-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, G6eKH2/EPgW6bjdnCA6EtrrltkxpV2fdN/DoNjTeNTAgAFbUD5uiiDojaPLCZpCG 1K5VpBJj8kTAJldIin5t6g== 0000950152-04-006183.txt : 20040812 0000950152-04-006183.hdr.sgml : 20040812 20040812170306 ACCESSION NUMBER: 0000950152-04-006183 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 20040630 FILED AS OF DATE: 20040812 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BELDEN & BLAKE CORP /OH/ CENTRAL INDEX KEY: 0000880114 STANDARD INDUSTRIAL CLASSIFICATION: DRILLING OIL & GAS WELLS [1381] IRS NUMBER: 341686642 STATE OF INCORPORATION: OH FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 000-20100 FILM NUMBER: 04971011 BUSINESS ADDRESS: STREET 1: 5200 STONEHAM RD STREET 2: P O BOX 2500 CITY: NORTH CANTON STATE: OH ZIP: 44720 BUSINESS PHONE: 3304991660 MAIL ADDRESS: STREET 1: 5200 STONEHAM RD STREET 2: P O BOX 2500 CITY: NORTH CANTON STATE: OH ZIP: 44720 FORMER COMPANY: FORMER CONFORMED NAME: BELDEN & BLAKE ENERGY CORP /OH DATE OF NAME CHANGE: 19920427 10-Q 1 l08586ae10vq.txt BELDEN & BLAKE CORPORATION 10-Q/QUARTER END 6-30-04 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (Mark One) [X] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the quarterly period ended June 30, 2004 or [ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from ____________ to ____________ Commission File Number: 0-20100 BELDEN & BLAKE CORPORATION - -------------------------------------------------------------------------------- (Exact name of registrant as specified in its charter) Ohio 34-1686642 - -------------------------------------------------------------------------------- (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 5200 Stoneham Road North Canton, Ohio 44720 - -------------------------------------------------------------------------------- (Address of principal executive offices) (Zip Code) (330) 499-1660 - -------------------------------------------------------------------------------- (Registrant's telephone number, including area code) - -------------------------------------------------------------------------------- (Former name, former address and former fiscal year, if changed since last report.) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. [X] Yes [ ] No Indicate by check mark whether the Registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). [ ] Yes [X] No As of July 31, 2004, Belden & Blake Corporation had outstanding 1,500 shares of common stock, without par value, which is its only class of stock. BELDEN & BLAKE CORPORATION INDEX
PAGE ---- PART I Financial Information: Item 1. Financial Statements Consolidated Balance Sheets as of June 30, 2004 and December 31, 2003................ 1 Consolidated Statements of Operations for the three and six months ended June 30, 2004 and 2003 ..................................................................... 2 Consolidated Statements of Shareholders' Equity (Deficit) for the six months ended June 30, 2004 and the years ended December 31, 2003 and 2002...................... 3 Consolidated Statements of Cash Flows for the six months ended June 30, 2004 and 2003 .......................................................................... 4 Notes to Consolidated Financial Statements........................................... 5 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations......................................................................... 9 Item 3. Quantitative and Qualitative Disclosures About Market Risk........................... 18 Item 4. Controls and Procedures.............................................................. 20 PART II Other Information Item 6. Exhibits and Reports on Form 8-K..................................................... 20
BELDEN & BLAKE CORPORATION CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA)
JUNE 30, DECEMBER 31, 2004 2003 --------- --------- (UNAUDITED) ASSETS - ------ CURRENT ASSETS Cash and cash equivalents $ 45,616 $ 1,428 Accounts receivable, net 17,731 14,270 Inventories 701 780 Deferred income taxes 9,859 6,853 Other current assets 1,912 2,353 Fair value of derivatives 733 319 Assets of discontinued operations 3,721 22,230 --------- --------- TOTAL CURRENT ASSETS 80,273 48,233 PROPERTY AND EQUIPMENT, AT COST Oil and gas properties (successful efforts method) 463,403 452,167 Gas gathering systems 15,255 15,264 Land, buildings, machinery and equipment 13,076 13,173 --------- --------- 491,734 480,604 Less accumulated depreciation, depletion and amortization 258,539 250,162 --------- --------- PROPERTY AND EQUIPMENT, NET 233,195 230,442 FAIR VALUE OF DERIVATIVES 528 755 OTHER ASSETS 5,371 5,881 --------- --------- $ 319,367 $ 285,311 ========= ========= LIABILITIES AND SHAREHOLDERS' DEFICIT - ------------------------------------- CURRENT LIABILITIES Accounts payable $ 3,931 $ 4,873 Accrued expenses 17,839 12,726 Current portion of long-term liabilities 665 729 Fair value of derivatives 23,182 14,765 Liabilities of discontinued operations 4,378 3,811 --------- --------- TOTAL CURRENT LIABILITIES 49,995 36,904 LONG-TERM LIABILITIES Bank and other long-term debt 23,954 47,503 Senior subordinated notes 225,000 225,000 Other 4,264 4,108 --------- --------- 253,218 276,611 FAIR VALUE OF DERIVATIVES 9,853 9,723 DEFERRED INCOME TAXES 34,726 19,413 SHAREHOLDERS' DEFICIT Common stock without par value; $.10 stated value per share; authorized 58,000,000 shares; issued 10,675,428 and 10,610,450 shares (which includes 221,888 and 214,593 treasury shares, respectively) 1,045 1,040 Paid in capital 108,640 107,633 Deficit (117,085) (150,656) Accumulated other comprehensive loss (21,025) (15,357) --------- --------- TOTAL SHAREHOLDERS' DEFICIT (28,425) (57,340) --------- --------- $ 319,367 $ 285,311 ========= =========
See accompanying notes. 1 BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED, IN THOUSANDS)
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30, --------------------------- ------------------------- 2004 2003 2004 2003 ------- -------- -------- -------- REVENUES Oil and gas sales $22,945 $ 21,250 $ 45,307 $ 40,677 Gas gathering and marketing 2,474 2,244 5,057 5,495 Other 329 240 458 400 ------- -------- -------- -------- 25,748 23,734 50,822 46,572 EXPENSES Production expense 5,545 4,766 10,951 9,322 Production taxes 648 656 1,300 1,329 Gas gathering and marketing 2,300 1,929 4,533 5,236 Exploration expense 1,369 1,589 2,717 3,241 General and administrative expense 1,265 1,096 2,500 2,270 Franchise, property and other taxes 45 49 115 105 Depreciation, depletion and amortization 4,535 4,121 9,089 8,151 Accretion expense 100 80 195 162 Derivative fair value (gain) loss 11 (451) (321) (174) ------- -------- -------- -------- 15,818 13,835 31,079 29,642 ------- -------- -------- -------- OPERATING INCOME 9,930 9,899 19,743 16,930 OTHER EXPENSE Interest expense 6,112 6,036 12,184 11,941 ------- -------- -------- -------- INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 3,818 3,863 7,559 4,989 Provision for income taxes 1,240 1,406 2,615 1,813. ------- -------- -------- -------- INCOME FROM CONTINUING OPERATIONS BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 2,578 2,457 4,944 3,176 Income (loss) from discontinued operations, net of tax 28,941 (845) 28,627 (1,193) ------- -------- -------- -------- INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE 31,519 1,612 33,571 1,983 Cumulative effect of change in accounting principle, net of tax -- -- -- 2,397 ------- -------- -------- -------- NET INCOME $31,519 $ 1,612 $ 33,571 $ 4,380 ======= ======== ======== ========
See accompanying notes. 2 BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (DEFICIT) (IN THOUSANDS)
ACCUMULATED OTHER TOTAL COMMON COMMON PAID IN COMPREHENSIVE EQUITY SHARES STOCK CAPITAL DEFICIT INCOME (DEFICIT) ------- ------- --------- --------- --------- -------- JANUARY 1, 2002 10,290 $ 1,029 $ 107,402 $(150,797) $ 15,087 $(27,279) Comprehensive income (loss): Net income 2,465 2,465 Other comprehensive income, net of tax: Change in derivative fair value (5,518) (5,518) Reclassification adjustment for derivative (gain) loss reclassified into oil and gas sales (14,030) (14,030) -------- Total comprehensive loss (17,083) -------- Stock options exercised 65 7 (2) 5 Stock-based compensation 82 82 Repurchase of stock options (29) (29) Tax benefit of repurchase of stock options and stock options exercised 57 57 Treasury stock (59) (6) (392) (398) ------ ------- --------- --------- -------- -------- DECEMBER 31, 2002 10,296 1,030 107,118 (148,332) (4,461) (44,645) Comprehensive (loss) income: Net loss (2,324) (2,324) Other comprehensive income, net of tax: Change in derivative fair value (17,439) (17,439) Reclassification adjustment for derivative (gain) loss reclassified into oil and gas sales 6,543 6,543 -------- Total comprehensive loss (13,220) -------- Stock options exercised 120 12 108 120 Stock-based compensation 326 326 Repurchase of stock options (48) (48) Tax benefit of repurchase of stock options and stock options exercised 170 170 Treasury stock (20) (2) (41) (43) ------ ------- --------- --------- -------- -------- DECEMBER 31, 2003 10,396 1,040 107,633 (150,656) (15,357) (57,340) Comprehensive income (loss): Net income 33,571 33,571 Other comprehensive income, net of tax: Change in derivative fair value (11,180) (11,180) Reclassification adjustment for derivative (gain) loss reclassified into oil and gas sales 5,512 5,512 -------- Total comprehensive income 27,903 -------- Stock options exercised 65 6 105 111 Stock-based compensation 1,097 1,097 Repurchase of stock options (283) (283) Tax benefit of repurchase of stock options and stock options exercised 116 116 Treasury stock (6) (1) (28) (29) ------ ------- --------- --------- -------- -------- JUNE 30, 2004 (UNAUDITED) 10,455 $ 1,045 $ 108,640 $(117,085) $(21,025) $(28,425) ====== ======= ========= ========= ======== ========
See accompanying notes. 3 BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED, IN THOUSANDS)
SIX MONTHS ENDED JUNE 30, ------------------------- 2004 2003 ---------- ---------- CASH FLOWS FROM OPERATING ACTIVITIES: Income from continuing operations $ 4,944 $ 3,176 Adjustments to reconcile income from continuing operations to net cash provided by operating activities: Depreciation, depletion and amortization 9,089 8,151 Accretion 195 162 Loss on disposal of property and equipment 375 610 Amortization of derivatives and other noncash hedging activities (549) 416 Exploration expense 2,717 3,241 Deferred income taxes 2,896 1,813 Stock-based compensation 1,097 36 Change in operating assets and liabilities, net of effects of acquisition and disposition of businesses: Accounts receivable and other operating assets (4,486) (5,506) Inventories 79 (102) Accounts payable and accrued expenses 2,237 (2,371) --------- --------- NET CASH PROVIDED BY CONTINUING OPERATIONS 18,594 9,626 CASH FLOWS FROM INVESTING ACTIVITIES: Acquisition of businesses, net of cash acquired -- (4,628) Disposition of businesses, net of cash -- 100 Proceeds from property and equipment disposals 247 118 Exploration expense (2,717) (3,241) Additions to property and equipment (11,228) (6,556) Decrease (increase) in other assets 1,218 (83) --------- --------- NET CASH USED IN INVESTING ACTIVITIES (12,480) (14,290) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from revolving line of credit 140,679 105,198 Repayment of long-term debt and other obligations (164,335) (88,158) Debt issue costs 131 -- Proceeds from stock options exercised 111 61 Repurchase of stock options (283) (48) Purchase of treasury stock (29) (25) --------- --------- NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES (23,726) 17,028 --------- --------- NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS FROM CONTINUING OPERATIONS (17,612) 12,364 NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS FROM DISCONTINUED OPERATIONS 61,800 (12,304) CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 1,428 1,715 --------- --------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 45,616 $ 1,775 ========= =========
See accompanying notes. 4 BELDEN & BLAKE CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) JUNE 30, 2004 (1) BASIS OF PRESENTATION The accompanying unaudited consolidated financial statements of Belden & Blake Corporation (the "Company") 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 six-month period ended June 30, 2004 are not necessarily indicative of the results that may be expected for the year ended December 31, 2004. For further information, refer to the consolidated financial statements and footnotes included in the Company's annual report on Form 10-K for the year ended December 31, 2003. Certain reclassifications have been made to conform to the current presentation. (2) NEW ACCOUNTING PRONOUNCEMENTS In 2003, the Company was made aware of an issue regarding the application of provisions of Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards No. (SFAS) 141, "Business Combinations" and SFAS 142, "Goodwill and Other Intangible Assets," to oil and gas companies. The issue was whether SFAS 142 required registrants to reclassify costs associated with mineral rights, including both proved and unproved leasehold acquisition costs, as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs. Historically, the Company and other oil and gas companies have included the cost of oil and gas leasehold interests as part of oil and gas properties and provided the disclosures required by SFAS 69, "Disclosures about Oil and Gas Producing Activities." This matter was referred to the Emerging Issues Task Force (EITF) in late 2003. Although the EITF has not issued formal guidance for oil and gas companies, at the March 2004 meeting, the Task Force reached a consensus that mineral rights for mining companies should be accounted for as tangible assets. In order to resolve this inconsistency, the FASB directed the FASB staff to prepare a FASB Staff Position (FSP) that amended SFAS 141 and SFAS 142. FSP FAS 141-1 and 142-1 is effective for the first reporting period beginning after April 29, 2004. As the Company already includes these assets as part of its capitalized oil and gas properties, the application of this FSP did not have an impact on the Company. (3) DISPOSITIONS AND DISCONTINUED OPERATIONS On June 25, 2004, the Company completed a sale of substantially all of its Trenton Black River ("TBR") assets to Fortuna Energy Inc., a wholly owned subsidiary of Talisman Energy Inc. The assets sold include working interests in 16 wells, approximately 11 miles of natural gas gathering lines and oil and gas leases on approximately 475,000 gross acres. The assets are located primarily in New York, Pennsylvania, Ohio and West Virginia. The TBR assets accounted for approximately 5 Bcfe of the Company's estimated proved reserves as of December 31, 2003. The sale resulted in proceeds of approximately $68.4 million. The proceeds were used to pay down the Company's existing revolving credit facility. As a result of the disposition of the TBR geographical/geological pools, the Company recorded a gain of approximately $46.3 million ($29.5 5 million net of tax) in June 2004. According to SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," the disposition of this group of wells is classified as discontinued operations. In April 2004, the Company decided to dispose of its Arrow Oilfield Service Company ("Arrow") assets. The Company sold the Michigan assets of Arrow in May 2004 and sold the Ohio and Pennsylvania assets of Arrow in June 2004. The two Arrow asset sales resulted in proceeds of approximately $4.2 million. As a result of the disposition of all of its Arrow assets, the Company recorded a loss of approximately $1.3 million ($839,000 net of tax) in the second quarter of 2004. According to SFAS 144, the disposition of the Arrow assets is classified as discontinued operations. (4) DERIVATIVES AND HEDGING The Company recognizes all derivative financial instruments as either assets or liabilities at fair value. The changes in fair value of derivative instruments not qualifying for designation as cash flow hedges that occur prior to maturity are initially reported in expense in the consolidated statements of operations as derivative fair value (gain) loss. All amounts recorded in this line item are ultimately reversed within the same line item and included in oil and gas sales revenues over the respective contract terms. Changes in the fair value of derivative instruments that are fair value hedges are offset against changes in the fair value of the hedged assets, liabilities, or firm commitments, through net income (loss). Changes in the fair value of derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time as the hedged items are recognized in net income (loss). The hedging 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. The Company measures effectiveness at least on a quarterly basis. 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 the Company may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage its exposure to natural gas or oil price volatility and support the Company's capital expenditure plans. The Company employs a policy of hedging gas production sold under New York Mercantile Exchange ("NYMEX") based contracts by selling NYMEX based commodity derivative contracts which are placed with major financial institutions that the Company believes are minimal credit risks. The contracts may take the form of futures contracts, swaps, collars or options. At June 30, 2004, the Company's derivative contracts were comprised of natural gas swaps, collars and options. Qualifying NYMEX based derivative contracts are designated as cash flow hedges. During the first six months of 2004 and 2003, a net loss of $8.7 million ($5.5 million after tax) and a net loss of $8.5 million ($5.4 million after tax), respectively, were reclassified from accumulated other comprehensive income to earnings. The fair value of open hedges decreased $17.6 million ($11.2 million after tax) in the first six months of 2004 and decreased $28.0 million ($17.8 million after tax) in the first six months of 2003. At June 30, 2004, the estimated net loss in accumulated other comprehensive income that is expected to be reclassified into earnings within the next 12 months is approximately $22.8 million. At June 30, 2004, the Company has partially hedged its exposure to the variability in future cash flows through December 2005. See Note 8. 6 The following table reflects the natural gas volumes and the weighted average prices under financial hedges (including settled hedges) at June 30, 2004:
NATURAL GAS SWAPS NATURAL GAS COLLARS ------------------------ -------------------------- NYMEX PRICE NYMEX PRICE PER MMBTU QUARTER ENDING BBTU PER MMBTU BBTU FLOOR/CAP (1) - -------------- ---- ----------- ---- ------------- September 30, 2004 2,040 $ 3.84 1,080 $ 4.00 - 5.80 December 31, 2004 2,040 3.84 1,080 4.00 - 5.80 ----- ------------ ----- ------------- 4,080 $ 3.84 2,160 $ 4.00 - 5.80 ===== ============ ===== ============= March 31, 2005 1,500 $ 3.84 1,500 $ 4.00 - 5.37 June 30, 2005 1,500 3.73 1,500 4.00 - 5.37 September 30, 2005 1,500 3.73 1,500 4.00 - 5.37 December 31, 2005 1,500 3.73 1,500 4.00 - 5.37 ----- ------------ ----- ------------- 6,000 $ 3.76 6,000 $ 4.00 - 5.37 ===== ============ ===== =============
MMBTU - MILLION BRITISH THERMAL UNITS BBTU - BILLION BRITISH THERMAL UNITS (1) The NYMEX price per Mmbtu floor/cap for the natural gas collars in 2004 assume the monthly NYMEX settles at $3.00 per Mmbtu or higher. If the monthly NYMEX settles at less than $3.00 per Mmbtu then the NYMEX price per Mmbtu will be the NYMEX settle plus $1.00. The NYMEX price per Mmbtu floor/cap for the natural gas collars in 2005 assume the monthly NYMEX settles at $3.10 per Mmbtu or higher. If the monthly NYMEX settles at less than $3.10 per Mmbtu then the NYMEX price per Mmbtu will be the NYMEX settle plus $0.90. (5) STOCK-BASED COMPENSATION The Company measures 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 by the Company upon the issuance of stock options to key employees as the exercise price of the option is equal to the market price of the underlying common stock at the date of grant. For purposes of the pro forma disclosures required by SFAS 123, the estimated fair value of the options is amortized to expense over the options' vesting period. The changes in net income or loss as if the Company had applied the fair value provisions of SFAS 123 for the quarters ended June 30, 2004, and 2003 were not material. The changes in share value and the vesting of shares are reported as adjustments to compensation expense. The change in share value in the quarter ended June 30, 2004, resulted in anon-cash increase in compensation expense of $1.1 million. The vesting of shares in the quarter ended June 30, 2003, resulted in a non-cash increase in compensation expense of $18,000. (6) INDUSTRY SEGMENT FINANCIAL INFORMATION The Company operates 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. The Company's operations are conducted entirely in the United States. 7 (7) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
SIX MONTHS ENDED JUNE 30, ---------------------------- (IN THOUSANDS) 2004 2003 ---------- ----------- CASH PAID DURING THE PERIOD FOR: Interest $ 12,158 $ 11,829 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF TAX -- 2,397
(8) SUBSEQUENT EVENT On July 7, 2004, the Company, Capital C Energy Operations, LP, a Delaware limited partnership ("Capital C"), and Capital C Ohio, Inc., an Ohio corporation and a wholly owned subsidiary of Capital C ("Merger Sub"), completed a merger pursuant to which Merger Sub was merged with and into the Company (the "Merger"), with the Company surviving the Merger as a wholly owned subsidiary of Capital C. The Merger resulted in a change in control of the Company. The general partner of Capital C's general partner is Capital C Energy, LLC, an entity formed in April 2004 by David M. Carmichael, Frost W. Cochran and Peter R. Coneway in partnership with Carlyle/Riverstone Global Energy & Power Fund II, L.P. and Capital C Energy Partners, L.P. Capital C Energy, LLC is headquartered in Houston, Texas. The Merger was completed on July 7, 2004 and for financial reporting purposes will be accounted for as a purchase effective July 1, 2004. The acquisition will result in a new basis of accounting reflecting estimated fair values for assets and liabilities at that date. In the Merger, each issued and outstanding share of the Company common stock was converted into the right to receive cash. All outstanding amounts of indebtedness under the Company's prior credit facility were repaid. In connection with the Consent Solicitation and Tender Offer previously announced by the Company, over 98% of the Company's $225 million aggregate principal amount of 9-7/8% Senior Subordinated Notes were also tendered and repaid at the closing of the Merger, and the terms of a supplemental indenture eliminating several covenants in the indenture governing the 9-7/8% Senior Subordinated Notes have become effective. Capital C obtained the funds necessary to consummate the Merger through (1) equity capital contributions of $77.5 million by its partners, (2) the Company's entry into a secured credit facility with various lenders arranged through Goldman Sachs Credit Partners, L.P. with a $100 million term facility maturing on July 7, 2011, a $30 million revolving facility maturing on July 7, 2010 and a $40 million letter of credit facility, which amounts are secured by substantially all of the assets of the Company and are guaranteed by two of the Company's subsidiaries, Ward Lake Drilling, Inc. and The Canton Oil & Gas Company (the "Senior Facilities"), and (3) a private placement of $192.5 million aggregate principal amount of 8-3/4% Senior Secured Notes due 2012 (the "Notes"), which are secured by a second-priority lien on the same assets and guaranteed by the same subsidiaries that guarantee the Senior Facilities. Pre-existing commodity hedges and ten-year commodity hedges effected in connection with the Merger will also be secured by a second-priority lien on the same assets and guaranteed by the same subsidiaries that guarantee the Senior Facilities and the Notes. In connection with the Merger the Company entered into commodity hedges on a substantial portion of its future oil and gas production through the year 2013. See Note 8. The Company's management team remained with the Company after the Merger with the exception of the retirement of the former Chief Executive Officer, John L. Schwager. Frost W. Cochran is the Company's new President and Chief Executive Officer. In addition, Gregory A. Beard joined the Company as Executive Vice President, Assistant Secretary and Director; and B. Dee Davis and W. Mac Jensen joined the Company as Senior Vice Presidents. Upon consummation of the Merger all former 8 directors of the Company resigned and the new Board of Directors consists of six members, each of whom is elected annually to serve one-year terms. The initial six members of the Board of Directors are Frost W. Cochran, David M. Carmichael, Michael B. Hoffman, Pierre F. Lapeyre, Jr., David M. Leuschen, and Gregory A. Beard. In April 2002, the Company was notified of a claim by an overriding royalty owner in Michigan alleging the underpayment of royalty resulting from disputes as to the interpretation of the terms of several farmout agreements. On July 6, 2004, a suit was filed in Otsego County, Michigan by the successor in interest to these royalty interests, alleging substantially the same underpayments. The Company believes there will be no material amount payable above and beyond the amount accrued as of June 30, 2004 and therefore, the result will have no material adverse effect on its financial position, results of operation or cash flows. ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FORWARD-LOOKING INFORMATION The information in this document includes forward-looking statements that are made pursuant to Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Statements preceded by, followed by or that otherwise include the statements "should," "believe," "expect," "anticipate," "intend," "will," "continue," "estimate," "plan," "outlook," "may," "future," "projection," and variations of these statements and similar expressions are forward-looking statements. These forward-looking statements are based on current expectations and projections about future events. Forward-looking statements, and the business prospects of the Company are subject to a number of risks and uncertainties which may cause the Company's 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, the Company's access to capital, the market demand for and prices of oil and natural gas, the Company's oil and gas production and costs of operation, results of the Company's 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 the Company's 10-K and 10-Q reports and other filings with the Securities and Exchange Commission ("SEC"). CRITICAL ACCOUNTING POLICIES The Company prepares its 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 the Company's 2003 Form 10-K annual report filed with the SEC for a comprehensive discussion of the Company's 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 the Company's most critical accounting policies: SUCCESSFUL EFFORTS METHOD OF ACCOUNTING The accounting for and disclosure of oil and gas producing activities requires the Company's management to choose between GAAP alternatives and to make judgments about estimates of future uncertainties. The Company utilizes 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, 9 property acquisition and development costs and certain productive exploration costs are capitalized while non-productive exploration costs, which include certain geological and geophysical costs, exploratory dry hole costs and costs of carrying and retaining unproved properties, are expensed as incurred. The major difference between the successful efforts method of accounting and the full cost method is under the full cost method of accounting, such exploration costs and expenses are capitalized as assets, pooled with the costs of successful wells and charged against the net income (loss) of future periods as a component of depletion expense. OIL AND GAS RESERVES The Company's proved developed and proved undeveloped reserves are all located within the Appalachian and Michigan Basins in the United States. The Company cautions that there are many uncertainties inherent in estimating proved reserve quantities and in projecting future production rates and the timing of development expenditures. In addition, estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are expected to change as future information becomes available. Material revisions of reserve estimates may occur in the future, development and production of the oil and gas reserves may not occur in the periods assumed and actual prices realized and actual costs incurred may vary significantly from assumptions used. Proved reserves represent estimated quantities of natural gas and oil that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions existing at the time the estimates were made. Proved developed reserves are proved reserves expected to be recovered through wells and equipment in place and under operating methods being utilized at the time the estimates were made. The accuracy of a reserve estimate is a function of: -- the quality and quantity of available data; -- the interpretation of that data; -- the accuracy of various mandated economic assumptions; and -- the judgment of the persons preparing the estimate. The Company's proved reserve information included in the Company's 2003 Form 10-K is based on estimates prepared by independent petroleum engineers. Estimates prepared by others may be higher or lower than these estimates. CAPITALIZATION, DEPRECIATION, DEPLETION AND IMPAIRMENT OF LONG-LIVED ASSETS See the "Successful Efforts Method of Accounting" discussion above. Capitalized costs related to proved properties are depleted using the unit-of-production method. Depreciation, depletion and amortization of proved oil and gas properties is calculated on the basis of estimated recoverable reserve quantities. These estimates can change based on economic or other factors. No gains or losses are recognized upon the disposition of oil and gas properties except in extraordinary transactions. Sales proceeds are credited to the carrying value of the properties. Maintenance and repairs are expensed, and expenditures which enhance the value of properties are capitalized. Unproved oil and gas properties are stated at cost and consist of undeveloped leases. These costs are assessed periodically to determine whether their value has been impaired, and if impairment is indicated, the costs are charged to expense. Gas gathering systems are stated at cost. Depreciation expense is computed using the straight-line method over 15 years. Property and equipment are stated at cost. Depreciation of non-oil and gas properties is computed using the straight-line method over the useful lives of the assets ranging from 3 to 15 years for machinery 10 and equipment and 30 to 40 years for buildings. When assets other than oil and gas properties are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is reflected in income for the period. The cost of maintenance and repairs is expensed as incurred, and significant renewals and betterments are capitalized. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the sum of the expected future undiscounted cash flows is less than the carrying amount of the asset, a loss is recognized for the difference between the fair value and the carrying amount of the asset. Fair value is determined on management's outlook of future oil and natural gas prices and estimated future cash flows to be generated by the assets, discounted at a market rate of interest. Impairment of unproved properties is based on the estimated fair value of the property. DERIVATIVES AND HEDGING The Company recognizes 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). 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). 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. The Company measures effectiveness on changes in the hedge's intrinsic value. The Company considers these hedges to be highly effective and expects 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. Ongoing assessments of hedge effectiveness will include verifying and documenting that the critical terms of the hedge and forecasted transaction do not change. The Company measures effectiveness on at least a quarterly basis. The Company's financial results and cash flows can be significantly impacted as commodity prices fluctuate widely in response to changing market conditions. To manage its exposure to natural gas or oil price volatility, the Company has entered into NYMEX based commodity derivative contracts, currently natural gas swaps and collars, and has designated the contracts for the special hedge accounting treatment permitted under SFAS 133. 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. Oilfield service revenues are recognized when the goods or services have been provided. NEW ACCOUNTING PRONOUNCEMENTS In 2003, the Company was made aware of an issue regarding the application of provisions of SFAS 141, "Business Combinations" and SFAS 142, "Goodwill and Other Intangible Assets," to oil and gas companies. The issue was whether SFAS 142 required registrants to reclassify costs associated with mineral rights, including both proved and unproved leasehold acquisition costs, as intangible assets in the 11 balance sheet, apart from other capitalized oil and gas property costs. Historically, the Company and other oil and gas companies have included the cost of oil and gas leasehold interests as part of oil and gas properties and provided the disclosures required by SFAS 69, "Disclosures about Oil and Gas Producing Activities." This matter was referred to the EITF in late 2003. Although the EITF has not issued formal guidance for oil and gas companies, at the March 2004 meeting, the Task Force reached a consensus that mineral rights for mining companies should be accounted for as tangible assets. In order to resolve this inconsistency, the Board directed the FASB staff to prepare a FSP that amended SFAS 141 and SFAS 142. FSP FAS 141-1 and 142-1 is effective for the first reporting period beginning after April 29, 2004. As the Company already includes these assets as part of its capitalized oil and gas properties the application of this FSP did not have an impact on the Company. RESULTS OF OPERATIONS 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 the Company's net oil and natural gas production, revenues and expenses for the periods indicated:
THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30, --------------------------- ------------------------- 2004 2003 2004 2003 ---- ---- ---- ---- PRODUCTION Gas (Mmcf) 3,818 3,582 7,697 7,025 Oil (Mbbls) 92 102 189 203 Total production (M mcfe) 4,370 4,194 8,828 8,241 AVERAGE PRICE Gas (per Mcf) $ 5.17 $ 5.18 $ 5.07 $ 4.97 Oil (per Bbl) 34.94 26.59 33.46 28.33 Mcfe 5.25 5.07 5.13 4.94 AVERAGE COSTS (PER MCFE) Production expense 1.27 1.14 1.24 1.13 Production taxes 0.15 0.16 0.15 0.16 Depletion 0.84 0.78 0.83 0.78 OPERATING MARGIN (PER MCFE) 3.83 3.77 3.74 3.65
MMCF - MILLION CUBIC FEET MBBLS - THOUSAND BARRELS MMCFE - MILLION CUBIC FEET OF NATURAL GAS EQUIVALENT MCF - THOUSAND CUBIC FEET BBL - BARREL MCFE - THOUSAND CUBIC FEET OF NATURAL GAS EQUIVALENT OPERATING MARGIN (PER MCFE) - AVERAGE PRICE LESS PRODUCTION EXPENSE AND PRODUCTION TAXES
RESULTS OF OPERATIONS - SECOND QUARTERS OF 2004 AND 2003 COMPARED REVENUES Net operating revenues increased from $23.5 million in the second quarter of 2003 to $25.4 million in the second quarter of 2004. The increase was due to higher gas sales revenues of $1.2 million, higher oil sales revenues of $506,000 and higher gas gathering and marketing revenues of $230,000. Gas volumes sold increased 236 Mmcf (7%) from 3.6 Bcf (billion cubic feet) in the second quarter of 2003 to 3.8 Bcf in the second quarter of 2004 resulting in an increase in gas sales revenues of approximately $1.2 million. Oil volumes sold decreased approximately 10,000 Bbls (10%) from 102,000 Bbls in the second quarter of 2003 to 92,000 Bbls in the second quarter of 2004 resulting in a decrease in oil sales revenues of approximately $265,000. The gas sales volume increase was due to the production from wells drilled in 2003 and 2004 and increased production as a result of additional expenditures to stimulate production on declining wells partially offset by normal production declines. The lower oil 12 sales volumes are due to normal production declines. The Company's drilling program primarily targets natural gas reserves. The average price realized for the Company's natural gas decreased $0.01 per Mcf to $5.17 per Mcf in the second quarter of 2004 compared to the second quarter of 2003 which decreased gas sales revenues in the second quarter of 2004 by approximately $40,000. As a result of the Company's hedging activities, gas sales revenues were decreased by $4.9 million ($1.28 per Mcf) in the second quarter of 2004 and decreased by $2.4 million ($0.68 per Mcf) in the second quarter of 2003. The average price paid for the Company's oil increased from $26.59 per Bbl in the second quarter of 2003 to $34.94 per Bbl in the second quarter of 2004 which increased oil sales revenues by approximately $770,000. 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 $3.77 per Mcfe in the second quarter of 2003 to $3.83 per Mcfe in the second quarter of 2004. The increase in gas gathering and marketing revenues was primarily due to a $140,000 increase in gas marketing revenues and a $90,000 increase in gas gathering revenues. The higher marketing revenues were the result of higher prices. The increase in gas gathering revenues was primarily due to higher margins on a gathering system in Pennsylvania. COSTS AND EXPENSES Production expense increased $779,000 (16%) from $4.8 million in the second quarter of 2003 to $5.5 million in the second quarter of 2004 primarily due to $462,000 of additional non-cash stock-based compensation expense recorded in the second quarter of 2004 to reflect the increased value of the Company's stock and increased costs to stimulate production on declining wells in the higher oil and natural gas price environment. These efforts increased production volumes during the second quarter of 2004 but also had the effect of increasing the per unit cost. The average production cost increased from $1.14 per Mcfe in the second quarter of 2003 to $1.27 per Mcfe in the second quarter of 2004. The per unit increase was primarily due to the higher costs incurred during the second quarter of 2004 as discussed above partially offset by certain fixed costs spread over greater volumes in the second quarter of 2004. Production taxes decreased $8,000 from $656,000 in the second quarter of 2003 to $648,000 in the second quarter of 2004. Exploration expense decreased $220,000 (14%) from $1.6 million in the second quarter of 2003 to $1.4 million in the second quarter of 2004. This decrease is primarily due to decreases in expired lease expense and exploratory dry hole cost partially offset by additional non-cash stock-based compensation expense in the second quarter of 2004. General and administrative expense increased $169,000 (15%) from the second quarter of 2003 to the second quarter of 2004 due to $292,000 of additional non-cash stock-based compensation expense recorded in the second quarter of 2004 to reflect the increased value of the Company's stock partially offset by decreases in other employment and compensation related expenses. Depreciation, depletion and amortization increased by $414,000 from $4.1 million in the second quarter of 2003 to $4.5 million in the second quarter of 2004. This increase was primarily due to an increase in depletion expense. Depletion expense increased $398,000 (12%) from $3.3 million in the second quarter of 2003 to $3.7 million in the second quarter of 2004 due to higher gas volumes and a higher depletion rate per Mcfe. Depletion per Mcfe increased from $0.78 per Mcfe in the second quarter of 2003 to $0.84 per Mcfe in the second quarter of 2004, primarily due to higher production from higher cost wells. 13 Derivative fair value (gain) loss was a gain of $451,000 in the second quarter of 2003 compared to a loss of $11,000 in the second quarter of 2004. The derivative fair value (gain) loss reflects the changes in fair value of certain derivative instruments that are not designated as cash flow hedges. Interest expense increased $76,000 from $6.0 million in the second quarter of 2003 to $6.1 million in the second quarter of 2004. This increase was due to an increase in average outstanding borrowings partially offset by lower blended interest rates. Income tax expense decreased $166,000 from $1.4 million in the second quarter of 2003 to $1.2 million in the second quarter of 2004. The decrease was due to a decrease in income from continuing operations before income taxes and a lower effective tax rate in the second quarter of 2004. Discontinued operations relating to the TBR and Arrow asset sales resulted in a net income of $28.9 million in the second quarter of 2004 compared to a net loss of $845,000 in the second quarter of 2003. This was primarily attributable to the $45.0 million ($28.6 million net of tax) gain recorded in the second quarter of 2004. RESULTS OF OPERATIONS - SIX MONTHS OF 2004 AND 2003 COMPARED REVENUES Net operating revenues increased from $46.2 million in the first six months of 2003 to $50.4 million in the first six months of 2004. The increase was due to higher gas sales revenues of $4.1 million and higher oil sales revenues of $568,000 partially offset by lower gas gathering and marketing revenues of $438,000. Gas volumes sold increased 672 Mmcf (10%) from 7.0 Bcf in the first six months of 2003 to 7.7 Bcf in the first six months of 2004 resulting in an increase in gas sales revenues of approximately $3.3 million. Oil volumes sold decreased approximately 14,000 Bbls (7%) from 203,000 Bbls in the first six months of 2003 to 189,000 Bbls in the first six months of 2004 resulting in a decrease in oil sales revenues of approximately $400,000. The gas sales volume increase was primarily due to the production from wells drilled in 2003 and 2004 and increased production as a result of additional expenditures to stimulate production on declining wells partially offset by normal production declines. The lower oil sales volumes are due to normal production declines. The Company's drilling program primarily targets natural gas reserves. The average price realized for the Company's natural gas increased $0.10 per Mcf to $5.07 per Mcf in the first six months of 2004 compared to the first six months of 2003 which increased gas sales revenues in the first six months of 2004 by approximately $770,000. As a result of the Company's hedging activities, gas sales revenues were decreased by $8.4 million ($1.10 per Mcf) in the first six months of 2004 and decreased by $8.5 million ($1.21 per Mcf) in the first six months of 2003. The average price paid for the Company's oil increased from $28.33 per Bbl in the first six months of 2003 to $33.46 per Bbl in the first six months of 2004 which increased oil sales revenues by approximately $1.0 million. The operating margin from oil and gas sales on a per unit basis increased from $3.65 per Mcfe in the first six months of 2003 to $3.74 per Mcfe in the first six months of 2004. The decrease in gas gathering and marketing revenues was primarily due to a $1.0 million decrease in gas marketing revenues partially offset by a $577,000 increase in gas gathering revenues. The lower marketing revenues were the result of decreased gas marketing activity and lower prices. The increase in gas gathering revenues was primarily due to higher margins on a gathering system in Pennsylvania. 14 COSTS AND EXPENSES Production expense increased $1.7 million (17%) from $9.3 million in the first six months of 2003 to $11.0 million in the first six months of 2004 primarily due to increased costs to stimulate production on declining wells in the higher oil and natural gas price environment and $462,000 of additional non-cash stock-based compensation expense recorded in the second quarter of 2004 to reflect the increased value of the Company's stock. The additional expenditures increased production volumes during the first six months of 2004 but also had the effect of increasing the per unit cost. The average production cost increased from $1.13 per Mcfe in the first six months of 2003 to $1.24 per Mcfe in the first six months of 2004. The per unit increase was primarily due to the higher costs incurred during the first six months of 2004 as discussed above partially offset by certain fixed costs spread over greater volumes in the first six months of 2004. Production taxes decreased $29,000 in the first six months of 2004. Exploration expense decreased $524,000 (16%) from $3.2 million in the first six months of 2003 to $2.7 million in the first six months of 2004 primarily due to decreases in expiring lease expense and exploratory dry hole expense partially offset by additional non-cash stock-based compensation expense recorded in the second quarter of 2004. General and administrative expense increased $230,000 (10%) from the first six months of 2003 to the first six months of 2004 due to $292,000 of additional non-cash stock-based compensation expense recorded in the second quarter of 2004 to reflect the increased value of the Company's stock partially offset by decreases in other employment and compensation related expenses. Depreciation, depletion and amortization increased by $938,000 from $8.2 million in the first six months of 2003 to $9.1 million in the first six months of 2004. This increase was primarily due to an increase in depletion expense. Depletion expense increased $944,000 (15%) from $6.4 million in the first six months of 2003 to $7.4 million in the first six months of 2004 due to higher gas volumes and a higher depletion rate per Mcfe. Depletion per Mcfe increased from $0.78 per Mcfe in the first six months of 2003 to $0.83 per Mcfe in the first six months of 2004, primarily due to higher production from higher cost wells. Derivative fair value (gain) loss was a gain of $174,000 in the first six months of 2003 compared to a gain of $321,000 in the first six months of 2004. The derivative fair value (gain) loss reflects the changes in fair value of certain derivative instruments that are not designated as cash flow hedges. Interest expense increased $243,000 (2%) from $11.9 million in the first six months of 2003 to $12.2 million in the first six months of 2004. This increase was due to an increase in average outstanding borrowings partially offset by lower blended interest rates. Income tax expense increased $802,000 from $1.8 million in the first six months of 2003 to $2.6 million in the first six months of 2004. The increase was due to an increase in income from continuing operations before income taxes partially offset by a lower effective tax rate in the first six months of 2004. Discontinued operations relating to the TBR and Arrow asset sales resulted in a net income of $28.6 million in the first six months of 2004 compared to a net loss of $1.2 million in the first six months of 2003. This was primarily attributable to the $45.0 million ($28.6 million net of tax) gain recorded in the second quarter of 2004. 15 LIQUIDITY AND CAPITAL RESOURCES CASH FLOWS The primary sources of cash in the six-month period ended June 30, 2004 have been net proceeds from the sale of the Company's TBR and Arrow assets, funds generated from operations and from borrowings under the Company's $100 million revolving credit facility (the "Revolver"). Funds used during this period were primarily used for operations, exploration and development expenditures, interest expense and repayment of debt. The Company's liquidity and capital resources are closely related to and dependent on the current prices paid for its oil and natural gas. The Company's operating activities provided cash flows of $18.6 million during the first six months of 2004 compared to $9.6 million in the first six months of 2003. The increase was primarily due to higher cash received for oil and gas revenues (net of hedging) of $4.6 million and changes in working capital items of $8.0 million. Cash flows used in investing activities decreased in the first six months of 2004 primarily due to $4.6 million in acquisitions in the first six months of 2003, a $1.3 million decrease in other assets and a $524,000 decrease in exploration expense partially offset by $4.7 million of increased capital expenditures in the first six months of 2004. Cash flows used in financing activities in the first six months of 2004 were primarily due to payments on the credit facility. Cash flows provided by financing activities during the first six months of 2003 were borrowings on the credit facility to fund acquisition, exploration and development expenditures in the first six months of 2003. The Company's current ratio from continuing operations at June 30, 2004 was 1.68 to 1. During the first six months of 2004, the working capital from continuing operations increased $38.0 million from a deficit of $7.1 million at December 31, 2003 to working capital of $30.9 million at June 30, 2004. The increase was primarily due to a $44.2 million increase in cash from the proceeds of the second quarter 2004 asset sales, a $3.5 million increase in accounts receivable and a $3.0 increase in the deferred income taxes asset partially offset by an $8.0 million increase in the net current liability for the fair value of derivatives and a $5.1 million increase in accrued expenses. The increase in accrued expenses is primarily due to increases in accrued income taxes and accrued drilling costs. CAPITAL EXPENDITURES During the first six months of 2004, the Company spent approximately $11 million on its drilling activities and other capital expenditures related to continuing operations. In the first six months of 2004, the Company drilled 41 gross (37.4 net) development wells, all of which were successfully completed as producers in the target formation. The cost excludes approximately $300,000 related to 2 gross (1.2 net) shallow exploratory wells in progress as of June 30, 2004. The Company currently expects to spend approximately $24 million during 2004 on its drilling activities and other capital expenditures related to continuing operations. The Company intends to finance its planned capital expenditures through its available cash flow, available revolving credit line and the sale of non-strategic assets. At June 30, 2004, the Company had approximately $52.9 million available under the Revolver. The level of the Company's 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 its drilling activities and its ability to acquire additional producing properties. CAPITAL C MERGER As disclosed in Note 8 "Subsequent Event" to the consolidated financial statements, on July 7, 2004, the Company, Capital C Energy Operations, LP, a Delaware limited partnership ("Capital C"), and Capital C Ohio, Inc., an Ohio corporation and a wholly owned subsidiary of Capital C ("Merger Sub"), 16 completed a merger pursuant to which Merger Sub was merged with and into the Company (the "Merger"), with the Company surviving the Merger as a wholly owned subsidiary of Capital C. The Merger resulted in a change in control of the Company. The general partner of Capital C's general partner is Capital C Energy, LLC, an entity formed in April 2004 by David M. Carmichael, Frost W. Cochran and Peter R. Coneway in partnership with Carlyle/Riverstone Global Energy & Power Fund II, L.P. and Capital C Energy Partners, L.P. Capital C Energy, LLC is headquartered in Houston, Texas. The Merger was completed on July 7, 2004 and for financial reporting purposes will be accounted for as a purchase effective July 1, 2004. The acquisition will result in a new basis of accounting reflecting estimated fair values for assets and liabilities at that date. In the Merger, each issued and outstanding share of the Company common stock was converted into the right to receive cash. All outstanding amounts of indebtedness under the Company's prior credit facility were repaid. In connection with the Consent Solicitation and Tender Offer previously announced by the Company, over 98% of the Company's $225 million aggregate principal amount of 9-7/8% Senior Subordinated Notes were also tendered and repaid at the closing of the Merger, and the terms of a supplemental indenture eliminating several covenants in the indenture governing the 9-7/8% Senior Subordinated Notes have become effective. Capital C obtained the funds necessary to consummate the Merger through (1) equity capital contributions of $77.5 million by its partners, (2) the Company's entry into a secured credit facility with various lenders arranged through Goldman Sachs Credit Partners, L.P. with a $100 million term facility maturing on July 7, 2011, a $30 million revolving facility maturing on July 7, 2010 and a $40 million letter of credit facility, which amounts are secured by substantially all of the assets of the Company and are guaranteed by two of the Company's subsidiaries, Ward Lake Drilling, Inc. and The Canton Oil & Gas Company (the "Senior Facilities"), and (3) a private placement of $192.5 million aggregate principal amount of 8-3/4% Senior Secured Notes due 2012 of the Company (the "Notes"), which are secured by a second-priority lien on the same assets and guaranteed by the same subsidiaries that guarantee the Senior Facilities. Pre-existing commodity hedges and ten-year commodity hedges effected in connection with the Merger will also be secured by a second-priority lien on the same assets and guaranteed by the same subsidiaries that guarantee the Senior Facilities and the Notes. In connection with the Merger the Company entered into commodity hedges on a substantial portion of its future oil and gas production through the year 2013. See Note 8. The Company's management team remained with the Company after the Merger with the exception of the retirement of the former Chief Executive Officer, John L. Schwager. Frost W. Cochran is the Company's new President and Chief Executive Officer. In addition, Gregory A. Beard joined the Company as Executive Vice President, Assistant Secretary and Director; and B. Dee Davis and W. Mac Jensen joined the Company as Senior Vice Presidents. Upon consummation of the Merger all former directors of the Company resigned and the new Board of Directors consists of six members, each of whom is elected annually to serve one-year terms. The initial six members of the Board of Directors are Frost W. Cochran, David M. Carmichael, Michael B. Hoffman, Pierre F. Lapeyre, Jr., David M. Leuschen, and Gregory A. Beard. FINANCING AND CREDIT FACILITIES At June 30, 2004, the Company had a $100 million revolving credit facility and a special letter of credit facility in the amount of $25 million from Ableco Finance LLC and Wells Fargo Foothill, Inc. At June 30, 2004, the interest rate was 6.00%. At June 30, 2004, the Company had $48.2 million of outstanding letters of credit. At June 30, 2004, the outstanding balance under the credit agreement was $23.9 million with $52.9 million of borrowing capacity available for general corporate purposes. As of 17 June 30, 2004, the Company had satisfied all financial covenants and requirements under the existing revolving credit facility. At July 31, 2004, the Company had $55.0 million of outstanding letters of credit under the Company's post Merger Senior Facilities. From time to time the Company may enter into interest rate swaps to hedge the interest rate exposure associated with the credit facility, whereby a portion of the Company's floating rate exposure is exchanged for a fixed interest rate. There were no interest rate swaps in the first six months of 2004 or 2003. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Among other risks, the Company is exposed to interest rate and commodity price risks. The interest rate risk relates to existing debt under the Company's revolving credit facility as well as any new debt financing needed to fund capital requirements. The Company may manage its interest rate risk through the use of interest rate swaps to hedge the interest rate exposure associated with the credit agreement, whereby a portion of the Company's floating rate exposure is exchanged for a fixed interest rate. A portion of the Company's long-term debt consists of senior subordinated notes where the interest component is fixed. The Company had no derivative financial instruments for managing interest rate risks in place as of June 30, 2004 or 2003. If market interest rates for short-term borrowings increased 1%, the increase in the Company's interest expense in the second quarter would be approximately $60,000. This sensitivity analysis is based on the Company's financial structure at June 30, 2004. The commodity price risk relates to natural gas and crude oil produced, held in storage and marketed by the Company. The Company's financial results can be significantly impacted as commodity prices fluctuate widely in response to changing market forces. From time to time the Company may enter into a combination of futures contracts, commodity derivatives and fixed-price physical contracts to manage its exposure to commodity price volatility. The fixed-price physical contracts generally have terms of a year or more. The Company employs a policy of hedging gas production sold under NYMEX based contracts by selling NYMEX based commodity derivative contracts which are placed with major financial institutions that the Company believes are minimal credit risks. The contracts may take the form of futures contracts, swaps or options. If NYMEX gas prices decreased $0.50 per Mcf, the Company's gas sales revenues for the quarter would decrease by $833,000, after considering the effects of the hedging contracts in place. At June 30, 2004, the Company had no hedges or fixed price contracts on its oil production during 2004 or 2003. If the price of crude oil decreased $3.00 per Bbl, the Company's oil sales revenues for the quarter would decrease by $276,000. To manage its exposure to natural gas or oil price volatility, the Company may partially hedge its physical gas or oil sales prices by selling futures contracts on the NYMEX or by selling NYMEX based commodity derivative contracts which are placed with major financial institutions that the Company believes are minimal credit risks. The contracts may take the form of futures contracts, swaps, collars or options. The Company had net pretax losses on its hedging activities of $8.4 million in the first six months of 2004 and $8.5 million in the first six months of 2003. The Company's financial results and cash flows can be significantly impacted as commodity prices fluctuate widely in response to changing market conditions. Accordingly, the Company may modify its fixed price contract and financial hedging positions by entering into new transactions. 18 The following table reflects the natural gas and crude oil volumes and the weighted average prices under financial hedges (including settled hedges) at July 31, 2004:
NATURAL GAS SWAPS NATURAL GAS COLLARS CRUDE OIL SWAPS ----------------- ------------------- --------------- NYMEX PRICE NYMEX PER MMBTU NYMEX PRICE PER FLOOR/CAP ESTIMATED PRICE PER QUARTER ENDING BBTU MMBTU BBTU (1) MBBLS BBL ------ --------- ----- ----------- --------- ----------- September 30, 2004 2,040 $ 3.82 1,080 $4.00-5.77 74 $ 36.06 December 31, 2004 2,040 3.81 1,080 4.00-5.76 74 35.68 ------ --------- ----- ---------- --- ----------- 4,080 $ 3.82 2,160 $4.00-5.76 148 $ 35.87 ====== ========= ===== ========== === =========== March 31, 2005 1,500 $ 3.81 1,500 $4.00-5.32 68 $ 34.76 June 30, 2005 1,500 3.70 1,500 4.00-5.32 68 34.18 September 30, 2005 1,500 3.70 1,500 4.00-5.32 67 33.72 December 31, 2005 1,500 3.70 1,500 4.00-5.32 67 33.31 ------ --------- ----- ---------- --- ----------- 6,000 $ 3.73 6,000 $4.00-5.32 270 $ 34.00 ====== ========= ===== ========== === =========== March 31, 2006 2,829 $ 6.14 63 $ 32.71 June 30, 2006 2,829 5.24 62 32.35 September 30, 2006 2,829 5.22 62 32.02 December 31, 2006 2,829 5.39 62 31.71 ------ --------- --- ----------- 11,316 $ 5.50 249 $ 32.20 ====== ========= === =========== YEAR ENDING December 31, 2007 10,745 $ 4.97 227 $ 30.91 December 31, 2008 10,126 4.64 208 29.96 December 31, 2009 9,529 4.43 191 29.34 December 31, 2010 8,938 4.28 175 28.86 December 31, 2011 8,231 4.19 157 28.77 December 31, 2012 7,005 4.09 138 28.70 December 31, 2013 6,528 4.04 127 28.70
BBL - BARREL MMBTU - MILLION BRITISH THERMAL UNITS MBBLS - THOUSAND BARRELS BBTU - BILLION BRITISH THERMAL UNITS (1) The NYMEX price per Mmbtu floor/cap for the natural gas collars in 2004 assume the monthly NYMEX settles at $3.00 per Mmbtu or higher. If the monthly NYMEX settles at less than $3.00 per Mmbtu then the NYMEX price per Mmbtu will be the NYMEX settle plus $1.00. The NYMEX price per Mmbtu floor/cap for the natural gas collars in 2005 assume the monthly NYMEX settles at $3.10 per Mmbtu or higher. If the monthly NYMEX settles at less than $3.10 per Mmbtu then the NYMEX price per Mmbtu will be the NYMEX settle plus $0.90. The proximity of the Company's properties in the Appalachian and Michigan basins to large commercial and industrial natural gas markets has generally resulted in premium wellhead gas prices compared with the prices of NYMEX futures contracts for gas delivered at the Henry Hub in Louisiana. Monthly spot natural gas prices in our market areas are typically 15 to 60 cents higher per Mcf than comparable NYMEX prices. The Company's average price received for crude oil is typically $2.50 to $3.25 per barrel below the NYMEX price per barrel. 19 ITEM 4. CONTROLS AND PROCEDURES As of the end of the period covered by this quarterly report, the Company carried out an evaluation, under the supervision and with the participation of the Company's management, including the Company's Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company's disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon the evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company's disclosure controls and procedures were effective as of the end of the period covered by this quarterly report. During the quarter ended June 30, 2004, there have been no changes in the Company's internal controls over financial reporting, identified in connection with our evaluation thereof that have materially affected, or are reasonably likely to materially affect our internal control over financial reporting. PART II OTHER INFORMATION Item 6. Exhibits and Reports on Form 8-K (a) Exhibits 10.1* Amendment No. 3 of the Belden & Blake Corporation 1999 Change in Control Protection Plan for Key Employees dated as of April 20, 2004. 31.1* Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2* Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1* Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2* Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. *Filed herewith (b) Reports on Form 8-K On June 22, 2004, the Company filed a Current Report on Form 8-K dated June 15, 2004, reporting under Item 5 that the Company had issued two press releases announcing that (1) it had signed an Agreement and Plan of Merger with an affiliate of Capital C Energy, LLC, a private investment limited partnership controlled by Carlyle/Riverstone Global Energy and Power Fund II, L.P.; and (2) it had commenced a cash tender offer and consent solicitation to purchase for cash any and all of its outstanding $225,000,000 aggregate principal amount of 9 7/8% Senior Subordinated Notes due 2007. On June 24, 2004, the Company filed a Current Report on Form 8-K dated June 23, 2004, reporting under Item 5 that the Company had issued two press releases announcing that (1) it planed to offer $192.5 million principal amount of Senior Secured Notes due 2012 pursuant to a private placement; and (2) it had executed a Letter Agreement with a third-party buyer, pursuant to which the Company will sell substantially all of its Trenton Black River assets. The assets are located primarily in New York, Pennsylvania, Ohio and West Virginia. 20 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. BELDEN & BLAKE CORPORATION Date: August 10, 2004 By: /s/ Frost W. Cochran ------------------------------------ Frost W. Cochran, Director, President and Chief Executive Officer Date: August 10, 2004 By: /s/ Robert W. Peshek ------------------------------------ Robert W. Peshek, Senior Vice President and Chief Financial Officer 21 EX-10.1 2 l08586aexv10w1.txt EXHIBIT 10.1 EXHIBIT 10.1 AMENDMENT NO. 3 OF THE BELDEN & BLAKE CORPORATION 1999 CHANGE IN CONTROL PROTECTION PLAN FOR KEY EMPLOYEES AMENDED EFFECTIVE APRIL 20, 2004 The Belden & Blake Corporation 1999 Change in Control Protection Plan for Key Employees, originally effective August 12, 1999, is hereby amended, effective as of April 20, 2004, by adding a new paragraph at the end of Section 3.1 to read as follows: Notwithstanding any other provision of this Plan, an Employee otherwise meeting the Eligibility criteria shall not be eligible for severance benefits hereunder if the Employee's termination is the result of the sale of less than seventy-five (75%) percent of the Company's assets, if such Employee is offered what is in the sole opinion of the Company a comparable position with the buyer of the assets as further defined in the Belden & Blake Corporation 1999 Severance Pay Plan, Amendment 2 effective September 1, 2002. All other aspects of the Plan remain unchanged and are reaffirmed. IN WITNESS WHEREOF, Belden & Blake Corporation has caused this amendment to the Plan to be executed as of the 20th day of April 2004. ATTEST: BELDEN & BLAKE CORPORATION /s/ Duane D. Clark By: /s/ John L. Schwager - ----------------------- -------------------------------------- Duane D. Clark John L. Schwager Secretary President and Chief Executive Officer EX-31.1 3 l08586aexv31w1.txt EXHIBIT 31.1 Exhibit 31.1 CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES -OXLEY ACT OF 2002 I, Frost W. Cochran, certify that: 1. I have reviewed this report on Form 10-Q of Belden & Blake Corporation; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)), for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: August 10, 2004 /s/ Frost W. Cochran ------------------------------------ Frost W. Cochran, Director, President and Chief Executive Officer 22 EX-31.2 4 l08586aexv31w2.txt EXHIBIT 31.2 Exhibit 31.2 CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES -OXLEY ACT OF 2002 I, Robert W. Peshek, certify that: 1. I have reviewed this report on Form 10-Q of Belden & Blake Corporation; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)), for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: August 10, 2004 /s/ Robert W. Peshek --------------------------------------- Robert W. Peshek, Senior Vice President and Chief Financial Officer 23 EX-32.1 5 l08586aexv32w1.txt EXHIBIT 32.1 Exhibit 32.1 CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES -OXLEY ACT OF 2002 In connection with the Quarterly Report of Belden & Blake Corporation (the "Company") on Form 10-Q for the quarterly period ended June 30, 2004, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned, in the capacities and on the dates indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the knowledge of the undersigned: 1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and 2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Date: August 10, 2004 /s/ Frost W. Cochran ------------------------------------- Frost W. Cochran, Director, President and Chief Executive Officer This certification accompanies the Form 10-Q and shall not be treated as having been filed as part of the Form 10-Q. 24 EX-32.2 6 l08586aexv32w2.txt EXHIBIT 32.2 Exhibit 32.2 CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES -OXLEY ACT OF 2002 In connection with the Quarterly Report of Belden & Blake Corporation (the "Company") on Form 10-Q for the quarterly period ended June 30, 2004, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), the undersigned, in the capacities and on the dates indicated below, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the knowledge of the undersigned: 1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and 2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Date: August 10, 2004 /s/ Robert W. Peshek --------------------------------------- Robert W. Peshek, Senior Vice President and Chief Financial Officer This certification accompanies the Form 10-Q and shall not be treated as having been filed as part of the Form 10-Q. 25 -----END PRIVACY-ENHANCED MESSAGE-----