due to changes in working capital items of $1.3 million.

Cash flows used in investing activities were $3.5 million in the first quarter of 2011 compared to $881,000 in the first quarter of 2010. The increase was primarily due to an increase in additions to property and equipment of $4.7 million partially offset by an increase in the proceeds from property and equipment disposals of $2.4 million.

Cash flows used in financing activities were $1.8 million in the first quarter of 2011 compared to $3.8 million in the first quarter of 2010. The decrease was primarily due to a $2.1 million decrease in the settlement of derivative liabilities.

Our current ratio at March 31, 2011 was 1.49 to 1. During the first quarter of 2011, the working capital increased $2.5 million from $13.6 million at December 31, 2010 to $16.1 million at March 31, 2011. The increase was primarily due to a decrease in accrued expenses of $7.2 million and a decrease in the deferred tax asset of $1.0 million, which were partially offset by a decrease in cash of $2.8 million and an increase in the current liability related to the fair value of derivatives of $2.5 million.

Capital Expenditures

During the first quarter of 2011, we spent approximately $5.3 million on our drilling activities and other capital expenditures. We currently expect to spend approximately $15.8 million during 2011 on drilling and other capital expenditures. We intend to finance our planned capital expenditures through our cash on hand and available operating cash flow. At March 31, 2011, we had cash of $33.2 million. The level of our future cash flow will depend on a number of factors including the demand for and price levels of oil and gas, the scope and success of our drilling activities and our ability to acquire additional producing properties. There can be no assurance that the future drilling of our proved undeveloped locations will provide adequate liquidity in the future.

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 (“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 Credit Agreement are secured by substantially all of our assets.

At March 31, 2010, we had a Credit Agreement comprised of a $90 million revolving facility with a borrowing base of $55 million, of which $23.9 million was outstanding at March 31, 2010, 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. This facility is for working capital requirements and general corporate purposes, including the issuance of letters of credit. Borrowings under the 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 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 Credit Agreement. The full amount borrowed under the Credit Agreement will mature on April 14, 2012.

In connection with our entry into the 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 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”).

The Senior Secured Notes mature on July 15, 2012 and are secured on a second-priority lien on the same assets subject to the liens securing our obligations under the Credit Agreement. Interest is payable semi-annually on January 15 and July 15 of each year at 8.75% based on the face amount of $139.5 million (for an effective rate of 7.946% based on the fair value on the Transaction date).

In April 2011, we provided the notice required by our Indenture to redeem all of such notes at a price of 100% of the principal amount plus accrued but unpaid interest. As of March 31, 2011, $139.5 million principal amount of Senior Secured Notes was outstanding. We expect the redemption to occur on May 24, 2011. The redemption will result in a gain on the early extinguishment of debt of approximately $1.3 million.

We are working with our bank group to refinance our Credit Agreement in conjunction with the redemption process. We have commitments from our bank group to provide the funding necessary to redeem the Senior Secured Notes, subject to a number of conditions we expect to meet prior to the redemption. We can provide no assurance that we will complete the refinancing of our Credit Agreement. Following this transaction, we will no longer have any notes outstanding and we will no longer be required to make filings with the SEC.

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 March 31, 2011, we had an interest rate swap in place on $23.5 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 $23.5 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 quarterly interest expense would be approximately $60,000. 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 March 31, 2011.

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 March 31, 2011, 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 $3.3 million in the first three months of 2010 and a net pre-tax loss of $2.7 million in the first three months of 2011 on our previously qualified effective oil and gas hedges.

In May 2011, in recognition of the current market conditions and in an effort to better mitigate risk to our anticipated cash flows through 2013, we entered into transactions which increased the fixed price to be received on approximately 50% of our existing oil swaps covering (i) 52,416 barrels for the remainder of 2011 from $28.77 per barrel to $105.00 per barrel, (ii) 68,964 barrels for 2012 from $28.70 per barrel to $105.00 per barrel, and (iii) 63,564 barrels for 2013 from $28.70 to $102.00 per barrel. As consideration for such increases in the fixed price of such swaps, we made a payment of $14.1 million to the hedge counterparty.

If gas prices decreased $0.50 per Mcf, our gas sales revenues for the quarter would decrease by approximately $1.2 million. If the price of crude oil decreased $10.00 per Bbl, our oil sales revenues for the quarter would decrease by approximately $677,000. The impact of these price decreases on our cash flows would be significantly less than these amounts due to our oil and gas derivatives. Price decreases of $0.50 per Mcf and $10.00 per Bbl would decrease cash flows from the sale of oil and gas for the quarter by approximately $503,000 after considering the effects of the derivative contracts in place as of March 31, 2011. This sensitivity analysis is based on our first quarter 2011 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 March 31, 2011:

		Natural Gas Swaps								Crude Oil Swaps
						NYMEX								NYMEX				Natural Gas Basis Swaps
						Price per								Price per								Basis
		Bbtu				Mmbtu				Mbbls				Bbl				Bbtu				Differential
Quarter Ending
June 30, 2011			2,057			$	4.00				50			$	46.33				1,943			$	0.196
September 30, 2011			2,058				4.01				51				46.47				1,964				0.196
December 31, 2011			2,058				4.26				51				46.47				1,964				0.196
			6,173			$	4.09				152			$	46.42				5,871			$	0.196
Year Ending
December 31, 2012			7,005			$	4.09				184			$	47.83				6,991			$	0.086
December 31, 2013			6,528				4.04				164				45.33

The fair value of our oil and gas swaps was a net liability of approximately $41.9 million as of March 31, 2011.

At March 31, 2011, we had interest rate swaps in place through September 30, 2013 covering $23.5 million of our outstanding debt under the revolving credit facility, which currently matures on April 14, 2012. The swaps provide 1-month LIBOR fixed rates at 4.10% plus the applicable margin.

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 March 31, 2011 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 March 31, 2011 that has materially affected, or is 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

There have been no significant 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, 2010.

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

The exhibits listed below are filed or furnished as part of this report:

+31.1		Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
+31.2		Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
+32.1		Section 1350 Certification of Chief Executive Officer
+32.2		Section 1350 Certification of Chief Financial Officer

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.