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 September 30, 1999 { } TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transaction 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 --- --- 37,635,727 Common Shares were outstanding on November 10, 1999. 2 PART I. FINANCIAL INFORMATION The financial statements included herein have been prepared in conformity with generally accepted accounting principles and should be read in conjunction with the Company's December 31, 1998 Form 10-K. 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) December 31, September 30, 1998 1999 ---------------- --------------- (unaudited) ASSETS Current assets Cash and equivalents ......................................................... $ 10,954 $ 11,289 Accounts receivable .......................................................... 30,384 25,967 IPF receivables (Note 4) ..................................................... 7,140 11,000 Marketable securities ........................................................ 3,258 3,219 Assets held for sale (Note 5) ................................................ 51,822 19,867 Inventory and other .......................................................... 3,373 9,562 --------- --------- 106,931 80,904 --------- --------- IPF receivables, net (Note 4) .................................................. 70,032 58,263 Oil and gas properties, successful efforts method .............................. 935,822 926,544 Accumulated depletion and impairment ....................................... (273,723) (322,684) --------- --------- 662,099 603,860 --------- --------- Transportation, processing and field assets .................................... 89,471 27,657 Accumulated depreciation ................................................... (15,146) (3,252) --------- --------- 74,325 24,405 --------- --------- Other .......................................................................... 8,225 8,353 --------- --------- $ 921,612 $ 775,785 ========= ========= LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities Accounts payable ............................................................. $ 28,163 $ 26,847 Accrued liabilities .......................................................... 23,626 19,636 Accrued interest ............................................................. 9,439 4,749 Current portion of long-term debt (Note 6) ................................... 55,187 29 --------- --------- 116,415 51,261 --------- --------- Senior debt (Note 6) ........................................................... 311,875 146,650 Non-recourse debt (Note 6) ..................................................... 60,100 146,755 Subordinated notes (Note 6) .................................................... 180,000 176,360 Commitments and contingencies (Note 8) ......................................... -- -- Company-obligated preferred securities of subsidiary trust (Note 9) ............ 120,000 117,669 Stockholders' equity (Notes 9 and 10) Preferred stock, $1 par, 10,000,000 shares authorized, $2.03 convertible preferred, 1,149,840 issued (liquidation preference $28,746,000) ..................................... 1,150 1,150 Common stock, $.01 par, 50,000,000 shares authorized, 35,933,523 and 37,489,311 issued ......................................... 359 375 Capital in excess of par value ............................................... 334,817 339,188 Retained deficit ............................................................. (203,396) (204,600) Other comprehensive income .................................................... 292 977 --------- --------- 133,222 137,090 --------- --------- $ 921,612 $ 775,785 ========= ========= SEE ACCOMPANYING NOTES. 3 4 RANGE RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT PER SHARE DATA) Three Months Ended Nine Months Ended September 30, September 30, --------------------------- --------------------------- 1998 1999 1998 1999 ----------- ----------- ----------- ------------ (unaudited) (unaudited) Revenues Oil and gas sales ..................................... $ 32,467 $ 37,530 $ 95,748 $ 108,611 Transportation, processing and marketing .............. 1,682 2,100 5,045 5,798 IPF income ............................................ 1,130 2,065 1,130 5,520 Gain on sales, net (Note 17) .......................... 140 39,259 1,619 40,736 Interest and other .................................... 116 141 275 579 --------- --------- --------- --------- 35,535 81,095 103,817 161,244 --------- --------- --------- --------- Expenses Direct operating ...................................... 9,999 11,041 26,041 33,126 IPF expense ........................................... 452 1,412 452 4,389 Exploration ........................................... 1,997 368 4,428 1,730 General and administrative ............................ 2,401 2,244 6,336 5,906 Interest .............................................. 10,995 12,126 29,103 36,579 Depletion, depreciation and amortization .............. 14,618 18,770 39,371 57,708 Provision for impairment (1999 amount relates to assets held for sale) ...................................... 97,862 20,988 97,862 20,988 --------- --------- --------- --------- 138,324 66,949 203,593 160,426 --------- --------- --------- --------- Income (loss) before taxes ............................... (102,789) 14,146 (99,776) 818 Income taxes Current ............................................... 57 1,424 192 1,594 Deferred .............................................. (35,939) -- (34,884) -- --------- --------- --------- --------- (35,882) 1,424 (34,692) 1,594 Income (loss) before extraordinary item ................. (66,907) 12,722 (65,084) (776) Extraordinary item Gain on retirement of securities, net (Note 18) ...... -- -- -- 2,430 --------- --------- --------- --------- Net income (loss) ........................................ $ (66,907) $ 12,722 $ (65,084) $ 1,654 ========= ========= ========= ========= Comprehensive income (loss) Note (2) ..................... $ (68,243) $ 11,559 $ (67,679) $ 1,894 ========= ========= ========= ========= Earnings (loss) per common share Basic ............................................. $ (2.57) $ 0.33 $ (2.92) $ 0.00 ========= ========= ========= ========= Dilutive .......................................... $ (2.57) $ 0.33 $ (2.92) $ 0.00 ========= ========= ========= ========= SEE ACCOMPANYING NOTES. 4 5 RANGE RESOURCES CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS) Nine Months Ended September 30, -------------------------------------- 1998 1999 ----------------- --------------- (unaudited) Cash flows from operations: Net income (loss) ........................................................ $ (65,084) $ 1,654 Adjustments to reconcile net income (loss) to net cash provided by operations: Depletion, depreciation and amortization ............................ 39,371 57,708 Provision for impairment ............................................ 97,862 20,988 Amortization of security issuance costs ............................. 868 887 Deferred taxes ...................................................... (34,884) -- Changes in working capital net of effects of purchases of businesses: Accounts receivable ........................................ 5,314 4,417 Allowance for IPF receivables .............................. -- 2,965 Marketable securities ...................................... (67) -- Inventory and other ........................................ (583) (6,219) Accounts payable ........................................... (5,747) (4,639) Accrued liabilities ........................................ 1,620 (8,680) Gain on sale of assets and other .................................... (2,874) (40,736) Gain on exchange of securities ...................................... -- (2,430) --------- --------- Net cash provided by operations .......................................... 35,796 25,915 Cash flows from investing: Acquisition of businesses, net of cash .............................. (46,277) -- Investment in Great Lakes ........................................... -- 97,095 Oil and gas properties .............................................. (128,485) (8,901) Additions to property and equipment ................................. (1,131) (432) IPF investments of capital .......................................... (3,397) (4,180) IPF repayments of capital ........................................... 596 9,124 Proceeds on sale of assets .......................................... 18,195 17,270 --------- --------- Net cash provided by (used in) investing ................................. (160,499) 109,976 Cash flows from financing: Proceeds from indebtedness .......................................... 130,608 -- Repayments of indebtedness .......................................... (406) (133,729) Preferred stock dividends ........................................... (1,751) (1,750) Common stock dividends .............................................. (2,490) (1,108) Proceeds from common stock issuance ................................. 1,415 1,054 Repurchase of common stock .......................................... (2,705) (23) --------- --------- Net cash provided by (used in) financing ................................. 124,671 (135,556) --------- --------- Change in cash ........................................................... (32) 335 Cash and equivalents at beginning of period .............................. 9,725 10,954 --------- --------- Cash and equivalents at end of period .................................... $ 9,693 $ 11,289 ========= ========= Supplemental disclosures of non-cash investing and financing activities: Purchase of property and equipment financed with common stock ......................................................... $ 111,062 -- Common stock issued in connection with benefit plans ................... 1,267 777 Common stock issued in connection with retirement of securities (Note 18) ................................................ -- 3,355 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 Independent Producer Finance subsidiary ("IPF"), 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 nine months ended September 30, 1999 Range sold $1.2 million of marketable equity securities for a $0.4 million gain. GREAT LAKES ENERGY PARTNERS, L.L.C. ("GREAT LAKES") In September 1999, Range and FirstEnergy Corp. ("FirstEnergy") each contributed all of their Appalachia oil and gas properties and associated gas gathering and transportation systems to Great Lakes. In addition, Range contributed $188.3 million of indebtedness and FirstEnergy contributed $2.0 million in cash. Great Lakes expects to increase production by active development of existing fields and exploitation of deeper formations. In addition, Great Lakes intends to pursue acquisition opportunities in Appalachia. Range and FirstEnergy each retained a 50% ownership interest in Great Lakes. The Company consolidates its pro rata interest in the joint venture's assets and liabilities based upon its ownership interest in Great Lakes. Great Lakes had proved reserves of approximately 450 Bcfe as of September 30, 1999, of which 90 percent is natural gas, 4,700 miles of gas gathering and transportation lines and a leasehold position of nearly one million gross acres. The joint venture owns interest in over 1,000 proved drilling locations within existing fields and has a reserve life of 18 years. 6 7 INDEPENDENT PRODUCER FINANCE 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 nine months of 1999, IPF recorded gross income of $8.5 million and allowances against its portfolio of receivables of $3.0 million. At September 30, 1999 IPF's allowance for uncollectible receivables totaled $16.9 million. During the first nine months of 1999, IPF expenses were comprised of $3.2 million of interest and $1.2 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 $0.87 and $0.99 in the nine months of 1998 and 1999, respectively. Approximately $75.9 million and $72.5 million of oil and gas properties were classified as unproved properties as of December 31, 1998 and September 30, 1999, respectively. The Company has adopted SFAS No. 121 "Accounting for the Impairment of Long-Lived Assets", which establishes accounting standards for the impairment of long-lived assets, certain identifiable intangibles and goodwill. SFAS No. 121 requires a review for impairment whenever circumstances indicate that the carrying amount of an asset may not be recoverable. In performing the review for recoverability at September 30, 1998, the Company recorded provision for impairment of $97.8 million which reduced the carrying value of certain oil and gas properties to what the Company estimates to have been their fair value at that time. The provision for impairment on the oil and gas properties was due to reserve revisions as a result of drilling results and declines in oil and gas prices in 1998. The impairment was determined based on the difference between the carrying amount of the assets and the present value of the future cash flows from proved properties discounted at 10%. Impairment is recognized only if the carrying amount of a property is greater than its expected undiscounted future cash flows. A change in reserve or price estimates could occur which would adversely affect management's estimate of future cash flows and consequently the carrying value of the properties. Unproved properties are assessed periodically to determine whether there has been a decline in value. If such decline is indicated, a loss is recognized. The Company compares the carrying value of its unproved properties to the present value of the future cash flows of unproved properties discounted at 10% or considers such other information the Company believes is relevant in evaluating the properties' fair value. Such other information may include the Company's geological assessment of the area or other acreage purchases in the area. The present value of future cash flows from such properties has been adjusted for the Company's assessment of risk related to the unproved properties. 7 8 TRANSPORTATION, PROCESSING AND FIELD ASSETS The Company's gas gathering systems and gas processing plant are in proximity to its principal gas properties. Depreciation is calculated on the straight-line method based on estimated useful lives ranging from four to fifteen years. At September 30, 1999, the Company decided to sell its gas processing plant and certain related assets. See Note (5) - Assets Held For Sale 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 seven 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 sheet and are being amortized on the interest method over the term of the securities. 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 September 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 nine month periods ended September 30, 1998 and 1999. Three Months Ended Nine Months Ended September 30, September 30, ------------------------------ --------------------------------- 1998 1999 1998 1999 -------------- ------------- ------------- --------------- Net income (loss).......................... $ (66,907) $ 12,722 $ (65,084) $ 1,654 Add: Unrealized gain/(loss) Gross................................ (2,138) (806) (4,087) 685 Tax effect........................... 802 - 1,533 - Less: Realized gain/(loss) Gross................................ - (357) (66) (445) Tax effect........................... - - 25 - -------------- ------------- ------------- --------------- Comprehensive income (loss)................ $ (68,243) $ 11,559 $ (67,679) $ 1,894 ============== ============= ============= =============== 8 9 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 debt securities. 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 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 the prior period presentation to conform with current period 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 with bank debt 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 $22 million and $2 million during the nine months ended September 30, 1998 and 1999, respectively. 9 10 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 Great Lakes transaction. Nine Months Ended September 30, ---------------------------------------- 1998 1999 ------------------ ------------------ (In thousands, except per share data) Revenues............................ $ 95,210 $ 154,495 Net income (loss)................... (59,777) 3,845 Earnings (loss) per share-basic..... (2.69) 0.06 Earnings (loss) per share-diluted... (2.69) 0.06 Total assets........................ 936,600 775,785 Stockholders' equity................ 234,575 137,090 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 transaction occurred at the beginning of each period presented or to necessarily be indicative of future results. (4) IPF RECEIVABLES At September 30, 1999, IPF had net receivables of $69.3 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 $11.0 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 $16.9 million at December 31, 1998 and September 30, 1999, respectively. (5) ASSETS HELD FOR SALE At September 30, 1999, assets held for sale consisted of the Company's gas processing plant and associated assets located in the Permian Basin. In connection with the 1999 plan of disposal, the Company determined that the carrying value of the gas processing plant exceeded its fair value. Accordingly, an impairment loss of $21.0 million represents the excess of the carrying value over the fair value. Fair value was determined by reference to the present value of the estimated future cash inflows of the gas processing plant. The impairment estimate on the gas processing plant recorded in the third quarter 1999 was based on estimates of future cash flows for the property. Future cash flows include revenues from residue gas, plant liquids and by-products derived from both equity and third party proved natural gas reserves, which are estimated to pass through the plant, direct operating costs and capitalized costs. The Company used estimated future gas prices by referencing ten year future strip prices in the calculation of the plant revenues estimated over the anticipated life of the property. These prices were then adjusted for the effect of the estimated throughput production, subject to existing sales contracts, and are not necessarily indicative of actual prices received by the Company at the date of the impairment charge. Operating costs and capitalized costs were estimated based on the Company's historical operating experience. These costs and expenses were adjusted for changes in variable costs attributable to changes in estimated throughput volumes. The impairment estimate was determined based on the difference between the carrying value of the plant and the present value of future cash flows discounted at 10%. It is reasonably possible that a change in 10 11 reserve or price estimates could occur in the near term and adversely impact management's estimate of future cash flows and consequently the carrying value of property. At December 31, 1998, assets held for sale primarily consisted of oil and gas properties located in south Texas and in the Gulf of Mexico. The Company entered into agreements with an independent firm to assist it in selling these assets. The assets were 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. (6) INDEBTEDNESS The Company had the following debt outstanding as of the dates shown. Interest rates at September 30, 1999 are shown parenthetically (in thousands): December 31, September 30, 1998 1999 -------- -------- Senior debt Credit Facility (7.4%) ........................... $365,175 $146,600 Other (6.3%) ..................................... 1,887 79 -------- -------- 367,062 146,679 Less amounts due within one year ................. 55,187 29 -------- -------- Senior debt, net ................................. $311,875 $146,650 ======== ======== Non-recourse debt Great Lakes (7.6%) ............................... $ -- $ 94,139 IPF (7.5%) ....................................... 60,100 52,616 -------- -------- Non-recourse debt ................................ $ 60,100 $146,755 ======== ======== Subordinated notes 8.75% Senior Subordinated Notes due 2007 ......... $125,000 $125,000 6% Convertible Subordinated Debentures due 2007 .. 55,000 51,360 -------- -------- Subordinated notes ............................... $180,000 $176,360 ======== ======== The Company maintains a $225 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 November 10, 1999, the borrowing base on the Credit Facility was $160 million of which $18.0 million was available. The borrowing base is subject to semi-annual determination 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 the revolving credit commitment may be reduced, in whole or in part at anytime in certain minimum amounts. The next redetermination occurs on April 1, 2000. If amounts outstanding at April 1, 2000 exceed the redetermined borrowing base, one-half of the excess, if any, must be repaid within 90 days and the remaining excess, if any, must be repaid within 180 days. Any borrowing base in excess of $135 million requires the approval of all lenders. 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 0.50% depending upon the percentage of the borrowing base drawn. It is the Company's policy to extend the term of the Credit Facility annually. The interest rate on the Credit Facility is LIBOR plus between 1.50% and 2.25%, depending upon amounts outstanding. The weighted average interest rates on these borrowings were 6.8% and 7.2% for the three months ended September 30, 1998 and 1999, respectively. 11 12 The Company pro rata consolidates 50% of amounts outstanding under the $275 million revolving bank facility (the "Great Lakes Facility") through its participation in Great Lakes. The Great Lakes Facility is non-recourse to Range. The Great Lakes Facility provides for a borrowing base, which is subject to semi-annual redeterminations. The Great Lakes Facility is secured by the Great Lakes oil and gas properties. At November 10, 1999, the borrowing base on the Great Lakes Facility was $195 million of which $5.7 million was available. Beginning December 1, 1999, the borrowing base reduces by $1 million per month to $190 million at April 1, 2000. The borrowing base is subject to a semi-annual borrowing review on April 1, 2000. The redetermined borrowing base on April 1, 2000 requires the approval of all lenders. Interest is payable quarterly or as LIBOR notes mature and the loan matures in September 2002. The interest rate on the Great Lakes Facility is LIBOR plus between 1.50% and 2.00%, depending upon amounts outstanding. A commitment fee is paid quarterly on the undrawn balance at a rate of 0.25% to 0.50% depending upon the percentage of the borrowing base drawn. IPF has a $150 million revolving credit facility (the "IPF Facility") through which it finances its activities. The IPF Facility is non-recourse to Range. The IPF Facility matures in July 2001 at which time all amounts owed thereunder are due and payable. The IPF Facility is secured by substantially all of IPF's assets. The borrowing base under the IPF Facility is subject to redeterminations, which occur routinely during the year. On November 10, 1999, the borrowing base on the IPF Facility was $56 million of which $3.4 million was available. 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 nine months of 1999 amounted to $3.2 million and is included in IPF expenses on the Consolidated Statements of Operations. A commitment fee is paid quarterly on the average undrawn balance at a rate of 0.375% to 0.50%. The weighted average interest rate on these borrowings was 7.5% for the nine months ended September 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 are 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 nine 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 as the Debentures were retired at a discount to their face value. The debt agreements contain various covenants relating to net worth, working capital maintenance and financial ratio requirements. The Company is in compliance with these various covenants as of September 30, 1999. Interest paid during the nine months ended September 30, 1998 and 1999 totaled $32.1 million and $36.6 million, respectively. The Company does not capitalized any interest expense. (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 receivables are concentrated in the oil and gas industry. The Company does not view such a 12 13 concentration as an unusual credit risk. The Company had allowances for doubtful accounts (excluding IPF) of $.8 million and $1.0 million at December 31, 1998 and September 30, 1999, respectively. 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: December 31, September 30, 1998 1999 ------------------------------- ------------------------------- (In thousands) Book Fair Book Fair Value Value Value Value -------------- ------------- -------------- -------------- Cash and equivalents................ $ 10,954 $ 10,954 $ 11,289 $ 11,289 Marketable securities............... 2,966 3,258 2,242 3,219 Long-term debt...................... (607,162) (607,162) (469,794) (469,794) Commodity swaps..................... - 45 - (6,908) Interest rate swaps................. - (361) - (13) At September 30, 1999, the Company had open contracts for gas and oil price derivative swaps of 36 Bcfe of gas and 800,000 Bbls of oil. The swap contracts are designed to set average NYMEX prices ranging from $1.90 to $3.17 per Mmbtu of gas and fix oil prices ranging from $17.32 to $20.71 per Bbl. While these transactions have no carrying value, the fair value of these and subsequent transactions entered into, represented by the estimated amount that would be required to terminate the contracts, was a net loss of approximately $3.4 million at November 10, 1999. These contracts expire monthly through September 2000. 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 (losses) relating to these derivatives for the nine months ended September 30, 1998 and 1999 approximated $2.8 million and $(6.6) 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 September 30, 1999, the Company had $80 million of borrowings subject to four interest rate swap agreements at rates of 5.35%, 4.82%, 5.64% and 5.59% through January 2000, September 2000, October 2000 and October 2001, 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 September 30, 1999 was 5.40%. The fair value of the interest rate swap agreements at September 30, 1999 is based upon quotes at that date 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 13 14 with certain counterparties or groups of counterparties. The credit worthiness of counterparties is subject to continuing review and full performance is anticipated. (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 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. In September 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 $.3 million. The settlement in principle is subject to court approval and certain other conditions that have not been satisfied. (9) EQUITY AND TRUST SECURITIES In October 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 nine months of 1999, $2.3 million of Convertible Preferred Securities were retired at the option of the holder in exchange for approximately 202,000 shares of Common Stock. An extraordinary gain of $1.2 million was recorded as the 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 Convertible 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 becomes fixed at 100% of the principal amount. If the Company 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 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. The Company owns all the common securities of the Trust. As such, the accounts of the Trust will be included in Range's consolidated financial statements after appropriate eliminations of intercompany balances. The distributions on the Convertible Preferred Securities will be recorded as a charge to interest expense on Range's consolidated statements of operations, and such distributions are deductible by Range for income tax purposes. 14 15 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 redeemable, at the option of the Company, at a price of $26.25 per share beginning November 1, 1998, declining $0.25 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, one stock incentive plan, 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 stock option plans is summarized as follows: Plans Adopted Via the Merger 1999 ---------------------- Incentive Option Director's Option Director's Plan Plan Plan Plan Plan Total ---------- ---------- ----------- ---------- ----------- ---------- Outstanding at December 31, 1998 - 2,042,757 140,000 938,976 19,340 3,141,073 Granted........................ 60,000 904,150 40,000 - 1,004,150 Exercised...................... - - - (374,264) - (374,264) Expired/Cancelled.............. - (426,871) (12,000) (12,833) - (451,704) ---------- ---------- ---------- ---------- ----------- --------- Outstanding at September 30, 1999 60,000 2,520,036 168,000 551,879 19,340 3,319,255 ========== ========== =========== ========== =========== ========== In May 1999, the shareholders approved the Company's 1999 Stock Incentive Plan (the "Incentive Plan") providing for the issuance of up to 1.4 million shares of common stock. The Incentive Plan is administered by the Compensation Committee of the Board. All options issued under the Incentive Plan vest 25% per year beginning one year after the grant date and expire 10 years from date of grant. During the nine months ended September 30, 1999, 60,000 options were granted, none of which were exercisable. Range maintains the 1989 stock option plan ("Option Plan") which authorized the grant of options of up to 3.0 million shares of Common Stock, however, no new options will be granted under this plan. Under the Option Plan, incentive and non-qualified options have been issued to officers, 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 and expire 5 years from date of grant. Options issued after September 1998 vest 25% per year beginning one year after the grant date and expire 10 years from date of grant. During the nine months ended September 30, 1999, no options were exercised. At September 30, 1999, 972,216 options were exercisable at prices ranging from $3.375 to $18.00 per share. In 1994, the stockholders approved the 1994 Outside Directors Stock Option Plan (the "Directors Plan"). Only Directors who are not employees of the Company are eligible under the Directors Plan. The Directors Plan covers a maximum of 200,000 shares. At September 30, 1999, 92,800 options were exercisable at prices ranging from $8.00 to $16.875 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 first nine months ended September 30, 1999 options covering 356,812 shares were exercised at $0.01 per share and 17,452 shares were exercised at $3.46 per share. At September 30, 1999, 440,174 options were currently exercisable under the Domain Option Plan at $3.46 per share. The remaining 111,705 options have an exercise price of $0.01 per share. 15 16 At September 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 1997 Plan, the right to purchase shares at prices ranging from 50% to 85% of market value may be granted. Through September 30, 1999, no rights had been granted for less than 75% of market value. The Company previously had stock purchase plans which covered 833,333 shares. The previous stock purchase plans have been terminated. The 1997 Plan is administered by the Compensation Committee of the Board. From inception through September 30, 1999, a total of 499,897 registered shares had been sold through stock purchase plans, for a total consideration of approximately $2.9 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 nine month periods ended September 30, 1998 and 1999 were $(34.7) million and $1.6 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 $29 million at September 30, 1999. Upon future realization of the deferred tax asset, $29 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 $.9 million. The statutory depletion carryover and alternative minimum tax credit carryover are not subject to limitation or expiration. 16 17 (13) 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): Three months ended Nine months ended September 30, September 30, ----------------------------- ----------------------------- 1998 1999 1998 1999 --------------- --------------- --------------- --------------- Numerator: Net Income ................................. $ (66,907) $ 12,722 $ (65,084) $ 1,654 Preferred stock dividends................... (584) (584) (1,751) (1,751) -------------- -------------- -------------- -------------- Numerator for earnings per common share..... (67,491) 12,138 (66,835) (97) Effect of dilutive securities: Preferred stock dividends................. - - - - -------------- -------------- -------------- -------------- Numerator for earnings per common Share - assuming dilution................. $ (67,491) $ 12,138 $ (66,835) $ (97) ============== ============== ============== ============== Denominator: Denominator for basic earnings per common Share - weighted average shares........... 26,243 37,477 22,857 36,745 Effect of dilutive securities: Employee stock options.................... 385 - 469 - Warrants.................................. - - - - -------------- -------------- -------------- -------------- 385 - 469 - -------------- -------------- -------------- -------------- Dilutive potential common shares Denominator for diluted earnings per share Adjusted weighted-average shares and Assumed conversions....................... 26,628 37,477 23,326 36,745 ============== ============== ============== ============== Earnings (loss) per common share................ $ (2.57) $ 0.33 $ (2.92) $ 0.00 ============== ============== ============== ============== Earnings (loss) per common Share - assuming dilution................. $ (2.57) $ 0.33 $ (2.92) $ 0.00 ============== ============== ============== ============== 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 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 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 effect would be antidilutive. There were employee stock options outstanding during the first nine months of 1998 and 1999 which were exercisable, resulting in 1,051,370 and 1,683,936 additional shares, respectively, under the treasury method of accounting for common stock equivalents. These additional shares were not included in the first nine months 1999 computations of diluted earnings per share because the effect was antidilutive. 17 18 (14) 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 89% of gas production is currently sold under market sensitive contracts, which do not contain floor price provisions. For the nine months ended September 30, 1999, no one customer accounted for 10% or more of total oil and gas revenues. Management believes that the loss of any one customer would not have a material adverse effect on operations. 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. (15) OIL AND GAS ACTIVITIES The following summarizes selected information with respect to oil and gas activities (in thousands): December 31, September 30, 1998 1999 ----------------- ---------------- (unaudited) Oil and gas properties: Proved properties.................................. $ 859,911 $ 854,090 Unproved properties................................ 75,911 72,454 ----------------- ---------------- Total.......................................... 935,822 926,544 Accumulated depletion and impairment............... (273,723) (322,684) ----------------- ---------------- Net oil and gas properties..................... $ 662,099 $ 603,860 ================= ================ Nine Months Year Ended Ended December 31, September 30, 1998 1999 ----------------- ---------------- (unaudited) Costs incurred: Acquisition........................................ $ 286,974 $ 2,084 Development........................................ 71,793 20,074 Exploration........................................ 9,756 2,438 ----------------- ---------------- Total costs incurred........................... $ 368,523 $ 24,596 ================= ================ 18 19 (16) INVESTMENT IN GREAT LAKES As described in Note 2, the Company has a 50% ownership interest in Great Lakes. At September 30, 1999, the Company pro rata consolidated its interest in the joint venture's assets and liabilities based upon its ownership interest in Great Lakes. No operations for Great Lakes are reflected in the Company's Statements of Operations due to the fact that the joint venture was completed on September 30, 1999. The following table summarizes the financial information for 100% of Great Lakes (in thousands). September 30, 1999 ----------------- (unaudited) Current assets............................................ $ 2,708 Oil and gas properties, net............................... 288,941 Transportation, processing and field assets, net.......... 39,710 Other assets.............................................. 2,166 Current liabilities....................................... 5,003 Long-term debt............................................ 188,277 Net equity................................................ 140,245 (17) GAIN ON SALE In September 1999, Range transferred all of its Appalachian oil and gas properties and associated gas gathering and transportation systems to Great Lakes in exchange for a non-controlling ownership interest. Additionally, the Company contributed $188.3 million of indebtedness to Great Lakes. The Great Lakes partners have no commitment to support the operations or related obligations of Great Lakes. In connection with the transfer, Range recognized a gain of $41.0 million, which was attributable to the portion of the net assets conveyed to Great Lakes. The gain was calculated by comparing the Company's estimate of the fair market value of the assets and liabilities conveyed to their net book value. The estimated fair market value of oil and gas properties was based upon future net cash flows from the assets discounted 10% at September 30, 1999. The present value of future cash flows from such properties has been adjusted for the Company's assessment of risk related to the properties. For purposes of determining the fair market value of oil and gas properties, risk factors ranging from 20% to 60% were used depending on the nature of the reserve category. The Company assumed NYMEX prices of $19.00 per barrel of oil and $2.65 per mcf of gas for purposes of calculating future net cash flows. Prices were escalated 2.5% annually, with oil capped at the price of $30.00 per barrel and gas capped at the price of $5.00 per mcf. These prices were then adjusted for the effect of the Company's production subject to existing sales contracts, and are not necessarily indicative of actual prices received by the Company at the dates of the impairment charges. Severance taxes, direct operating costs and capitalized costs were estimated based on the Company's historical operating experience. These costs and expenses were escalated at 2.5% per year. These prices and costs were applied to production profiles developed by the Company's engineers using estimates of proved reserves and unproved reserves. The estimated fair market value of other assets contributed to Great Lakes was determined by an internally generated cash flow model which was developed to determine the future revenues and costs associated with these activities, discounted 10% annually. These discounted cash flows were risked individually at rates ranging between 30% and 60%. During the nine months ended September 30, 1999, the Company sold various non-strategic properties. A net loss in the amount of $1.8 million was recognized on the sale of these properties due to their net book value being greater than proceeds received upon their sale. 19 20 (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. 20 21 MANAGEMENT'S DISCUSSION AND ANALYSIS ------------------------------------ OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ------------------------------------------------ FACTORS AFFECTING FINANCIAL CONDITION AND LIQUIDITY LIQUIDITY AND CAPITAL RESOURCES General During the nine months ended September 30, 1999, the Company spent approximately $24.6 million on acquisition, development and exploration activities. At September 30, 1999, the Company had $14.5 million in cash and marketable securities and total assets of $776 million. At that date working capital was $29.6 million. During the first nine months of 1999, total debt decreased $137.4 million. At September 30, 1999, debt to total book capitalization was 65%. Long-term debt at September 30, 1999 included $147 million of borrowings under the Credit Facility, $94 million under the non-recourse Great Lakes Facility, $53 million under the non-recourse IPF Facility, $125 million of 8.75% Senior Subordinated Notes and $51 million of 6% Convertible Subordinated Debentures. The Company's exposure to its recourse Credit Facility was reduced 60% from $365 million at December 31, 1998 to $147 million at September 30, 1999. Including the debt exchanges noted below, total debt fell from $607.2 million at December 31, 1998 to $469.8 million at September 30, 1999. 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 as the Convertible Preferred securities and Debentures were retired at a discount to their face value. The Company believes that its capital resources are adequate to meet the requirements of its business. However, future cash flows are subject to a number of variables including the level of production and oil and gas prices, and there can be no assurance that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures. In September 1999, the Company elected to pursue the sale of its gas processing plant and associated assets located in the Permian Basin. At September 30, 1999, the Company classified these assets as held for sale. In that connection, the Company determined that the carrying value of the plant exceeded its fair value. Accordingly, an impairment loss of $21.0 million was recorded which represented the excess of the carrying value over the estimated fair value. Fair value of the gas processing plant was estimated by reference to the present value of the estimated future cash inflows of the gas processing plant. The impairment estimate on the gas processing plant recorded in the third quarter 1999 was based on estimates of future cash flows for the property. Future cash flows include revenues from residue gas, plant liquids and by-products derived from both equity and third party proved natural gas reserves, which are estimated to pass through the plant, direct operating costs and capitalized costs. The Company used an estimated future gas prices by referencing ten year future strip prices in the calculation of the plant revenues estimated over the anticipated life of the property. These prices were then adjusted for the effect of the estimated throughput production, subject to existing sales contracts, and are not necessarily indicative of actual prices received by the Company at the date of the impairment charge. 21 22 Cash Flow The Company's principal operating sources of cash include sales of oil and gas, revenues from transportation, processing and marketing and IPF revenues. The Company's cash flow is highly dependent upon oil and gas prices. Decreases in the market price of oil and gas in late 1998 reduced cash flow and resulted in the reduction of the borrowing base under the Credit Facility. As a result, the Company reduced its development and exploration budget to $38 million in 1999. For the first nine months of 1999, the Company spent approximately $22.5 million on these activities. The 1999 expenditures have been funded primarily by internally generated cash flow. The Company's net cash provided by operations for the nine months ended September 30, 1998 and 1999 was $35.8 million and $25.9 million, respectively. The decrease in the Company's cash flow from operations is attributed primarily to decreases in oil and gas prices and increased interest on amounts outstanding under the Credit Facility. The Company's net cash provided by (used in) investing for the nine months ended September 30, 1998 and 1999 was $(160.5) million and $110.0 million, respectively. Investing activities for these periods are comprised primarily of additions to oil and gas properties through the Company's investment in Great Lakes, acquisitions and development, proceeds on sale of assets, IPF investments and, to a lesser extent, exploration and additions of field assets. Cash flows from investing in 1999 also included the Company's investment in Great Lakes. These uses of cash have historically been partially offset by cash inflows associated with asset sales and IPF return of capital. The Company's acquisition, drilling and IPF 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 (used in) financing for the nine months ended September 30, 1998 and 1999 was $124.7 million and $(135.6) million, respectively. Sources of financing used by the Company during the most recent nine month period were borrowings under its Credit Facilities. The Company decreased its debt borrowings by $133.7 million during the period primarily due to the conveyance of debt to Great Lakes. Capital Requirements During the nine months ended September 30, 1999, $22.5 million and 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 activities are highly discretionary and in 1999 have been reduced to levels below internally generated cash flow. The remaining cash flow has been available for debt repayment. The Company does not expect any additional material capital expenditures outside its normal operations over the next 12 month period. Bank Facilities The Company maintains a $225 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 November 10, 1999, the borrowing base on the Credit Facility was $160 million of which $18.0 million was available to be drawn. The borrowing base is subject to semi-annual determination 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 the revolving credit commitment may be reduced, in whole or in part at anytime in certain minimum amounts. The next redetermination occurs on April 1, 2000. If amounts outstanding at April 1, 2000 exceed the redetermined borrowing base, one-half of the excess, if any, must be repaid within 90 days and the remaining excess, if any, must be repaid within 180 days. Any borrowing base in excess of $135 million requires the approval of all lenders. 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 0.50% depending upon the percentage of the borrowing base drawn. It is the Company's policy to extend the term period of the Credit 22 23 Facility annually. The interest rate on the Credit Facility is LIBOR plus between 1.50% and 2.25%, depending upon amounts outstanding. The weighted average interest rates on these borrowings were 6.8% and 7.2% for the three months ended September 30, 1998 and 1999, respectively. The Company pro rata consolidates 50% of amounts outstanding under the $275 million revolving bank facility (the "Great Lakes Facility") through its participation in Great Lakes. The Great Lakes Facility is non-recourse to Range. The Great Lakes Facility provides for a borrowing base, which is subject to semi-annual redeterminations. The Great Lakes Facility is secured by the Great Lakes oil and gas properties. At November 10, 1999, the borrowing base on the Great Lakes Facility was $195 million of which $5.7 million was available to be drawn. Beginning December 1, 1999, the borrowing base reduces $1 million per month to $190 million at April 1, 2000. The borrowing base is subject to a semi-annual borrowing review on April 1, 2000. The redetermined borrowing base on April 1, 2000 requires the approval of all lenders. Interest is payable quarterly or as LIBOR notes mature and the loan matures in September 2002. The interest rate on the Great Lakes Facility is LIBOR plus between 1.50% and 2.00%, depending upon amounts outstanding. A commitment fee is paid quarterly on the undrawn balance at a rate of 0.25% to 0.50% depending upon the percentage of the borrowing base drawn. IPF has a $150 million revolving credit facility (the "IPF Facility") through which it finances its activities. The IPF Facility is non-recourse to Range. The IPF Facility matures in July 2001 at which time all amounts owed thereunder are due and payable. The IPF Facility is secured by substantially all of IPF's assets. The borrowing base under the IPF Facility is subject to redeterminations, which occur routinely during the year. On November 10, 1999, the borrowing base on the IPF Facility was $56 million of which $3.4 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 nine months of 1999 amounted to $3.2 million and is included in IPF expenses on the Consolidated Statements of Operations. A commitment fee is paid quarterly on the average undrawn balance at a rate of 0.375% to 0.50%. The weighted average interest rate on these borrowings was 7.5% for the nine months ended September 30, 1999. 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 September 30, 1999, the Company had open hedges for natural gas of 36 Bcf and oil swaps of 800,000 barrels. While these transactions have no carrying value, the fair value of these and subsequent transactions entered into, represented by the estimated amount that would be required to terminate the contracts, was a net loss of approximately $3.4 million at November 10, 1999. The gas contracts are at prices ranging from $1.90 to $3.17 per Mmbtu and the oil contracts range from $17.32 to $22.95 per Bbl. The gains or losses on the Company's hedging transactions are 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 nine months ended September 30, 1998 and 1999, approximated $2.8 million and $(6.6) million respectively. Interest Rate Risk At September 30, 1999, Range had debt outstanding of $469.8 million. Of this amount, $176.4 million, or 38% bears interest at fixed rates averaging 7.9%. The remaining $293.4 million of debt outstanding at September 30, 1999 bears interest at floating rates which averaged 7.6%. The terms of the credit facilities in place allow interest rates to be fixed at Range's option for periods of between 30 and 180 days. At September 30, 1999, the Company had $80 million of borrowings subject to four interest rate swap agreements at rates of 5.35%, 4.82%, 5.64% and 5.59% through January 2000, September 2000, October 2000 and October 2001, 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 require the counterparty to pay the Company interest at the 30-day LIBOR rate. The closing 30-day LIBOR rate on September 30, 1999 was 5.40%. A 10% increase in short-term interest rates on the floating-rate debt outstanding at the end of 1998 would equal 23 24 approximately 76 basis points. Such an increase in interest rates would increase Range's nine month 1999 interest expense by approximately $1.7 million, assuming borrowed amounts remain outstanding. 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. 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 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 nine months of 1999, the Company received an average of $13.97 per barrel of oil, an increase of 13% from the comparable 1998 period, and $2.01 per Mcf of gas, a decrease of 17% from the comparable 1998 period. 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 nine months of 1999. RESULTS OF OPERATIONS Comparison of 1999 to 1998 The Company reported net income for the three months ended September 30, 1999 of $12.7 million compared to net loss of $66.9 million in the third quarter of 1998. Production volumes increased 7% from 165,760 Mcfe/d in 1998 to 177,816 Mcfe/d in 1999. The average price received on an equivalent unit basis increased 8% from $2.13 per Mcfe in 1998 to $2.29 per Mcfe in 1999. The average oil price increased 38% to $16.21 per barrel while average gas prices decreased 2% to $2.18 per Mcf. As a result of the Company's larger base of producing properties and production, oil and gas production expenses increased 10% to $11.0 million in 1999 versus $10.0 million in 1998. The average operating cost per Mcfe of production increased 2% from $0.66 in the third quarter of 1998 to $0.67 in 1999 due to higher production taxes. Transportation, processing and marketing net revenues increased 25% to $2.1 million versus $1.7 million in 1998. IPF net income consists of the interest portion of the term overriding royalty interest and is net an allowance for possible uncollectable accounts. During the third quarter of 1999, IPF expense included $1.0 million of interest and $0.4 million of administrative expense. General and administrative expenses decreased 7% from $2.4 million in 1998 to $2.2 million in 1999. General and administrative cost per Mcfe produced decreased 13% from $0.16 in 1998 to $0.14 in 1999. Exploration expense decreased from $2.0 million to $.4 million due to the farming out of projects in exchange for carried interests and decreased expenditures resulting from a reduced capital expenditure budget. Gain on sale relates to the net excess of proceeds received on the sale of properties over their book value. The increase in gain on sale of $39.1 million over that in the third quarter 1998 primarily due to the $41 million proportional gain recognized on the Great Lakes transaction (See Note (17) - Gain on Sale). Interest and other income remained relatively constant compared to the same 1998 period. Interest and other income is primarily comprised of interest on bank deposits. In 1999 interest expense increased 10% to $12.1 million as compared to $11.0 million in 1998. The increase was primarily 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 borrowing. The average outstanding balances on the Credit Facility were $240 million and $363 million and the nine months ended September 30, 1998 and 1999, respectively. The weighted average interest rate on these borrowings was 6.7% and 7.0% for the nine month periods ended September 30, 1998 and 1999, respectively. 24 25 Depletion, depreciation and amortization increased 28% compared to 1998 as a result of increased production volumes. The Company's depletion rate was $0.84 per Mcfe in the third quarter of 1998 versus $1.02 per Mcfe in the third quarter of 1999. In the third quarter of 1999, the Company recognized a $21 million impairment on a gas processing plant and related assets located in the Permian Basin. The Company has decided to sell the plant and related assets and the net book value of these assets is classified as a current asset at September 30, 1999 on the Consolidated Balances Sheets (See Note (5) Assets Held For Sale). 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 / production / land system was upgraded and tested to be Year 2000 compliant. The Company's personal computer systems are also Year 2000 compliant. 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 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 September 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 has conducted 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. Business contingency plans for mission critical systems have been developed to deal with misrepresentations by equipment manufacturers and the inability of purchasers or partners to conduct normal operations. The total costs for the Year 2000 Project is not expected to be in excess of $180,000. Of this amount, approximately $150,000 had been incurred as of September 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 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. 25 26 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. 26 27 Productive well. A well that is producing oil or gas or that is capable of production. 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. 27 28 PART II. OTHER INFORMATION Item 1. Legal Proceedings The Company is involved in various legal actions and claims arising in the ordinary course of business. In the opinion of management, such litigation and claims are likely to be resolved without material adverse effect on the Company's financial position. 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 $.3 million. The settlement in principle is subject to court approval and certain other conditions that have not been satisfied. Items 2 - 5. Not applicable Item 6. Exhibits and Report on Form 8-K (a) Exhibits 10.1 $225,000,000 Amended and Restated Credit Agreement among Range Resources Corporation, as Borrower, The Lenders from Time to Time Parties Hereto, as Lenders, Bank One, Texas, N.A., as Administrative Agent, Chase Bank of Texas, N.A., as Syndication Agent, and Bank of America, N.A., as Documentation Agent dated September 30, 1999. 10.2 Credit Agreement Among Great Lakes Energy Partners, L.L.C., as Borrower and Bank One, Texas, N.A., as Administrative Agent, Chase Bank of Texas, N.A., as Syndication Agent, Bankers Trust Company, as Documentation Agent, The Bank of Nova Scotia and Credit Lyonnais New York Branch, as Managing Agents Banc One Capital Markets, Inc., as Co-Lead Arranger and Chase Securities Inc., as Co-Lead Arranger, as dated September 30, 1999. 27 Financial data schedule (b) Reports on Form 8-K Current Report on Form 8-K, dated October 15, 1999 regarding the Great Lakes transaction. 28 29 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. RANGE RESOURCES CORPORATION By: (Thomas W. Stoelk) --------------------------- Thomas W. Stoelk Senior Vice President Finance & Administration Chief Financial Officer November 15, 1999 29 30 EXHIBIT INDEX Exhibit Number Description of Exhibit - ----------------------- ---------------------------------------------------- 10.1 $225,000,000 Amended and Restated Credit Agreement among Range Resources Corporation, as Borrower, The Lenders from Time to Time Parties Hereto, as Lenders, Bank One, Texas, N.A., as Administrative Agent, Chase Bank of Texas, N.A., as Syndication Agent, and Bank of America, N.A., as Documentation Agent dated September 30, 1999. 10.2 Credit Agreement Among Great Lakes Energy Partners, L.L.C., as Borrower and Bank One, Texas, N.A., as Administrative Agent, Chase Bank of Texas, N.A., as Syndication Agent, Bankers Trust Company, as Documentation Agent, The Bank of Nova Scotia and Credit Lyonnais New York Branch, as Managing Agents Banc One Capital Markets, Inc., as Co-Lead Arranger and Chase Securities Inc., as Co-Lead Arranger, as dated September 30, 1999. 27 Financial data schedule 30