================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 -------------------------- FORM 10-Q (Mark one) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended June 30, 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 0-9592 RANGE RESOURCES CORPORATION (Exact name of registrant as specified in its charter) DELAWARE 34-1312571 (State of or other jurisdiction (I.R.S. Employer of incorporation or organization) Identification No.) 777 MAIN STREET, SUITE 800 FT. WORTH, TEXAS (Address of principal executive offices) 76102 (Zip Code) Registrant's telephone number, including area code: (817) 870-2601 Former name, former address and former fiscal year, if changed since last report: Not applicable 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. Yes [X] No [ ] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes [X] No [ ] 56,002,697 Common Shares were outstanding on July 31, 2003. PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS The financial statements included herein should be read in conjunction with latest Form 10-K for Range Resources Corporation (the "Company"). The statements are unaudited but reflect all adjustments which, in the opinion of management, are necessary to fairly present the Company's financial position and results of operations. All adjustments are of a normal recurring nature unless otherwise noted. These financial statements, including selected notes, have been prepared in accordance with the applicable rules of the Securities and Exchange Commission (the "SEC") and do not include all of the information and disclosures required by accounting principles generally accepted in the United States for complete financial statements. 2 RANGE RESOURCES CORPORATION CONSOLIDATED BALANCE SHEETS (IN THOUSANDS) DECEMBER 31, JUNE 31, 2002 2003 ------------ ----------- ASSETS (Unaudited) Current assets Cash and equivalents $ 1,334 $ 1,309 Accounts receivable 26,832 39,394 IPF receivables, net (Note 2) 6,100 5,500 Unrealized derivative gain (Note 2) 4 16 Inventory and other 3,084 2,301 Deferred tax asset, net (Note 13) - 25,284 ---------- ---------- 37,354 73,804 ---------- ---------- IPF receivables, net (Note 2) 18,351 10,767 Unrealized derivative gain (Note 2) 13 99 Oil and gas properties, successful efforts method (Note 16) 1,154,549 1,242,089 Accumulated depletion and depreciation (590,143) (606,789) ---------- ---------- 564,406 635,300 ---------- ---------- Transportation and field assets (Note 2) 34,143 35,714 Accumulated depreciation and amortization (16,071) (17,520) ---------- ---------- 18,072 18,194 ---------- ---------- Deferred tax asset, net (Note 13) 15,785 - Other (Note 2) 4,503 5,273 ---------- ---------- $ 658,484 $ 743,437 ========== ========== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities Accounts payable $ 27,044 $ 26,101 Asset retirement obligation (Note 3) - 16,399 Accrued liabilities 9,678 9,781 Accrued interest 4,449 4,342 Unrealized derivative loss (Note 2) 26,035 54,304 ---------- ---------- 67,206 110,927 ---------- ---------- Senior debt (Note 6) 115,800 110,600 Non-recourse debt (Note 6) 76,500 73,500 Subordinated notes (Note 6) 90,901 89,521 Trust preferred securities - manditorily redeemable security of subsidiary 84,840 84,440 Deferred tax credits, net (Note 13) - 1,991 Unrealized derivative loss (Note 2) 9,079 29,186 Deferred compensation liability (Note 11) 8,049 11,262 Asset retirement obligation (Note 3) - 38,825 Commitments and contingencies (Note 8) Stockholders' equity (Notes 9 and 10) Preferred stock, $1 par, 10,000,000 shares authorized, - - none issued or outstanding Common stock, $.01 par, 100,000,000 shares authorized, 550 559 54,991,611 and 55,952,379 issued and outstanding, respectively Capital in excess of par value 391,082 396,302 Stock held by employee benefit trust, and 1,324,537 1,605,992 shares, respectively, at cost (Note 11) (6,188) (7,867) Retained earnings (deficit) (158,059) (144,014) Deferred compensation expense (125) (157) Other comprehensive income (loss) (Note 2) (21,151) (51,638) ---------- ---------- 206,109 193,185 ---------- ---------- $ 658,484 $ 743,437 ========== ========== SEE ACCOMPANYING NOTES 3 RANGE RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED, IN THOUSANDS EXCEPT PER SHARE DATA) Three Months Six Months Ended June 30, Ended June 30, ----------------------- ----------------------- 2002 2003 2002 2003 ---------- ---------- ---------- ---------- Revenues Oil and gas sales $ 48,626 $ 55,273 $ 92,909 $ 109,603 Transportation and processing 924 940 1,698 1,967 IPF income (Note 2) 992 428 2,163 967 Gain (loss) on retirement of securities (Note 18) 845 (10) 2,030 140 Other (1,235) (1,913) (3,244) (985) ---------- ---------- ---------- ---------- 50,152 54,718 95,556 111,692 ---------- ---------- ---------- ---------- Expenses Direct operating 9,938 12,644 19,142 25,672 IPF 2,178 568 3,950 1,186 Exploration 2,172 2,687 7,443 5,140 General and administrative (Note 11) 4,733 5,313 9,203 10,159 Debt conversion and extinguishment expense (Note 6) - - - 465 Interest expense and dividends on trust preferred 6,274 5,175 11,631 10,719 Depletion, depreciation and amortization 19,304 21,276 37,404 42,243 ---------- ---------- ---------- ---------- 44,599 47,663 88,773 95,584 ---------- ---------- ---------- ---------- Income before income taxes and accounting change 5,553 7,055 6,783 16,108 Income taxes (Note 13) Current 45 (6) 45 (2) Deferred (1,802) 2,470 (4,913) 6,556 ---------- ---------- ---------- ---------- (1,757) 2,464 (4,868) 6,554 ---------- ---------- ---------- ---------- Income before cumulative effect of change in accounting principle 7,310 4,591 11,651 9,554 Cumulative effect of change in accounting principle (net of taxes of $2.4 million) (Note 3) - - - 4,491 ---------- ---------- ---------- ---------- Net income $ 7,310 $ 4,591 $ 11,651 $ 14,045 ========== ========== ========== ========== Comprehensive income (loss) (Note 2) $ (1,155) $ (10,594) $ (24,227) $ (16,442) ========== ========== ========== ========== Earnings per share (Note 14) Before cumulative effect of change in accounting principle - basic $ 0.14 $ 0.08 $ 0.22 $ 0.18 ========== ========== ========== ========== - diluted $ 0.13 $ 0.08 $ 0.22 $ 0.17 ========== ========== ========== ========== After cumulative effect of change in accounting principle - basic $ 0.14 $ 0.08 $ 0.22 $ 0.26 ========== ========== ========== ========== - diluted $ 0.13 $ 0.08 $ 0.22 $ 0.25 ========== ========== ========== ========== SEE ACCOMPANYING NOTES. 4 RANGE RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED, IN THOUSANDS) SIX MONTHS ENDED JUNE 30, ------------------------- 2002 2003 ---------- ---------- CASH FLOWS FROM OPERATIONS Net income $ 11,651 $ 14,045 Adjustments to reconcile net income to net cash provided by operations: Cumulative effect of change in accounting principle - (4,491) Deferred income tax expense (benefit) (4,913) 6,556 Depletion, depreciation and amortization 37,404 42,243 Write-down of marketable securities 1,220 - Unrealized hedging (gains) losses 2,090 1,188 Allowance for bad debts 2,567 708 Exploration expense 7,443 5,140 Amortization of deferred issuance costs 411 446 Gain on retirement of securities (2,055) (140) Debt conversion and extinguishment expense - 465 Deferred compensation adjustments 2,876 1,596 Gain on sale of assets (26) (157) Changes in working capital: Accounts receivable (3,511) (12,857) Inventory and other 556 783 Accounts payable 1,446 535 Accrued liabilities (3,702) 1,436 ---------- ---------- Net cash provided by operations 53,457 57,496 ---------- ---------- CASH FLOWS FROM INVESTING Oil and gas properties (37,692) (50,892) Field service assets (912) (1,592) IPF investments (2,729) (1,088) IPF repayments 4,263 8,698 Exploration expense (7,443) (5,140) Asset sales 20 302 ---------- ---------- Net cash used in investing (44,493) (49,712) ---------- ---------- CASH FLOWS FROM FINANCING Borrowings on senior debt and non-recourse debt 67,900 78,900 Repayments on senior debt and non-recourse debt (71,400) (87,100) Debt issuance costs (952) (684) Other debt repayments (4,981) (744) Issuance of common stock 1,214 1,819 ---------- ---------- Net cash used in financing (8,219) (7,809) ---------- ---------- Increase (decrease) in cash and cash equivalents 745 (25) Cash and equivalents, beginning of period 3,380 1,334 ---------- ---------- Cash and equivalents, end of period $ 4,125 $ 1,309 ========== ========== SEE ACCOMPANYING NOTES. 5 RANGE RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (1) ORGANIZATION AND NATURE OF BUSINESS The Company is engaged in the development, exploration and acquisition of oil and gas properties primarily in the Southwestern, Gulf Coast and Appalachian regions of the United States. To a minor extent, the Company also provides financing to smaller oil and gas producers through a wholly-owned subsidiary, Independent Producer Finance ("IPF"). The Company seeks to increase its reserves and production primarily through drilling and complementary acquisitions. The Company holds its Appalachian oil and gas assets through a 50% owned joint venture, Great Lakes Energy Partners L.L.C. ("Great Lakes"). The Company believes it has sufficient liquidity and cash flow to meet its obligations for the next twelve months. However, a material drop in oil and gas prices or a reduction in production and reserves would reduce its ability to fund capital expenditures, reduce debt and meet its future financial obligations. The Company operates in an environment with numerous financial and operating risks, including, but not limited to, the ability to acquire reserves on an attractive basis, the inherent risks of the search for, development and production of oil and gas, the ability to sell production at prices which provide an attractive return and the highly competitive nature of the industry. The Company's ability to expand its reserve base is, in part, dependent on obtaining sufficient capital through internal cash flow, borrowings or the issuance of debt or equity securities. (2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES BASIS OF PRESENTATION The accompanying consolidated financial statements include the accounts of the Company, wholly-owned subsidiaries and a 50% pro rata share of the assets, liabilities, income and expenses of Great Lakes. Liquid investments with original maturities of 90 days or less are considered cash equivalents. Certain reclassifications have been made to the presentation of prior periods to conform to current year presentation. These financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary for a fair presentation of the results for the periods presented. All such adjustments are of a normal recurring nature unless disclosed otherwise. REVENUE RECOGNITION The Company recognizes revenues from the sale of products and services in the period delivered. Payments received at IPF relating to return on investment are recognized as income; while remaining receipts reduce receivables. Although receivables are concentrated in the oil industry, the Company does not view this as an unusual credit risk. The Company had allowances for doubtful accounts relating to its exploration and production business of $835,000 and $826,000 at December 31, 2002 and June 30, 2003, respectively. 6 MARKETABLE SECURITIES Holdings of equity securities that qualify as available-for-sale are recorded at fair value. The Company owns approximately 18% of a small publicly traded exploration and production company. Based on its analysis of the investment and its assessment of realizing any value on the stock, the Company determined that the investment had no determinable value at June 30, 2002 and the book value of the investment was fully reserved. For the three months and the six months ended June 30, 2002, $851,000 and $1.2 million, respectively, was recorded as a reduction to Other revenues. This exploration and production company is currently involved in Chapter 11 bankruptcy proceedings. INDEPENDENT PRODUCER FINANCE IPF acquires dollar denominated royalties in oil and gas properties from small producers. The royalties are accounted for as receivables because the investment is recovered from a percentage of revenues until a specified return is received. Payments received that relate to the return on investment are recognized as income; while remaining receipts reduce receivables. No interest income is recorded on impaired receivables and any payments received that are applicable to impaired receivables are applied as a reduction of the receivable. Receivables classified as current represent the return on capital expected within 12 months. All receivables are evaluated quarterly and provisions for uncollectible amounts are established based on the Company's valuation of its royalty interest in the oil and gas properties. At December 31, 2002 and June 30, 2003, IPF's valuation allowance totaled $12.6 million and $10.7 million, respectively. The receivables are non-recourse and are from small independent operators who usually have limited access to capital and the property interests backing the receivables frequently lack diversification. Therefore, operational risk is substantial and there is significant risk that required maintenance and repairs, development and planned exploitation may be delayed or not accomplished. During the second quarter of 2003, IPF revenues were $428,000 offset by $209,000 of general and administrative costs, $60,000 of interest and a $299,000 increase in the valuation allowance. During the same period of the prior year, revenues were $992,000 offset by $476,000 of general and administrative expenses, $261,000 of interest and a $1.4 million increase in the valuation allowance. IPF's net receivables have declined from a high of $77.2 million in 1998 to $16.3 million at June 30, 2003, as IPF has focused on recovering its investment. The Company is continually assessing its strategic alternatives with regard to IPF. Since 2001, IPF has not entered into any new client financing agreements and therefore, the size of its portfolio should continue to decline due to collections. OIL AND GAS PROPERTIES The Company follows the successful efforts method of accounting. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Depletion is provided on the unit-of-production method. Oil is converted to gas equivalent basis ("mcfe") at the rate of six mcf per barrel. The depletion, depreciation an amortization ("DD&A") rates were $1.41 and $1.48 per mcfe in the quarters ended June 30, 2002 and 2003, respectively, and $1.38 and $1.49 for the six months ended June 30, 2002 and 2003, respectively. Unproved properties had a net book value of $19.0 million and $17.5 million at December 31, 2002 and June 30, 2003, respectively. The Company's long-lived assets are reviewed for impairment quarterly for events or changes in circumstances that indicate that the carrying amount of an asset may not be recoverable in accordance with SFAS No. 144. The review is done by determining if the historical cost of proved properties less the applicable accumulated depreciation, depletion and amortization is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on management's plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. Management estimates prices based upon market related information including published futures prices. In years where market information is not available, prices are escalated for inflation. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. When the carrying value exceeds such cash flows, an impairment loss is recognized for the difference between the estimated fair value and the carrying value of the assets. 7 TRANSPORTATION, PROCESSING AND FIELD ASSETS The Company's gas gathering systems are generally located in proximity to certain of its principal fields. Depreciation on these systems is provided on the straight-line method based on estimated useful lives of 10 to 15 years. The Company receives third party income for providing certain field services which are recognized as earned. These revenues approximated $500,000 in each of the three month periods ended June 30, 2002 and 2003. Depreciation on the field assets is calculated on the straight-line method based on estimated useful lives of five to seven years. Buildings are depreciated over 10 to 15 years. OTHER ASSETS The cost of issuing debt is capitalized and included in Other assets on the balance sheet. These costs are generally amortized over the expected life of the related securities (using the sum-of-the-years digits amortization method which management believes does not differ materially from the effective interest method). When a security is retired prior to maturity, related unamortized costs are expensed. At December 31, 2002 and June 30, 2003, these capitalized costs totaled $3.0 million and $3.3 million, respectively. At June 30, 2003, Other assets included $3.3 million unamortized debt issuance costs, $588,000 of long-term deposits, and $1.4 million of marketable securities held in a deferred compensation plan. GAS IMBALANCES The Company uses the sales method to account for gas imbalances, recognizing revenue based on cash received rather than gas produced. A liability is recognized when the imbalance exceeds the estimate of remaining reserves. Gas imbalances at December 31, 2002 and June 30, 2003 were immaterial. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING The Company enters into contracts to reduce the impact of volatile oil and gas prices. These contracts generally qualify as cash flow hedges; however, certain of the contracts have an ineffective portion (changes in realized prices that do not match the changes in hedge price) which is recognized in earnings. Historically, the Company's hedging program was based on fixed price swaps. In the second quarter of 2003, the hedging program was modified to include collars which establish a minimum floor price and a predetermined ceiling price. Gains or losses on open contracts are recorded in Other comprehensive income (loss) ("OCI"). The Company also enters into swap agreements to reduce the risk of changing interest rates. These agreements qualify as cash flow hedges whereby changes in the fair value of the swaps are reflected as an adjustment to OCI to the extent the swaps are effective and are recognized in income as an adjustment to interest expense in the period covered for the ineffective portion. In prior periods, certain of the interest rate swaps did not qualify as interest rate hedges which required the changes in fair value to be reported in interest expense. Derivatives are recorded on the balance sheet as assets or liabilities at fair value. For derivatives qualifying as hedges, the effective portion of changes in fair value is recognized in Stockholders' equity as OCI and reclassified to earnings when the transaction is closed (settled). Changes in the value of the ineffective portion of all open hedges are recognized in earnings as they occur. At June 30, 2003, the Company reflected an unrealized net pre-tax hedging loss on its balance sheet of $82.0 million. This accounting can greatly increase the volatility of earnings and stockholders' equity for companies that have hedging programs, such as the Company's hedging program. Earnings are affected by the ineffective portion of a hedge contract (changes in realized prices that do not match the changes in the hedge price). Ineffective gains or losses are recorded in Other revenue while the hedge contract is open and may increase or reverse until settlement of the contract. Stockholders' equity is affected by the increase or decrease in OCI. Typically, when oil and gas prices increase, OCI decreases. Of the $82.0 million unrealized pre-tax loss at June 30, 2003, $53.0 million of losses would be reclassified to earnings over the next twelve month period and $29.0 million for the periods thereafter, if prices remained constant. Actual amounts that will be reclassified will vary as a result of future changes in prices. The Company had hedge agreements with Enron North America Corp. ("Enron") for 22,700 Mmbtu per day at $3.20 per Mmbtu for the first three contract months of 2002. At December 31, 2001, based on accounting requirements, an allowance for bad debts of $1.4 million was recorded, offset by a $318,000 ineffective gain included in income and a $1.0 million gain included in OCI related to these defaulted hedge contracts. The gain included in OCI at year-end 2001 was included in Other revenue in the first quarter of 2002. In the three months 8 ended March 31, 2002, the Company wrote off this receivable against the allowance for bad debts. The last Enron contract expired in March 2002. Other revenues in the Consolidated Statements of Operations reflected ineffective hedging losses of $463,000 and $2.1 million for the three months ended June 30, 2002 and June 30, 2003, respectively, and a loss of $2.2 million and $1.3 million for the six months ended June 30, 2002 and 2003, respectively. Interest expense includes ineffective interest hedging losses of $300,000 and a gain of $154,000 for the three months ended June 30, 2002 and June 30, 2003, and gains of $72,000 and $83,000 for the six months ended June 30, 2002 and 2003, respectively. Unrealized hedging losses at June 30, 2003 are shown on the Company's balance sheet as net unrealized hedging losses of $83.4 million (including $1.4 million of losses on interest rate swaps) and OCI losses of $51.6 million (net of taxes) (see Note 7). COMPREHENSIVE INCOME Comprehensive income is defined as changes in Stockholders' equity from non-owner sources, which is calculated below (in thousands): Three Months Ended Six Months Ended June 30, June 30, ---------------------- ------------------------ 2002 2003 2002 2003 ---------- --------- -------- --------- Net income $ 7,310 $ 4,591 $ 11,651 $ 14,045 Net amount of hedging (gain) loss reclassed to earnings (3,639) 15,365 (15,365) 41,255 Change in unrealized losses, net (4,899) (30,393) (19,700) (71,618) Defaulted hedge contracts, net - - (672) - Unrealized loss (gain) from available-for-sale securities 73 (157) (141) (124) ---------- --------- -------- --------- Comprehensive income (loss) $ (1,155) $ (10,594) $(24,227) $ (16,442) ========== ========= ======== ========= USE OF ESTIMATES The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect reported assets, liabilities, revenues and expenses, as well as disclosure of contingent assets and liabilities. Actual results could differ from those estimates. Estimates which may significantly impact the financial statements include oil and gas reserves, impairment tests on oil and gas properties, IPF valuation allowance and the fair value of derivatives. RECENT ACCOUNTING PRONOUNCEMENTS In April 2002, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 145 "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement 13 and Technical Corrections" ("SFAS 145"). Extinguishment of debt will be accounted for in accordance with Accounting Principle Board ("APB") Opinion No. 30 "Reporting the Results of Operations, Reporting the effects of Disposal of a Segment of a Business and Extraordinary, Unusual and Infrequently Occurring Events and Transactions." As a result, gains from early extinguishment of debt will be reported in income from continuing operations. The Company adopted the provisions of SFAS 145 as of January 1, 2003. This adoption resulted in the reclassification of extraordinary gain on sale of securities totaling $845,000 to revenue in the three months and $2.0 million in the six months ended June 30, 2002, with no change to reported net income. In January 2003, the FASB issued Interpretation No. 46 "Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51" (the "Interpretation"). The Interpretation will significantly change whether entities included in its scope are consolidated by their sponsors, transferors, or investors. The Interpretation introduces a new consolidation model - the variable interest model - which determines control (and consolidation) based on potential variability in gains and losses of the entity being evaluated for consolidation. These provisions apply immediately to variable interests in VIE's created after January 15, 2003 and are effective 9 beginning in the third quarter of 2003 for VIE's in which the Company holds a variable interest that it acquired prior to February 1, 2003. The Company is still evaluating the impact of this new interpretation. In May 2003, the FASB issued Statement of Financial Accounting Standards No. 150 "Accounting or Certain Financial Instruments with Characteristics of Both Liabilities and Equity" ("SFAS 150"). SFAS 150 established standards for classification and measurement in the statement of financial position of certain financial instruments with characteristics of both liabilities and equity. It requires classification of a financial instrument that is within its scope as a liability (or an asset in some circumstances). SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. As the Company's 5-3/4% Trust Preferred Securities is currently presented as a long-term liability in the consolidated financial statements, the adoption of SFAS 150 is not expected to have a material impact on the Company's consolidated financial statements. The FASB and representatives of the accounting staff of the SEC are engaged in discussions on the issue of whether the FASB's No. 141 and 142, issued effective for June 30, 2001, called for mineral rights held under lease or other contractual arrangements to be classified in the balance sheet as intangible assets and accompanied by specific footnote disclosures. Historically, the Company and all other oil and gas companies have included the cost of these oil and gas leasehold interests as part of oil and gas properties. Although, most of the Company's oil and gas property interests are held under oil and gas leases, this interpretation, if adopted, would not have a material impact on the Company's financial condition or its results of operations. In the event this interpretation is adopted, a substantial portion of acquisition costs of oil and gas properties since June 30, 2001 would be separately classified on the balance sheets as intangible assets. As of June 30, 2003, the Company has expended approximately $23.6 million on the acquisition of oil and gas properties since June 30, 2001. Some additional direct costs of other oil and gas leases acquired since that date could also be categorized as intangible under this interpretation. Results of operations would not be affected by this interpretation, if adopted, since these costs would continue to be depleted in accordance with successful efforts accounting for oil and gas companies. Another possible effect of this interpretation, if adopted, could be a change in some of the financial measurements used in financial covenants of debt instruments that focus on tangible assets. The Company does not believe that its debt covenants would be materially affected by the adoption of this accounting interpretation. PROFORMA STOCK BASED COMPENSATION The Company has adopted the disclosure-only provisions of SFAS No. 123, "Accounting for Stock-Based Compensation" ("SFAS 123"). Accordingly, no compensation cost has been recognized for the stock option plans because the exercise prices employee stock options equals the market prices of the underlying stock on the date of grant. If compensation cost had been determined based on the fair value at the grant date for awards in the three months and the six months ended June 30, 2002 and 2003, consistent with the provisions of SFAS 123, the Company's net income and earnings per share would have been reduced to the pro forma amounts indicated below (in thousands, except per share data): 10 Three Months Ended Six Months Ended June 30, June 30, ----------------------- ----------------------- 2002 2003 2002 2003 ---------- ---------- ---------- ---------- Net income, as reported - $ 7,310 $ 4,591 $ 11,651 $ 14,045 Deduct: Total stock based employee compensation fair value based method for all awards, net of related tax effects 346 428 549 826 ---------- ---------- ---------- ---------- Pro forma net income $ 6,964 $ 4,163 $ 11,102 $ 13,219 ========== ========== ========== ========== Earnings per share: Basic-as reported $ 0.14 $ 0.08 $ 0.22 $ 0.26 Basic-pro forma $ 0.13 $ 0.08 $ 0.21 $ 0.24 Diluted-as reported $ 0.13 $ 0.08 $ 0.22 $ 0.25 Diluted-pro forma $ 0.13 $ 0.07 $ 0.21 $ 0.24 (3) ASSET RETIREMENT OBLIGATION Beginning in 2003, Statement of Financial Accounting Standards No. 143 "Asset Retirement Obligations" ("SFAS 143") requires the Company to recognize an estimated liability for the plugging and abandonment of its oil and gas wells and associated pipelines and equipment. Previously, the Company had recognized a plugging and abandonment obligation primarily for its offshore properties. This liability was shown netted against oil and gas properties on the balance sheet. Under SFAS 143, the Company now recognizes a liability for asset retirement obligations in the period in which they are incurred, if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. SFAS 143 requires the Company to consider estimated salvage value in the calculation of DD&A. Consistent with industry practice, historically the Company had assumed the cost of plugging and abandonment on its onshore properties would be offset by salvage value received. The adoption of SFAS 143 resulted in (i) an increase of total liabilities because retirement obligations are required to be recognized, (ii) an increase in the recognized cost of assets because the retirement costs are added to the carrying amount of the long-lived asset and (iii) an increase in DD&A expense, because of the accretion of the retirement obligation and increased basis. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment of oil and gas wells. The estimated liability is based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserves estimates, external estimates as to the cost to plug and abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate of 9%. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. The adoption of SFAS 143 as of January 1, 2003 resulted in a cumulative effect gain of $4.5 million (net of income taxes of $2.4 million) or $0.08 per share which is included in income in the six months ended June 30, 2003. The adoption resulted in a January 1, 2003 cumulative effect adjustment to record (i) a $37.3 million increase in the carrying values of proved properties, (ii) a $21.0 million decrease in accumulated depletion, (iii) a $2.3 million increase in current plugging and abandonment liabilities, (iv) a $49.1 million increase in non-current plugging and abandonment liabilities and (v) a $2.4 million decrease in deferred tax assets. The net impact of items (i) through (v) was to record a gain of $4.5 million, net of tax, as a cumulative effect adjustment of a change in accounting principle. The pro forma effects of the application of SFAS 143, as if the statement had been adopted net-of-tax on January 1, 2002 (rather than January 1, 2003), including an associated proforma asset retirement obligation on that date of $48.3 million, are presented below (in thousands, except per share data): 11 Pro Forma Pro Forma Three Months Ended June 30, Six Months Ended June 30, --------------------------- --------------------------- 2002 2003 2002 2003 ------------ ------------ ------------ ------------ Net income $ 7,029 $ 4,591 $ 15,715 $ 14,045 Earnings per share - basic $ 0.13 $ 0.08 $ 0.30 $ 0.26 - diluted $ 0.13 $ 0.08 $ 0.29 $ 0.25 A reconciliation of the Company's liability for plugging and abandonment costs for the six months ended June 30, 2003 is as follows (in thousands): Asset retirement obligation, December 31, 2002 $ - Cumulative effect adjustment 51,390 Liabilities incurred 2,011 Liabilities settled (448) Accretion expense 2,271 ------------ Asset retirement obligation, June 30, 2003 $ 55,224 ============ (4) ACQUISITIONS Acquisitions are accounted for under the purchase method. Purchase prices are assigned to acquired assets and assumed liabilities based on their estimated fair value at acquisition. The Company purchased various properties for $2.7 million and $9.7 million during the six months ended June 30, 2002 and 2003, respectively. These purchases include $75,000 and $6.3 million for proved oil and gas reserves, respectively, while the remainder represents unproved acreage purchases. (5) SUPPLEMENTAL CASH FLOW INFORMATION Six Months Ended June 30, ----------------------- 2002 2003 ---------- ---------- (in thousands) Non-cash investing and financing activities: Common stock issued Under benefit plans $ 1,528 $ 1,958 Exchanged for fixed income securities 8,359 1,370 Cash used in operating activities: Income taxes paid - - Interest paid $ 11,889 $ 10,596 The Company has and will continue to consider exchanging common stock or equity-linked securities for debt, despite the impact on its financial statements due to Statement of Financial Accounting Standards 84 (see Note 6). If, in the opinion of management, the transaction is favorable for the Company and its shareholders, the transaction will be executed. Existing stockholders may be materially diluted if substantial exchanges are consummated. The extent of dilution will depend on the number of shares and price at which common stock is issued, the price at which newly issued securities are convertible, and the price at which debt is acquired. 12 (6) INDEBTEDNESS The Company had the following debt and 5-3/4% Trust Convertible Preferred Securities ("Trust Preferred Securities") outstanding as of the dates shown (in thousands). Interest rates at June 30, 2003, excluding the impact of interest rate swaps, are shown parenthetically: December 31, June 30, 2002 2003 ------------ ---------- Senior debt: Senior Credit Facility (2.9%) $ 115,800 $ 110,600 ---------- ---------- Non-recourse debt: Great Lakes Credit Facility (2.9%) 76,500 73,500 ---------- ---------- Subordinated debt: 8-3/4% Senior Subordinated Notes due 2007 69,281 68,781 6% Convertible Subordinated Debentures due 2007 21,620 20,740 ---------- ---------- 90,901 89,521 ---------- ---------- Total debt 283,201 273,621 ---------- ---------- Trust Preferred Securities- manditorily redeemable securities of subsidiary 84,840 84,440 ---------- ---------- Total $ 368,041 $ 358,061 ========== ========== Interest paid in cash during the three months ended June 30, 2002 and 2003 totaled $3.8 million and $3.5 million, respectively. Interest paid in cash during the six months ended June 30, 2002 and 2003 totaled $11.9 million and $10.6 million, respectively. No interest expense was capitalized during the three months or the six months ended June 30, 2002 and 2003. SENIOR CREDIT FACILITY In 2002, the Company entered into an amended and restated $225.0 million secured revolving bank facility (the "Senior Credit Facility") which is secured by substantially all of the assets of the Company (excluding Great Lakes). The Senior Credit Facility provides for a borrowing base subject to redeterminations semi-annually each April and October and pursuant to certain unscheduled redeterminations. As of June 30, 2003, the outstanding balance under the Senior Credit Facility was $110.6 million and there was approximately $59.4 million of borrowing capacity available. At the Company's election, the borrowing base may be increased by up to $10 million during any six month borrowing base period based on a percentage of the face value of subordinated debt retired by the Company. The loan matures on January 1, 2007. Borrowings under the Senior Credit Facility can either be base rate loans or LIBOR loans. On all base rate loans, the rate per annum is equal to the lesser of (i) the maximum rate (the "weekly ceiling" as defined in Section 303 of the Texas Finance Code or other applicable laws if greater) (the "Maximum Rate") or, (ii) the sum of (A) the higher of (1) the prime rate for such date, or (2) the sum of the federal funds effective rate for such date plus one-half of one percent (.50%) per annum, plus a base rate margin of between .25% to 1.0% per annum depending on the total outstanding under the Senior Credit Facility relative to the borrowing base under the Senior Credit Facility. On all LIBOR loans, the Company pays a varying rate per annum equal to the lesser of (i) the Maximum Rate, or (ii) the sum of the quotient of (A) the LIBOR base rate, divided by (B) one minus the reserve requirement applicable to such interest period, plus a LIBOR margin of between 1.50% and 2.25% per annum depending on the total outstanding under the Senior Credit Facility relative to the borrowing base under the Senior Credit Facility. The Company may elect, from time to time, to convert all or any part of its LIBOR loans to base rate loans or to convert all or any part of its base rate loans to LIBOR loans. The weighted 13 average interest rate was 4.0% and 3.2% for the three months ended June 30, 2002 and 2003 and 4.1% and 3.3% for the six months ended June 30, 2002 and 2003, respectively. A commitment fee is paid on the undrawn balance based on an annual rate of 0.375% to 0.50%. At June 30, 2003, the commitment fee was 0.375% and the interest rate margin was 1.75%. At July 31, 2003, the interest rate was 2.6%. GREAT LAKES CREDIT FACILITY The Company consolidates its proportionate share of borrowings on the Great Lakes' $275.0 million secured revolving bank facility (the "Great Lakes Credit Facility"). The Great Lakes Credit Facility is non-recourse to the Company and provides for a borrowing base subject to redeterminations semi-annually each April and October and pursuant to certain unscheduled redeterminations. As of June 30, 2003, the Company's portion of the outstanding balance owed under the Great Lakes Credit Facility was $73.5 million. The loan matures on January 1, 2007. Any advance under the commitment may be a base rate loan or a Eurodollar loan. On all base rate loans the Company pays a varying rate per annum equal to the lesser of (i) the maximum nonusurious rate of interest under applicable law, or (ii) the sum of the base rate plus a base rate margin of between .25% to .75% per annum depending on the amounts outstanding on the loan, plus all outstanding letters of credit, divided by the borrowing base under the Great Lakes Credit Facility. On all Eurodollar loans, the Company pays a varying rate per annum equal to the lesser of (i) the maximum nonusurious rate of interest under applicable law, or (ii) the Eurodollar rate plus a Eurodollar margin of between 1.50% to 2.0% per annum depending on the amounts outstanding on the loan, plus all outstanding letters of credit, divided by the borrowing base under the Great Lakes Credit Facility. Great Lakes may elect, from time to time, to convert all or any part of its Eurodollar loans to base rate loans or to convert all or any part of its base rate loans to Eurodollar loans. Cash distributions to members of the joint venture are limited by a covenant contained in the Great Lakes Credit Facility. A commitment fee is paid on the undrawn balance at an annual rate of 0.25% to 0.50%. At June 30, 2003, the commitment fee was 0.50% and the interest rate margin was 1.75%. The average interest rate on the Great Lakes Credit Facility, excluding hedges, was 3.9% and 3.1% for the three months ended June 30, 2002 and 2003, respectively, and 3.9% and 3.2% for the six months then ended, respectively. After hedging (see Note 7), the rate was 6.8% and 5.5% for the three months ended June 30, 2002 and 2003, respectively, and 6.8% and 5.6% for the six months ended June 30, 2002 and 2003, respectively. At July 31, 2003, the interest rate was 2.9% excluding hedges and 5.0% after hedging. 8-3/4% SENIOR SUBORDINATED NOTES DUE 2007 In 1997, the Company sold $125 million in aggregate principal amount of its 8-3/4% Senior Subordinated Notes due 2007 (the "8-3/4% Notes"). Interest on the 8-3/4% Notes accrues at the rate of 8-3/4% per annum and is payable semi-annually in arrears in January and July of each year. The 8-3/4% Notes mature on January 15, 2007, unless previously redeemed. The 8-3/4% Notes are subject to redemption at the Company's option, in whole or in part, at redemption prices from 102.9% of the principal amount as of June 30, 2003, and declining to 100% in 2005. The 8-3/4% Notes are the Company's unsecured general obligations and are subordinated to all of the Company's senior indebtedness. The 8-3/4% Notes are guaranteed on a senior subordinated basis by certain of the Company's subsidiaries and each guarantor is one of the Company's wholly owned subsidiaries. The guarantees are full, unconditional, and joint and several. During the three month period ended June 30, 2003, the Company repurchased $500,000 of the 8-3/4% Notes. During the three month period ended June 30, 2002, the Company repurchased $5.0 million of the 8-3/4% Notes at a discount. Only cash repurchases are reflected on the cash flow statement. The net gain on all exchanges and repurchases is included as a Gain on retirement of securities on the Consolidated Statement of Operations. As of July 31, 2003, $68.8 million of the 8-3/4% Notes was outstanding. On July 21, 2003, the Company announced its election to redeem all of its outstanding 8-3/4% Notes on August 20, 2003. The 8-3/4% Notes are being called at 102.9% of principal amount, plus accrued interest. Interest on the notes ceases to accrue on the redemption date. The aggregate redemption price, including the premium, will be $70.8 million. The redemption was financed by the issuance of the 7-3/8% Notes. 14 6% CONVERTIBLE SUBORDINATED DEBENTURES DUE 2007 In 1996, the Company sold $55.0 million aggregate principal amount of 6% Convertible Subordinated Debentures due 2007 (the "6% Debentures"). Interest on the 6% Debentures is payable semi-annually in February and August of each year. The 6% Debentures are convertible into shares of the Company's common stock at the option of the holder at any time prior to maturity, unless previously redeemed or repurchased, at a conversion price of $19.25 per share, subject to adjustment in certain events. The 6% Debentures will mature in 2007. The 6% Debentures are subject to redemption at the Company's option, in whole or in part, at redemption prices from 102.5% of the principal amount as of June 30, 2003, and declining to 101.0% in 2006. Upon a change of control, the Company is required to offer to repurchase each holder's 6% Debenture at a purchase price equal to 100% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase. The 6% Debentures are unsecured general obligations and are the Company's subordinated to all of the Company's senior indebtedness. During the three months ended June 30, 2002, $5.6 million of 6% Debentures were retired at a discount in exchange for 918,700 shares of common stock. During the six months ended June 30, 2002, $7.1 million of 6% Debentures were retired at a discount in exchange for 1,165,700 shares of common stock and $15,000 were repurchased for cash at a discount. During the six month period ended June 30, 2003, $880,000 was retired at a discount in exchange for 128,793 shares of common stock. The Company recorded a $465,000 conversion expense related to this exchange (see discussion below). On July 31, 2003, $20.7 million of the 6% Debentures was outstanding. 5-3/4%TRUST PREFERRED SECURITIES - MANDITORILY REDEEMABLE SECURITIES OF SUBSIDIARY In 1997, the Company issued $120.0 million of the Trust Preferred Securities through a newly-formed affiliate Lomak Financing Trust (the "Trust"). The Trust issued 2,400,000 shares of the Trust Preferred Securities at $50 per share. Each Trust Preferred Security is convertible at the holder's option into shares of the Company's common stock, at a conversion price of $23.50 per share. The Trust invested the $120 million of proceeds in the 5-3/4% convertible junior subordinated debentures (the "Junior Debentures"). The sole assets of the Trust are the Junior Debentures. The Junior Debentures and the related Trust Preferred Securities mature in November 2027. The Company and the Trust may redeem the Junior Debentures and the Trust Preferred Securities, respectively, in whole or in part. As of June 30, 2003, the price at which these redemptions could be made was 102.9% of the principal amount. The premium declines proportionally every 12 months until November 2007, when the redemption price becomes fixed at 100% of the principal amount. If any Junior Debentures are redeemed prior to the scheduled maturity date, the Trust must redeem Trust Preferred Securities having an aggregate liquidation amount equal to the aggregate principal amount of the Junior Debentures the Company redeems. The Company has guaranteed the payments of distributions and other payments on the Trust Preferred Securities only if and to the extent that the Trust has funds available. The Company's guarantee, when taken together with the Company's obligation under the Junior Debentures and related indenture and declaration of trust, provide a full and unconditional guarantee on a subordinated basis of amounts due on the Trust Preferred Securities. The accounts of the Trust are included in the consolidated financial statements after eliminations. Distributions are recorded as Interest expense in the Consolidated Statement of Operations, are tax deductible and are subject to limitations in the Senior Credit Facility as described below. During the six months ended June 30, 2002, $2.4 million of Trust Preferred Securities were retired at a discount in exchange for 283,200 shares of common stock. During the six months ended June 30, 2003, the Company repurchased for cash $400,000 of the Trust Preferred Securities at a discount. On July 31, 2003, $84.4 million of the Trust Preferred Securities was outstanding. INDUCED CONVERSIONS In September 2002, the Emerging Issues Task Force ("EITF") issued EITF Issue No. 02-15, Determining Whether Certain conversions of Convertible Debt to Equity Securities are within the Scope of FASB Statement No. 84 "Induced Conversions of Convertible Debt" ("SFAS 84"). SFAS 84 was issued to amend APB Opinion No. 26, "Early Extinguishment of Debt" to exclude from its scope convertible debt that is converted to equity securities of the debtor pursuant to conversion privileges different from those included in the terms of the debt at issuance, and 15 the change in conversion privileges is effective for a limited period of time, involves additional consideration, and is made to induce conversion. SFAS 84 applies only to conversions that both (a) occur pursuant to changed conversion privileges that are exercisable only for a limited period of time and (b) include the issuance of all of the equity securities issuable pursuant to conversion privileges included in the terms of the debt at issuance for each debt instrument that is converted. The Task Force reached a consensus that SFAS 84 applies to all conversions that both (a) occur pursuant to changed conversion privileges that are exercisable only for a limited period of time and (b) include the issuance of all of the equity securities issuable pursuant to conversion privileges included in the terms of the debt at issuance for each debt instrument that is converted, regardless of the party that initiates the offer. This consensus should be applied prospectively to debt conversions completed after September 11, 2002. Since 1999, the Company has retired 6% Debentures and Trust Preferred Securities, each of which are convertible into common stock, by either purchasing securities for cash or issuing common stock in exchange for such securities. Since the exchanges of common stock for these convertible debt securities were at relative market values, the convertible securities were retired at a discount to face value. Under the provisions of SFAS 84, when an inducement is issued to retire convertible debt, the face value of the convertible debt security shall be charged to Stockholders' equity (common stock and paid in capital), the shares of common stock issued in excess of the shares that would have been issued under the terms of the debt instrument are expensed at the market value of such shares and an offsetting increase to paid in capital will also be recorded. Therefore, instead of recording gains on retirements of such securities acquired at discounts to face value, an expense will be recorded. There will be no difference in Stockholders' equity from the change in methods of recording the transactions. DEBT COVENANTS The debt agreements contain covenants relating to net worth, working capital, dividends and financial ratios. The Company was in compliance with all covenants at June 30, 2003. Under the most restrictive covenant, which is embodied in the 8-3/4% Notes, approximately $560,000 of restricted payments could be made at June 30, 2003. Under the Senior Credit Facility, common dividends are permitted. Dividends on the Trust Preferred Securities may not be paid unless certain ratio requirements are met. The Senior Credit Facility provides for a restricted payment basket of $20.0 million plus 50% of net income (excluding Great Lakes) plus 66-2/3% of distributions, dividends or payments of debt from or proceeds from sales of equity interests of Great Lakes plus 66-2/3% of net cash proceeds from common stock issuances. The Company estimates that $25.2 million was available under the Senior Credit Facility's restricted payment basket on June 30, 2003. 7-3/8% SENIOR SUBORDINATED NOTES DUE 2013 On July 21, 2003, the Company issued $100.0 million aggregate principal amount of 7-3/8% Senior Subordinated Notes due 2013. The Company pays interest on the 7-3/8% Notes semi-annually in arrears in January and July of each year, starting in January 2004. The 7-3/8% Notes mature in July 2013. The 7-3/8% Notes are guaranteed by certain of the Company's subsidiaries (the "Subsidiary Guarantors"). The Company may redeem the 7-3/8% Notes, in whole or in part, at any time on or after July 15, 2008, at redemption prices from 103.7% of the principal amount as of July 15, 2008, and declining to 100.0% on July 15, 2011 and thereafter. Prior to July 15, 2006, the Company may redeem up to 35% of the original aggregate principal amount of the notes at a redemption price of 107.4% of the principal amount thereof plus accrued and unpaid interest, if any, with the proceeds of certain equity offerings. If the Company experiences a change of control, the Company may be required to repurchase all or a portion of the 7-3/8% Notes at 101% of the principal amount thereof plus accrued and unpaid interest, if any. The 7-3/8% Notes and the guarantees by the Subsidiary Guarantors are general, unsecured obligations and are subordinated to the Company's and the Subsidiary Guarantors senior debt and will be subordinated to future senior debt that the Company and the Subsidiary Guarantors are permitted to incur under the senior credit facilities and the indenture governing the 7-3/8% Notes. 16 (7) FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES The Company's financial instruments include cash and equivalents, receivables, payables, debt and commodity and interest rate derivatives. The book value of cash and equivalents, receivables and payables is considered representative of fair value because of their short maturity. The book value of bank borrowings is believed to approximate fair value because of their floating rate structure. The following table sets forth the book and estimated fair values of financial instruments as of December 31, 2002 and June 30, 2003 (in thousands): December 31, 2002 June 30, 2003 -------------------------------- ------------------------------- Book Fair Book Fair Value Value Value Value ------------- ------------- ------------- -------------- Assets Cash and equivalents $ 1,334 $ 1,334 $ 1,309 $ 1,309 Marketable securities 1,040 1,040 1,404 1,404 Interest swaps - - 43 43 Commodity derivatives 17 17 72 72 ----------- ------------ ------------ ------------ Total 2,391 2,391 2,828 2,828 ----------- ------------ ------------ ------------ Liabilities Commodity derivatives (32,964) (32,964) (82,091) (82,091) Interest rate swaps (2,150) (2,150) (1,399) (1,399) Long-term debt(1) (283,201) (279,894) (273,621) (273,695) Trust Preferred Securities(1) (84,840) (52,177) (84,440) (54,042) ----------- ------------ ------------ ------------ Total (403,155) (367,185) (441,551) (411,227) ----------- ------------ ------------ ------------ Net financial instruments $ (400,764) $ (364,794) $ (438,723) $ (408,399) =========== ============ ============ ============ (1) Fair value based on quotes received from certain brokerage houses. Quotes for June 30, 2003 were 101.5% for the 8-3/4% Notes, 95.4% for the 6% Debentures and 64.0% for the Trust Preferred Securities. A portion of future oil and gas sales is periodically hedged through the use of option or swap contracts. In the second quarter of 2003, the hedging program was modified to include collars which assume a minimum floor price and a predetermined ceiling price. Realized gains and losses on these instruments are reflected in the contract month being hedged as an adjustment to oil and gas revenue. At times, the Company seeks to manage interest rate risk through the use of swaps. Gains and losses on interest rate swaps are included as an adjustment to interest expense in the relevant periods. At June 30, 2003, the Company had hedging contracts covering 68.7 Bcf of gas at prices averaging $4.07 per mcf and 1.6 million barrels of oil at prices averaging $25.05 per barrel. The fair value, represented by the estimated amount that would be realized upon termination, based on contract prices versus the New York Mercantile Exchange ("NYMEX") price on June 30, 2003, was a net unrealized pre-tax loss of $82.0 million. The contracts expire monthly through December 2006. Gains or losses on open and closed hedging transactions are determined as the difference between the contract price and the reference price, which are closing prices on the NYMEX. Transaction gains and losses on settled contracts are determined monthly and are included as increases or decreases to oil and gas revenues in the period the hedged production is sold. Oil and gas revenues were increased by $3.6 million and decreased by $15.4 million due to hedging in the quarters ended June 30, 2002 and 2003, respectively. 17 The following schedule shows the effect of closed oil and gas hedges since January 1, 2002 and the value of open contracts at June 30, 2003 (in thousands): Quarter Hedging Gain/ Ended (Loss) - ---------------------------------------------------------- ------------- Closed Contracts 2002 March 31 $ 11,727 June 30 3,638 September 30 3,484 December 31 (1,059) ----------- Subtotal 17,790 2003 March 31 (25,890) June 30 (15,365) ----------- Subtotal (41,255) ----------- Total realized loss $ (23,465) =========== Open Contracts 2003 September 30 $ (15,342) December 31 (15,277) ----------- Subtotal (30,619) 2004 March 31 (13,574) June 30 (8,774) September 30 (7,940) December 31 (8,281) ----------- Subtotal (38,569) 2005 March 31 (5,983) June 30 (2,282) September 30 (2,047) December 31 (2,545) ----------- Subtotal (12,857) 2006 March 31 (36) June 30 30 September 30 32 December 31 - ----------- Subtotal 26 ----------- Total unrealized loss $ (82,019) 18 Through Great Lakes, the Company uses interest rate swap agreements to manage the risk that future cash flows associated with interest payments on amounts outstanding under the variable rate Great Lakes Credit Facility may be adversely affected by volatility in market interest rates. Under the interest swap agreements, the Company agrees to pay an amount equal to a specified fixed rate of interest times a notional principal amount, and to receive in return, a specified variable rate of interest times the same notional principal amount. Changes in the fair value of the Company's interest rate swaps, which qualify for cash flow hedge accounting treatment, are reflected as adjustments to OCI to the extent the swaps are effective and will be recognized as an adjustment to interest expense during the period in which the cash flows related to the Company's interest payments are made. The ineffective portion of the changes in fair value of the Company's interest rate swaps is recorded in interest expense in the period incurred. Interest expense also includes the fair value effect of non-qualifying interest rate swaps. At June 30, 2003, Great Lakes had seven interest rate swap agreements totaling $110.0 million, of which 50% is consolidated at the Company. These swaps consist of two agreements totaling $45.0 million at 7.1% which expire in May 2004, two agreements totaling $20.0 million at rates averaging 2.3% which expire in December 2004 and three agreements totaling $45.0 million at rates averaging 1.7% which expire in June 2006. The fair value of these swaps at June 30, 2003 approximated a net loss of $2.7 million, of which 50% is consolidated at the Company. The combined fair value of net unrealized losses on oil and gas hedges and net losses on interest rate swaps totaled $83.4 million and appear as short-term and long-term Unrealized derivative gains and short-term and long-term Unrealized derivative losses on the balance sheet. Hedging activities are conducted with major financial or commodities trading institutions which management believes are acceptable credit risks. At times, such risks may be concentrated with certain counterparties. The creditworthiness of these counterparties is subject to continuing review. (8) COMMITMENTS AND CONTINGENCIES The Company is involved in various legal actions and claims arising in the ordinary course of business which, in the opinion of management, are likely to be resolved without material adverse effect on the Company's financial position or results of operations. (9) STOCKHOLDERS' EQUITY The Company has authorized capital stock of 110 million shares which includes 100 million shares of common stock and 10 million shares of preferred stock. Stockholders' equity was $193.2 million at June 30, 2003. The following is a schedule of changes in the number of outstanding common shares from December 31, 2002 to June 30, 2003: Twelve Months Six Months Ended Ended December 31, 2002 June 30, 2003 --------------------- ------------------ Beginning Balance 52,643,275 54,991,611 Issuances: Employee benefit plans 417,661 217,938 Stock options exercised 130,566 526,537 Stock purchase plan 168,500 87,500 Exchanges for: 6% Debentures 1,165,700 128,793 Trust Preferred Securities 283,200 - 8-3/4% Senior notes 182,709 - ---------- ---------- 2,348,336 960,768 ---------- ---------- Ending Balance 54,991,611 55,952,379 ========== ========== 19 (10) STOCK OPTION AND PURCHASE PLANS The Company has four stock option plans, of which two are active, and a stock purchase plan. Under these plans, incentive and non-qualified options and stock purchase rights are issued to directors, officers and employees pursuant to decisions of the Compensation Committee of the Board of Directors (the "Board"). Information with respect to the option plans is summarized below: Inactive Active -------------------------- -------------------------- Domain 1989 Directors' 1999 Plan Plan Plan Plan Total ---------- ---------- ---------- ---------- ---------- Outstanding on December 31, 2002 131,702 453,580 152,000 2,544,862 3,282,144 Granted - - 56,000 1,436,900 1,492,900 Exercised (28,670) (134,518) (4,000) (259,849) (427,037) Expired - (3,500) - (271,536) (275,036) ---------- ---------- ---------- ---------- ---------- (28,670) (138,018) 52,000 905,515 790,827 ---------- ---------- ---------- ---------- ---------- Outstanding on June 30, 2003 103,032 315,562 204,000 3,450,377 4,072,971 ========== ========== ========== ========== ========== In 1999, shareholders approved a stock option plan (the "1999 Plan"). In May 2003, shareholders approved an increase in the number of options issuable to 8.75 million. All options issued under the 1999 Plan from August 1999 through May 2002 vested 25% per year beginning after one year and had a maximum term of 10 years. Options issued under the 1999 Plan after May 2002 vest 30%, 30% and 40% over a three year period and have a maximum term of five years. During the six months ended June 30, 2003, options were granted under the 1999 Plan at exercise prices of $5.83 and $5.62 a share to eligible employees, including 250,000 and 175,000 options granted to the former Chairman and the President, respectively. At June 30, 2003, 3.4 million options were outstanding under the 1999 Plan at exercise prices ranging from $1.94 to $6.67. In 1994, shareholders approved the Outside Directors' Stock Option Plan (the "Directors' Plan"). In 2000, shareholders approved an increase in the number of options issuable to 300,000, extended the term of the options to ten years and set the vesting period at 25% per year beginning a year after grant. In May 2002, the term of the options was changed to five years with vesting immediately upon grant. Director's options are normally granted upon election of a director or annually upon their re-election at the annual meeting. At June 30, 2003, 204,000 options were outstanding under the Directors' Plan at exercise prices ranging from $2.81 to $6.00 a share. The Company maintains the 1989 Stock Option Plan (the "1989 Plan") which authorized the issuance of options on 3.0 million common shares. No options have been granted under this plan since March 1999. Options issued under the 1989 Plan vest 30%, 30% and 40% over a three year period and expire in five years. At June 30, 2003, 315,562 options remained outstanding under the 1989 Plan at exercise prices ranging from $2.63 to $7.63 a share. The Domain stock option plan was adopted when that company was acquired in 1998, with existing Domain options becoming exercisable into the Company's common stock. No options have been granted under this plan since the acquisition. At June 30, 2003, 103,032 options remained outstanding at an exercise price of $3.46 a share. 20 In total, 4.1 million options were outstanding at June 30, 2003 at exercise prices of $1.94 to $7.63 a share as follows: Inactive Active -------------------------- -------------------------- Range of Average Domain 1989 Directors' 1999 Exercise Prices Exercise Price Plan Plan Plan Plan Total - ------------------- -------------- ---------- ---------- ---------- ---------- ---------- $ 1.94 - $4.99 $ 3.44 103,032 174,387 52,000 869,343 1,198,762 $ 5.00 - $7.63 $ 5.93 - 141,175 152,000 2,581,034 2,874,209 ------- ------- ------- --------- --------- Total $ 5.20 103,032 315,562 204,000 3,450,377 4,072,971 ======= ======= ======= ========= ========= In 1997, shareholders approved a plan (the "Stock Purchase Plan") authorizing the sale of 900,000 shares of common stock to officers, directors, key employees and consultants. In 2001, shareholders approved an increase in the number of shares authorized under the Stock Purchase Plan to 1.75 million. Under the Stock Purchase Plan, the right to purchase shares at prices ranging from 50% to 85% of market value may be granted. To date, all purchase rights have been granted at 75% of market. Due to the discount from market value, the Company recorded additional compensation expense of $126,000 and $96,000 in the three months ended June 30, 2002 and 2003, respectively. Through June 30, 2003, 1,377,319 shares have been sold under the Stock Purchase Plan for $5.8 million. At June 30, 2003, there were no rights outstanding to purchase shares. (11) DEFERRED COMPENSATION In 1996, the Board of the Company adopted a deferred compensation plan (the "Plan"). The Plan gives certain senior employees the ability to defer all or a portion of their salaries and bonuses and invests in common stock of the Company or makes other investments at the employee's discretion. The assets of the Plan are held in a rabbi trust (the "Rabbi Trust") and, therefore, are available to satisfy the claims of the Company's creditors in the event of bankruptcy or insolvency of the Company. The Company's stock held in the Rabbi Trust is treated in a manner similar to treasury stock with an offsetting amount reflected as a deferred compensation liability of the Company and the carrying value of the deferred compensation liability is adjusted to fair value each reporting period by a charge or credit to operations in the General and administrative expense category on the Company's Consolidated Statement of Operations. The assets of the Rabbi Trust, other than common stock of the Company, are invested in marketable securities and reported at market value in Other assets on the Company's balance sheet. The Deferred Compensation liability on the Company's balance sheet reflects the face market value of the marketable securities and the Company's common stock held in the Rabbi Trust. The cost of common stock held in the Rabbi Trust is shown as a reduction to Stockholders' equity. Changes in the market value of the marketable securities are reflected in OCI, while changes in the market value of the common stock held in the Rabbi Trust is charged or credited to General and administrative expense each quarter. The Company recorded mark-to-market expense related to the Company stock held in the Rabbi Trust of $538,000 and $912,000 in the three months ended June 30, 2002 and 2003, respectively. The Company recorded mark-to-market expense related to deferred compensation of $1.3 million in both the six months ended June 30, 2002 and 2003. (12) BENEFIT PLAN The Company maintains a 401(k) Plan for its employees. The Plan permits employees to contribute up to 50% of their salary (subject to Internal Revenue limitations) on a pre-tax basis. Historically, the Company has made discretionary contributions of Company common stock to the 401(k) Plan annually. All Company contributions become fully vested after the individual employee has three years of service with the Company. In 2000, 2001 and 2002, the Company contributed $483,000, $554,000 and $602,000 at then market value, respectively, of the Company's common stock to the 401(k) Plan. The Company does not require that employees hold the contributed stock in their account. Employees have a variety of investment options in the 401(k) Plan. Employees may at any time diversify out of Company stock based on their personal investment strategy. 21 (13) INCOME TAXES The Company follows SFAS No. 109, "Accounting for Income Taxes," pursuant to which the liability method is used. Under this method, deferred tax assets and liabilities are determined based on differences between financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and regulations that will be in effect when the differences are expected to reverse. The significant components of deferred tax liabilities and assets on December 31, 2002 and June 30, 2003 were as follows (in thousands): December 31, June 30, 2002 2003 ----------- -------- Deferred tax assets/(liabilities) Net unrealized loss on hedging $ 11,388 $ 27,869 Other 4,397 (4,576) -------- -------- Net deferred tax asset $ 15,785 $ 23,293 ======== ======== At December 31, 2002, deferred tax assets exceeded deferred tax liabilities by $15.7 million with $11.4 million of deferred tax assets related to deferred hedging losses included in OCI. Based on the Company's recent profitability and its current outlook, no valuation allowance was deemed necessary at December 31, 2002. At June 30, 2003, deferred tax assets exceeded deferred tax liabilities by $23.3 million with $27.9 million of deferred tax assets related to hedging losses in OCI. For six months ended June 30, 2003, deferred tax expense includes $917,000 of expense related to an adjustment of prior periods' deferred tax asset for the Company's percentage depletion carryover. At December 31, 2002, the Company had regular net operating loss ("NOL") carryovers of $218.2 million and alternative minimum tax ("AMT") NOL carryovers of $198.5 million that expire between 2003 and 2022. At December 31, 2002, the Company had an AMT credit carryover of $665,000 which is not subject to limitation or expiration. 22 (14) EARNINGS PER SHARE The following table sets forth the computation of basic and diluted earnings per common share (in thousands except per share amounts): Three Months Ended, Six Months Ended June 30, June 30, ---------------------- ---------------------- 2002 2003 2002 2003 -------- -------- -------- -------- Numerator Numerator for earnings per share, before extraordinary item $ 7,310 $ 4,591 $ 11,651 $ 9,554 Cumulative effect of accounting change - - - 4,491 -------- -------- -------- -------- Numerator for earnings per share, basic and diluted $ 7,310 $ 4,591 $ 11,651 $ 14,045 ======== ======== ======== ======== Denominator Weighted average shares outstanding 54,540 55,682 53,763 55,440 Stock held by employee benefit trust (1,172) (1,520) (1,106) (1,424) -------- -------- -------- -------- Weighted average shares, basic 53,368 54,162 52,657 54,016 Stock held by employee benefit trust 1,172 1,520 1,106 1,424 Dilutive potential common shares stock options 399 486 345 404 -------- -------- -------- -------- Denominator for dilutive earnings per share 54,939 56,168 54,108 55,844 ======== ======== ======== ======== Earnings per share basic and diluted: Before cumulative effect of accounting change Basic $ 0.14 $ 0.08 $ 0.22 $ 0.18 Diluted $ 0.13 $ 0.08 $ 0.22 $ 0.17 After cumulative effect of accounting change Basic $ 0.14 $ 0.08 $ 0.22 $ 0.26 Diluted $ 0.13 $ 0.08 $ 0.22 $ 0.25 During the three months ended June 30, 2002 and 2003, 420,000 and 515,000 stock options were included in the computation of diluted earnings per share and for the six months then ended, 367,000 and 435,000 stock options were included in such computation. Remaining stock options, the 6% Debentures and the Trust Preferred Securities were not included because their inclusion would have been antidilutive. (15) MAJOR CUSTOMERS The Company markets its production on a competitive basis. Gas is sold under various types of contracts ranging from life-of-the-well to short-term contracts that are cancelable within 30 days. Oil purchasers may be changed on 30 days notice. The price for oil is generally equal to a posted price set by major purchasers in the area. The Company sells to oil purchasers on the basis of price and service. For the three months ended June 30, 2003, three customers, Duke Energy Field Services, Inc, Petrocom Energy Group, Ltd. and Conoco, Inc., accounted for 23%, 22% and 11%, respectively, of oil and gas revenues. Management believes that the loss of any one customer would not have a material long-term adverse effect on the Company. 23 (16) OIL AND GAS ACTIVITIES The following summarizes selected information with respect to producing activities. Exploration costs include capitalized as well as expensed outlays (in thousands): Six Year Ended Months Ended December 31, June 30, 2002 2003 ------------ ----------- Book value Properties subject to depletion $ 1,135,590 $ 1,224,560 Unproved properties 18,959 17,529 ----------- ----------- Total 1,154,549 1,242,089 Accumulated depletion (590,143) (606,789) ----------- ----------- Net $ 564,406 $ 635,300 =========== =========== Costs incurred(a) Development $ 66,284 $ 39,879 Exploration(b) 23,232 8,266 Acquisition(c) 21,790 9,729 ----------- ----------- Total $ 111,306 $ 57,874 =========== =========== (a) Excludes asset retirement costs of $2.0 million in the six months ended June 30, 2003. (b) Includes $11,525 and $5,140 of exploration costs expensed in the year ended 2002 and the six months ended June 30, 2003, respectively. (c) Includes $15,643 and $6,339 for oil and gas reserves, the remainder represents acreage purchases for the year ended 2002 and the six months ended June 30, 2003, respectively. 24 (17) INVESTMENT IN GREAT LAKES The Company owns 50% of Great Lakes and consolidates its proportionate interest in the joint venture's assets, liabilities, revenues and expenses. The following table summarizes the 50% interest in Great Lakes financial statements as of or for the six months ended June 30, 2002 and 2003 (in thousands): June 30, June 30, 2002 2003 -------------- --------------- Balance Sheet Current assets $ 9,799 $ 11,365 Oil and gas properties, net 168,747 209,601 Transportation and field assets, net 15,308 15,004 Unrealized derivative gain - 99 Other assets 199 347 Current liabilities 10,445 25,322 Unrealized derivative loss 2,820 8,170 Asset retirement obligation - 17,657 Long-term debt 68,500 73,500 Members' equity 112,288 111,767 Statement of Operations Revenues $ 25,660 $ 28,147 Direct operating expense 4,092 5,046 Exploration 1,200 781 G&A expense 921 930 Interest expense 2,499 2,280 DD&A 6,771 7,126 Pretax income 10,175 11,983 Cumulative effect of change in accounting principle (before income taxes) - 1,601 (18) GAIN ON RETIREMENT OF SECURITIES In the second quarter of the 2003, $500,000 of the 8-3/4% Notes were repurchased for cash and a loss of $10,400 was recorded on the transaction. In the six months of 2003, $400,000 of Trust Preferred Securities and $500,000 of 8-3/4% Notes were repurchased for cash and $880,000 of 6% Debentures was exchanged for common stock. A net gain of $139,600 was recorded on the cash transaction because the securities were acquired at a discount. The exchange transaction included conversion expense of $465,000. (See Note 6 regarding further guidance on SFAS 84 and accounting for gains on sale of securities). In the second quarter of 2002, $5.0 million of 8-3/4% Notes were repurchased for cash and $5.6 million of 6% Debentures were exchanged for common stock. In the first six months of 2002, $5.0 million of 6% Debentures were repurchased for cash. Also, $2.4 million, $7.1 million, and $875,000 of Trust Preferred Securities, 6% Debentures, and 8-3/4% Notes, respectively, were exchanged for common stock. A gain of $845,000 was recorded because the securities were acquired at a discount and SFAS 84 did not apply to these transactions because they occurred before the effective date of September 11, 2002. 25 ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FACTORS AFFECTING FINANCIAL CONDITION AND LIQUIDITY CRITICAL ACCOUNTING POLICIES The Company's discussion and analysis of its financial condition and results of operation are based upon unaudited consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses. Application of certain of the Company's accounting policies, including those related to oil and gas revenues, oil and gas properties, income taxes, and litigation, bad debts, marketable securities, hedging and the deferred compensation plan, require significant estimates. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. The Company believes the following critical accounting policies affect its more significant judgments and estimates used in the preparation of its consolidated financial statements. The FASB and representatives of the accounting staff of the SEC are engaged in discussions on the issue of whether the FASB's No. 141 and 142, issued effective for June 30, 2001, called for mineral rights held under lease or other contractual arrangements to be classified in the balance sheet as intangible assets and accompanied by specific footnote disclosures. Historically, the Company and all other oil and gas companies have included the cost of these oil and gas leasehold interests as part of oil and gas properties. Although, most of the Company's oil and gas property interests are held under oil and gas leases, this interpretation, if adopted, would not have a material impact on the Company's financial condition or its results of operations. In the event this interpretation is adopted, a substantial portion of acquisition costs of oil and gas properties since June 30, 2001 would be separately classified on the balance sheets as intangible assets. As of June 30, 2003, the Company's has expended approximately $23.6 million on the acquisition of oil and gas properties since June 30, 2001. Some additional direct costs of other oil and natural gas leases acquired since that date could also be categorized as intangible under this interpretation. Results of operations would not be affected by this interpretation, if adopted, since these costs would continue to be depleted in accordance with successful efforts accounting for oil and gas companies. Another possible effect of this interpretation, if adopted, would be a change in some of the financial measurements used in financial covenants of debt instruments that focus on tangible assets. The Company does not believe that its debt covenants would be materially affected by the adoption of this accounting interpretation. Proved oil and natural gas reserves - Proved reserves are defined by the SEC as those volumes of crude oil, condensate, natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered through existing wells with existing equipment and operating methods. Although the Company's engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of reserves requires the engineers to make a significant number of assumptions based on professional judgment. Reserve estimates are updated at least annually and consider recent production levels and other technical information about each well. Estimated reserves are often subject to future revision, which could be substantial, based on the availability of additional information, including: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes, and other economic factors. Changes in oil and gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions in turn cause adjustments in the depletion rates utilized by the Company. The Company can not predict what reserve revisions may be required in future periods. Depletion rates are determined based on reserve quantity estimates and the capitalized costs of producing properties. As the estimated reserves are adjusted, the depletion expense for a property will change, assuming no change in production volumes or the costs capitalized. Estimated reserves are used as the basis for calculating the expected future cash flows from a property, which are used to determine whether that property may be impaired. Reserves are also used to estimate the supplemental disclosure of the standardized measure of discounted future net cash flows relating to its oil and gas producing activities and reserve quantities annual disclosure to the consolidated 26 financial statements. Changes in the estimated reserves are considered changes in estimates for accounting purposes and are reflected on a prospective basis. Successful efforts accounting - The Company utilizes the successful efforts method to account for exploration and development expenditures. Unsuccessful exploration wells are expensed and can have a significant effect on operating results. Successful exploration drilling costs and all development costs are capitalized and systematically charged to expense using the units of production method based on proved developed oil and natural gas reserves as estimated by the Company's and third-party engineers. Proven leasehold costs are charged expense to using the units of production method based on total proved reserves. Unproved properties are assessed periodically within specific geographic areas and impairments to value are charged to expense. Impairment of properties - The Company monitors its long-lived assets recorded in Property, plant and equipment in the Consolidated Balance Sheet to make sure that they are fairly presented. The Company must evaluate its properties for potential impairment when circumstances indicate that the carrying value of an asset could exceed its fair value. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future oil and gas sales prices, an estimate of the ultimate amount of recoverable oil and natural gas reserves that will be produced, the timing of future production, future production costs, and future inflation. The need to test a property for impairment can be based on several factors, including a significant reduction in sales prices for oil and/or gas, unfavorable adjustment to reserves, or other changes to contracts, environmental regulations or tax laws. All of these factors must be considered when testing a property's carrying value for impairment. The Company cannot predict whether impairment charges may be recorded in the future. Income taxes - The Company is subject to income and other similar taxes in all areas in which it operates. When recording income tax expense, certain estimates are required because: (a) income tax returns are generally filed months after the close of its calendar year; (b) tax returns are subject to audit by taxing authorities and audits can often take years to complete and settle; and (c) future events often impact the timing of when income tax expenses and benefits are recognized by the Company. The Company has deferred tax assets relating to tax operating loss carry forwards and other deductible differences. The Company routinely evaluates its deferred tax assets to determine the likelihood of their realization. A valuation allowance has not been recognized for deferred tax assets due to management's belief that these assets are likely to be realized. At year-end 2002, deferred tax assets exceeded deferred tax liabilities by $15.8 million with $11.4 million of deferred tax assets related to deferred hedging losses included in OCI. Based on the Company's projected profitability, no valuation allowance was deemed necessary. The Company occasionally is challenged by taxing authorities over the amount and/or timing of recognition of revenues and deductions in its various income tax returns. Although the Company believes that it has adequate accruals for matters not resolved with various taxing authorities, gains or losses could occur in future years from changes in estimates or resolution of outstanding matters. Legal, environmental, and other contingent matters - A provision for legal, environmental, and other contingent matters is charged to expense when the loss is probable and the cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental, and contingent matters. In addition, the Company often must estimate the amount of such losses. In many cases, management's judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. Management closely monitors known and potential legal, environmental, and other contingent matters, and makes its best estimate of when the Company should record losses for these based on available information. Other significant accounting policies requiring estimates include the following: The Company recognizes revenues from the sale of products and services in the period delivered. The Company uses the sales method to account for gas imbalances. Revenues at IPF are recognized as earned. An allowance for doubtful accounts is provided for specific receivables which are unlikely to be collected. At IPF, all receivables are evaluated quarterly and provisions for uncollectible amounts are established. Such provisions for uncollectible amounts are recorded when management believes that a related receivable is not recoverable based on current estimates of expected discounted cash flows. The Company records a write down of marketable securities when the decline in market value is considered to be other than temporary. Change in the value of the ineffective position of all open hedges is 27 recognized in earnings quarterly. The fair value of open hedging contracts is an estimated amount that could be realized upon termination. The Company stock held in the deferred compensation plan is treated as treasury stock and the carrying value of the deferred compensation is adjusted to fair value each reporting period by a charge or credit to operations in general and administrative expense. As of January 1, 2003, the accounting for expected future costs to retire long-lived assets changed with the adoption of SFAS 143. LIQUIDITY AND CAPITAL RESOURCES During the six months ended June 30, 2003, the Company spent $57.9 million on development, exploration and acquisitions. During the period, debt and Trust Preferred Securities decreased by $10.0 million. At June 30, 2003, the Company had $1.3 million in cash, total assets of $743.4 million and, including the Trust Preferred Securities as debt, a debt to capitalization (including debt, deferred taxes and stockholders' equity) ratio of 65%. Excluding the Trust Preferred Securities from debt and equity, the debt to capitalization ratio was 59%. Available borrowing capacity on the credit facilities at June 30, 2003 was $59.4 million on the Senior Credit Facility and $78.0 million on the Great Lakes Credit Facility. Long-term debt at June 30, 2003 totaled $358.1 million. This included $110.6 million of Senior Credit Facility debt, a net $73.5 million of Great Lakes Credit Facility debt, $68.8 million of 8-3/4% Notes, $20.7 million of 6% Debentures and $84.4 million of Trust Preferred Securities. During the six months ended June 30, 2003, 129,000 shares of common stock were exchanged for $880,000 of 6% Debentures. In addition, $400,000 of Trust Preferred Securities and $500,000 of 8-3/4% Notes were repurchased for cash. A $139,600 net gain on retirement was recorded on the cash repurchase as most securities were acquired at a discount and a conversion expense of $465,000 was recorded on the exchange. 7-3/8% Subordinated Notes Issuance On July 21, 2003, the Company issued $100.0 million principal amount of 7-3/8% Senior Subordinated Notes due 2013. The Company pays interest on the 7-3/8% Notes semi-annually in arrears in January and July of each year, starting in January 2004. The 7-3/8% Notes mature on July 2013. The 7-3/8% Notes are guaranteed by certain of the Company's subsidiaries (the "Subsidiary Guarantors"). The Company may redeem the 7-3/8% Notes, in whole or in part, at any time on or after July 15, 2008, at redemption prices from 103.7% of the principal amount as of July 15, 2008, and declining to 100.0% on July 15, 2011 and thereafter. Prior to July 15, 2006, the Company may redeem up to 35% of the original aggregate principal amount of the notes at a redemption price of 107.4% of the principal amount thereof plus accrued and unpaid interest, if any, with the proceeds of certain equity offerings. If the Company experiences a change of control, the Company may be required to repurchase all or a portion of the 7-3/8% Notes at 101% of the principal amount thereof plus accrued and unpaid interest, if any. The 7-3/8% Notes and the guarantees by the Subsidiary Guarantors are general, unsecured obligations and are subordinated to the Company's and the Subsidiary Guarantors senior debt and will be subordinated to future senior debt that the Company and the Subsidiary Guarantors are permitted to incur under the senior credit facilities and the indenture governing the 7-3/8% Notes. The Company believes its capital resources are adequate to meet its requirements for at least the next twelve months; however, future cash flows are subject to a number of variables including the level of production and prices as well as various economic conditions that have historically affected the oil and gas business. There can be no assurance that internal cash flow and other capital sources will provide sufficient funds to maintain planned capital expenditures. The debt agreements contain covenants relating to net worth, working capital, dividends and financial ratios. The Company was in compliance with all covenants at June 30, 2003. Under the most restrictive covenant, which is embodied in the 8-3/4% Notes, approximately $560,000 of restricted payments could be made at June 30, 2003. Under the Senior Credit Facility, common dividends are permitted. Dividends on the Trust Preferred Securities may not be paid unless certain ratio requirements are met. The Senior Credit Facility provides for a restricted payment basket of $20.0 million plus 50% of net income (excluding Great Lakes) plus 66-2/3% of distributions, dividends or payments of debt from or proceeds from sales of equity interests of Great Lakes plus 66-2/3% of net cash proceeds from common stock issuances. The Company estimates that $25.2 million was available under the Senior Credit Facility's restricted payment basket on June 30, 2003. 28 During the six months ended January 30, 2003, there were no material changes from the 2002 Form 10K disclosures regarding the Company's contractual commitments, other than the extension of the Senior Credit Facility's maturity date from 2005 to 2007. Cash Flow The Company's principal sources of cash are operating cash flow and bank borrowings. The Company's cash flow is highly dependent on oil and gas prices. The Company has entered into hedging agreements covering 68.7 bcf of gas and 1.6 million barrels of oil for the remainder of 2003, 2004, 2005, and 2006, respectively. The $52.5 million of capital expenditures in the six months ended June 30, 2003 was funded with internal cash flow. Net cash provided by operations for the six months ended June 30, 2002 and 2003 was $53.5 million and $57.5 million, respectively. Cash flow from operations was higher than the prior year due to higher prices and volumes and lower exploration expense partially offset by higher direct operating expenses. Accounts receivable increased $12.6 million from December 31, 2002 due to higher prices and volumes. These receivables will be collected in the third quarter of 2003. Net cash used in investing for the six months ended June 30, 2002 and 2003 was $44.5 million and $49.7 million, respectively. The 2002 period included $37.7 million of additions to oil and gas properties. The 2003 period included $50.9 million of additions to oil and gas properties partially offset by $7.6 million of IPF receipts (net of fundings) and lower exploration expenditures. Net cash provided by financing for the six months ended June 30, 2002 and 2003 was $8.2 million and $7.8 million, respectively. During the first six months of 2003, total debt, including Trust Preferred Securities decreased $10.0 million. Senior Credit Facility debt and Great Lake Credit Facility debt decreased $8.2 million, subordinated notes (8-3/4% Notes and 6% Debentures) decreased $1.4 million and the Trust Preferred Securities decreased $400,000. The net decrease in debt was the result of excess cash flows. On July 21, 2003, the Company elected to redeem all of its outstanding 8-3/4% Notes on August 20, 2003. The redemption price, including the premium, will be $70.8 million. The redemption was financed by the issuance of $100.0 million of 7-3/8% Notes due 2013. Capital Requirements During the six months ended June 30, 2003, $52.5 million of capital expenditures was funded with internal cash flow. The Company seeks to fund its capital budget with internal cash flow. Based on the 2003 capital budget of $110.0 million, the Company seeks to increase production and expand its reserve base. Banking The Company maintains two separate revolving bank credit facilities: a $225.0 million Senior Credit Facility and a $275.0 million Great Lakes Credit Facility (of which 50% is consolidated at the Company). Each facility is secured by substantially all the borrowers' assets. The Great Lakes Credit Facility is non-recourse to the Company. As Great Lakes is 50% owned, half its borrowings are consolidated in the Company's financial statements. Availability under the facilities is subject to borrowing bases set by the banks semi-annually and in certain other circumstances. Redeterminations, other than increases, require approval of 75% of the lenders while, increases require unanimous approval. At July 31, 2003, the Senior Credit Facility had a $170.0 million borrowing base of which $154.8 million was available. The Great Lakes Credit Facility, half of which is consolidated at the Company, had a $225.0 million borrowing base, of which $75.0 million was available. HEDGING Oil and Gas Prices The Company enters into hedging agreements to reduce the impact of oil and gas price fluctuations. The Company's current policy, when futures prices justify, is to hedge 50% to 75% of projected production on a rolling 12 to 24 month basis. At June 30, 2003, hedges were in place covering 68.7 Bcf of gas at prices averaging $4.07 per Mmbtu and 1.6 million barrels of oil at prices averaging $25.05 per barrel. Their fair value at June 30, 2003 (the estimated amount that would be realized on termination based on contract versus NYMEX prices) was a net unrealized pre-tax loss of $82.0 million. Gains or losses on open and closed hedging transactions are determined based on the difference between the contract price and a reference price, generally closing prices on the NYMEX. Gains and losses are 29 determined monthly and are included as increases or decreases in oil and gas revenues in the period the hedged production is sold. An ineffective portion (changes in contract prices that do not match changes in the hedge price) of open hedge contracts is recognized in earnings as it occurs. Net decreases to Oil and gas revenues from hedging for the three months ended June 30, 2003 were $15.4 million and Oil and gas revenues were increased by $3.6 million from hedging for the three months ended June 30, 2002. Interest Rates At June 30, 2003, the Company had $358.1 million of debt (including Trust Preferred Securities) outstanding. Of this amount, $174.0 million bore interest at fixed rates averaging 7.0%. Senior Credit Facility debt and Great Lakes Credit Facility debt totaling $184.1 million bore interest at floating rates which averaged 2.9% at June 30, 2003. At times, the Company enters into interest rate swap agreements to limit the impact of interest rate fluctuations on its floating rate debt. At June 30, 2003, Great Lakes had interest rate swap agreements totaling $110.0 million, 50% of which is consolidated at the Company. These swaps consist of two agreements totaling $45.0 million at 7.1% which expire in May 2004, two agreements totaling $20.0 million at rates averaging 2.3% which expire in December 2004 and three agreements totaling $45.0 million at rates averaging 1.7% which expire in June 2006. The fair value of the swaps, based on then current quotes for equivalent agreements at June 30, 2003 was a net loss of $2.7 million, of which 50% is consolidated at the Company. The 30 day LIBOR rate on June 30, 2003 was 1.1%. Capital Restructuring Program The Company has taken a number of steps since 1998 to strengthen its financial position. These steps included the sale of assets and the exchange of common stock for debt. These initiatives have helped reduce the Senior Credit Facility debt from $365.2 million to $110.6 million and total debt (including Trust Preferred Securities) from $727.2 million to $358.1 million at June 30, 2003. The Company currently believes it has sufficient liquidity and cash flow to meet its obligations for the next twelve months; however, a significant drop in oil and gas prices or a reduction in production or reserves would reduce the Company's ability to fund capital expenditures and meet its financial obligations. INFLATION AND CHANGES IN PRICES The Company's revenues, the value of its assets, its ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in oil and gas prices. Oil and gas prices are subject to significant fluctuations that are beyond the Company's ability to control or predict. During the first six months of 2003, the Company received an average of $23.38 per barrel of oil and $3.91 per mcf of gas after hedging compared to $22.46 per barrel of oil and $3.42 per mcf of gas in the same period of the prior year. Although certain of the Company's costs and expenses are affected by the general inflation, inflation does not normally have a significant effect on the Company. During 2002, the Company experienced a slight decline in certain drilling and operational costs when compared to the prior year. Increases in commodity prices can cause inflationary pressures specific to the industry to also increase certain costs. The Company expects an increase in these costs in 2003. 30 RESULTS OF OPERATIONS VOLUMES AND SALES DATA: Three Months Ended Six Months Ended June 30, June 30, --------------------------------- --------------------------------- 2002 2003 2002 2003 -------------- -------------- -------------- -------------- Production: Crude oil and liquid (bbls) 559,553 630,600 1,093,718 1,213,739 Natural gas (mcfs) 10,358,893 10,619,549 20,573,203 20,977,908 Average daily production: Crude oil (bbls) 5,008 5,807 4,949 5,622 NGLs (bbls) 1,141 1,123 1,093 1,084 Natural gas (mcfs) 113,834 116,698 113,664 115,900 Total (mcfes) 150,728 158,276 149,920 156,134 Average sales prices (excluding hedging): Crude oil (per bbl) $ 23.09 $ 26.71 $ 20.98 $ 28.98 NGLs (per bbl) $ 12,58 $ 18.46 $ 11.79 $ 19.28 Natural gas (per mcf) $ 3.20 $ 5.14 $ 2.74 $ 5.61 Average sales price (including hedging): Crude oil (per bbl) $ 22.27 $ 23.14 $ 22.46 $ 23.38 NGLs (per bbl) $ 12.58 $ 18.46 $ 11.79 $ 19.28 Natural gas (per mcf) $ 3.59 $ 3.88 $ 3.42 $ 3.91 Total (per mcfe) $ 3.55 $ 3.84 $ 3.42 $ 3.88 31 The following table identifies certain items included in the results of operations and is presented to assist in comparison of the second quarter and year to date 2003 to the same periods of the prior year. The table should be read in conjunction with the following discussions of results of operations (in thousands): Three Months Ended Six Months Ended June 30, June 30, ---------------------- ---------------------- 2002 2003 2002 2003 -------- -------- -------- -------- Increase (decrease) in revenues: Write-down of marketable securities $ (851) $ - $ (1,220) $ - Gains (losses) on retirement of securities 845 (10) 2,030 140 Ineffective portion of commodity hedges (463) (2,075) (2,162) (1,271) Gain from sales of assets 27 69 26 157 Realized hedging gains (losses) 3,639 (15,365) 15,365 (41,255) -------- -------- -------- -------- $ 3,197 $(17,381) $ 14,039 $(42,229) ======== ======== ======== ======== Increase (decrease) to expenses: Fair value deferred compensation adjustment $ 538 $ 912 $ 1,320 $ 1,297 Bad debt expense accrual - 75 - 150 Adjustment to IPF valuation allowance 1,441 299 2,567 558 Non-qualifying interest rate swaps 300 (154) (72) (83) -------- -------- -------- -------- $ 2,279 $ 1,132 $ 3,815 $ 1,922 ======== ======== ======== ======== Cumulative effect of change in accounting principle (net of tax) $ - $ - $ - $ 4,491 ======== ======== ======== ======== Comparison of 2002 to 2003 Quarters Ended June 30, 2002 and 2003 Net income in the second quarter of 2003 totaled $4.6 million, compared to $7.3 million in the prior year period. The second quarter of 2003 includes a tax expense of $2.5 million versus a tax benefit in the prior year of $1.8 million. Production increased to 158.3 Mmcfe per day, a 5% increase from the prior year period. The production increase was due to higher production in the Appalachia and Southwest divisions offset by lower production in the Gulf Coast division. Revenues increased primarily due to an 8% increase in average prices per mcfe to $3.84. The average prices received for oil increased 4% to $23.14 per barrel, increased 8% for gas to $3.88 per mcf and increased 47% for NGLs to $18.46 per barrel. Production expenses increased 27% to $12.6 million as a result of significantly higher production taxes, increased costs from new wells and higher workover costs. Production taxes averaged $0.12 per mcfe in 2002 versus $0.18 per mcfe in 2003. Production taxes are paid on market prices not on hedged prices. Operating costs, including production taxes, per mcfe produced averaged $0.72 in 2002 versus $0.88 in 2003. Transportation and processing revenues increased 2% to $940,000 in 2003 with higher oil trading margins and higher gas prices. IPF recorded income of $428,000, a decrease of $564,000 from the 2002 period due to a smaller portfolio balance. 2002 IPF expenses included a $1.4 million unfavorable valuation allowance adjustment. IPF expenses in 2003 include a $299,000 unfavorable valuation allowance. During the quarter ended June 30, 2003, IPF expenses included $209,000 of administrative costs and $60,000 of interest, compared to prior year period administrative expenses of $476,000 and interest of $261,000. Exploration expense increased $515,000 to $2.7 million in 2003 due to higher dry hole costs. General and administrative expenses increased 12% or $580,000 to $5.3 million in the quarter with higher mark-to-market expenses relating to the deferred compensation plan and higher legal and other professional fees partially offset by certain bank fee and other refunds. The fair value deferred compensation adjustment included in general and administrative expense was $912,000 in the three months ended 2003 versus $538,000 in the same period of the prior year period. (See Note 11 to the consolidated financial statements). Other income reflected a loss of $1.2 million in 2002 and a loss of $1.9 million in 2003. The 2003 period included $2.1 million of ineffective hedging losses partially offset by $69,000 of gains on asset sales. The 2002 period included $463,000 of ineffective hedging losses and an $851,000 write down of marketable securities. Interest expense 32 decreased 18% to $5.2 million with lower expense related to the non-qualifying interest swaps, lower interest rates and lower outstanding debt. Total debt was $373.3 million and $358.1 million at June 30, 2002 and 2003, respectively. The average interest rates (excluding hedging) were 5.3% and 4.9%, respectively, at June 30, 2002 and 2003 including fixed and variable rate debt. DD&A increased 10% from the second quarter of 2002 with higher production and an additional $1.2 million of accretion expense related to the adoption of the new accounting principle (see Note 3 to the consolidated financial statements). The per mcfe DD&A rate for the second quarter of 2003 was $1.48, a $0.07 increase from the rate for the second quarter of 2002. This increase is due to higher accretion expense ($0.08 per mcfe) and the mix of production offset by lower depletion rates. The DD&A rate is determined based on year-end reserves and the net book value associated with them and, to a lesser extent, deprecation on other assets owned. The Company currently expects its DD&A rate for the remainder of 2003 to approximate $1.50 per mcfe. Income taxes reflected a benefit of $1.8 million in the second quarter of 2002 versus tax expenses of $2.5 million in the three months ended June 30, 2003. (See Note 13 to the consolidated financial statements). Six Months Periods Ended June 30, 2002 and 2003 Net income for the six months ended June 30, 2003 totaled $14.0 million compared to $11.7 million for the comparable period of 2002. The six months ended June 2003 includes tax expenses of $6.6 million versus a tax benefit of $4.9 million in the prior year. 2003 also includes $4.5 million gain on adoption of a new accounting principle. Production for the six months increased to 156.1 Mmcfe per day, an increase of 4% from the prior year period. The production increase was due to higher production in the Appalachia and Southwest divisions and higher production at West Cameron 45 somewhat offsetting natural production declines in other Gulf Coast wells. Revenues increased primarily due to higher prices which averaged $3.88 per mcfe. The average prices received for oil increased 4% to $23.38 per barrel, 14% for gas to $3.91 per mcf and 64% for NGLs to $19.28 per barrel. Production expenses increased 34% to $25.7 million as a result of higher production taxes, costs from new wells and higher workover costs in the Gulf of Mexico. Operating cost (including production taxes) per mcfe produced averaged $0.91 in 2003 versus $0.71 in 2002. Transportation and processing revenues increased 16% to $2.0 million with higher gas prices and higher oil trading margin. IPF recorded income of $967,000 million, a decrease of $1.2 million from the 2002. IPF revenue declined from the previous year due to a smaller portfolio balance. 2002 IPF expenses included $2.6 million of unfavorable valuation allowance adjustments. IPF expenses for the six months ended June 2003 included $558,000 of unfavorable valuation allowance adjustments. During the six months ended June 30, 2003, IPF expenses included $467,000 of administrative costs and $161,000 of interest, compared to prior year period administrative expenses of $870,000 and interest of $513,000. Exploration expense decreased $2.3 million to $5.1 million, primarily due to lower dry hole costs partially offset by higher seismic costs. General and administrative expenses increased 10% to $10.2 million in the six months ended June 30, 2003 due to higher compensation related expenses and legal and other professional fees. The fair value deferred compensation adjustment included in general and administrative expense is an expense of $1.3 million in both the six months ended 2002 and 2003. Other income reflected a loss of $3.2 million and a loss of $985,000. The 2002 period included $2.2 million of ineffective hedging losses and a $1.2 million write down of marketable securities. The 2003 period included a $1.3 million ineffective hedging loss and a $157,000 gain on sale of assets. Interest expense decreased 9% to $10.7 million as a result of lower outstanding debt and lower interest rates. DD&A increased 13% from the same period of the prior year with higher production and an additional $2.3 million of accretion expense related to the adoption of the new accounting principle.. The per mcfe DD&A rate for the six months of 2003 was $1.49, a $0.11 increase from the rate for the same period with higher accretion expense ($0.08 per mcfe) and higher depletion rates. Income taxes reflected a benefit of $4.9 million in the six months of 2002 versus tax expenses of $6.6 million in the same period of 2003. 33 ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. The primary objective of the following information is to provide forward-looking quantitative and qualitative information about the Company's potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in oil and gas prices and interest rates. The disclosures are not meant to be indicators of expected future losses, but rather an indicator of reasonably possible losses. This forward-looking information provides indicators of how the Company views and manages its ongoing market-risk exposures. All of the Company's market-risk sensitive instruments were entered into for purposes other than trading. Commodity Price Risk. The Company's major market risk exposure is to oil and gas prices. Realized prices are primarily driven by worldwide prices for oil and spot market prices for North American gas production. Oil and gas prices have been volatile and unpredictable for many years. The Company periodically enters into hedging arrangements with respect to its oil and gas production. Pursuant to these swaps, the Company receives a fixed price for its production and pays market prices to the counterparty. Hedging is intended to reduce the impact of oil and gas price fluctuations. In the second quarter of 2003, the hedging program was modified to include collars which assume a minimum floor price and predetermined ceiling price. Realized gains or losses are generally recognized in oil and gas revenues when the associated production occurs. Starting in 2001, gains or losses on open contracts are recorded either in current period income or OCI. The gains and losses realized as a result of hedging are substantially offset in the cash market when the commodity is delivered. Of the $82.0 million unrealized pre-tax loss included in OCI at June 30, 2003, $53.0 million of losses would be reclassified to earnings over the next twelve month period if prices remained constant. The actual amounts that will be reclassified will vary as a result of changes in prices. The Company does not hold or issue derivative instruments for trading purposes. As of June 30, 2003, the Company had oil and gas hedges in place covering 68.7 Bcf of gas and 1.6 million barrels of oil. Their fair value, represented by the estimated amount that would be realized on termination, based on contract versus NYMEX prices, approximated a net unrealized pre-tax loss of $82.0 million at that date. These contracts expire monthly through December 2006. Gains or losses on open and closed hedging transactions are determined as the difference between the contract price and the reference price, generally closing prices on the NYMEX. Transaction gains and losses are determined monthly and are included as increases or decreases to oil and gas revenues in the period the hedged production is sold. Any ineffective portion of such hedges is recognized in earnings as it occurs. Net realized losses relating to these derivatives for the six months ended June 30, 2003 were $41.3 million and net realized gains were $15.4 million for the six months ended June 30, 2002. In the first six months of 2003, a 10% reduction in oil and gas prices, excluding amounts fixed through hedging transactions, would have reduced revenue by $15.1 million. If oil and gas future prices at June 30, 2003 had declined 10%, the unrealized hedging loss at that date would have decreased $38.6 million. Interest rate risk. At June 30, 2003, the Company had $358.1 million of debt (including Trust Preferred Securities) outstanding. Of this amount, $174.0 million bore interest at fixed rates averaging 7.0%. Senior Credit Facility debt and the Great Lakes Credit Facility debt totaling $184.1 million bore interest at floating rates averaging 2.9%. At June 30, 2003 Great Lakes had interest rate swap agreements totaling $110.0 million (See Note 7), 50% of which is consolidated at the Company, which had a fair value loss (the Company's share) of $1.4 million at that date. A 1% increase or decrease in short-term interest rates would cost or save the Company approximately $1.3 million in annual interest expense. 34 ITEM 4. CONTROLS AND PROCEDURES. Within the 90 days prior to the date of this 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 Acting 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-14 (c) and Rule 15d-14(c). Based upon that evaluation, the Chief Executive Officer and the Acting Chief Financial Officer concluded that the Company's disclosure controls and procedures are effective in timely alerting them to material information relating to the Company (including its consolidated subsidiaries) required to be included in the Company's periodic filings with the SEC. No significant changes in the Company's internal controls or other factors that could affect these controls have occurred subsequent to the date of such evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS. The Company is involved in various legal actions and claims arising in the ordinary course of business. In the opinion of management, such litigation and claims are likely to be resolved without material adverse effect on its financial position or results of operations. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS On May 21, 2003, the Company held its Annual Meeting of Stockholders to (a) elect a Board of seven directors, each for a one-year term and (b) consider and vote on a proposal to (i) amend the 1999 Plan increasing the number of shares of common stock authorized to be issued from 6,000,000 to 8,750,000 and (ii) amend the 1999 Plan to prohibit the repricing of stock options granted under the 1999 Plan without a vote by the stockholders (collectively (a)(i) and (a)(ii) shall hereinafter be referred to as the "1999 Plan Amendments"). At such meeting, Robert E. Aikman, Anthony V. Dub, V. Richard Eales, Allen Finkelson, Jonathan S. Linker and John H. Pinkerton were reelected as Directors of the Company and Charles L. Blackburn was elected to serve as a director and Chairman of the Board. In addition, the 1999 Plan Amendments were approved by the Stockholders of the Company. The following is a summary of the votes cast at the Annual Meeting: Results of Voting Votes For Withheld Abstentions ----------------- ----------- ----------- ----------- 1. Election of Directors Robert E. Aikman 43,302,684 7,796,868 - Charles L. Blackburn 43,483,026 7,616,526 - Anthony V. Dub 43,126,349 7,973,203 - V. Richard Eales 43,124,899 7,974,653 - Allen Finkelson 43,321,546 7,778,006 - Jonathan S. Linker. 43,124,711 7,974,841 - John H. Pinkerton 43,393,308 7,706,244 - Results of Voting Votes For Against Abstentions ----------------- ----------- ----------- ----------- 2. 1999 Plan Amendments 30,093,708 20,791,451 214,392 35 ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) (a) Exhibits: 3.1.1 Certificate of Incorporation of Lomak Petroleum, Inc. ("Lomak") dated March 24, 1980 (incorporated by reference to Exhibit 3.1.1 to the Range Resources Corporation (the "Company") Registration Statement (File No. 33-31558)) 3.1.2 Certificate of Amendment to the Certificate of Incorporation dated July 22, 1981 (incorporated by reference to Exhibit 3.1.2 to the Company's Registration Statement (File No. 33-31558)) 3.1.3 Certificate of Amendment to the Certificate of Incorporation of Lomak dated August 27, 1982 (incorporated by reference to Exhibit 3.1.3 to the Company's Registration Statement (File No. 33-31558)) 3.1.4 Certificate of Amendment to the Certificate of Incorporation of Lomak dated December 28, 1988 (incorporated by reference to Exhibit 3.1.4 to the Company's Registration Statement (File No. 33-31558)) 3.1.5 Certificate of Amendment to the Certificate of Incorporation of Lomak dated August 31, 1989 (incorporated by reference to Exhibit 3.1.5 to the Company's Registration Statement (File No. 33-31558)) 3.1.6 Certificate of Amendment to the Certificate of Incorporation of Lomak dated May 17, 1991 (incorporated by reference to Exhibit 4.4(f) to the Company's Form S-3/A (File No. 333-20257) as filed with the Securities and Exchange Commission (the "SEC") on March 4, 1997) 3.1.7 Certificate of Amendment to the Certificate of Incorporation of Lomak dated November 20, 1992 (incorporated by reference to Exhibit 4.4(g) to the Company's Form S-3/A (File No. 333-20257) as filed with the SEC on March 4, 1997) 3.1.8 Certificate of Amendment to the Certificate of Incorporation of Lomak dated May 24, 1996 (incorporated by reference to Exhibit 4.4(h) to the Company's Form S-3/A (File No. 333-20257) as filed with the SEC on February 14, 1997) 3.1.9 Certificate of Amendment to the Certificate of Incorporation of Lomak dated October 2, 1996 (incorporated by reference to Exhibit 4.4(i) to the Company's Form S-3/A (File No. 333-20257) as filed with the SEC on February 14, 1997) 3.1.10 Restated Certificate of Incorporation of Lomak as required by Item 102 of Regulation S-T (incorporated by reference to Exhibit 4.4(j) to the Company's Form S-3/A (File No. 333-20257) as filed with the SEC on March 4, 1997) 3.1.11* Certificate of Amendment to the Certificate of Incorporation of Lomak dated June 20, 1997 3.1.12 Certificate of Amendment to the Certificate of Incorporation of Lomak dated August 25, 1998 (incorporated by reference to Exhibit 3.1 to the Company's Form S-8 (File No. 333-62439) as filed with the SEC on August 28, 1998) 3.1.13 Certificate of Amendment to the Certificate of Incorporation of the Company dated May 24, 2000 (incorporated by reference to Exhibit 3.1.12 to the Company's Form 10-Q (File No. 001-12209) as filed with the SEC on May 17, 2003) 3.2.1 Amended and Restated By-laws of the Company dated May 24, 2001 (incorporated by reference to Exhibit 3.2.2 to the Company's Form 10-K (File No. 001-12209) as filed with the SEC on March 5, 2002) 4.1.1 Form of 6% Convertible Subordinated Debentures due 2007 (contained as an exhibit to Exhibit 4.1.2 hereto) 4.1.2 Indenture dated December 20, 1996 by and between Lomak and Keycorp Shareholders Services, Inc., as trustee (incorporated by reference to Exhibit 4.1(A) to the Company's Form S-3 (File No. 333-23955) as filed with the SEC on March 25, 1997) 4.2.1 Form of 8-3/4% Senior Subordinated Notes due 2007 (contained as an exhibit to Exhibit 4.2.2 hereto) 4.2.2 Indenture dated March 14, 1997 by and among Lomak, the Subsidiary Guarantors (as defined therein) and Fleet National Bank, as trustee (incorporated by reference to Exhibit 4.3 to the Company's Form S-3/A (File No. 333-20257) as filed with the SEC on February 14, 1997) 4.3.1 Form of 5-3/4% Convertible Preferred Securities (contained as an exhibit to Exhibit 4.3.5 hereto) 36 4.3.2 Form of 5-3/4% Convertible Junior Subordinated Debentures (contained as an exhibit to Exhibit 4.3.4 hereto) 4.3.3 Indenture dated October 22, 1997 by and between Lomak and The Bank of New York, as trustee (incorporated by reference to Exhibit 4.6 of the Company's Form S-3 (File No. 333-43823) as filed with the SEC on January 7, 1998) 4.3.4 First Supplemental Indenture dated October 22, 1997 by and between Lomak and The Bank of New York, as trustee (incorporated by reference to Exhibit 4.7 to the Company's Form S-3 (File No. 333-43823) as filed with the SEC on January 7, 1998) 4.3.5 Certificate of Trust of Lomak Financing Trust dated October 8, 1997 (incorporated by reference to Exhibit 4.4 to the Company's Form S-3 (File No. 333-43823) as filed with the SEC on January 7, 1998) 4.3.6 Amended and Restated Declaration of Trust of Lomak Financing Trust dated October 22, 1997 by and between the Trustees (as defined therein), the Sponsor (as defined therein) and the holders, from time to time, of undivided beneficial ownership interests in the Trust (as defined therein) (incorporated by reference to Exhibit 4.5 to the Company's Form S-3 (File No. 333-43823) as filed with the SEC on January 7, 1998) 4.3.7 Convertible Preferred Securities Guarantee Agreement dated October 22, 1997 by and between Lomak, as guarantor, and The Bank of New York, as trustee (incorporated by reference to Exhibit 4.10 to the Company's Form S-3 (File No. 333-43823) as filed with the SEC on January 7, 1998) 4.3.8 Common Securities Guarantee Agreement dated October 22, 1997 executed and delivered by Lomak, as guarantor, for the benefit of the Holders (as defined therein) from time to time of the Common Securities (as defined therein) of Lomak Financing Trust (incorporated by reference to Exhibit 4.11 to the Company's Form S-3 (File No. 333-43823) as filed with the SEC on January 7, 1998) 4.4.1* Form of 7-3/8% Senior Subordinated Notes due 2013 (contained as an exhibit to Exhibit 4.4.2 hereto) 4.4.2* Indenture dated July 21, 2003 by and among the Company, as issuer, the Subsidiary Guarantors (as defined therein), as guarantors, and Bank One, National Association, as trustee 4.4.3* Registration Rights Agreement dated July 21, 2003 by and between the Company and UBS Securities LLC, Banc One Capital Markets, Inc., Credit Lyonnais Securities (USA) Inc. and McDonald Investments Inc. 10.1* Amended Application Service Provider and Outstanding Agreement dated June 2, 2003 by and between the Company and CGI Information Systems and Management Consultants, Inc. 10.2* Consulting Agreement dated May 7, 2003 by and between the Company and Thomas J. Edelman 10.3* Third Amendment to Amended and Restated Credit Agreement dated April 1, 2003 by and among the Company, Bank One, NA, the Lenders (as defined therein), Fleet National Bank, Fortis Capital Corp., JPMorgan Chase Bank, Credit Lyonnais New York Branch, Banc One Capital Markets, Inc. and JPMorgan Securities Inc. 10.4.1* Restated Credit Agreement dated May 3, 2002 by and among Great Lakes Energy Partners, L.L.C. ("Great Lakes"), Bank One, NA, JPMorgan Chase Bank, The Bank of Nova Scotia, Bank of Scotland, Credit Lyonnais New York Branch, Fortis Capital Corp., The Frost National Bank, Union Bank of California, N.A. and each Lender (as defined therein) 10.4.2* First Amendment to Restated Credit Agreement dated April 1, 2003 by and among Great Lakes, Bank One, NA, JPMorgan Chase Bank, The Bank of Nova Scotia, Bank of Scotland, Credit Lyonnais New York Branch, Fortis Capital Corp., The Frost National Bank, Union Bank of California, N.A., Comerica Bank-Texas, Natexis Banques Populaires, each Lender (as defined therein), Banc One Capital Markets, Inc. and JPMorgan Securities, Inc. 31.1* Certification by the President and Chief Executive Officer of the Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 31.2* Certification by the Acting Chief Financial Officer of the Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 32.1* Certification by the President and Chief Executive Officer of the Company Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 32.2* Certification by the Acting Chief Financial Officer of the Company Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - ------------------------------------ * filed herewith 37 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. RANGE RESOURCES CORPORATION By: /s/ RODNEY L. WALLER ------------------------------- Rodney L. Waller Acting Chief Financial Officer August 6, 2003 38 EXHIBIT INDEX ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits: 3.1.1 Certificate of Incorporation of Lomak Petroleum, Inc. ("Lomak") dated March 24, 1980 (incorporated by reference to Exhibit 3.1.1 to the Range Resources Corporation (the "Company") Registration Statement (File No. 33-31558)) 3.1.2 Certificate of Amendment to the Certificate of Incorporation dated July 22, 1981 (incorporated by reference to Exhibit 3.1.2 to the Company's Registration Statement (File No. 33-31558)) 3.1.3 Certificate of Amendment to the Certificate of Incorporation of Lomak dated August 27, 1982 (incorporated by reference to Exhibit 3.1.3 to the Company's Registration Statement (File No. 33-31558)) 3.1.4 Certificate of Amendment to the Certificate of Incorporation of Lomak dated December 28, 1988 (incorporated by reference to Exhibit 3.1.4 to the Company's Registration Statement (File No. 33-31558)) 3.1.5 Certificate of Amendment to the Certificate of Incorporation of Lomak dated August 31, 1989 (incorporated by reference to Exhibit 3.1.5 to the Company's Registration Statement (File No. 33-31558)) 3.1.6 Certificate of Amendment to the Certificate of Incorporation of Lomak dated May 17, 1991 (incorporated by reference to Exhibit 4.4(f) to the Company's Form S-3/A (File No. 333-20257) as filed with the Securities and Exchange Commission (the "SEC") on March 4, 1997) 3.1.7 Certificate of Amendment to the Certificate of Incorporation of Lomak dated November 20, 1992 (incorporated by reference to Exhibit 4.4(g) to the Company's Form S-3/A (File No. 333-20257) as filed with the SEC on March 4, 1997) 3.1.8 Certificate of Amendment to the Certificate of Incorporation of Lomak dated May 24, 1996 (incorporated by reference to Exhibit 4.4(h) to the Company's Form S-3/A (File No. 333-20257) as filed with the SEC on February 14, 1997) 3.1.9 Certificate of Amendment to the Certificate of Incorporation of Lomak dated October 2, 1996 (incorporated by reference to Exhibit 4.4(i) to the Company's Form S-3/A (File No. 333-20257) as filed with the SEC on February 14, 1997) 3.1.10 Restated Certificate of Incorporation of Lomak as required by Item 102 of Regulation S-T (incorporated by reference to Exhibit 4.4(j) to the Company's Form S-3/A (File No. 333-20257) as filed with the SEC on March 4, 1997) 3.1.11* Certificate of Amendment to the Certificate of Incorporation of Lomak dated June 20, 1997 3.1.12 Certificate of Amendment to the Certificate of Incorporation of Lomak dated August 25, 1998 (incorporated by reference to Exhibit 3.1 to the Company's Form S-8 (File No. 333-62439) as filed with the SEC on August 28, 1998) 3.1.13 Certificate of Amendment to the Certificate of Incorporation of the Company dated May 24, 2000 (incorporated by reference to Exhibit 3.1.12 to the Company's Form 10-Q (File No. 001-12209) as filed with the SEC on May 17, 2003) 3.2.1 Amended and Restated By-laws of the Company dated May 24, 2001 (incorporated by reference to Exhibit 3.2.2 to the Company's Form 10-K (File No. 001-12209) as filed with the SEC on March 5, 2002) 4.1.1 Form of 6% Convertible Subordinated Debentures due 2007 (contained as an exhibit to Exhibit 4.1.2 hereto) 4.1.2 Indenture dated December 20, 1996 by and between Lomak and Keycorp Shareholders Services, Inc., as trustee (incorporated by reference to Exhibit 4.1(A) to the Company's Form S-3 (File No. 333-23955) as filed with the SEC on March 25, 1997) 4.2.1 Form of 8-3/4% Senior Subordinated Notes due 2007 (contained as an exhibit to Exhibit 4.2.2 hereto) 4.2.2 Indenture dated March 14, 1997 by and among Lomak, the Subsidiary Guarantors (as defined therein) and Fleet National Bank, as trustee (incorporated by reference to Exhibit 4.3 to the Company's Form S-3/A (File No. 333-20257) as filed with the SEC on February 14, 1997) 4.3.1 Form of 5-3/4% Convertible Preferred Securities (contained as an exhibit to Exhibit 4.3.5 hereto) 41 4.3.2 Form of 5-3/4% Convertible Junior Subordinated Debentures (contained as an exhibit to Exhibit 4.3.4 hereto) 4.3.3 Indenture dated October 22, 1997 by and between Lomak and The Bank of New York, as trustee (incorporated by reference to Exhibit 4.6 of the Company's Form S-3 (File No. 333-43823) as filed with the SEC on January 7, 1998) 4.3.4 First Supplemental Indenture dated October 22, 1997 by and between Lomak and The Bank of New York, as trustee (incorporated by reference to Exhibit 4.7 to the Company's Form S-3 (File No. 333-43823) as filed with the SEC on January 7, 1998) 4.3.5 Certificate of Trust of Lomak Financing Trust dated October 8, 1997 (incorporated by reference to Exhibit 4.4 to the Company's Form S-3 (File No. 333-43823) as filed with the SEC on January 7, 1998) 4.3.6 Amended and Restated Declaration of Trust of Lomak Financing Trust dated October 22, 1997 by and between the Trustees (as defined therein), the Sponsor (as defined therein) and the holders, from time to time, of undivided beneficial ownership interests in the Trust (as defined therein) (incorporated by reference to Exhibit 4.5 to the Company's Form S-3 (File No. 333-43823) as filed with the SEC on January 7, 1998) 4.3.7 Convertible Preferred Securities Guarantee Agreement dated October 22, 1997 by and between Lomak, as guarantor, and The Bank of New York, as trustee (incorporated by reference to Exhibit 4.10 to the Company's Form S-3 (File No. 333-43823) as filed with the SEC on January 7, 1998) 4.3.8 Common Securities Guarantee Agreement dated October 22, 1997 executed and delivered by Lomak, as guarantor, for the benefit of the Holders (as defined therein) from time to time of the Common Securities (as defined therein) of Lomak Financing Trust (incorporated by reference to Exhibit 4.11 to the Company's Form S-3 (File No. 333-43823) as filed with the SEC on January 7, 1998) 4.4.1* Form of 7-3/8% Senior Subordinated Notes due 2013 (contained as an exhibit to Exhibit 4.4.2 hereto) 4.4.2* Indenture dated July 21, 2003 by and among the Company, as issuer, the Subsidiary Guarantors (as defined therein), as guarantors, and Bank One, National Association, as trustee 4.4.3* Registration Rights Agreement dated July 21, 2003 by and between the Company and UBS Securities LLC, Banc One Capital Markets, Inc., Credit Lyonnais Securities (USA) Inc. and McDonald Investments Inc. 10.1* Amended Application Service Provider and Outstanding Agreement dated June 2, 2003 by and between the Company and CGI Information Systems and Management Consultants, Inc. 10.2* Consulting Agreement dated May 7, 2003 by and between the Company and Thomas J. Edelman 10.3* Third Amendment to Amended and Restated Credit Agreement dated April 1, 2003 by and among the Company, Bank One, NA, the Lenders (as defined therein), Fleet National Bank, Fortis Capital Corp., JPMorgan Chase Bank, Credit Lyonnais New York Branch, Banc One Capital Markets, Inc. and JPMorgan Securities Inc. 10.4.1* Restated Credit Agreement dated May 3, 2002 by and among Great Lakes Energy Partners, L.L.C. ("Great Lakes"), Bank One, NA, JPMorgan Chase Bank, The Bank of Nova Scotia, Bank of Scotland, Credit Lyonnais New York Branch, Fortis Capital Corp., The Frost National Bank, Union Bank of California, N.A. and each Lender (as defined therein) 10.4.2* First Amendment to Restated Credit Agreement dated April 1, 2003 by and among Great Lakes, Bank One, NA, JPMorgan Chase Bank, The Bank of Nova Scotia, Bank of Scotland, Credit Lyonnais New York Branch, Fortis Capital Corp., The Frost National Bank, Union Bank of California, N.A., Comerica Bank-Texas, Natexis Banques Populaires, each Lender (as defined therein), Banc One Capital Markets, Inc. and JPMorgan Securities, Inc. 31.1* Certification by the President and Chief Executive Officer of the Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 31.2* Certification by the Acting Chief Financial Officer of the Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 32.1* Certification by the President and Chief Executive Officer of the Company Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 32.2* Certification by the Acting Chief Financial Officer of the Company Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - ------------------------------------ * filed herewith 42