##### Table of Contents



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION  FORM 10-Q (Mark One) [X]
    
    Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934For the quarterly period ended September 30, 2004
 or [  ]
    
    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
    
    (I.R.S. Employerincorporation or organization)
    
    Identification No.)
 5200 Stoneham RoadNorth 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. [X] Yes [  ] No Indicate by check mark whether the Registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). [  ] Yes [X] No As of November 10, 2004, 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 Information:Item 1. Financial StatementsConsolidated Balance Sheet as of September 30, 2004 (Successor Company)
    
    
    1Consolidated Statements of Operations for the Successor Company for the 91 day
period from July 2, 2004 to September 30, 2004 and the Predecessor Company
for the 183 Day Period From January 1, 2004 to July 1, 2004 and three and
nine months ended September 30, 2003
    
    
    2Consolidated Statements of Shareholders Equity (Deficit) for the Successor Company
for the 91 day period from July 2, 2004 to September 30, 2004 and the
Predecessor Company for the 183 Day Period From January 1, 2004 to July 1, 2004 and the
years ended December 31, 2003 and 2002
    
    
    3Consolidated Statements of Cash Flows for the Successor Company for the 91 day
period from July 2, 2004 to September 30, 2004 and the Predecessor Company
for the 183 Day Period From January 1, 2004 to July 1, 2004 and the nine months
ended September 30, 2003
    
    
    4Notes to Consolidated Financial Statements
    
    
    5Item 2. Managements Discussion and Analysis of Financial
Condition and Results of Operations
    
    
    11Item 3. Quantitative and Qualitative Disclosures About Market Risk
    
    
    21Item 4. Controls and Procedures
    
    
    23PART II Other InformationItem 6. Exhibits
    
    
    24EX-31.1 CertificationEX-31.2 CertificationsEX-32.1 CertificationsEX-32.2 Certifications




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##### Table of Contents



BELDEN & BLAKE
CORPORATION 
 CONSOLIDATED BALANCE SHEET
(in thousands, except share data)
 September 30,2004(unaudited)ASSETSCurrent assetsCash and cash equivalents
    
    $
    25,949Accounts receivable, net
    
    
    14,822Inventories
    
    
    589Deferred income taxes
    
    
    3,519Other current assets
    
    
    1,399Assets of discontinued operations
    
    
    320Total current assets
    
    
    46,598Property and equipment, at costOil and gas properties (successful efforts method)
    
    
    510,537Gas gathering systems
    
    
    4,578Land, buildings, machinery and equipment
    
    
    8,051523,166Less accumulated depreciation, depletion and amortization
    
    
    8,174Property and equipment, net
    
    
    514,992Other assets
    
    
    12,163$
    573,753LIABILITIES AND SHAREHOLDERS EQUITYCurrent liabilitiesAccounts payable
    
    $
    3,546Accrued expenses
    
    
    20,002Current portion of long-term liabilities
    
    
    1,110Fair value of derivatives
    
    
    33,008Liabilities of discontinued operations
    
    
    237Total current liabilities
    
    
    57,903Long-term liabilitiesSenior secured facility and other long-term debt
    
    
    98,843Senior secured notes
    
    
    192,500Asset retirement obligations and other long-term liabilities
    
    
    7,663299,006Fair value of derivatives
    
    
    53,533Deferred income taxes
    
    
    110,838Shareholders equityCommon stock without par value; 1,500 shares authorized and issued
    
    
    Paid in capital
    
    
    77,500Deficit
    
    
    (2,304
    )Accumulated other comprehensive loss
    
    
    (22,723
    )Total shareholders equity
    
    
    52,473$
    573,753
 See accompanying notes. 1




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##### Table of Contents



BELDEN & BLAKE
CORPORATION 
 CONSOLIDATED STATEMENT OF OPERATIONS
(unaudited, in thousands)
 Successor
    
    Predecessor
    
    SuccessorCompany
    
    Company
    
    Company
    
    Predecessor CompanyFor the 91 Day
    
    
    
    
    
    For the 91 DayPeriod From
    
    Three months
    
    Period From
    
    For the 183 Day
    
    Nine monthsJuly 2, 2004 to
    
    ended
    
    July 2, 2004 to
    
    Period From
    
    endedSeptember 30,
    
    September 30,
    
    September 30,
    
    January 1, 2004
    
    September 30,2004
    
    2003
    
    2004
    
    to July 1, 2004
    
    2003RevenuesOil and gas sales
    
    $
    21,668
    
    
    $
    21,527
    
    
    $
    21,668
    
    
    $
    45,307
    
    
    $
    62,204Gas gathering and marketing
    
    
    2,179
    
    
    
    2,439
    
    
    
    2,179
    
    
    
    5,057
    
    
    
    7,934Other
    
    
    550
    
    
    
    (68
    )
    
    
    550
    
    
    
    458
    
    
    
    33224,397
    
    
    
    23,898
    
    
    
    24,397
    
    
    
    50,822
    
    
    
    70,470ExpensesProduction expense
    
    
    5,500
    
    
    
    4,980
    
    
    
    5,500
    
    
    
    10,951
    
    
    
    14,302Production taxes
    
    
    650
    
    
    
    615
    
    
    
    650
    
    
    
    1,300
    
    
    
    1,944Gas gathering and marketing
    
    
    2,026
    
    
    
    2,162
    
    
    
    2,026
    
    
    
    4,533
    
    
    
    7,398Exploration expense
    
    
    1,334
    
    
    
    1,449
    
    
    
    1,334
    
    
    
    2,717
    
    
    
    4,690General and administrative expense
    
    
    1,100
    
    
    
    1,099
    
    
    
    1,100
    
    
    
    2,500
    
    
    
    3,369Franchise, property and other taxes
    
    
    67
    
    
    
    65
    
    
    
    67
    
    
    
    115
    
    
    
    170Depreciation, depletion and amortization
    
    
    8,611
    
    
    
    4,415
    
    
    
    8,611
    
    
    
    9,089
    
    
    
    12,566Accretion expense
    
    
    134
    
    
    
    85
    
    
    
    134
    
    
    
    195
    
    
    
    247Derivative fair value loss
    
    
    3,788
    
    
    
    340
    
    
    
    3,788
    
    
    
    2,038
    
    
    
    166Transaction-related expenses
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    21,155
    
    
    
    23,210
    
    
    
    15,210
    
    
    
    23,210
    
    
    
    54,593
    
    
    
    44,852Operating income (loss)
    
    
    1,187
    
    
    
    8,688
    
    
    
    1,187
    
    
    
    (3,771
    )
    
    
    25,618Other expenseInterest expense
    
    
    6,143
    
    
    
    5,722
    
    
    
    6,143
    
    
    
    12,184
    
    
    
    17,663(Loss) income from continuing operations before income taxes
and cumulative effect of change in accounting principle
    
    
    (4,956
    )
    
    
    2,966
    
    
    
    (4,956
    )
    
    
    (15,955
    )
    
    
    7,955(Benefit) provision for income taxes
    
    
    (2,314
    )
    
    
    1,031
    
    
    
    (2,314
    )
    
    
    (3,318
    )
    
    
    2,844(Loss) income from continuing operations before cumulative
effect of change in accounting principle
    
    
    (2,642
    )
    
    
    1,935
    
    
    
    (2,642
    )
    
    
    (12,637
    )
    
    
    5,111Income (loss) from discontinued operations, net of tax
    
    
    338
    
    
    
    (3,576
    )
    
    
    338
    
    
    
    27,840
    
    
    
    (4,769
    )(Loss) income before cumulative effect of change in
accounting principle
    
    
    (2,304
    )
    
    
    (1,641
    )
    
    
    (2,304
    )
    
    
    15,203
    
    
    
    342Cumulative effect of change in accounting principle, net of tax
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2,397Net (loss) income
    
    $
    (2,304
    )
    
    $
    (1,641
    )
    
    $
    (2,304
    )
    
    $
    15,203
    
    
    $
    2,739
 See accompanying notes. 2




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##### Table of Contents



BELDEN & BLAKE
CORPORATION 
 CONSOLIDATED STATEMENTS OF SHAREHOLDERS EQUITY (DEFICIT)
(in thousands)
 Successor Company
    
    Predecessor Company
    
    
    
    
    
    
    
    
    
    Accumulated
Other
    
    TotalCommon
    
    Common
    
    Common
    
    Common
    
    Paid in
    
    
    
    
    
    Comprehensive
    
    EquityShares
    
    Stock
    
    Shares
    
    Stock
    
    Capital
    
    Deficit
    
    Income
    
    (Deficit)Predecessor Company:January 1, 2002
    
    
    
    
    
    
    
    
    
    
    10,290
    
    
    $
    1,029
    
    
    $
    107,402
    
    
    $
    (150,797
    )
    
    $
    15,087
    
    
    $
    (27,279
    )Comprehensive income (loss):Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2,465
    
    
    
    
    
    
    
    2,465Other comprehensive income (loss), net of tax:Change in derivative fair value
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (5,518
    )
    
    
    (5,518
    )Reclassification adjustment for derivative (gain) loss
reclassified into oil and gas sales
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (14,030
    )
    
    
    (14,030
    )Total comprehensive loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (17,083
    )Stock options exercised
    
    
    
    
    
    
    
    
    
    
    65
    
    
    
    7
    
    
    
    (2
    )
    
    
    
    
    
    
    
    
    
    
    5Stock-based compensation
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    82
    
    
    
    
    
    
    
    
    
    
    
    82Repurchase of stock options
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (29
    )
    
    
    
    
    
    
    
    
    
    
    (29
    )Tax benefit of repurchase of stock options
and stock options exercised
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    57
    
    
    
    
    
    
    
    
    
    
    
    57Treasury stock
    
    
    
    
    
    
    
    
    
    
    (59
    )
    
    
    (6
    )
    
    
    (392
    )
    
    
    
    
    
    
    
    
    
    
    (398
    )December 31, 2002
    
    
    
    
    
    
    
    
    
    
    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
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    33,571
    
    
    
    
    
    
    
    33,571Other 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
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    27,903Stock 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
    )
    
    
    117,085
    
    
    
    21,025
    
    
    
    28,425July 1, 2004 (unaudited)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Successor Company:Sale of common stock
    
    
    2
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    77,500
    
    
    
    
    
    
    
    
    
    
    
    77,500Comprehensive income (loss):Net income
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (2,304
    )
    
    
    
    
    
    
    (2,304
    )Other comprehensive income (loss), net of tax:Change in derivative fair value
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (25,723
    )
    
    
    (25,723
    )Reclassification adjustment for derivative (gain) loss
reclassified into oil and gas sales
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3,000
    
    
    
    3,000Total comprehensive loss
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (25,027
    )September 30, 2004 (unaudited)
    
    
    2
    
    
    $
    
    
    
    
    
    
    
    $
    
    
    
    $
    77,500
    
    
    $
    (2,304
    )
    
    $
    (22,723
    )
    
    $
    52,473
 See accompanying notes. 3




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##### Table of Contents



BELDEN & BLAKE
CORPORATION 
 CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited, in thousands)
 SuccessorCompany
    Predecessor CompanyFor the 91 Day
    For the 183 DayPeriod From July
    Period From
    
    Nine months2, to September
    January 1, to July
    
    ended September30,
    1,
    
    30,2004
    2004
    
    2003Cash flows from operating activities:Income from continuing operations
    
    $
    (2,642
    )
    
    $
    (12,637
    )
    
    $
    5,111Adjustments to reconcile income from continuing operations
to net cash provided by operating activities:Depreciation, depletion and amortization
    
    
    8,611
    
    
    
    9,089
    
    
    
    12,566Accretion
    
    
    134
    
    
    
    195
    
    
    
    247Loss on disposal of property and equipment
    
    
    37
    
    
    
    375
    
    
    
    780Amortization of derivatives and other noncash hedging activities
    
    
    3,788
    
    
    
    1,810
    
    
    
    (2,194
    )Exploration expense
    
    
    1,334
    
    
    
    2,717
    
    
    
    4,690Deferred income taxes
    
    
    (2,314
    )
    
    
    (3,037
    )
    
    
    188Stock-based compensation
    
    
    
    
    
    
    1,097
    
    
    
    54Transaction-related expenses
    
    
    
    
    
    
    21,155
    
    
    
    Change in operating assets and liabilities, net of
effects of acquisition and disposition of businesses:Accounts receivable and other operating assets
    
    
    3,422
    
    
    
    (4,486
    )
    
    
    (5,152
    )Inventories
    
    
    112
    
    
    
    79
    
    
    
    138Accounts payable and accrued expenses
    
    
    1,778
    
    
    
    2,237
    
    
    
    4,275Net cash provided by continuing operations
    
    
    14,260
    
    
    
    18,594
    
    
    
    20,703Cash flows from investing activities:Acquisition of businesses, net of cash acquired
    
    
    
    
    
    
    
    
    
    
    (4,728
    )Disposition of businesses, net of cash
    
    
    
    
    
    
    
    
    
    
    100Proceeds from property and equipment disposals
    
    
    117
    
    
    
    247
    
    
    
    3,118Exploration expense
    
    
    (1,334
    )
    
    
    (2,717
    )
    
    
    (4,690
    )Additions to property and equipment
    
    
    (6,157
    )
    
    
    (11,228
    )
    
    
    (8,143
    )Decrease (increase) in other assets
    
    
    (18
    )
    
    
    1,218
    
    
    
    (52
    )Net cash used in investing activities
    
    
    (7,392
    )
    
    
    (12,480
    )
    
    
    (14,395
    )Cash flows from financing activities:Proceeds from senior secured notes
    
    
    
    
    
    
    192,500
    
    
    
    Proceeds from senior secured facility  term loan
    
    
    
    
    
    
    100,000
    
    
    
    Sale of common stock
    
    
    
    
    
    
    77,500
    
    
    
    Repayment of senior sub notes
    
    
    (1,040
    )
    
    
    (223,960
    )
    
    
    Payment to shareholders and optionholders
    
    
    
    
    
    
    (113,674
    )
    
    
    Transaction-related expenses
    
    
    
    
    
    
    (21,155
    )
    
    
    Debt issue costs
    
    
    
    
    
    
    (12,028
    )
    
    
    (240
    )Repayment of senior secured facility  term loan
    
    
    (250
    )
    
    
    
    
    
    
    Proceeds from revolving line of credit
    
    
    
    
    
    
    146,636
    
    
    
    147,222Repayment of long-term debt and other obligations
    
    
    
    
    
    
    (194,187
    )
    
    
    (134,940
    )Proceeds from stock options exercised
    
    
    
    
    
    
    111
    
    
    
    117Repurchase of stock options
    
    
    
    
    
    
    (283
    )
    
    
    (7
    )Purchase of treasury stock
    
    
    
    
    
    
    (29
    )
    
    
    (37
    )Net cash (used in) provided by financing activities
    
    
    (1,290
    )
    
    
    (48,569
    )
    
    
    12,115Net (decrease) increase in cash and cash equivalents
from continuing operations
    
    
    5,578
    
    
    
    (42,455
    )
    
    
    18,423Net increase (decrease) in cash and cash equivalents
from discontinued operations
    
    
    
    
    
    
    61,398
    
    
    
    (19,155
    )Cash and cash equivalents at beginning of period
    
    
    20,371
    
    
    
    1,428
    
    
    
    1,715Cash and cash equivalents at end of period
    
    $
    25,949
    
    
    $
    20,371
    
    
    $
    983
 See accompanying notes. 4




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##### Table of Contents



BELDEN & BLAKE
CORPORATION 
 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
 September 30, 2004 (1) Merger 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 subsidiaries. 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s general partner is Capital C Energy, LLC, an entity formed in April
2004 by David M. Carmichael, Frost W. Cochran and Peter R. Coneway in
partnership with Carlyle/Riverstone Global Energy & Power Fund II, L.P. and
Capital C Energy Partners, L.P. Capital C Energy, LLC is headquartered in
Houston, Texas. 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 the periods ended July 1,
2004 and June 30, 2003 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 Merger, each issued and outstanding share of the Companys common
stock was converted into the right to receive cash. All outstanding amounts of
indebtedness under the Companys prior credit facility were repaid. In
connection with the Consent Solicitation and Tender Offer previously announced
by the Company, over 98% of the Companys $225 million aggregate principal
amount of 9-7/8% Senior Subordinated Notes were also tendered and repaid at the
closing of the Merger. As of September 30, 2004, all of the $225 million
aggregate principal amount has been paid. Capital C obtained the funds necessary to consummate the Merger through
(1) equity capital contributions of $77.5 million by its partners, (2) the
Companys entry into a secured credit facility with various lenders arranged
through Goldman Sachs Credit Partners, L.P. with a $100 million term facility
maturing on July 7, 2011, a $30 million revolving facility maturing on July 7,
2010 and a $40 million letter of credit facility, which amounts are secured by
substantially all of the assets of the Company and are guaranteed by two of the
Companys subsidiaries, Ward Lake Drilling, Inc. and The Canton Oil & Gas
Company (the Senior Facilities), with the two subsidiaries stock pledged as
collateral and (3) a private placement of $192.5 million aggregate principal
amount of 8.75% Senior Secured Notes due 2012 (the Notes), which are secured
by a second-priority lien on the same assets and guaranteed by the same
subsidiaries that guarantee the Senior Facilities. Pre-existing commodity
hedges and ten-year commodity hedges effected in connection with the Merger
were also secured by a second-priority lien on the same assets and guaranteed
by the same subsidiaries that guarantee the Senior Facilities and the Notes. 5




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##### Table of Contents



The table below summarizes the preliminary allocation of the purchase price based on the acquisition date fair values of the
assets acquired and the liabilities assumed. The purchase price allocation is preliminary because the determination of fair values of certain assets and liabilities as of the acquisition date have
not been completed. (in thousands)Net working capital
    
    $
    17,215Oil and gas properties
    
    
    503,910Other assets
    
    
    24,610Derivative liability
    
    
    (46,898
    )Other non-current liabilities
    
    
    (7,464
    )Net deferred income tax liabilities
    
    
    (121,373
    )Long-term debt
    
    
    (292,500
    )Net cash equity contribution
    
    $
    77,500
 In connection with the Merger we entered into commodity hedges on a
substantial portion of our future oil and gas production through the year 2013.
See Note 5. Our management team remained after the Merger with the exception of the
retirement of the former Chief Executive Officer, John L. Schwager. Frost W.
Cochran is the Companys new President and Chief Executive Officer. In
addition, B. Dee Davis and W. Mac Jensen joined the Company as Senior Vice
Presidents. Upon consummation of the Merger all former directors of the
Company resigned and the new Board of Directors consisted of six members, each
of whom is elected annually to serve one-year terms. The initial six members
of the Board of Directors were Frost W. Cochran, David M. Carmichael, Michael
B. Hoffman, Pierre F. Lapeyre, Jr., David M. Leuschen, and Gregory A. Beard.
On November 1, 2004, James A. Winne III and Michael Becci were elected to our
Board of Directors and were also named Senior Vice Presidents of the Company.
Their election brings the Boards membership to eight. Following are unaudited pro forma results of operations as if the Merger
occurred at the beginning of 2003 (in thousands): Nine months ended September 30,2004
    
    2003Total revenues
    
    $
    75,219
    
    
    $
    70,470Loss from continuing operations
    
    
    (3,792
    )
    
    
    (2,821
    )
 The unaudited pro forma information presented above assumes the
transaction-related expenses were incurred prior to the period presented and
does not purport to be indicative of the results that actually would have been
obtained if the merger had been consummated at the beginning of 2003 and is not
intended to be a projection of future results or trends. In connection with the
Merger, we entered into a management services agreement with Capital C,
pursuant to which Capital C, initially Frost W. Cochran, B. Dee Davis and W.
Mac Jensen, provides certain management and advisory services to us for a
quarterly fee of $250,000. These services include general management
supervision and oversight, in the capacity as officers of Belden & Blake;
financial advisory services; evaluation of potential acquisitions and other
business opportunities; and strategic consulting services. This agreement will
be in effect until July 7, 2014 unless otherwise terminated due to the sale of
substantially all of our assets, or our dissolution and winding up of our
business. Carlyle/Riverstone or an affiliate received a fee from us of approximately
$1.4 million in connection with the Merger. 6




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##### Table of Contents



(2) Basis of Presentation 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 91 day period from July 2, 2004 to September 30, 2004 and the
predecessor company for the 183 day period from January 1, 2004 are not
necessarily indicative of the results that may be expected for the year ended
December 31, 2004. 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, 2003. Certain reclassifications have been made
to conform to the current presentation. We incurred transaction costs associated with the Merger of $21.2 million.
These costs were expensed in the predecessor company period ended July 1,
2004. We also capitalized $12.0 million of debt financing costs. The change
in fair value of $2.4 million of certain hedges from July 1, 2004 to July 7,
2004 was recorded in Derivative fair value loss in the predecessor company
period ended July 1, 2004. Income tax benefits of $5.1 million were recorded
in the one day predecessor company period ended July 1, 2004. (3) New Accounting Pronouncements In 2003, we were made aware of an issue regarding the application of
provisions of Financial Accounting Standards Board (FASB) Statement of
Financial Accounting Standards No. (SFAS) 141, Business Combinations and SFAS
142, Goodwill and Other Intangible Assets, to oil and gas companies. The
issue was whether SFAS 142 required registrants to reclassify costs associated
with mineral rights, including both proved and unproved leasehold acquisition
costs, as intangible assets in the balance sheet, apart from other capitalized
oil and gas property costs. Historically, the Company and other oil and gas
companies have included the cost of oil and gas leasehold interests as part of
oil and gas properties and provided the disclosures required by SFAS 69,
Disclosures about Oil and Gas Producing Activities. This matter was referred to the Emerging Issues Task Force (EITF) in late
2003. Although the EITF has not issued formal guidance for oil and gas
companies, at the March 2004 meeting, the EITF reached a consensus that mineral
rights for mining companies should be accounted for as tangible assets. In
order to resolve this inconsistency, the FASB directed the FASB staff to
prepare a FASB Staff Position (FSP) that amended SFAS 141 and SFAS 142. FSP FAS
141-1 and 142-1 is effective for the first reporting period beginning after
April 29, 2004. Since we already include these assets as part of our
capitalized oil and gas properties, the application of this FSP did not have an
impact. (4) Dispositions and Discontinued Operations On June 25, 2004, we completed a sale of substantially all of our Trenton
Black River (TBR) assets to Fortuna Energy Inc., a wholly owned subsidiary of
Talisman Energy Inc. The assets sold include working interests in 16 wells,
approximately 11 miles of natural gas gathering lines and oil and gas leases on
approximately 475,000 gross acres. The assets are located primarily in New
York, Pennsylvania, Ohio and West Virginia. The TBR assets accounted for
approximately 5 Bcfe of our estimated proved reserves as of December 31, 2003. The sale resulted in proceeds of approximately $68.4 million. The
proceeds were used to pay down our existing revolving credit facility. As a
result of the disposition of the TBR geographical/geological pools, we recorded
a gain of approximately $46.3 million ($29.5 million net of 7




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##### Table of Contents



tax) in June 2004. According to SFAS 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, the disposition was classified as discontinued
operations. In April 2004, we decided to dispose of our Arrow Oilfield Service Company
(Arrow) assets. We sold the Michigan assets of Arrow in May 2004 and sold
the Ohio and Pennsylvania assets of Arrow in June 2004. The two Arrow asset
sales resulted in proceeds of approximately $4.2 million. As a result of the
disposition of all of its Arrow assets, we recorded a loss of approximately
$1.3 million ($839,000 net of tax) in the second quarter of 2004. According
to SFAS 144, the disposition of the Arrow assets was classified as discontinued
operations. (5) Derivatives and Hedging Our financial results and cash flows can be significantly impacted as
commodity prices fluctuate widely in response to changing market conditions.
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 September 30, 2004, 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. 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 posted price which is different from the
NYMEX price. Historically there has been a high correlation between the posted
price and NYMEX. The changes 8




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##### Table of Contents



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. During the first nine months of 2004 and 2003, a net loss of $13.4 million
($8.5 million after tax) and a net loss of $9.7 million ($6.2 million after
tax), respectively, were reclassified from accumulated other comprehensive
income to earnings. The fair value of open hedges decreased $58.2 million
($36.9 million after tax) in the first nine months of 2004 and decreased $19.3
million ($12.3 million after tax) in the first nine months of 2003. At
September 30, 2004, the estimated net loss in accumulated other comprehensive
income that is expected to be reclassified into earnings within the next 12
months is approximately $6.7 million. At September 30, 2004, we have partially
hedged our exposure to the variability in future cash flows through December
2013. See Note 1. 9




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##### Table of Contents



The following table reflects the natural gas and crude oil volumes and the
weighted average prices under financial hedges (including settled hedges) at
September 30, 2004: Natural Gas Swaps
    
    Natural Gas Collars
    
    Crude Oil SwapsNYMEX
    
    
    
    
    
    NYMEXPrice per
    
    
    
    
    
    Price per
    
    Estimated
    
    NYMEXBbtu
    
    Mmbtu
    
    Bbtu
    
    Mmbtu Floor/Cap (1)
    
    Mbbls
    
    Price per BblQuarter
EndingDecember 31, 2004
    
    
    2,040
    
    
    
    3.81
    
    
    
    1,080
    
    
    
    4.00 - 5.76
    
    
    
    74
    
    
    
    35.682,040
    
    
    $
    3.81
    
    
    
    1,080
    
    
    $
    4.00 - 5.76
    
    
    
    74
    
    
    $
    35.68March 31, 2005
    
    
    1,500
    
    
    $
    3.81
    
    
    
    1,500
    
    
    $
    4.00 - 5.32
    
    
    
    68
    
    
    $
    34.76June 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
    
    
    
    33.316,000
    
    
    $
    3.73
    
    
    
    6,000
    
    
    $
    4.00 - 5.32
    
    
    
    270
    
    
    $
    34.00March 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 2004
assume the monthly NYMEX settles at $3.00 per Mmbtu or higher. If the monthly
NYMEX settles at less than $3.00 per Mmbtu then the NYMEX price per Mmbtu will
be the NYMEX settle plus $1.00. 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. (6) 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, 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 183 day
period from January 1, 2004 to July 1, 2004 and three and nine months ended
September 30, 2003 were not material. The successor company does not have any
stock options. 10




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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 September 30, 2003, resulted in a non-cash increase in
compensation expense of $36,000. The successor company does not have any
stock-based compensation. (7) 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. (8) Supplemental Disclosure of Cash Flow Information Successor Company
    Predecessor CompanyFor The 91 Day
    For The 183 DayPeriod From July 2,
    Period From January
    
    Nine months endedto September 30,
    1, to July 1,
    
    September 30,(in thousands)
    
    2004
    2004
    
    2003Cash paid during the period for:Interest
    
    $
    1,668
    
    $
    14,759
    
    
    $
    12,034Cumulative effect of change in accounting principle, net of tax
    
    
    
    
    
    
    
    
    
    2,397
 (9) Contingencies In April 2002, we were notified of a claim by an overriding royalty owner
in Michigan alleging the underpayment of royalty 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. We
believe there will be no material amount payable above and beyond the amount
accrued as of September 30, 2004 and therefore, the result will have no
material adverse effect on our financial position, results of operations or
cash flows. 
 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 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, and variations of these statements
and similar expressions are forward-looking statements. These forward-looking
statements are based on current expectations and projections about future
events. Forward-looking statements and our business prospects 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 11




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regulatory changes, changes in accounting
principles, policies or guidelines and environmental risks. These and other
risks are described in our 10-K and 10-Q reports and other filings with the
Securities and Exchange Commission (SEC). 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 2003 Form 10-K
annual report filed with the SEC for a 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 management to choose between GAAP alternatives and to make judgments
about estimates of future uncertainties. We utilize 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 unproved properties, are expensed as incurred. 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 proved developed
 and 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.  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. Proved developed
 reserves are proved reserves expected to be recovered through wells and equipment in
 place and under operating methods being utilized 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. The proved reserve information included in our 2003 Form 10-K is based on
estimates prepared by independent petroleum engineers. Estimates prepared by
others may be higher or lower than these estimates. 12




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Capitalization, Depreciation, Depletion and Impairment of Long-Lived Assets See the Successful Efforts Method of Accounting discussion above.
Capitalized costs related to proved properties are depleted using the
unit-of-production method. Depreciation, depletion and amortization of proved
oil and gas properties is 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. 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
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.
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 13




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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 September 30, 2004, 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. 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 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. New Accounting Pronouncements In 2003, we were made aware of an issue regarding the application of
provisions of SFAS 141, Business Combinations and SFAS 142, Goodwill and
Other Intangible Assets, to oil and gas companies. The issue was whether SFAS
142 required registrants to reclassify costs associated with mineral rights,
including both proved and unproved leasehold acquisition costs, as intangible
assets in the balance sheet, apart from other capitalized oil and gas property
costs. Historically, the Company and other oil and gas companies have included
the cost of oil and gas leasehold interests as part of oil and gas properties
and provided the disclosures required by SFAS 69, Disclosures about Oil and
Gas Producing Activities. This matter was referred to the EITF in late 2003. Although the EITF has
not issued formal guidance for oil and gas companies, at the March 2004
meeting, the EITF reached a consensus that mineral rights for mining companies
should be accounted for as tangible assets. In order to resolve this
inconsistency, the Board directed the FASB staff to prepare a FSP that amended
SFAS 141 and SFAS 142. FSP FAS 141-1 and 142-1 is effective for the first
reporting period beginning after April 29, 2004. Since we already include
these assets as part of our capitalized oil and gas properties the application
of this FSP will not have an impact. Results of Operations As disclosed in the accompanying notes to consolidated financial
statements, 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 14




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are presented on the Companys new
basis of accounting, while the results of operations for the periods ended July
1, 2004 and June 30, 2003 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. In conjunction with the
Merger, we recorded an additional $121 million to oil and gas properties as a
result of the deferred tax liability for the difference between the tax basis
and the book basis attributed to the properties under the purchase method of
accounting. The increase in the book value of assets resulted in materially
higher charges for depreciation, depletion and amortization in the successor
company period ended September 30, 2004. These higher charges are expected to
continue in subsequent accounting periods. We incurred transaction costs associated with the Merger of $21.2 million.
These costs were expensed in the predecessor company period ended July 1,
2004. We also capitalized $12.0 million of debt financing costs. The change
in fair value of $2.4 million of certain hedges from July 1, 2004 to July 7,
2004 was recorded in Derivative fair value loss in the predecessor company
period ended July 1, 2004. Income tax benefits of $5.1 million were recorded
in the one day predecessor company period ended July 1, 2004. 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.
As a result of the Merger, the results of operations for the periods subsequent
to July 1, 2004 are not necessarily comparable to those prior to July 1, 2004.
The following table combines the predecessor company period from January 1,
2004 to July 1, 2004, with the successor company period from July 2, 2004 to
September 30, 2004, for purposes of the discussion of year-to-date. The
discussion of third quarter results include the one day predecessor company
period ended July 1, 2004. 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 September 30,
    
    Nine months ended September 30,2004
    
    2003
    
    2004
    
    2003ProductionGas (Mmcf)
    
    
    3,795
    
    
    
    3,832
    
    
    
    11,492
    
    
    
    10,857Oil (Mbbls)
    
    
    93
    
    
    
    103
    
    
    
    282
    
    
    
    306Total production (Mmcfe)
    
    
    4,355
    
    
    
    4,452
    
    
    
    13,183
    
    
    
    12,694Average priceGas (per Mcf)
    
    $
    4.87
    
    
    $
    4.87
    
    
    $
    5.00
    
    
    $
    4.94Oil (per Bbl)
    
    
    34.28
    
    
    
    27.57
    
    
    
    33.73
    
    
    
    28.07Mcfe
    
    
    4.98
    
    
    
    4.83
    
    
    
    5.08
    
    
    
    4.90Average costs (per Mcfe)Production expense
    
    
    1.26
    
    
    
    1.12
    
    
    
    1.25
    
    
    
    1.13Production taxes
    
    
    0.15
    
    
    
    0.14
    
    
    
    0.15
    
    
    
    0.15Depletion
    
    
    1.83
    
    
    
    0.80
    
    
    
    1.16
    
    
    
    0.79Operating margin (per Mcfe)
    
    
    3.57
    
    
    
    3.57
    
    
    
    3.68
    
    
    
    3.62
 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
 Third Quarters of 2004 and 2003 Compared Revenues Net operating revenues decreased from $24.0 million in the third quarter
of 2003 to $23.8 million in the third quarter of 2004. The decrease was due to
lower gas sales revenues of $207,000 and lower gas 15




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gathering and marketing
revenues of $260,000, partially offset by higher oil sales revenues of
$348,000. Gas volumes sold were 3.8 Bcf (billion cubic feet) in the third quarter of
2004, which was a decrease of 37 Mmcf (1%) compared to the third quarter of
2003. This decrease in gas volumes sold resulted in a decrease in gas sales
revenues of approximately $180,000. Oil volumes sold decreased approximately
10,000 Bbls (10%) from 103,000 Bbls in the third quarter of 2003 to 93,000 Bbls
in the third quarter of 2004 resulting in a decrease in oil sales revenues of
approximately $280,000. The lower gas sales volumes are due to normal
production declines, partially offset by production from new wells drilled
during 2004. The lower oil sales volumes are due to normal production
declines. Our drilling program primarily targets natural gas reserves. The average price realized for our natural gas was consistent in the third
quarter of 2004 compared to the third quarter of 2003 at $4.87 per Mcf. As a
result of our hedging activities, gas sales revenues were decreased by $4.2
million ($1.10 per Mcf) in the third quarter of 2004 and decreased by $1.1
million ($0.30 per Mcf) in the third quarter of 2003. The average price
realized for our oil increased from $27.57 per Bbl in the third quarter of 2003
to $34.28 per Bbl in the third quarter of 2004, which increased oil sales
revenues by approximately $630,000. As a result of our hedging activities, oil
sales revenues were decreased by approximately $578,000 ($6.19 per Bbl) in the
third quarter of 2004. The operating margin from oil and gas sales (oil and gas sales revenues
less production expense and production taxes) on a per unit basis remained
consistent at $3.57 per Mcfe in the third quarter of 2004 compared to the third
quarter of 2003. The average price increased $0.15 per Mcfe which was offset
by an increase in production expense of $0.14 per Mcfe and an increase in
production taxes per Mcfe of $0.01 in the third quarter of 2004 compared to the
third quarter of 2003. The decrease in gas gathering and marketing revenues was due to a $216,000
decrease in gas marketing revenues and a $42,000 decrease in gas gathering
revenues. The lower gas gathering and marketing revenues resulted primarily
from lower gas volumes from third party wells. Costs and Expenses Production expense increased $520,000 (10%) from $5.0 million in the third
quarter of 2003 to
$5.5 million in the third quarter of 2004 primarily due to an increase in labor
resulting from continued well development activities, an increased focus on
production and compressor optimization and a general increase in fuel and power
costs. The average production cost increased from $1.12 per Mcfe in the third
quarter of 2003 to $1.26 per Mcfe in the third quarter of 2004. The per unit
increase was due to the higher costs and lower volumes discussed above. Production taxes increased $35,000 from $615,000 in the third quarter of
2003 to $650,000 in the third quarter of 2004. Average per unit production
taxes increased from $0.14 per Mcfe to $0.15 per Mcfe. 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 $115,000 (8%) from $1.4 million in the third
quarter of 2003 to $1.3 million in the third quarter of 2004. This decrease is
primarily due to lower exploratory dry hole expense as we have decreased
exploration activity in order to focus our drilling efforts on lower risk
developmental drilling. General and administrative expense was consistent at $1.1 million in the
third quarter of 2003 and in the third quarter of 2004. Depreciation, depletion and amortization increased by $4.2 million from
$4.4 million in the third 16




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quarter of 2003 to $8.6 million in the third quarter
of 2004. This increase was primarily due to an increase in depletion expense.
Depletion expense increased $4.4 million (124%) from $3.6 million in the third
quarter of 2003 to $8.0 million in the third quarter of 2004 primarily due to a
higher depletion rate per Mcfe. Depletion per Mcfe increased from $0.80 per
Mcfe in the third quarter of 2003 to $1.83 per Mcfe in the third quarter of
2004, primarily due to a higher cost basis resulting from purchase accounting
for the Merger in the third quarter of 2004. Approximately $0.44 per Mcfe of
the increase in depletion per Mcfe was due to the $121 million deferred tax
gross-up to producing oil and gas properties. Derivative fair value loss was $340,000 in the third quarter of 2003
compared to a loss of $6.1 million in the third quarter of 2004. 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 $1.6 million related to the ineffective portion of crude oil swaps
qualifying for hedge accounting which was recorded in the third quarter of
2004. Interest expense increased $421,000 from $5.7 million in the third quarter
of 2003 to $6.1 million in the third quarter of 2004. This increase was due to
an increase in average outstanding borrowings partially offset by lower blended
interest rates. Income tax expense decreased $9.2 million from $1.0 million in the third
quarter of 2003 to a benefit of $8.2 million in the third quarter of 2004. The
decrease was due to a decrease in income from continuing operations before
income taxes coupled with a lower effective tax rate in the third quarter of
2004. The effective tax rate was reduced due to certain nondeductible
transaction-related expenses recorded in the one-day predecessor period. The
tax rate was also impacted by the redetermination of deferred taxes under
purchase accounting and the resulting impact on deferred tax expense during the
third quarter of 2004. The state effective rate is also impacted by income in
a low tax rate state offset by losses in a higher tax rate state. Discontinued operations relating to the TBR and Arrow asset sales resulted
in a loss, net of tax, of $449,000 in the third quarter of 2004 compared to a
loss, net of tax, of $3.6 million in the third quarter of 2003. This was
primarily attributable to $4.7 million of exploration expense incurred in the
third
quarter of 2003. The TBR properties were sold in the second quarter of 2004. Nine Months of 2004 and 2003 Compared Revenues Net operating revenues increased from $70.1 million in the first nine
months of 2003 to $74.2 million in the first nine months of 2004. The increase
was due to higher gas sales revenues of $3.8 million and higher oil sales
revenues of $916,000 partially offset by lower gas gathering and marketing
revenues of $698,000. Gas volumes sold increased 635 Mmcf (6%) from 10.9 Bcf in the first nine
months of 2003 to 11.5 Bcf in the first nine months of 2004 resulting in an
increase in gas sales revenues of approximately $3.1 million. Oil volumes sold
decreased approximately 24,000 Bbls (8%) from 306,000 Bbls in the first nine
months of 2003 to 282,000 Bbls in the first nine months of 2004 resulting in a
decrease in oil sales revenues of approximately $680,000. The gas sales volume
increase was primarily due to the production from wells drilled in 2003 and
2004 and increased production as a result of additional expenditures to
stimulate production on declining wells partially offset by normal production
declines. The lower oil sales volumes are due to normal production declines.
Our drilling program primarily targets natural gas reserves. The average price realized for our natural gas increased $0.06 per Mcf to
$5.00 per Mcf in the first nine months of 2004 compared to the first nine
months of 2003, which increased gas sales revenues 17




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in the first nine months of
2004 by approximately $690,000. As a result of our hedging activities, gas
sales revenues were decreased by $12.6 million ($1.10 per Mcf) in the first
nine months of 2004 and decreased by $9.7 million ($.89 per Mcf) in the first
nine months of 2003. The average price paid for our oil increased from $28.07
per Bbl in the first nine months of 2003 to $33.73 per Bbl in the first nine
months of 2004, which increased oil sales revenues by approximately $1.6
million. As a result of our hedging activities, oil sales revenues were
decreased by approximately $578,000 ($2.05 per Bbl) in the first nine months of
2004. The operating margin from oil and gas sales on a per unit basis increased
from $3.62 per Mcfe in the first nine months of 2003 to $3.68 per Mcfe in the
first nine months of 2004. The average price increased $0.18 per Mcfe which was
partially offset by an increase in production expense of $0.12 per Mcfe in the
first nine months of 2004 compared to the first nine months of 2003. The decrease in gas gathering and marketing revenues was due to a $1.2
million decrease in gas marketing revenues partially offset by a $535,000
increase in gas gathering revenues. The lower marketing revenues were
primarily the result of decreased gas volumes from third party wells. The
increase in gas gathering revenues was primarily due to higher margins on a
gathering system in Pennsylvania. Costs and Expenses Production expense increased $2.2 million (15%) from $14.3 million in the
first nine months of 2003 to $16.5 million in the first nine months of 2004
primarily due to an increase in labor resulting from continued well development
activities, an increased focus on production and compressor optimization, a
general increase in fuel and power costs and $462,000 of additional non-cash
stock-based compensation expense recorded in the second quarter of 2004 to
reflect the increased value of our stock. The average production cost
increased from $1.13 per Mcfe in the first nine months of 2003 to $1.25 per
Mcfe in the first nine months of 2004. The per unit increase was primarily due
to the higher costs discussed above partially offset by certain fixed costs
spread over greater volumes in the first nine months of 2004. The non-cash
stock-based compensation expense was $0.04 per Mcfe of the per unit increase.
Production
taxes increased $7,000 in the first nine months of 2004. Exploration expense decreased $639,000 (14%) from $4.7 million in the
first nine months of 2003 to $4.1 million in the first nine months of 2004
primarily due to a decrease in exploratory dry hole expense partially offset by
additional non-cash stock-based compensation expense recorded in the second
quarter of 2004. We have decreased exploration activity in order to focus our
drilling efforts on lower risk developmental drilling. General and administrative expense increased $231,000 (7%) from the first
nine months of 2003 to the first nine months of 2004 due to $292,000 of
additional non-cash stock-based compensation expense recorded in the second
quarter of 2004 to reflect the increased value of our stock partially offset by
decreases in other employment and compensation related expenses. Depreciation, depletion and amortization increased by $5.1 million from
$12.6 million in the first nine months of 2003 to $17.7 million in the first
nine months of 2004. This increase was primarily due to an increase in
depletion expense. Depletion expense increased $5.3 million (54%) from $10.0
million in the first nine months of 2003 to $15.3 million in the first nine
months of 2004 due to higher gas volumes and a higher depletion rate per Mcfe.
Depletion per Mcfe increased from $0.79 per Mcfe in the first nine months of
2003 to $1.16 per Mcfe in the first nine months of 2004, primarily due to a
higher cost basis resulting from purchase accounting for the Merger in the
third quarter of 2004. Approximately $0.15 per Mcfe of the increase in
depletion per Mcfe was due to the $121 million deferred tax gross-up to
producing oil and gas properties. 18




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Derivative fair value loss was $166,000 in the first nine months of 2003
compared to $5.8 million in the first nine months of 2004. The derivative fair
value loss reflects the changes in fair value of certain derivative instruments
that are not designated or do not qualify as cash flow hedges and $1.6 million
related to the ineffective portion of crude oil swaps qualifying for hedge
accounting which was recorded in the third quarter of 2004. Interest expense increased $664,000 (4%) from $17.7 million in the first
nine months of 2003 to $18.3 million in the first nine months of 2004. This
increase was due to an increase in average outstanding borrowings partially
offset by lower blended interest rates. Income tax expense decreased $8.4 million from $2.8 million in the first
nine months of 2003 to a benefit of $5.6 million in the first nine months of
2004. The decrease was due to a decrease in income from continuing operations
before income taxes coupled with a lower effective tax rate in the nine month
period of 2004. The effective tax rate was reduced due to certain
nondeductible transaction-related expenses recorded in the one-day predecessor
period. The tax rate was also impacted by the redetermination of deferred
taxes under purchase accounting and the resulting impact on deferred tax
expense during the third quarter of 2004. The state effective tax rate is also
impacted by income in a low tax rate state offset by losses in a higher tax
rate state. Discontinued operations relating to the TBR and Arrow asset sales resulted
in a gain, net of tax, of $28.2 million in the first nine months of 2004
compared to a loss, net of tax, of $4.8 million in the first nine months of
2003. This was primarily attributable to the $45.0 million ($28.6 million net
of tax) gain recorded in the second quarter of 2004 and decreased exploration
expense as a result of the sale of the TBR properties in the second quarter of
2004. Liquidity and Capital Resources Cash Flows The primary sources of cash in the nine-month period ended September 30,
2004 have been net proceeds from the sale of our TBR and Arrow assets, funds
generated from operations and from borrowings under our credit facilities, the
merger and proceeds from our 8.75% Senior Secured Notes. Funds used during
this period were primarily used for operations, exploration and development
expenditures, interest expense, merger expenses and repayment of debt. 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 $32.9 million during the
first nine months of 2004 compared to $20.7 million in the first nine months of
2003. The increase was primarily due to higher oil and gas margins (net of
hedging) of $2.6 million and changes in working capital items of $6.6 million. Cash flows used in investing activities increased in the first nine months
of 2004 primarily due to $4.5 million of increased capital expenditures in the
first nine months of 2004. Cash flows used in financing activities in the first nine months of 2004
were primarily due to the Merger and payments on the predecessor company credit
facility. Cash flows provided by financing activities during the first nine
months of 2003 were borrowings on the credit facility to fund acquisition,
exploration and development expenditures in the first nine months of 2003. Our current ratio from continuing operations at September 30, 2004 was
0.80 to 1. During the first nine months of 2004, the working capital from
continuing operations decreased $4.3 million from a deficit of $7.1 million at
December 31, 2003 to a working capital deficit of $11.4 million at September
30, 2004. The decrease was primarily due to a $18.6 million increase in the
net current liability for the 19




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fair value of derivatives, a $7.3 million
increase in accrued expenses and a $3.3 million decrease in the deferred income
taxes asset partially offset by a $24.5 million increase in cash and cash
equivalents. The increase in accrued expenses was primarily due to a $3.0
million increase in accrued drilling costs related to the current development
drilling program and a $2.8 million increase in accrued interest expense. Capital Expenditures During the first nine months of 2004, we spent approximately $17.6
million, including exploratory dry hole expense, on our drilling activities and
other capital expenditures related to continuing operations. In the first nine
months of 2004, we drilled 71 gross (67.4 net) development wells, all of which
were successfully completed as producers in the target formation and 3 gross
(1.8 net) shallow exploratory wells, which were dry holes. These results
exclude approximately $500,000 related to three shallow exploratory wells in
progress as of September 30, 2004. If these wells are determined to be dry
holes, the cost will be charged to exploratory dry hole expense in subsequent
periods. We currently expect to spend approximately $24.3 million during 2004 on
our drilling activities and other capital expenditures related to continuing
operations. We intend to finance our planned capital expenditures through our
available cash flow, available revolving credit line and the sale of
non-strategic assets. At September 30, 2004, we had cash of $25.9 million and
approximately $15.0 million available under the revolving credit 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. Capital C Merger As disclosed in Note 1 Merger to the consolidated financial statements,
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s general partner is
Capital C Energy, LLC, an entity formed in April 2004 by David M. Carmichael,
Frost W. Cochran and Peter R. Coneway in partnership with Carlyle/Riverstone
Global Energy & Power Fund II, L.P. and Capital C Energy Partners, L.P.
Capital C Energy, LLC is headquartered in Houston, Texas. The Merger was
completed on July 7, 2004 and for financial reporting purposes will be
accounted for as a purchase effective July 1, 2004. The acquisition will
result in a new basis of accounting reflecting estimated fair values for assets
and liabilities at that date. In the Merger, each issued and outstanding share of the Company common
stock was converted into the right to receive cash. All outstanding amounts of
indebtedness under the Companys prior credit facility were repaid. In
connection with the Consent Solicitation and Tender Offer previously announced
by the Company, over 98% of the Companys $225 million aggregate principal
amount of 9-7/8% Senior Subordinated Notes were also tendered and repaid at the
closing of the Merger. As of September 30, 2004, all of the $225 million
aggregate principal amount has been paid. Capital C obtained the funds necessary to consummate the Merger through
(1) equity capital contributions of $77.5 million by its partners, (2) the
Companys entry into a secured credit facility with various lenders arranged
through Goldman Sachs Credit Partners, L.P. with a $100 million term facility
maturing on July 7, 2011, a $30 million revolving facility maturing on July 7,
2010 and a $40 million letter of credit facility, which amounts are secured by
substantially all of the assets of the Company and are guaranteed by two of the
Companys subsidiaries, Ward Lake Drilling, Inc. and The Canton Oil & Gas
Company (the Senior Facilities), and (3) a private placement of $192.5
million aggregate principal amount of 8.75% Senior Secured Notes due 2012 of
the Company (the Notes), which are secured by a 20




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second-priority lien on the
same assets and guaranteed by the same subsidiaries that guarantee the Senior
Facilities. Pre-existing commodity hedges and ten-year commodity hedges
effected in connection with the Merger will also be secured by a
second-priority lien on the same assets and guaranteed by the same subsidiaries
that guarantee the Senior Facilities and the Notes. In connection with the Merger the Company entered into commodity hedges on
a substantial portion of its future oil and gas production through the year
2013. See Note 8. Our management team remained after the Merger with the exception of the
retirement of the former Chief Executive Officer, John L. Schwager. Frost W.
Cochran is the Companys new President and Chief Executive Officer. In
addition, B. Dee Davis and W. Mac Jensen joined the Company as Senior Vice
Presidents. Upon consummation of the Merger all former directors of the
Company resigned and the new Board of Directors consisted of six members, each
of whom is elected annually to serve one-year terms. The initial six members
of the Board of Directors were Frost W. Cochran, David M. Carmichael, Michael
B. Hoffman, Pierre F. Lapeyre, Jr., David M. Leuschen, and Gregory A. Beard.
On November 1, 2004, James A. Winne III and Michael Becci were elected to our
Board of Directors and were also named Senior Vice Presidents of the Company.
Their election brings the Boards membership to eight. Financing and Credit Facilities At September 30, 2004, 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 facility that may be used only to provide credit support for our
obligations under the hedge
agreement and other hedge transactions. At September 30, 2004, the interest
rate under our base rate option was 6.50%. Under our three month LIBOR option
the rate was 4.48%. At September 30, 2004, we had $55 million of outstanding
letters of credit. At September 30, 2004, there was no outstanding balance
under the revolving credit agreement. Under the term facility the outstanding
balance was $99.75 million. We had $15 million of borrowing capacity under our
revolving credit facility available for general corporate purposes. As of
September 30, 2004, we had satisfied all financial covenants and requirements
under the existing credit facilities. From time to time we may enter into interest rate swaps to hedge the
interest rate exposure associated with the credit facility, whereby a portion
of our floating rate exposure is exchanged for a fixed interest rate. There
were no interest rate swaps in the first nine months of 2004 or 2003. 
 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 the term and
revolving credit facilities. 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 the floating rate exposure is
exchanged for a fixed interest rate. A portion of the 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 September 30, 2004 or 2003. If market interest rates for short-term
borrowings increased 1%, the increase in interest expense in the third quarter
would be approximately $254,000. This sensitivity analysis is based on our
financial structure at September 30, 2004. The commodity price risk relates to natural gas and crude oil produced,
held in storage and marketed by the Company. Our financial results can be
significantly impacted as commodity prices 21




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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
hedging 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. 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
$620,000, after considering the effects of the hedging contracts in place. At
September 30, 2004, we had hedges on a portion of our oil production for the
remainder of 2004 through 2013. We had no hedges on oil production during
2003. If the price of crude oil decreased $3.00 per Bbl, oil sales revenues
for the quarter would decrease by $58,000. We had net pretax losses on our
hedging activities of $13.2 million in the first nine months of 2004 and $9.7
million in the first nine months of 2003. Our financial results and cash flows can be significantly impacted as
commodity prices fluctuate widely in response to changing market conditions.
Accordingly, we may modify our fixed price contract and financial hedging
positions by entering into new transactions. 22




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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
October 31, 2004: Natural Gas Swaps
    
    Natural Gas Collars
    
    Crude Oil SwapsNYMEX
    
    
    
    
    
    NYMEXPrice per
    
    
    
    
    
    Price per
    
    Estimated
    
    NYMEXBbtu
    
    Mmbtu
    
    Bbtu
    
    Mmbtu Floor/Cap (1)
    
    Mbbls
    
    Price per BblQuarter EndingDecember 31, 2004
    
    
    2,040
    
    
    
    3.81
    
    
    
    1,080
    
    
    
    4.00 - 5.76
    
    
    
    74
    
    
    
    35.682,040
    
    
    $
    3.81
    
    
    
    1,080
    
    
    $
    4.00 - 5.76
    
    
    
    74
    
    
    $
    35.68March 31, 2005
    
    
    1,500
    
    
    $
    3.81
    
    
    
    1,500
    
    
    $
    4.00 - 5.32
    
    
    
    68
    
    
    $
    34.76June 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
    
    
    
    33.316,000
    
    
    $
    3.73
    
    
    
    6,000
    
    
    $
    4.00 - 5.32
    
    
    
    270
    
    
    $
    34.00March 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 2004
assume the monthly NYMEX settles at $3.00 per Mmbtu or higher. If the monthly
NYMEX settles at less than $3.00 per Mmbtu then the NYMEX price per Mmbtu will
be the NYMEX settle plus $1.00. 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 15 to 60 cents higher per Mcf than
comparable NYMEX prices. Our average price received for crude oil is typically
$2.50 to $3.25 per barrel below the NYMEX price per barrel. 
 ITEM 4. CONTROLS AND PROCEDURES As of the end of the period covered by this quarterly report, we carried
out an evaluation, under the supervision and with the participation of
management, including our Chief Executive Officer and Chief Financial Officer,
of the effectiveness of the design and operation of our disclosure controls and
procedures pursuant to Exchange Act Rule 13a-15. Based upon the evaluation,
the Chief Executive Officer and Chief Financial Officer concluded that our
disclosure controls and procedures were effective 23




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as of the end of the period
covered by this quarterly report. During the quarter ended September 30, 2004,
there have been no changes in our internal controls over financial reporting,
identified in connection with our evaluation thereof that have materially
affected, or are reasonably likely to materially affect our internal control
over financial reporting. 
 PART II Other Information 
 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 193431.2*
    
    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 193432.1*
    
    Certification of Chief Executive Officer of Belden & Blake Corporation
pursuant to 18 U.S.C. Section 1350.32.2*
    
    Certification of Chief Executive Officer of Belden & Blake Corporation
pursuant to 18 U.S.C. Section 1350.
 * Filed herewith 24




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SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, the Registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized. BELDEN & BLAKE CORPORATIONDate: November 12, 2004
    
    By:
    
    /s/ Frost W. CochranFrost W. Cochran, Director, Presidentand Chief Executive OfficerDate: November 12, 2004
    
    By:
    
    /s/ Robert W. PeshekRobert W. Peshek, Senior Vice Presidentand Chief Financial Officer
 25