SEC Filing | Range Resources

1 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q (MARK ONE) {x} QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarter ended June 30, 1999 { } TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ______ to ________ COMMISSION FILE NUMBER 0-9592 RANGE RESOURCES CORPORATION (Exact name of registrant as specified in its charter) DELAWARE 34-1312571 (State of incorporation) (I.R.S. Employer Identification No.) 500 THROCKMORTON STREET, FT. WORTH, TEXAS 76102 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (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 --- --- 37,567,786 Common Shares were outstanding on August 10, 1999 2 PART I. FINANCIAL INFORMATION The financial statements included herein have been prepared in conformity with generally accepted accounting principles. They should be read in conjunction with the December 31, 1998 Form 10-K filing. 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. 2 3 RANGE RESOURCES CORPORATION CONSOLIDATED BALANCE SHEETS (IN THOUSANDS, EXCEPT PER SHARE DATA)

SEE ACCOMPANYING NOTES. 3 4 RANGE RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF INCOME (IN THOUSANDS, EXCEPT PER SHARE DATA)

SEE ACCOMPANYING NOTES. 4 5 RANGE RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)

SEE ACCOMPANYING NOTES. 5 6 RANGE RESOURCES CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) ORGANIZATION: Range Resources Corporation ("Range" or the "Company") is an independent oil and gas company engaged in development, exploration and acquisition primarily in three core areas of the United States: the Southwest, the Gulf Coast and Appalachia. Through its IPF subsidiary, the Company also provides financing to smaller producers by purchasing term overriding royalty interests in oil and gas properties. Historically, the Company has increased its reserves and production through acquisitions, development and exploration. In pursuing this strategy, the Company has concentrated its activities in selected geographic areas. In each core area, the Company has established operating, engineering, geoscience, marketing and acquisition expertise. In August 1998, the stockholders of the Company approved the acquisition via merger (the "Merger") of Domain Energy Corporation ("Domain"). Pursuant to the Merger, Domain became a wholly owned subsidiary. Simultaneously, the Company's name was changed to Range Resources Corporation. (2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: BASIS OF PRESENTATION The accompanying financial statements include the accounts of the Company, all majority owned subsidiaries and its pro rata share of the assets, liabilities, income and expenses of certain oil and gas partnerships and joint ventures. Highly liquid temporary investments with an initial maturity of ninety days or less are considered cash equivalents. The Company recognizes revenues from the sale of its respective products in the period delivered. Revenue for services is recognized in the period the services are provided. MARKETABLE SECURITIES Debt and marketable equity securities are classified in one of three categories: trading, available-for-sale, or held to maturity. Equity securities of other companies held by Range qualify as available-for-sale. Such securities are recorded at fair value, and unrealized holding gains and losses, net of the related tax effect, are reflected as a separate component of stockholders' equity. A decline in the market value of an available-for-sale security below cost that is deemed other than temporary is charged to earnings and results in the establishment of a new cost basis for the security. Realized gains and losses are determined on the specific identification method and are reflected in income. During the six months ended June 30, 1999 Range sold $416,000 of marketable equity securities for an $88,000 gain. INDEPENDENT PRODUCER FINANCE ("IPF") Through IPF, Range acquires dollar denominated term overriding royalty interests in properties owned by smaller oil and gas producers. The Company accounts for the acquired term overriding royalty interests as receivables because the funds advanced to a producer for these interests are repaid from an agreed upon share of cash proceeds from the sale of production until the amount advanced plus a specified return is received. Only the interest portion of payments, net of reserves, received from producers is recognized as IPF income. The remaining cash receipts are recorded as a reduction in receivables on the balance sheet and as a return of capital on the statements of cash flows. The portion of the term overriding royalty interests classified as a current asset are those expected to be received as repayments over the next twelve month period. Periodically, the Company reviews IPF's receivables and provides an allowance for uncollectible amounts. During the first six months of 1999, IPF recorded gross income of $5.7 million and allowances against its portfolio of receivables of $2.2 million. At June 30, 1999 IPF's allowance for uncollectible receivables totaled 6 7 $16.2 million. During the first six months of 1999, IPF expenses were comprised of $2.2 million of interest and $0.8 million of administrative expenses. OIL AND GAS PROPERTIES The Company follows the successful efforts method of accounting for oil and gas properties. Exploratory costs are capitalized pending determination of whether the well has found proved reserves. Exploratory costs which result in the discovery of proved reserves and the cost of development wells are capitalized. In the absence of a determination as to whether the reserves found from an exploratory well can be classified as proved, the costs of drilling such an exploratory well are not carried as an asset for more than one year following the completion of drilling. Geological and geophysical costs, delay rentals and costs to drill unsuccessful exploratory wells are expensed. Depletion is provided on the unit-of-production method. Oil is converted to Mcfe at the rate of 6 Mcf per barrel. The depletion rates per Mcfe were $0.84 and $0.98 in the first six months of 1998 and 1999, respectively. Per unit depletion rates rose because of the impact of low year-end 1998 oil and gas prices and performance adjustments on the reserve volumes used to calculate the depletion rate for 1999. Approximately $75.9 million and $72.4 million of oil and gas properties were classified as unproved leaseholds as of December 31, 1998 and June 30, 1999, respectively. The Company performs a review for impairment at least annually or whenever circumstances indicate that the carrying amount of an asset may not be recoverable. The Company compares the carrying value of its properties to the present value of their future cash flows of unproved properties discounted at 10%, or considers such other information the Company believes relevant in evaluating the properties' fair value. Such other information may include the Company's geological assessment of the area, other acreage purchases occurring in the area, or the properties' uniqueness. Impairment is recognized if the carrying amount of an asset is greater than its expected future cash flows or realizable value. The amount of the impairment is based on the difference between a property's carrying value and estimated fair value of the asset. Unproved leaseholds whose acquisition costs are not individually significant are aggregated, and the portion of such costs estimated to ultimately prove unproductive are amortized over an average holding period. If such decline is indicated, a loss is recognized. Changes in reserves or prices could occur in the near term and adversely impact management's estimate of future cash flows and consequently the carrying value of the properties. TRANSPORTATION, PROCESSING AND FIELD ASSETS The Company owns and operates over 3,000 miles of gas gathering systems as well as a gas processing plant in proximity to its gas properties. Depreciation is calculated on the straight-line method based on estimated useful lives ranging from four to ten years. The Company receives fees for providing field related services. These fees are recognized as earned. Depreciation is calculated on the straight-line method based on estimated useful lives ranging from one to five years, except buildings which are being depreciated over ten to twenty-five year periods. SECURITY ISSUANCE COSTS Expenses associated with the issuance of the 6% Convertible Subordinated Debentures due 2007, the 8.75% Senior Subordinated Notes due 2007 and the 5 3/4% Trust Convertible Preferred Securities are included in Other Assets on the accompanying balance sheets and are being amortized on the interest method over the term of the securities. 7 8 GAS IMBALANCES The Company uses the sales method to account for gas imbalances. Under the sales method, revenue is recognized based on cash received rather than the proportionate share of gas produced. Gas imbalances at December 31, 1998 and June 30, 1999 were not material. COMPREHENSIVE INCOME Comprehensive income is defined as changes in stockholders' equity from nonowner sources which includes net income and changes in the fair value of marketable securities. The following is a calculation of comprehensive income for the three and six month periods ended June 30, 1998 and 1999.

USE OF ESTIMATES The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. NATURE OF BUSINESS The Company operates in an environment with many financial and operating risks, including, but not limited to, the ability to acquire additional economically recoverable oil and gas reserves, the inherent risks of the search for, development of and production of oil and gas, the ability to sell oil and gas at prices which will provide attractive rates of return, and the highly competitive nature of the industry and worldwide economic conditions. The Company's ability to expand its reserve base and diversify its operations is also dependent on its ability to obtain the necessary capital through operating cash flow, borrowings or the issuance of equity. RECENT ACCOUNTING PRONOUNCEMENTS In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards ("SFAS") No. 133, Accounting for Derivative Instruments and Hedging Activities, which is effective for fiscal years beginning after June 15, 1999. SFAS No. 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It also requires that an entity recognize all derivatives as either assets or liabilities on the balance sheet and measure those items at fair value. If certain conditions are met, a derivative may be specifically designated 8 9 as (a) a hedge of the exposure to change in the fair value of a recognized asset or liability or an unrecognized firm commitment, (b) a hedge of the exposure to variable cash flows of a forecasted transaction or (c) a hedge of the foreign currency exposure of a net investment in a foreign operation, an unrecognized firm commitment, an available-for-sale security, or a foreign-currency-denominated forecasted transaction. The Company plans to adopt SFAS No. 133 during 2000 and is currently evaluating its effects. RECLASSIFICATIONS Certain reclassifications have been made to prior periods presentation to conform with current classifications. (3) ACQUISITION AND DEVELOPMENT: All of the Company's acquisitions have been accounted for as purchases. Purchase prices were allocated to the assets acquired based on estimates of the fair value of such assets and liabilities at the respective acquisition dates. The acquisitions were funded by working capital, advances under the Credit Facility and the issuance of securities. In March 1998, oil and gas properties in the Powell Ranch Field in West Texas (the "Powell Ranch Properties") were acquired for $60 million, comprised of $54.6 million in cash and $5.4 million of Common Stock. As described in Note 1, the Company acquired Domain for a purchase price of $161.6 million, comprised of $50.5 million of cash and $111.1 million of Common Stock. Domain's principal assets included oil and gas properties in the Gulf Coast and the Gulf of Mexico, as well as IPF. The Company acquired other properties for an aggregate consideration of $2.7 million and $1.1 million during the year ended December 31, 1998 and the six months ended June 30, 1999, respectively. UNAUDITED PRO FORMA FINANCIAL INFORMATION The following table presents unaudited pro forma operating results as if certain transactions had occurred at the beginning of each period presented. The pro forma operating results include the Domain and Powell Ranch acquisitions.

The pro forma operating results have been prepared for comparative purposes only. They do not purport to present actual operating results that would have been achieved had the acquisitions been made at the beginning of each period presented or to necessarily be indicative of future results of operations. 9 10 (4) IPF RECEIVABLES At June 30, 1999, IPF had net receivables of $72.2 million. The receivables result from the purchase of term overriding royalty interests representing an agreed share of revenues from certain properties until the amount invested and a specified rate of return are received. These royalty interests constitute property interests that serve as security for the receivables. The Company has estimated that $8.6 million of receivables will be repaid in the next twelve months and has classified such receivables as current assets. The net outstanding receivables include an allowance for uncollectible receivables of $14.0 million and $16.2 million at December 31, 1998 and June 30, 1999, respectively. (5) ASSETS HELD FOR SALE Assets held for sale primarily consist of oil and gas properties located in south Texas and in the Gulf of Mexico. The Company has entered into agreements with an independent firm to assist it in selling these assets. The assets are recorded at the lower of cost or estimated market value of the properties as assets held for sale in the current asset section of the Consolidated Balance Sheets as of December 31, 1998 and June 30, 1999. These sales are expected to be completed during 1999. The Company sold properties for $4.1 million during the six months ended June 30, 1999. In July 1999, the Company subsequently sold properties for $16.9 million. (6) INDEBTEDNESS: The Company had the following debt outstanding as of the dates shown. Interest rates at June 30, 1999 are shown parenthetically (in thousands):

The Company maintains a $400 million revolving bank facility (the "Credit Facility"). The Credit Facility provides for a borrowing base, which is subject to semi-annual redeterminations. The Credit Facility is secured by the Company's oil and gas properties. At August 10, 1999, the borrowing base on the Credit Facility was $385 million of which $41.9 million was available to be drawn. Interest is payable quarterly or as LIBOR notes mature and the loan matures in February 2003. A commitment fee is paid quarterly on the undrawn balance at a rate of 0.25% to 0.375% depending upon the percentage of the borrowing base drawn. It is the Company's policy to extend the term period of the Credit Facility annually. Through April 30, 1999, the interest rate on the Credit Facility was LIBOR plus 1.75%. Until amounts under the Credit Facility are reduced to $300 million or the redetermined borrowing base, the interest rate is LIBOR plus 2.0%. If amounts outstanding under the Credit Facility exceed the higher of the redetermined borrowing base or $300 million on August 31, 1999, then the Company will have 10 days to 10 11 repay any excess. At June 30, 1999, the Company classified $52.1 million of borrowings under the Credit Facility as current to reflect an estimate of the amounts outstanding that will be repaid during the next twelve months. The weighted average interest rates on these borrowings were 6.6% and 7.05% for the six months ended June 30, 1998 and 1999, respectively. IPF has a $150 million revolving credit facility (the "IPF Facility") through which it finances its activities. The IPF Facility matures July 1, 2001 at which time all amounts owed thereunder are due and payable. The IPF Facility is secured by substantially all of IPF's assets and is non-recourse to the Company. The Company has no rights or obligations as to the IPF Facility. The borrowing base under the IPF Facility is subject to redeterminations, which occur routinely during the year and is currently under review. On August 10, 1999, the borrowing base on the IPF Facility was $56.5 million of which $2.9 million was available to be drawn. The IPF Facility bears interest at prime rate or interest at LIBOR plus a margin of 1.75% to 2.25% per annum depending on the total amount outstanding. Interest expense during the first six months of 1999 amounted to $2.2 million and is included in IPF expenses on the Consolidated Statements of Income. A commitment fee is paid quarterly by IPF on the average undrawn balance at a rate of 0.375% to 0.50%. The weighted average interest rate on these borrowings was 7.26% on June 30, 1999. The 8.75% Senior Subordinated Notes due 2007 (the "8.75% Notes") are not redeemable prior to January 15, 2002. Thereafter, the 8.75% Notes will be subject to redemption at the option of the Company, in whole or in part, at redemption prices beginning at 104.375% of the principal amount and declining to 100% in 2005. The 8.75% Notes are unsecured general obligations of the Company and are subordinated to all senior debt (as defined) including borrowings under the Credit Facility. The 8.75% Notes are guaranteed on a senior subordinated basis by the Company's subsidiaries. The 6% Convertible Subordinated Debentures Due 2007 (the "Debentures") are convertible into shares of Common Stock at the option of the holder at any time prior to maturity. The Debentures are convertible at a conversion price of $19.25 per share, subject to adjustment in certain events. Interest is payable semi-annually in January and June. The Debentures mature in 2007 and are redeemable beginning on February 1, 2000 at a price of 104% of the face amount and declining 0.5% annually though 2007. The Debentures are unsecured general obligations and are subordinated to all senior indebtedness (as defined), which includes the 8.75% Notes and the Credit Facility. During the first six months of 1999, $3.6 million of Debentures were retired at the option of the holders in exchange for approximately 496,000 shares of Common Stock. An extraordinary gain of $1.2 million was recorded because the Debentures were retired at a discount to their face value. The debt agreements contain covenants relating to net worth, working capital maintenance and financial ratio requirements. The Company is in compliance with these various covenants as of June 30, 1999. Interest paid during the six month periods ended June 30, 1998 and 1999 totaled, $17.9 million and $24.4 million, respectively. The Company has not capitalized any interest in the periods presented. (7) FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES: The Company's financial instruments include cash and equivalents, accounts receivable, accounts payable, debt obligations, commodity and interest rate futures, options, and swaps. The book value of cash and equivalents, accounts receivable and payable and short term debt are considered to be representative of fair value because of the short maturity of these instruments. The Company believes that the carrying value of its borrowings under its bank credit facility approximates their fair value as they bear interest at rates indexed to LIBOR. The Company's accounts receivable are concentrated in the oil and gas industry. The Company does not view such a concentration as an unusual credit risk. The Company had allowances for doubtful accounts (excluding IPF) of $782,000 and $921,000 at December 31, 1998 and June 30, 1999, respectively. 11 12 A portion of the Company's crude oil and natural gas sales are periodically hedged against price risks through the use of futures, option or swap contracts. The gains and losses on these instruments are included in the valuation of the production being hedged in the contract month and are included as an adjustment to oil and gas revenue. The Company also manages interest rate risk on its Credit Facility through the use of interest rate swap agreements. Gains and losses on swap agreements are included as an adjustment to interest expense. The following table sets forth the book value and estimated fair values of the Company's financial instruments:

At June 30, 1999, the Company had open contracts for gas and oil price derivative swaps of 25 Bcf of gas and 1,000,000 Bbls of oil. The swap contracts are designed to set average prices ranging from $1.90 to $2.75 per Mcf of gas and fix oil prices ranging form $16.82 to $19.15 per Bbl. While these transactions have no carrying value, their fair value, represented by the estimated amount that would be required to terminate the contracts, was a net loss of approximately $6.8 million at June 30, 1999. These contracts expire monthly through September 2000 on gas and through March 2000 on oil. The gains or losses on the Company's hedging transactions are determined as the difference between the contract price and the reference price, generally closing prices on the New York Mercantile Exchange. The resulting transaction gains and losses are determined monthly and are included in net income in the period the hedged production or inventory is sold. Net gains or (losses) relating to these derivatives for the six months ended June 30, 1998 and 1999 approximated $1.4 million and $1.3 million, respectively. Interest rate swap agreements, which are used by the Company in the management of interest rate exposure, are accounted for on the accrual basis. Income and expense resulting from these agreements are recorded in the same category as expense arising from the related liability. Amounts to be paid or received under interest rate swap agreements are recognized as an adjustment to expense in the periods in which they accrue. At June 30, 1999, the Company had $100 million of borrowings subject to five interest rate swap agreements at rates of 5.71%, 5.59%, 5.35%, 4.82% and 5.64% through September 1999, October 1999, January 2000, September 2000 and October 2000, respectively. The interest rate swaps may be extended at the counterparties' option for two years. The agreements require that the Company pay the counterparty interest at the above fixed swap rates and requires the counterparty to pay the Company interest at the 30-day LIBOR rate. The closing 30-day LIBOR rate on June 30, 1999 was 5.22%. The fair value of the interest rate swap agreements at June 30, 1999 is based upon current quotes for equivalent agreements. As discussed in Note 6, the Company's bank facilities are based on LIBOR plus applicable margin (as defined). These hedging activities are conducted with major financial or commodities trading institutions which management believes entail acceptable levels of market and credit risks. At times such risks may be concentrated with certain counterparties or groups of counterparties. The credit worthiness of counterparties is subject to continuing review and full performance is anticipated. 12 13 (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 July 1997, a gas utility filed an action in the State District Court of Texas. In the lawsuit, the gas utility asserted a breach of contract claim arising out of a gas purchase contract. Under the gas utility's interpretation of the contract, it sought, as damages, the reimbursement of the difference between the above-market contract price it paid and market price on a portion of the gas it has taken beginning in July 1997. In May 1998, the court granted a partial summary judgment on the contract interpretation issue in favor of the gas utility. The summary judgment allows the utility to take or pay for a limited volume of gas defined in the contract as the "contract volume" at the contract price. In October 1998, the gas utility dropped its damages claim and the state district court signed a final judgment in this case. Range appealed the judgment and in August 1999 the court of appeals affirmed the lower court's judgement. Range believes it has fully reflected the effects of the litigation in its financial statements. In May 1998, a Domain stockholder filed an action in the Delaware Court of Chancery, alleging that the terms of the Merger were unfair to a purported class of Domain stockholders and that the defendants (except Range) violated their legal duties to the class in connection with the Merger. Range is alleged to have aided and abetted the breaches of fiduciary duty allegedly committed by the other defendants. The action sought an injunction enjoining the Merger as well as a claim for money damages. On September 3, 1998, the parties executed a Memorandum of Understanding (the "MOU"), which represents a settlement in principle of the litigation. Under the terms of the MOU, appraisal rights (subject to certain conditions) were offered to all holders of Domain common stock (excluding the defendants and their affiliates). Domain also agreed to pay any court-awarded attorneys' fees and expenses of the plaintiffs' counsel in an amount not to exceed $290,000. The settlement in principle is subject to court approval and certain other conditions that have not been satisfied. (9) EQUITY SECURITIES: On October 16, 1997, the Company, through a newly-formed affiliate Lomak Financing Trust (the "Trust"), completed the issuance of $120 million of 5 3/4% trust convertible preferred securities (the "Convertible Preferred Securities"). The Trust issued 2,400,000 shares of the Convertible Preferred Securities at $50 per share. Each Convertible Preferred Security is convertible at the holder's option into 2.1277 shares of Common Stock, representing a conversion price of $23.50 per share. During the first six months of 1999, $2.3 million of Convertible Preferred Securities were retired at the option of the holders in exchange for approximately 202,000 shares of Common Stock. An extraordinary gain of $1.2 million was recorded because the Trust Convertible Preferred Securities were retired at a discount to their face value. The Trust invested the $120 million of proceeds in 5 3/4% convertible junior subordinated debentures issued by Range (the " Junior Debentures"). In turn, Range used the net proceeds from the issuance of the Junior Debentures to repay a portion of its Credit Facility. The sole assets of the Trust are the Junior Debentures. The Junior Debentures and the related Convertible Preferred Securities mature on November 1, 2027. Range and the Trust may redeem the Junior Debentures and the Convertible Preferred Securities, respectively, in whole or in part, on or after November 4, 2000. For the first twelve months thereafter, redemptions may be made at 104.025% of the principal amount. This premium declines proportionally every twelve months until November 1, 2007, when the redemption price falls to 100% of the principal. If Range redeems any Junior Debentures prior to the scheduled maturity date, the Trust must redeem Convertible Preferred Securities having an aggregate liquidation amount equal to the aggregate principal amount of the Junior Debentures so redeemed. The Company has guaranteed the payments of distributions and other payments on the Convertible Preferred Securities only if and to the extent that the Trust has funds available. Such 13 14 guarantee, when taken together with Range's obligations under the Junior Debentures and related indenture and declaration of trust, provide a full and unconditional guarantee of amounts due on the Convertible Preferred Securities. Range owns all the common securities of the Trust. As such, the accounts of the Trust have been included in Range's consolidated financial statements after appropriate eliminations of intercompany balances. The distributions on the Convertible Preferred Securities have been recorded as a charge to interest expense on Range's consolidated statements of income, and such distributions are deductible by Range for income tax purposes. In November 1995, the Company issued 1,150,000 shares of $2.03 convertible exchangeable preferred stock (the "$2.03 Preferred Stock") for $28.8 million. The $2.03 Preferred Stock is convertible into the Company's common stock at a conversion price of $9.50 per share, subject to adjustment in certain events. The $2.03 Preferred Stock is currently redeemable, at the option of the Company, at a price of $26.25 per share beginning November 1, 1998, declining $.25 per share annually through 2003. At the option of the Company, the $2.03 Preferred Stock is exchangeable for the Company's 8-1/8% Convertible Subordinated Notes due 2005. The notes would be subject to the same redemption and conversion terms as the $2.03 Preferred Stock. (10) STOCK OPTION AND PURCHASE PLAN: The Company has four stock option plans as well as a stock purchase plan. Two of the stock option plans were adopted as a result of the Merger. Information with respect to these plans is summarized below:

Range maintains a stock option plan (the "Option Plan") which authorizes the grant of options on up to 3.0 million shares of Common Stock. Under the Option Plan, incentive and non-qualified options may be issued to officers, key employees and consultants. The Option Plan is administered by the Compensation Committee of the Board. All options issued under the Option Plan before September 1998 vest 30% after one year, 60% after two years and 100% after three years. Options issued after that date vest 25% per year beginning one year after the grant date. During the six months ended June 30, 1999, no options were exercised. At June 30, 1999, 963,477 options were exercisable at prices ranging from $3.375 to $18.00 per share. In 1994, the stockholders approved an Outside Directors Stock Option Plan (the "Directors Plan"). Only Directors who are not employees of the Company are eligible to participate in the Directors Plan. The Directors Plan covers a maximum of 200,000 shares. At June 30, 1999, 92,800 director options were exercisable at prices ranging from $7.75 to $16.88 per share. In connection with the Merger, Range adopted the Second Amended and Restated 1996 Stock Purchase and Option Plan for Key Employees of Domain Energy Corporation and Affiliates (the "Domain Option Plan") and the Domain Energy Corporation 1997 Stock Option Plan for Nonemployee Directors (the "Domain Director Plan"). Subsequent to the Merger, no new options will be granted under the Domain Option and Director Plans and existing options are exercisable into shares of Range Common Stock. During the six months ended June 30, 1999 options covering 356,812 shares were exercised at a price of $0.01 per share and 11,670 shares were exercised at $3.46 per share. At June 30, 1999, 457,626 options were currently exercisable under the Domain 14 15 Option Plan at $3.46 to $11.70 per share. The remaining 13,008 options are currently exercisable at an exercise price of $0.01 per share. At June 30, 1999, options totaling 19,340 shares were outstanding and exercisable under the Domain Director Plan at $11.17 per share. In June 1997, the stockholders approved the 1997 Stock Purchase Plan (the "1997 Plan") which authorizes the sale of up to 900,000 shares of common stock to officers, directors, key employees and consultants. Under the Plan, the right to purchase shares at prices ranging from 50% to 85% of market value may be granted. The Company previously had stock purchase plans which covered 833,333 shares. The previous stock purchase plans have been terminated. The plans are administered by the Compensation Committee of the Board. From inception through June 30, 1999, a total of 417,397 registered shares had been sold under this plan through stock purchase plans, for a total consideration of approximately $2.6 million. (11) BENEFIT PLAN: The Company maintains a 401(K) Plan for the benefit of its employees. The Plan permits employees to make contributions on a pre-tax salary reduction basis. The Company makes discretionary contributions to the Plan. Company contributions for 1998 totaled $0.7 million of Common Stock, valued at market on date of contribution. (12) INCOME TAXES: The Company follows FASB Statement No. 109, "Accounting for Income Taxes". Under Statement 109, the liability method is used in accounting for income taxes. 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 laws that will be in effect when the differences are expected to reverse. The income tax provisions for the six month periods ended June 30, 1998 and 1999 were $1.2 million and $0.2 million, respectively. The current portion of the income tax provisions represent state income taxes currently payable. Statement 109 requires a valuation allowance be recorded when it is more likely than not that some or all of the deferred tax assets will not be realized. A valuation allowance for the full amount of the net deferred tax asset was recorded due to the uncertainties as to the amount of taxable income that would be generated in future years. The Company established a valuation allowance of $25 million at December 31, 1998 and increased the allowance to $30 million at June 30, 1999. Upon future realization of the deferred tax asset, $30 million of the valuation allowance will reduce the Company's future income tax expense. The Company has entered into several business combinations accounted for as purchases. In connection with these transactions, deferred tax assets and liabilities of $7.7 million and $38.3 million respectively, were recorded. In 1998 the Company acquired Domain Energy Corporation in a taxable business combination accounted for as a purchase. A net deferred tax liability of $29 million was recorded in the transaction. At December 31, 1998, the Company had available for federal income tax reporting purposes net operating loss carryovers of approximately $131 million that are subject to annual limitations as to their utilization and otherwise expire between 1999 and 2013, if unused. The Company has alternative minimum tax net operating loss carryovers of $116 million that are subject to annual limitations as to their utilization and otherwise expire from 1999 to 2013 if unused. The Company has statutory depletion carryover of approximately $4 million and an alternative minimum tax credit carryover of approximately 15 16 $911,000. The statutory depletion carryover and alternative minimum tax credit carryover are not subject to limitation or expiration. (13) ACCRUED RESTRUCTURING COSTS: In 1998, the Company implemented a restructuring plan to reduce costs and improve operating efficiencies. The restructuring plan included actions by the Company to close certain field offices, eliminate a number of technical positions, cancel certain exploration and drilling obligations, as well as consolidate administrative functions. In connection with this plan, 54 employees were terminated. In addition to termination costs, the restructuring costs include the writedown of certain impaired assets and lease and contract termination costs. Estimated charges of $0.7 million for lease and contract terminations and $0.4 million for asset impairments were recorded during the fourth quarter of 1998. At December 31, 1998 and June 30, 1999, $2.7 million and $0.5 million, respectively, were accrued in connection with the restructuring and are included in Consolidated Balance Sheet as accrued liabilities. The accrual remaining at June 30, 1999 was comprised primarily of lease and contract termination costs. The plan is anticipated to be completed during the third quarter of 1999. (14) EARNINGS PER COMMON SHARE The following table sets forth the computation of earnings per common share and earnings per common share assuming dilution (in thousands, except per share data):

16 17 For additional disclosure regarding the Debentures and the $2.03 Preferred Stock, see Notes 6 and 9, respectively. The Debentures were outstanding during 1998 and the first six months of 1999 but were not included in the computation of diluted earnings per share because the conversion price was greater than the average market price of common shares and, therefore, the effect would be antidilutive. The $2.03 Preferred Stock was outstanding during 1998 and the first six months of 1999 and was convertible into 3,026,316 of additional shares of common stock. The 3,026,316 additional shares were not included in the computation of diluted earnings per share because the conversion price was greater than the average market price of common shares and, therefore, the effect would be antidilutive. There were employee stock options outstanding during the first six months of 1998 and 1999 which were exercisable, resulting in 1,104,150 and 1,636,583 additional shares, respectively, under the treasury method of accounting for common stock equivalents. These additional shares were not included in the first six months 1999 computations of diluted earnings per share because the effect was antidilutive. (15) MAJOR CUSTOMERS: The Company markets its oil and gas production on a competitive basis. The type of contract under which gas production is sold varies but can generally be grouped into three categories: (a) life-of-the-well; (b) long-term (1 year or longer); and (c) short-term contracts which may have a primary term of one year, but which are cancelable at either party's discretion in 30-120 days. Approximately 11.5% of the Company's gas production is currently sold under market sensitive contracts which do not contain floor price provisions. For the six months ended June 30, 1999, no one customer accounted for 10% or more of the Company's total oil and gas revenues. Management believes that the loss of any one customer would not have a material adverse effect on the operations of the Company. Oil is sold on a basis such that the purchaser can be changed on 30 days notice. The price received is generally equal to a posted price set by the major purchasers in the area. Oil is sold on a basis of price and service. (16) OIL AND GAS ACTIVITIES: The following summarizes selected information with respect to oil and gas activities (in thousands):

17 18 (17) SUBSEQUENT EVENTS In June 1999, Range signed a letter of intent to form a joint venture with First Energy Corporation. Under the terms of the letter, Range and First Energy will contribute their Appalachian oil and gas properties and associated gas gathering and transportation systems to the venture and each partner will own 50% of the joint venture. Range will be contributing approximately $300 million of assets and $200 million of debt from its Credit Facility. The Appalachian properties Range intends to contribute to the joint venture represent approximately $17.5 million of the Company's oil and gas revenues for the six months ended June 30, 1999. Subsequent to closing, Range intends to consolidate its 50% interest in the assets, liabilities and operations of the joint venture. The parties need to negotiate and execute definitive agreements, complete due diligence, obtain financing and receive regulatory approval. (18) EXTRAORDINARY ITEM During 1999 Range exchanged $2.3 million of Convertible Preferred Securities and $3.6 million of Debentures for approximately 698,000 shares of Common Stock. In connection with the exchange a $2.4 million extraordinary gain was recorded because the Convertible Preferred Securities and Debentures were retired at a discount to their face value. 18 19 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS FACTORS EFFECTING FINANCIAL CONDITION AND LIQUIDITY LIQUIDITY AND CAPITAL RESOURCES General At June 30, 1999, the Company had $20 million in cash and marketable securities and total assets of $896 million. At that date, working capital was $6.1 million. During the first six months of 1999, total debt decreased $4.3 million. Approximately $369 million of the long-term debt at that date was comprised of borrowings under the Credit Facility, $125 million of 8.75% Senior Subordinated Notes and $51 million of 6% Convertible Subordinated Debentures. The Credit Facility currently provides for quarterly payments of interest, or as LIBOR notes mature, with principal due in February 2003. During 1999 Range exchanged $2.3 million of Convertible Preferred Securities and $3.6 million of Debentures for approximately 698,000 shares of Common Stock. In connection with the exchange a $2.4 million extraordinary gain was recorded because the Convertible Preferred securities and Debentures were retired at a discount to their face value. Cash Flow The Company's principal operating sources of cash include sales of oil and gas and revenues from gas transportation and marketing. The Company's cash flow is highly dependent upon oil and gas prices. Recent decreases in the market price of oil or gas have reduced cash flow and could reduce the borrowing base under the Credit Facility. The Company's principal operating sources of cash are sales of oil, natural gas and natural gas liquids, sales of natural gas, revenues from transportation, processing and marketing and IPF repayments. The decreases in the Company's cash flow from operations can be attributed primarily to decreases in oil and natural gas prices. The Company's net cash used in investing for the six months ended June 30, 1998 and 1999 was $92 million and $8.9 million, respectively. Investing activities for these periods are comprised primarily of additions to oil and gas properties through acquisitions and development and, to a lesser extent, exploitation and additions of field assets. These uses of cash have historically been partially offset through the Company's policy of divesting those properties that it deems to be marginal or outside of its core areas of operation. The Company's acquisition and development activities have been financed through a combination of operating cash flow, bank borrowings and capital raised through equity and debt offerings. The Company's net cash provided by financing for the six months ended June 30, 1998 and 1999 was $63 million and $(4.9) million, respectively. Sources of financing used by the Company have been primarily borrowings under its Credit Facility and capital raised through the various debt and equity offerings. Capital Requirements During the first six months of 1999, $15.9 million of costs were incurred for development and exploration activities. In an effort to reduce outstanding debt, the Company reduced its 1999 exploration and development capital budget to $38 million. The development and exploration expenditures are currently expected to be funded entirely by internally generated cash flow. 19 20 Bank Facilities The Credit Facility permits the Company to obtain revolving credit loans and to issue letters of credit for the account of the Company from time to time in an aggregate amount not to exceed $400 million. The Credit Facility is secured by the Company's oil and gas properties. The borrowing base is currently $385 million and is subject to semi-annual redetermination and certain other redeterminations based upon a variety of factors, including the discounted present value of estimated future net cash flow from oil and gas production. At the Company's option, loans may be prepaid, and revolving credit commitments may be reduced, in whole or in part at any time in certain minimum amounts. At August 10, 1999, the Company had $41.9 million of availability under the Credit Facility. Through April 30, 1999, the interest rate on the Credit Facility was LIBOR plus 1.75%. Until amounts under the Credit Facility are reduced to $300 million or the redetermined borrowing base, the interest rate will be LIBOR plus 2.0%. If amounts outstanding under the Credit Facility exceed the higher of the redetermined borrowing base or $300 million on August 31, 1999, then the Company will have 10 days to repay any excess. The Company plans to reduce outstanding amounts under the Credit Facility through operating cash flow and the sale of assets. Since the borrowing base is principally determined by the estimated value of oil and gas reserves these asset sales are expected to reduce the borrowing base and cash flows due to the loss of future production. The Company has developed a number of packages of oil and gas assets to offer for sale. The Company will utilize the proceeds from the sale of assets to reduce amounts outstanding under the Credit Facility. Additionally, the Company is considering the monetization of oil and gas assets whose proceeds would be used to reduce the Credit Facility. At June 30, 1999, the Company classified $55.2 million of Credit Facility borrowings as current to reflect an estimate of the amounts outstanding at June 30, 1999 that will be repaid during the next twelve months. The IPF Facility is secured by substantially all of IPF's assets and is non-recourse to the Company. The borrowing base under the IPF Facility is subject to redeterminations, which occur routinely during the year. On August 10, 1999, the borrowing base on the IPF Facility was $56.5 million of which $2.9 million was available to be drawn. The IPF Facility bears interest at prime rate or interest at LIBOR plus a margin of 1.75% to 2.25% per annum depending on the amount outstanding. Hedging Activities Periodically, the Company enters into futures, option and swap contracts to reduce the effects of fluctuations in crude oil and natural gas prices. At June 30, 1999, the Company had open hedges for natural gas swaps of 25 Bcf and oil swaps of 1,000,000 barrels. The hedged contracts are designed to set average prices ranging from $1.90 to $2.75 per Mcf of gas and fix oil prices at $18.24 per barrel. While these transactions have no carrying value, the Company's mark-to-market exposure under these contracts at June 30, 1999 was a net loss of $6.8 million. The gains or losses on the Company's hedging transactions is determined as the difference between the contract price and a reference price, generally closing prices on the NYMEX. The resulting transaction gains and losses are determined monthly and are included in the period the hedged production or inventory is sold. Net gains (losses) relating to these derivatives for the six months ended June 30, 1998 and 1999 approximated $1.4 million and $1.3 million, respectively. INFLATION AND CHANGES IN PRICES The Company's revenues and the value of its oil and gas properties have been and will be affected by changes in oil and gas prices. The Company's ability to maintain current borrowing capacity and to obtain additional capital on attractive terms is also substantially dependent on oil and gas prices. Oil and gas prices are subject to significant seasonal and other fluctuations that are beyond the Company's ability to control or predict. During the first six months of 1999, the Company received an average of $12.94 per barrel of oil and $1.94 per Mcf of gas. Although certain of the Company's costs and expenses are affected by the level of inflation, inflation did not have a significant effect during the first six months of in 1999. Should conditions in the industry improve, inflationary cost pressures may resume. 20 21 RESULTS OF OPERATIONS Comparison of 1999 to 1998 The Company reported a net loss for the three months ended June 30, 1999 of $2.1 million, versus a $0.9 million loss in the prior year period. The decrease was primarily the result of lower product prices received on oil and gas production and higher interest and depletion expenses. During the periods presented, oil and gas production volumes increased 35% to 18.0 Bcfe, an average of 197,650 Mcfe per day. Production revenues were impacted by a 10% decrease in the average price received per Mcfe of production from $2.31 in 1998 to $2.07 in 1999. The average oil price increased 25% to $15.21 per barrel while average gas prices decreased 19% to $2.00 per Mcf. As a result of the Company's larger base of producing properties and production, oil and gas production expenses increased 41% to $10.8 million in 1999 versus $7.6 million in 1998. The average operating cost per Mcfe produced increased 5% from $0.57 to $0.60 in the three months ended June 30, 1998 and 1999, respectively. Transportation, processing and marketing revenues increased only marginally during 1999. IPF income consists of the interest portion of the term overriding royalty interests and is net of an allowance for possible uncollectible accounts. During the second quarter of 1999, IPF expenses included $1.1 million of interest and $0.4 million of administrative expenses. Exploration expense decreased approximately $1.6 million to $0.4 million due to restructuring and the cost reduction program. General and administrative expenses decreased 15% to $1.8 million. General and administrative cost per Mcfe produced decreased 38% from $0.16 in 1998 to $0.10 in 1999. The decrease is principally attributable to the cost reduction program. Interest and other income increased from $(0.1) million in 1998 to $1.0 million in 1999 primarily due to increased sales of oil and gas properties. In 1999 interest expense increased 32% to $12.4 million as compared to $9.4 million in 1998. This was primarily as a result of the higher average outstanding debt balance during the year due to the financing of acquisitions and capital expenditures and a higher average cost of borrowings. The average outstanding balances on the Credit Facility were $202 million and $370 million for the first six months of 1998 and 1999, respectively. The weighted average interest rate on these borrowings were 6.6% and 6.9% for the six months ended June 30, 1998 and 1999, respectively. Depletion, depreciation and amortization increased 58% compared to 1998 as a result of increased production volumes and the amortization of $1.9 million of unproved acreage. The Company's depletion rate was $0.84 per Mcfe in the first six months of 1998 and $0.98 per Mcfe in the first six months of 1999. YEAR 2000 The Company has developed a plan (the "Year 2000 Plan") to address the Year 2000 issue caused by computer programs and applications that utilize two digit date fields rather than four to designate a year. As a result, computer equipment, software and devices with embedded technology that are date sensitive may be unable to recognize or misinterpret the actual date. This could result in a system failure or miscalculations causing disruptions of operations. The Company's Board of Directors has established a Year 2000 committee to review the adoption and implementation of the Year 2000 Plan. Assessment of the information technology ("IT") and non-IT systems has been completed. The term "IT systems" include personal computers, accounting/data processing software and other miscellaneous systems. Range's computerized accounting system was upgraded and tested to be Year 2000 compliant. The Company's personal computer systems will be compliant with minor upgrades provided by the software vendors and with the purchase of a nominal amount of additional computer equipment. The non-IT systems include operational and control equipment with embedded chip technology that is utilized in the offices and field operations. The systems were reviewed as part of the Year 2000 Plan. Most 21 22 of the wells are operated by non-computerized equipment. The potentially affected areas are the gas processing plant in the Midland Basin, telemetry that controls approximately 10% of the wells and portable metering devices which are used on less than 2% of the wells. As of June 30, 1999, Range has completed the remediation of all known Year 2000 problems associated with non-IT systems. Range is also monitoring the compliance efforts of its significant suppliers, customers and service providers with whom it does business and whose IT and non-IT systems interface with those of the Company to ensure that they will be Year 2000 compliant. If they are not, such failure could affect the ability of the Company to sell its oil and gas and receive payments therefrom and the ability of vendors to provide products and services in support of the Company's operations. Although the Company has no reason to believe that its vendors and customers will not be compliant by the year 2000, the Company is unable to determine the extent to which Year 2000 issues will affect its vendors and customers. However, management believes that ongoing communication with and assessment of the compliance efforts of these third parties will minimize these risks. The discussion of the Company's efforts and management's expectations relating to Year 2000 compliance contains forward-looking statements. Range is currently conducting a comprehensive analysis of the financial and operational problems that would be reasonably likely to result from failure by Range and significant third parties to complete efforts necessary to achieve Year 2000 compliance on a timely basis. The Company intends to complete its contingency plan by the third quarter of 1999. The primary goals are to maintain continuity of operations, preserve Company assets and protect the environment. The total costs for the Year 2000 Project is not expected to be in excess of $180,000. Of this amount, approximately $127,000 had been incurred as of June 30, 1999. Range presently does not expect to experience significant operational problems due to the Year 2000 issues. However, if all Year 2000 issues are not properly and timely identified, assessed, remediated and tested, there can be no assurance that the Year 2000 issue will not materially impact Range's results of operations or adversely affect its relationship with customers, vendors, or others. Additionally, there can be no assurance that the Year 2000 issues of other entities will not have a material impact on Range's systems or results of operations. 22 23 GLOSSARY The terms defined in this glossary are used throughout this From 10-Q. Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons. Bcf. One billion cubic feet. Bcfe. One billion cubic feet of natural gas equivalents, based on a ratio of 6 Mcf for each barrel of oil, which reflects the relative energy content. Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. Dry hole. A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or gas well. Exploratory well. A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned. Infill well. A well drilled between known producing wells to better exploit the reservoir. Mbbl. One thousand barrels of crude oil or other liquid hydrocarbons. Mcf. One thousand cubic feet. Mcf/d. One thousand cubic feet per day. Mcfe. One thousand cubic feet of natural gas equivalents, based on a ratio of 6 Mcf for each barrel of oil, which reflects the relative energy content. Mmbbl. One million barrels of crude oil or other liquid hydrocarbons. MmBtu. One million British thermal units. One British thermal unit is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit. Mmcf. One million cubic feet. Mmcfe. One million cubic feet of natural gas equivalents. Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells. Net oil and gas sales. Oil and natural gas sales less oil and natural gas production expenses. Present Value. The pre-tax present value, discounted at 10%, of future net cash flows from estimated proved reserves, calculated holding prices and costs constant at amounts in effect on the date of the report (unless such prices or costs are subject to change pursuant to contractual provisions) and otherwise in accordance with the Commission's rules for inclusion of oil and gas reserve information in financial statements filed with the Commission. Productive well. A well that is producing oil or gas or that is capable of production. 23 24 Proved developed non-producing reserves. Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells. Proved developed producing reserves. Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods. Proved developed reserves. Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved reserves. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Recompletion. The completion for production of an existing wellbore in another formation from that in which the well has previously been completed. Reserve life index. The presentation of proved reserves defined in number of years of annual production. Royalty interest. An interest in an oil and gas property entitling the owner to a share of oil and natural gas production free of costs of production. Standardized Measure. The present value, discounted at 10%, of future net cash flows from estimated proved reserves after income taxes calculated holding prices and costs constant at amounts in effect on the date of the report (unless such prices or costs are subject to change pursuant to contractual provisions) and otherwise in accordance with the Commission's rules for inclusion of oil and gas reserve information in financial statements filed with the Commission. Term overriding royalty. A royalty interest that is carved out of the operating or working interest in a well. Its term does not extend to the economic life of the property and is of shorter duration than the underlying working interest. The term overriding royalties in which the Company participates through its Independent Producer Finance subsidiary typically extend until amounts financed and a designated rate of return have been achieved. At such point in time, the override interest reverts back to the working interest owner. Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith. 24 25 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 will be resolved without a material adverse effect on the Company's financial position. In July 1997, a gas utility filed an action in the State District Court of Texas. In the lawsuit, the gas utility asserted a breach of contract claim arising out of a gas purchase contract. Under the gas utility's interpretation of the contract, it sought, as damages, the reimbursement of the difference between the above-market contract price it paid and market price on a portion of the gas it has taken beginning in July 1997. In May 1998, the court granted a partial summary judgment on the contract interpretation issue in favor of the gas utility. The summary judgment allows the utility to take or pay for a limited volume of gas defined in the contract as the "contract volume" at the contract price. In October 1998, the gas utility dropped its damages claim and the state district court signed a final judgment in this case. Range appealed the judgment and in August 1999 the court of appeals affirmed the lower court's judgement. Range believes it has fully reflected the effects of the litigation in its financial statements. In May 1998, a Domain stockholder filed an action in the Delaware Court of Chancery, alleging that the terms of the Merger were unfair to a purported class of Domain stockholders and that the defendants (except Range) violated their legal duties to the class in connection with the Merger. Range is alleged to have aided and abetted the breaches of fiduciary duty allegedly committed by the other defendants. The action sought an injunction enjoining the Merger as well as a claim for money damages. On September 3, 1998, the parties executed a Memorandum of Understanding (the "MOU"), which represents a settlement in principle of the litigation. Under the terms of the MOU, appraisal rights (subject to certain conditions) were offered to all holders of Domain common stock (excluding the defendants and their affiliates). Domain also agreed to pay any court-awarded attorneys' fees and expenses of the plaintiffs' counsel in an amount not to exceed $290,000. The settlement in principle is subject to court approval and certain other conditions that have not been satisfied. Items 2 Not applicable Item 3 Quantitative and Qualitative Disclosure About Market Risk The primary objective of the following information is to provide forward-looking quantitative and qualitative information about Range's potential exposure to market risks. The term "market risk" refers to the risk of loss arising from adverse changes in oil and gas prices and interest rates. The disclosures are not meant to be precise 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. All of Range's market risk sensitive instruments were entered into for purposes other than trading. Commodity Price Risk. Range's major market risk exposure is in the pricing applicable to its oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to U.S. natural gas production. Pricing for oil and gas production has been volatile and unpredictable for several years. Range periodically enters into financial hedging activities with respect to a portion of its projected oil and natural gas production through financial swaps whereby Range will receive a fixed price for its production and pay a variable market price to the contract counterparty. These financial hedging activities are intended to support oil and gas price fluctuations. Realized gains and losses from the settlement of these financial hedging instruments are recognized in oil and gas revenues when the associated production 25 26 occurs. The gains and losses realized as a result of these hedging activities are substantially offset in the cash market when the commodity is delivered. Range does not hold or issue derivative instruments for trading purposes. As of June 30, 1999, Range had financial oil and gas price hedging instruments in place that represented approximately 1 million barrels of oil production through March 2000 and approximately 25 Bcf of gas production through September 2000. At June 30, 1999, the 1999 hedged oil and gas volumes represented an average of approximately 70% and 55%, respectively, of remaining monthly production. The 2000 hedged oil and gas volumes represent approximately 25% and 24%, respectively, of expected 2000 production. While these transactions have no carrying value, their fair value, represented by the estimated amount that would be required to terminate the contracts, was a net loss of approximately $6.7 million at June 30, 1999. These contracts expire monthly through September 2000 on gas and through March 2000 on oil. The gains or losses on the Company's hedging transactions are determined as the difference between the contract price and the reference price, generally closing prices on the New York Mercantile Exchange. The resulting transaction gains and losses are determined monthly and are included in net income in the period the hedged production or inventory is sold. Net gains or (losses) relating to these derivatives for the six months ended June 30, 1998 and 1999 approximated $1.4 million and $1.3 million, respectively. Range uses a sensitivity analysis technique to evaluate the hypothetical effect that changes in the market value of oil and gas may have on the fair value of its commodity hedging instruments. At June 30, 1999, a 10% increase in the underlying commodities' prices would have reduced the fair value of Range's commodity hedging instruments by $3.1 million. In addition to the commodity hedging instruments described above, Range also manages its exposure to gas price risks by periodically entering into fixed-price gas contracts. The majority of these fixed-price contracts relate to Range's Appalachian and Oakridge gas production. For the remainder of 1999 and 2000 through 2003, Range's fixed-price gas contracts cover approximately 3.0 Bcf, 6.4 Bcf, 0.7 Bcf, 0.7 Bcf and 0.7 Bcf of production, respectively. Range also has gas volumes subject to fixed-price contracts from 2004 forward but the yearly volumes are less than 1.0 Bcf. The amount of 1999's remaining production covered by fixed-price contracts represents approximately 12% of expected remaining 1999 total production. Interest Rate Risk. At June 30, 1999, Range had long-term debt outstanding of $599.7 million. Of this amount, $176.3 million, or 29%, bears interest at fixed rates averaging 7.9%. The remaining $423.4 million of debt outstanding at June 30, 1999 is comprised of the Credit Facility and the IPF Facility (See Note 6) which bear interest at floating rates that averaged 7.1% at June 30, 1999. The terms of the Credit Facility and IPF Facility in place allow interest rates to be fixed at the Company's option for periods of between 30 to 360 days. To manage its potential interest rate exposure, the Company uses interest rate swap arrangements. Income and expense resulting from these arrangements are recorded in the same category as expense arising from the related liability. Amounts to be paid or received under interest rate swap agreements are recognized as an adjustment to expense in the periods in which they accrue. At June 30, 1999, the Company had $100 million of borrowings subject to five interest rate swap agreements at rates of 5.71%, 5.59%, 5.35%, 4.82% and 5.64% through September 1999, October 1999, January 2000, September 2000 and October 2000, respectively. The interest rate swaps may be extended at the counterparties' option for two years. The interest rate swaps require that the Company pay the counterparty interest at the above fixed swap rates and requires the counterparty to pay the Company interest at the 30-day LIBOR rate. The closing 30-day LIBOR rate on June 30, 1999 was 5.22%. A 10% increase in short-term interest rates on the floating-rate debt outstanding on June 30, 1999 would equal approximately 71 basis points. Such an increase in interest rates would increase Range's annual interest expense by approximately $3.0 million assuming borrowed amounts were at June 30, 1999 levels throughout the period. The above sensitivity analysis for interest rate risk excludes accounts receivable, accounts payable and accrued liabilities because of the short-term maturity of such instruments. 26 27 Item 4-5 Not applicable Item 6. Exhibits and Reports on Form 8-K (a) Exhibits Exhibit Number Description of Exhibit ----------------------- ------------------------------------------- 27 Financial Data Schedule (b) No reports filed on Form 8-K. 27 28 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: (Thomas W. Stoelk) ------------------------------------------ Thomas W. Stoelk Senior Vice President - Finance and Administration and Chief Financial Officer August 12, 1999 28 29 EXHIBIT INDEX Exhibit Number Description of Exhibit ----------------------- ------------------------------------------- 27 Financial Data Schedule 29

5 1,000 6-MOS DEC-31-1999 JAN-01-1999 JUN-30-1999 15,757 4,422 107,512 (16,177) 5,289 110,456 1,034,824 (320,793) 895,677 104,393 0 0 1,150 374 124,446 895,677 71,082 80,149 22,085 26,423 67,054 0 38,939 (13,328) 170 (13,498) 0 2,430 0 (11,068) (0.34) (0.34)