10-Q 1 l90929ae10-q.txt BELDEN & BLAKE CORPORATION FORM 10-Q SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (Mark One) [X] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the period ended September 30, 2001 or [ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from _______________ to _______________ Commission File Number: 0-20100 BELDEN & BLAKE CORPORATION ------------------------------------------------------------------------------- (Exact name of registrant as specified in its charter) Ohio 34-1686642 ------------------------------------------------------------------------------- (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 5200 Stoneham Road North Canton, Ohio 44720 ------------------------------------------------------------------------------- (Address of principal executive offices) (Zip Code) (330) 499-1660 ------------------------------------------------------------------------------- (Registrant's telephone number, including area code) ------------------------------------------------------------------------------- (Former name, former address and former fiscal year, if changed since last report.) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. [X] Yes [ ] No As of October 31, 2001, Belden & Blake Corporation had outstanding 10,293,039 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, 2001 and December 31, 2000.................................................. 1 Consolidated Statements of Operations for the three and nine months ended September 30, 2001 and 2000 .......................... 2 Consolidated Statements of Shareholders' Equity (Deficit) for the nine months ended September 30, 2001 and the years ended December 31, 2000 and 1999......................................... 3 Consolidated Statements of Cash Flows for the nine months ended September 30, 2001 and 2000 .......................... 4 Notes to Consolidated Financial Statements........................... 5 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations................................ 8 PART II Other Information Item 6. Exhibits and Reports on Form 8-K..................................... 15
BELDEN & BLAKE CORPORATION CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT SHARE DATA)
SEPTEMBER 30, DECEMBER 31, 2001 2000 --------- --------- (UNAUDITED) ASSETS CURRENT ASSETS Cash and cash equivalents $ 1,504 $ 1,798 Accounts receivable, net 14,737 22,620 Inventories 2,115 2,222 Deferred income taxes -- 1,475 Other current assets 1,970 1,448 Fair value of derivatives 20,559 -- --------- --------- TOTAL CURRENT ASSETS 40,885 29,563 PROPERTY AND EQUIPMENT, AT COST Oil and gas properties (successful efforts method) 440,889 413,824 Gas gathering systems 13,402 13,445 Land, buildings, machinery and equipment 25,526 23,469 --------- --------- 479,817 450,738 Less accumulated depreciation, depletion and amortization 224,451 208,435 --------- --------- PROPERTY AND EQUIPMENT, NET 255,366 242,303 FAIR VALUE OF DERIVATIVES 7,462 -- OTHER ASSETS 11,390 13,251 --------- --------- $ 315,103 $ 285,117 ========= ========= LIABILITIES AND SHAREHOLDERS' DEFICIT CURRENT LIABILITIES Accounts payable $ 5,217 $ 5,926 Accrued expenses 22,974 19,316 Current portion of long-term liabilities 189 141 Deferred income taxes 6,608 -- --------- --------- TOTAL CURRENT LIABILITIES 34,988 25,383 LONG-TERM LIABILITIES Bank and other long-term debt 55,264 61,535 Senior subordinated notes 225,000 225,000 Other 435 323 --------- --------- 280,699 286,858 DEFERRED INCOME TAXES 24,417 21,189 SHAREHOLDERS' DEFICIT Common stock without par value; $.10 stated value per share; authorized 58,000,000 shares; issued 10,423,853 and 10,357,255 shares (which includes 100,971 and 53,972 treasury shares, respectively) 1,032 1,030 Paid in capital 107,465 107,921 Deficit (150,728) (157,264) Accumulated other comprehensive income 17,230 -- --------- --------- TOTAL SHAREHOLDERS' DEFICIT (25,001) (48,313) --------- --------- $ 315,103 $ 285,117 ========= =========
See accompanying notes. 1 BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS) (UNAUDITED)
THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, -------------------------------- ------------------------------- 2001 2000 2001 2000 -------------- ------------- ----------- ------------------ REVENUES Oil and gas sales $ 22,952 $ 18,782 $ 72,293 $ 55,663 Gas gathering, marketing, and oilfield service 7,421 7,726 25,652 25,328 Other 533 682 1,431 2,535 -------- -------- -------- -------- 30,906 27,190 99,376 83,526 EXPENSES Production expense 6,043 5,221 17,209 15,287 Production taxes 546 583 1,982 1,865 Gas gathering, marketing, and oilfield service 6,081 6,677 22,176 22,308 Exploration expense 2,296 1,940 5,956 4,901 General and administrative expense 1,099 1,243 3,261 3,244 Franchise, property and other taxes 93 117 297 401 Depreciation, depletion and amortization 6,489 6,242 18,666 21,539 Severance and other nonrecurring expense 312 -- 1,813 24 -------- -------- -------- -------- 22,959 22,023 71,360 69,569 -------- -------- -------- -------- OPERATING INCOME 7,947 5,167 28,016 13,957 OTHER (INCOME) EXPENSE Gain on sale of subsidiary and other income -- (86) -- (14,512) Interest expense 6,819 7,098 20,866 22,114 -------- -------- -------- -------- INCOME (LOSS) BEFORE INCOME TAXES AND EXTRAORDINARY ITEM 1,128 (1,845) 7,150 6,355 Provision (benefit) for income taxes 446 (670) 614 1,484 -------- -------- -------- -------- INCOME (LOSS) BEFORE EXTRAORDINARY ITEM 682 (1,175) 6,536 4,871 Extraordinary item - early extinguishment of debt, net of tax benefit -- (1,360) -- (1,360) -------- -------- -------- -------- NET INCOME (LOSS) $ 682 $ (2,535) $ 6,536 $ 3,511 ======== ======== ======== ========
See accompanying notes. 2 BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY (DEFICIT) (in thousands)
ACCUMULATED OTHER COMMON COMMON PAID IN COMPREHENSIVE TOTAL SHARES STOCK CAPITAL DEFICIT INCOME DEFICIT ---------- ---------- ---------- ----------- ---------- ----------- JANUARY 1, 1999 10,111 $ 1,011 $ 107,897 $(141,922) $ -- $ (33,014) Net loss (18,303) (18,303) Stock options exercised 31 3 3 Stock-based compensation 118 12 (288) (276) ----------------------------------------------- ---------- ---------- ---------- ---------- --------- --------- DECEMBER 31, 1999 10,260 1,026 107,609 (160,225) -- (51,590) Net income 2,961 2,961 Stock options exercised 97 10 (9) 1 Stock-based compensation 336 336 Treasury stock (54) (6) (15) (21) ----------------------------------------------- ---------- ---------- ---------- ---------- --------- --------- DECEMBER 31, 2000 10,303 1,030 107,921 (157,264) -- (48,313) Comprehensive income: Net income 6,536 6,536 Other comprehensive income, net of tax: Cumulative effect of accounting change (6,691) (6,691) Change in derivative fair value 23,178 23,178 Reclassification adjustments - contract settlements 743 743 --------- Total comprehensive income 23,766 --------- Stock options exercised 67 7 (1) 6 Stock-based compensation 379 379 Repurchase of stock options (670) (670) Treasury stock (47) (5) (164) (169) ----------------------------------------------- ---------- ---------- ---------- ---------- --------- --------- SEPTEMBER 30, 2001 (UNAUDITED) 10,323 $ 1,032 $ 107,465 $(150,728) $ 17,230 $ (25,001) =============================================== ========== ========== ========== ========== ========= =========
Total comprehensive income in the quarter ended September 30, 2001, was $7.3 million. A net gain of $3.2 million was reclassified to earnings from accumulated other comprehensive income in the quarter ended September 30, 2001. See accompanying notes. 3 BELDEN & BLAKE CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) (IN THOUSANDS)
NINE MONTHS ENDED SEPTEMBER 30, ------------------------------- 2001 2000 --------- --------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 6,536 $ 3,511 Adjustments to reconcile net income to net cash provided by operating activities: Net loss on early extinguishment of debt -- 1,360 Depreciation, depletion and amortization 18,666 21,539 Gain on sale of subsidiary -- (13,241) Loss on disposal of property and equipment 142 295 Exploration expense 5,956 4,901 Deferred income taxes 521 1,397 Stock-based compensation 379 (30) Change in operating assets and liabilities, net of effects of disposition of subsidiary: Accounts receivable and other operating assets 7,371 (1,848) Inventories 107 (366) Accounts payable and accrued expenses 2,939 7,696 --------- --------- NET CASH PROVIDED BY OPERATING ACTIVITIES 42,617 25,214 CASH FLOWS FROM INVESTING ACTIVITIES: Acquisition of businesses, net of cash acquired (2,130) -- Disposition of businesses, net of cash 400 69,031 Proceeds from property and equipment disposals 1,162 157 Exploration expense (5,956) (4,901) Additions to property and equipment (28,826) (14,363) Increase in other assets (72) (164) --------- --------- NET CASH (USED IN) PROVIDED BY INVESTING ACTIVITIES (35,422) 49,760 CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from revolving line of credit 137,921 80,161 Repayment of long-term debt and other obligations (144,367) (149,244) Debt issue costs (210) (5,012) Proceeds from stock options exercised 6 -- Repurchase of stock options (670) -- Purchase of treasury stock (169) (19) --------- --------- NET CASH USED IN FINANCING ACTIVITIES (7,489) (74,114) --------- --------- NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS (294) 860 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 1,798 4,536 --------- --------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 1,504 $ 5,396 ========= ========= CASH PAID DURING THE PERIOD FOR: Interest $ 15,530 $ 17,677 Income taxes, net of refunds 359 -- NON-CASH INVESTING AND FINANCING ACTIVITIES: Acquisition of assets in exchange for long-term liabilities 443 239
See accompanying notes. 4 BELDEN & BLAKE CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) SEPTEMBER 30, 2001 ------------------------------------------------------------------------------- (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, 2001 are not necessarily indicative of the results that may be expected for the year ended December 31, 2001. 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, 2000. Certain reclassifications have been made to conform to the current presentation. (2) NEW ACCOUNTING PRONOUNCEMENTS In July 2001, the Financial Accounting Standards Board (FASB) issued Statements of Financial Accounting Standards No. (SFAS) 141, "Business Combinations," and SFAS 142, "Goodwill and Other Intangible Assets." Adoption of these standards is not expected to have a material effect on the Company's financial position, results of operations or cash flows. SFAS 141 eliminates the pooling-of-interests method of accounting for business combinations except for qualifying business combinations that were initiated prior to July 1, 2001. SFAS 141 further clarifies the criteria to recognize intangible assets separately from goodwill. The requirements of SFAS 141 are effective for any business combination accounted for by the purchase method that is completed after June 30, 2001. Under SFAS 142, goodwill and indefinite lived intangible assets are no longer amortized but are reviewed for impairment annually or if certain impairment indicators arise. Separable intangible assets that are not deemed to have an indefinite life will continue to be amortized over their useful lives (but with no maximum life). The amortization provisions of SFAS 142 apply to goodwill and intangible assets acquired after June 30, 2001. With respect to goodwill and intangible assets acquired prior to July 1, 2001, companies are required to adopt SFAS 142 in their fiscal year beginning after December 15, 2001. Early adoption is not permitted for calendar year companies. Because of the different transition dates for goodwill and intangible assets acquired on or before June 30, 2001 and those acquired after that date, pre-existing goodwill and intangibles will be amortized during this transition period until adoption whereas new goodwill and indefinite lived intangible assets acquired after June 30, 2001 will not. In August 2001, the FASB issued SFAS 143, "Accounting for Asset Retirement Obligations." SFAS 143 addresses obligations associated with the retirement of tangible, long-lived assets and the associated asset retirement costs. This statement amends SFAS 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies", and is effective for financial statements issued for fiscal years beginning after June 15, 2002. The Company is currently assessing the impact of SFAS 143 and has not yet determined whether adoption will have a material effect on the Company's financial position, results of operations or cash flows. In October 2001, the FASB issued SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which establishes a single accounting model to be used for long-lived assets, to be 5 disposed of. The new rules supersede SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." Although retaining many of the fundamental recognition and measurement provisions of SFAS 121, the new rules significantly change the criteria that would have to be met to classify an asset as held-for-sale. This distinction is important because assets to be disposed of are stated at the lower of their fair values or carrying amounts and depreciation is no longer recognized. The new rules also will supersede the provisions of APB Opinion 30 with regard to reporting the effects of a disposal of a segment of a business and will require the expected future operating losses from discontinued operations to be displayed in discontinued operations in the periods in which the losses are incurred rather than as of the measurement date as presently required by APB 30. In addition, more dispositions will qualify for discontinued operations treatment in the income statement. SFAS 144 is effective for fiscal years beginning after December 15, 2001. The adoption of this standard is not expected to have a material effect on the Company's financial position, results of operations or cash flows. (3) CREDIT AGREEMENT On June 29, 2001, the Company amended its $100 million revolving credit facility ("the Revolver") from Ableco Finance LLC and Foothill Capital Corporation. The amendment extended the Revolver's final maturity date to April 22, 2004, from August 23, 2002, increased the letter of credit sub-limit from $20 million to $30 million and eliminated the effects of SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," from covenant calculations. The Company paid approximately $200,000 in fees and expenses related to the amendment. The amendment extended the financial covenant for the senior interest coverage ratio of 3.2 to 1 for the quarters ending September 30, 2002, through March 31, 2004; and the senior debt leverage ratio of 2.7 to 1 was extended for the quarters ending September 30, 2002, through March 31, 2004. These ratios will be calculated quarterly based on the financial results of the previous four quarters. The amendment added an early termination fee equal to .25% of the facility if terminated between the effective date and May 31, 2002. If termination is after May 31, 2002 but on or before May 31, 2003, the termination fee is .125% of the facility. There is no termination fee after May 31, 2003. The Company is required to hedge at least 20% but not more than 80% of its estimated hydrocarbon production, on an Mcfe (thousand cubic feet of natural gas equivalent) 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 June 2003. (4) SEVERANCE AND OTHER NONRECURRING EXPENSE Effective April 1, 2001, certain senior management members of the Company accepted early retirements. These retirements will result in a cash charge of approximately $760,000 and an additional non-cash charge of $100,000 related to the acceleration of certain stock options. The Company recorded severance and other nonrecurring expense of $1.8 million in the first nine months of 2001 related to these retirement agreements and other severance charges incurred which included non-cash charges totaling approximately $200,000 due to the acceleration of certain related stock options. (5) DERIVATIVES AND HEDGING As of January 1, 2001, the Company adopted SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," as amended. As a result of the adoption of SFAS 133, 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). Under the provisions of SFAS 6 133, changes in the fair value of derivative instruments that are fair value hedges are offset against changes in the fair value of the hedged assets, liabilities, or firm commitments, through net income (loss). Changes in the fair value of derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time as the hedged items are recognized in net income (loss). The hedging relationship between the hedging instruments and hedged item must be highly effective in achieving the offset of changes in fair values or cash flows attributable to the hedged risk both at the inception of the contract and on an ongoing basis. The Company measures effectiveness on a monthly 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. 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, 2001, the Company's derivative contracts consist of natural gas swaps and natural gas costless collars. All of these NYMEX based derivative contracts are designated as cash flow hedges. Adoption of SFAS 133 resulted in recording a $10.5 million ($6.7 million net of tax) decline in fair value to accumulated other comprehensive loss, consisting of $11.8 million to current fair value of derivative liabilities and $1.3 million to current fair value of derivative assets. The fair value of derivative assets represent the difference between hedged prices and market prices on hedged volumes of natural gas as of September 30, 2001. During the first nine months of 2001, a net loss on contract settlements of $1.0 million ($743,000 after tax) was reclassified from accumulated other comprehensive income to earnings and the fair value of open hedges increased by $37.5 million ($23.2 million after tax). At September 30, 2001, the estimated net gains in accumulated other comprehensive income that are expected to be reclassified into earnings within the next 12 months are approximately $20.6 million. The Company has partially hedged its exposure to the variability in future cash flows through December 2003. (6) INCOME TAX During the second quarter, the Company concluded an IRS income tax examination of the years 1994 through 1997. A federal income tax benefit of $1.5 million was recorded during the quarter as a result of the examination. Also, in the second quarter, a federal income tax benefit was recorded for approximately $700,000 along with a corresponding reduction in the valuation allowance as a result of certain net operating loss carryforwards which the Company now believes it can fully utilize. (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 gathering natural gas for delivery to intrastate and interstate gas transmission pipelines. The Company's operations are conducted entirely in the United States. 7 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS On March 17, 2000, the Company sold the stock of Peake Energy, Inc. ("Peake"), a wholly owned subsidiary, to an independent oil and gas company, with an effective date of January 1, 2000. The sale included substantially all of the Company's oil and gas properties in West Virginia and Kentucky. The sale resulted in net proceeds of approximately $69 million. The Company recorded a $13.2 million gain on the sale in the first quarter of 2000. The following table presents certain information with respect to the oil and gas operations of the Company. The last column in the table excludes Peake:
EXCLUDING PEAKE --------------- THREE MONTHS ENDED NINE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30, ------------------ ----------------- ----------------- 2001 2000 2001 2000 2001 2000 ---- ---- ---- ---- ---- ---- PRODUCTION Gas (Mmcf) 4,680 4,815 13,713 15,369 13,713 14,215 Oil (Mbbls) 173 144 490 450 490 434 Total production (Mmcfe) 5,717 5,677 16,653 18,071 16,653 16,818 AVERAGE PRICE Gas (per Mcf) $ 4.03 $ 3.04 $ 4.39 $ 2.84 $ 4.39 $ 2.85 Oil (per Bbl) 23.55 28.70 24.74 26.80 24.74 26.87 Mcfe 4.01 3.31 4.34 3.08 4.34 3.10 AVERAGE COSTS (PER MCFE) Production expense 1.06 0.92 1.03 0.85 1.03 0.87 Production taxes 0.10 0.10 0.12 0.10 0.12 0.09 Depletion 0.86 0.75 0.79 0.83 0.79 0.84 GROSS MARGIN (PER MCFE) 2.85 2.29 3.19 2.13 3.19 2.14
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 RESULTS OF OPERATIONS - THIRD QUARTERS OF 2001 AND 2000 COMPARED Operating income increased $2.7 million (54%) from $5.2 million in the third quarter of 2000 to $7.9 million in the third quarter of 2001. This increase was primarily a result of a $3.7 million (26%) increase in operating margins partially offset by a $356,000 increase in exploration expense, a $247,000 increase in depreciation, depletion and amortization, and $312,000 of severance and other nonrecurring expense in the third quarter of 2001. The increase in operating margins was primarily due to a $3.4 million increase in the operating margin from oil and gas sales primarily due to a $.99 per Mcf increase in the average price realized for the Company's natural gas. Net income increased $3.2 million from a net loss of $2.5 million in the third quarter of 2000 to net income of $682,000 in the third quarter of 2001. This increase was primarily a result of the increase in operating income discussed above, a $279,000 decrease in interest expense and a $1.4 million (net of tax benefit) extraordinary loss from the early extinguishment of debt in 2000 offset by a $1.1 million increase in the provision for income taxes. 8 Earnings before interest expense, income taxes, depreciation, depletion, amortization, exploration expense and severance and other nonrecurring items ("EBITDAX") increased $3.7 million (28%) from $13.3 million in the third quarter of 2000 to $17.0 million in the third quarter of 2001 primarily due to the increased operating margins discussed above. Total revenues increased $3.7 million (14%) in the third quarter of 2001 compared to the third quarter of 2000 primarily due to a $.99 per Mcf increase in the average price realized for the Company's natural gas. Oil volumes increased 29,000 Bbls (20%) from 144,000 Bbls in the third quarter of 2000 to 173,000 Bbls in the third quarter of 2001 resulting in an increase in oil sales of approximately $840,000. The increased oil volumes were primarily due to new wells drilled in 2000 and 2001. Gas volumes decreased 135 Mmcf (3%) from 4.8 Bcf (billion cubic feet) in the third quarter of 2000 to 4.7 Bcf in the third quarter of 2001 resulting in a decrease in gas sales of approximately $410,000. The average price paid for the Company's oil decreased from $28.70 per Bbl in the third quarter of 2000 to $23.55 per Bbl in the third quarter of 2001 which decreased oil sales by approximately $890,000. The average price realized for the Company's natural gas increased $.99 per Mcf to $4.03 per Mcf in the third quarter of 2001 compared to the third quarter of 2000 which increased gas sales in the third quarter of 2001 by approximately $4.6 million. As a result of the Company's hedging activities, gas sales revenue for the third quarter of 2001 increased by approximately $3.2 million or $.67 per Mcf compared to a decrease of approximately $4.4 million or $.92 per Mcf for the third quarter of 2000. Production expense increased $822,000 (16%) from $5.2 million in the third quarter of 2000 to $6.0 million in the third quarter of 2001. The average production cost increased from $.92 per Mcfe in the third quarter of 2000 to $1.06 per Mcfe in the third quarter of 2001 primarily due to additional costs incurred in the third quarter of 2001 to minimize production declines in order to take advantage of higher gas prices and general cost increases due to current market conditions. Production taxes were $583,000 in the third quarter of 2000 compared to $546,000 in the third quarter of 2001. Exploration expense increased $356,000 (18%) from $1.9 million in the third quarter of 2000 to $2.3 million in the third quarter of 2001 primarily due to a $379,000 increase in dry hole expense. General and administrative expense decreased $144,000 (12%) from $1.2 million in the third quarter of 2000 to $1.1 million in the third quarter of 2001 primarily due to decreases in employment and compensation related expenses. Depreciation, depletion and amortization increased by $247,000 (4%) from $6.2 million in the third quarter of 2000 to $6.5 million in the third quarter of 2001. Depletion expense increased $650,000 (15%) from $4.3 million in the third quarter of 2000 to $4.9 million in the third quarter of 2001. Depletion per Mcfe increased from $.75 per Mcfe in the third quarter of 2000 to $.86 per Mcfe in the third quarter of 2001. These increases were primarily the result of a higher amortization rate per Mcfe due to lower reserves resulting from lower oil and gas prices at mid-year 2001, excluding the effect of hedging. The Company incurred severance and other nonrecurring expense of $312,000 in the third quarter of 2001 related to employee reduction costs. 9 Interest expense decreased $279,000 (4%) from $7.1 million in the third quarter of 2000 to approximately $6.8 million in the third quarter of 2001 due to a decrease in average outstanding borrowings and lower blended interest rates. RESULTS OF OPERATIONS - NINE MONTHS OF 2001 AND 2000 COMPARED Operating income increased $14.0 million from $14.0 million in the first nine months of 2000 to $28.0 million in the first nine months of 2001. This increase was primarily a result of a $15.0 million (36%) increase in operating margins and a $2.8 million (13%) decrease in depreciation, depletion and amortization expense partially offset by a $1.1 million decrease in other income, a $1.1 million (22%) increase in exploration expense and the $1.8 million of severance and other nonrecurring expense recorded in the first nine months of 2001. The increase in operating margins was primarily due to a $14.6 million increase in the operating margin from oil and gas sales primarily as a result of a $1.55 per Mcf increase in the average price realized for the Company's natural gas. The decrease in other income was primarily due to a reduction in income from the monetization of nonconventional fuel source tax credits as a result of the Peake sale and proceeds received in the second quarter of 2000 from the settlement of a lawsuit. Net income increased $3.0 million from $3.5 million in the first nine months of 2000 to $6.5 million in the first nine months of 2001. Gain on sale of subsidiary and other income in the first nine months of 2000 was $14.5 million as discussed below. Significant changes in the first nine months of 2001 compared to the first nine months of 2000 were the $14.0 million increase in operating income discussed above, a $1.2 million decrease in interest expense, favorable adjustments to income tax expense in the second quarter of 2001 (see Note 6 to the Consolidated Financial Statements) and a $1.4 million (net of tax benefit) extraordinary loss from the early extinguishment of debt in the first nine months of 2000. EBITDAX increased $14.1 million (35%) from $40.4 million in the first nine months of 2000 to $54.5 million in the first nine months of 2001. This increase was primarily due to the $15.0 million increase in operating margins offset by the decrease in other income discussed above. Total revenues increased $15.9 million (19%) in the first nine months of 2001 compared to the first nine months of 2000 primarily due to a $1.55 per Mcf increase in the average price realized for the Company's natural gas, an increase in the volume of oil sold and an increase in oilfield service revenue partially offset by a decrease in the volume of natural gas sold, a decrease in the price paid for the Company's oil and the decrease in other income discussed above. Oil volumes increased approximately 40,000 Bbls (9%) from 450,000 Bbls in the first nine months of 2000 to 490,000 Bbls in the first nine months of 2001 resulting in an increase in oil sales of approximately $1.1 million. Gas volumes decreased 1.7 Bcf (11%) from 15.4 Bcf in the first nine months of 2000 to 13.7 Bcf in the first nine months of 2001 resulting in a decrease in gas sales of approximately $4.7 million. These volume decreases were due to the sale of Peake in the first quarter of 2000 and the natural production decline of the wells partially offset by production from wells drilled in 2000 and 2001. The average price paid for the Company's oil decreased from $26.80 per Bbl in the first nine months of 2000 to $24.74 per Bbl in the first nine months of 2001 which decreased oil sales by approximately $1.0 million. The average price realized for the Company's natural gas increased $1.55 per Mcf (55%) to $4.39 per Mcf in the first nine months of 2001 compared to the first nine months of 2000 which increased gas sales in the first nine months of 2001 by approximately $21.3 million. As a 10 result of the Company's hedging activities, gas sales revenue for the first nine months of 2001 decreased by approximately $1.0 million or $.07 per Mcf compared to a decrease of approximately $7.3 million or $.47 per Mcf for the first nine months of 2000. Production expense increased approximately $1.9 million (13%) from $15.3 million in the first nine months of 2000 to $17.2 million in the first nine months of 2001. The average production cost increased from $.85 per Mcfe in the first nine months of 2000 to $1.03 per Mcfe in the first nine months of 2001. The per unit increase was primarily due to the sale of Peake, increased compensation related expenses, additional costs incurred in the first nine months of 2001 to minimize production declines in order to take advantage of higher gas prices and general cost increases due to current market conditions. Production taxes increased $117,000 (6%) from $1.9 million in the first nine months of 2000 to $2.0 million in the first nine months of 2001 primarily due to higher natural gas prices in 2001 partially offset by decreased production taxes from lower oil and gas sales due to the sale of Peake. Exploration expense increased by $1.1 million (22%) from $4.9 million in the first nine months of 2000 to $6.0 million in the first nine months of 2001 primarily due to increases in leasing activity and geophysical expenses associated with the Company's planned drilling activity in 2001 and 2002. The Company currently expects to spend $26 million to drill 175 gross (152.4 net) wells in 2001. General and administrative expense in the first nine months of 2001 was consistent with the first nine months of 2000. Depreciation, depletion and amortization decreased by $2.8 million (13%) from $21.5 million in the first nine months of 2000 to $18.7 million in the first nine months of 2001. Depletion expense decreased $1.8 million (12%) from $15.0 million in the first nine months of 2000 to $13.2 million in the first nine months of 2001. Depletion per Mcfe decreased from $.83 per Mcfe in the first nine months of 2000 to $.79 per Mcfe in the first nine months of 2001. These decreases were primarily the result of decreased production volumes due to the sale of Peake and a lower amortization rate per Mcfe due to higher reserves resulting from higher oil and gas prices at year-end 2000. The Company recorded a nonrecurring charge of $1.8 million in the first nine months of 2001 primarily related to the early retirement of certain senior management members of the Company and other severance charges incurred which included a non-cash charge of approximately $200,000 due to the acceleration of certain related stock options. The Company expects to reduce its forecasted future general and administrative expenses by over $500,000 annually as a result of the retirements. Gain on sale of subsidiary and other income in the first nine months of 2000 was the result of the $13.2 million gain on the sale of Peake and the $1.3 million gain on terminated interest rate swaps. Interest expense decreased approximately $1.2 million (6%) from $22.1 million in the first nine months of 2000 to $20.9 million in the first nine months of 2001 due to a decrease in average outstanding borrowings partially offset by higher blended interest rates. 11 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, 2001 was 1.17 to 1. During the first nine months of 2001, working capital increased $1.7 million from $4.2 million at December 31, 2000 to $5.9 million at September 30, 2001. The increase was primarily due to an increase in the fair value of derivatives in the first nine months of 2001 which increased working capital by $20.6 million, net of a related increase in current deferred taxes of $8.1 million. This increase was offset by a $7.9 million decrease in accounts receivable and a $3.7 million increase in accrued expenses. The Company's operating activities provided cash flows of $42.6 million during the first nine months of 2001. On June 29, 2001, the Company amended its $100 million credit facility from Ableco Finance LLC and Foothill Capital Corporation. The amendment extended the Revolver's final maturity date to April 22, 2004, from August 23, 2002, increased the letter of credit sub-limit from $20 million to $30 million and eliminated the effects of SFAS 133 from covenant calculations. The Company paid approximately $200,000 in fees and expenses related to the amendment. The amendment extended the financial covenant for the senior interest coverage ratio of 3.2 to 1 for the quarters ending September 30, 2002, through March 31, 2004; and the senior debt leverage ratio of 2.7 to 1 was extended for the quarters ending September 30, 2002, through March 31, 2004. These ratios will be calculated quarterly based on the financial results of the previous four quarters. The amendment added an early termination fee equal to .25% of the facility if terminated between the effective date and May 31, 2002. If termination is after May 31, 2002 but on or before May 31, 2003, the termination fee is .125% of the facility. There is no termination fee after May 31, 2003. The Company is required to hedge at least 20% but not more than 80% of its estimated hydrocarbon production, on an Mcfe basis, for the succeeding 12 months on a rolling 12 month basis. Based on the Company's hedges currently in place and its expected production levels, the Company is in compliance with this hedging requirement through June 2003. The Revolver bears interest at the prime rate plus two percentage points, payable monthly. At September 30, 2001 the interest rate was 8.00%. At September 30, 2001, the Company had $2.3 million of outstanding letters of credit. At September 30, 2001, the outstanding balance under the credit agreement was $55.1 million with $42.6 million of borrowing capacity available for general corporate purposes. 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 value of the Company's proved developed producing reserves subject to a mortgage; (ii) 45% of the value of the Company's proved developed non-producing reserves subject to a mortgage; and (iii) 40% of the value of the Company's proved undeveloped reserves subject to a mortgage. The price forecast used for calculation of the future net income from proved reserves is the three-year NYMEX strip for oil and natural gas as of the date of the reserve report. Prices beyond three years are held constant. Prices are adjusted for basis differential, fixed price contracts and financial hedges in place. The present value (using a 10% discount rate) of the Company's future net income at September 30, 2001, under the borrowing base formula above was approximately $201 million for all proved reserves of the Company and $152 million for properties secured by a mortgage. 12 The Revolver is subject to certain financial covenants. These include a senior debt interest coverage ratio ranging from 4.0 to 1 at September 30, 2001, to 3.2 to 1 at March 31, 2004; and a senior debt leverage ratio ranging from 2.6 to 1 and 3.2 to 1 for the periods from September 30, 2001, through March 31, 2004. 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 trailing 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, 2001, the Company's current ratio including the above adjustments was 2.25 to 1. The Company has satisfied all financial covenants as of September 30, 2001. 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. At September 30, 2000, the Company had swap arrangements, which expired in October 2000, covering $40 million of debt. The Company's interest expense was reduced by $123,000 in the first nine months of 2000 due to interest rate swaps. There were no interest rate swaps open in the first nine months of 2001. During the first nine months of 2001, the Company invested $21.7 million to drill 140 development wells and 9 exploratory wells. Of these wells, 131 development wells and 3 exploratory wells were successfully completed as producers, for a completion success rate of 94% and 33%, respectively (an overall success rate of 90%). In addition, $2.1 million was invested in proved reserve acquisitions. The Company currently expects to spend approximately $41 million during 2001 on its drilling activities, acquisitions and other capital expenditures. The Company intends to finance its planned capital expenditures through its available cash flow, available borrowing capacity under the Revolver and the sale of non strategic assets. At September 30, 2001, the Company had approximately $42.6 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. 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 pretax losses on its hedging activities of $1.0 million and $7.3 million in the first nine months of 2001 and 2000, respectively. 13 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), fixed price contracts and costless collars at September 30, 2001:
NATURAL GAS SWAPS FIXED PRICE CONTRACTS ------------------------------------------- ---------------------------- ESTIMATED ESTIMATED NYMEX PRICE WELLHEAD ESTIMATED WELLHEAD QUARTER ENDING BBTU PER MMBTU PRICE PER MCF MMCF PRICE PER MCF -------------- ---- --------- ------------- ---- ------------- December 31, 2001 2,400 $ 4.77 $ 4.99 1,000 $ 4.42 ======= ====== ====== ====== ====== March 31, 2002 2,550 $ 4.95 $ 5.20 1,050 $ 4.57 June 30, 2002 2,550 4.61 4.76 780 4.25 September 30, 2002 2,550 4.61 4.76 630 4.30 December 31, 2002 2,550 4.63 4.84 560 4.45 ------- ------ ------ ------ ------ 10,200 $ 4.70 $ 4.89 3,020 $ 4.41 ======= ====== ====== ====== ====== March 31, 2003 960 $ 3.79 $ 4.04 65 $ 2.50 June 30, 2003 960 3.79 3.94 65 2.50 September 30, 2003 960 3.79 3.94 65 2.50 December 31, 2003 960 3.79 3.99 65 2.50 ------- ------ ------ ------ ------ 3,840 $ 3.79 $ 3.98 260 $ 2.50 ======= ====== ====== ====== ======
NATURAL GAS COLLARS -------------------------------------------- NYMEX PRICE ESTIMATED PER MMBTU WELLHEAD QUARTER ENDING BBTU FLOOR/CAP PRICE PER MCF -------------- ------- ------------ ------------- March 31, 2003 1,650 $3.40 - 5.23 $ 3.60 - 5.43 June 30, 2003 1,650 3.40 - 5.23 3.60 - 5.43 September 30, 2003 1,650 3.40 - 5.23 3.60 - 5.43 December 31, 2003 1,650 3.40 - 5.23 3.60 - 5.43 ------- ------------ ------------- 6,600 $3.40 - 5.23 $ 3.60 - 5.43 ======= ============ =============
BBTU - BILLION BRITISH THERMAL UNITS MMCF - MILLION CUBIC FEET MMBTU - MILLION BRITISH THERMAL UNITS MCF - THOUSAND CUBIC FEET At September 30, 2001, the natural gas swaps and collars above represented approximately $28.0 million in unrealized gains. 14 FORWARD-LOOKING INFORMATION The forward-looking statements regarding future operating and financial performance contained in this report involve risks and uncertainties that include, but are not limited to, the Company's availability of capital, production and costs of operation, the market demand for and prices of oil and natural gas, results of the Company's future drilling, the uncertainties of reserve estimates, environmental risks, availability of financing and other factors detailed in the Company's filings with the Securities and Exchange Commission. Actual results may differ materially from forward-looking statements made in this report. ------------------------------------------------------------------------------- PART II OTHER INFORMATION Item 6. Exhibits and Reports on Form 8-K (a) Exhibits (b) Reports on Form 8-K On July 5, 2001, the Company filed a Current Report on Form 8-K dated June 29, 2001 related to the amendment of the Company's revolving credit facility and Regulation FD disclosures. On July 11, 2001, the Company filed a Current Report on Form 8-K dated June 29, 2001 related to an exploration agreement and joint operating agreement. On August 9, 2001, the Company filed a Current Report on Form 8-K dated August 8, 2001 related to Regulation FD disclosures. On September 19, 2001, the Company filed a Current Report on Form 8-K dated September 12, 2001 related to the resignation of certain directors. 15 SIGNATURES ------------------------------------------------------------------------------- Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. BELDEN & BLAKE CORPORATION Date: November 12, 2001 By: /s/ John L. Schwager ----------------- -------------------------------------- John L. Schwager, Director, President and Chief Executive Officer Date: November 12, 2001 By: /s/ Robert W. Peshek ----------------- --------------------------------------- Robert W. Peshek, Vice President and Chief Financial Officer 16