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SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q/A AMENDMENT NO. 1 (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, 2002. { } TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934. COMMISSION FILE NUMBER 0-9592 RANGE RESOURCES CORPORATION (Exact name of registrant as specified in its charter) DELAWARE 34-1312571 (State of incorporation) (I.R.S. Employer Identification No.) 777 MAIN STREET, FT. WORTH, TEXAS 76102 (Address of principal executive offices) (Zip Code) Registrant's telephone number: (817) 870-2601 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 --- --- 54,764,002 Common Shares were outstanding on July 26, 2002. 1

Introductory Note - Restatement This Quarterly Amendment No. 1 to Form 10-Q/A amends Item 1 and 2 of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, including the consolidated financial statements therein, originally filed on August 14, 2002. As described in Note 2 to the consolidated financial statements, a restatement has been made to correct previously reported financial results. This amendment does not otherwise update the other information in the originally filed form 10-Q to reflect events after the original filing date. PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS. The financial statements included herein should be read in conjunction with the Company's latest Form 10-K/A. 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 disclosed. These financial statements have been prepared in accordance with the applicable rules of the Securities and Exchange Commission 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)

SEE ACCOMPANYING NOTES. 3

RANGE RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED, IN THOUSANDS EXCEPT PER SHARE DATA)

SEE ACCOMPANYING NOTES. 4

RANGE RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED, IN THOUSANDS)

SEE ACCOMPANYING NOTES. 5

RANGE RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) ORGANIZATION AND NATURE OF BUSINESS Range Resources Corporation ("Range") is engaged in the development, acquisition and exploration of oil and gas properties primarily in the Southwestern, Gulf Coast and Appalachian regions of the United States. The Company also provides financing to small oil and gas producers through a subsidiary, Independent Producer Finance ("IPF"). The Company seeks to increase its reserves and production principally through development drilling and acquisitions. Range holds its Appalachian oil and gas assets through a 50% owned joint venture, Great Lakes Energy Partners L.L.C. ("Great Lakes"). The Company's financial statements for the three years ended 2001 have been restated. 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 financial obligations. In addition, the Company's high depletion, depreciation and amortization ("DD&A") rate may make it difficult to remain profitable if oil and gas prices decline. 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) RESTATEMENT In July 2002, the Company selected KPMG LLP is its new independent auditor. The Company also chose to reaudit its consolidated financial statements for the three years ended December 31, 2001, even though a reaudit was not required. The reaudit was intended to provide additional assurance to shareholders, insure the Company's ongoing access to the capital markets and to avoid any possible impediment to future transactions. As part of the auditor selection process, KPMG performed its normal client acceptance procedures and advised the Company that it believed a different accounting principle should have been used to determine the amount of gain recognized in 1999 upon the formation of the Great Lakes joint venture. Specifically the gain recognized in September 1999 should be reduced from $39.8 million to $30.9 million and income in subsequent periods should increase as a result of lower depletion expense. As a result of the actual reaudit, a series of additional issues came to light which required restatement of the Company's previously reported operating results and financial condition. These issues and their impact on pretax income is outlined below. In 1998, the Company acquired Domain Energy. In recording the transaction, the purchase price was not appropriately allocated to the individual oil and gas properties, causing a subsequent purchase price adjustment to be miscalculated. As a result, impairments recognized at year-end 2001 were reduced. In addition, properties in Appalachia and Michigan, that had been combined into accounting pools for the purpose of calculating depletion, were subdivided into smaller pools and the depreciation rates historically applied on non-oil and gas assets were reduced. As a result of these changes, pretax income decreased $7.1 million in 1999, increased $4.8 million in 2000, increased $7.6 million in 2001 and decreased $2.9 million in the first six months of 2002. The Company maintains a deferred compensation plan (the "Plan"), under which eligible employees can defer all or a portion of their cash compensation and invest those amounts in a variety of investment options (including Company common stock) which are placed in a rabbi trust (the "Trust"). Eligible employees can also place common stock awards in the Trust. Pursuant to a consensus of the Emerging Issues Task Force, assets and 6

liabilities of the Trust must be consolidated on the Company's balance sheet. While the Trust's assets and liabilities are of identical value, Company common stock held in the Trust is treated as if it were treasury stock (it is deducted from outstanding shares as shares held by an employee benefit plan). Furthermore, because the Plan allows participants to diversify their investments, the liability to Plan participants must be revalued on the balance sheet each accounting period at the assets' then-quoted market prices and increases or decreases between accounting periods reflected on the statement of operations as increases or decreases in compensation expense. Historically, the Company did not consolidate the Trust in its consolidated financial statements nor added or subtracted changes in the market value of the Plan's assets on its statement of operations. However, all material information about the Plan has historically been disclosed in footnotes to the financial statements and in proxy statements. In addition, the Company offers designated employees the ability to purchase shares at a discount under a shareholder-approved Stock Purchase Plan or to receive bonuses or a portion of their base pay in restricted common stock issued at a discount from quoted market prices. Previously, such shares had always been accounted for based on the Company's estimate of the fair value of the stock granted or purchased. In the restated financial statements, stock purchased through the Plan or granted to employees was expensed based on the quoted market value without regard to the Company's estimate of fair value. The difference between previously reported values and market value will be included as additional compensation expense on the restated statement of operations. As a result of these changes, pretax income decreased $561,000 in 1999, decreased $3.8 million in 2000, increased $1.7 million in 2001 and decreased $1.8 million in the first six months of 2002. At June 30, 2002, the Company corrected a series of unreconciled balance sheet accounts that had a net minimal statement of operations impact. These balance sheet general ledger accounts were not supported by the underlying subsidiary ledger detail when the Company's accounting department moved from Ohio to Fort Worth. In the restatement, these corrections were reflected in the periods in which they applied, rather than in the second quarter of 2002. As a result, pretax income for periods prior to 1999 increased by $1.9 million, increased by $627,000 in 1999, decreased $2.9 million in 2000, increased by $190,000 in 2001 and increased by $134,000 in the first six months of 2002. Finally, certain of GLEP's interest rate swaps had early cancellation provisions but had been accounted for as cash flow hedges. Upon further review, the swaps did not meet the documentation and effectiveness provisions of SFAS 133, requiring changes in fair value to be reported as interest expense on the restated financial statements as opposed to changes in Other Comprehensive Income. As a result, pretax income decreased $1.4 million in 2001 and will increase by a corresponding amount in future periods. Additionally, the ineffective portion of certain commodity hedges increased income $71,000 in 2001. In total, all of the current changes (including the previously announced change in the gain on the Great Lakes' transaction) increased net loss by $15.7 million in 1999, decreased net income by $1.4 million in 2000 and increased net income by $8.7 million in 2001. The changes decreased net income by $2.3 million in the first half of 2002 but are projected to increase net income by approximately $3.9 million in the second half of 2002. 7

(3) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES BASIS OF PRESENTATION The accompanying consolidated financial statements include the accounts of the Company, majority-owned subsidiaries and a pro rata share of the assets, liabilities, income and expenses of Great Lakes. Liquid investments with maturities of ninety days or less are considered cash equivalents. Certain reclassifications have been made to the presentation of prior periods to conform with current year presentation. The Company's financial statements for the last three years have been restated. REVENUE RECOGNITION The Company recognizes revenues from the sale of products and services in the period delivered. Payments received at IPF relating to return are recognized as income; remaining receipts reduce receivables. The Company's receivables are concentrated in the oil and gas industry. However, IPF's receivables are from small independent operators who usually have limited access to capital and the assets which underlie the receivables 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. At December 31, 2001 and June 30, 2002, IPF had valuation allowances of $17.3 million and $19.8 million and the Company had other allowances for doubtful accounts of $2.9 million and $825,000, respectively. A decrease in oil prices would be likely to cause an increase in IPF's valuation allowance. MARKETABLE SECURITIES The Company has adopted Statement of Financial Accounting Standards ("SFAS") No. 115, "Accounting for Investments," pursuant to which the holdings of equity securities qualify as available-for-sale and are recorded at fair value. Unrealized gains and losses are reflected in Stockholders' equity as a component of Other comprehensive income. A decline in the market value of a security below cost deemed other than temporary is charged to earnings. Realized gains and losses are reflected in income. The Company has owned approximately 15% of a very small publicly traded independent exploration and production company. This company has experienced growing difficulties, operationally and financially. During the first six months of 2001 and 2002, the Company determined that the decline in the market value of this equity security it holds was other than temporary and losses of $1.3 million and $1.2 million, respectively, were recorded as reductions to Interest and other revenues. Based on its analysis of the investment and its assessment of the prospects 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. 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 believed to relate to the return are recognized as income; remaining receipts reduce receivables. Receivables classified as current represent the return of capital expected within twelve months. All receivables are evaluated quarterly and provisions for uncollectible amounts established based on the Company's valuation of its royalty interest in the oil and gas properties. At June 30, 2002, IPF's valuation allowance totaled $19.8 million. 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. Due to favorable oil and gas prices in early 2001, certain of IPF's receivables began to generate cash flows which favorably impacted the valuation of the receivable. As a result, $816,000 and $1.9 million increases in receivables were recorded as reduction to expense for the three months and the six months ended June 30, 2001, respectively. In addition, the IPF valuation allowance was reduced $406,000 in the second quarter of 2001 which had a favorable impact on IPF income. In the first quarter of 2002, based on price declines and the disappointing performance of certain properties, the valuation allowance was increased $1.1 million which was recorded as an increase to expense. In the second quarter of 2002, the valuation allowance was increased again by $1.4 million. During the second quarter of 2002, IPF revenues were $992,000 offset by $476,000 of general and 11

administrative costs, $261,000 of interest and the unfavorable $1.1 million valuation allowance. During the same period of the prior year, revenues were $1.1 million, the $406,000 favorable valuation adjustment and the $816,000 favorable increase to receivables offset by general and administrative expenses of $419,000 and $393,000 of interest. IPF's receivables have declined from a high of $77.2 million in 1998 to $37.4 million at June 30, 2002, as it has focused on recovering as much as possible of its investments. During this period, IPF's debt declined from $60.1 million to $23.5 million. The Company is assessing alternatives relating to its ownership of IPF. 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. Wells subsequently determined to be a dry hole are then 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 mcfe at the rate of six mcf per barrel. DD&A rates were $1.32 and $1.41 per mcfe in the quarters ended June 30, 2001 and 2002 and $1.32 and $1.38 for the six months ended June 30, 2001 and 2002, respectively. Unproved properties had a net book value of $25.7 million and $21.5 million at December 31, 2001 and June 30, 2002, respectively. TRANSPORTATION 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 four to fifteen years. The Company also receives third party income for providing certain field services which are recognized as earned. These earnings approximated $500,000 in each of the three month periods ended June 2001 and 2002, and $900,000 and $1,000,000 for the six month periods, respectively. Depreciation on the associated field assets is calculated on the straight-line method based on estimated useful lives of three to seven years. Buildings are depreciated over ten years. OTHER ASSETS The expense 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). When a security is retired prior to maturity, related unamortized costs are expensed. At June 30, 2002, these capitalized costs totaled $3.6 million. In the second quarter of 2002, the Company had a deferred tax asset of $8.1 million which is included in Other assets. This deferred tax asset was $8.3 million at March 31, 2002. At December 31, 2001, the Company had a $4.5 million net tax liability. At June 30, 2002, Other assets included $3.6 million unamortized debt issuance costs, $8.1 million deferred tax assets and $916,000 of long-term deposits and other assets. GAS IMBALANCES The Company uses the sales method to account for gas imbalances, recognizing revenue based on cash received rather than gas produced. At June 30, 2002, a gas imbalance liability of $114,000 was included in Accrued liabilities. 12

COMPREHENSIVE INCOME The Company follows SFAS No. 130, "Reporting Comprehensive Income," defined as changes in Stockholders' equity from nonowner sources, which is calculated below (in thousands):

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 estimates. Estimates which may significantly impact the financial statements include reserves, impairment tests on oil and gas properties, IPF valuation allowance and the fair value of derivatives. RECENT ACCOUNTING PRONOUNCEMENTS In April 2002, the FASB issued SFAS No. 145, Rescission of SFAS Nos. 4, 44 and 64, Amendment of SFAS No. 13 and Technical Corrections, which rescinds SFAS No. 4, Reporting Gains and Losses from Extinguishment of Debt and an amendment of that statement, SFAS No. 64, Extinguishment of Debt Made to Satisfy Sinking - Fund Requirements. Management has not yet determined the effects of adopting this Statement on the financial position or results of operations. However, it appears that gains or losses on certain debt extinguishments previously reported as extraordinary will now generally be included in pretax income. The Company intends to adopt SFAS No. 145 effective January 1, 2003. In 2001, SFAS No. 143 "Accounting for Asset Retirement" established rules for the recognition and measurement of retirement obligations associated with long-lived assets. The pronouncement requires that retirement costs be capitalized as part of the cost of related assets and subsequently expensed using a systematic and rational method. The Company will adopt the statement effective January 1, 2003. The transition adjustment resulting from the adoption of SFAS No. 143 will be reported as the cumulative effect of a change in accounting principle. At this time, the Company cannot estimate the effect of SFAS No. 143's adoption on its financial position or results of operations. However, given the large number of wells in which the Company owns an interest, the effect could be significant. In 2001, the FASB issued SFAS No. 144, "Accounting for Impairment or Disposal of Long-Lived Assets." The Statement establishes a single accounting model for long-lived assets to be disposed of by sale and provides additional implementation guidance for assets to be held and used and assets to be disposed of other than by sale. The statement requires operating losses from discontinued operations to be recognized in the periods in which they are incurred. This statement was adopted by the Company effective January 1, 2002 with no initial effect on its financial statements. Beginning in 2001, SFAS No. 133, "Accounting for Derivatives," required that derivatives be 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 Other Comprehensive Income ("OCI") and reclassified to earnings when the transaction is consummated. Ineffective portions of such hedges are recognized 13

in earnings as they occur. On adopting SFAS No. 133 in January 2001, the Company recorded a $72.1 million net unrealized pre-tax hedging loss on its balance sheet and an offsetting deficit in OCI. Due to the decline in oil and gas prices since then, the roll off of expiring hedges and the effect of new hedges, this loss had become a $6.8 million unrealized pre-tax gain at June 30, 2002. SFAS No. 133 can greatly increase volatility of earnings and stockholders' equity of independent oil companies which have active hedging programs such as Range. 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 Interest and 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. The reduced OCI at June 30, 2002 related to increases in oil and gas prices since December 31, 2001. Of the $6.8 million unrealized pre-tax gain at June 30, 2002, $7.6 million would be reclassified to earnings over the next twelve month period if prices remained constant. Actual amounts that will be reclassified will vary as a result of 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 months of 2002. At December 31, 2001, based on accounting requirements, an allowance for bad debts of $1.3 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 amounts. The gain included in OCI at year-end 2001 was included in Interest and other revenue in the first quarter of 2002. In the three months ended June 30, 2002, the Company wrote off this receivable against the allowance for bad debts. The last Enron contract expired in March 2002. If the Company recovers any of its $1.6 million unsecured claim, the recovery will be reported as income at that time. The Company enters into contracts to reduce the effect of fluctuations in oil and gas prices. These contracts generally qualify as cash flow hedges; however, a portion has an ineffective portion (changes in realized prices that do not match the changes in hedge price) which is recognized in earnings. Prior to 2001, gains and losses were determined monthly and included in revenues in the period the hedged production was sold. Starting in 2001, gains or losses on open contracts were recorded in OCI. The Company also enters into swap agreements to reduce the risk of changing interest rates. These agreements qualify as fair value hedges and related income or expense are recorded as an adjustment to interest expense in the period covered. Interest and other revenues in the Consolidated Statements of Operations reflected ineffective hedging gains of $1.0 million and $3.3 million for the three months and the six months ended June 30, 2001, respectively. Ineffective hedging losses of $462,000 and $2.2 million are included for the three months and six months ended June 30, 2002, respectively. Net unrealized hedging gains and losses of $4.4 million (net of $2.4 million losses on interest rate swaps) and restated OCI of $9.6 million (net of tax) were recorded on the balance sheet at June 30, 2002. See Note 7. (4) ACQUISITIONS Acquisitions are accounted for as purchases. Purchase prices are allocated to acquired assets and assumed liabilities based on estimates of fair value. Acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities. The Company purchased various properties for $2.2 million and $2.7 million during the six months ended June 30, 2001 and 2002, respectively. (5) IPF RECEIVABLES At June 30, 2002, IPF had net receivables of $37.4 million after a $19.8 million valuation allowance. The receivables represent overriding royalty interests payable from an agreed-upon share of revenues until a specified return is achieved. The royalties are property interests that serve as security for receivables. The Company estimates that $7.7 million of receivables at June 30, 2002 will be repaid in the next twelve months and are classified as current. Since IPF's receivables primarily relate to oil properties, a decrease in the oil price could cause an increase in IPF's valuation allowance. 14

(6) INDEBTEDNESS The Company had the following debt and Trust Preferred (as hereinafter defined) outstanding as of the dates shown. Interest rates at June 30, 2002, excluding the impact of interest rate swaps, are shown parenthetically (in thousands):

Subsequent to June 30, 2002, the Company repurchased $3.0 million of 8.75% Notes and $500,000 of 6% Debentures at a discount. Interest paid in cash during the three months ended June 30, 2001 and 2002 totaled $4.9 million and $2.9 million, respectively. Interest paid in cash during the six months ended June 30, 2001 and 2002 totaled $17.1 million and $12.0 million, respectively. No interest expense was capitalized during the three months or the six months ended June 30, 2001 and 2002, respectively. 15

PARENT SENIOR DEBT On May 2, 2002, the Company entered into an amended and restated $225.0 million revolving bank facility (the "Parent Facility"). The Parent Facility provides for a borrowing base subject to redeterminations each April and October. The initial borrowing base was $135.0 million. The Company has the right to increase the borrowing base by up to $10 million during any six month borrowing base period based on a percentage of the face value of subordinated debt (8.75% Notes, 6% Debentures or Trust Preferred) retired by the Company. In July 2002, the Company elected to increase the borrowing base to $141.0 million under this provision. On July 26, 2002, the borrowing base was $141.0 million, of which $39.5 million was available. The loan matures in July 2005. The weighted average interest rate was 6.7% and 4.0% for the three months ended June 30, 2001 and 2002, and 7.5% and 4.1% for the six months then ended, respectively. The interest rate is LIBOR plus a margin of 1.50% to 2.25%, depending on outstandings. A commitment fee is paid on the undrawn balance based on an annual rate of 0.375% to 0.50%. At June 30, 2002, the commitment fee was 0.375% and the interest rate margin was 1.75%. At July 26, 2002, the interest rate was 3.6%. NON-RECOURSE DEBT The Company consolidates its proportionate share of borrowings on Great Lakes' $275.0 million secured revolving bank facility (the "Great Lakes Facility"). The Great Lakes Facility is non-recourse to Range and provides for a borrowing base subject to redeterminations each April and October. On July 26, 2002, the borrowing base was $205.0 million of which $62.0 million was available. The loan matures in January 2005. The interest rate on the Great Lakes Facility is LIBOR plus 1.50% to 2.00%, depending on outstandings. A commitment fee is paid on the undrawn balance at an annual rate of 0.25% to 0.50%. At June 30, 2002, the commitment fee was 0.375% and the interest rate margin was 1.75%. The average interest rate on the Great Lakes Facility, excluding hedges, was 6.7% and 3.9% for the three months ended June 30, 2001 and 2002 and 7.4% and 3.9% for the six months then ended, respectively. After hedging (see Note 7), the rate was 7.1% and 8.6% for the quarters and 9.4% and 6.7% for the six months ended June 30, 2001 and 2002, respectively. At July 26, 2002, the interest rate was 3.6% excluding hedges and 6.6% after hedging. IPF has a $100.0 million secured revolving credit facility (the "IPF Facility"). The IPF Facility is non-recourse to Range and matures in January 2004. The borrowing base under the IPF Facility is subject to redeterminations each April and October. On July 26, 2002, the borrowing base was $27 million of which $3.5 million was available. The IPF Facility bears interest at LIBOR plus 1.75% to 2.25% depending on outstandings. A commitment fee is paid on the undrawn balance at an annual rate of 0.375% to 0.50%. The weighted average interest rate on the IPF Facility was 6.6% and 4.1% for the three months ended June 30, 2001 and 2002, and 7.4% and 4.1% for the six months ended June 30, 2001 and 2002, respectively. As of July 26, 2002, the interest rate was 4.4%. SUBORDINATED NOTES The 8.75% Senior Subordinated Notes Due 2007 (the "8.75% Notes") are redeemable at 104.375% of principal, declining 1.46% each January to par in 2005. The 8.75% Notes are unsecured general obligations subordinated to senior debt. During the six month period ended June 30, 2002, the Company exchanged $875,000 face amount of the 8.75% Notes for 183,000 shares of common stock. In addition, during the second quarter ended June 30, 2002, the Company repurchased $5.0 million face amount of the 8.75% Notes. During the six months ended June 30, 2001, the Company repurchased $25.0 million face amount of the 8.75% Notes in the market at a discount. Only cash repurchases are reflected on the cash flow statement. The gain on all exchanges is included as a Gain on retirement of debt securities on the Consolidated Statements of Operations. Subsequent to June 30, 2002, the Company repurchased $3.0 million face amount of the 8.75% Notes at a discount. On July 26, 2002, $70.2 million of the 8.75% Notes were outstanding. The 6% Convertible Subordinated Debentures Due 2007 (the "6% Debentures") are convertible into common stock at the option of the holder at a price of $19.25 per share. The 6% Debentures mature in 2007 and are redeemable at 103.0% of principal, declining 0.5% each February to 101% in 2006, remaining at that level until it becomes par at maturity. The 6% Debentures are unsecured general obligations subordinated to all senior indebtedness, including the 8.75% Notes. During the quarters ended June 30, 2001 and 2002, $2.6 million and 16

$5.6 million of 6% Debentures were retired at a discount in exchange for 340,000 and 919,000 shares of common stock, respectively. During the six months ended June 30, 2001 and 2002, $4.2 million and $7.1 million of 6% Debentures were retired at a discount in exchange for 533,000 and 1,166,000 shares of common stock, respectively. In addition, $15,000 face amount were repurchased in the six months ended June 30, 2002. Extraordinary gains of $365,000 and $914,000 were recorded in the second quarter of 2001 and 2002, and $647,000 and $1,154,000 for the six months ended June 30, 2001 and 2002, respectively. Subsequent to June 30, 2002, the Company repurchased $500,000 face amount of the 6% Debentures at a discount. On July 26, 2002, $21.9 million of 6% Debentures were outstanding. TRUST PREFERRED - MANDATORILY REDEEMABLE SECURITIES OF SUBSIDIARIES In 1997, a special purpose affiliate (the "Trust") issued $120 million of 5.75% Trust Convertible Preferred Securities (the "Trust Preferred"). The Trust Preferred is convertible into the Company's common stock at a price of $23.50 a share. The Trust invested the proceeds in 5.75% convertible junior subordinated debentures of the Company (the "Junior Debentures"). The Junior Debentures and the Trust Preferred mature in 2027 and are currently redeemable at 103.450% of principal, declining 0.58% each November to par in 2007. The Company guarantees payment on the Trust Preferred to a limited extent, which taken with other obligations, provides a full subordinated guarantee. The Company has the right to suspend distributions on the Trust Preferred for five years without triggering a default. During such suspension, accumulated distributions accrue additional interest at a rate of 5.75% per annum. The accounts of the Trust are included in the consolidated financial statements after eliminations. Distributions are recorded as interest expense in the statement of operations, and are tax deductible. In the quarter ended June 30, 2001, $2.4 million of Trust Preferred was reacquired at a discount in exchange for 231,000 shares of common stock. During the six months ended June 30, 2001 and 2002, $2.4 million and $2.4 million of Trust Preferred were reacquired at a discount in exchange for 231,000 and 283,000 shares of common stock. An extraordinary gain of $619,000 was recorded for the quarter ended June 30, 2001 and $619,000 and $900,000 for the six months ended June 30, 2001 and 2002, respectively. On July 26, 2002, $87.3 million face amount of the Trust Preferred was outstanding. 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, 2002. Under the most restrictive covenant, which is embodied in the 8.75% Notes, approximately $3.0 million of other restricted payments could be made at June 30, 2002. As this covenant limits the ability to repurchase the 6% Convertible Debentures and Trust Preferred, the Company may seek to amend it. Subsequent to June 30, 2002, the Company repurchased $500,000 face amount of the 6% Debentures for cash which reduced the restricted payment basket to approximately $2.5 million. Under the Parent Facility, common dividends are permitted beginning January 1, 2003. Dividends on the Trust Preferred may not be paid unless certain ratio requirements are met. The Parent Facility provides for a restricted payment basket of $20.0 million plus 50% of net income (excluding Great Lakes and IPF) plus 66 2/3% of distributions, dividends or payments of debt from or proceeds from sales of equity interests of Great Lakes and IPF plus 66 2/3% of net cash proceeds from common stock issuances. The Company estimates that $22.6 million was available under the Parent Facility's restricted payment basket on June 30, 2002. (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. A portion of future oil and gas sales is periodically hedged through the use of option or swap contracts. 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, 2002, the Company had hedging contracts covering 52.7 Bcf of gas at prices averaging $3.97 per mcf and 1.2 million barrels of oil averaging $23.25 per barrel. Their fair value, represented by the estimated amount that would be realized upon termination, based on contract prices versus the New York Mercantile 17

Exchange ("NYMEX") price on June 30, 2002, was a net unrealized pre-tax gain of $6.8 million. The contracts expire monthly through December 2005. Gains or losses on open and closed hedging transactions are determined as the difference between the contract price and the reference price, which is 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 decreased by $5.3 million and increased by $3.6 million due to hedging in the quarters ended June 30, 2001 and 2002 and decreased by $28.7 million and increased by $15.4 million for the six months then ended, respectively. The following table sets forth the book and estimated fair values of financial instruments (in thousands):

(1) Fair value based on quotes received from certain brokerage houses. Quotes were 99.5% for the 8.75% Notes, 84% for the 6% Debentures and 57.2% for the 5.75% Trust Preferred. 18

The following schedule shows the effect of closed oil and gas hedges since January 1, 2001 and the value of open contracts at June 30, 2002 (in thousands):

Interest rate swaps are accounted for on the accrual basis with income or expense being recorded as an adjustment to interest expense in the period covered. For the quarter and the six months ended June 30, 2002, the related losses were insignificant. Neither the Parent Company nor IPF had interest rate swaps in effect. However, Great Lakes had nine interest rate swap agreements totaling $100.0 million, of which 50% is consolidated at Range. Two agreements totaling $45.0 million at LIBOR rates of 7.1% expire in May 2004. Two agreements totaling $20.0 million at 6.2% expire in December 2002. Five agreements totaling $35.0 million at rates averaging 4.63% expire in June of 2003. The fair value of these swaps at June 30, 2002 approximated a net loss of $4.7 million of which 50% is consolidated at Range. The combined fair value of gains on oil and gas hedges and net losses on interest rate swaps totaled $4.4 million and appear as short-term and long-term Unrealized derivative hedging gains and short-term and long-term Unrealized derivative hedging 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. In the opinion of management, such litigation and claims are likely to be resolved without material adverse effect on the Company's financial position or results of operations. In 2000, a royalty owner filed suit asking for class action certification against Great Lakes and the Company in New York, alleging that gas was sold to affiliates and gas marketers at low prices, inappropriate post production expenses reduced proceeds to the royalty owners, and improper accounting for the royalty owners' share of gas. The action sought proper accounting, the difference in prices paid and the highest obtainable prices, punitive damages and attorneys' fees. The case has been remanded to state court in New York. While the outcome of the suit is uncertain, the Company believes it will be resolved without material adverse effect on its financial position or results of operations. 20

(9) STOCKHOLDERS' EQUITY The Company has authorized capital stock of 110 million shares which includes 100 million of common stock and 10 million of preferred stock. In 1995, the Company issued $28.8 million of $2.03 Convertible Exchangeable Preferred Stock which was convertible into common stock at a price of $9.50. The issue was retired in December 2001. Stockholders Equity was $220.6 million at June 30, 2002. The following is a schedule of changes in the number of outstanding common shares since the beginning of 2001:

Supplemental disclosures of non-cash investing and financing activities

(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:

In 1999, shareholders approved a stock option plan (the "1999 Plan") authorizing the issuance of up to 1.4 million options. In 2001, shareholders approved an increase in the number of options issuable to 3.4 million. The Company submitted a proposal to shareholders, which was approved at the annual meeting of shareholders in May 2002, increasing the number of options issuable to 6.0 million. All options issued under the 1999 Plan from August 5, 1999 through May 22, 2002 vest 25% per year beginning after one year and have a maximum term of 10 years. Options issued under the 1999 Plan after May 22, 2002 vest 30%/30%/40% over a three year period and have a maximum term of 5 years. During the six months ended June 30, 2002, 1,428,850 options were granted under the 1999 Plan at exercise prices of $4.43, $5.19 and $5.49 a share to eligible employees, including 250,000 and 175,000 options granted to the Chairman and the President, respectively. At June 30, 2002, 2.6 million options were outstanding under the 1999 Plan at exercise prices of $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. Effective May 22, 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 reelection at the Annual Meeting. At June 30, 2002, 168,000 options were outstanding under the Directors' Plan at exercise prices of $2.81 to $6.00. The Company maintains the 1989 Stock Option Plan (the "1989 Plan") which authorizes the issuance of up to 3.0 million options. No options have been granted under this plan since March 1999. Options issued under the 1989 Plan vest 30% after a year, 60% after two years and 100% after three years and expire in 5 years. At June 30, 2002, 471,505 options remained outstanding under the 1989 Plan at exercise prices of $2.63 to $7.63 a share. The Domain stock option plan was adopted when that company was acquired with existing Domain options becoming exercisable into Range common stock. No options have been granted under the Plan since the acquisition. At June 30, 2002, 131,702, all of which were vested, options remained outstanding under the Plan at an exercise price of $3.46 a share. 22

In total, 3.3 million options were outstanding at June 30, 2002 at exercise prices of $1.94 to $7.62 a share as follows:

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. Under the Stock Purchase Plan, the right to purchase shares at prices ranging from 50% to 85% of market value may be granted. Acquired shares are subject to a one year holding requirement. To date, all purchase rights have been granted at 75% of market. Due to the discount from market value, in the restatement, the Company recorded additional compensation expense of $220,000 and $126,000 in the three months ended June 30, 2001 and 2002, respectively. In May 2001, shareholders approved an increase in the number of shares authorized under the Stock Purchase Plan to 1,750,000. Through June 30, 2002, 1,213,819 shares have been sold under the Stock Purchase Plan for $5.1 million. At June 30, 2002, rights to purchase 110,500 shares were outstanding with terms expiring in May 2003. (11) DEFERRED COMPENSATION In 1996, the Board of Directors of the Company adopted a deferred compensation plan (the Plan) to encourage employees to invest in the shares of the Company. The Plan gives employees the ability to defer all or a portion of their salaries and bonuses and invest in Common Stock of the Company at a discount to market prices or make other investments at the employee's discretion. The stock held in the benefit trust is treated in a manner similar to treasury stock with an offsetting amount reflected as a deferred compensation liability of the Company and is marked-to-market, with any necessary adjustment to general and administrative expense. The Company recorded total expenses related to deferred compensation of $545,000 and $791,000 million the three months ended June 30, 2001 and 2002, respectively. For the six months ended June 30, 2001 and 2002, the Company recorded total expenses of ($648,000) and $1.7 million, respectively. (12) BENEFIT PLAN The Company maintains a 401(k) Plan which 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 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 December 2000 and 2001, the Company contributed $483,000 and $554,000, at then market value, respectively, of the Company's common stock to the 401(k) Plan. Employees have a variety of investment options in the 401(k) Plan. The Company does not require that employees hold the contributed stock in their account and are encouraged to diversify out of Company stock based on their personal investment strategies. 23

(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 were as follows (in thousands):

A deferred tax liability, generated by gains in OCI of $4.5 million, was recorded on the balance sheet at December 31, 2001. The deferred tax asset of $12.2 million at December 31, 2001 was used to offset the majority of the deferred tax liability generated by OCI. Therefore, the benefit of the reduced liability will be recorded in 2002 as the hedges creating the gains in OCI transfer to realized revenue. During the three and six months ended June 30, 2002, the Company recorded a deferred tax benefit in the income statement of $3.1 million and $4.9 million, respectively. The deferred tax benefit included $3.9 million and $3.4 million which was reclassified from other comprehensive income during the first and second quarters of 2002. The Company estimates an additional $3.0 million and $1.9 million deferred tax benefit will be reclassified from other comprehensive income to income in the third quarter and fourth quarters of 2002, respectively. At December 31, 2001, the Company had regular net operating loss (NOL) carryovers of $174.3 million and alternative minimum tax ("AMT") NOL carryovers of $155.9 million that expire between 2012 and 2020. Regular NOL's generally offset taxable income and to such extent, no income tax payments are required. To the extent that AMT NOL's offset AMT Income, no alternative minimum tax payment is due. NOL's generated prior to a change of control are subject to limitations. The Company experienced several changes of control between 1994 and 1998. Consequently, the use of $34.1 million of NOL's is limited to $10.2 million per year. No such annual limitation exists on the remaining NOL's. At December 31, 2001, the Company had a statutory depletion carryover of $6.6 million and an AMT credit carryover of $660,000 which are not subject to limitation or expiration. 24

(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):

During the three months ended June 30, 2001 and 2002, 150,000 and 262,000 stock options were included in the computation of diluted earnings per share and for the six months then ended, 154,000 and 173,000 stock options were included in such computation. Remaining stock options, the 6% Debentures, the Trust Preferred and the $2.03 Preferred were not included because their inclusion would have been antidilutive. The Company has and will continue to consider exchanging common stock or equity-linked securities for debt. 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. (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 six months ended June 30, 2002, two customers, Duke Energy Trading and Marketing and Petrocom Energy Group, LTD, accounted for 10% 25

and 11%, respectively, or more 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. Between late 1999 and June 30, 2001, Great Lakes sold approximately 90% of its gas production to First Energy, at prices based on the close of NYMEX contracts each month plus a basis differential. In mid-2001, Great Lakes began selling its gas to various purchasers including FirstEnergy. Over the next twelve months, Great Lakes expects to sell approximately a third of its gas to FirstEnergy. At December 31, 2001, 91% of Great Lakes gas was being sold at prices based on the close of NYMEX contracts each month plus a basis differential. The remainder is sold at a fixed price. (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):

(a) Includes $5,879 and $7,443 of exploration costs expensed in 2001 and the six months ended June 30, 2002, respectively. (b) Includes $3,792 and $75 for oil and gas reserves, the remainder represents acreage purchases in 2001 and the six months ended June 30, 2002, respectively. 26

(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 (in thousands):

(18) EXTRAORDINARY ITEM During the second quarter of 2001, 571,000 shares of common stock were exchanged for $2.6 million of 6% Debentures, and $2.4 million of Trust Preferred. In addition, $25.0 million face amount of 8.75% Notes were repurchased. An extraordinary gain of $1.6 million was recorded because the securities were acquired at a discount. In addition, 1,800 shares of common stock were exchanged for $12,500 of $2.03 Preferred. In the second quarter of 2002, 919,000 shares of common stock were exchanged for $5.6 million of 6% Debentures and $5.0 million of 8.75% Notes were repurchased for cash. An extraordinary gain of $845,000 was recorded because the securities were acquired at a discount. 27

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 consolidated financial statements, which have been prepared in accordance with accounting principles generally adopted in the Unites 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 Companies accounting policies, including those related to oil and gas revenues, bad debts, oil and gas properties, marketable securities, income taxes and contingencies and litigation, 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. Proved oil and natural gas reserves - Proved reserves are defined by the U.S. Securities and Exchange Commission (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. Estimated reserves are often subject to future revision, certain of 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 natural gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions inherently lead to adjustments of depreciation rates utilized by the Company. The Company can not predict the types of reserve revisions that will be required in future periods. 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 capital expenditures 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 engineers. The Company also uses proved developed reserves to recognize expense for future estimated dismantlement and abandonment costs. Costs of exploration wells in progress at year-end 2001 were not significant. Impairment of properties - The Company continually 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 natural gas sales prices, an estimate of the ultimate amount of recoverable oil and natural gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels. 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 natural gas, unfavorable adjustment to reserves, or other changes to contracts environmental regulations or tax laws. All of these same factors must be considered when testing a property's carrying value for impairment. The Company can not predict the amount of impairment charges that 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 28

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 carryforwards and other deductible differences. The Company routinely evaluates all deferred tax assets to determine the likelihood of their realization. A valuation allowance has been recognized for deferred tax assets due to management's belief that certain of these assets are not likely to be realized. The Company's deferred tax assets exceed deferred tax liabilities at year-end 2001, before considering the effects of Other comprehensive income ("OCI"). In determining deferred tax liabilities, accounting rules require OCI to be considered, even though such income (loss) has not yet been earned. The inclusion of OCI causes deferred tax liabilities to exceed deferred tax assets by $4.5 million of pre-tax income from the unrealized hedges included in OCI at year-end before statutory taxes will be recorded on the income statement. Due to the complexity of the accounting rules regarding taxes, the timing of when the Company will record deferred taxes is uncertain. 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. The Company's 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 information available to the Company. Other significant accounting policies requiring estimates include the following: The Company recognizes revenues from the sale of products and services in the period delivered. Revenues at IPF are recognized as earned. We provide an allowance for doubtful accounts for specific receivables we judge unlikely to be collected. At IPF, all receivables are evaluated quarterly and provisions for uncollectible amounts are established. The Company records a write down of marketable securities when the decline in market value is considered to be other than temporary. Impairments are recorded when management believes that a property's net book value is not recoverable based on current estimates of expected future cash flows. LIQUIDITY AND CAPITAL RESOURCES During the six months ended June 30, 2002, the Company spent $36.9 million on development, exploration and acquisitions. During the period, debt and Trust Preferred were reduced by $18.9 million. At June 30, 2002, the Company had $4.1 million in cash, total assets of $640.2 million and, including the Trust Preferred as debt, a debt to capitalization (including debt, deferred taxes and stockholders' equity) ratio of 63%. Excluding the Trust Preferred as debt, the debt to Capitalization ratio was 56%. Available borrowing capacity on the Company's bank lines at June 30, 2002 was $39.5 million at the parent, a net $31.0 million at Great Lakes and $3.5 million at IPF. Long-term debt at June 30, 2002 totaled $373.3 million. This included $98.3 million of parent bank borrowings, a net $68.5 million at Great Lakes, $23.5 million at IPF, $73.3 million of 8.75% Notes, $22.4 million of 6% Debentures and $87.3 million of Trust Preferred. During the six months ended June 30, 2002, 1.6 million shares of common stock were exchanged for $7.1 million of 6% Debentures, $2.4 million of Trust Preferred and $875,000 of 8.75% Notes. In addition, $15,000 face amount of 6% Debentures and $5.0 million face amount of 8.75% Notes were repurchased for cash. A $2.0 million extraordinary gain was recorded as the securities were acquired at a discount. Subsequent to June 30, 2002, the Company repurchased $500,000 face amount of the 6% Debentures and $3.0 million of 8.75% 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 29

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. 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 approximately 70%, 55%, 30% and 5% of anticipated production from proved reserves on an mcfe basis for the remainder of 2002, 2003, 2004 and 2005, respectively. The $38.6 million of capital expenditures (which included $6.0 million for abandonment) in the six months ended June 30, 2002 was funded with internal cash flow. Net cash provided by operations for the six months ended June 30, 2001 and 2002 was $63.0 million and $46.0 million, respectively. Cash flow from operations decreased from the prior year with lower prices and higher exploration expense being somewhat offset by lower direct operating and interest expense. Net cash used in investing for the six months ended June 30, 2001 and 2002 was $24.7 million and $37.1 million, respectively. The 2001 period included $32.6 million of additions to oil and gas properties partially offset by $6.9 million of IPF receipts (net of fundings) and $1.0 million in asset sales. The 2002 period included $38.6 million of additions to oil and gas properties partially offset by $1.5 million of IPF receipts (net of fundings). Net cash used in financing for the six months ended June 30, 2001 and 2002 was $38.0 million and $8.2 million, respectively. During the first six months of 2002, total debt (including Trust Preferred) declined $18.9 million. Parent bank debt increased which was more than offset by decreases in non-recourse bank debt of $6.8 million, Subordinated Notes (8.75% Notes and 6% Debentures) of $13.0 million and the Trust Preferred of $2.4 million. The net reduction in debt was the result of exchanges of common stock and the use of excess cash flow to reduce debt. Capital Requirements During the six months ended June 30, 2002, the $38.6 million of capital expenditures was funded with internal cash flow. The Company seeks to entirely fund its capital budget with internal cash flow. Based on the 2002 capital budget of $100.0 million, the Company sought to increase production and expand the reserve base. Due to certain production interruptions experienced in the first quarter of this year, production during the year may not increase. However, the Company believes production will grow on a quarterly basis by year-end. The Company currently anticipates the capital expenditure program will be entirely funded with internal cash flow in 2002. Banking The Company maintains three separate revolving bank credit facilities: a $225.0 million facility at the Parent; a $100.0 million facility at IPF and a $275.0 million facility at Great Lakes. Each facility is secured by substantially all the borrowers' assets. The IPF and Great Lakes facilities are non-recourse to Range. As Great Lakes is 50% owned, half its borrowings are consolidated in Range's financial statements. Availability under the facilities is subject to borrowing bases set by the banks semi-annually and in certain other circumstances. The borrowing bases are dependent on a number of factors, primarily the lenders' assessment of the future cash flows. Redeterminations, other than increases, require approval of 75% of the lenders, increases require unanimous approval. At July 26, 2002, the Parent had a $141.0 million borrowing base of which $39.5 million was available. IPF had a $27.0 million borrowing base, of which $3.5 million was available. Great Lakes, half of which is consolidated at Range, had a $205.0 million borrowing base, of which $62.0 million was available. Hedging Oil and Gas Prices The Company regularly enters into hedging agreements to reduce the impact of fluctuations in oil and gas prices. The Company's current policy, when futures prices justify, is to hedge 50% to 75% of anticipated production from existing proved reserves on a rolling 12 to 18 month basis. At June 30, 2002, hedges were in place covering 52.7 Bcf of gas at prices averaging $3.97 per Mmbtu and 1.2 million barrels of oil at prices 30

averaging $23.25 per barrel. Their fair value at June 30, 2002 (the estimated amount that would be realized on termination based on contract versus NYMEX prices) was a net unrealized pre-tax gain of $6.8 million. The contracts expire monthly and cover approximately 70%, 55%, 30% and 5% of anticipated production from proved reserves on an mcfe basis for the remainder of 2002, 2003, 2004 and 2005, respectively. Gains or losses on open and closed hedging transactions are determined as the difference between contract price and a reference price, generally closing prices on the NYMEX. Gains and losses are 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 six months ended June 30, 2001 were $28.7 million and oil and gas revenues were increased by $15.4 million from hedging for the six months ended June 30, 2002. Interest Rates At June 30, 2002, Range had $373.3 million of debt (including Trust Preferred) outstanding. Of this amount, $183.0 million bore interest at fixed rates averaging 7.0%. Senior debt and non-recourse debt totaling $190.3 million bore interest at floating rates which averaged 3.7% at that date. 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, 2002, Great Lakes had interest rate swap agreements totaling $100.0 million, 50% of which is consolidated at Range. Two agreements totaling $45.0 million at rates of 7.1% expire in May 2004, two agreements totaling $20.0 million at 6.2% expire in December 2002, and five agreements totaling $35.0 million at rates averaging 4.63% expire in June 2003. The values of these swaps are marked to market quarterly. The fair value of the swaps, based on then current quotes for equivalent agreements at June 30, 2002, was a net loss of $4.7 million, of which 50% is consolidated at Range. The 30-day LIBOR rate on June 30, 2002 was 1.8%. A 1% increase or decrease in short-term interest rates would cost or save the Company approximately $1.4 million in annual interest expense. Capital Restructuring Program As described in Note 1 to the Consolidated Financial Statements, the Company took a number of steps beginning in 1998 to strengthen its financial position. These steps included asset sales and the exchange of common stock for fixed income securities. These initiatives have helped reduce parent company bank debt from $365.2 million to $98.3 million and total debt (including Trust Preferred) from $727.2 million to $373.3 million at June 30, 2002. While the Company's financial position has stabilized, management believes debt remains too high. To return to its historical posture of consistent profitability and growth, the Company believes it should further reduce debt. Management currently believes the Company has sufficient cash flow and liquidity 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 2002, the Company received an average of $22.46 per barrel of oil and $3.42 per mcf of gas after hedging compared to $26.12 per barrel of oil and $4.04 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, such inflation does not normally have a significant effect on the Company. However, industry specific inflationary pressure built up in late 2000 and 2001 due to favorable conditions in the industry. While product prices declined in late 2001 and the first quarter of 2002, the cost of services in the industry have not declined by the same percentage. Increases in product prices could cause industry specific inflationary pressures to again increase. 31

RESULTS OF OPERATIONS The following table identifies certain items in the results of operations and is presented to assist in comparison of the second quarter and six month period of 2002 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):

Comparison of 2002 to 2001 Quarters Ended June 30, 2001 and 2002 Net income in the second quarter of 2002 totaled $7.3 million, compared to $17.0 million in the prior year period. Gains on retirement of securities of $1.6 million and $845,000 are included in the three months ended June 30, 2001 and 2002, respectively. Production declined to 150.7 Mmcfe per day, a 1% decrease from the prior year period. The decline was due to lower production at Matagorda Island 519 and other natural production declines in the Gulf Coast area. Late in 2001, the operator of Matagorda Island 519 began a workover on the L-4 well with the intent of adding production from a shallower formation. During the workover, the well was damaged and attempts to bring it back have failed to date. Revenues declined primarily due to a decrease in average prices per mcfe to $3.55. The average prices received for oil decreased 12% to $22.27 per barrel, 7% for gas to $3.59 per mcf and 47% for NGL's to $12.58 per barrel. Production expenses decreased 15% to $9.9 million as a result of significantly lower production taxes and workover costs in the Gulf of Mexico. Operating cost (including production taxes) per mcfe produced averaged $0.72 in 2002 versus $0.84 in 2001. Transportation and processing revenues increased 29% to $924,000 with significantly lower compressor rental expense and higher oil trading margins due to lower oil inventories. IPF recorded income of $1.0 million, a decrease of $109,000 from the 2001 period. IPF expenses in 2001 included a $406,000 favorable valuation allowance adjustment and an $816,000 favorable increase to receivables. The 2002 period includes a $1.4 million unfavorable valuation allowance adjustment. IPF net also declined from the previous year due to lower oil and gas prices and a smaller portfolio balance. During the quarter ended June 30, 2002, IPF expenses included $476,000 of administrative costs and $261,000 of interest, compared to prior year period administrative expenses of $419,000 and interest of $393,000. Exploration expense increased $810,000 to $2.2 million, primarily due to additional seismic activity. General and administrative expenses increased 12% to $4.7 million in the quarter primarily due to higher 32

accounting and engineering technical consulting costs, information systems programming costs, salary related expenses and non-cash compensation expenses. Interest and other income decreased from a positive $1.8 million in 2001 to a loss of $1.2 million. The 2001 period included $1.0 million of ineffective hedging gains and $768,000 of gains on asset sales. The 2002 period included $462,000 of ineffective hedging gains and a $851,000 write down of marketable securities. Interest expense decreased 20% to $6.3 million as a result of the lower outstanding debt and falling interest rates. Total debt was $412.3 million and $373.3 million at June 30, 2001 and 2002, respectively. The average interest rates were 6.6% and 5.3%, respectively, at June 30, 2001 and 2002 including fixed and variable rate debt. Depletion, depreciation and amortization ("DD&A") increased 5% from the second quarter of 2001. The per mcfe DD&A rate for the second quarter of 2002 was $1.41, a $0.09 increase from the rate for the second quarter of 2001. The DD&A rate is determined based on year-end reserves (which are evaluated based on a published ten-year price forecast) 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 2002 to approximate $1.38 per mcfe. The high DD&A rate will make it difficult for the Company to remain profitable if commodity prices fall materially. Six Month Periods Ended June 30, 2001 and 2002 Net income for the six months ended June 30, 2002 totaled $11.7 million compared to $37.0 million for the comparable period of 2001. Gains on retirement of securities of $2.0 million are included in each of the six months ended June 30, 2001 and 2002, respectively. Production for the six months declined to 149.9 Mmcfe per day, a 1% decrease from the prior year period. The decline was due to lower production at Matagorda Island 519 and other natural production declines in the Gulf Coast area. Revenues declined primarily due to a decrease in average prices per Mcfe to $3.42. The average prices received for oil decreased 14% to $22.46 per barrel, 15% for gas to $3.42 per mcf and 49% for NGL's to $11.79 per barrel. Production expenses decreased 21% to $19.1 million as a result of lower production taxes and workover costs in the Gulf of Mexico. Operating cost (including production taxes) per mcfe produced averaged $0.71 in 2002 versus $0.89 in 2001. Transportation and processing revenues were the same as the prior year at $1.7 million. IPF recorded income of $2.2 million, a decrease of $1.5 million from the 2001 period. IPF expenses in 2001 included $1.9 million of favorable valuation allowance adjustments and increases to receivables. The 2002 period includes $2.5 million unfavorable valuation allowance adjustments. IPF revenue declined from the previous year due to lower oil and gas prices and a smaller portfolio balance. During the six months ended June 30, 2002, IPF expenses included $870,000 of administrative costs and $513,000 of interest, compared to prior year period administrative expenses of $938,000 and interest of $1,084,000. Exploration expense increased $5.0 million to $7.4 million, primarily due to additional seismic activity and the first quarter $3.5 million dry hole cost in East Texas. General and administrative expenses increased 46% to $9.2 million in the six months ended June 30, 2002 due to higher non-cash compensation expense, higher accounting and engineering consulting costs, information systems programming costs and salary related expenses. Interest and other income decreased from a positive $3.3 million to a loss of $3.2 million. The 2001 period included $3.3 million of ineffective hedging gains, $1.1 million of gains on asset sales offset by a $1.3 million write down of marketable securities. The 2002 period included $2.2 million of ineffective hedging losses and a $1.2 million write down of marketable securities. Interest expense decreased 34% to $11.6 million as a result of lower outstanding debt and falling interest rates. Depletion, depreciation and amortization increased 3% from the six month period of 2001. The per mcfe DD&A rate for the six months of 2002 was $1.38, a $0.06 increase from the rate for the same period of the prior year. 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. In the Company's case, the term "market risk" refers primarily 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 indicators of reasonably possible losses. This forward-looking information provides indicators of how Range views and manages its ongoing market risk exposures. The Company's market risk sensitive instruments were entered into for purposes other than trading. Commodity Price Risk. Range's major market risk exposure is to oil and gas pricing. Realized pricing is primarily driven by worldwide prices for oil and 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, Range receives a fixed price for its production and pays market prices to the contract counterparty. This hedging is intended to reduce the impact of oil and gas price fluctuations on the Company's results and not to increase profits. 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 other comprehensive income ("OCI"). The gains or losses realized as a result of hedging are substantially offset in the cash market when the commodity is delivered. Of the $6.8 million unrealized pre-tax gain included in OCI at June 30, 2002, $7.6 million 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. Range does not hold or issue derivative instruments for trading purposes. As of June 30, 2002, oil and gas hedges were in place covering 52.7 Bcf of gas and 1.2 million barrels of oil. Their fair value, represented by the estimated amount that would be realized on termination based on contract versus NYMEX prices, was a net unrealized pre-tax gain of $6.8 million at June 30, 2002. These contracts expire monthly through December 2005 and cover approximately 70%, 55%, 30% and 5% of anticipated production from proved reserves on an mcfe basis for the remainder of 2002, 2003, 2004 and 2005, respectively. 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. Net realized losses incurred relating to these swaps for the six months ended June 30, 2001 were $28.7 million and net realized gains were $15.4 million for the six months ended June 30, 2002. In the first six months of 2002, a 10% reduction in oil and gas prices, excluding amounts fixed through hedging transactions, would have reduced revenue by $7.8 million. If oil and gas future prices at June 30, 2002 had declined 10%, the unrealized hedging gain at that date would have increased $22.3 million. Interest rate risk. At June 30, 2002, Range had $373.3 million of debt (including Trust Preferred) outstanding. Of this amount, $183.0 million bore interest at fixed rates averaging 7.0%. Senior debt and non-recourse debt totaling $190.3 million bore interest at floating rates averaging 3.7%. At June 30, 2002, Great Lakes had nine interest rate swap agreements totaling $100.0 million (See Note 7), 50% of which is consolidated at Range, which had a fair value loss (Range's share) of $2.4 million at that date. A 1% increase or decrease in short-term interest rates would cost or save the Company approximately $1.4 million in annual interest expense. 34

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. In February 2000, a royalty owner filed suit asking for class certification against Great Lakes and the Company in New York federal district court, alleging that gas was sold to affiliates and gas marketers at low prices and inappropriate post production expenses reduced proceeds to the royalty owners and that the royalty owners' share of gas was improperly accounted for. The action sought a proper accounting, an amount equal to the difference in prices paid and the highest obtainable prices, punitive damages and attorneys' fees. While the outcome is uncertain, the Company believes the suit will be resolved without material adverse effect on its financial position or result of operations. ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS. (a) Not applicable (b) Not applicable (c) At various times during the quarter and six months ended June 30, 2002, the Company issued common stock in exchange for fixed income securities. The shares of common stock issued in such exchanges were exempt from registration under Section 3(a)(9) of the Securities Act of 1933. During the quarter and the six months ended June 30, 2002, a total of $5.6 million and $7.1 million face value of the 6% Debentures were retired in exchange for 919,000 and 1.2 million shares of common stock, $875,000 face value of 8.75% Notes was retired in exchange for 183,000 shares of common stock, $2.4 million face value of Trust Preferred were exchanged for 283,000 shares of common stock. (d) Not applicable. 35

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. On May 23, 2002, the Company held its Annual Meeting of Stockholders. At such meeting Robert E. Aikman, Anthony Dub, V. Richard Eales, Thomas J. Edelman, Allen Finkelson, Alexander P. Lynch and John H. Pinkerton were reelected as Directors of the Company. Jonathan S. Linker was also elected as a Director of the Company. At the Annual Meeting, the shareholders approved the following: 1. An increase in the Common shares authorized for issuance under the Company's Stock Option Plan to 6,000,000 shares.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K. (a) Exhibits: 3.1.1. Certificate of Incorporation of Lomak dated March 24, 1980 (incorporated by reference to the Company's Registration Statement (No. 33-31558)). 3.1.2. Certificate of Amendment of Certificate of Incorporation dated July 22, 1981 (incorporated by reference to the Company's Registration Statement (No. 33-31558)). 3.1.3. Certificate of Amendment of Certificate of Incorporation dated September 8, 1982 (incorporated by reference to the Company's Registration Statement (No. 33-31558)). 3.1.4. Certificate of Amendment of Certificate of Incorporation dated December 28, 1988 (incorporated by reference to the Company's Registration Statement (No. 33-31558)). 3.1.5. Certificate of Amendment of Certificate of Incorporation dated August 31, 1989 (incorporated by reference to the Company's Registration Statement (No. 33-31558)). 3.1.6. Certificate of Amendment of Certificate of Incorporation dated May 30, 1991 (incorporated by reference to the Company's Registration Statement (No. 333-20259)). 3.1.7. Certificate of Amendment of Certificate of Incorporation dated November 20, 1992 (incorporated by reference to the Company's Registration Statement (No. 333-20257)). 3.1.8. Certificate of Amendment of Certificate of Incorporation dated May 24, 1996 (incorporated by reference to the Company's Registration Statement (No. 333-20257)). 3.1.9. Certificate of Amendment of Certificate of Incorporation dated October 2, 1996 (incorporated by reference to the Company's Registration Statement (No. 333-20257)). 3.1.10. Restated Certificate of Incorporation as required by Item 102 of Regulation S-T (incorporated by reference to the Company's Registration Statement (No. 333-20257)). 3.1.11. Certificate of Amendment of Certificate of Incorporation dated August 25, 1998 (incorporated by reference to the Company's Registration Statement (No. 333-62439)). 3.1.12. Certificate of Amendment of Certificate of Incorporation dated May 25, 2000 (incorporated by reference to the Company's Form 10-Q dated August 8, 2000). 3.2.1. By-Laws of the Company (incorporated by reference to the Company's Registration Statement (No. 33-31558). 3.2.2 Amended and Restated By-laws of the Company dated May 24, 2001. (b) Reports on Form 8-K Form 8-K/A dated July 17, 2002 (filed on July 17, 2002) reporting under Item 4 - Changes in Registrant's Certifying Accountant. Form 8-K dated July 15, 2002 (filed on July 15, 2002) reporting under Item 4 - Changes in Registrant's Certifying Accountant. Form 8-K dated August 14, 2002 (filed on August 14, 2002) reporting under Item 9 - Regulation FD Disclosure. 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. RANGE RESOURCES CORPORATION By: /s/ Eddie M. LeBlanc -------------------------- Eddie M. LeBlanc Chief Financial Officer October 24, 2002 38

I, John H. Pinkerton, certify that: 1. I have reviewed this quarterly report on Form 10-Q/A of Range Resources Corporation; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; and 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report. Date: October 24, 2002 /s/ John H. Pinkerton ------------------------------------------ John H. Pinkerton, President I, Eddie M. LeBlanc, certify that: 1. I have reviewed this quarterly report on Form 10-Q/A of Range Resources Corporation; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; and 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report. Date: October 24, 2002 /s/ Eddie M. LeBlanc ------------------------------------------ Eddie M. LeBlanc, Chief Financial Officer 39

EXHIBIT INDEX