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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, 2005
 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
incorporation or organization)
    
    (I.R.S. Employer
Identification No.)5200 Stoneham Road
North Canton, Ohio
    
    44720(Address of principal executive offices)
    
    (Zip Code)
 (330) 499-1660 
   
  Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.  [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 Indicate
by check mark whether the registrant is a shell company (as defined
in Rule 12b-2 of the Exchange
Act).  [   ] Yes   [X] No As of October 31, 2005, Belden & Blake Corporation had outstanding 1,534 shares of common
stock, without par value, which is its only class of stock.




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BELDEN & BLAKE CORPORATION INDEX PagePART I Financial InformationItem 1. Financial StatementsConsolidated Balance Sheets as of September 30, 2005 (Successor Company)
and December 31, 2004 (Predecessor I Company)
    
    
    1Consolidated Statements of Operations for the three months ended
September 30, 2005 and 2004:Successor Company for the 46 day period from August 16, 2005 to September 30,
2005; the Predecessor I Company 46 day period from July 1, 2005 to August 15, 2005
and 86 day period from July 7, 2004 to September 30, 2004; and the Predecessor II
Company 6 day period from July 1, 2004 to July 6, 2004
    
    
    2Consolidated Statements of Operations for the nine months ended
September 30, 2005 and 2004:Successor Company for the 46 day period from August 16, 2005 to September 30,
2005; the Predecessor I Company 227 day period from January 1, 2005 to
August 15, 2005 and 86 day period from July 7, 2004 to September 30, 2004; and the
Predecessor II Company 188 day period from January 1, 2004 to July 6, 2004
    
    
    3Consolidated Statements of Cash Flows for the nine months ended:Successor Company for the 46 day period from August 16, 2005 to September 30,
2005; the Predecessor I Company 227 day period from January 1, 2005 to
August 15, 2005 and 86 day period from July 7, 2004 to September 30, 2004; and the
Predecessor II Company 188 day period from January 1, 2004 to July 6, 2004
    
    
    4Notes to Consolidated Financial Statements
    
    
    5Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
    
    
    15Item 3. Quantitative and Qualitative Disclosures About Market Risk
    
    
    25Item 4. Controls and Procedures
    
    
    26PART II Other InformationItem 1. Legal Proceedings
    
    
    27Item 4. Submission of Matters to a Vote of Security Holders
    
    
    27Item 6. Exhibits
    
    
    27EX-10.1 First Amendment to the Credit AgreementEX-31.1 302 Certification for CEOEX-31.2 302 Certification for CFOEX-32.1 906 Certification for CEOEX-32.2 906 Certification for CFO




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CONSOLIDATED BALANCE SHEETS BELDEN & BLAKE CORPORATION
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
(unaudited) Successor
    
    
    Predecessor ISeptember 30,
    
    
    December 31,2005
    
    
    2004ASSETSCurrent assetsCash and cash equivalents
    
    $
    4,404
    
    
    
    $
    18,407Accounts receivable, net
    
    
    23,467
    
    
    
    
    18,667Inventories
    
    
    1,323
    
    
    
    
    518Deferred income taxes
    
    
    35,206
    
    
    
    
    10,558Other current assets
    
    
    1,562
    
    
    
    
    1,101Total current assets
    
    
    65,962
    
    
    
    
    49,251Property and equipment, at costOil and gas properties (successful efforts method)
    
    
    657,068
    
    
    
    
    514,242Gas gathering systems
    
    
    1,765
    
    
    
    
    4,485Land, buildings, machinery and equipment
    
    
    6,815
    
    
    
    
    7,720665,648
    
    
    
    
    526,447Less accumulated depreciation, depletion and amortization
    
    
    4,568
    
    
    
    
    16,917Property and equipment, net
    
    
    661,080
    
    
    
    
    509,530Goodwill
    
    
    89,270
    
    
    
    
    Other assets
    
    
    2,878
    
    
    
    
    11,461$
    819,190
    
    
    
    $
    570,242LIABILITIES AND SHAREHOLDERS EQUITYCurrent liabilitiesAccounts payable
    
    $
    4,464
    
    
    
    $
    3,796Accrued expenses
    
    
    25,464
    
    
    
    
    23,445Current portion of long-term liabilities
    
    
    653
    
    
    
    
    1,964Fair value of derivatives
    
    
    85,638
    
    
    
    
    23,252Total current liabilities
    
    
    116,219
    
    
    
    
    52,457Long-term liabilitiesBank and other long-term debt
    
    
    52,087
    
    
    
    
    88,592Senior secured notes
    
    
    200,681
    
    
    
    
    192,500Subordinated
promissory note-related party
    
    
    25,000
    
    
    
    
    Asset retirement obligations and other long-term liabilities
    
    
    19,712
    
    
    
    
    14,390297,480
    
    
    
    
    295,482Fair value of derivatives
    
    
    214,828
    
    
    
    
    55,182Deferred income taxes
    
    
    91,941
    
    
    
    
    108,994Shareholders equityCommon stock without par value: Successor; 3,000 shares authorized;
1,534 issued; Predecessor; 1,500 shares authorized and issued
    
    
    
    
    
    
    
    Paid in capital
    
    
    125,000
    
    
    
    
    77,500Retained earnings
    
    
    909
    
    
    
    
    890Accumulated other comprehensive loss
    
    
    (27,187
    )
    
    
    
    (20,263
    )Total shareholders equity
    
    
    98,722
    
    
    
    
    58,127$
    819,190
    
    
    
    $
    570,242
 See accompanying notes. 1




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CONSOLIDATED STATEMENTS OF OPERATIONS BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, in thousands) Three Months Ended September 30, 2005
    
    Three Months Ended September 30, 2004Predecessor IISuccessor Company
    
    
    Predecessor I Company
    
    
    CompanyFor the 46 Day
    
    
    For the 46 Day
    
    For the 86 Day
    
    
    For the 6 DayPeriod From
    
    
    Period From
    
    Period From
    
    
    Period FromAugust 16, 2005 to
    
    
    July 1, 2005 to
    
    July 7, 2004 to
    
    
    July 1, 2004 toSeptember 30, 2005
    
    
    August 15, 2005
    
    September 30, 2004
    
    
    July 6, 2004(Restated)
    
    
    (Restated)RevenuesOil and gas sales
    
    $
    16,620
    
    
    
    $
    13,146
    
    
    $
    21,896
    
    
    
    $
    Gas gathering and marketing
    
    
    1,625
    
    
    
    
    1,419
    
    
    
    2,179
    
    
    
    
    Other
    
    
    81
    
    
    
    
    67
    
    
    
    550
    
    
    
    
    18,326
    
    
    
    
    14,632
    
    
    
    24,625
    
    
    
    
    ExpensesProduction expense
    
    
    3,284
    
    
    
    
    2,667
    
    
    
    5,500
    
    
    
    
    1,171Production taxes
    
    
    524
    
    
    
    
    406
    
    
    
    650
    
    
    
    
    Gas gathering and marketing
    
    
    1,441
    
    
    
    
    1,209
    
    
    
    2,026
    
    
    
    
    46Exploration expense
    
    
    379
    
    
    
    
    490
    
    
    
    1,334
    
    
    
    
    503General and administrative expense
    
    
    381
    
    
    
    
    618
    
    
    
    1,100
    
    
    
    
    1,172Franchise, property and other taxes
    
    
    41
    
    
    
    
    30
    
    
    
    67
    
    
    
    
    Depreciation, depletion and
amortization
    
    
    4,528
    
    
    
    
    4,248
    
    
    
    8,611
    
    
    
    
    Accretion expense
    
    
    149
    
    
    
    
    163
    
    
    
    134
    
    
    
    
    Derivative fair value loss
    
    
    3,263
    
    
    
    
    6,212
    
    
    
    4,016
    
    
    
    
    2,359Transaction expenses
    
    
    
    
    
    
    
    7,535
    
    
    
    
    
    
    
    
    26,00113,990
    
    
    
    
    23,578
    
    
    
    23,438
    
    
    
    
    31,252Operating income (loss)
    
    
    4,336
    
    
    
    
    (8,946
    )
    
    
    1,187
    
    
    
    
    (31,252
    )Other expenseInterest expense
    
    
    2,903
    
    
    
    
    3,010
    
    
    
    6,143
    
    
    
    
    Income (loss) from continuing operations
before income taxes
    
    
    1,433
    
    
    
    
    (11,956
    )
    
    
    (4,956
    )
    
    
    
    (31,252
    )Provision (benefit) for income taxes
    
    
    524
    
    
    
    
    (3,983
    )
    
    
    (2,314
    )
    
    
    
    (7,439
    )Income (loss) from continuing operations
    
    
    909
    
    
    
    
    (7,973
    )
    
    
    (2,642
    )
    
    
    
    (23,813
    )Income from discontinued operations, net of tax
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    241Net income (loss)
    
    $
    909
    
    
    
    $
    (7,973
    )
    
    $
    (2,642
    )
    
    
    $
    (23,572
    )
 See accompanying notes. 2




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CONSOLIDATED STATEMENTS OF OPERATIONS BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited, in thousands) Nine Months Ended September 30, 2005
    
    Nine Months Ended September 30, 2004Predecessor IISuccessor Company
    
    
    Predecessor I Company
    
    
    CompanyFor the 46 Day
    
    
    For the 227 Day
    
    For the 86 Day
    
    
    For the 188 DayPeriod From
    
    
    Period From
    
    Period From
    
    
    Period FromAugust 16, 2005 to
    
    
    January 1, 2005 to
    
    July 7, 2004 to
    
    
    January 1, 2004 toSeptember 30, 2005
    
    
    August 15, 2005
    
    September 30, 2004
    
    
    July 6, 2004(Restated)
    
    
    (Restated)RevenuesOil and gas sales
    
    $
    16,620
    
    
    
    $
    60,576
    
    
    $
    21,896
    
    
    
    $
    45,307Gas gathering and marketing
    
    
    1,625
    
    
    
    
    6,439
    
    
    
    2,179
    
    
    
    
    5,057Other
    
    
    81
    
    
    
    
    284
    
    
    
    550
    
    
    
    
    45818,326
    
    
    
    
    67,299
    
    
    
    24,625
    
    
    
    
    50,822ExpensesProduction expense
    
    
    3,284
    
    
    
    
    13,423
    
    
    
    5,500
    
    
    
    
    12,122Production taxes
    
    
    524
    
    
    
    
    1,901
    
    
    
    650
    
    
    
    
    1,300Gas gathering and marketing
    
    
    1,441
    
    
    
    
    5,629
    
    
    
    2,026
    
    
    
    
    4,579Exploration expense
    
    
    379
    
    
    
    
    2,424
    
    
    
    1,334
    
    
    
    
    3,220General and administrative expense
    
    
    381
    
    
    
    
    3,835
    
    
    
    1,100
    
    
    
    
    3,672Franchise, property and other taxes
    
    
    41
    
    
    
    
    129
    
    
    
    67
    
    
    
    
    115Depreciation, depletion and
amortization
    
    
    4,528
    
    
    
    
    21,265
    
    
    
    8,611
    
    
    
    
    9,089Accretion expense
    
    
    149
    
    
    
    
    745
    
    
    
    134
    
    
    
    
    195Derivative fair value loss
    
    
    3,263
    
    
    
    
    12,307
    
    
    
    4,016
    
    
    
    
    2,038Transaction expenses
    
    
    
    
    
    
    
    7,535
    
    
    
    
    
    
    
    
    26,00113,990
    
    
    
    
    69,193
    
    
    
    23,438
    
    
    
    
    62,331Operating income (loss)
    
    
    4,336
    
    
    
    
    (1,894
    )
    
    
    1,187
    
    
    
    
    (11,509
    )Other expenseInterest expense
    
    
    2,903
    
    
    
    
    14,786
    
    
    
    6,143
    
    
    
    
    12,184Income (loss) from continuing operations
before income taxes
    
    
    1,433
    
    
    
    
    (16,680
    )
    
    
    (4,956
    )
    
    
    
    (23,693
    )Provision (benefit) for income taxes
    
    
    524
    
    
    
    
    (7,011
    )
    
    
    (2,314
    )
    
    
    
    (4,824
    )Income (loss) from continuing operations
    
    
    909
    
    
    
    
    (9,669
    )
    
    
    (2,642
    )
    
    
    
    (18,869
    )Income from discontinued operations, net of tax
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    28,868Net income (loss)
    
    $
    909
    
    
    
    $
    (9,669
    )
    
    $
    (2,642
    )
    
    
    $
    9,999
 See accompanying notes. 3




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CONSOLIDATED STATEMENTS OF CASH FLOWS BELDEN & BLAKE CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited, in thousands) Nine Months Ended September 30, 2005
    
    Nine Months Ended September 30, 2004Predecessor IISuccessor Company
    
    
    Predecessor I Company
    
    
    CompanyFor the 46 Day
    
    
    For the 227 Day
    
    For the 86 Day
    
    
    For the 188 DayPeriod From
    
    
    Period From
    
    Period From
    
    
    Period FromAugust 16, 2005 to
    
    
    January 1, 2005 to
    
    July 7, 2004 to
    
    
    January 1, 2004 toSeptember 30, 2005
    
    
    August 15, 2005
    
    September 30, 2004
    
    
    July 6, 2004(Restated)
    
    
    (Restated)Cash flows from operating activities:Net income (loss)
    
    $
    909
    
    
    
    $
    (9,669
    )
    
    $
    (2,642
    )
    
    
    $
    9,999Adjustments
to reconcile net income (loss) to net cash provided by operating activities:Depreciation, depletion and amortization
    
    
    4,528
    
    
    
    
    21,265
    
    
    
    8,611
    
    
    
    
    9,723Accretion
    
    
    149
    
    
    
    
    745
    
    
    
    134
    
    
    
    
    221Gain on sale of businesses
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (45,223
    )(Gain) loss on disposal of property and equipment
    
    
    (21
    )
    
    
    
    86
    
    
    
    37
    
    
    
    
    375Amortization of derivatives and other noncash hedging activities
    
    
    (288
    )
    
    
    
    7,359
    
    
    
    3,788
    
    
    
    
    2,037Exploration expense
    
    
    379
    
    
    
    
    2,424
    
    
    
    1,334
    
    
    
    
    4,639Deferred income taxes
    
    
    524
    
    
    
    
    (7,011
    )
    
    
    (2,314
    )
    
    
    
    10,802Stock-based compensation
    
    
    
    
    
    
    
    2,586
    
    
    
    
    
    
    
    
    3,990Change in operating assets and liabilities, net of
effects of acquisition and disposition of businesses:Accounts receivable and other operating assets
    
    
    (877
    )
    
    
    
    (369
    )
    
    
    3,422
    
    
    
    
    (900
    )Inventories
    
    
    (571
    )
    
    
    
    (85
    )
    
    
    112
    
    
    
    
    79Accounts payable and accrued expenses
    
    
    3,427
    
    
    
    
    (8,845
    )
    
    
    (993
    )
    
    
    
    678Net cash
provided by (used in) operating activities
    
    
    8,159
    
    
    
    
    8,486
    
    
    
    11,489
    
    
    
    
    (3,580
    )Cash flows from investing activities:Disposition of businesses, net of cash
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    72,464Proceeds from property and equipment disposals
    
    
    21
    
    
    
    
    5
    
    
    
    117
    
    
    
    
    247Exploration expense
    
    
    (379
    )
    
    
    
    (2,424
    )
    
    
    (1,334
    )
    
    
    
    (4,639
    )Additions to property and equipment
    
    
    (4,942
    )
    
    
    
    (17,177
    )
    
    
    (4,482
    )
    
    
    
    (18,597
    )(Increase) decrease in other assets
    
    
    (11
    )
    
    
    
    (34
    )
    
    
    (18
    )
    
    
    
    1,218Net cash (used in) provided by investing activities
    
    
    (5,311
    )
    
    
    
    (19,630
    )
    
    
    (5,717
    )
    
    
    
    50,693Cash flows from financing activities:Proceeds from senior secured notes
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    192,500Proceeds from senior secured facility  term loan
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    100,000Proceeds from senior secured facility
    
    
    
    
    
    
    
    57,000
    
    
    
    
    
    
    
    
    Sale of common stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    77,500Proceeds
from subordinated promissory note
    
    
    
    
    
    
    
    25,000
    
    
    
    
    
    
    
    
    Repayment of senior subordinated notes
    
    
    
    
    
    
    
    
    
    
    
    (1,040
    )
    
    
    
    (223,960
    )Payment to shareholders and optionholders
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (113,674
    )Debt issue costs
    
    
    
    
    
    
    
    (2,120
    )
    
    
    
    
    
    
    
    (11,700
    )Repayment of senior secured facility  term loan
    
    
    
    
    
    
    
    (89,500
    )
    
    
    (250
    )
    
    
    
    Repayment of senior secured facility
    
    
    (5,000
    )
    
    
    
    
    
    
    
    Proceeds from revolving line of credit
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    146,636Repayment of long-term debt and other obligations
    
    
    (3
    )
    
    
    
    (84
    )
    
    
    
    
    
    
    
    (194,187
    )Equity contribution
    
    
    
    
    
    
    
    9,000
    
    
    
    
    
    
    
    
    Proceeds from stock options exercised
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    111Repurchase of stock options
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (283
    )Purchase of treasury stock
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (29
    )Net cash used in financing activities
    
    
    (5,003
    )
    
    
    
    (704
    )
    
    
    (1,290
    )
    
    
    
    (27,086
    )Net
(decrease) increase in cash and cash equivalents
    
    
    (2,155
    )
    
    
    
    (11,848
    )
    
    
    4,482
    
    
    
    
    20,027Cash and cash equivalents at beginning of period
    
    
    6,559
    
    
    
    
    18,407
    
    
    
    21,467
    
    
    
    
    1,440Cash and cash equivalents at end of period
    
    $
    4,404
    
    
    
    $
    6,559
    
    
    $
    25,949
    
    
    
    $
    21,467
 See accompanying notes. 4




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##### Table of Contents



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS BELDEN & BLAKE CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Restated)(Unaudited) September 30, 2005 (1) Restatement and Amendment We filed amendments to our Annual Report on Form 10-K for the year ended December 31, 2004
(the 2004 Form 10-K) and to our Quarterly Report on Form 10-Q for the quarter ended March 31,
2005 (the First Quarter 10-Q) to amend and restate the financial statements and other financial
information contained in those reports with respect to the accounting and disclosures for (1) stock
options that should have resulted in additional non-cash compensation expense when it was probable
that the employee would be able to put those options back to the company within six months of
issuance of the shares, (2) the presentation of realized gain or loss on derivatives that do not
qualify for hedge accounting treatment in the line item Derivative fair value (gain) or loss, (3)
the presentation of the predecessor period as ending on July 6, 2004 rather than July 1, 2004, (4)
the presentation of transaction expenses related to the merger in the operating activities section
of the statements of cash flows rather than in the financing activities section and (5) the
presentation of the effect of cash flows from discontinued operations in each of the operating,
investing and financing sections of the statements of cash flows. The restatement had no impact on
our net (loss) income for the first quarters of 2005 and 2004. The applicable amendments and
restatements described above are included in this Quarterly Report on Form 10-Q for the quarter
ended September 30, 2005. The information contained in the amendment to the 2004 Form 10-K, including the financial
statements and the notes thereto, amends only Items 1, 2, 6, 7, 7A and 8 of our originally filed
Annual Report on Form 10-K for the year ended December 31, 2004, in each case to reflect only the
adjustments described below, and no other information in our originally filed 2004 Form 10-K is
amended hereby. The amendment to the 2004 Form 10-K does not reflect events occurring after March
31, 2005, the date of the original filing of our 2004 Form 10-K, or modify or update those
disclosures that may have been affected by subsequent events. In addition, currently-dated
certifications from our Chief Executive Officer and Chief Financial Officer have been included as
exhibits to the amendment to the 2004 Form 10-K. The information contained in the amendment to the First Quarter 10-Q, including the financial
statements and the notes thereto, reflect only the adjustments described above and do not reflect
events occurring after May 10, 2005, the date of the original
filing of the First Quarter 10-Q. In
addition, currently-dated certifications from our Chief Executive Officer and Chief Financial
Officer have been included as exhibits to the amendment to the First Quarter 10-Q. Restatement of stock options compensation expense. We had stock options outstanding at the
time of the merger that occurred on July 7, 2004. Upon the merger, these stock options were
cancelled in exchange for cash in the amount of the excess of the merger price per share over the
per share exercise price of the option. Some of these options were subject to variable accounting
as a result of the strike price having been previously re-priced. This resulted in non-cash
compensation expense of $1.1 million that was previously reported. The remaining options were
previously not reported as variable accounting. We concluded that these stock options should have
resulted in compensation expense when it was probable that the employee would be able to put those
options back to the Company within six months of issuance of the shares. As a result of the
merger, the options became exercisable and were simultaneously cancelled in exchange for cash. The
adjustment recognizes additional non cash compensation expense of approximately $2.9 million
(pre-tax) in the six day predecessor II period ended
July 6, 2004. As a result, income taxes were adjusted by $1.1 million. 5




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Restatement of realized gain or loss on derivatives that do not qualify for hedge accounting
treatment. We previously reported all unrealized gains and losses from derivatives on a single
line item in the statement of operations. Upon realization, we previously reported all derivative
gains and losses as a component or adjustment of the related oil or gas revenue. The adjustment
records the realized gain or loss on derivatives that do not qualify for hedge accounting treatment
in the line item Derivative fair value (gain) or loss. As a result, our oil and gas revenues do
not include realized gains and losses from non-qualified derivatives. Presentation of the predecessor period ending July 6, 2004. Capital C Energy Operations, LP
(Capital C), acquired us pursuant to a merger that was completed on July 7, 2004. We previously
disclosed that for financial reporting purposes the merger was accounted for as a purchase
effective July 1, 2004. We amended the 2004 Form 10-K and the First Quarter 10-Q to report the
merger as effective on July 7, 2004. This change in presentation has no impact on the balance
sheet, statement of operations or statement of cash flows other than to present the predecessor
period as ending on July 6, 2004 rather than July 1, 2004. The operating results for the six-day
period were not material and have been included in the successor period beginning on July 7, 2004. Presentation of transaction expenses in the statements of cash flows. We previously reported
transaction expenses related to the merger of $22.6 million in the financing activity section of
the statements of cash flows. We amended the 2004 Form 10-K to present these expenses in the
operating activities section of the statements of cash flows. Presentation of cash flows from discontinued operations in the statements of cash flows. We
previously reported discontinued operations as a single line item in the statements of cash flows.
We amended the 2004 Form 10-K and the First Quarter 10-Q to present the cash flows from
discontinued operations in each of the operating, investing and financing sections of the
statements of cash flows. (2) Change in Control, Merger and Basis of Presentation Unless the context requires otherwise or unless otherwise noted, when we use the terms Belden
& Blake, we, us, our or the Company, we are referring to Belden & Blake Corporation
(Successor Company) and its predecessors. On August 16, 2005, the former partners of the direct
parent of Belden & Blake Corporation (Company),
Capital C Energy Operations, L.P., a Delaware
limited partnership (Capital C), completed the sale of all of the partnership interests in
Capital C to certain institutional funds managed by EnerVest Management Partners, Ltd.
(EnerVest), a Houston-based privately held oil and gas operator and institutional funds manager
(the Transaction). The Transaction resulted in a change in control of the Company (Change in
Control). On July 7, 2004, the Company, 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 was controlled by Carlyle/Riverstone Global Energy and Power Fund
II, L.P until the Transaction on August 16, 2005. The
Transaction and Merger were each accounted for as a purchase effective August 16, 2005 and July
7, 2004, respectively. The Transaction and Merger resulted in a new basis of accounting reflecting
estimated fair values for assets and liabilities at August 16, 2005 and July 7, 2004. Accordingly,
the financial statements for the period subsequent to August 15, 2005 are presented on the
Companys new
basis of accounting, while the results of operations for prior periods reflect the historical
results of the two 6




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##### Table of Contents



predecessor companies. Vertical black lines are presented to separate the
financial statements of the two predecessor companies and the successor company. The Successor
Company refers to the period from August 16, 2005 and forward. The Predecessor I Company refers
to the period from July 7, 2004 through August 15, 2005. The Predecessor II Company refers to
the period prior to July 7, 2004. The aggregate value of the total equity consideration paid for the Transaction was $125
million. The table below summarizes the preliminary allocation of the Transactions purchase price
based on the acquisition date fair values of the assets acquired and the liabilities assumed. The
purchase price allocation is preliminary and subject to change as additional information becomes
available. (in thousands)Net working capital, including
cash of $6,559
    
    $
    3,657Oil and gas properties
    
    
    652,569Goodwill
    
    
    89,270Other assets
    
    
    11,292Derivative liability
    
    
    (258,417
    )Other non-current liabilities
    
    
    (19,693
    )Net deferred income tax liabilities
    
    
    (70,909
    )Long-term debt
    
    
    (282,769
    )Equity contribution
    
    $
    125,000
 Goodwill represents the excess of the purchase price over the estimated fair value of the
assets acquired net of the fair value of liabilities assumed in the acquisition. The recorded goodwill is not deductible for tax purposes. The principal factors that contributed to the purchase price that resulted in goodwill are as
follows:  
    
    Cost savings and operational synergies of the Company when combined with the other
operations managed by EnerVest. These savings include the elimination of duplicative
facilities, reduction of personnel and operating and development costs through the
management of a larger asset base.
    
    The affiliation with EnerVest, an acquisition-focused company, coupled with the enhanced
presence in the Appalachian and Michigan basins with EnerVests
other operations, provides
the opportunity to create value by highgrading investment opportunities and identifying new
investment opportunities.
    
    The going-concern value of the Company, including its experienced workforce.
    
    A deferred tax liability was recorded to recognize the difference between the historical
tax basis of the assets and the acquisition costs recorded for book purposes. Goodwill was
recorded to recognize this tax basis differential. SFAS No. 142, Goodwill and Other Intangible Assetsrequires that intangible assets with
indefinite lives, including goodwill, be evaluated on an annual basis for impairment or more
frequently if an event occurs or circumstances change could potentially result in an impairment. The impairment test requires the allocation of goodwill and all other assets and liabilities
to reporting units. As the Company has only one reporting unit the reporting unit used for testing will be the entire company. The fair value
of the 7




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##### Table of Contents



reporting unit is determined and compared to the book value of that reporting unit. If the
fair value of the reporting unit is less than the book value (including goodwill) then goodwill is
reduced to its fair value and the amount of the writedown is charged to earnings. The fair value of the reporting unit will be based on estimates of future net cash flows
from proved reserves and from future exploration for and development of unproved reserves. Downward
revisions of estimated reserves or production, increases in estimated future costs or decreases in
oil and gas prices could lead to an impairment of all or a portion of goodwill in future periods. In connection with the Transaction, the Company entered into Compensation Agreements
(Compensation Agreements), each on substantially similar terms, with James A. Winne III, the
Companys former Chairman of the Board and Chief Executive Officer, and Michael Becci, the
Companys former President and Chief Operating Officer. The Compensation Agreements provide for a
severance payment equal to $250,000 and the issuance of 17.1037 restricted shares of common stock
in the Company, payable to each of Messrs. Winne and Becci promptly upon the Transaction. In
exchange for their severance payments, Messrs. Winne and Becci resigned as officers and directors
of the Company effective August 16, 2005. This was reported as compensation expense of $3.1
million and included in the transaction expenses in the predecessor I period ending August 15,
2005. The Company entered into a Contingent Value Agreement (Contingent Value Agreement) with the
former partners of Capital C, Messrs. Becci and Winne, and the EnerVest funds that purchased
Capital C. Under the Contingent Value Agreement, if properties are contributed to a publicly traded
partnership or a publicly traded royalty trust (MLP), then the Company has agreed to pay the
following aggregate amount to the former partners of Capital C, and Messrs. Becci and Winne:  
    
    20% of the difference between the value received for the assets upon transfer to a MLP and
the book value of the assets, if the transfer occurs within one year following the
Transaction; and
    
    10% of the difference between the value received for the assets upon transfer to a MLP and
the book value of the assets, if the transfer occurs in the second year following the
Transaction. The Company does not intend to contribute assets to a publicly traded partnership, publicly traded
royalty trust or MLP at this time. The Companys management team remained with the Company following the Change in Control
Transaction with the exception of James A. Winne III, who resigned as Chairman of the Board of
Directors and Chief Executive Officer of the Company, and Michael Becci, who resigned as director,
President and Chief Operating Officer of the Company. Upon consummation of the Transaction, all of
the members of the board of directors of the Company resigned on August 16, 2005 and Capital C
replaced the board with John B. Walker, James M. Vanderhider, Mark A. Houser, Ken Mariani and
Matthew Coeny. Each such individual shall serve a term ending on the date of the annual meeting of
shareholders to be held in 2006. On August 16, 2005, the board of directors of the Company appointed Mark A. Houser as Chairman
and Chief Executive Officer and James M. Vanderhider as President and Chief Operating Officer. On
October 3, 2005, James M. Vanderhider resigned as Chief Operating Officer and the Board of
Directors of the Company appointed Ken Mariani as its Senior Vice President and Chief Operating
Officer. On October 6, 2005, Robert W. Peshek resigned as Senior Vice President and Chief
Financial Officer and the Board of Directors of the Company appointed James M. Vanderhider as its
Chief Financial Officer. We
incurred transaction costs associated with the Transaction of
$7.5 million including $500,000 of severance costs. These costs were expensed in the predecessor I company period ended
August 15, 2005. 8




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##### Table of Contents



We also capitalized $2.1 million of debt financing costs and recorded obligations
of $5.5 million in purchase accounting including $4.2 million of severance cost and $1.2 million of
acquisition costs incurred by EnerVest. Following are unaudited pro forma results of operations as if the Merger occurred at the
beginning of 2004 (in thousands): Nine months ended September 30,2005
    
    2004Total revenues
    
    $
    85,625
    
    
    $
    75,447Loss from continuing operations
    
    
    (6,257
    )
    
    
    (9,216
    )
 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 2004 and is not intended to be a projection of future results or trends. In the second quarter of 2004, we sold substantially all of our Trenton Black River (TBR)
assets and our Arrow Oilfield Service Company (Arrow) assets. According to Statement of
Financial Accounting Standards No. (SFAS) 144, Accounting for the Impairment or Disposal of
Long-Lived Assets, the dispositions were classified as discontinued operations. Discontinued
operations relating to the TBR and Arrow asset sales resulted in a
gain of $45.2 million ($28.9
million net of tax) in the first nine months of 2004. 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 period ended September 30, 2005 are not necessarily
indicative of the results that may be expected for the year ended December 31, 2005. For further
information, refer to the consolidated financial statements and footnotes included in Amendment No.
1 to our Annual Report on Form 10-K for the year ended December 31, 2004, as amended. Certain
reclassifications have been made to conform to the current presentation. 9




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##### Table of Contents



(3) Long-Term Debt Successor Company
    
    
    Predecessor I CompanySeptember 30, 2005
    
    
    December 31, 2004Long-term debt consists of the following (in thousands)Revolving Credit facility
    
    $
    52,000
    
    
    
    $
    Senior secured facility
    
    
    
    
    
    
    
    89,500Senior secured notes
    
    
    200,681
    
    
    
    
    192,500Subordinated promissory note
    
    
    25,000
    
    
    
    
    Other
    
    
    93
    
    
    
    
    97277,774
    
    
    
    
    282,097Less current portion
    
    
    6
    
    
    
    
    1,005Long-term debt
    
    $
    277,768
    
    
    
    $
    281,092
 Amended Credit Agreement On August 16, 2005, the Company amended and restated its existing $170 million Credit
Agreement, dated as of July 7, 2004 and amended as of July 22, 2004, by and among the Company, as
borrower, the various lenders
named therein, Goldman Sachs Credit Partners, L.P., as sole lead arranger, sole book runner,
syndication agent and administrative agent, and General Electric Capital Corporation and National
City Bank, as co-documentation agents, by entering into a First Amended and Restated Credit and
Guaranty Agreement (Amended Credit Agreement) by and among the Company and BNP Paribas, as sole
lead arranger, sole book runner, syndication agent and administrative agent. The Amended Credit
Agreement provides for loans and other extensions of credit to be made to the Company up to a
maximum aggregate principal amount of $390 million. The obligations under the Amended Credit
Agreement are secured by substantially all of the assets of the Company. The Amended Credit Agreement provides for a revolving credit line in the aggregate principal
amount of $350 million and a hedge letter of credit facility in the aggregate principal amount of
$40 million. Borrowings under the Amended Credit Agreement may not exceed the borrowing base, which
was initially set at $80.25 million, of which $57 million was drawn at closing on August 16, 2005.
At September 30, 2005, the outstanding balance was $52 million. Borrowings under the Amended Credit Agreement bear interest (i) at the greater of the prime
rate or an adjusted federal funds rate, plus an applicable margin ranging from 0% to 0.625% based
on the aggregate principal amount outstanding under the Amended Credit Agreement, or, (ii) at the
Companys option, the Eurodollar base rate plus an applicable margin ranging from 1.125% to 2.125%
based on the aggregate principal amount outstanding under the Amended Credit Agreement. The full
amount borrowed under the Amended Credit Agreement will mature on August 16, 2010. The obligations under the Amended Credit Agreement are secured by a first lien security
interest in substantially all of the assets of the Company. The obligations under the Amended
Credit Agreement are further secured by a pledge of 100% of the capital stock of the Company held
by Capital C, the Companys parent. 10




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##### Table of Contents



The Amended Credit Agreement contains covenants that will limit the ability of the Company to,
among other things, incur or guarantee additional indebtedness; create liens; pay dividends on or
repurchase stock of the Company or its subsidiaries; pay principal and interest on certain
subordinated debt; make certain types of investments; sell assets or merge with another entity;
pledge or otherwise encumber the capital stock of the Company or its subsidiaries; or enter into
transactions with affiliates. The Amended Credit Agreement also requires compliance with customary
financial covenants, including a minimum interest coverage ratio, a maximum leverage ratio and a
minimum current ratio. As of September 30, 2005, we were in compliance with all financial
covenants and requirements under the existing credit facilities. Borrowings under the revolving credit line will be used by the Company for general corporate
purposes, including refinancing of existing indebtedness. In accordance with the terms of the
Amended
Credit Agreement, letters of credit issued under the hedge letter of credit commitment and any
related borrowings are to be used solely to secure payment of the Companys obligations under the
J. Aron Swap (defined hereinafter). In connection with the Companys entry into the Amended Credit Agreement, the Company executed
a Subordinated Promissory Note (Note) in favor of Capital C in the maximum principal amount of
$94 million. Under the Note, Capital C loaned $25 million to the Company on August 16, 2005. The
Note accrues interest at a rate of 10% per annum and matures on August 16, 2012. We received a
fairness opinion from an unrelated financial services firm with respect to the terms of the Note
made on August 16, 2005. Interest payments on the Note are due quarterly commencing September 30,
2005. In lieu of cash payments, the Company has the option to make interest payments on the Note
by borrowing additional amounts against the Note. The interest payment on September 30, 2005 was
paid in cash. The Note has no prepayment penalty or premium and may be prepaid in whole or in part
at any time. The Note is expressly subordinate to the Companys senior debt, which includes
obligations under the Amended Credit Agreement, the J. Aron Swap and notes issued under the
Companys Indenture dated July 7, 2004 with BNY Midwest Trust Company, as indenture trustee
(Senior Secured Notes). On
August 16, 2005 the Company repaid the amounts outstanding under the
term facility with cash
borrowed under the Amended Credit Agreement. ISDA Master Agreement The Company amended and restated the Schedule and Credit Support Annex to its ISDA Master
Agreement, dated as of June 30, 2004, by and between the Company and J. Aron & Company (J. Aron
Swap), pursuant to which the Company has agreed, from time to time, to enter into cash-settled
hedge transactions with J. Aron & Company, as hedge counterparty, in connection with various gas
and oil commodity derivatives transactions. The amendments to the J. Aron Swap conform the terms of
the Schedule and Credit Support Annex to the terms of the Amended Credit Agreement, change certain
covenants and reduce the maximum amount of the letter of credit securing the hedge obligations from
$55 million to $40 million. Senior Secured Notes We have Senior Secured Notes outstanding with a principal amount of $192.5 million. As a
result of the application of purchase accounting, the notes were recorded as a liability based on
the estimated fair value of $200,681,000 on the Transaction date. The Transaction resulted in a change of control of the Company under the indenture governing
the Senior Secured Notes. We commenced a tender offer for the Senior Secured Notes, as required
under the indenture, on August 26, 2005. The tender offer expired on October 12, 2005 with no
notes tendered. 11




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##### Table of Contents



(4) Derivatives and Hedging Our financial results and cash flows can be significantly impacted as commodity prices
fluctuate widely in response to changing market conditions. As a result of the adoption of SFAS
133, Accounting for Derivative Instruments and Hedging Activities, we recognize all derivative
financial instruments as either assets or liabilities at fair value. Derivative instruments that
are not hedges must be adjusted to fair value through net income (loss). Under the provisions of
SFAS 133, changes in the fair value of derivative instruments that are fair value hedges are offset
against changes in the fair value of the hedged assets, liabilities, or firm commitments, through
net income (loss). Changes in the fair value of derivative instruments that are cash flow hedges
are recognized in other comprehensive income (loss) until such time as the hedged items are
recognized in net income (loss). Ineffective portions of a
derivative instruments change in fair value are immediately recognized in net income (loss).
Deferred gains and losses on terminated commodity hedges will be recognized as increases or
decreases to oil and gas revenues during the same periods in which the underlying forecasted
transactions are recognized in net income (loss). If there is a discontinuance of a cash flow
hedge because it is probable that the original forecasted transaction will not occur, deferred
gains or losses are recognized in earnings immediately. The relationship between the hedging instruments and the hedged items must be highly effective
in achieving the offset of changes in fair values or cash flows attributable to the hedged risk,
both at the inception of the contract and on an ongoing basis. Ongoing assessments of hedge
effectiveness include verifying and documenting that the critical terms of the hedge and forecasted
transaction do not change. We measure effectiveness at least on a quarterly basis. From time to time we may enter into a combination of futures contracts, commodity derivatives
and fixed-price physical contracts to manage our exposure to natural gas or crude oil price
volatility and support our capital expenditure plans. Our derivative financial instruments take
the form of swaps or collars. At September 30, 2005, our derivative contracts were comprised of
natural gas swaps and collars and crude oil swaps, which were placed with a major financial
institution that we believe is a minimal credit risk. Qualifying derivative financial instruments
are designated as cash flow hedges. The changes in fair value of non-qualifying derivative
contracts will be reported in expense in the consolidated statements of operations as derivative
fair value loss. We consider our natural gas swaps to be highly effective and expect there will be no
ineffectiveness to be recognized in net income (loss) since the critical terms of the hedging
instruments and the hedged forecasted transactions are the same. We have not experienced
ineffectiveness on our natural gas swaps because we use New York Mercantile Exchange (NYMEX)
based commodity derivative contracts to hedge on the same basis as our natural gas production is
sold (NYMEX-based sales contracts). We have collar agreements that could not be redesignated as
cash flow hedges because these collars were not effective due to unrealized losses at the date of
the Merger and Transaction. These collars qualified and were designated as cash flow hedges from
their inception through the predecessor II company period ended July 6, 2004. Although these
collars are not deemed to be effective hedges in accordance with the provisions of SFAS 133, we
have retained these instruments as protection against changes in commodity prices and we will
continue to record the mark-to-market adjustments on these natural gas collars, through 2005, in
our income statement. Our NYMEX crude oil swaps are highly effective and were designated as cash
flow hedges. We have ineffectiveness on the crude oil swaps because the oil is sold locally at a
posted price which is different from the NYMEX price. Historically, there has been a high
correlation between the posted price and the NYMEX price. The changes in the fair values of the
natural gas collars and the ineffective portion of the crude oil swaps are recorded as Derivative
fair value (gain) loss. During the first nine months of 2005 and 2004, net losses of $19.7 million ($13.5 million
after tax) and $13.2 million ($8.4 million after tax), respectively, were reclassified from
accumulated other 12




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##### Table of Contents



comprehensive income to earnings. The fair value of open hedges decreased $234.4
million ($161.0 million after tax) in the first nine months of 2005 and decreased $58.0 million
($36.8 million after tax) in the first nine months of 2004. At September 30, 2005, the estimated
net loss in accumulated other comprehensive income that is expected to be reclassified into
earnings within the next 12 months is approximately $27.1 million. At September 30, 2005, we have
partially hedged our exposure to the variability in future cash flows through December 2013. The following table reflects the natural gas and crude oil volumes and the weighted average
prices under financial hedges (including settled hedges) at September 30, 2005: Natural Gas Swaps
    
    Natural Gas Collars
    
    Crude Oil SwapsNYMEX
    
    
    
    
    
    NYMEX Price
    
    
    
    
    
    NYMEXPrice per
    
    
    
    
    
    per Mmbtu
    
    Estimated
    
    Price perQuarter Ending
    
    Bbtu
    
    Mmbtu
    
    Bbtu
    
    Floor/Cap (1)
    
    Mbbls
    
    BblDecember 31, 2005
    
    
    1,500
    
    
    $
    3.70
    
    
    
    1,500
    
    
    $
    4.00-5.32
    
    
    
    67
    
    
    $
    33.31March 31, 2006
    
    
    2,829
    
    
    $
    6.14
    
    
    
    
    
    
    
    
    
    
    
    63
    
    
    $
    32.71June 30, 2006
    
    
    2,829
    
    
    
    5.24
    
    
    
    
    
    
    
    
    
    
    
    62
    
    
    
    32.35September 30, 2006
    
    
    2,829
    
    
    
    5.22
    
    
    
    
    
    
    
    
    
    
    
    62
    
    
    
    32.02December 31, 2006
    
    
    2,829
    
    
    
    5.39
    
    
    
    
    
    
    
    
    
    
    
    62
    
    
    
    31.7111,316
    
    
    $
    5.50
    
    
    
    
    
    
    
    
    
    
    
    249
    
    
    $
    32.20Year EndingDecember 31, 2007
    
    
    10,745
    
    
    $
    4.97
    
    
    
    
    
    
    
    
    
    
    
    227
    
    
    $
    30.91December 31, 2008
    
    
    10,126
    
    
    
    4.64
    
    
    
    
    
    
    
    
    
    
    
    208
    
    
    
    29.96December 31, 2009
    
    
    9,529
    
    
    
    4.43
    
    
    
    
    
    
    
    
    
    
    
    191
    
    
    
    29.34December 31, 2010
    
    
    8,938
    
    
    
    4.28
    
    
    
    
    
    
    
    
    
    
    
    175
    
    
    
    28.86December 31, 2011
    
    
    8,231
    
    
    
    4.19
    
    
    
    
    
    
    
    
    
    
    
    157
    
    
    
    28.77December 31, 2012
    
    
    7,005
    
    
    
    4.09
    
    
    
    
    
    
    
    
    
    
    
    138
    
    
    
    28.70December 31, 2013
    
    
    6,528
    
    
    
    4.04
    
    
    
    
    
    
    
    
    
    
    
    127
    
    
    
    28.70
 Bbl  Barrel
    
    Mmbtu  Million British thermal unitsMbbls  Thousand barrels
    
    Bbtu  Billion British thermal units
 (1) The NYMEX price per Mmbtu floor/cap for the natural gas
collars in 2005 assumes 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. In September 2005, we entered into a three-year interest rate swap. The Company will pay
a fixed LIBOR rate of 4.285% on the notional amount of $40 million. The swap is based on the one
month LIBOR. This is designated as a cash flow hedge and qualifies for the shortcut method. (5) Stock-Based Compensation We measure expense associated with stock-based compensation under the provisions of Accounting
Principles Board Opinion No. (APB) 25, Accounting for Stock Issued to Employees and its related
interpretations. Under APB 25, no compensation expense is required to be recognized upon the
issuance of stock options to key employees as the exercise price of the option is equal to the
market price of the underlying common stock at the date of grant. For purposes of the pro forma disclosures required by SFAS 123, Accounting for Stock Based
Compensation, the estimated fair value of the options is amortized to expense over the options
vesting period. The changes in net income or loss as if we had applied the fair value provisions
of SFAS 123 for 13




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the predecessor II company for the period ended July 6, 2004 were not material.
The successor company and predecessor I company did not have any stock options. The changes in share value and the vesting of shares are reported as adjustments to
compensation expense. The changes in share value and the vesting of shares in the predecessor II
company period
ended July 6, 2004, resulted in a non-cash increase in compensation expense of $4.0 million. The
successor company and predecessor I company did not have any stock-based compensation. In connection with the closing of the Transaction, the Company issued approximately 34 shares
of common stock to Messrs. Winne and Becci. The shares were purchased from them at the closing of
the Transaction. These shares were reported as compensation expense of $2.6 million and included
in the transaction expenses in the predecessor I period ending August 15, 2005. (6) 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. (7) Supplemental Disclosure of Cash Flow Information Successor
    
    
    Predecessor I
    
    Predecessor I
    
    
    Predecessor IICompany
    
    
    Company
    
    Company
    
    
    CompanyFor The 46 Day
    
    
    For The 227 Day
    
    For The 91 Day
    
    
    For The 188 DayPeriod From
    
    
    Period From
    
    Period From
    
    
    Period FromAugust 16, to
    
    
    January 1, to
    
    July 2, to
    
    
    January 1, toSeptember 30,
    
    
    August 15,
    
    September 30,
    
    
    July 6,(in thousands)
    
    2005
    
    
    2005
    
    2004
    
    
    2004Cash paid during the period for:Interest
    
    $
    1,367
    
    
    
    $
    20,803
    
    
    $
    1,668
    
    
    
    $
    14,759Income taxes
    
    
    
    
    
    
    
    500
    
    
    
    
    
    
    
    
    
 (8) Contingencies In April 2002, we were notified of a claim by an overriding royalty owner in Michigan alleging
the underpayment of royalties resulting from disputes as to the interpretation of the terms of
several farmout agreements. On July 6, 2004, a suit was filed in Otsego County, Michigan by the
successor in interest to these royalty interests, alleging substantially the same underpayments.
In April 2005, we entered into a settlement agreement that provided for a payment to the royalty
owner of an amount approximately equal to the amount accrued at March 31, 2005 and an increase in
the future overriding royalty percentage in several wells. The result had no material adverse
effect on our financial position, results of operations or cash flows of the Company. (9) Related Party Transactions In connection with the Companys entry into the Amended Credit Agreement, the Company executed
a Subordinated Promissory Note in favor of Capital C in the maximum principal amount of $94
million. Under the Note, Capital C loaned $25 million to the Company on August 16, 2005. The Note
accrues interest at a rate of 10% per annum and matures on August 16, 2012. We received a fairness
opinion from an unrelated financial services firm with respect to the terms of the Note made on
August 16, 2005. Interest payments on the Note are due quarterly commencing September 30, 2005.
In lieu of cash payments, the Company has the option to make interest payments on the Note by
borrowing additional 14




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##### Table of Contents



amounts against the Note. The interest payment on September 30, 2005 was paid
in cash. The Note has no prepayment penalty or premium and may be prepaid in whole or in part at
any time. The Note is expressly subordinate to the Companys senior debt, which includes
obligations under the Amended
Credit Agreement, the J. Aron Swap and notes issued under the Companys Indenture dated July
7, 2004 with BNY Midwest Trust Company, as indenture trustee. See Note 3. In connection with the Transaction the Company has a payable due to EnerVest in the amount of
$1.3 million at September 30, 2005. 
 Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations. Forward-Looking Information The information in this document includes forward-looking statements that are made pursuant to
the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Statements
preceded by, followed by or that otherwise include the statements should, believe, expect,
anticipate, intend, will, continue, estimate, plan, outlook, may, future,
projection, likely, possible, would, could and variations of these statements and similar
expressions are forward-looking statements as are any other statements relating to developments,
events, occurrences, results, efforts or impacts. These forward-looking statements are based on
current expectations and projections about future events. Forward-looking statements and the
business prospects of Belden & Blake are subject to a number of risks and uncertainties which may
cause our actual results in future periods to differ materially from the forward-looking statements
contained herein. These risks and uncertainties include, but are not limited to, our access to
capital, the market demand for and prices of oil and natural gas, our oil and gas production and
costs of operation, results of our future drilling activities, the uncertainties of reserve
estimates, general economic conditions, new legislation or regulatory changes, changes in
accounting principles, policies or guidelines and environmental risks. These and other risks are
described in our Annual Report on Form 10-K for the year ended December 31, 2004, as amended, under
the heading Risk Factors and in our other filings with the Securities and Exchange Commission
(SEC). We undertake no obligation to publicly update or revise any forward-looking statement,
whether as a result of new information, future events, changes in assumptions, or otherwise. CRITICAL ACCOUNTING POLICIES We prepare our consolidated financial statements in accordance with accounting principles
generally accepted in the United States (GAAP) and SEC guidance. See the Notes to Consolidated
Financial Statements included in Item 8. Financial Statements and Supplementary Data in our
Annual Report on Form 10-K for the year ended December 31, 2004, as amended, filed with the SEC for
a more comprehensive discussion of our significant accounting policies. GAAP requires information
in financial statements about the accounting principles and methods used and the risks and
uncertainties inherent in significant estimates including choices between acceptable methods.
Following is a discussion of our most critical accounting policies. Successful Efforts Method of Accounting The accounting for and disclosure of oil and gas producing activities requires our management
to choose between GAAP alternatives and to make judgments about estimates of future uncertainties. We use the successful efforts method of accounting for oil and gas producing activities as
opposed to the alternate acceptable full cost method. Under the successful efforts method,
property 15




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acquisition and development costs and certain productive exploration costs are capitalized
while non-productive exploration costs, which include certain geological and geophysical costs,
exploratory
dry hole costs and costs of carrying and retaining undeveloped properties, are expensed as
incurred. The geological and geophysical costs include costs for salaries and benefits of our
personnel in those areas and other third party costs. The costs of carrying and retaining
undeveloped properties include salaries and benefits of our land department personnel, delay rental
payments made on new and existing leases, ad valorem taxes on existing leases and the cost of
previously capitalized leases that are written off because the leases were dropped or expired.
Exploratory dry hole costs include the costs associated with drilling an exploratory well that has
been determined to be a dry hole. The major difference between the successful efforts method of accounting and the full cost
method is under the full cost method of accounting, such exploration costs and expenses are
capitalized as assets, pooled with the costs of successful wells and charged against the net income
(loss) of future periods as a component of depletion expense. Oil and Gas Reserves Our estimated proved developed and estimated proved undeveloped reserves are all located
within the Appalachian and Michigan Basins in the United States. There are many uncertainties
inherent in estimating proved reserve quantities and in projecting future production rates and the
timing of development expenditures. In addition, estimates of new discoveries are more imprecise
than those of properties with a production history. Accordingly, these estimates are expected to
change as future information becomes available. Material revisions of reserve estimates may occur
in the future, development and production of the oil and gas reserves may not occur in the periods
assumed and actual prices realized and actual costs incurred may vary significantly from
assumptions used. Estimated proved reserves represent estimated quantities of natural gas and oil
that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in
future years from known reservoirs under economic and operating conditions existing at the time the
estimates were made. Estimated proved developed reserves are estimated proved reserves expected to
be recovered through wells and equipment in place and under operating methods being used at the
time the estimates were made. The accuracy of a reserve estimate is a function of:  
    
    the quality and quantity of available data;
    
    the interpretation of that data;
    
    the accuracy of various mandated economic assumptions; and
    
    the judgment of the persons preparing the estimate. Capitalization, Depreciation, Depletion and Impairment of Long-Lived Assets See the Successful Efforts Method of Accounting discussion above. Capitalized costs related
to estimated proved properties are depleted using the unit-of-production method. Depreciation,
depletion and amortization of proved oil and gas properties are calculated on the basis of
estimated recoverable proved 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. 16




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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
based on managements outlook of future oil and natural gas prices and estimated future cash flows
to be generated by the assets, discounted at a market rate of interest. Impairment of unproved
properties is based on the estimated fair value of the property. Derivatives and Hedging Our financial results and cash flows can be significantly impacted as commodity prices
fluctuate widely in response to changing market conditions. Under the provisions of SFAS 133,
Accounting for Derivative Instruments and Hedging Activities, as amended, we recognize all
derivative financial instruments as either assets or liabilities at fair value. The changes in
fair value of derivative instruments not qualifying for designation as cash flow hedges are
reported in expense in the consolidated statements of operations as derivative fair value (gain)
loss. 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 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, 2005, our derivative contracts were comprised of
natural gas swaps and collars and crude oil swaps, which were placed with a major financial
institution that we believe is a minimal credit risk. Qualifying derivative financial instruments
are designated as cash flow hedges. We consider our natural gas swaps to be highly effective and expect there will be no
ineffectiveness to be recognized in net income (loss) since the critical terms of the hedging
instruments and the hedged forecasted transactions are the same. We have not experienced
ineffectiveness on our
natural gas swaps because we use NYMEX-based commodity derivative contracts to hedge on the same 17




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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 and Transaction. These collars
qualified and were designated as cash flow hedges from their inception through the predecessor II
company period ended July 6, 2004. Although these collars are not deemed to be effective hedges in
accordance with the provisions of SFAS 133, we have retained these instruments as protection
against changes in commodity prices and we will continue to record the mark-to-market adjustments
on these natural gas collars, through 2005, in our income statement. Our NYMEX crude oil swaps are
highly effective and were designated as cash flow hedges. We have ineffectiveness on the crude oil
swaps because the oil is sold locally at a posted price which is different from the NYMEX price.
Historically, there has been a high correlation between the posted price and the NYMEX price. The
changes in the fair values of the natural gas collars and the ineffective portion of the crude oil
swaps are recorded as Derivative fair value (gain) or loss. Revenue Recognition Oil and gas production revenue is recognized as production and delivery take place. Oil and
gas marketing revenues are recognized when title passes. Asset Retirement Obligations Under the provisions of SFAS 143, Accounting for Asset Retirement Obligations, we recognize
a liability for the fair value of our asset retirement obligations associated with our tangible,
long-lived assets. The majority of our asset retirement obligations recorded relate to the
plugging and abandonment (excluding salvage value) of our oil and gas properties. Subsequent to
the adoption of SFAS 143, there has been no significant current period activity with respect to
additional retirement obligations, settled obligations, accretion expense and revisions of
estimated cash flows. The asset retirement obligations increased as a result of purchase accounting
for the Transaction and Merger, primarily due to a lower discount rate and revised estimates of
asset lives on certain oil and gas wells. Results of Operations The Transaction and Merger were accounted for as purchases effective August 16, 2005 and July
7, 2004, respectively. The Transaction and Merger resulted in a new basis of accounting reflecting
estimated fair values for assets and liabilities at August 16, 2005 and July 7, 2004, respectively.
Accordingly, the financial statements for the period subsequent to August 15, 2005 are presented
on the Companys new basis of accounting, while the results of operations for prior periods reflect
the historical results of the two predecessor companies. Vertical black lines are presented to
separate the financial statements of the two predecessor companies and the successor company. The allocation of the purchase price at fair value resulted in a significant increase in the
book value of our assets. The increase in the book value of assets resulted in materially higher
charges for depreciation, depletion and amortization in the successor company and predecessor I
company periods. These higher charges are expected to continue in subsequent accounting periods. 18




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The following Managements Discussion and Analysis is based on the results of operations from
continuing operations, unless otherwise noted. Accordingly, discontinued operations have been
excluded. The following table sets forth certain information regarding our net oil and natural gas
production, revenues and expenses for the periods indicated: Three months ended September 30,
    
    Nine months ended September 30,2005
    
    2004
    
    2005
    
    2004(Restated)
    
    
    
    (Restated)ProductionGas (Mmcf)
    
    
    3,633
    
    
    
    3,795
    
    
    
    10,844
    
    
    
    11,492Oil (Mbbls)
    
    
    87
    
    
    
    93
    
    
    
    264
    
    
    
    282Total production (Mmcfe)
    
    
    4,155
    
    
    
    4,355
    
    
    
    12,430
    
    
    
    13,183Average priceGas (per Mcf)
    
    $
    7.31
    
    
    $
    4.93
    
    
    $
    6.25
    
    
    $
    5.02Oil (per Bbl)
    
    
    36.92
    
    
    
    34.28
    
    
    
    35.80
    
    
    
    33.73Mcfe
    
    
    7.16
    
    
    
    5.03
    
    
    
    6.21
    
    
    
    5.10Average costs (per Mcfe)Production expense
    
    
    1.43
    
    
    
    1.53
    
    
    
    1.34
    
    
    
    1.34Production taxes
    
    
    0.22
    
    
    
    0.15
    
    
    
    0.20
    
    
    
    0.15Depletion
    
    
    2.00
    
    
    
    1.83
    
    
    
    1.93
    
    
    
    1.16Operating margin (per Mcfe)
    
    
    5.51
    
    
    
    3.35
    
    
    
    4.67
    
    
    
    3.61
 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
 Results of Operations  Third Quarters of 2005 and 2004 Compared Revenues Net operating revenues increased from $24.1 million in the third quarter of 2004 to $32.8
million in the third quarter of 2005. The increase was due to higher oil and gas sales revenues of
$7.9 million and higher gas gathering and marketing revenues of $865,000. Gas volumes sold were 3.6 Bcf (billion cubic feet) in the third quarter of 2005, which was a
decrease of 162 Mmcf (4%) compared to the third quarter of 2004. This decrease in gas volumes sold
resulted in a decrease in gas sales revenues of approximately $800,000. Oil volumes sold decreased
approximately 6,000 Bbls (7%) from 93,000 Bbls in the third quarter of 2004 to 87,000 Bbls in the
third quarter of 2005, resulting in a decrease in oil sales revenues of approximately $220,000.
The lower volumes are primarily due to normal production declines partially offset by production
from new wells drilled during 2004 and 2005. The average price realized for our natural gas increased $2.38 per Mcf from $4.93 in the third
quarter of 2004 to $7.31 per Mcf in the third quarter of 2005, which increased gas sales revenues
by approximately $8.6 million. As a result of our hedging activities, gas sales revenues were
decreased by $7.2 million ($1.98 per Mcf) in the third quarter of 2005 and decreased by $4.0
million ($1.04 per Mcf) in the third quarter of 2004. The average price realized for our oil
increased from $34.28 per Bbl in the third quarter of 2004 to $36.92 per Bbl in the third quarter
of 2005, which increased oil sales revenues by approximately $230,000. As a result of our hedging
activities, oil sales revenues were decreased by approximately $2.0 million ($22.86 per Bbl) in the
third quarter of 2005 and decreased by $578,000
($6.19 per Bbl) in the third quarter of 2004. 19




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The operating margin from oil and gas sales (oil and gas sales revenues less production
expense and production taxes) on a per unit basis increased from $3.35 per Mcfe in the third
quarter of 2004 to $5.51 per Mcfe in the third quarter of 2005. The average price increased $2.13
per Mcfe and the average production expense decreased $0.10 per Mcfe, which were partially offset
by an increase in production taxes of $0.07 per Mcfe in the third quarter of 2005 compared to the
third quarter of 2004. The increase in gas gathering and marketing revenues was due to a $656,000 increase in gas
marketing revenues and a $209,000 increase in gas gathering revenues. The higher gas gathering and
marketing revenues resulted primarily from higher gas prices. Costs and Expenses Production expense was $6.7 million in the third quarter of 2004 compared to $6.0 million in
the third quarter of 2005. The average production cost was $1.53 per Mcfe in the third quarter of
2004 and $1.43 per Mcfe in the third quarter of 2005. Production expense includes non-cash
expenses of $1.2 million related to stock compensation expense in the third quarter of 2004 and
costs of oil sold from inventory of $644,000 in the third quarter of 2005. The average production
cost after adjustment for these non-cash items was $1.25 per Mcfe in the third quarter of 2004 and
$1.28 per Mcfe in the third quarter of 2005. Production taxes increased $280,000 from $650,000 in the third quarter of 2004 to $930,000 in
the third quarter of 2005. Average per unit production taxes increased from $0.15 per Mcfe in the
third quarter of 2004 to $0.22 per Mcfe in the third quarter of 2005. The increased production
taxes are primarily due to higher oil and gas prices in Michigan, where production taxes are based
on a percentage of revenues, excluding the effects of hedging. Exploration
expense decreased $968,000 (53%) from $1.8 million in the third quarter of 2004 to
$869,000 in the third quarter of 2005. This decrease is primarily due to lower land leasing and
expired lease expense and decreases in employment and compensation related expense. General and administrative expense decreased $1.3 million (56%) from $2.3 million in the third
quarter of 2004 to $1.0 million in the third quarter of 2005 primarily due to $1.2 million of stock
compensation expense recorded in the third quarter of 2004 related to the Merger. Depreciation, depletion and amortization increased by $165,000 from $8.6 million in the third
quarter of 2004 to $8.8 million in the third quarter of 2005. This increase was primarily due to
an increase in depletion expense. Depletion expense increased $322,000 (4%) from $8.0 million in
the third quarter of 2004 to $8.3 million in the third quarter of 2005 primarily due to a higher
depletion rate per Mcfe. Depletion per Mcfe increased from $1.83 per Mcfe in the third quarter of
2004 to $2.00 per Mcfe in the third quarter of 2005, primarily due to a higher cost basis resulting
from purchase accounting for the Merger in 2004 and the Transaction in 2005. Derivative fair value (gain) loss was a loss of $6.4 million in the third quarter of 2004
compared to a loss of $9.5 million in the third quarter of 2005. The derivative fair value (gain)
loss reflects the changes in fair value of certain derivative instruments that are not designated
or do not qualify as cash flow hedges and $1.6 million and $1.2 million related to the ineffective
portion of crude oil swaps qualifying for hedge accounting which were recorded in the third
quarters of 2004 and 2005, respectively. Transaction expenses were recorded in the predecessor I and predecessor II periods. These
expenses include severance and retention payments accrued or made to employees, unamortized loan
costs written off, temporary financing facility costs, costs of the consent solicitation process
for our $225 20




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million Senior Subordinated Notes due 2007 and buyer and seller investment banking
fees, professional fees and other transaction related expenses. Interest expense decreased $229,000 from $6.1 million in the third quarter of 2004 to $5.9
million in the third quarter of 2005. This decrease was due to lower average outstanding
borrowings. There was an income tax benefit of $3.5 million in the third quarter of 2005 compared to a
benefit of $9.8 million in the third quarter of 2004. The decrease in the income tax benefit was
primarily due to a decrease in the loss from continuing operations before income taxes in the 2005
period compared to the 2004 period, partially offset by a higher effective tax rate in the 2005
period. The effective tax rate was higher in the 2005 period due to certain nondeductible
transaction-related expenses in the 2004 period which reduced the 2004 rate. Results of Operations  Nine Months of 2005 and 2004 Compared Revenues Net operating revenues increased from $74.4 million in the first nine months of 2004 to $85.3
million in the first nine months of 2005. The increase was due to higher oil and gas sales
revenues of $10.0 million and higher gas gathering and marketing revenues of $828,000. Gas volumes sold were 10.8 Bcf in the first nine months of 2005, which was a decrease of 648
Mmcf (6%) compared to the first nine months of 2004. This decrease in gas volumes sold resulted in
a decrease in gas sales revenues of approximately $3.3 million. Oil volumes sold decreased
approximately 18,000 Bbls (6%) from 282,000 Bbls in the first nine months of 2004 to 264,000 Bbls
in the first nine months of 2005 resulting in a decrease in oil sales revenues of approximately
$590,000. The lower oil and gas sales volumes are primarily due to normal production declines
partially offset by production from new wells drilled during 2004 and 2005. The average price realized for our natural gas increased $1.23 per Mcf from $5.02 in the first
nine months of 2004 to $6.25 per Mcf in the first nine months of 2005, which increased gas sales
revenues by approximately $13.3 million. As a result of our hedging activities, gas sales revenues
were decreased by $15.4 million ($1.42 per Mcf) in the first nine months of 2005 and decreased by
$12.4 million ($1.08 per Mcf) in the first nine months of 2004. The average price realized for our
oil increased from $33.73 per Bbl in the first nine months of 2004 to $35.80 per Bbl in the first
nine months of 2005, which increased oil sales revenues by approximately $550,000. As a result of
our hedging activities, oil sales revenues were decreased by approximately $4.3 million ($16.21 per
Bbl) in the first nine months of 2005 and decreased by $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 $3.61 per Mcfe
in the first nine months of 2004 to $4.67 per Mcfe in the first nine months of 2005. The average
price increased $1.11 per Mcfe, which was partially offset by an increase in production taxes of
$0.05 per Mcfe in the first nine months of 2005 compared to the first nine months of 2004. The increase in gas gathering and marketing revenues was due to a $550,000 increase in gas
marketing revenues and a $278,000 increase in gas gathering revenues. The higher gas gathering and
marketing revenues resulted primarily from higher gas prices. Costs and Expenses Production expense was $17.6 million in the first nine months of 2004 and $16.7 million in the
first nine months of 2005. The average production cost was $1.34 per Mcfe in the first nine months
of 21




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2004 and 2005. Production expense includes non-cash expenses of $1.6 million related to stock
compensation expense in the first nine months of 2004 and costs of oil sold from inventory of
$595,000 in the first nine months of 2005. The average production cost after adjustment for these
non-cash items was $1.21 per Mcfe in the first nine months of 2004 and $1.30 per Mcfe in the first
nine months of 2005. The increase in the per Mcfe production expense was primarily due to the
decreased volumes discussed above. Production taxes increased $475,000 from $2.0 million in the first nine months of 2004 to $2.4
million in the first nine months of 2005. Average per unit production taxes increased from $0.15
per Mcfe in the first nine months of 2004 to $0.20 per Mcfe in the first nine months of 2005. The
increased production taxes are primarily due to higher oil and gas prices in Michigan, where
production taxes are based on a percentage of revenues, excluding the effects of hedging. Exploration expense decreased $1.8 million (38%) from $4.6 million in the first nine months of
2004 to $2.8 million in the first nine months of 2005. This decrease is primarily due to lower
land leasing and expired lease expense and decreases in employment and compensation related
expense. General and administrative expense decreased $557,000 (12%) from $4.8 million in the first
nine months of 2004 to $4.2 million in the first nine months of 2005 primarily due to $1.5 million
of non-cash stock compensation expense recorded in the first nine months of 2004 partially offset
by $489,000 related to severance agreements with two former executives in the first quarter of 2005
and an increase of $603,000 in audit and legal services related to our public filings and
Sarbanes-Oxley efforts in the first nine months of 2005. Depreciation, depletion and amortization increased $8.1 million (46%) from $17.7 million in
the first nine months of 2004 to $25.8 million in the first nine months of 2005. This increase was
primarily due to an increase in depletion expense. Depletion expense increased $8.7 million (57%)
from $15.3 million in the first nine months of 2004 to $24.0 million in the first nine months of
2005 primarily due to a higher depletion rate per Mcfe. Depletion per Mcfe increased from $1.16
per Mcfe in the first nine months of 2004 to $1.93 per Mcfe in the first nine months of 2005,
primarily due to a higher cost basis resulting from purchase accounting for the Merger in 2004 and
the Transaction in 2005. Derivative fair value (gain) loss was a loss of $6.1 million in the first nine months of 2004
compared to a loss of $15.6 million in the first nine months of 2005. The derivative fair value
(gain) loss reflects the changes in fair value of certain derivative instruments that are not
designated or do not qualify as cash flow hedges, and $1.6 million and $4.9 million related to the
ineffective portion of crude oil swaps qualifying for hedge accounting, which were recorded in the
first nine months of 2004 and 2005, respectively. Interest expense decreased $638,000 from $18.3 million in the first nine months of 2004 to
$17.7 million in the first nine months of 2005. This decrease was due to lower blended interest
rates partially offset by an increase in average outstanding borrowings. There was an income tax benefit of $6.5 million for the first nine months of 2005 compared to
a benefit of $7.1 million for the first nine months of 2004. The decrease in the income tax
benefit was
primarily related to a decrease in the loss from continuing operations before income taxes,
partially offset by a higher effective tax rate in the 2005 period. The effective tax rate was
higher in the 2005 period due to certain nondeductible transaction-related expenses in the 2004
period which reduced the 2004 rate and a change in the Ohio tax law in the 2005 period. On June
30, 2005 the State of Ohio enacted new tax legislation that will result in the elimination of the
income and franchise tax over a four year period and it will be replaced with a gross receipts
based tax. As a result of the new tax structure, we recorded a tax 22




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benefit of $1.1 million to
adjust the recorded deferred tax account balances for Ohio during the second quarter of 2005. This
benefit increased the effective tax rate during the 2005 period. Discontinued operations relating to the TBR and Arrow asset sales resulted in a gain, net of
tax, of $28.9 million in the first nine months of 2004. The TBR and Arrow assets were sold in the
second quarter of 2004. Liquidity and Capital Resources Cash Flows The primary sources of cash in the nine month period ended September 30, 2005 were funds
generated from operations and the Transaction. Funds used during this period were primarily used
for operations, exploration and development expenditures, debt costs, interest expense and
transaction costs. Our liquidity and capital resources are closely related to and dependent upon
the current prices paid for our oil and natural gas. The
cash flow activities for the Transaction are reflected in the
predecessor period in the statement of cash flows. The equity
contribution and the changes in debt are reflected in the opening
cash balances of the successor company. The activity in the successor
period reflects the normal operational cash flows of the successor
company after the Transaction was completed. EnerVest has advised the Company that it endeavors to achieve a high rate of return for its
institutional investors on its investment in the Company. Consistent with that investment goal,
the Company anticipates that it will make dividends of cash flows not necessary to meet operating
and capital requirements, consistent with the terms of the various agreements governing payment of
dividends, including the indenture. Our
operating activities provided cash flows of $16.6 million during the first nine months of
2005 compared to $7.9 million in the first nine months of 2004. The increase was primarily due to
higher oil and gas margins (net of hedging) of $10.4 million. Our
investing activities used cash flows of $24.9 million during the first nine months of 2005
compared to $45.0 million provided in the first nine months of 2004. In the first nine months of
2004 the TBR and Arrow asset sales provided cash flows of $72.7 million. Cash flows used in financing activities decreased $22.7 million in the first nine months of
2005 primarily due to lower debt repayment during the first nine months of 2005. Our
current ratio at September 30, 2005 was 0.57 to 1. During the first nine months of 2005,
the working capital decreased $47.1 million from a deficit of $3.2 million at December 31, 2004 to
a deficit of $50.3 million at September 30, 2005. The decrease was primarily due to a $62.4 million
increase in the current liability for the fair value of derivatives and a $14.0 million decrease in
cash partially offset by a $24.6 million increase in the deferred income taxes asset and a $4.8
million increase in accounts receivable. Capital Expenditures During the first nine months of 2005, we spent approximately $26.2 million, including
exploratory dry hole expense, on our drilling activities and other capital expenditures. In the
first nine months of 2005, we drilled 107 gross (104.6 net) development wells, all of which have
been or are expected to be successfully completed as producers in the target formation. This cost
excludes approximately $679,000 related to wells in progress as of September 30, 2005, including
approximately $242,000 to drill 2 gross (1.5 net) exploratory Trenton Black River wells in Ohio
during the second quarter of 2005. If these wells are determined to be dry holes, their cost will
be charged to exploration expense in subsequent periods. 23




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We currently expect to spend approximately $34 million during 2005 on our drilling activities,
including exploratory dry hole expense, and other capital expenditures. We intend to finance our
planned capital expenditures through our cash on hand, available cash flow and borrowings under our
revolving credit facility. At September 30, 2005, we had cash of $4.4 million and approximately
$27.0 million available under our 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. There can be no assurance that the future drilling of our proved undeveloped locations
will provide adequate liquidity in the future. At September 30, 2005, we had a $390 million credit facility comprised of a five-year $350
million revolving facility with an initial borrowing base of $80.25 million, of which $52 million
was outstanding at September 30, 2005. This facility is for working capital requirements and
general corporate purposes, including the issuance of letters of credit; and a five year $40
million letter of credit facility that may be used only to provide credit support for our
obligations under the hedge agreement and other hedge transactions. Borrowings under the Amended
Credit Agreement bear interest (i) at the greater of the prime rate or an adjusted federal funds
rate, plus an applicable margin ranging from 0% to 0.625% based on the aggregate principal amount
outstanding under the Amended Credit Agreement, or, (ii) at the Companys option, the Eurodollar
base rate plus an applicable margin ranging from 1.125% to 2.125% based on the aggregate principal
amount outstanding under the Amended Credit Agreement. The full amount borrowed under the Amended
Credit Agreement will mature on August 16, 2010. The obligations under the Amended Credit Agreement are secured by a first lien security
interest in substantially all of the assets of the Company. The obligations under the Amended
Credit Agreement are further secured by a pledge of 100% of the capital stock of the Company held
by Capital C, the Companys parent. The Amended Credit Agreement contains covenants that will limit the ability of the Company to,
among other things, incur or guarantee additional indebtedness; create liens; pay dividends on or
repurchase stock of the Company or its subsidiaries; pay principal and interest on certain
subordinated debt; make certain types of investments; sell assets or merge with another entity;
pledge or otherwise encumber the capital stock of the Company or its subsidiaries; or enter into
transactions with affiliates. The Amended Credit Agreement also requires compliance with customary
financial covenants, including a minimum interest coverage ratio, a maximum leverage ratio and a
minimum current ratio. Borrowings under the revolving credit line may be used by the Company for general corporate
purposes, including refinancing of existing indebtedness. In accordance with the terms of the
Amended Credit Agreement, letters of credit issued under the hedge letter of credit commitment and
any related borrowings are to be used solely to secure payment of the Companys obligations under
the J. Aron Swap. At September 30, 2005, the interest rate under our base rate option was 6.875%. Under our
one-month LIBOR option the rate was 5.425%. At September 30, 2005, we had $41.2 million of
outstanding letters of credit. At September 30, 2005, there was $52 million outstanding under the
revolving credit agreement. We had $27.0 million of borrowing capacity under our revolving facility
available for general corporate purposes. As of September 30, 2005, we were in compliance with all
financial covenants and requirements under the existing credit facilities. In connection with the Transaction, the Company executed a Subordinated Promissory Note
(Note) in favor of Capital C in the maximum principal amount of $94 million. Under the Note,
Capital C loaned $25 million to the Company. The Note accrues interest at a rate of 10% per annum
and matures 24




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##### Table of Contents



on August 16, 2012. We received a fairness opinion from an unrelated financial
services firm with respect to the terms of the Note made on August 16, 2005. Interest payments on
the Note are due quarterly commencing September 30, 2005. In lieu of cash payments, the Company has
the option to make interest payments on the Note by borrowing additional amounts against the Note.
The Note has no prepayment penalty or premium and may be prepaid in whole or in part at any time.
The Note is expressly subordinate to the Companys senior debt, which includes obligations under
the Amended Credit Agreement, the J. Aron Swap and notes issued under the Companys Indenture dated
July 7, 2004 with BNY Midwest Trust Company, as indenture trustee. 
 Item 3. Quantitative and Qualitative Disclosures About Market Risk Among other risks, we are exposed to interest rate and commodity price risks. The interest rate risk relates to existing debt under our revolving facility as well as any
new debt financing needed to fund capital requirements. We may manage our interest rate risk
through the use of interest rate swaps to hedge the interest rate exposure associated with the
credit agreement, whereby a portion of our floating rate exposure is exchanged for a fixed interest
rate. A portion of our long-term debt consists of senior secured notes where the interest
component is fixed. At September 30, 2005, we had an interest rate swap on $40 million of our
revolving loan outstanding on our credit agreement. The fair value of this interest rate swap was
$224,000 at September 30, 2005. We had no derivative financial instruments for managing interest
rate risks in place as of September 30, 2004. If market interest rates for short-term borrowings
increased 1%, the increase in interest expense in the quarter would be approximately $30,000. This
sensitivity analysis is based on our financial structure at September 30, 2005. The commodity price risk relates to natural gas and crude oil produced, held in storage and
marketed. Our financial results can be significantly impacted as commodity prices fluctuate widely
in response to changing market forces. From time to time, we may enter into a combination of
futures contracts, commodity derivatives and fixed-price physical contracts to manage our exposure
to commodity price volatility. We employ a policy of partially hedging oil production sold locally
at a posted price and gas production sold under NYMEX-based contracts by selling NYMEX-based
commodity derivative contracts which are placed with major financial institutions that we believe
are minimal credit risks. Historically, there has been a high correlation between the posted price
and NYMEX. The contracts may take the form of futures contracts, swaps or options. If NYMEX gas
prices decreased $1.00 per Mcf, our gas sales revenues for the quarter would decrease by $633,000,
after considering the effects of the hedging contracts in place at September 30, 2005. If the
price of crude oil decreased $5.00 per Bbl, oil sales revenues for the quarter would decrease by
$97,000, after considering the effects of the hedging contracts in place at September 30, 2005. We
had net pre-tax losses on our hedging activities of $19.7 million in the first nine months of 2005
and $13.0 million in the first nine months of 2004. At September 30, 2005, we had hedges on a
portion of our oil and gas production for
the remainder of 2005 through 2013. This sensitivity analysis is based on our 2005 oil and gas
sales volumes and assumes the NYMEX gas price would be above the ceiling in 2005 listed in the
table below. 25




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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, 2005: Natural Gas Swaps
    
    Natural Gas Collars
    
    Crude Oil SwapsNYMEX
    
    
    
    
    
    NYMEX Price
    
    
    
    
    
    NYMEXPrice per
    
    
    
    
    
    per Mmbtu
    
    Estimated
    
    Price perQuarter
Ending
    
    Bbtu
    
    Mmbtu
    
    Bbtu
    
    Floor/Cap (1)
    
    Mbbls
    
    BblDecember 31, 2005
    
    
    1,500
    
    
    $
    3.70
    
    
    
    1,500
    
    
    $
    4.00-5.32
    
    
    
    67
    
    
    $
    33.31March 31, 2006
    
    
    2,829
    
    
    $
    6.14
    
    
    
    
    
    
    
    
    
    
    
    63
    
    
    $
    32.71June 30, 2006
    
    
    2,829
    
    
    
    5.24
    
    
    
    
    
    
    
    
    
    
    
    62
    
    
    
    32.35September 30, 2006
    
    
    2,829
    
    
    
    5.22
    
    
    
    
    
    
    
    
    
    
    
    62
    
    
    
    32.02December 31, 2006
    
    
    2,829
    
    
    
    5.39
    
    
    
    
    
    
    
    
    
    
    
    62
    
    
    
    31.7111,316
    
    
    $
    5.50
    
    
    
    
    
    
    
    
    
    
    
    249
    
    
    $
    32.20Year EndingDecember 31, 2007
    
    
    10,745
    
    
    $
    4.97
    
    
    
    
    
    
    
    
    
    
    
    227
    
    
    $
    30.91December 31, 2008
    
    
    10,126
    
    
    
    4.64
    
    
    
    
    
    
    
    
    
    
    
    208
    
    
    
    29.96December 31, 2009
    
    
    9,529
    
    
    
    4.43
    
    
    
    
    
    
    
    
    
    
    
    191
    
    
    
    29.34December 31, 2010
    
    
    8,938
    
    
    
    4.28
    
    
    
    
    
    
    
    
    
    
    
    175
    
    
    
    28.86December 31, 2011
    
    
    8,231
    
    
    
    4.19
    
    
    
    
    
    
    
    
    
    
    
    157
    
    
    
    28.77December 31, 2012
    
    
    7,005
    
    
    
    4.09
    
    
    
    
    
    
    
    
    
    
    
    138
    
    
    
    28.70December 31, 2013
    
    
    6,528
    
    
    
    4.04
    
    
    
    
    
    
    
    
    
    
    
    127
    
    
    
    28.70
 Bbl  Barrel
    
    Mmbtu  Million British thermal unitsMbbls  Thousand barrels
    
    Bbtu  Billion British thermal units
 (1) The NYMEX price per Mmbtu floor/cap for the natural gas collars in 2005
assumes the monthly NYMEX settles at $3.10 per Mmbtu or higher. If the monthly NYMEX settles at
less than $3.10 per Mmbtu then the NYMEX price per Mmbtu will be the NYMEX settle plus $0.90. The proximity of our properties in the Appalachian and Michigan Basins to large
commercial and industrial natural gas markets has generally resulted in premium wellhead gas prices
compared with the prices of NYMEX futures contracts for gas delivered at the Henry Hub in
Louisiana. Monthly spot natural gas prices in our market areas are typically $0.15 to $0.60 higher
per Mcf than comparable NYMEX prices. Our average price received for crude oil is typically $3.00
to $3.50 per barrel below the NYMEX price per barrel. 
 Item 4. Controls and Procedures As of the end of the quarterly period ended September 30, 2005, Mark A. Houser, our Chief
Executive Officer, and James M. Vanderhider, our Chief Financial Officer, evaluated the
effectiveness of our disclosure controls and procedures. There are inherent limitations to the
effectiveness of any system of disclosure controls and procedures, including the possibility of
human error and the circumvention or overriding of the controls and procedures. Accordingly, even
effective disclosure controls and procedures can only provide reasonable assurance of achieving
their control objectives. Based upon and as of the date of the evaluation, our Chief Executive
Officer and our Chief Financial Officer believe that:  
    
    our disclosure controls and procedures were effective in ensuring that information
required to be disclosed by us in the reports we file or submit under the Securities
Exchange Act of 1934 was
recorded, processed, summarized and reported within the time periods specified in the SECs
rules and forms; and 26




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
    
    our disclosure controls and procedures were effective in ensuring that material
information required to be disclosed by us in the report we file or submit under the
Securities Exchange Act of 1934 was accumulated and communicated to our management,
including the Chief Executive Officer and the Chief Financial Officer, as appropriate to
allow timely decisions regarding required disclosure. Internal Control Over Financial Reporting There has not been any change in our internal control over financial reporting that occurred
during our quarterly period ended September 30, 2005 that has materially affected, or is reasonably
likely to materially affect, our internal control over financial reporting. 
 PART II OTHER INFORMATION 
 Item 1. Legal Proceedings. See the prior disclosure in the Companys prior 10-Q for the quarterly period ended June 30,
2005 filed with the SEC on August 11, 2005. 
 Item 4. Submission of Matters to a Vote of Security Holders. 
 On
July 26, 2005, Capital C approved by written consent in lieu of an
annual meeting the increase in the number of shares the Company is
authorized to have outstanding from 1,500 to 3,000. Item 6. Exhibits. (a) Exhibits 10.1*
    
    First Amendment to the Credit Agreement.31.1*
    
    Certification of Principal Executive Officer of Belden & Blake Corporation as required by
Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934.31.2*
    
    Certification of Principal Financial Officer of Belden & Blake Corporation as required by
Rule 13a-14(a) or Rule 15d-14(a) of the Securities Exchange Act of 1934.32.1*
    
    Certification of Chief Executive Officer of Belden & Blake Corporation pursuant to 18 U.S.C.
Section 1350.32.2*
    
    Certification of Chief Financial Officer of Belden & Blake Corporation pursuant to 18 U.S.C.
Section 1350.
 *Filed herewith. 27




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##### Table of Contents



SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the
Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized. BELDEN & BLAKE CORPORATIONDate: November 18, 2005
    
    By:
    
    /s/ Mark A. HouserMark A. Houser, Chief Executive Officer,
Chairman of the Board of Directors and DirectorDate: November 18, 2005
    
    By:
    
    /s/ James M. VanderhiderJames M. Vanderhider, President,
Chief Financial Officer and Director
 28