UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

(Mark one)

OR

Commission file number 0-9592

RANGE RESOURCES CORPORATION

777 Main Street, Suite 800
Fort 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 precedings 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 [  ]

69,500,017 Common Shares were outstanding on October 26, 2004.

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

     The financial statements included herein should be read in conjunction with the latest Form 10-K/A for Range Resources Corporation (the “Company” or “Range”). 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.

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RANGE RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

See accompanying notes.

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RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

See accompanying notes.

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RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

See accompanying notes.

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RANGE RESOURCES CORPORATION

See accompanying notes.

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RANGE RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

(1) ORGANIZATION AND NATURE OF BUSINESS

     The Company is engaged in the exploration, development and acquisition of oil and gas properties primarily in the Southwestern, Appalachian and Gulf Coast regions of the United States. The Company seeks to increase its production and reserves primarily through drilling and complementary acquisitions. Prior to June 23, 2004, the Company held its Appalachian oil and gas assets through a 50% owned joint venture, Great Lakes Energy Partners L.L.C. (“Great Lakes”). On June 23, 2004, the Company purchased the 50% of Great Lakes that it did not own (see footnote 4). Range is a Delaware corporation whose common stock is listed on the New York Stock Exchange.

     The Company operates in an environment with numerous financial and operating risks, including, but not limited to, 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, the highly competitive nature of the industry, and the ability to drill and acquire reserves on an attractive basis. 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. A material drop in oil and gas prices or a reduction in production and reserves would reduce its ability to fund capital expenditures through internally generated cash flow.

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

     The accompanying consolidated financial statements include the accounts of the Company, wholly-owned subsidiaries and for the periods prior to June 23, 2004, a 50% pro rata share of the assets, liabilities, income and expenses of Great Lakes. On June 23, 2004, the Company purchased the 50% of Great Lakes that it did not own (see footnote 4). The September 30, 2004 balance sheet includes 100% of the assets and liabilities of Great Lakes. The statement of operations for the three months ended September 30, 2004 includes 100% of the revenues and expenses of Great Lakes. The statement of operations for the nine months ended September 30, 2004 includes 50% of the revenues and expenses of Great Lakes up to June 23, 2004 and 100% thereafter. Liquid investments with 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 and Credit Risk

     The Company recognizes revenues from the sale of products and services in the period delivered. Payments received at Independent Producer Finance (“IPF”) relating to return on investment are recognized as income with remaining receipts reducing receivables. Currently, all IPF receipts are being recognized as return of capital and therefore reduce receivables. Although all receivables are concentrated in the oil and gas industry, the Company does not view this as an unusual credit risk. The Company provides for an allowance for doubtful accounts for specific receivables judged unlikely to be collected based on the age of the receivable, the Company’s experience with the debtor, potential offsets to the amount owed and economic conditions. In addition to the allowance for doubtful accounts for IPF, the Company has allowances for doubtful accounts relating to exploration and production of $944,000 and $1.0 million at September 30, 2004 and December 31, 2003, respectively.

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 and NGLs are converted to gas equivalent basis (“mcfe”) at the rate of six mcf per barrel. The depletion, depreciation and amortization (“DD&A”) rates were $1.36 per mcfe and $1.49 per mcfe in the three months ended September 30, 2004 and 2003, respectively and $1.37 per mcfe and $1.49 per mcfe for the nine months ended September 30, 2004 and 2003, respectively. Unproved properties had a net book value of $11.5 million and $12.2 million at September 30, 2004 and December 31, 2003, respectively.

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     The Company’s long-lived assets are reviewed for impairment quarterly for events or changes in circumstances that indicate that the carrying amount of these assets may not be recoverable in accordance with Statement of Financial Accounting Standards No. 144, “Accounting for Impairment or Disposal of Long-Lived Assets.” The review is done by determining if the historical cost of proved properties less the applicable accumulated DD&A exceeds 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. 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.

Transportation and Field Assets

     The Company’s gas transportation and 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 received income for providing certain field services which are recognized as earned and are recorded as an offset to direct operating expenses. These revenues approximated $950,000 and $500,000 in the three month periods ended September 30, 2004 and 2003, respectively. 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.

Independent Producer Finance

     IPF owns dollar denominated overriding royalties in oil and gas properties. 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 relating to the return on investment are recognized as income with the remaining receipts reducing receivables. Currently, all receipts are being recognized as a return of capital. The receivables are evaluated quarterly and provisions for the valuation allowance are adjusted accordingly. At September 30, 2004, the receivable balance was $10.7 million, offset by a valuation allowance of $4.8 million for a net receivable balance of $5.9 million. At December 31, 2003, the receivable balance was $22.2 million offset by a valuation allowance of $9.6 million for a net receivable balance of $12.6 million. The decline in the receivable balance and the valuation allowance from December 31, 2003 is due to collections and the sale of certain royalties, where the receivable amounts and the valuation allowance amounts were eliminated. The receivables are non-recourse and are from small operators who have limited access to capital and the royalties frequently lack diversification. During the third quarter of 2004, IPF revenues of $1,300 were offset by $154,000 of administrative expenses and a $240,000 net increase in the valuation allowance. During the same period of the prior-year, revenues of $297,000 were offset by $252,000 of interest and administrative expenses, and a $326,000 increase in the valuation allowance. Since 2001, IPF has not acquired any new royalties and therefore, the portfolio has declined due to collections and sales.

Other Assets

     The cost of issuing debt is capitalized and included in other assets on the Company’s Consolidated Balance Sheets. These costs are generally amortized over the expected life of the related securities. When a security is retired prior to maturity, related unamortized costs are expensed. At September 30, 2004 and December 31, 2003, these capitalized costs totaled $5.8 million and $2.4 million, respectively. At September 30, 2004, other assets included $5.8 million unamortized debt issuance costs, $474,000 of long-term deposits, $5.2 million of marketable securities held in deferred compensation plans and an insurance claim receivable related to certain offshore properties. The insurance claim is under normal review by the insurance carrier; therefore, it may deny some or all of the claim.

Gas Imbalances

     The Company uses the sales method to account for gas imbalances, recognizing revenue based on gas sold rather than the Company’s shares of gas produced. A liability is recognized when the imbalance exceeds the estimate of remaining reserves. Gas imbalances at September 30, 2004 and December 31, 2003 were not significant.

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Derivative Financial Instruments and Hedging

     The Company enters into contracts to reduce the impact of volatile oil and gas prices. 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 floor price and a predetermined ceiling price.

     The Company also enters into swap agreements to reduce the risk of changing interest rates. These instruments qualify as cash flow hedges whereby changes in the fair value of the swaps are reflected as an adjustment to other comprehensive income (loss) (“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.

     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 as such transactions are settled. Changes in the value of the ineffective portion of all open hedges (changes in realized prices that do not match the changes in the hedge price) are recognized in earnings as they occur. 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. At September 30, 2004, the Company reflected an unrealized net pre-tax commodity hedging loss on its Balance Sheet of $132.9 million. Ineffective gains or losses are recorded in other revenue while the hedge contract is open and may increase or decrease 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 $132.9 million unrealized pre-tax loss at September 30, 2004, $103.4 million of losses would be reclassified to earnings over the next twelve month period and $29.5 million in later periods, if future prices remained constant. Actual amounts that will be reclassified will vary as a result of future changes in prices.

     Other revenues in the Consolidated Statements of Operations reflected ineffective commodity hedging losses (changes in realized prices did not match the changes in the hedge price) of $507,000 and gains of $1.1 million for the three months ended September 30, 2004 and September 30, 2003, respectively, and losses of $1.1 million and $178,000 in the nine months ended September 30, 2004 and 2003, respectively. Interest expense includes ineffective interest hedging gains of $157,000 for the three months ended September 30, 2003, and $1.1 million and $240,000 for the nine months ended September 30, 2004 and 2003, respectively. Unrealized hedging losses at September 30, 2004 are shown on the Company’s Consolidated Balance Sheets as net unrealized hedging losses of $132.3 million (including $575,000 of gains on interest rate swaps) and OCI losses of $81.2 million (net of taxes) (see Note 7).

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. Depletion of oil and gas properties is determined using estimates of proved oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including estimates of future recoverable reserves and commodity prices. Other estimates which may significantly impact the Company’s financial statements involve IPF receivables, deferred tax valuation allowances, fair value of derivatives and asset retirement obligations.

Pro Forma 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 of employee stock options equals the market prices of the underlying stock on the date of

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grant. If compensation cost had been determined based on the fair value at the grant date for awards in the three months and the nine months ended September 30, 2004 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):

(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 an asset retirement obligation in the period in which the liability is incurred, if a reasonable estimate of the obligation 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 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, 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, changes in the risk-free interest rate or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. At the time of abandonment, the Company will likely recognize a gain or loss on abandonment based on actual costs incurred.

     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 nine months ended September 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.

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     A reconciliation of the Company’s liability for plugging and abandonment costs for the nine months ended September 30, 2004 and 2003 is as follows (in thousands):

(4) ACQUISITIONS AND DISPOSITIONS

     Acquisitions are accounted for as purchases, and accordingly, the results of operations are included in the Company’s Statements of Operations from the respective date of acquisition. Purchase prices are assigned to acquired assets and assumed liabilities based on their estimated fair value at acquisition. The Company purchased various properties for $331.2 million and $12.4 million during the nine months ended September 30, 2004 and 2003, respectively. The purchases include $323.7 million and $8.0 million for proved oil and gas reserves, respectively, with the remainder representing unproved acreage.

     On June 23, 2004, the Company purchased the 50% of Great Lakes that it did not previously own for $200.0 million paid to the seller plus the assumption of $70.0 million of Great Lakes bank debt and the retirement of $27.7 million of oil and gas commodity hedges. The debt assumed was refinanced and consolidated with the Company’s existing credit facility as of the purchase date (See further discussion in Note 6.). The following table summarizes the preliminary allocation of the purchase price to the assets acquired and liabilities assumed at the date of acquisition (in thousands):

     The Great Lakes acquisition will involve many post-closing integration tasks. Among these are combining the Range and Great Lakes information systems and finance/accounting functions. The integration of Great Lakes into Range will require expenditures for information technology hardware and software, consultants, and employee costs. As the acquisition closed on June 23, 2004, there has not been sufficient time to determine the scope of all integration related activities and quantify the potential cost of implementing the integration. Because these issues are unresolved, additional liabilities and expense may occur from the acquisition impacting future periods.

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     The following unaudited pro forma data for the Company include the results of operations of the above acquisition as if it had been consummated at the beginning of the three months and nine months ended September 30, 2004 and 2003. The pro forma data are based on historical information and does not necessarily reflect the actual results that would have occurred nor is it necessarily indicative of future results of operations (in thousands).