-----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, VAFhzDpGvMmpMOkTciS+Gc2EeDuPrA+iVRPX5cEeymuSJHXp2gVP63yBCsExlrsI eXSasc3J0s+k3gPn/ehzwg== 0000950152-03-009612.txt : 20031112 0000950152-03-009612.hdr.sgml : 20031112 20031112173005 ACCESSION NUMBER: 0000950152-03-009612 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 20030930 FILED AS OF DATE: 20031112 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: 03995096 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 l03420ae10vq.txt BELDEN & BLAKE CORPORATION 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 September 30, 2003 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 October 31, 2003, Belden & Blake Corporation had outstanding 10,393,000 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, 2003 and December 31, 2002................................................................ 1 Consolidated Statements of Operations for the three and nine months ended September 30, 2003 and 2002 ........................................ 2 Consolidated Statements of Shareholders' Equity (Deficit) for the nine months ended September 30, 2003 and the years ended December 31, 2002 and 2001........................................... 3 Consolidated Statements of Cash Flows for the nine months ended September 30, 2003 and 2002 ........................................ 4 Notes to Consolidated Financial Statements.......................................... 5 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.............................................. 10 Item 3. Quantitative and Qualitative Disclosures About Market Risk.......................... 23 Item 4. Controls and Procedures............................................................. 25 PART II Other Information Item 6. Exhibits and Reports on Form 8-K.................................................... 25
BELDEN & BLAKE CORPORATION CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA)
SEPTEMBER 30, DECEMBER 31, 2003 2002 ------------- ------------ (UNAUDITED) ASSETS CURRENT ASSETS Cash and cash equivalents $ 991 $ 1,722 Accounts receivable, net 17,970 14,652 Inventories 717 848 Deferred income taxes 6,162 4,200 Other current assets 2,039 1,341 Fair value of derivatives 13 -- Assets of discontinued operations -- 1,066 --------- --------- TOTAL CURRENT ASSETS 27,892 23,829 PROPERTY AND EQUIPMENT, AT COST Oil and gas properties (successful efforts method) 466,848 438,240 Gas gathering systems 14,750 14,482 Land, buildings, machinery and equipment 23,829 22,748 --------- --------- 505,427 475,470 Less accumulated depreciation, depletion and amortization 250,814 243,596 --------- --------- PROPERTY AND EQUIPMENT, NET 254,613 231,874 FAIR VALUE OF DERIVATIVES 807 3 OTHER ASSETS 7,463 8,139 --------- --------- $ 290,775 $ 263,845 ========= ========= LIABILITIES AND SHAREHOLDERS' DEFICIT CURRENT LIABILITIES Accounts payable $ 5,742 $ 5,661 Accrued expenses 22,273 17,767 Current portion of long-term liabilities 729 315 Fair value of derivatives 8,524 5,486 Liabilities of discontinued operations -- 335 --------- --------- TOTAL CURRENT LIABILITIES 37,268 29,564 LONG-TERM LIABILITIES Bank and other long-term debt 39,832 26,868 Senior subordinated notes 225,000 225,000 Other 4,344 91 --------- --------- 269,176 251,959 FAIR VALUE OF DERIVATIVES 9,552 4,371 DEFERRED INCOME TAXES 22,663 22,596 SHAREHOLDERS' DEFICIT Common stock without par value; $.10 stated value per share; authorized 58,000,000 shares; issued 10,590,157 and 10,490,440 shares (which includes 212,277 and 206,534 treasury shares, respectively) 1,038 1,030 Paid in capital 107,237 107,118 Deficit (145,593) (148,332) Accumulated other comprehensive loss (10,566) (4,461) --------- --------- TOTAL SHAREHOLDERS' DEFICIT (47,884) (44,645) --------- --------- $ 290,775 $ 263,845 ========= =========
See accompanying notes. 1 BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED, IN THOUSANDS)
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, -------------------------------- ------------------------------- 2003 2002 2003 2002 ------------- ------------- ------------ ------------ REVENUES Oil and gas sales $ 21,547 $ 22,571 $ 62,422 $ 68,143 Gas gathering, marketing, and oilfield service 4,862 3,990 18,780 17,123 Other 6 548 483 1,556 -------- -------- -------- -------- 26,415 27,109 81,685 86,822 EXPENSES Production expense 4,983 4,841 14,238 14,800 Production taxes 615 385 1,945 1,316 Gas gathering, marketing, and oilfield service 4,445 3,235 17,240 13,843 Exploration expense 6,106 4,236 10,849 10,087 General and administrative expense 1,108 1,065 3,369 3,441 Franchise, property and other taxes 72 119 230 264 Depreciation, depletion and amortization 4,728 5,573 13,495 17,425 Accretion expense 91 -- 263 -- Derivative fair value loss (gain) 340 (64) 166 134 Severance and other nonrecurring expense -- 127 -- 292 -------- -------- -------- -------- 22,488 19,517 61,795 61,602 -------- -------- -------- -------- OPERATING INCOME 3,927 7,592 19,890 25,220 OTHER EXPENSE Interest expense 6,463 5,871 19,101 17,604 -------- -------- -------- -------- (LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE (2,536) 1,721 789 7,616 (Benefit) provision for income taxes (895) 653 336 2,921 -------- -------- -------- -------- (LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE (1,641) 1,068 453 4,695 Income (loss) from discontinued operations, net of tax -- 75 (111) 472 -------- -------- -------- -------- (LOSS) INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE (1,641) 1,143 342 5,167 Cumulative effect of change in accounting principle, net of tax -- -- 2,397 -- -------- -------- -------- -------- NET (LOSS) INCOME $ (1,641) $ 1,143 $ 2,739 $ 5,167 ======== ======== ======== ========
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, 2001 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 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 income (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 income: Net income 2,739 2,739 Other comprehensive income, net of tax: Change in derivative fair value (12,256) (12,256) Reclassification adjustment for derivative (gain) loss reclassified into oil and gas sales 6,151 6,151 --------- Total comprehensive income (3,366) --------- Stock options exercised 99 10 107 117 Stock-based compensation 54 54 Repurchase of stock options (47) (47) Tax benefit of repurchase of stock options and stock options exercised 40 40 Treasury stock (17) (2) (35) (37) --------- -------- --------- ---------- ------------ --------- SEPTEMBER 30, 2003 (UNAUDITED) 10,378 $ 1,038 $ 107,237 $ (145,593) $ (10,566) $ (47,884) ========= ======== ========= ========== ============ =========
See accompanying notes. 3 BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED, IN THOUSANDS)
NINE MONTHS ENDED SEPTEMBER 30, ------------------------------- 2003 2002 ---------- ---------- CASH FLOWS FROM OPERATING ACTIVITIES: Income from continuing operations $ 453 $ 4,695 Adjustments to reconcile income from continuing operations to net cash provided by operating activities: Depreciation, depletion and amortization 13,495 17,425 Accretion of discount on asset retirement obligations 263 -- Loss on disposal of property and equipment 849 613 Net monetization of derivatives -- 22,091 Amortization of derivatives and other noncash hedging activities (2,194) (14,524) Exploration expense 10,849 10,087 Deferred income taxes 188 2,921 Stock-based compensation 54 62 Change in operating assets and liabilities, net of effects of acquisition and disposition of businesses: Accounts receivable and other operating assets (4,018) (31) Inventories 131 294 Accounts payable and accrued expenses 4,587 10,077 --------- --------- NET CASH PROVIDED BY CONTINUING OPERATIONS 24,657 53,710 CASH FLOWS FROM INVESTING ACTIVITIES: Acquisition of businesses, net of cash acquired (4,728) (2,835) Disposition of businesses, net of cash 100 8,161 Proceeds from property and equipment disposals 2,953 1,497 Exploration expense (10,849) (10,087) Additions to property and equipment (25,510) (26,782) Other (497) 749 --------- --------- NET CASH USED IN INVESTING ACTIVITIES (38,531) (29,297) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from revolving line of credit 147,222 107,960 Repayment of long-term debt and other obligations (134,532) (134,451) Debt issue costs (240) (81) Proceeds from stock options exercised 117 5 Repurchase of stock options (47) (13) Tax benefit of repurchase of stock options and stock options exercised 40 -- Purchase of treasury stock (37) (41) --------- --------- NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES 12,523 (26,621) --------- --------- NET DECREASE IN CASH AND CASH EQUIVALENTS FROM CONTINUING OPERATIONS (1,351) (2,208) NET INCREASE IN CASH AND CASH EQUIVALENTS FROM DISCONTINUED OPERATIONS 620 2,011 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 1,722 1,935 --------- --------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 991 $ 1,738 ========= =========
See accompanying notes. 4 BELDEN & BLAKE CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) SEPTEMBER 30, 2003 (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, 2003 are not necessarily indicative of the results that may be expected for the year ended December 31, 2003. 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, 2002. Certain reclassifications have been made to conform to the current presentation. (2) NEW ACCOUNTING PRONOUNCEMENTS On January 1, 2003, the Company adopted Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards No. (SFAS) 143, "Accounting for Asset Retirement Obligations." SFAS 143 amends SFAS 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies" to require the Company to recognize a liability for the fair value of its asset retirement obligations associated with its tangible, long-lived assets. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment (excluding salvage value) of its oil and gas properties. At January 1, 2003, there were no assets legally restricted for purposes of settling asset retirement obligations. The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect adjustment to record a $4.0 million increase in long-term asset retirement obligation liabilities, a $621,000 increase in current asset retirement obligation liabilities, a $3.2 million increase in the carrying value of oil and gas assets, a $5.2 million decrease in accumulated depreciation, depletion and amortization and a $1.4 million increase in deferred income tax liabilities. The net effect of adoption was to record a gain of $2.4 million, net of tax, as a cumulative effect of a change in accounting principle in the Company's consolidated statement of operations in the first quarter of 2003. Subsequent to the adoption of SFAS 143, there has been no significant current period activity with respect to additional retirement obligations, settled obligations, accretion expense and revisions of estimated cash flows. The unaudited pro forma net income for the nine months and quarter ended September 30, 2002 was $5.9 million and $1.4 million, respectively, and has been prepared to give effect to the adoption of SFAS 143 as if it had been adopted on January 1, 2002. Assuming retroactive application of the change in accounting principle as of January 1, 2002, liabilities would have increased approximately $6 million. 5 A reconciliation of the Company's liability for plugging and abandonment costs for the nine months ended September 30, 2003 is as follows (in thousands): Asset retirement obligation, December 31, 2002 $ -- Cumulative effect adjustment 4,614 Liabilities incurred 204 Liabilities settled (138) Accretion expense 263 ------- Asset retirement obligation, September 30, 2003 $ 4,943 =======
On January 1, 2003, the Company adopted 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 Accounting Principles Board Opinion No. (APB) 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. The adoption of SFAS 145 did not have any effect on the Company's financial position, results of operations or cash flows. In June 2002, the FASB issued SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS 146 was effective for the Company for disposal activities initiated after December 31, 2002. The adoption of this standard did not have any effect on the Company's financial position, results of operations or cash flows. In November 2002, the FASB issued FASB Interpretation No. (FIN) 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." FIN 45's disclosure requirements are effective for the Company's interim and annual financial statements for periods ending after December 15, 2002. The initial recognition and measurement provisions are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. FIN 45 requires certain guarantees to be recorded at fair value, which is different from current practice, which is generally to record a liability only when a loss is probable and reasonably estimable. FIN 45 also requires a guarantor to make significant new disclosures, even when the likelihood of making any payments under the guarantee is remote. The adoption of FIN 45 did not have any effect on the Company's financial statement disclosures, financial position, results of operations or cash flows. In December 2002, the FASB issued SFAS 148, "Accounting for Stock-Based Compensation - Transition and Disclosure." SFAS 148 amends FASB 123, "Accounting for Stock-Based Compensation," to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The Company measures expense associated with stock-based compensation using the intrinsic value method prescribed by APB 25, "Accounting for Stock Issued to Employees" and its related interpretations. Under APB 25, no compensation expense is required to be 6 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. The provisions of SFAS 148 were effective for financial statements for fiscal years ending after December 15, 2002. The adoption of SFAS 148 did not have a material effect on the Company's financial position, results of operations or cash flows. The fair value of the Company's stock options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for the first nine months of 2003 and 2002, respectively: risk-free interest rates of 3.7% and 4.4%, volatility factor of the expected market price of the Company's common stock of near zero, dividend yield of zero, and a weighted-average expected life of the option of seven years. The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company's stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its stock options. 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 September 30, 2003 and 2002 were not material. In January 2003, the FASB issued FIN 46, "Consolidation of Variable Interest Entities - An Interpretation of Accounting Research Bulletin (ARB) 51." FIN 46 is an interpretation of ARB 51, "Consolidated Financial Statements," and addresses consolidation by business enterprises of variable interest entities (VIEs). The primary objective of FIN 46 is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. FIN 46 requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity's expected losses if they occur, receive a majority of the entity's expected residual returns if they occur, or both. An enterprise shall consider the rights and obligations conveyed by its variable interests in making this determination. This guidance applies immediately to VIEs created after January 31, 2003, and to VIEs in which an enterprise obtains an interest after that date. It applies in the first fiscal year or interim period beginning after December 15, 2003, to VIEs in which an enterprise holds a variable interest that it acquired before February 1, 2003. The adoption of FIN 46 is not expected to have any effect on the Company's financial statement disclosures, financial position, results of operations or cash flows. In April 2003, the FASB issued SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." This Statement is intended to result in more consistent reporting of contracts as either freestanding derivative instruments subject to Statement 133 in its entirety, or as hybrid instruments with debt host contracts and embedded derivative features. SFAS 149 is effective for the Company's financial statements for the interim period beginning July 1, 2003. The adoption of SFAS 149 did not have a material effect on the Company's financial position, results of operations or cash flows. In May 2003, the FASB issued SFAS 150, "Accounting for Financial Instruments with Characteristics of both Liabilities and Equity." This Statement establishes standards for classifying and measuring as liabilities certain financial instruments that embody obligations of the issuer and have 7 characteristics of both liabilities and equity. Instruments that are indexed to and potentially settled in an issuer's own shares that are not within the scope of Statement 150 remain subject to existing guidance. SFAS 150 is effective for the Company's financial statements for the interim period beginning July 1, 2003. The adoption of SFAS 150 did not have a material effect on the Company's financial position, results of operations or cash flows. The Company has been 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 is whether SFAS 142 requires 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." If it is ultimately determined that SFAS 142 requires the Company to reclassify costs associated with mineral rights from property and equipment to intangible assets, the Company currently believes that its financial condition, results of operations or cash flows would not be affected, since such intangible assets would continue to be depleted and assessed for impairment in accordance with existing successful efforts accounting rules and impairment standards. The Company had undeveloped leasehold costs of $12.8 million at September 30, 2003. The amount of potential balance sheet reclassifications for developed leasehold costs has not been determined. (3) ACQUISITION In February 2003, the Company purchased reserves in certain wells the Company operates in Michigan for $3.75 million in cash. These properties were subject to a prior monetization transaction of the Section 29 tax credits which the Company entered into in 1996. The Company had the option to purchase these properties beginning in 2003. The Company previously held a production payment on these properties including a 75% reversionary interest in certain future production. The Company purchased those reserve volumes beyond its previously held production payment along with the 25% reversionary interest not owned. The estimated volumes acquired were 4.4 Bcf (billion cubic feet) of proved developed producing gas reserves. The pro forma effect of the acquisition was not material. (4) DISPOSITION As a result of the Company's decision to shift focus away from exploration and development activities in the Knox formation in Ohio, the Company sold substantially all of its undeveloped Knox acreage in Ohio for approximately $2.8 million in September 2003. The sale resulted in a loss of approximately $90,000. (5) 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 8 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 September 30, 2003, 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 nine months of 2003 and 2002, a net loss of $9.7 million ($6.2 million after tax) and a net gain of $17.5 million ($11.1 million after tax), respectively, were reclassified from accumulated other comprehensive income to earnings. The fair value of open hedges decreased $19.3 million ($12.3 million after tax) in the first nine months of 2003 and decreased $682,000 ($434,000 after tax) in the first nine months of 2002. At September 30, 2003, the estimated net loss in accumulated other comprehensive income that is expected to be reclassified into earnings within the next 12 months is approximately $7.9 million. The Company has partially hedged its exposure to the variability in future cash flows through December 2005. In March 2003, the Company entered into a collar for 4,320 Bbtu (billion British thermal units) of its natural gas production in 2004 with a ceiling price of $5.80 per Mmbtu (million British thermal units) and a floor price of $4.00 per Mmbtu. The Company also sold a floor at $3.00 per Mmbtu on this volume of gas. This aggregate structure has the effect of: 1) setting a maximum price of $5.80 per Mmbtu; 2) floating at prices from $4.00 to $5.80 per Mmbtu; 3) locking in a price of $4.00 per Mmbtu if prices are between $3.00 and $4.00 per Mmbtu; and 4) receiving a price of $1.00 per Mmbtu above the price if the price is $3.00 or less. All prices are based on monthly NYMEX settle. In April 2003, the Company entered into a collar for 6,000 Bbtu of its natural gas production in 2005 with a ceiling price of $5.37 per Mmbtu and a floor price of $4.00 per Mmbtu. The Company also sold a floor at $3.10 per Mmbtu on this volume of gas. This aggregate structure has the effect of: 1) setting a maximum price of $5.37 per Mmbtu; 2) floating at prices from $4.00 to $5.37 per Mmbtu; 3) locking in a price of $4.00 per Mmbtu if prices are between $3.10 and $4.00 per Mmbtu; and 4) receiving a price of $0.90 per Mmbtu above the price if the price is $3.10 or less. All prices are based on monthly NYMEX settle. (6) LONG-TERM DEBT The Company has a $100 million revolving credit facility (the "Revolver") from Ableco Finance LLC and Wells Fargo Foothill, Inc. (formerly known as Foothill Capital Corporation) which matures on June 30, 2006. The Revolver bears interest at the prime rate plus two percentage points, payable monthly. At September 30, 2003, the interest rate was 6.00%. At September 30, 2003, the Company had $29.7 million of outstanding letters of credit. At September 30, 2003, the outstanding balance under the credit agreement was $39.7 million with $55.6 million of borrowing capacity available for general corporate purposes. 9 The Revolver was amended on March 31, 2003 to increase the letter of credit sublimit to $55 million. On May 30, 2003, the Company amended its $100 million revolving credit facility. The amendment increased the total commitment amount from $100 million to $125 million solely to provide for a special letter of credit facility in the amount of $25 million which combined with the existing letter of credit sub-limit of $55 million would allow a total of $80 million in letters of credit. The amendment also extended the Revolver's final maturity date to June 30, 2006, from December 31, 2005. The Revolver, as amended, is subject to certain financial covenants. These include a quarterly senior debt interest coverage ratio of 3.2 to 1 extended through March 31, 2006; and a senior debt leverage ratio of 2.7 to 1 extended through March 31, 2006. The amendment extended the early termination fee, equal to .125% of the Revolver, to June 30, 2005, from December 31, 2004. There is no termination fee after June 30, 2005. The Company had satisfied all financial covenants as of September 30, 2003. (7) 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. (8) SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
NINE MONTHS ENDED SEPTEMBER 30, ------------------------------- (IN THOUSANDS) 2003 2002 ------------- ------------- CASH PAID DURING THE PERIOD FOR: Interest $ 13,472 $ 13,331 Income taxes, net of refunds -- 8 NON-CASH INVESTING AND FINANCING ACTIVITIES: Acquisition of assets in exchange for long-term liabilities -- 263 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE, NET OF TAX 2,397 --
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 10 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 2002 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 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, 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 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 11 reserves have been reviewed by independent petroleum engineers. 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 was 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. 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 12 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, options and collars, and has designated the contracts for the special hedge accounting treatment. Had the Company not designated the derivative contracts as hedges, the change in fair value of the contracts would have been reflected directly in the statement of operations. 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 On January 1, 2003, the Company adopted SFAS 143, "Accounting for Asset Retirement Obligations." SFAS 143 amends SFAS 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies" to require the Company to recognize a liability for the fair value of its asset retirement obligations associated with its tangible, long-lived assets. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment (excluding salvage value) of its oil and gas properties. At January 1, 2003, there were no assets legally restricted for purposes of settling asset retirement obligations. The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect adjustment to record a $4.0 million increase in long-term asset retirement obligation liabilities, a $621,000 increase in current asset retirement obligation liabilities, a $3.2 million increase in the carrying value of oil and gas assets, a $5.2 million decrease in accumulated depreciation, depletion and amortization and a $1.4 million increase in deferred income tax liabilities. The net effect of adoption was to record a gain of $2.4 million, net of tax, as a cumulative effect of a change in accounting principle in the Company's consolidated statement of operations in the first quarter of 2003. Subsequent to the adoption of SFAS 143, there has been no significant current period activity with respect to additional retirement obligations, settled obligations, accretion expense and revisions of estimated cash flows. The unaudited pro forma net income for the nine months and quarter ended September 30, 2002 was $5.9 million and $1.4 million, respectively, and has been prepared to give effect to the adoption of SFAS 143 as if it had been adopted on January 1, 2002. Assuming retroactive application of the change in accounting principle as of January 1, 2002, liabilities would have increased approximately $6 million. A reconciliation of the Company's liability for plugging and abandonment costs for the nine months ended September 30, 2003 is as follows (in thousands): Asset retirement obligation, December 31, 2002 $ -- Cumulative effect adjustment 4,614 Liabilities incurred 204 Liabilities settled (138) Accretion expense 263 ------- Asset retirement obligation, September 30, 2003 $ 4,943 =======
13 On January 1, 2003, the Company adopted 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 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. The adoption of SFAS 145 did not have any effect on the Company's financial position, results of operations or cash flows. In June 2002, the FASB issued SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities." SFAS 146 was effective for the Company for disposal activities initiated after December 31, 2002. The adoption of this standard did not have any effect on the Company's financial position, results of operations or cash flows. In November 2002, the FASB issued FIN 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." FIN 45's disclosure requirements are effective for the Company's interim and annual financial statements for periods ending after December 15, 2002. The initial recognition and measurement provisions are applicable on a prospective basis to guarantees issued or modified after December 31, 2002. FIN 45 requires certain guarantees to be recorded at fair value, which is different from current practice, which is generally to record a liability only when a loss is probable and reasonably estimable. FIN 45 also requires a guarantor to make significant new disclosures, even when the likelihood of making any payments under the guarantee is remote. The adoption of FIN 45 did not have any effect on the Company's financial statement disclosures, financial position, results of operations or cash flows. In December 2002, the FASB issued SFAS 148, "Accounting for Stock-Based Compensation - Transition and Disclosure." SFAS 148 amends FASB 123, "Accounting for Stock-Based Compensation," to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS 148 amends the disclosure requirements of SFAS 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The Company measures expense associated with stock-based compensation using the intrinsic value method prescribed by 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. The provisions of SFAS 148 were effective for financial statements for fiscal years ending after December 15, 2002. The adoption of SFAS 148 did not have a material effect on the Company's financial position, results of operations or cash flows. The fair value of the Company's stock options was estimated at the date of grant using a Black-Scholes option pricing model with the following weighted-average assumptions for the first nine months of 2003 and 2002, respectively: risk-free interest rates of 3.7% and 4.4%, volatility factor of the expected market price of the Company's common stock of near zero, dividend yield of zero, and a weighted-average expected life of the option of seven years. 14 The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company's stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its stock options. 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 September 30, 2003 and 2002 were not material. In January 2003, the FASB issued FIN 46, "Consolidation of Variable Interest Entities - An Interpretation of Accounting Research Bulletin (ARB) 51." FIN 46 is an interpretation of ARB 51, "Consolidated Financial Statements," and addresses consolidation by business enterprises of VIEs. The primary objective of FIN 46 is to provide guidance on the identification of, and financial reporting for, entities over which control is achieved through means other than voting rights; such entities are known as VIEs. FIN 46 requires an enterprise to consolidate a VIE if that enterprise has a variable interest that will absorb a majority of the entity's expected losses if they occur, receive a majority of the entity's expected residual returns if they occur, or both. An enterprise shall consider the rights and obligations conveyed by its variable interests in making this determination. This guidance applies immediately to VIEs created after January 31, 2003, and to VIEs in which an enterprise obtains an interest after that date. It applies in the first fiscal year or interim period beginning after December 15, 2003, to VIEs in which an enterprise holds a variable interest that it acquired before February 1, 2003. The adoption of FIN 46 is not expected to have any effect on the Company's financial statement disclosures, financial position, results of operations or cash flows. In April 2003, the FASB issued SFAS 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." This Statement is intended to result in more consistent reporting of contracts as either freestanding derivative instruments subject to Statement 133 in its entirety, or as hybrid instruments with debt host contracts and embedded derivative features. SFAS 149 is effective for the Company's financial statements for the interim period beginning July 1, 2003. The adoption of SFAS 149 did not have a material effect on the Company's financial position, results of operations or cash flows. In May 2003, the FASB issued SFAS 150, "Accounting for Financial Instruments with Characteristics of both Liabilities and Equity." This Statement establishes standards for classifying and measuring as liabilities certain financial instruments that embody obligations of the issuer and have characteristics of both liabilities and equity. Instruments that are indexed to and potentially settled in an issuer's own shares that are not within the scope of Statement 150 remain subject to existing guidance. SFAS 150 is effective for the Company's financial statements for the interim period beginning July 1, 2003. The adoption of SFAS 150 did not have a material effect on the Company's financial position, results of operations or cash flows. The Company has been 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 is whether SFAS 142 requires 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 15 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." If it is ultimately determined that SFAS 142 requires the Company to reclassify costs associated with mineral rights from property and equipment to intangible assets, the Company currently believes that its financial condition, results of operations or cash flows would not be affected, since such intangible assets would continue to be depleted and assessed for impairment in accordance with existing successful efforts accounting rules and impairment standards. The Company had undeveloped leasehold costs of $12.8 million at September 30, 2003. The amount of potential balance sheet reclassifications for developed leasehold costs has not been determined. RESULTS OF OPERATIONS - THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2003 AND 2002 COMPARED The following Management's Discussion and Analysis is based on the results of operations from continuing operations, unless otherwise noted. Accordingly, the 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 quarters indicated:
THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, -------------------- ------------------- 2003 2002 2003 2002 ------ ------- ------- ------- PRODUCTION Gas (Mmcf) 3,836 3,978 10,896 12,260 Oil (Mbbls) 103 139 306 429 Total production (Mmcfe) 4,456 4,811 12,732 14,836 AVERAGE PRICE Gas (per Mcf) $ 4.87 $ 4.80 $ 4.94 $ 4.78 Oil (per Bbl) 27.57 24.90 28.07 22.20 Mcfe 4.84 4.69 4.90 4.59 AVERAGE COSTS (PER MCFE) Production expense 1.12 1.01 1.12 1.00 Production taxes 0.14 0.08 0.15 0.09 Depletion 0.80 0.88 0.78 0.88 OPERATING MARGIN (PER MCFE) 3.58 3.60 3.63 3.50
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 2003 AND 2002 COMPARED Operating income decreased $3.7 million (48%) from $7.6 million in the third quarter of 2002 to $3.9 million in the third quarter of 2003. This decrease was primarily a result of a $1.7 million (10%) decrease in operating margins, a $1.9 million (44%) increase in exploration expense, a $542,000 decrease in other revenue and a $404,000 increase in derivative fair value loss partially offset by a $845,000 decrease in depreciation, depletion and amortization. The $1.7 million decrease in operating margins was primarily due to a $1.4 million decrease in the operating margin from oil and gas sales resulting primarily from a decrease in oil and gas volumes sold partially offset by an increase in the average prices realized for the Company's oil and natural gas in 16 the third quarter of 2003. A $338,000 decrease in the operating margin from gas gathering, marketing and oilfield service also contributed to the decrease in operating margins. Income or loss from continuing operations before income taxes and cumulative effect of change in accounting principle decreased $4.2 million from income of $1.7 million in the third quarter of 2002 to a loss of $2.5 million in the third quarter of 2003. This decrease is due primarily to the decrease in operating income discussed above and a $592,000 increase in interest expense. Net income decreased $2.7 million from net income of $1.1 million in the third quarter of 2002 to a net loss of $1.6 million in the third quarter of 2003. This decrease was a result of the $4.2 million increase in loss from continuing operations before income taxes and cumulative effect of change in accounting principle discussed above. This increase was partially offset by a $1.5 million decrease in the provision for income taxes. Total revenues decreased $694,000 (3%) in the third quarter of 2003 compared to the third quarter of 2002 due to a $1.0 million decrease in oil and gas sales revenues and a $542,000 decrease in other revenues partially offset by a $872,000 increase in gas gathering, marketing and oilfield service revenues. The decrease in other revenues is due to the loss of revenue from Section 29 tax credit monetization transactions which ended upon expiration of the non-conventional fuel source tax credit as of December 31, 2002. The increase in gas gathering, marketing and oilfield service revenues was due to a $919,000 increase in gas marketing revenues primarily resulting from higher natural gas prices. Gas volumes sold in the third quarter of 2003 were 3.8 Bcf, a decrease of 142 Mmcf (4%) compared to the third quarter of 2002 due primarily to the sale of wells in Ohio and Pennsylvania during 2002 and the natural decline of the wells partially offset by production from wells drilled in 2003 and 2002. The decrease in gas volumes sold resulted in a decrease in gas sales revenues of approximately $680,000. Oil volumes sold decreased 35,000 Bbls (25%) from 139,000 Bbls in the third quarter of 2002 to 103,000 Bbls in the third quarter of 2003 primarily due to the sale of wells in Ohio during 2002 and the natural decline of the wells. This resulted in a decrease in oil sales revenues of approximately $880,000. The average price realized for the Company's natural gas increased $0.07 per Mcf to $4.87 per Mcf in the third quarter of 2003 compared to the third quarter of 2002, which increased gas sales revenues in the third quarter of 2003 by approximately $270,000. As a result of the Company's hedging activities, gas sales revenues for the third quarter of 2003 decreased by approximately $1.1 million or $0.30 per Mcf compared to an increase of approximately $5.2 million or $1.33 per Mcf for the third quarter of 2002. The average price realized for the Company's oil increased from $24.90 per Bbl in the third quarter of 2002 to $27.57 per Bbl in the third quarter of 2003 which increased oil sales revenues by approximately $280,000. Production expense increased $142,000 (3%) from $4.8 million in the third quarter of 2002 to $5.0 million in the third quarter of 2003 primarily due to increased costs to stimulate production on declining wells in the higher oil and natural gas price environment of 2003. The average production cost increased from $1.01 per Mcfe in the third quarter of 2002 to $1.12 per Mcfe in the third quarter of 2003 due to the cost increases and lower volumes discussed above. Production taxes increased $230,000 from $385,000 in the third quarter of 2002 to $615,000 in the third quarter of 2003. Average per unit production taxes increased from $0.08 per Mcfe in the third quarter of 2002 to $0.14 per Mcfe in the third quarter of 2003 primarily due to higher oil and gas prices in Michigan, where production taxes are based on a percentage of revenues, excluding the effect of hedging. 17 Exploration expense increased $1.9 million (44%) from $4.2 million in the third quarter of 2002 to $6.1 million in the third quarter of 2003 primarily due to a $2.8 million increase in dry hole expense partially offset by lower land leasing expenses and decreased expiring lease costs. General and administrative expense of $1.1 million in the third quarter of 2003 was consistent when compared to the third quarter of 2002. Depreciation, depletion and amortization decreased by $845,000 (15%) from $5.6 million in the third quarter of 2002 to $4.7 million in the third quarter of 2003. Depletion expense decreased $660,000 (16%) from $4.2 million in the third quarter of 2002 to $3.6 million in the third quarter of 2003 due to lower oil and gas volumes sold and a lower depletion rate per Mcfe. Depletion per Mcfe decreased from $0.88 per Mcfe in the third quarter of 2002 to $0.80 per Mcfe in the third quarter of 2003. This decrease in the depletion rate per Mcfe was primarily due to higher reserves resulting from higher oil and gas prices at year-end 2002, excluding the effect of hedging, and the effect of the adoption of SFAS 143. The depreciable basis of oil and gas properties was increased by the fair value of the estimated future plugging liability and decreased by the gross amount of the estimated salvage value of the well equipment. Interest expense increased $592,000 (10%) from $5.9 million in the third quarter of 2002 to $6.5 million in the third quarter of 2003 due to higher average outstanding borrowings and higher blended interest rates in the third quarter of 2003. Income tax expense decreased $1.5 million from $653,000 in the third quarter of 2002 to a benefit of $895,000 in the third quarter of 2003 due primarily to the decrease in income from continuing operations before income taxes. In accordance with SFAS 144, the Company was required to reclassify the assets, liabilities and results of discontinued operations for all accounting periods presented. Although both revenues and expenses for prior periods were reclassified, there was no impact upon previously reported net earnings. RESULTS OF OPERATIONS - NINE MONTHS OF 2003 AND 2002 COMPARED Operating income decreased $5.3 million (21%) from $25.2 million in the first nine months of 2002 to $19.9 million in the first nine months of 2003. This decrease was primarily a result of a $7.5 million (14%) decrease in operating margins, a $1.1 million decrease in other revenue and a $762,000 (8%) increase in exploration expense partially offset by a $3.9 million decrease in depreciation, depletion and amortization. The $7.5 million decrease in operating margins was primarily due to a $5.8 million decrease in the operating margin from oil and gas sales resulting primarily from a decrease in oil and gas volumes sold partially offset by an increase in the average prices realized for the Company's oil and natural gas in the first nine months of 2003. A $1.7 million decrease in the operating margin from gas gathering, marketing and oilfield service, resulting primarily from a lower margin on a gathering system in Pennsylvania, also contributed to the decrease in operating margins. Income from continuing operations before income taxes and cumulative effect of change in accounting principle decreased $6.8 million from $7.6 million in the first nine months of 2002 to $789,000 in the first nine months of 2003. This decrease is due primarily to the decrease in operating income discussed above and a $1.5 million increase in interest expense. Net income decreased $2.5 million from $5.2 million in the first nine months of 2002 to $2.7 million in the first nine months of 2003. This decrease was a result of the decrease in income from continuing operations before income taxes and cumulative effect of change in accounting principle 18 discussed above and a $583,000 decrease in income from discontinued operations. This decrease in net income was partially offset by a $2.4 million gain on the cumulative effect of change in accounting principle, net of tax, recorded in the first nine months of 2003 related to asset retirement obligations and a decrease in the provision for income taxes of $2.6 million. Total revenues decreased $5.1 million (6%) in the first nine months of 2003 compared to the first nine months of 2002 due to a $5.7 million decrease in oil and gas sales revenues and a $1.1 million decrease in other revenues partially offset by a $1.7 million increase in gas gathering, marketing and oilfield service revenues. The decrease in other revenues is due to the loss of revenue from Section 29 tax credit monetization transactions which ended upon expiration of the non-conventional fuel source tax credit as of December 31, 2002. The increase in gas gathering, marketing and oilfield service revenues was due primarily to a $4.9 million increase in oilfield service revenues primarily from drilling operations as a result of the acquisition of a drilling consulting business in the second quarter of 2002. This increase was partially offset by a $3.3 million decrease in gas gathering and marketing revenues resulting from a decrease in gas marketing activity, the termination of a gas marketing contract and lower revenues from a gas gathering system in Pennsylvania. Gas volumes sold in the first nine months of 2003 decreased 1.4 Bcf (11%) from 12.3 Bcf in the first nine months of 2002 to 10.9 Bcf in the first nine months of 2003 due primarily to the sale of wells in Ohio and Pennsylvania during 2002, extreme weather conditions experienced in the first quarter of 2003 and the natural decline of the wells partially offset by production from wells drilled in 2003 and 2002. The decrease in gas volumes sold resulted in a decrease in gas sales revenues of approximately $6.5 million. Oil volumes sold decreased 123,000 Bbls (29%) from 429,000 Bbls in the first nine months of 2002 to 306,000 Bbls in the first nine months of 2003 primarily due to the sale of wells in Ohio during 2002, extreme weather conditions experienced in the first quarter of 2003 and the natural decline of the wells. This resulted in a decrease in oil sales revenues of approximately $2.7 million. The extreme weather conditions, including colder temperatures and greater snowfall, negatively impacted production during the first quarter of 2003 due to mechanical breakdowns and freezing of pipelines and wellheads which reduced production and created difficulty accessing wells for production and well maintenance. The average price realized for the Company's natural gas increased $0.16 per Mcf to $4.94 per Mcf in the first nine months of 2003 compared to the first nine months of 2002 which increased gas sales revenues in the first nine months of 2003 by approximately $1.7 million. As a result of the Company's hedging activities, gas sales revenues for the first nine months of 2003 decreased by approximately $9.7 million or $0.89 per Mcf compared to an increase of approximately $17.2 million or $1.40 per Mcf for the first nine months of 2002. The average price realized for the Company's oil increased from $22.20 per Bbl in the first nine months of 2002 to $28.07 per Bbl in the first nine months of 2003 which increased oil sales revenues by approximately $1.8 million. Production expense decreased $562,000 (4%) from $14.8 million in the first nine months of 2002 to $14.2 million in the first nine months of 2003 primarily due to the sale of wells in Ohio and Pennsylvania during 2002 partially offset by additional costs incurred as a result of colder temperatures and greater amounts of snow during the first quarter of 2003 and increased costs to stimulate production on declining wells in the higher oil and natural gas price environment of 2003. The average production cost increased from $1.00 per Mcfe in the first nine months of 2002 to $1.12 per Mcfe in the first nine months of 2003 due to the cost increases and lower volumes discussed above. Production taxes increased $629,000 from $1.3 million in the first nine months of 2002 to $1.9 million in the first nine months of 2003. Average per unit production taxes increased from $0.09 per Mcfe in the first nine months of 2002 to $0.15 per Mcfe in the first nine months of 2003 primarily due to higher oil and gas prices in Michigan, where production taxes are based on a percentage of revenues, excluding the effect of hedging. 19 Exploration expense increased $762,000 (8%) from $10.1 million in the first nine months of 2002 to $10.8 million in the first nine months of 2003 primarily due to a $2.0 million increase in dry hole expense and higher delay rental expenses partially offset by lower geophysical and land leasing expenses. General and administrative expense of $3.4 million in the first nine months of 2003 was consistent when compared to the first nine months of 2002. Depreciation, depletion and amortization decreased by $3.9 million (23%) from $17.4 million in the first nine months of 2002 to $13.5 million in the first nine months of 2003. Depletion expense decreased $3.1 million (24%) from $13.1 million in the first nine months of 2002 to $10.0 million in the first nine months of 2003 due to lower oil and gas volumes sold and a lower depletion rate per Mcfe. Depletion per Mcfe decreased from $0.88 per Mcfe in the first nine months of 2002 to $0.78 per Mcfe in the first nine months of 2003. This decrease in the depletion rate per Mcfe was primarily due to higher reserves resulting from higher oil and gas prices at year-end 2002, excluding the effect of hedging, and the effect of the adoption of SFAS 143. The depreciable basis of oil and gas properties was increased by the fair value of the estimated future plugging liability and decreased by the gross amount of the estimated salvage value of the well equipment. Interest expense increased $1.5 million (9%) from $17.6 million in the first nine months of 2002 to approximately $19.1 million in the first nine months of 2003 due to higher blended interest rates in the first nine months of 2003. This increase was partially offset by a decrease in average outstanding borrowings in the first nine months of 2003. Income tax expense decreased $2.6 million from $2.9 million in the first nine months of 2002 to $336,000 in the first nine months of 2003 due primarily to the decrease in income from continuing operations before income taxes. In accordance with SFAS 144, the Company was required to reclassify the assets, liabilities and results of discontinued operations for all accounting periods presented. Although both revenues and expenses for prior periods were reclassified, there was no impact upon previously reported net earnings. 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, 2003 was .75 to 1. During the first nine months of 2003, the working capital from continuing operations decreased $2.9 million from a deficit of $6.5 million at December 31, 2002 to a deficit of $9.4 million at September 30, 2003. The decrease was primarily due to a $4.5 million increase in accrued expenses and a $3.0 million decrease in the fair value of derivatives in the first nine months of 2003 partially offset by a $3.3 million increase in accounts receivable and a $2.0 million increase in the deferred income taxes asset. The $3.3 million increase in accounts receivable was primarily due to higher natural gas prices. The Company's operating activities provided cash flows of $24.7 million during the first nine months of 2003. The Company has a $100 million revolving credit facility from Ableco Finance LLC and Wells Fargo Foothill, Inc. (formerly known as Foothill Capital Corporation) which matures on June 30, 2006. The Revolver bears interest at the prime rate plus two percentage points, payable monthly. At September 30, 2003, the interest rate was 6.00%. At September 30, 2003, the Company had $29.7 million of outstanding letters of credit. At September 30, 2003, the outstanding balance under the credit agreement was $39.7 million with $55.6 million of borrowing capacity available for general corporate purposes. 20 The Revolver was amended on March 31, 2003 to increase the letter of credit sublimit to $55 million. On May 30, 2003, the Company amended its $100 million revolving credit facility. The amendment increased the total commitment amount from $100 million to $125 million solely to provide for a special letter of credit facility in the amount of $25 million which combined with the existing letter of credit sub-limit of $55 million would allow a total of $80 million in letters of credit. The amendment also extended the Revolver's final maturity date to June 30, 2006, from December 31, 2005. The Revolver, as amended, is subject to certain financial covenants. These include a quarterly senior debt interest coverage ratio of 3.2 to 1 extended through March 31, 2006; and a senior debt leverage ratio of 2.7 to 1 extended through March 31, 2006. The amendment extended the early termination fee, equal to .125% of the Revolver, to June 30, 2005, from December 31, 2004. There is no termination fee after June 30, 2005. The Company's agreement with its hedging counterparty requires letters of credit based on an initial collateral requirement plus any negative market value thereafter. The initial collateral requirement currently is approximately $10 million. At October 31, 2003, the Company's hedge position had a negative market value of approximately $16.8 million and the aggregate minimum letter of credit requirement was approximately $27.0 million. At October 31, 2003, the Company had a total of $31.7 million of outstanding letters of credit. The Company is required to hedge, through financial instruments or fixed price contracts, at least 20% but not more than 80% of its estimated hydrocarbon production, on a Mcfe basis, for the succeeding 12 months on a rolling 12-month basis. Based on the Company's hedges currently in place and its expected production levels, the Company is in compliance with this hedging requirement through August 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 provided that the NYMEX strip price for natural gas shall not exceed $5.00 per Mmbtu. Prices are adjusted for basis differential, fixed price contracts and financial hedges in place. The weighted average price at September 30, 2003, was $4.71 per Mcfe. The present value (using a 10% discount rate) of the Company's future net income at September 30, 2003, using the borrowing base price forecast, was $419 million. The present value under the borrowing base formula above was approximately $246 million for all proved reserves of the Company and $170 million for properties secured by a mortgage. The Revolver is subject to certain financial covenants. These include a senior debt interest coverage ratio of 3.2 to 1 and a senior debt leverage ratio of 2.7 to 1. 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 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, 2003, the Company's current ratio including the above adjustments was 3.93 to 1. The Company had satisfied all financial covenants as of September 30, 2003. 21 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 2003 or 2002. During the first nine months of 2003, the Company invested approximately $26 million, including exploratory dry hole expense, to drill 78 development wells and 11 exploratory wells. All 78 of the development wells and three of the exploratory wells were successfully completed as producers in the target formation. This cost excludes approximately $3.1 million related to 2 gross (1.5 net) Trenton Black River ("TBR") wells in progress as of September 30, 2003. If these wells are determined to be dry holes, their cost will be charged to exploratory dry hole expense in subsequent periods. The Company had four exploratory wells in progress at December 31, 2002. Two of the wells were completed as productive TBR wells during the current year while the other two wells were determined to be unproductive and approximately $500,000 was recorded as exploratory dry hole expense in 2003. Five additional exploratory wells were drilled to the TBR and one exploratory and three development wells were drilled to the Oriskany formation in the first nine months of 2003. One of the TBR wells and all three of the additional development Oriskany wells were completed as producers while four TBR wells and the exploratory Oriskany well were unproductive and the related drilling cost of approximately $3.9 million was recorded as exploratory dry hole expense in the third quarter of 2003. The Company currently expects to spend approximately $35 million during 2003 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 and the sale of non-strategic assets. At September 30, 2003, the Company had approximately $55.6 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. 22 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 September 30, 2003 or 2002. If market interest rates for short-term borrowings increased 1%, the increase in the Company's interest expense in the third quarter would be approximately $101,000. This sensitivity analysis is based on the Company's financial structure at September 30, 2003. 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 $1.0 million, after considering the effects of the hedging contracts in place. The Company had no hedges or fixed price contracts on its oil production during 2003 or 2002. If the price of crude oil decreased $3.00 per Bbl, the Company's oil sales revenues for the quarter would decrease by $310,000. 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 a net pretax loss on its hedging activities of $9.7 million in the first nine months of 2003 and a net pretax gain of $17.5 million in the first nine months of 2002. In March 2003, the Company entered into a collar for 4,320 Bbtu of its natural gas production in 2004 with a ceiling price of $5.80 per Mmbtu and a floor price of $4.00 per Mmbtu. The Company also sold a floor at $3.00 per Mmbtu on this volume of gas. This aggregate structure has the effect of: 1) setting a maximum price of $5.80 per Mmbtu; 2) floating at prices from $4.00 to $5.80 per Mmbtu; 3) locking in a price of $4.00 per Mmbtu if prices are between $3.00 and $4.00 per Mmbtu; and 4) receiving a price of $1.00 per Mmbtu above the price if the price is $3.00 or less. All prices are based on monthly NYMEX settle. In April 2003, the Company entered into a collar for 6,000 Bbtu of its natural gas production in 2005 with a ceiling price of $5.37 per Mmbtu and a floor price of $4.00 per Mmbtu. The Company also sold a floor at $3.10 per Mmbtu on this volume of gas. This aggregate structure has the effect of: 1) setting a maximum price of $5.37 per Mmbtu; 2) floating at prices from $4.00 to $5.37 per Mmbtu; 3) locking in a price of $4.00 per Mmbtu if prices are between $3.10 and $4.00 per Mmbtu; and 4) receiving a price of $0.90 per Mmbtu above the price if the price is $3.10 or less. All prices are based on monthly NYMEX settle. 23 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 October 31, 2003:
NATURAL GAS SWAPS NATURAL GAS COLLARS FIXED PRICE CONTRACTS ------------------------------------ -------------------------------------- --------------------------- ESTIMATED NYMEX PRICE ESTIMATED ESTIMATED NYMEX PRICE WELLHEAD PRICE PER MMBTU WELLHEAD PRICE ESTIMATED WELLHEAD PRICE QUARTER ENDING BBTU PER MMBTU PER MCF BBTU FLOOR/CAP (1) PER MCF (1) MMCF PER MCF - -------------- ----- ------------ -------------- ----- ------------- -------------- --------- -------------- December 31, 2003 1,800 $ 3.92 $ 4.14 1,290 $ 3.40 - 5.23 $ 3.62 - 5.45 55 $ 4.00 ----- ------------ -------------- ----- ------------- -------------- --- -------------- 1,800 $ 3.92 $ 4.14 1,290 $ 3.40 - 5.23 $ 3.62 - 5.45 55 $ 4.00 ===== ============ ============== ===== ============= ============== === ============== March 31, 2004 2,040 $ 3.84 $ 4.09 1,080 $ 4.00 - 5.80 $ 4.25 - 6.05 54 $ 4.10 June 30, 2004 2,040 3.84 3.99 1,080 4.00 - 5.80 4.15 - 5.95 37 4.06 September 30, 2004 2,040 3.84 3.99 1,080 4.00 - 5.80 4.15 - 5.95 5 3.20 December 31, 2004 2,040 3.84 4.06 1,080 4.00 - 5.80 4.22 - 6.02 5 3.20 ----- ------------ -------------- ----- ------------- -------------- --- -------------- 8,160 $ 3.84 $ 4.03 4,320 $ 4.00 - 5.80 $ 4.19 - 5.99 101 $ 4.00 ===== ============ ============== ===== ============= ============== === ============== March 31, 2005 1,500 $ 3.84 $ 4.09 1,500 $ 4.00 - 5.37 $ 4.25 - 5.62 5 $ 4.00 June 30, 2005 1,500 3.73 3.88 1,500 4.00 - 5.37 4.15 - 5.52 5 4.00 September 30, 2005 1,500 3.73 3.88 1,500 4.00 - 5.37 4.15 - 5.52 5 4.00 December 31, 2005 1,500 3.73 3.95 1,500 4.00 - 5.37 4.22 - 5.59 5 4.00 ----- ------------ -------------- ----- ------------- -------------- --- -------------- 6,000 $ 3.76 $ 3.95 6,000 $ 4.00 - 5.37 $ 4.19 - 5.56 20 $ 4.00 ===== ============ ============== ===== ============= ============== === ==============
BBTU-BILLION BRITISH THERMAL UNITS MMCF-MILLION CUBIC FEET MMBTU-MILLION BRITISH THERMAL UNITS MCF-THOUSAND CUBIC FEET
(1) The NYMEX price per Mmbtu floor/cap and the estimated wellhead price per Mcf 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 and the estimated wellhead price per Mcf will be the NYMEX settle plus $1.15 to $1.25. The NYMEX price per Mmbtu floor/cap and the estimated wellhead price per Mcf 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 and the estimated wellhead price per Mcf will be the NYMEX settle plus $1.05 to $1.15. 24 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 September 30, 2003, 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 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. (b) Reports on Form 8-K On August 27, 2003, the Company filed a Current Report on Form 8-K dated August 22, 2003, reporting under Item 9 related to its operational outlook for 2003. 25 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 10, 2003 By: /s/ John L. Schwager ------------------------------------- John L. Schwager, Director, President and Chief Executive Officer Date: November 10, 2003 By: /s/ Robert W. Peshek ------------------------------------- Robert W. Peshek, Vice President and Chief Financial Officer 26 EX-31.1 3 l03420aexv31w1.txt EX-31.1 CERTIFICATION FOR 302 OF CEO Exhibit 31.1 CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES -OXLEY ACT OF 2002 I, John L. Schwager, 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: November 10, 2003 /s/ John L. Schwager ------------------------------------- John L. Schwager, Director, President and Chief Executive Officer 27 EX-31.2 4 l03420aexv31w2.txt EX-31.2 CERTIFICATION FOR 302 OF CFO 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: November 10, 2003 /s/ Robert W. Peshek ------------------------------------ Robert W. Peshek, Vice President and Chief Financial Officer 28 EX-32.1 5 l03420aexv32w1.txt EX-32.1 CERTIFICATION FOR 906 OF CEO 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 September 30, 2003, 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 10, 2003 /s/ John L. Schwager -------------------------------------- John L. Schwager, 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. 29 EX-32.2 6 l03420aexv32w2.txt EX-32.2 CERTIFICATION FOR 906 OF CFO 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 September 30, 2003, 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 10, 2003 /s/ Robert W. Peshek ---------------------------------- Robert W. Peshek, 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. 30 -----END PRIVACY-ENHANCED MESSAGE-----