##### Table of Contents



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 1934For the quarterly period ended March 31, 2005   o
    Transition Report Pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934For the transition period from ________________________ to _______________________ Commission File Number:  0-20100 BELDEN & BLAKE CORPORATION 
  Ohio
    
    34-1686642(State or other jurisdiction of
incorporation or organization)
    
    (I.R.S. Employer
Identification No.)
 5200 Stoneham Road
North Canton, Ohio
    
    44720(Address of principal executive offices)
    
    (Zip Code)
 (330) 499-1660 
     Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. þ Yes o No Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule
12b-2 of the Act). o Yes þ No As of April 30, 2005, Belden & Blake Corporation had outstanding 1,500 shares of common stock,
without par value, which is its only class of stock.




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BELDEN & BLAKE CORPORATION INDEX   PagePART I Financial InformationItem 1. Financial StatementsConsolidated Balance Sheets as of March 31, 2005 and December 31, 2004
    
    
    1Consolidated Statements of Operations:Three months ended March 31, 2005 (Successor Company)Three months ended March 31, 2004 (Predecessor Company)
    
    
    2Consolidated Statements of Shareholders Equity (Deficit):Three months ended March 31, 2005 (Successor Company)183 day period from July 2, 2004 to December 31, 2004 (Successor Company)183 day period From January 1, 2004 to July 1, 2004 (Predecessor Company)and the year ended December 31, 2003 (Predecessor Company)
    
    
    3Consolidated Statements of Cash Flows:Three months ended March 31, 2005 (Successor Company)Three months ended March 31, 2004 (Predecessor Company)
    
    
    4Notes to Consolidated Financial Statements
    
    
    5Item 2. Managements Discussion and Analysis of Financial
Condition and Results of Operations
    
    
    9Item 3. Quantitative and Qualitative Disclosures About Market Risk
    
    
    16Item 4. Controls and Procedures
    
    
    18PART II Other InformationItem 1. Legal Proceedings
    
    
    18Item 4. Submission of Matters to a Vote of Security Holders
    
    
    18Item 6. Exhibits
    
    
    19EX-31.1 Certification of Principal Executive OfficerEX-31.2 Certification of Principal Financial OfficerEX-32.1 Certification of Chief Executive OfficerEX-32.2 Certification of Chief Financial Officer




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PART I. FINANCIAL INFORMATION 
 Item 1. Financial Statements BELDEN & BLAKE CORPORATION 
 CONSOLIDATED BALANCE SHEETS
 (in thousands, except share data)
 March 31,
    
    
    December 31,2005
    
    
    2004(unaudited)ASSETSCurrent assetsCash and cash equivalents
    
    $
    15,388
    
    
    $
    18,407Accounts receivable, net
    
    
    15,710
    
    
    
    18,667Inventories
    
    
    550
    
    
    
    518Deferred income taxes
    
    
    17,679
    
    
    
    10,558Other current assets
    
    
    1,271
    
    
    
    1,101Total current assets
    
    
    50,598
    
    
    
    49,251Property and equipment, at costOil and gas properties (successful efforts method)
    
    
    520,792
    
    
    
    514,242Gas gathering systems
    
    
    5,106
    
    
    
    4,485Land, buildings, machinery and equipment
    
    
    7,796
    
    
    
    7,720533,694
    
    
    
    526,447Less accumulated depreciation, depletion and amortization
    
    
    24,861
    
    
    
    16,917Property and equipment, net
    
    
    508,833
    
    
    
    509,530Other assets
    
    
    11,076
    
    
    
    11,461$
    570,507
    
    
    $
    570,242LIABILITIES AND SHAREHOLDERS EQUITYCurrent liabilitiesAccounts payable
    
    $
    5,141
    
    
    $
    3,796Accrued expenses
    
    
    16,413
    
    
    
    23,445Current portion of long-term liabilities
    
    
    1,965
    
    
    
    1,964Fair value of derivatives
    
    
    42,232
    
    
    
    23,252Total current liabilities
    
    
    65,751
    
    
    
    52,457Long-term liabilitiesBank and other long-term debt
    
    
    88,340
    
    
    
    88,592Senior secured notes
    
    
    192,500
    
    
    
    192,500Asset retirement obligations and other long-term liabilities
    
    
    14,704
    
    
    
    14,390295,544
    
    
    
    295,482Fair value of derivatives
    
    
    123,074
    
    
    
    55,182Deferred income taxes
    
    
    83,148
    
    
    
    108,994Shareholders equityCommon stock: without par value; 1,500 shares authorized and
issued
    
    
    
    
    
    
    Paid in capital
    
    
    77,500
    
    
    
    77,500(Deficit) retained earnings
    
    
    (4,014
    )
    
    
    890Accumulated other comprehensive loss
    
    
    (70,496
    )
    
    
    (20,263
    )Total shareholders equity
    
    
    2,990
    
    
    
    58,127$
    570,507
    
    
    $
    570,242
 See accompanying notes. 1




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BELDEN & BLAKE CORPORATION 
 CONSOLIDATED STATEMENTS OF OPERATIONS
 (unaudited, in thousands)
 Successor
    
    
    
    
    
    
    
    
    
    
    
    PredecessorCompany
    
    
    
    
    
    
    
    
    
    
    
    CompanyThree months
    
    
    
    
    
    
    
    
    
    
    
    Three monthsended March 31,
    
    
    
    
    
    
    
    
    
    
    
    ended March 31,2005
    
    
    
    
    
    
    
    
    
    
    
    2004RevenuesOil and gas sales
    
    $
    21,638
    
    
    
    
    
    
    
    
    
    
    
    $
    22,362Gas gathering and marketing
    
    
    2,443
    
    
    
    
    
    
    
    
    
    
    
    
    2,583Other
    
    
    107
    
    
    
    
    
    
    
    
    
    
    
    
    12924,188
    
    
    
    
    
    
    
    
    
    
    
    
    25,074ExpensesProduction expense
    
    
    5,420
    
    
    
    
    
    
    
    
    
    
    
    
    5,406Production taxes
    
    
    734
    
    
    
    
    
    
    
    
    
    
    
    
    652Gas gathering and marketing
    
    
    2,106
    
    
    
    
    
    
    
    
    
    
    
    
    2,232Exploration expense
    
    
    952
    
    
    
    
    
    
    
    
    
    
    
    
    1,349General and administrative expense
    
    
    1,764
    
    
    
    
    
    
    
    
    
    
    
    
    1,235Franchise, property and other taxes
    
    
    54
    
    
    
    
    
    
    
    
    
    
    
    
    70Depreciation, depletion and amortization
    
    
    8,305
    
    
    
    
    
    
    
    
    
    
    
    
    4,554Accretion expense
    
    
    255
    
    
    
    
    
    
    
    
    
    
    
    
    95Derivative fair value (gain) loss
    
    
    6,777
    
    
    
    
    
    
    
    
    
    
    
    
    (332
    )26,367
    
    
    
    
    
    
    
    
    
    
    
    
    15,261Operating (loss) income
    
    
    (2,179
    )
    
    
    
    
    
    
    
    
    
    
    
    9,813Other expenseInterest expense
    
    
    5,830
    
    
    
    
    
    
    
    
    
    
    
    
    6,072(Loss) income from continuing operations before income taxes
    
    
    (8,009
    )
    
    
    
    
    
    
    
    
    
    
    
    3,741(Benefit) provision for income taxes
    
    
    (3,105
    )
    
    
    
    
    
    
    
    
    
    
    
    1,375(Loss) income from continuing operations
    
    
    (4,904
    )
    
    
    
    
    
    
    
    
    
    
    
    2,366Loss from discontinued operations, net of tax
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (314
    )Net (loss) income
    
    $
    (4,904
    )
    
    
    
    
    
    
    
    
    
    
    $
    2,052
 See accompanying notes. 2




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BELDEN & BLAKE CORPORATION 
 CONSOLIDATED STATEMENTS OF SHAREHOLDERS EQUITY (DEFICIT)
 (in thousands)
 AccumulatedSuccessor Company
    
    
    Predecessor Company
    
    
    
    
    
    
    
    
    
    
    Other
    
    
    TotalCommon
    
    
    Common
    
    
    Common
    
    
    Common
    
    
    Paid in
    
    
    Equity
    
    
    Comprehensive
    
    
    EquityShares
    
    
    Stock
    
    
    Shares
    
    
    Stock
    
    
    Capital
    
    
    (Deficit)
    
    
    Income
    
    
    (Deficit)Predecessor Company:January 1, 2003
    
    
    
    
    
    
    
    
    
    
    10,296
    
    
    $
    1,030
    
    
    $
    107,118
    
    
    $
    (148,332
    )
    
    $
    (4,461
    )
    
    $
    (44,645
    )Comprehensive (loss) income:Net loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (2,324
    )
    
    
    
    
    
    
    (2,324
    )Other comprehensive income (loss), net of tax:Change in derivative fair value
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (17,439
    )
    
    
    (17,439
    )Reclassification adjustment for derivative (gain) loss
reclassified into oil and gas sales
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    6,543
    
    
    
    6,543Total comprehensive loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (13,220
    )Stock options exercised
    
    
    
    
    
    
    
    
    
    
    120
    
    
    
    12
    
    
    
    108
    
    
    
    
    
    
    
    
    
    
    
    120Stock-based compensation
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    326
    
    
    
    
    
    
    
    
    
    
    
    326Repurchase of stock options
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (48
    )
    
    
    
    
    
    
    
    
    
    
    (48
    )Tax benefit of repurchase of stock options
and stock options exercised
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    170
    
    
    
    
    
    
    
    
    
    
    
    170Treasury stock
    
    
    
    
    
    
    
    
    
    
    (20
    )
    
    
    (2
    )
    
    
    (41
    )
    
    
    
    
    
    
    
    
    
    
    (43
    )December 31, 2003
    
    
    
    
    
    
    
    
    
    
    10,396
    
    
    
    1,040
    
    
    
    107,633
    
    
    
    (150,656
    )
    
    
    (15,357
    )
    
    
    (57,340
    )Comprehensive income (loss):Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    11,834
    
    
    
    
    
    
    
    11,834Other comprehensive income (loss), net of tax:Change in derivative fair value
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (11,180
    )
    
    
    (11,180
    )Reclassification adjustment for derivative (gain) loss
reclassified into oil and gas sales
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    5,512
    
    
    
    5,512Total comprehensive income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    6,166Stock options exercised
    
    
    
    
    
    
    
    
    
    
    65
    
    
    
    6
    
    
    
    105
    
    
    
    
    
    
    
    
    
    
    
    111Stock-based compensation
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,097
    
    
    
    
    
    
    
    
    
    
    
    1,097Repurchase of stock options
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (283
    )
    
    
    
    
    
    
    
    
    
    
    (283
    )Tax benefit of repurchase of stock options
and stock options exercised
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    116
    
    
    
    
    
    
    
    
    
    
    
    116Treasury stock
    
    
    
    
    
    
    
    
    
    
    (6
    )
    
    
    (1
    )
    
    
    (28
    )
    
    
    
    
    
    
    
    
    
    
    (29
    )Redemption of common stock
    
    
    
    
    
    
    
    
    
    
    (10,455
    )
    
    
    (1,045
    )
    
    
    (108,640
    )
    
    
    138,822
    
    
    
    21,025
    
    
    
    50,162July 1, 2004
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Successor Company:Sale of common stock
    
    
    2
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    77,500
    
    
    
    
    
    
    
    
    
    
    
    77,500Comprehensive income (loss):Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    890
    
    
    
    
    
    
    
    890Other comprehensive income (loss), net of tax:Change in derivative fair value
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (28,919
    )
    
    
    (28,919
    )Reclassification adjustment for derivative (gain) loss
reclassified into oil and gas sales
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    8,656
    
    
    
    8,656Total comprehensive loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (19,373
    )December 31, 2004
    
    
    2
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    77,500
    
    
    
    890
    
    
    
    (20,263
    )
    
    
    58,127Comprehensive income (loss):Net loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (4,904
    )
    
    
    
    
    
    
    (4,904
    )Other comprehensive income (loss), net of tax:Change in derivative fair value
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (54,079
    )
    
    
    (54,079
    )Reclassification adjustment for derivative (gain) loss
reclassified into oil and gas sales
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3,846
    
    
    
    3,846Total comprehensive loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (55,137
    )March 31, 2005 (unaudited)
    
    
    2
    
    
    $
    
    
    
    
    
    
    
    $
    
    
    
    $
    77,500
    
    
    $
    (4,014
    )
    
    $
    (70,496
    )
    
    $
    2,990
 See accompanying notes. 3




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BELDEN & BLAKE CORPORATION 
 CONSOLIDATED STATEMENTS OF CASH FLOWS
 (unaudited, in thousands)
 Successor
    
    
    
    
    
    
    
    
    
    
    
    PredecessorCompany
    
    
    
    
    
    
    
    
    
    
    
    CompanyThree months
    
    
    
    
    
    
    
    
    
    
    
    Three monthsended March 31,
    
    
    
    
    
    
    
    
    
    
    
    ended March 31,2005
    
    
    
    
    
    
    
    
    
    
    
    2004Cash flows from operating activities:(Loss) income from continuing operations
    
    $
    (4,904
    )
    
    
    
    
    
    
    
    
    
    
    $
    2,366Adjustments to reconcile income from continuing operations
to net cash provided by operating activities:Depreciation, depletion and amortization
    
    
    8,305
    
    
    
    
    
    
    
    
    
    
    
    
    4,554Accretion expense
    
    
    255
    
    
    
    
    
    
    
    
    
    
    
    
    95Loss on disposal of property and equipment
    
    
    12
    
    
    
    
    
    
    
    
    
    
    
    
    325Amortization of derivatives and other noncash hedging activities
    
    
    6,777
    
    
    
    
    
    
    
    
    
    
    
    
    (697
    )Exploration expense
    
    
    952
    
    
    
    
    
    
    
    
    
    
    
    
    1,349Deferred income taxes
    
    
    (3,105
    )
    
    
    
    
    
    
    
    
    
    
    
    1,375Stock-based compensation
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    19Change in operating assets and liabilities, net of
effects of acquisition and disposition of businesses:Accounts receivable and other operating assets
    
    
    2,787
    
    
    
    
    
    
    
    
    
    
    
    
    (849
    )Inventories
    
    
    8
    
    
    
    
    
    
    
    
    
    
    
    
    (99
    )Accounts payable and accrued expenses
    
    
    (5,648
    )
    
    
    
    
    
    
    
    
    
    
    
    4,161Net cash provided by continuing operations
    
    
    5,439
    
    
    
    
    
    
    
    
    
    
    
    
    12,599Cash flows from investing activities:Proceeds from property and equipment disposals
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    41Exploration expense
    
    
    (952
    )
    
    
    
    
    
    
    
    
    
    
    
    (1,349
    )Additions to property and equipment
    
    
    (7,214
    )
    
    
    
    
    
    
    
    
    
    
    
    (5,703
    )(Increase) decrease in other assets
    
    
    (14
    )
    
    
    
    
    
    
    
    
    
    
    
    144Net cash used in investing activities
    
    
    (8,180
    )
    
    
    
    
    
    
    
    
    
    
    
    (6,867
    )Cash flows from financing activities:Repayment of senior secured facility  term loan
    
    
    (250
    )
    
    
    
    
    
    
    
    
    
    
    
    Proceeds from revolving line of credit
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    42,366Repayment of long-term debt and other obligations
    
    
    (28
    )
    
    
    
    
    
    
    
    
    
    
    
    (44,488
    )Proceeds from stock options exercised
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    110Repurchase of stock options
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (283
    )Purchase of treasury stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (25
    )Net cash used in financing activities
    
    
    (278
    )
    
    
    
    
    
    
    
    
    
    
    
    (2,320
    )Net (decrease) increase in cash and cash equivalents
from continuing operations
    
    
    (3,019
    )
    
    
    
    
    
    
    
    
    
    
    
    3,412Net decrease in cash and cash equivalents
from discontinued operations
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (3,289
    )Cash and cash equivalents at beginning of period
    
    
    18,407
    
    
    
    
    
    
    
    
    
    
    
    
    1,428Cash and cash equivalents at end of period
    
    $
    15,388
    
    
    
    
    
    
    
    
    
    
    
    $
    1,551
 See accompanying notes. 4




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##### Table of Contents



BELDEN & BLAKE CORPORATION 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
 (unaudited)
 March 31, 2005 
 (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
(Successor Company) and its predecessor. On July 7, 2004, the Company, Capital C Energy
Operations, LP, a Delaware limited partnership (Capital C), and Capital C Ohio, Inc., an Ohio
corporation and a wholly owned subsidiary of Capital C (Merger Sub), completed a merger pursuant
to which Merger Sub was merged with and into the Company (the Merger), with the Company surviving
the Merger as a wholly owned subsidiary of Capital C. The Merger resulted in a change in control
of the Company. The general partner of Capital C is controlled by Carlyle/Riverstone Global Energy
and Power Fund II, L.P. The Merger for financial reporting purposes was accounted for as a purchase effective July 1,
2004. The Merger resulted in a new basis of accounting reflecting estimated fair values for assets
and liabilities at that date. Accordingly, the financial statements for the period subsequent to
July 1, 2004 are presented on the Companys new basis of accounting, while the results of
operations for prior periods reflect the historical results of the predecessor company. A vertical
black line is presented to separate the financial statements of the predecessor and successor
companies. In the second quarter of 2004, we sold substantially all of our Trenton Black River (TBR)
assets and our Arrow Oilfield Service Company (Arrow) assets. According to Statement of
Financial Accounting Standards No. (SFAS) 144, Accounting for the Impairment or Disposal of
Long-Lived Assets, the dispositions were classified as discontinued operations. Discontinued
operations relating to the TBR and Arrow asset sales resulted in a loss of $483,000 ($314,000 net
of tax) in the first quarter of 2004. Total revenue of $4.1 million was reclassified to
discontinued operations in the first quarter of 2004. Historical information has been restated to
remove the TBR and Arrow assets from continuing operations. The accompanying unaudited consolidated financial statements have been prepared in
accordance with generally accepted accounting principles for interim financial information and with
the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include
all of the information and footnotes required by generally accepted accounting principles for
complete financial statements. In the opinion of management, all adjustments (consisting of normal
recurring accruals) considered necessary for a fair presentation have been included. Operating
results for the successor company for the three-month period ended March 31, 2005 are not
necessarily indicative of the results that may be expected for the year ended December 31, 2005.
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, 2004. Certain reclassifications
have been made to conform to the current presentation. (2) Derivatives and Hedging Our financial results and cash flows can be significantly impacted as commodity prices
fluctuate widely in response to changing market conditions. As a result of the adoption of SFAS
133, we recognize all derivative financial instruments as either assets or liabilities at fair
value. Derivative instruments that are not hedges must be adjusted to fair value through net
income (loss). Under the provisions of SFAS 133, changes in the fair value of derivative
instruments that are fair value hedges are offset against 5




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changes in the fair value of the hedged
assets, liabilities, or firm commitments, through net income (loss). Changes in the fair value of
derivative instruments that are cash flow hedges are recognized in other comprehensive income
(loss) until such time as the hedged items are recognized in
net income (loss). Ineffective portions of a derivative instruments change in fair value are
immediately recognized in net income (loss). Deferred gains and losses on terminated commodity
hedges will be recognized as increases or decreases to oil and gas revenues during the same periods
in which the underlying forecasted transactions are recognized in net income (loss). If there is a
discontinuance of a cash flow hedge because it is probable that the original forecasted transaction
will not occur, deferred gains or losses are recognized in earnings immediately. The relationship between the hedging instruments and the hedged items must be highly effective
in achieving the offset of changes in fair values or cash flows attributable to the hedged risk,
both at the inception of the contract and on an ongoing basis. Ongoing assessments of hedge
effectiveness will include verifying and documenting that the critical terms of the hedge and
forecasted transaction do not change. We measure effectiveness at least on a quarterly basis. 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 natural gas or crude oil price
volatility and support our capital expenditure plans. Our derivative financial instruments
primarily take the form of swaps or collars. At March 31, 2005, our derivative contracts were
comprised of natural gas swaps and collars and crude oil swaps, which were placed with a major
financial institution that we believe is a minimal credit risk. Qualifying derivative financial
instruments are designated as cash flow hedges. The changes in fair value of non-qualifying
derivative contracts will be initially reported in expense in the consolidated statements of
operations as derivative fair value (gain) loss and will ultimately be reversed within the same
line item and included in oil and gas sales over the respective contract terms. We consider our natural gas swaps to be highly effective and expect there will be no
ineffectiveness to be recognized in net income (loss) since the critical terms of the hedging
instruments and the hedged forecasted transactions are the same. We have not experienced
ineffectiveness on our natural gas swaps because we use New York Mercantile Exchange (NYMEX)
based commodity derivative contracts to hedge on the same basis as our natural gas production is
sold (NYMEX-based sales contracts). We have collar agreements that could not be redesignated as
cash flow hedges because these collars were not effective due to unrealized losses at the date of
the Merger. These collars qualified and were designated as cash flow hedges from their inception
through the predecessor company period ended July 1, 2004. Although these collars are not deemed to
be effective hedges in accordance with the provisions of SFAS 133, we have retained these
instruments as protection against changes in commodity prices and we will continue to record the
mark-to-market adjustments on these natural gas collars, through 2005, in our income statement. Our
NYMEX crude oil swaps are highly effective and were designated as cash flow hedges. We have
ineffectiveness on the crude oil swaps because the oil is sold locally at a posted price which is
different from the NYMEX price. Historically there has been a high correlation between the posted
price and NYMEX. The changes in the fair values of the natural gas collars and the ineffective
portion of the crude oil swaps are recorded as Derivative fair value (gain) loss. During the first three months of 2005 and 2004, a net loss of $6.1 million ($3.8 million after
tax) and a net loss of $3.9 million ($2.5 million after tax), respectively, were reclassified from
accumulated other comprehensive income to earnings. The fair value of open hedges decreased $86.2
million ($54.1 million after tax) in the first three months of 2005 and decreased $11.0 million
($7.0 million after tax) in the first three months of 2004. At March 31, 2005, the estimated net
loss in accumulated other comprehensive income that is expected to be reclassified into earnings
within the next 12 months is approximately $20.5 million. At March 31, 2005, we have partially
hedged our exposure to the variability in future cash flows through December 2013. 6




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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 March 31, 2005: Natural Gas Swaps
    
    
    Natural Gas Collars
    
    
    Crude Oil SwapsNYMEX
    
    
    
    
    
    
    NYMEX Price perPrice per
    
    
    
    
    
    
    Mmbtu Floor/Cap
    
    
    
    
    
    
    NYMEX PriceBbtu
    
    
    Mmbtu
    
    
    Bbtu
    
    
    (1)
    
    
    Mbbls
    
    
    per BblQuarter EndingJune 30, 2005
    
    
    1,500
    
    
    $
    3.70
    
    
    
    1,500
    
    
    $
    4.00 - 5.32
    
    
    
    68
    
    
    $
    34.18September 30, 2005
    
    
    1,500
    
    
    
    3.70
    
    
    
    1,500
    
    
    
    4.00 - 5.32
    
    
    
    67
    
    
    
    33.72December 31, 2005
    
    
    1,500
    
    
    
    3.70
    
    
    
    1,500
    
    
    
    4.00 - 5.32
    
    
    
    67
    
    
    
    33.314,500
    
    
    $
    3.70
    
    
    
    4,500
    
    
    $
    4.00 - 5.32
    
    
    
    202
    
    
    $
    33.74March 31, 2006
    
    
    2,829
    
    
    $
    6.14
    
    
    
    
    
    
    
    
    
    
    
    63
    
    
    $
    32.71June 30, 2006
    
    
    2,829
    
    
    
    5.24
    
    
    
    
    
    
    
    
    
    
    
    62
    
    
    
    32.35September 30, 2006
    
    
    2,829
    
    
    
    5.22
    
    
    
    
    
    
    
    
    
    
    
    62
    
    
    
    32.02December 31, 2006
    
    
    2,829
    
    
    
    5.39
    
    
    
    
    
    
    
    
    
    
    
    62
    
    
    
    31.7111,316
    
    
    $
    5.50
    
    
    
    
    
    
    
    
    
    
    
    249
    
    
    $
    32.20Year EndingDecember 31, 2007
    
    
    10,745
    
    
    $
    4.97
    
    
    
    
    
    
    
    
    
    
    
    227
    
    
    $
    30.91December 31, 2008
    
    
    10,126
    
    
    
    4.64
    
    
    
    
    
    
    
    
    
    
    
    208
    
    
    
    29.96December 31, 2009
    
    
    9,529
    
    
    
    4.43
    
    
    
    
    
    
    
    
    
    
    
    191
    
    
    
    29.34December 31, 2010
    
    
    8,938
    
    
    
    4.28
    
    
    
    
    
    
    
    
    
    
    
    175
    
    
    
    28.86December 31, 2011
    
    
    8,231
    
    
    
    4.19
    
    
    
    
    
    
    
    
    
    
    
    157
    
    
    
    28.77December 31, 2012
    
    
    7,005
    
    
    
    4.09
    
    
    
    
    
    
    
    
    
    
    
    138
    
    
    
    28.70December 31, 2013
    
    
    6,528
    
    
    
    4.04
    
    
    
    
    
    
    
    
    
    
    
    127
    
    
    
    28.70
 Bbl  Barrel
    
    Mmbtu  Million British thermal unitsMbbls  Thousand barrels
    
    Bbtu  Billion British thermal units
   (1)
The NYMEX price per Mmbtu floor/cap for the natural gas collars in 2005
assume the monthly NYMEX settles at $3.10 per Mmbtu or higher. If the monthly NYMEX settles at
less than $3.10 per Mmbtu then the NYMEX price per Mmbtu will be the
NYMEX settle plus $0.90. (3) Stock-Based Compensation We measure expense associated with stock-based compensation under the provisions of Accounting
Principles Board Opinion No. (APB) 25, Accounting for Stock Issued to Employees and its related
interpretations. Under APB 25, no compensation expense is required to be recognized upon the
issuance of stock options to key employees as the exercise price of the option is equal to the
market price of the underlying common stock at the date of grant. For purposes of the pro forma disclosures required by SFAS 123, Accounting for Stock Based
Compensation, the estimated fair value of the options is amortized to expense over the options
vesting period. The changes in net income or loss as if we had applied the fair value provisions
of SFAS 123 for the predecessor company for the three-month ended March 31, 2004 were not material.
The successor company does not have any stock options. The changes in share value and the vesting of shares are reported as adjustments to
compensation expense. The vesting of shares in the predecessor company quarter ended March 31,
2004, resulted in a non-cash increase in compensation expense of $19,000. The successor company
does not have any stock-based compensation. 7




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(4) 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. (5) Supplemental Disclosure of Cash Flow Information Successor
    
    
    
    
    
    
    
    
    
    
    
    PredecessorCompany
    
    
    
    
    
    
    
    
    
    
    
    CompanyThree months
    
    
    
    
    
    
    
    
    
    
    
    Three monthsended March 31,
    
    
    
    
    
    
    
    
    
    
    
    ended March 31,(in thousands)
    
    2005
    
    
    
    
    
    
    
    
    
    
    
    2004Cash paid during the period for:Interest
    
    $
    10,398
    
    
    
    
    
    
    
    
    
    
    
    $
    981Income taxes
    
    
    500
    
    
    
    
    
    
    
    
    
    
    
    
    
 (6) Contingencies In April 2002, we were notified of a claim by an overriding royalty owner in Michigan alleging
the underpayment of royalties resulting from disputes as to the interpretation of the terms of
several farmout agreements. On July 6, 2004, a suit was filed in Otsego County, Michigan by the
successor in interest to these royalty interests, alleging substantially the same underpayments.
In April 2005, we entered into a settlement agreement that provides for a payment to the royalty
owner of an amount approximately equal to the amount accrued at March 31, 2005 and an increase in
the future overriding royalty percentage in several wells. The result will have no material
adverse effect on our financial position, results of operations or cash flows. 8




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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, will, continue, estimate, plan, outlook, may, future,
projection, likely, possible, would, could and variations of these statements and similar
expressions are forward-looking statements as are any other statements relating to developments,
events, occurrences, results, efforts or impacts. These forward-looking statements are based on
current expectations and projections about future events. Forward-looking statements and the
business prospects of Belden & Blake are subject to a number of risks and uncertainties which may
cause our actual results in future periods to differ materially from the forward-looking statements
contained herein. These risks and uncertainties include, but are not limited to, our access to
capital, the market demand for and prices of oil and natural gas, our oil and gas production and
costs of operation, results of our future drilling activities, the uncertainties of reserve
estimates, general economic conditions, new legislation or regulatory changes, changes in
accounting principles, policies or guidelines and environmental risks. These and other risks are
described in our Annual Report on Form 10-K for the year ended December 31, 2004 under the Heading
Risk Factors and in our other filings with the Securities and Exchange Commission (SEC). We
undertake no obligation to publicly update or revise any forward-looking statement, whether as a
result of new information, future events, changes in assumptions, or otherwise. CRITICAL ACCOUNTING POLICIES We prepare our consolidated financial statements in accordance with accounting principles
generally accepted in the United States (GAAP) and SEC guidance. See the Notes to Consolidated
Financial Statements included in Item 8. Financial Statements and Supplementary Data in our
Annual Report on Form 10-K for the year ended December 31, 2004 filed with the SEC for a more
comprehensive discussion of our significant accounting policies. GAAP requires information in
financial statements about the accounting principles and methods used and the risks and
uncertainties inherent in significant estimates including choices between acceptable methods.
Following is a discussion of our most critical accounting policies. Successful Efforts Method of Accounting The accounting for and disclosure of oil and gas producing activities requires our management
to choose between GAAP alternatives and to make judgments about estimates of future uncertainties. We use the successful efforts method of accounting for oil and gas producing activities as
opposed to the alternate acceptable full cost method. Under the successful efforts method,
property acquisition and development costs and certain productive exploration costs are capitalized
while non-productive exploration costs, which include certain geological and geophysical costs,
exploratory dry hole costs and costs of carrying and retaining undeveloped properties, are expensed
as incurred. The geological and geophysical costs include costs for salaries and benefits of our
personnel in those areas and other third party costs. The costs of carrying and retaining
undeveloped properties include salaries and benefits of our land department personnel, delay rental
payments made on new and existing leases, ad valorem taxes on existing leases and the cost of
previously capitalized leases that are written off because the leases were dropped or expired.
Exploratory dry hole costs include the costs associated with drilling an exploratory well that has
been determined to be a dry hole. 9




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The major difference between the successful efforts method of accounting and the full cost
method is under the full cost method of accounting, such exploration costs and expenses are
capitalized as assets, pooled with the costs of successful wells and charged against the net income
(loss) of future periods as a component of depletion expense. Oil and Gas Reserves Our estimated proved developed and estimated proved undeveloped reserves are all located
within the Appalachian and Michigan Basins in the United States. There are many uncertainties
inherent in estimating proved reserve quantities and in projecting future production rates and the
timing of development expenditures. In addition, estimates of new discoveries are more imprecise
than those of properties with a production history. Accordingly, these estimates are expected to
change as future information becomes available. Material revisions of reserve estimates may occur
in the future, development and production of the oil and gas reserves may not occur in the periods
assumed and actual prices realized and actual costs incurred may vary significantly from
assumptions used. Estimated proved reserves represent estimated quantities of natural gas and oil
that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in
future years from known reservoirs under economic and operating conditions existing at the time the
estimates were made. Estimated proved developed reserves are estimated proved reserves expected to
be recovered through wells and equipment in place and under operating methods being used at the
time the estimates were made. The accuracy of a reserve estimate is a function of:  
    the quality and quantity of available data;
    the interpretation of that data;
    the accuracy of various mandated economic assumptions; and
    the judgment of the persons preparing the estimate. Capitalization, Depreciation, Depletion and Impairment of Long-Lived Assets See the Successful Efforts Method of Accounting discussion above. Capitalized costs related
to estimated proved properties are depleted using the unit-of-production method. Depreciation,
depletion and amortization of proved oil and gas properties are calculated on the basis of
estimated recoverable reserve quantities. These estimates can change based on economic or other
factors. No gains or losses are recognized upon the disposition of oil and gas properties except
in extraordinary transactions. Sales proceeds are credited to the carrying value of the
properties. Maintenance and repairs are expensed, and expenditures which enhance the value of
properties are capitalized. Unproved oil and gas properties are stated at cost and consist of undeveloped leases. These
costs are assessed periodically to determine whether their value has been impaired, and if
impairment is indicated, the costs are charged to expense. Gas gathering systems are stated at cost. Depreciation expense is computed using the
straight-line method over 15 years. Property and equipment are stated at cost. Depreciation of non-oil and gas properties is
computed using the straight-line method over the useful lives of the assets ranging from 3 to 15
years for machinery and equipment and 30 to 40 years for buildings. When assets other than oil and
gas properties are retired or otherwise disposed of, the cost and related accumulated depreciation
are removed from the accounts, and any resulting gain or loss is reflected in income for the
period. The cost of maintenance and repairs is expensed as incurred, and significant renewals and
betterments are capitalized. 10




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Long-lived assets are reviewed for impairment whenever events or changes in circumstances
indicate that the carrying amount may not be recoverable. If the sum of the expected future
undiscounted cash flows is less than the carrying amount of the asset, a loss is recognized for the
difference between the fair value and the carrying amount of the asset. Fair value is determined
based on managements outlook of future oil and natural gas prices and estimated future cash flows
to be generated by the assets, discounted at a market rate of interest. Impairment of unproved
properties is based on the estimated fair value of the property. Derivatives and Hedging Our financial results and cash flows can be significantly impacted as commodity prices
fluctuate widely in response to changing market conditions. Under the provisions of SFAS 133,
Accounting for Derivative Instruments and Hedging Activities, as amended, we recognize all
derivative financial instruments as either assets or liabilities at fair value. The changes in
fair value of derivative instruments not qualifying for designation as cash flow hedges that occur
prior to maturity are initially reported in expense in the consolidated statements of operations as
derivative fair value (gain) loss. All amounts recorded in this line item are ultimately reversed
within the same line item and included in oil and gas sales revenues over the respective contract
terms. Changes in the fair value of derivative instruments that are fair value hedges are offset
against changes in the fair value of the hedged assets, liabilities, or firm commitments, through
net income (loss). Changes in the fair value of derivative instruments that are cash flow hedges
are recognized in other comprehensive income (loss) until such time as the hedged items are
recognized in net income (loss). The relationship between the hedging instruments and hedged item must be highly effective
in achieving the offset of changes in fair values or cash flows attributable to the hedged risk
both at the inception of the contract and on an ongoing basis. We measure effectiveness at least
on a quarterly basis. Ongoing assessments of hedge effectiveness will include verifying and
documenting that the critical terms of the hedge and forecasted transaction do not change.
Ineffective portions of a derivative instruments change in fair value are immediately recognized
in net income (loss). If there is a discontinuance of a cash flow hedge because it is probable
that the original forecasted transaction will not occur, deferred gains or losses are recognized in
earnings immediately. 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 natural gas or oil price
volatility and support our capital expenditure plans. Our derivative financial instruments
primarily take the form of swaps or collars. At March 31, 2005, our derivative contracts were
comprised of natural gas swaps and collars and crude oil swaps, which were placed with a major
financial institution that we believe is a minimal credit risk. Qualifying derivative
financial instruments are designated as cash flow hedges. We consider our natural gas swaps to be highly effective and expect there will be no
ineffectiveness to be recognized in net income (loss) since the critical terms of the hedging
instruments and the hedged forecasted transactions are the same. We have not experienced
ineffectiveness on our natural gas swaps because we use NYMEX-based commodity derivative contracts
to hedge on the same basis as our natural gas production is sold (NYMEX-based sales contracts). We
have collar agreements that could not be redesignated as cash flow hedges because these collars
were not effective due to unrealized losses at the date of the Merger. These collars qualified and
were designated as cash flow hedges from their inception through the predecessor company period
ended July 1, 2004. Although these collars are not deemed to be effective hedges in accordance
with the provisions of SFAS 133, we have retained these instruments as protection against changes
in commodity prices and we will continue to record the mark-to-market adjustments on these natural
gas collars, through 2005, in our income statement. Our NYMEX crude oil swaps are highly effective
and were designated as cash flow hedges. 11




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We have ineffectiveness on the crude oil swaps because the oil is sold locally at a posted price
which is different from the NYMEX price. Historically, there has been a high correlation between
the posted price and NYMEX. The changes in the fair values of the natural gas collars and the
ineffective portion of the crude oil swaps are recorded as Derivative fair value gain or loss. Revenue Recognition Oil and gas production revenue is recognized as production and delivery take place. Oil and
gas marketing revenues are recognized when title passes. Asset Retirement Obligations Under the provisions of SFAS 143, Accounting for Asset Retirement Obligations, we recognize
a liability for the fair value of our asset retirement obligations associated with our tangible,
long-lived assets. The majority of our asset retirement obligations recorded relate to the
plugging and abandonment (excluding salvage value) of our oil and gas properties. Subsequent to
the adoption of SFAS 143, there has been no significant current period activity with respect to
additional retirement obligations, settled obligations, accretion expense and revisions of
estimated cash flows. The asset retirement obligations increased as a result of purchase accounting
for the Merger, primarily due to a lower discount rate and revised estimates of asset lives on
certain oil and gas wells. Results of Operations The Merger was completed on July 7, 2004 and for financial reporting purposes was accounted
for as a purchase effective July 1, 2004. The Merger resulted in a new basis of accounting
reflecting estimated fair values for assets and liabilities at that date. Accordingly, the
financial statements for the period subsequent to July 1, 2004 are presented on the Companys new
basis of accounting, while the results of operations for prior periods reflect the historical
results of the predecessor company. A vertical black line is presented to separate the financial
statements of the predecessor and successor companies. The allocation of the purchase price at fair value resulted in a significant increase in the
book value of our assets. The increase in the book value of assets resulted in materially higher
charges for depreciation, depletion and amortization in the successor company period ended March
31, 2005. These higher charges are expected to continue in subsequent accounting periods. 12




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The following Managements Discussion and Analysis is based on the results of operations from
continuing operations, unless otherwise noted. Accordingly, discontinued operations have been
excluded. The following table sets forth certain information regarding our net oil and natural gas
production, revenues and expenses for the periods indicated: Three months ended March 31,2005
    
    
    2004ProductionGas (Mmcf)
    
    
    3,563
    
    
    
    3,879Oil (Mbbls)
    
    
    83
    
    
    
    97Total production (Mmcfe)
    
    
    4,059
    
    
    
    4,458Average priceGas (per Mcf)
    
    $
    5.28
    
    
    $
    4.97Oil (per Bbl)
    
    
    34.13
    
    
    
    32.05Mcfe
    
    
    5.33
    
    
    
    5.02Average costs (per Mcfe)Production expense
    
    
    1.34
    
    
    
    1.21Production taxes
    
    
    0.18
    
    
    
    0.15Depletion
    
    
    1.89
    
    
    
    0.83Operating margin (per Mcfe)
    
    
    3.81
    
    
    
    3.66
 Mmcf  Million cubic feet
    
    Mbbls  Thousand barrels
    
    Mmcfe  Million cubic feet of natural gas equivalentMcf  Thousand cubic feet
    
    Bbl  Barrel
    
    Mcfe  Thousand cubic feet of natural gas equivalentOperating margin (per Mcfe)  average price less production expense and production taxes
 First Quarters of 2005 and 2004 Compared Revenues Net operating revenues decreased from $24.9 million in the first quarter of 2004 to $24.1
million in the first quarter of 2005. The decrease was due to lower oil and gas sales revenues of
$724,000 and lower gas gathering and marketing revenues of $140,000. Gas volumes sold were 3.6 Bcf (billion cubic feet) in the first quarter of 2005, which was a
decrease of 316 Mmcf (8%) compared to the first quarter of 2004. This decrease in gas volumes sold
resulted in a decrease in gas sales revenues of approximately $1.6 million. Oil volumes sold
decreased approximately 14,000 Bbls (14%) from 97,000 Bbls in the first quarter of 2004 to 83,000
Bbls in the first quarter of 2005 resulting in a decrease in oil sales revenues of approximately
$440,000. The lower oil and gas sales volumes are primarily due to normal production declines partially offset by production from new wells drilled during 2004 and 2005. The average price realized for our natural gas increased $0.31 per Mcf from $4.97 in the
first quarter of 2004 to $5.28 per Mcf in the first quarter of 2005, which increased gas sales
revenues by approximately $1.1 million. As a result of our hedging activities, gas sales revenues
were decreased by $5.1 million ($1.44 per Mcf) in the first quarter of 2005 and decreased by $3.5
million ($0.91 per Mcf) in the first quarter of 2004. The average price realized for our oil
increased from $32.05 per Bbl in the first quarter of 2004 to $34.13 per Bbl in the first quarter
of 2005, which increased oil sales revenues by approximately $170,000. As a result of our hedging
activities, oil sales revenues were decreased by approximately $1.0 million ($12.30 per Bbl) in the
first quarter of 2005. The operating margin from oil and gas sales (oil and gas sales revenues less production
expense
and production taxes) on a per unit basis increased from $3.66 per Mcfe in the first quarter of
2004 to 13




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$3.81 per Mcfe in the first quarter of 2005. The average price increased $0.31 per Mcfe
which was partially offset by an increase in production expense of $0.13 per Mcfe and an increase
in production taxes of $0.03 per Mcfe in the first quarter of 2005 compared to the first quarter of
2004. The decrease in gas gathering and marketing revenues was due to a $128,000 decrease in gas
marketing revenues and a $12,000 decrease in gas gathering revenues. The lower gas gathering and
marketing revenues resulted primarily from the lower gas volumes discussed above. Costs and Expenses Production expense was $5.4 million in the first quarter of 2004 and the first quarter of
2005. The average production cost increased from $1.21 per Mcfe in the first quarter of 2004 to
$1.34 per Mcfe in the first quarter of 2005. The per unit increase was due to the lower volumes
discussed above. Production taxes increased $82,000 from $652,000 in the first quarter of 2004 to $734,000 in
the first quarter of 2005. Average per unit production taxes increased from $0.15 per Mcfe in the
first quarter of 2004 to $0.18 per Mcfe in the first quarter of 2005. The increased production
taxes are primarily due to higher oil and gas prices in Michigan, where production taxes are based
on a percentage of revenues, excluding the effects of hedging. Exploration expense decreased $397,000 (29%) from $1.3 million in the first quarter of 2004 to
$1.0 million in the first quarter of 2005. This decrease is primarily due to lower expired lease
expense and decreases in employment and compensation related expense. General and administrative expense increased $529,000 (43%) from $1.2 million in the first
quarter of 2004 to $1.8 million in the first quarter of 2005 primarily due to $489,000 related to
severance agreements with two former executives in the first quarter of 2005, an increase of
$311,000 in audit and legal services related to our public filings and Sarbanes-Oxley efforts
partially offset by $176,000 for strategic advisory services in the first quarter of 2004 related
to the potential sale of the Company. Depreciation, depletion and amortization increased by $3.7 million from $4.6 million in the
first quarter of 2004 to $8.3 million in the first quarter of 2005. This increase was primarily
due to an increase in depletion expense. Depletion expense increased $4.0 million (108%) from $3.7
million in the first quarter of 2004 to $7.7 million in the first quarter of 2005 primarily due to
a higher depletion rate per Mcfe. Depletion per Mcfe increased from $0.83 per Mcfe in the first
quarter of 2004 to $1.89 per Mcfe in the first quarter of 2005, primarily due to a higher cost
basis resulting from purchase accounting for the Merger. Derivative fair value (gain) loss was a gain of $332,000 in the first quarter of 2004 compared
to a loss of $6.8 million in the first quarter of 2005. 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 $2.7 million related to the ineffective portion of crude oil
swaps qualifying for hedge accounting which was recorded in the first quarter of 2005. Interest expense decreased $242,000 from $6.1 million in the first quarter of 2004 to $5.8
million in the first quarter of 2005. This decrease was due to lower blended interest rates
partially offset by an increase in average outstanding borrowings. Income tax expense decreased $4.5 million from $1.4 million in the first quarter of 2004
to a benefit of $3.1 million in the first quarter of 2005. The decrease was primarily due to a
decrease in
income from continuing operations before income taxes. 14




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##### Table of Contents



Discontinued operations relating to the TBR and Arrow asset sales resulted in a loss, net of
tax, of $314,000 in the first quarter of 2004. The TBR and Arrow assets were sold in the second
quarter of 2004. Liquidity and Capital Resources Cash Flows The primary sources of cash in the three-month period ended March 31, 2005 have been funds
generated from operations. Funds used during this period were primarily used for operations,
exploration and 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 $5.4 million during the first three months of
2005 compared to $12.6 million in the first three months of 2004. The decrease was primarily due
to lower oil and gas margins (net of hedging) of $820,000 and changes in working capital items of
$6.1 million. Cash flows used in investing activities increased in the first three months of 2005 primarily
due to $1.5 million of increased capital expenditures in the first three months of 2005. Cash flows used in financing activities decreased in the first three months of 2005 primarily
due to lower debt repayment during the first three months of 2005. Our current ratio at March 31, 2005 was 0.77 to 1. During the first three months of 2005, the
working capital from continuing operations decreased $11.9 million from a deficit of $3.2 million
at December 31, 2004 to a deficit of $15.2 million at March 31, 2005. The decrease was primarily
due to a $19.0 million increase in the current liability for the fair value of derivatives, a $3.0
million decrease in cash and cash equivalents and a $3.0 million decrease in accounts receivable
partially offset by a $7.0 million decrease in accrued expenses and a $7.1 million increase in the
deferred income taxes asset. The decrease in accrued expenses was primarily due to a $4.6 million
decrease in accrued interest expense. Capital Expenditures During the first three months of 2005, we spent approximately $7.3 million, including
exploratory dry hole expense, on our drilling activities and other capital expenditures. In the
first three months of 2005, we drilled 28 gross (27.3 net) development wells, all of which were
successfully completed as producers in the target formation. We currently expect to spend approximately $36 million during 2005 on our drilling
activities, including exploratory dry hole expense, and other capital expenditures. We
intend to finance our planned capital expenditures through our cash on hand, available cash flow,
borrowings under our revolving credit facility and, to a lesser extent, the sale of non-strategic
assets. At March 31, 2005, we had cash of $15.4 million and approximately $13.8 million available
under our revolving facility. The level of our future cash flow will depend on a number of factors
including the demand for and price levels of oil and gas, the scope and success of our drilling
activities 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. At March 31, 2005, we had a $170 million credit facility comprised of: a seven year $100
million term facility; a six year $30 million revolving facility for working capital requirements
and general
corporate purposes, including the issuance of letters of credit; and a six year $40 million letter
of credit 15




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##### Table of Contents



facility that may be used only to provide credit support for our obligations under the
hedge agreement and other hedge transactions. At March 31, 2005, the interest rate under our base
rate option was 7.50%. Under our three month LIBOR option the rate was 5.80%. At March 31, 2005,
we had $56.2 million of outstanding letters of credit. At March 31, 2005, there was no outstanding
balance under the revolving credit agreement. Under the term facility the outstanding balance was
$89.25 million. We had $13.8 million of borrowing capacity under our revolving facility available
for general corporate purposes. As of March 31, 2005, we were in compliance with all financial
covenants and requirements under the existing credit facilities. 
 Item 3. Quantitative and Qualitative Disclosures About Market Risk Among other risks, we are exposed to interest rate and commodity price risks. The interest rate risk relates to existing debt under our revolving facility as well as any
new debt financing needed to fund capital requirements. We may manage our interest rate risk
through the use of interest rate swaps to hedge the interest rate exposure associated with the
credit agreement, whereby a portion of our floating rate exposure is exchanged for a fixed interest
rate. A portion of our long-term debt consists of senior secured notes where the interest
component is fixed. We had no derivative financial instruments for managing interest rate risks in
place as of March 31, 2005 or 2004. If market interest rates for short-term borrowings increased
1%, the increase in interest expense in the first quarter would be approximately $223,000. This
sensitivity analysis is based on our financial structure at March 31, 2005. The commodity price risk relates to natural gas and crude oil produced, held in storage and
marketed. Our financial results can be significantly impacted as commodity prices fluctuate widely
in response to changing market forces. From time to time, we may enter into a combination of
futures contracts, commodity derivatives and fixed-price physical contracts to manage our exposure
to commodity price volatility. We employ a policy of partially hedging oil production sold locally
at a posted price and gas production sold under NYMEX-based contracts by selling NYMEX-based
commodity derivative contracts which are placed with major financial institutions that we believe
are minimal credit risks. Historically, there has been a high correlation between the posted price
and NYMEX. The contracts may take the form of futures contracts, swaps or options. If NYMEX gas
prices decreased $0.50 per Mcf, our gas sales revenues for the quarter would decrease by $281,000,
after considering the effects of the hedging contracts in place at March 31, 2005. If the price of
crude oil decreased $3.00 per Bbl, oil sales revenues for the quarter would decrease by $46,000,
after considering the effects of the hedging contracts in place at March 31, 2005. We had net
pre-tax losses on our hedging activities of $13.2 million in the first three months of 2005 and
$9.7 million in the first three months of 2004. At March 31, 2005, we had hedges on a portion of
our oil and gas production for the remainder of 2005 through 2013. This sensitivity analysis is
based on our 2005 oil and gas sales volumes and assumes the NYMEX gas price would be above the
ceiling in 2005 listed in the table below. 16




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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 April 30, 2005: Natural Gas Swaps
    
    
    Natural Gas Collars
    
    
    Crude Oil SwapsNYMEX
    
    
    
    
    
    
    NYMEX Price perPrice per
    
    
    
    
    
    
    Mmbtu Floor/Cap
    
    
    
    
    
    
    NYMEX PriceBbtu
    
    
    Mmbtu
    
    
    Bbtu
    
    
    (1)
    
    
    Mbbls
    
    
    per BblQuarter EndingJune 30, 2005
    
    
    1,500
    
    
    $
    3.70
    
    
    
    1,500
    
    
    $
    4.00 - 5.32
    
    
    
    68
    
    
    $
    34.18September 30, 2005
    
    
    1,500
    
    
    
    3.70
    
    
    
    1,500
    
    
    
    4.00 - 5.32
    
    
    
    67
    
    
    
    33.72December 31, 2005
    
    
    1,500
    
    
    
    3.70
    
    
    
    1,500
    
    
    
    4.00 - 5.32
    
    
    
    67
    
    
    
    33.314,500
    
    
    $
    3.70
    
    
    
    4,500
    
    
    $
    4.00 - 5.32
    
    
    
    202
    
    
    $
    33.74March 31, 2006
    
    
    2,829
    
    
    $
    6.14
    
    
    
    
    
    
    
    
    
    
    
    63
    
    
    $
    32.71June 30, 2006
    
    
    2,829
    
    
    
    5.24
    
    
    
    
    
    
    
    
    
    
    
    62
    
    
    
    32.35September 30, 2006
    
    
    2,829
    
    
    
    5.22
    
    
    
    
    
    
    
    
    
    
    
    62
    
    
    
    32.02December 31, 2006
    
    
    2,829
    
    
    
    5.39
    
    
    
    
    
    
    
    
    
    
    
    62
    
    
    
    31.7111,316
    
    
    $
    5.50
    
    
    
    
    
    
    
    
    
    
    
    249
    
    
    $
    32.20Year EndingDecember 31, 2007
    
    
    10,745
    
    
    $
    4.97
    
    
    
    
    
    
    
    
    
    
    
    227
    
    
    $
    30.91December 31, 2008
    
    
    10,126
    
    
    
    4.64
    
    
    
    
    
    
    
    
    
    
    
    208
    
    
    
    29.96December 31, 2009
    
    
    9,529
    
    
    
    4.43
    
    
    
    
    
    
    
    
    
    
    
    191
    
    
    
    29.34December 31, 2010
    
    
    8,938
    
    
    
    4.28
    
    
    
    
    
    
    
    
    
    
    
    175
    
    
    
    28.86December 31, 2011
    
    
    8,231
    
    
    
    4.19
    
    
    
    
    
    
    
    
    
    
    
    157
    
    
    
    28.77December 31, 2012
    
    
    7,005
    
    
    
    4.09
    
    
    
    
    
    
    
    
    
    
    
    138
    
    
    
    28.70December 31, 2013
    
    
    6,528
    
    
    
    4.04
    
    
    
    
    
    
    
    
    
    
    
    127
    
    
    
    28.70
 Bbl  Barrel
    
    Mmbtu  Million British thermal unitsMbbls  Thousand barrels
    
    Bbtu  Billion British thermal units
   (1)
    The NYMEX price per Mmbtu floor/cap for the natural gas collars in 2005
assume the monthly NYMEX settles at $3.10 per Mmbtu or higher. If the monthly NYMEX settles at
less than $3.10 per Mmbtu then the NYMEX price per Mmbtu will be the NYMEX settle plus $0.90. The proximity of our properties in the Appalachian and Michigan Basins to large
commercial and industrial natural gas markets has generally resulted in premium wellhead gas prices
compared with the prices of NYMEX futures contracts for gas delivered at the Henry Hub in
Louisiana. Monthly spot natural gas prices in our market areas are typically $0.15 to $0.60 higher
per Mcf than comparable NYMEX prices. Our average price received for crude oil is typically $3.00
to $3.50 per barrel below the NYMEX price per barrel. 17




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##### Table of Contents



Item 4. Controls and Procedures As of the end of the quarterly period ended March 31, 2005, James A. Winne III, our Chief
Executive Officer, and Robert W. Peshek, our Chief Financial Officer, evaluated the effectiveness
of our disclosure controls and procedures. There are inherent limitations to the effectiveness of
any system of disclosure controls and procedures, including the possibility of human error and the
circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure
controls and procedures can only provide reasonable assurance of achieving their control
objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our
Chief Financial Officer believe that:  
    our disclosure controls and procedures were effective in ensuring that information
required to be disclosed by us in the reports we file or submit under the Securities
Exchange Act of 1934 was recorded, processed, summarized and reported within the time
periods specified in the SECs rules and forms; and
    our disclosure controls and procedures were effective in ensuring that material
information required to be disclosed by us in the report we file or submit under the
Securities Exchange Act of 1934 was accumulated and communicated to our management,
including the Chief Executive Officer and the Chief Financial Officer, as appropriate to
allow timely decisions regarding required disclosure. Internal Controls Over Financial Reporting There has not been any change in our internal control over financial reporting that occurred
during our quarterly period ended March 31, 2005 that has materially affected, or is reasonably
likely to materially affect, our internal control over financial reporting. 
 PART II OTHER INFORMATION 
 Item 1. Legal Proceedings. In April 2002, we were notified of a claim by an overriding royalty owner in Michigan alleging
the underpayment of royalties resulting from disputes as to the interpretation of the terms of
several farmout agreements. On July 6, 2004, a suit was filed in Otsego County, Michigan by the
successor in interest to these royalty interests, alleging substantially the same underpayments.
In April 2005, we entered into a settlement agreement that provides for a payment to the royalty
owner of an amount approximately equal to the amount accrued at March 31, 2005 and an increase in
the future overriding royalty percentage in several wells. The result will have no material
adverse effect on our financial position, results of operations or cash flows. 
 Item 4. Submission of Matters to a Vote of Security Holders. On February 14, 2005, Capital C approved by written consent in lieu of a meeting, a resolution
naming Morris B. Sam Smith to our Board of Directors and increasing our Boards membership from
six to seven. The terms of office of our other directors, Gregory A. Beard, Michael Becci, Michael
B. Hoffman, Pierre F. Lapeyre, Jr., David M. Leuschen and James A. Winne III, continued after
February 14, 2005. 18




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##### Table of Contents



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. 19




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##### Table of Contents



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 CORPORATIONDate: May 10, 2005
    By:
    /s/ James A. Winne IIIJames A. Winne III, Chief Executive Officer,Chairman of the Board of Directors and Director Date: May 10, 2005
    By:
    /s/ Robert W. PeshekRobert W. Peshek, Senior Vice Presidentand Chief Financial Officer 20