-----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, RxYU7G0yF6SRz1VCS+LJWyyd2xzUzvoL/3MG3XMvoYl5FXYfrTNismcY7CfztPhQ k5XsKn6bKD47InKfMHwZrQ== 0000950152-02-008411.txt : 20021113 0000950152-02-008411.hdr.sgml : 20021113 20021113151956 ACCESSION NUMBER: 0000950152-02-008411 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 20020930 FILED AS OF DATE: 20021113 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: 02819733 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 l96727ae10vq.txt BELDEN & BLAKE CORPORATION 10-Q/QTR END 9-30-02 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 period ended September 30, 2002 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 As of October 31, 2002, Belden & Blake Corporation had outstanding 10,332,794 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 September 30, 2002 and December 31, 2001..................................................... 1 Consolidated Statements of Operations for the three and nine months ended September 30, 2002 and 2001 ............................. 2 Consolidated Statements of Shareholders' Equity (Deficit) for the nine months ended September 30, 2002 and the years ended December 31, 2001 and 2000............................................ 3 Consolidated Statements of Cash Flows for the nine months ended September 30, 2002 and 2001 ............................. 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................ 19 Item 4. Controls and Procedures................................................... 20 PART II Other Information Item 6. Exhibits and Reports on Form 8-K......................................... 21
BELDEN & BLAKE CORPORATION CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA)
SEPTEMBER 30, DECEMBER 31, 2002 2001 --------- --------- (UNAUDITED) ASSETS - ------ CURRENT ASSETS Cash and cash equivalents $ 1,738 $ 1,935 Accounts receivable, net 13,435 14,160 Inventories 993 1,695 Other current assets 1,847 1,094 Derivative fair value 1,103 19,965 --------- --------- TOTAL CURRENT ASSETS 19,116 38,849 PROPERTY AND EQUIPMENT, AT COST Oil and gas properties (successful efforts method) 463,784 446,977 Gas gathering systems 14,537 14,094 Land, buildings, machinery and equipment 24,739 24,113 --------- --------- 503,060 485,184 Less accumulated depreciation, depletion and amortization 248,891 233,396 --------- --------- PROPERTY AND EQUIPMENT, NET 254,169 251,788 DERIVATIVE FAIR VALUE 614 3,748 OTHER ASSETS 9,051 10,964 --------- --------- $ 282,950 $ 305,349 ========= ========= LIABILITIES AND SHAREHOLDERS' DEFICIT - ------------------------------------- CURRENT LIABILITIES Accounts payable $ 4,997 $ 5,253 Accrued expenses 24,568 14,465 Current portion of long-term liabilities 334 156 Derivative fair value 2,343 -- Deferred income taxes 59 5,470 --------- --------- TOTAL CURRENT LIABILITIES 32,301 25,344 LONG-TERM LIABILITIES Bank and other long-term debt 33,163 59,415 Senior subordinated notes 225,000 225,000 Other 116 330 --------- --------- 258,279 284,745 DERIVATIVE FAIR VALUE 1,445 -- DEFERRED INCOME TAXES 24,550 22,539 SHAREHOLDERS' DEFICIT Common stock without par value; $.10 stated value per share; authorized 58,000,000 shares; issued 10,490,440 and 10,425,103 shares (which includes 155,126 and 135,369 treasury shares, respectively) 1,034 1,029 Paid in capital 107,461 107,402 Deficit (145,630) (150,797) Accumulated other comprehensive income 3,510 15,087 --------- --------- TOTAL SHAREHOLDERS' DEFICIT (33,625) (27,279) --------- --------- $ 282,950 $ 305,349 ========= =========
See accompanying notes. 1 BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS) (UNAUDITED)
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30, ENDED SEPTEMBER 30, -------------------------- ------------------------- 2002 2001 2002 2001 -------- -------- -------- -------- REVENUES Oil and gas sales $ 23,645 $ 22,952 $ 71,334 $ 72,293 Gas gathering, marketing and oilfield service 7,474 7,421 24,192 25,652 Other 546 533 2,136 1,431 -------- -------- -------- -------- 31,665 30,906 97,662 99,376 EXPENSES Production expense 5,125 6,043 15,666 17,209 Production taxes 403 546 1,373 1,982 Gas gathering, marketing and oilfield service 6,695 6,081 20,831 22,176 Exploration expense 4,242 2,296 10,107 5,956 General and administrative expense 1,065 1,099 3,441 3,261 Franchise, property and other taxes 135 93 290 297 Depreciation, depletion and amortization 5,832 6,489 18,341 18,666 Derivative fair value (gain) loss (64) -- 134 -- Severance and other nonrecurring expense 127 312 292 1,813 -------- -------- -------- -------- 23,560 22,959 70,475 71,360 -------- -------- -------- -------- OPERATING INCOME 8,105 7,947 27,187 28,016 OTHER (INCOME) EXPENSE Interest expense 6,253 6,819 18,749 20,866 -------- -------- -------- -------- INCOME BEFORE INCOME TAXES 1,852 1,128 8,438 7,150 Provision for income taxes 709 446 3,271 614 -------- -------- -------- -------- NET INCOME $ 1,143 $ 682 $ 5,167 $ 6,536 ======== ======== ======== ========
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, 2000 10,260 $ 1,026 $107,609 $(160,225) $ -- $ (51,590) Net income 2,961 2,961 Stock options exercised 97 10 (9) 1 Stock-based compensation 336 336 Treasury stock (54) (6) (15) (21) - ------------------------------------------------- --------- --------- --------- --------- --------- ---------- DECEMBER 31, 2000 10,303 1,030 107,921 (157,264) -- (48,313) Comprehensive income: Net income 6,467 6,467 Other comprehensive income, net of tax: Cumulative effect of accounting change (6,691) (6,691) Change in derivative fair value 24,667 24,667 Reclassification adjustment for derivative (gain) loss reclassified into oil and gas sales (2,889) (2,889) -------- Total comprehensive income 21,554 -------- Stock options exercised 68 7 (1) 6 Stock-based compensation 275 275 Repurchase of stock options (772) (772) Tax benefit of repurchase of stock options and stock options exercised 260 260 Treasury stock (81) (8) (281) (289) - ------------------------------------------------- --------- --------- --------- --------- --------- ---------- DECEMBER 31, 2001 10,290 1,029 107,402 (150,797) 15,087 (27,279) Comprehensive income: Net income 5,167 5,167 Other comprehensive income, net of tax: Change in derivative fair value (434) (434) Reclassification adjustment for derivative (gain) loss reclassified into oil and gas sales (11,143) (11,143) -------- Total comprehensive income (6,410) -------- Stock options exercised 65 7 (2) 5 Stock-based compensation 62 62 Repurchase of stock options (13) (13) Tax benefit of repurchase of stock options and stock options exercised 51 51 Treasury stock (20) (2) (39) (41) - ------------------------------------------------- --------- --------- --------- --------- --------- ---------- SEPTEMBER 30, 2002 (UNAUDITED) 10,335 $ 1,034 $ 107,461 $(145,630) $ 3,510 $ (33,625) ================================================= ========= ========= ========= ========= ========= =========
See accompanying notes. 3 BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (IN THOUSANDS)
NINE MONTHS ENDED SEPTEMBER 30, ------------------------------- 2002 2001 --------- --------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 5,167 $ 6,536 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization 18,341 18,666 Loss on disposal of property and equipment 613 142 Net monetization of derivatives 22,091 -- Amortization of derivatives and other non-cash hedging adjustments (14,524) -- Exploration expense 10,107 5,956 Deferred income taxes 3,271 521 Stock-based compensation 62 379 Change in operating assets and liabilities, net of effects of acquisition and disposition of businesses: Accounts receivable and other operating assets (41) 7,371 Inventories 294 107 Accounts payable and accrued expenses 10,086 2,939 --------- --------- NET CASH PROVIDED BY OPERATING ACTIVITIES 55,467 42,617 CASH FLOWS FROM INVESTING ACTIVITIES: Acquisition of businesses, net of cash acquired (2,835) (2,130) Disposition of businesses 8,161 400 Proceeds from property and equipment disposals 1,497 1,162 Exploration expense (10,107) (5,956) Additions to property and equipment (26,508) (28,826) Decrease (increase) in other assets 749 (72) --------- --------- NET CASH USED IN INVESTING ACTIVITIES (29,043) (35,422) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from revolving line of credit 107,960 137,921 Repayment of long-term debt and other obligations (134,451) (144,367) Debt issue costs (81) (210) Proceeds from stock options exercised 5 6 Repurchase of stock options (13) (670) Purchase of treasury stock (41) (169) --------- --------- NET CASH USED IN FINANCING ACTIVITIES (26,621) (7,489) --------- --------- NET DECREASE IN CASH AND CASH EQUIVALENTS (197) (294) CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 1,935 1,798 --------- --------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 1,738 $ 1,504 ========= ========= CASH PAID DURING THE PERIOD FOR: Interest $ 13,331 $ 15,530 Income taxes, net of refunds 8 359 NON-CASH INVESTING AND FINANCING ACTIVITIES: Acquisition of assets in exchange for long-term liabilities 263 443
See accompanying notes. 4 BELDEN & BLAKE CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) SEPTEMBER 30, 2002 - -------------------------------------------------------------------------------- (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 three and nine month periods ended September 30, 2002 are not necessarily indicative of the results that may be expected for the year ended December 31, 2002. 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, 2001. Certain reclassifications have been made to conform to the current presentation. (2) NEW ACCOUNTING PRONOUNCEMENTS On January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. (SFAS) 142, "Goodwill and Other Intangible Assets" which was issued in June 2001 by the Financial Accounting Standards Board (FASB). Under SFAS 142, goodwill and indefinite lived intangible assets are no longer amortized but are reviewed for impairment annually or if certain impairment indicators arise. Separately identifiable intangible assets that are not deemed to have an indefinite life will continue to be amortized over their useful lives (but with no maximum life). At December 31, 2001, the Company had $2.7 million of unamortized goodwill which was subject to the transition provisions of SFAS 142. Amortization expense related to goodwill amounted to $130,000 and $132,000 for the years ended December 31, 2001 and 2000, respectively. The Company assessed the impact of SFAS 142 and has determined that adoption of SFAS 142 did not have a material effect on the Company's financial position, results of operations or cash flows, including any transitional impairment losses. In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement Obligations." SFAS 143 addresses obligations associated with the retirement of tangible, long-lived assets and the associated asset retirement costs. This statement amends SFAS 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies", and is effective for the Company's financial statements beginning January 1, 2003. This statement would require the Company to recognize a liability for the fair value of its plugging and abandoning liability (excluding salvage value) with the associated costs included as part of the Company's oil and gas properties balance. Due to the significant number of producing oil and gas properties operated by the Company, and the number of documents that must be reviewed and estimates that must be made to assess the effects of SFAS 143, it has not yet been determined whether adoption of SFAS 143 will have a material effect on the Company's financial position, results of operations or cash flows. In August 2001, the FASB issued SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which establishes a single accounting model to be used for long-lived assets to be disposed of. The new rules supersede SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." Although retaining many of the fundamental recognition and measurement provisions of SFAS 121, the new rules significantly change the criteria that would have 5 to be met to classify an asset as held-for-sale. This distinction is important because assets to be disposed of are stated at the lower of their fair values or carrying amounts and depreciation is no longer recognized. The new rules also supersede the provisions of Accounting Principles Board Opinion No. (APB) 30, "Reporting Results of Operations - Reporting the Effects of Disposal of a Segment of Business," with regard to reporting the effects of a disposal of a segment of a business and require the expected future operating losses from discontinued operations to be displayed in discontinued operations in the periods in which the losses are incurred rather than as of the measurement date as previously required by APB 30. In addition, more dispositions may qualify for discontinued operations treatment in the income statement. SFAS 144 was effective as of January 1, 2002. The adoption of this standard did not have a material effect on the Company's financial position, results of operations or cash flows. In April 2002, the FASB issued SFAS 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections." SFAS 145 rescinds SFAS 4, "Reporting Gains and Losses from Extinguishment of Debt," SFAS 44, "Accounting for Intangible Assets of Motor Carriers" and SFAS 64, "Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements" and amends SFAS No. 13, "Accounting for Leases". Statement 145 also makes technical corrections to other existing pronouncements. SFAS 4 required gains and losses from extinguishment of debt to be classified as an extraordinary item, net of the related income tax effect. As a result of the rescission of SFAS 4, the criteria for extraordinary items in APB Opinion No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions," now will be used to classify those gains and losses. SFAS 145 is effective for the Company's financial statements beginning January 1, 2003. The adoption of SFAS 145 is not expected to have a material effect on the Company's financial position, results of operations or cash flows. In July 2002, the FASB issued SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS 146 will be effective for the Company for disposal activities initiated after December 31, 2002. The adoption of this standard is not expected to have a material effect on the Company's financial position, results of operations or cash flows. (3) 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. 6 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 September 30, 2002, the Company's derivative contracts were comprised of natural gas swaps and natural gas collars. Qualifying NYMEX based derivative contracts are designated as cash flow hedges. During the first nine months of 2002 and 2001, a net gain of $17.5 million ($11.1 million after tax) and a net loss of $1.0 million ($743,000 after tax), respectively, were reclassified from accumulated other comprehensive income to earnings. The fair value of open hedges decreased $682,000 ($434,000 after tax) in the first nine months of 2002 and increased $37.5 million ($23.2 million after tax) in the first nine months of 2001. At September 30, 2002, the estimated net gain in accumulated other comprehensive income that is expected to be reclassified into earnings within the next 12 months is approximately $5.8 million. The Company has partially hedged its exposure to the variability in future cash flows through March 2005. On January 17 and 18, 2002, the Company monetized 9,350 Bbtu (billion British thermal units) of its 2002 natural gas hedge position at a weighted average NYMEX price of $2.53 per Mmbtu (million British thermal units) and 3,840 Bbtu of its 2003 natural gas hedge position at a NYMEX price of $3.01 per Mmbtu. The Company received net proceeds of $22.7 million that are recognized as increases to natural gas sales revenues during the same periods in which the underlying forecasted transactions are recognized in net income (loss). In January 2002, the Company entered into a collar for 9,350 Bbtu of its natural gas production in 2002 with a ceiling price of $4.00 per Mmbtu and a floor price of $2.25 per Mmbtu which qualified and was designated as a cash flow hedge under SFAS 133. The Company also sold a floor at $1.75 per Mmbtu on this volume of gas which was designated as a non-qualifying cash flow hedge under SFAS 133. The changes in fair value of the $1.75 floor will be initially reported in expense in the consolidated statements of operations as derivative fair value (gain) loss and will ultimately be reversed within the same line item and included in oil and gas sales over the respective contract terms. This aggregate structure has the effect of: 1) setting a maximum price of $4.00 per Mmbtu; 2) floating at prices from $2.25 to $4.00 per Mmbtu; 3) locking in a price of $2.25 per Mmbtu if prices are between $1.75 and $2.25 per Mmbtu; and 4) receiving a price of $0.50 per Mmbtu above the price if the price is $1.75 or less. All prices are based on monthly NYMEX settle. The Company paid $1.0 million for the options. The Company used the net proceeds of $21.7 million from the two transactions above to pay down on its credit facility. From August 30, 2002 through September 20, 2002, the Company placed additional hedge positions covering 16,860 Bbtu of its natural gas production for the period from October 2002 through March 2005. The hedges are in the form of swaps based on a NYMEX equivalent weighted average price of $3.88 per Mmbtu. 7 The following table summarizes, as of September 30, 2002, the Company's net deferred gains on terminated natural gas hedges. Cash has been received and the deferred gains recorded in accumulated other comprehensive income. The deferred gains are recognized as increases to gas sales revenues during the periods in which the underlying forecasted transactions are recognized in net income (loss).
2002 2003 -------------------------------------------- ------- FIRST SECOND THIRD FOURTH QUARTER QUARTER QUARTER QUARTER ------- ------- ------- ------- (IN THOUSANDS) Deferred Gains $ 4,521 $ 5,599 $ 5,495 $ 4,631 $ 2,851
(4) ACQUISITIONS On July 11, 2002, the Company acquired 77 gross (71.7 net) wells located in Ohio and Pennsylvania with net reserves totaling 4.2 Bcfe (billion cubic feet of natural gas equivalent) for a cash payment of $1.2 million. (5) DISPOSITIONS On August 1, 2002, the Company sold oil and gas properties consisting of 1,138 wells in Ohio. The properties had reserves of approximately 12 Bcfe. The proceeds of approximately $8.0 million were used to pay down the Company's revolving credit facility. On September 5, 2002, the Company completed the sale of three natural gas compressors in Michigan to a compression services company. The proceeds of approximately $1.2 million were used to pay down the Company's revolving credit facility. The Company also entered into an agreement to leaseback the compressors from the compression services company, which will provide full compression services including maintenance and repair on these and other compressors. Certain compressors will also be relocated to maximize compression efficiency. The Company plans to sell and leaseback additional compression units during the fourth quarter. (6) CREDIT AGREEMENT On July 25, 2002, the Company amended its $100 million revolving credit facility ("the Revolver"). The amendment extended the Revolver's final maturity date to April 22, 2005, from April 22, 2004 and permitted the Company to enter into the transaction to sell, transfer and assign oil and gas properties consisting of 1,138 wells in Ohio. The Revolver, as amended, is subject to certain financial covenants. These include a quarterly senior debt interest coverage ratio of 3.2 to 1 through March 31, 2005; and a senior debt leverage ratio of 2.7 to 1 through March 31, 2005. The amendment extended the early termination fee, equal to .125% of the Revolver, through November 30, 2003. There is no termination fee after November 30, 2003. (7) SETTLEMENT AGREEMENT In April 2002, the Company and one of its gas purchasers signed a settlement agreement resolving gas measurement disputes related to a gathering system in New York. Under the terms of the agreement, the Company received a cash payment to settle all issues associated with gas measurement disputes prior to December 31, 2001. The agreement also amended a prior agreement that governed the measurement of the Company's gas supply delivered into the purchaser's distribution system. The Company's net share of the settlement amount, $591,000, was recorded in the second quarter of 2002 as other revenue. 8 (8) COMMITMENTS AND CONTINGENCIES In April 2002, the Company was notified of a claim by an overriding royalty interest owner in Michigan alleging the underpayment of royalty resulting from disputes as to the interpretation of the terms of several farmout agreements. The Company believes the claim is without merit and will vigorously defend its position. The Company believes that the result of this issue will not have a material adverse effect on its financial position, results of operation or cash flows. (9) 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. (10) SUBSEQUENT EVENTS On October 10, 2002, the Company combined its Pennsylvania/New York District with its Ohio District to form a new "Appalachian District". A total of 28 positions were eliminated in the Ohio and Pennsylvania/New York Districts and in the corporate office. These actions were necessary to capitalize on operational and administrative efficiencies and bring the Company's employment level in line with current and anticipated future staffing. The Company expects to record a nonrecurring charge of approximately $700,000 in the fourth quarter of 2002 related to severance and other costs associated with these actions. The Company expects to reduce its future expenses by approximately $1.7 million annually beginning in the fourth quarter of 2002 as a result of the combined district and staff reductions. Subsequent to September 30, 2002, the Company has classified $18 million of oil and gas properties and acreage as assets held-for-sale in property and equipment. 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," 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 9 Consolidated Financial Statements" included in "Item 8. Financial Statements and Supplementary Data" in the Company's 2001 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, 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, these non-productive 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 is based on estimates it prepared. Estimates prepared by others may be higher or lower than the Company's estimates. The Company's estimates of proved reserves have been reviewed by independent petroleum engineers. 10 CAPITALIZATION, DEPRECIATION, DEPLETION AND IMPAIRMENT OF LONG-LIVED ASSETS See the "Successful Efforts Method of Accounting" discussion above. Capitalized costs related to proved properties are depleted using the unit-of-production method. Depreciation, depletion and amortization of proved oil and gas properties is calculated on the basis of estimated recoverable reserve quantities. These estimates can change based on economic or other factors. No gains or losses are recognized upon the disposition of oil and gas properties except in extraordinary transactions. Sales proceeds are credited to the carrying value of the properties. Maintenance and repairs are expensed, and expenditures which enhance the value of properties are capitalized. Unproved oil and gas properties are stated at cost and consist of undeveloped leases. These costs are assessed periodically to determine whether their value has been impaired, and if impairment is indicated, the costs are charged to expense. Gas gathering systems are stated at cost. Depreciation expense is computed using the straight-line method over 15 years. Property and equipment are stated at cost. Depreciation of non-oil and gas properties is computed using the straight-line method over the useful lives of the assets ranging from 3 to 15 years for machinery and equipment and 30 to 40 years for buildings. When assets other than oil and gas properties are retired or otherwise disposed of, the cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is reflected in income for the period. The cost of maintenance and repairs is expensed as incurred, and significant renewals and betterments are capitalized. Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. If the sum of the expected future undiscounted cash flows is less than the carrying amount of the asset, a loss is recognized for the difference between the fair value and the carrying amount of the asset. Fair value is 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. 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. 11 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 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. Qualifying NYMEX based derivative contracts are designated as cash flow hedges. 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 services have been provided. DISCLOSURE CONTROLS AND PROCEDURES Disclosure controls and procedures are controls and other procedures of the Company that are designed to ensure that information required to be disclosed by the Company in the reports filed or submitted by the Company under the Securities Exchange Act of 1934 ("Exchange Act") is recorded, processed, summarized and reported, within the time periods specified in the SEC's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by the Company in its Exchange Act reports is accumulated and communicated to the Company's management, including its principal executive and financial officers, as appropriate to allow timely decisions regarding required disclosures. NEW ACCOUNTING PRONOUNCEMENTS On January 1, 2002, the Company adopted SFAS 142, "Goodwill and Other Intangible Assets" which was issued in June 2001 by the FASB. Under SFAS 142, goodwill and indefinite lived intangible assets are no longer amortized but are reviewed for impairment annually or if certain impairment indicators arise. Separately identifiable assets that are not deemed to have an indefinite life will continue to be amortized over their useful lives (but with no maximum life). At December 31, 2001, the Company had $2.7 million of unamortized goodwill which was subject to the transition provisions of SFAS 142. Amortization expense related to goodwill amounted to $130,000 and $132,000 for the years ended December 31, 2001 and 2000, respectively. The Company assessed the impact of SFAS 142 and has determined that adoption of SFAS 142 did not have a material effect on the Company's financial position, results of operations or cash flows, including any transitional impairment losses. In June 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement Obligations." SFAS 143 addresses obligations associated with the retirement of tangible, long-lived assets and the associated asset retirement costs. This statement amends SFAS 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies", and is effective for the Company's financial statements beginning January 1, 2003. This statement would require the Company to recognize a liability for the fair value of its plugging and abandoning liability (excluding salvage value) with the associated costs included as part of the Company's oil and gas properties balance. Due to the significant number of producing oil and gas properties operated by the Company, and the number of documents that must be reviewed and estimates that must be made to assess the effects of SFAS 143, it has not yet been determined whether adoption of SFAS 143 will have a material effect on the Company's financial position, results of operations or cash flows. 12 In August 2001, the FASB issued SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which establishes a single accounting model to be used for long-lived assets to be disposed of. The new rules supersede SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." Although retaining many of the fundamental recognition and measurement provisions of SFAS 121, the new rules significantly change the criteria that would have to be met to classify an asset as held-for-sale. This distinction is important because assets to be disposed of are stated at the lower of their fair values or carrying amounts and depreciation is no longer recognized. The new rules also supersede the provisions of APB 30, "Reporting Results of Operations - Reporting the Effects of Disposal of a Segment of Business," with regard to reporting the effects of a disposal of a segment of a business and require the expected future operating losses from discontinued operations to be displayed in discontinued operations in the periods in which the losses are incurred rather than as of the measurement date as previously required by APB 30. In addition, more dispositions may qualify for discontinued operations treatment in the income statement. SFAS 144 was effective as of January 1, 2002. The adoption of this standard did not have a material effect on the Company's financial position, results of operations or cash flows. In April 2002, the FASB issued SFAS 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections." SFAS 145 rescinds SFAS 4, "Reporting Gains and Losses from Extinguishment of Debt," SFAS 44, "Accounting for Intangible Assets of Motor Carriers" and SFAS 64, "Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements" and amends SFAS No. 13, "Accounting for Leases". Statement 145 also makes technical corrections to other existing pronouncements. SFAS 4 required gains and losses from extinguishment of debt to be classified as an extraordinary item, net of the related income tax effect. As a result of the rescission of SFAS 4, the criteria for extraordinary items in APB Opinion No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions," now will be used to classify those gains and losses. SFAS 145 is effective for the Company's financial statements beginning January 1, 2003. The adoption of SFAS 145 is not expected to have a material effect on the Company's financial position, results of operations or cash flows. In July 2002, the FASB issued SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS 146 will be effective for the Company for disposal activities initiated after December 31, 2002. The adoption of this standard is not expected to have a material effect on the Company's financial position, results of operations or cash flows. 13 RESULTS OF OPERATIONS - THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2002 AND 2001 COMPARED The following table sets forth certain information regarding the Company's net oil and natural gas production, revenues and expenses for the quarters indicated:
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------- ------------- 2002 2001 2002 2001 ------- ------- ------- ------- PRODUCTION Gas (Mmcf) 4,291 4,680 13,238 13,713 Oil (Mbbls) 139 173 431 490 Total production (Mmcfe) 5,126 5,717 15,822 16,653 AVERAGE PRICE Gas (per Mcf) $ 4.70 $ 4.03 $ 4.67 $ 4.39 Oil (per Bbl) 24.91 23.55 22.20 24.74 Mcfe 4.61 4.01 4.51 4.34 AVERAGE COSTS (PER Mcfe) Production expense 1.00 1.06 0.99 1.03 Production taxes 0.08 0.10 0.09 0.12 Depletion 0.86 0.86 0.88 0.79 OPERATING MARGIN (PER Mcfe) 3.53 2.85 3.43 3.19
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 - THIRD QUARTERS OF 2002 AND 2001 COMPARED Operating income increased $158,000 (2%) from $7.9 million in the third quarter of 2001 to $8.1 million in the third quarter of 2002. This increase was primarily a result of a $1.2 million (7%) increase in operating margins; a $657,000 decrease in depreciation, depletion and amortization; and a $185,000 decrease in severance and other nonrecurring expense offset by a $1.9 million increase in exploration expense. Net income increased $461,000 from $682,000 in the third quarter of 2001 to $1.1 million in the third quarter of 2002. This increase was a result of a $566,000 decrease in interest expense and the increase in operating income discussed above offset by a $263,000 increase in the provision for income taxes. The increase in the provision for income taxes was primarily due to the increase in income before income taxes. The $1.2 million increase in operating margins was primarily due to a $1.8 million increase in the operating margin from oil and gas sales offset by a $561,000 decrease in the operating margin from gas gathering, marketing and oilfield services. The increase in the operating margin from oil and gas sales was due to an increase in the average prices realized for the Company's oil and natural gas and a $918,000 decrease in production expense partially offset by lower oil and gas volumes. The decrease in the operating margin from gas gathering, marketing and oilfield services was primarily due to a decrease in gas gathering revenue in Pennsylvania. Earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; derivative fair value loss (gain); and severance and other nonrecurring items ("EBITDAX") increased $1.2 million (7%) from $17.0 million in the third quarter of 2001 to $18.2 million in the third quarter of 2002 primarily due to the increased operating margins discussed above. 14 Total revenues increased $759,000 (2%) in the third quarter of 2002 compared to the third quarter of 2001 primarily due to an increase in the average prices realized for the Company's oil and natural gas partially offset by lower oil and gas volumes. Gas volumes sold decreased approximately 389 Mmcf (8%) from 4.7 Bcf (billion cubic feet) in the third quarter of 2001 to 4.3 Bcf in the third quarter of 2002. The decrease in gas volumes sold resulted in a decrease in gas sales revenues of approximately $1.6 million. Oil volumes sold decreased approximately 34,000 Bbls (19%) from 173,000 Bbls in the third quarter of 2001 to 139,000 Bbls in the third quarter of 2002 which resulted in a decrease in oil sales revenues of approximately $790,000. The decrease in oil and gas volumes sold was primarily due to the sale of wells in Ohio in the first and third quarters of 2002 and natural production declines partially offset by a reduction in oil inventory in the third quarter of 2002. The average price realized for the Company's natural gas increased $0.67 per Mcf to $4.70 per Mcf in the third quarter of 2002 compared to the third quarter of 2001 which increased gas sales revenues in the third quarter of 2002 by approximately $2.9 million. As a result of the Company's hedging activities, gas sales revenues for the third quarter of 2002 increased by approximately $5.3 million or $1.23 per Mcf compared to an increase of approximately $3.2 million or $0.67 per Mcf for the third quarter of 2001. The average price realized for the Company's oil increased from $23.55 per Bbl in the third quarter of 2001 to $24.91 per Bbl in the third quarter of 2002 which increased oil sales revenues by approximately $189,000. Production expense decreased $918,000 (15%) from $6.0 million in the third quarter of 2001 to $5.1 million in the third quarter of 2002. The average production cost decreased from $1.06 per Mcfe in the third quarter of 2001 to $1.00 per Mcfe in the third quarter of 2002. These decreases were primarily due to decreased compensation related expenses as a result of staff reductions in 2002. Production taxes decreased $143,000 from $546,000 in the third quarter of 2001 to $403,000 in the third quarter of 2002. Average per unit production taxes decreased from $0.10 per Mcfe in the third quarter of 2001 to $0.08 per Mcfe in the third quarter of 2002. The decreases in production taxes were primarily due to lower oil and gas sales volumes and the sale of wells in Ohio during 2002. Exploration expense increased $1.9 million (85%) from $2.3 million in the third quarter of 2001 to $4.2 million in the third quarter of 2002 primarily due to increases in leasing activity associated with the Company's planned future drilling activity, a $898,000 increase in dry hole expense and $413,000 associated with the expiration of a farm-in agreement in the third quarter of 2002. General and administrative expense of $1.1 million in the third quarter of 2002 was consistent compared to the third quarter of 2001. Depreciation, depletion and amortization decreased $657,000 (10%) from $6.5 million in the third quarter of 2001 to $5.8 million in the third quarter of 2002. Depletion expense decreased $524,000 (11%) from $4.9 million in the third quarter of 2001 to $4.4 million in the third quarter of 2002 due to the decreased oil and gas sales volumes discussed above. Depletion was $0.86 per Mcfe in the third quarter of 2001 and the third quarter of 2002. Interest expense decreased $566,000 (8%) from $6.8 million in the third quarter of 2001 to $6.3 million in the third quarter of 2002 due to a decrease in average outstanding borrowings and lower blended interest rates. 15 RESULTS OF OPERATIONS - NINE MONTHS OF 2002 AND 2001 COMPARED Operating income decreased $829,000 (3%) from $28.0 million in the first nine months of 2001 to $27.2 million in the first nine months of 2002. This decrease was primarily a result of a $4.1 million increase in exploration expense partially offset by a $1.5 million decrease in severance and other nonrecurring expense, a $1.1 million increase in operating margins and a $705,000 increase in other revenue. The increase in other revenue was primarily due to the settlement of a gas measurement dispute with one of the Company's gas purchasers related to a gathering system in New York. See Note 7 to the Consolidated Financial Statements. Net income decreased $1.3 million from $6.5 million in the first nine months of 2001 to $5.2 million in the first nine months of 2002. This decrease was a result of the decrease in operating income discussed above and a $2.7 million increase in the provision for income taxes partially offset by a $2.2 million decrease in interest expense. The increase in the provision for income taxes was due to the increase in income before income taxes and federal income tax benefits recorded in the second quarter of 2001. A federal income tax benefit of $1.5 million was recorded during the second quarter of 2001 due to the conclusion of an IRS income tax examination for the years 1994 through 1997. Also, in the second quarter of 2001, a federal income tax benefit was recorded for approximately $700,000 along with a corresponding reduction in the valuation allowance as a result of certain net operating loss carryforwards which the Company believes it can fully utilize. Operating margins in the first nine months of 2002 increased $1.1 million compared to the operating margins in the first nine months of 2001. The operating margin from oil and gas sales increased $1.2 million primarily due to an increase in the average price realized for the Company's natural gas and decreases in production expense and production taxes offset by decreases in the volumes of oil and natural gas sold and a decrease in the average price realized for the Company's oil. The increase in the margin from oil and gas sales was partially offset by a $115,000 decrease in the operating margin from gas gathering, marketing and oilfield services. EBITDAX increased $1.6 million (3%) from $54.5 million in the first nine months of 2001 to $56.1 million in the first nine months of 2002 primarily due to the increased operating margins discussed above and the increase in other revenue discussed above. Total revenues decreased $1.7 million (2%) in the first nine months of 2002 compared to the first nine months of 2001 primarily due to a decrease in the volumes of oil and natural gas sold, a decrease in the average price realized for the Company's oil and a decrease in gas gathering, marketing and oilfield services revenue. These decreases were partially offset by an increase in the average price realized for the Company's natural gas and the increase in other revenue discussed above. Gas volumes sold decreased approximately 475 Mmcf (3%) from 13.7 Bcf in the first nine months of 2001 to 13.2 Bcf in the first nine months of 2002. The decrease in gas volumes sold resulted in a decrease in gas sales revenues of approximately $2.1 million. Oil volumes sold decreased 59,000 Bbls (12%) from 490,000 Bbls in the first nine months of 2001 to 431,000 Bbls in the first nine months of 2002. The decrease in oil volumes sold resulted in a decrease in oil sales revenues of approximately $1.5 million. The decreases in oil and gas volumes were primarily due to the sale of wells in Ohio during the first and third quarters of 2002 and natural production declines partially offset by a reduction in oil inventory in the third quarter of 2002. The average price realized for the Company's natural gas increased $0.28 per Mcf to $4.67 per Mcf in the first nine months of 2002 compared to the first nine months of 2001 which increased gas sales revenues in the first nine months of 2002 by approximately $3.7 million. As a result of the Company's 16 hedging activities, gas sales revenues for the first nine months of 2002 increased by approximately $17.2 million or $1.30 per Mcf compared to a decrease of approximately $1.0 million or $0.07 per Mcf for the first nine months of 2001. The average price realized for the Company's oil decreased from $24.74 per Bbl in the first nine months of 2001 to $22.20 per Bbl in the first nine months of 2002 which decreased oil sales revenues by approximately $1.1 million. Production expense decreased $1.5 million (9%) from $17.2 million in the first nine months of 2001 to $15.7 million in the first nine months of 2002. The average production cost decreased from $1.03 per Mcfe in the first nine months of 2001 to $0.99 per Mcfe in the first nine months of 2002. These decreases were primarily due to decreased compensation related expenses as a result of staff reductions in 2002. Production taxes decreased $609,000 from $2.0 million in the first nine months of 2001 to $1.4 million in the first nine months of 2002. Average per unit production taxes decreased from $0.12 per Mcfe in the first nine months of 2001 to $0.09 per Mcfe in the first nine months of 2002. The decreases in production taxes are primarily due to lower oil and gas sales volumes in Michigan coupled with lower oil and gas prices in Michigan, where production taxes are based on a percentage of revenues. Exploration expense increased $4.1 million (70%) from $6.0 million in the first nine months of 2001 to $10.1 million in the first nine months of 2002 primarily due to increases in leasing activity and geophysical expenses associated with the Company's planned future drilling activity, a $1.8 million increase in dry hole expense and $413,000 associated with the expiration of a farm-in agreement in the third quarter of 2002. General and administrative expense increased $180,000 (6%) from $3.3 million in the first nine months of 2001 to $3.4 million in the first nine months of 2002 primarily due to increases in compensation related expenses. Depreciation, depletion and amortization decreased by $325,000 (2%) from $18.7 million in the first nine months of 2001 to $18.3 million in the first nine months of 2002. This decrease was primarily due to a $579,000 reduction in amortization of loan costs from the extension of the Revolver's final maturity date, a $424,000 reduction in the amortization of nonconventional fuel source tax credits in 2002 and a $173,000 reduction in amortization of non-compete covenants due to expiration of the covenants in 2001 partially offset by an increase in depletion expense. Depletion expense increased $728,000 (6%) from $13.2 million in the first nine months of 2001 to $13.9 million in the first nine months of 2002. Depletion per Mcfe increased from $0.79 per Mcfe in the first nine months of 2001 to $0.88 per Mcfe in the first nine months of 2002. These increases were primarily the result of a higher depletion rate per Mcfe due to lower reserves resulting from lower oil and gas prices at year-end 2001, excluding the effect of hedging. Severance and other nonrecurring expense decreased by $1.5 million from $1.8 million in the first nine months of 2001 to $292,000 in the first nine months of 2002 primarily due to costs associated with the early retirement of certain senior management members of the Company and other severance charges incurred in the first nine months of 2001. Interest expense decreased $2.2 million (10%) from $20.9 million in the first nine months of 2001 to $18.7 million in the first nine months of 2002 due to a decrease in average outstanding borrowings and lower blended interest rates. 17 LIQUIDITY AND CAPITAL RESOURCES 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 current ratio at September 30, 2002 was .59 to 1. During the first nine months of 2002, working capital decreased $26.7 million from $13.5 million at December 31, 2001 to a deficit of $13.2 million at September 30, 2002. The decrease was primarily due to a $21.2 million decrease in the fair value of derivatives in the first nine months of 2002, primarily as a result of the Company's monetization of derivatives in January 2002 and a $10.1 million increase in accrued expenses partially offset by a $5.4 million decrease in the current deferred tax liability. The Company's operating activities provided cash flows of $55.5 million during the first nine months of 2002. On July 25, 2002, the Company amended its $100 million Revolver. The amendment extended the Revolver's final maturity date to April 22, 2005, from April 22, 2004 and permitted the Company to enter into the transaction to sell, transfer and assign oil and gas properties consisting of 1,138 wells in Ohio. The Revolver bears interest at the prime rate plus two percentage points, payable monthly. At September 30, 2002, the interest rate was 6.75%. Up to $30 million in letters of credit may be issued pursuant to the Revolver. At September 30, 2002, the Company had $10.8 million of outstanding letters of credit. At September 30, 2002, the outstanding balance under the credit agreement was $33.1 million with $56.1 million of borrowing capacity available for general corporate purposes. The Revolver, as amended, has an early termination fee equal to .125% of the facility if termination is on or before November 30, 2003. There is no termination fee after November 30, 2003. The Company is required to hedge at least 20% but not more than 80% of its estimated hydrocarbon production, on an Mcfe basis, for the succeeding 12 months on a rolling 12 month basis. Based on the Company's hedges in place at September 30, 2002, and its expected production levels, the Company is in compliance with this hedging requirement through March 2005. The Revolver is secured by security interests and mortgages against substantially all of the Company's assets and is subject to periodic borrowing base determinations. The borrowing base is the lesser of $100 million or the sum of (i) 65% of the present value of the Company's proved developed producing reserves subject to a mortgage; (ii) 45% of the present value of the Company's proved developed non-producing reserves subject to a mortgage; and (iii) 40% of the present value of the Company's proved undeveloped reserves subject to a mortgage. The price forecast used for calculation of the future net income from proved reserves is the three-year NYMEX strip for oil and natural gas as of the date of the reserve report. Prices beyond three years are held constant. Prices are adjusted for basis differential, fixed price contracts and financial hedges in place. The present value (using a 10% discount rate) of the Company's future net income at September 30, 2002, under the borrowing base formula above was approximately $233.4 million for all proved reserves of the Company and $163.2 million for properties secured by a mortgage. The Revolver, as amended, is subject to certain financial covenants. These include a quarterly senior debt interest coverage ratio of 3.2 to 1 through March 31, 2005; and a senior debt leverage ratio of 2.7 to 1 through March 31, 2005. EBITDA, as defined in the Revolver, and consolidated interest expense on senior debt in these ratios are calculated quarterly based on the financial results of the previous four quarters. In addition, the Company is required to maintain a current ratio (including available borrowing capacity in current assets, excluding current debt and accrued interest from current liabilities and excluding any effects from the application of SFAS 133 to other current assets or current liabilities) of at 18 least 1.0 to 1 and maintain liquidity of at least $5 million (cash and cash equivalents including available borrowing capacity). As of September 30, 2002, the Company's current ratio including the above adjustments was 3.24 to 1. The Company had satisfied all financial covenants as of September 30, 2002. 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 nine months of 2002 or 2001. During the first nine months of 2002, the Company invested $19.7 million, including $2.4 million of exploratory dry hole expense, to drill 81 development wells and 13 exploratory wells, five of which tested the Trenton Black River ("TBR") formation. Of these wells, 78 development wells and three exploratory wells were completed as producing wells. The status of three other exploratory TBR wells has not yet been determined. Two of these exploratory TBR wells were completed in the target formation and are currently being evaluated. The other exploratory TBR well, which was dry in the target formation, was completed in an uphole formation and is currently being evaluated. The total cost of these three wells through September 30, 2002 was approximately $2.2 million. Through September 30, 2002, drilling and other capital expenditures, including exploratory dry hole expense, totaled approximately $29.3 million, excluding acquisitions. The Company currently expects to spend approximately $37 million during 2002 on its drilling activities, including exploratory dry hole expense, and other capital expenditures. The Company intends to finance its planned capital expenditures through its available cash flow, available revolving credit line, the sale of participating interests in its exploratory Trenton Black River prospect areas and the sale of non-strategic assets. At September 30, 2002, the Company had approximately $56.1 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. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 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 a net pretax gain on its hedging activities of $17.2 million in the first nine months of 2002 and a net pretax loss of $1.0 million in the first nine months of 2001. 19 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 or terminating existing contracts. The following table reflects the natural gas volumes and the weighted average prices under financial hedges (including settled hedges) and fixed price contracts at September 30, 2002:
NATURAL GAS COLLARS FIXED PRICE CONTRACTS --------------------------------------------------------------- ---------------------- MONTHLY NYMEX SETTLE OF $1.75 MONTHLY NYMEX SETTLE OR HIGHER LOWER THAN $1.75 ----------------------------- -------------------- ESTIMATED ESTIMATED NYMEX PRICE ESTIMATED NYMEX WELLHEAD WELLHEAD PER MMBTU WELLHEAD PRICE PRICE PER PRICE PER ESTIMATED PRICE PER QUARTER ENDING BBTU FLOOR/CAP PER MCF MMBTU MCF MMCF MCF - -------------- ---- ----------- -------------- ---------- --------- ---------- --------- December 31, 2002 2,130 $ 2.25 - 4.00 $ 2.47 - 4.22 Monthly Monthly 830 $ 4.12 ------ --------------- -------------- NYMEX NYMEX ----- -------- 2,130 $ 2.25 - 4.00 $ 2.47 - 4.22 settle plus settle plus 830 $ 4.12 ====== =============== ============== $0.50 $0.65 to ===== ======== $0.75 March 31, 2003 1,650 $ 3.40 - 5.23 $ 3.65 - 5.48 180 $ 3.48 June 30, 2003 1,650 3.40 - 5.23 3.55 - 5.38 110 3.12 September 30, 2003 1,650 3.40 - 5.23 3.55 - 5.38 75 2.68 December 31, 2003 1,650 3.40 - 5.23 3.62 - 5.45 70 2.59 ------ --------------- -------------- ----- -------- 6,600 $ 3.40 - 5.23 $ 3.59 - 5.42 435 $ 3.11 ====== =============== ============== ===== ========
NATURAL GAS SWAPS -------------------------------------------- ESTIMATED NYMEX PRICE WELLHEAD PRICE QUARTER ENDING BBTU PER MMBTU PER MCF - -------------- ---- --------- ------- December 31, 2002 800 $ 3.82 $ 4.00 ----- -------- ------- 800 $ 3.82 $ 4.00 ===== ======== ======= March 31, 2003 1,800 $ 3.92 $ 4.17 June 30, 2003 1,800 3.92 4.07 September 30, 2003 1,800 3.92 4.07 December 31, 2003 1,800 3.92 4.14 ----- -------- ------- 7,200 $ 3.92 $ 4.12 ===== ======== ======= March 31, 2004 2,040 $ 3.84 $ 4.09 June 30, 2004 2,040 3.84 3.99 September 30, 2004 2,040 3.84 3.99 December 31, 2004 2,040 3.84 4.06 ----- -------- ------- 8,160 $ 3.84 $ 4.03 ===== ======== ======= March 31, 2005 1,050 $ 3.87 $ 4.12 ----- -------- ------- 1,050 $ 3.87 $ 4.12 ===== ======== =======
ITEM 4. CONTROLS AND PROCEDURES DISCLOSURE CONTROLS AND PROCEDURES The Company, under the supervision of the principal executive and financial officers, has conducted an evaluation of the effectiveness of the design and operation of the Company's disclosure controls and procedures within 90 days of the filing date of this report. Based on the Company's 20 evaluation, the disclosure controls and procedures in place are effective in ensuring that information required to be disclosed by the Company in its Exchange Act reports is accumulated and communicated to the Company's management, including its principal executive and financial officers, as appropriate, to allow timely decisions regarding required disclosures. CHANGES IN INTERNAL CONTROLS There were no significant changes in the Company's internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. - -------------------------------------------------------------------------------- PART II OTHER INFORMATION Item 6. Exhibits and Reports on Form 8-K (a) Exhibits 99.1 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 99.2 Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (b) Reports on Form 8-K On August 20, 2002, the Company filed a Current Report on Form 8-K dated August 15, 2002, reporting under Item 9 the Company's operational outlook for 2002. On September 13, 2002, the Company filed a Current Report on Form 8-K dated August 30, 2002, reporting under Item 9 the Company's natural gas hedging position. On September 24, 2002, the Company filed a Current Report on Form 8-K dated September 18, 2002, reporting under Item 9 the Company's natural gas hedging position. 21 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: November 12, 2002 By: /s/ John L. Schwager ---------------------- ------------------------------ John L. Schwager, Director, President and Chief Executive Officer Date: November 12, 2002 By: /s/ Robert W. Peshek ---------------------- ------------------------------ Robert W. Peshek, Vice President and Chief Financial Officer 22 CERTIFICATIONS - -------------------------------------------------------------------------------- I, John L. Schwager, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Belden & Blake Corporation; 2. Based on my knowledge, this quarterly 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 quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly 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 quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures 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 quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 12, 2002 /s/ John L. Schwager ---------------------- ----------------------------------- John L. Schwager, Director, President and Chief Executive Officer 23 CERTIFICATIONS - -------------------------------------------------------------------------------- I, Robert W. Peshek, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Belden & Blake Corporation; 2. Based on my knowledge, this quarterly 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 quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly 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 quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures 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 quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 12, 2002 /s/ Robert W. Peshek ---------------------- ------------------------------------ Robert W. Peshek, Vice President and Chief Financial Officer 24 EX-99.1 3 l96727aexv99w1.txt EXHIBIT 99.1 Exhibit 99.1 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 September 30, 2002, 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: November 12, 2002 /s/ John L. Schwager ---------------------- ------------------------------------ John L. Schwager, Director, President and Chief Executive Officer 25 EX-99.2 4 l96727aexv99w2.txt EXHIBIT 99.2 Exhibit 99.2 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 September 30, 2002, 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: 3. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and 4. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Date: November 12, 2002 /s/ Robert W. Peshek ---------------------- ------------------------------------ Robert W. Peshek, Vice President and Chief Financial Officer 26 -----END PRIVACY-ENHANCED MESSAGE-----