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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 March 31, 2001 |
|
| { } |
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 (State of incorporation) |
34-1312571 (I.R.S. Employer Identification No.) |
|
| 777 Main Street, Ft. Worth, Texas (Address of principal executive offices) |
76102 (Zip Code) |
Registrant’s telephone number: (817) 870-2601
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ___
50,795,844 Common Shares were outstanding on May 7, 2001.
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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
The consolidated financial statements included herein have been prepared in conformity with generally accepted accounting principles and should be read in conjunction with the Company’s 2000 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.
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RANGE RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands except share data)
| December 31, | March 31, | |||||||||
| 2000 | 2001 | |||||||||
| (Unaudited) | ||||||||||
| Assets | ||||||||||
| Current assets | ||||||||||
| Cash and equivalents | $ | 2,485 | $ | 1,524 | ||||||
| Accounts receivable, net | 33,221 | 33,129 | ||||||||
| IPF receivables (Note 4) | 20,800 | 13,000 | ||||||||
| Inventory and other | 5,580 | 3,977 | ||||||||
| 62,086 | 51,630 | |||||||||
| IPF receivables, net (Note 4) | 28,128 | 29,754 | ||||||||
| Oil and gas properties, successful efforts method (Note 15) | 1,014,939 | 1,029,022 | ||||||||
| Accumulated depletion | (443,097 | ) | (460,342 | ) | ||||||
| 571,842 | 568,680 | |||||||||
| Transportation and field assets (Note 2) | 33,593 | 34,055 | ||||||||
| Accumulated depreciation | (12,339 | ) | (13,035 | ) | ||||||
| 21,254 | 21,020 | |||||||||
| Other (Note 2) | 5,855 | 5,392 | ||||||||
| $ | 689,165 | $ | 676,476 | |||||||
| Liabilities and Stockholders’ Equity | ||||||||||
| Current liabilities | ||||||||||
| Accounts payable | $ | 26,730 | $ | 21,939 | ||||||
| Accrued liabilities | 11,341 | 16,270 | ||||||||
| Unrealized hedging liability (Note 2) | — | 30,144 | ||||||||
| Accrued interest | 7,774 | 4,378 | ||||||||
| Current portion of long-term debt (Note 6) | 14 | 14 | ||||||||
| 45,859 | 72,745 | |||||||||
| Senior debt (Note 6) | 89,900 | 76,800 | ||||||||
| Non-recourse debt (Note 6) | 113,009 | 98,006 | ||||||||
| Subordinated notes (Note 6) | 162,550 | 160,940 | ||||||||
| Commitments and contingencies (Note 8) | — | — | ||||||||
| Trust Preferred (Note 6) | 92,640 | 92,640 | ||||||||
| Stockholders’ equity (Notes 9 and 10) | ||||||||||
| Preferred stock, $1 par, 10,000,000 shares authorized, $2.03 convertible preferred, 219,935 and 8,235 issued and outstanding (liquidation preference $5,498 and $206) | 220 | 8 | ||||||||
| Common stock, $.01 par, 100,000,000 shares authorized, 49,187,682 and 50,519,116 issued and outstanding | 492 | 505 | ||||||||
| Capital in excess of par value | 363,625 | 366,573 | ||||||||
| Retained earnings (deficit) | (178,223 | ) | (159,714 | ) | ||||||
| Other comprehensive income (loss) (Note 2) | (907 | ) | (32,027 | ) | ||||||
| 185,207 | 175,345 | |||||||||
| $ | 689,165 | $ | 676,476 | |||||||
See accompanying notes.
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RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited, in thousands except per share data)
| Three Months Ended March 31, | |||||||||
| 2000 | 2001 | ||||||||
| Revenues | |||||||||
| Oil and gas sales | $ | 38,969 | $ | 58,092 | |||||
| Transportation and processing, net | 1,994 | 981 | |||||||
| IPF income | 1,926 | 3,647 | |||||||
| Interest and other | (50 | ) | 1,482 | ||||||
| 42,839 | 64,202 | ||||||||
| Expenses | |||||||||
| Direct operating | 9,248 | 12,603 | |||||||
| IPF | 1,257 | 1,210 | |||||||
| Exploration | 878 | 1,083 | |||||||
| General and administrative | 2,265 | 3,470 | |||||||
| Interest | 10,337 | 9,117 | |||||||
| Depletion, depreciation and amortization | 18,106 | 18,639 | |||||||
| 42,091 | 46,122 | ||||||||
| Pretax income | 748 | 18,080 | |||||||
| Income taxes | |||||||||
| Current | — | — | |||||||
| Deferred | — | — | |||||||
| — | — | ||||||||
| Income before extraordinary item | 748 | 18,080 | |||||||
| Extraordinary item | |||||||||
| Gain on retirement of securities, net (Note 17) | 3,533 | 432 | |||||||
| Net income | $ | 4,281 | $ | 18,512 | |||||
| Comprehensive income (Note 2) | $ | 4,287 | $ | 58,575 | |||||
| Earnings per share (Note 13) | |||||||||
| Before extraordinary item, basic and diluted | $ | 0.03 | $ | 0.37 | |||||
| After extraordinary item, basic and diluted | $ | 0.12 | $ | 0.38 | |||||
See accompanying notes.
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RANGE RESOURCES CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited, in thousands)
| Three Months Ended March 31, | ||||||||||||
| 2000 | 2001 | |||||||||||
| Cash flows from operations | ||||||||||||
| Net income | $ | 4,281 | $ | 18,512 | ||||||||
| Adjustments to reconcile to net cash provided by operations: | ||||||||||||
| Depletion, depreciation and amortization | 18,106 | 18,639 | ||||||||||
| Writedown of marketable securities | — | 1,310 | ||||||||||
| Unrealized hedging gains | — | (2,266 | ) | |||||||||
| Adjustment to IPF receivables | — | (1,097 | ) | |||||||||
| Amortization of deferred offering costs | 425 | 874 | ||||||||||
| Gain on retirement of securities | (3,533 | ) | (435 | ) | ||||||||
| (Gain) loss on sale of assets | 307 | (298 | ) | |||||||||
| Changes in working capital: | ||||||||||||
| Accounts receivable | 357 | 92 | ||||||||||
| Inventory and other | (1,505 | ) | 875 | |||||||||
| Accounts payable | (9,711 | ) | 962 | |||||||||
| Accrued liabilities | (5,993 | ) | (3,874 | ) | ||||||||
| Net cash provided by operations | 2,734 | 33,294 | ||||||||||
| Cash flows from investing | ||||||||||||
| Oil and gas properties | (6,132 | ) | (14,095 | ) | ||||||||
| IPF repayments | 3,645 | 7,271 | ||||||||||
| Proceeds from asset sales | 1,094 | 304 | ||||||||||
| Net cash used in investing | (1,393 | ) | (6,520 | ) | ||||||||
| Cash flows from financing | ||||||||||||
| Repayment of indebtedness | (9,901 | ) | (28,103 | ) | ||||||||
| Preferred dividends | (520 | ) | (4 | ) | ||||||||
| Issuance of common stock | 267 | 372 | ||||||||||
| Repurchase of common stock | (2 | ) | — | |||||||||
| Net cash used in financing | (10,156 | ) | (27,735 | ) | ||||||||
| Change in cash | (8,815 | ) | (961 | ) | ||||||||
| Cash and equivalents, beginning of period | 12,937 | 2,485 | ||||||||||
| Cash and equivalents, end of period | $ | 4,122 | $ | 1,524 | ||||||||
See accompanying notes.
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RANGE RESOURCES CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND NATURE OF BUSINESS
Range Resources Corporation (“Range”) is an independent oil and gas company engaged in development, acquisition and exploration primarily in the Southwest, Gulf Coast and Appalachian regions of the United States. In addition, the Company provides financing to smaller oil and gas producers through a wholly-owned subsidiary, Independent Producer Finance (“IPF”), by purchasing overriding royalty interests. Historically, the Company has sought to increase its reserves and production primarily through development drilling and acquisitions. In September 1999, Range and FirstEnergy Corp. (“FirstEnergy”) contributed their Appalachian oil and gas properties to Great Lakes Energy Partners L.L.C. (“Great Lakes”). To equalize their interests, Great Lakes assumed $188.3 million of indebtedness from Range and FirstEnergy contributed $2.0 million of cash.
A series of significant acquisitions financed principally with debt and convertible fixed income securities were completed in 1997 and 1998. Due to the poor performance of the acquired properties, the Company was forced to take a number of steps. These included a sharp reduction in staff, a significant decrease in capital expenditures, the sale of assets, the formation of Great Lakes and initiation of an effort to exchange common stock for fixed income securities. Since 1998, these initiatives have reduced parent company bank debt by 79% to $76.8 million. Total debt (including Trust Preferred) has been reduced 41% to $428.4 million. While these steps have stabilized the Company’s financial position, total debt remains too high. To return to its historical posture of consistent profitability and growth, the Company believes it must further reduce debt. The Company expects to retire debt with excess cash flow and to continue to exchange stock or equity-linked securities for fixed income securities. Existing stockholders could be substantially diluted if a material portion of the fixed income securities are exchanged. The extent of dilution will depend on a number of factors, including the number of shares issued, the price at which stock is issued or newly issued securities are convertible into common stock and the price at which fixed income securities are reacquired. While such exchanges reduce existing stockholders’ proportionate ownership, management believes they enhance the Company’s financial flexibility and should increase the market value of its stock.
While the Company currently believes it has sufficient liquidity and cash flow to meet its obligations, a material drop in oil and gas prices or a reduction in production and reserves would reduce its ability to fund capital expenditures, reduce debt and meet its financial obligations.
The Company operates in an environment with numerous financial and operating risks, including, but not limited to, the ability to acquire reserves, the inherent risks of the search for, development and production of oil and gas, the ability to sell production at prices which provide an attractive return and the highly competitive nature of the industry. The Company’s ability to expand its reserve base is dependent on obtaining capital through internal cash flow, borrowings or the issuance of debt or equity securities.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation
The accompanying consolidated financial statements include the accounts of the Company, all majority-owned subsidiaries and a pro rata share of the assets, liabilities, income and expenses of Great Lakes. Liquid investments with maturities of ninety days or less are considered cash equivalents.
Certain reclassifications have been made to the presentation of prior periods to conform with current classifications.
Revenue Recognition
The Company recognizes revenues from the sale of products and services in the period they are delivered. IPF revenues are recognized in the period received. Although its receivables are concentrated in the oil and gas industry, the Company does not view this concentration as an unusual credit risk. In addition to IPF’s valuation allowances, the Company had allowances for doubtful accounts of $1.7 million at December 31, 2000 and at March 31, 2001.
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Marketable Securities
The Company has adopted Statement of Financial Accounting Standards (“SFAS”) No. 115, “Accounting for Certain Investments in Debt and Equity Securities,” pursuant to which debt and marketable equity securities are classified in three categories. The Company’s equity securities qualify as available-for-sale. Such securities are recorded at fair value and unrealized gains and losses are reflected in Stockholders’ Equity as a component of comprehensive income. A decline in the market value of a security below cost that is deemed other than temporary is charged to earnings and reflected in the book value of the security. Realized gains and losses are determined on the specific identification method and reflected in income. At March 31, 2001, the Company determined that the decline in market value of its investment in equity securities was other than temporary. A loss of $1.3 million was recorded in the Statements of Income as a reduction to Interest and other revenues.
Great Lakes
The Company contributed its Appalachian assets to Great Lakes in 1999, retaining a 50% interest in the venture. Great Lakes’ proved reserves, 85% of which are natural gas, approximated 481 Bcfe at December 31, 2000. In addition, Great Lakes owns 4,700 miles of gas gathering and transportation lines and a leasehold position of approximately 1.1 million gross (992,000 net) acres. To date, Great Lakes has identified over 1,600 proved drilling locations within existing fields. At year-end, it had a reserve life index of 20 years.
Independent Producer Finance
IPF acquires dollar denominated overriding royalties in oil and gas properties from smaller producers. These royalties are accounted for as receivables because the investment is recovered from an agreed-upon share of revenues until a specified rate of return is received. The portion of payments received relating to the return is recognized as income; remaining receipts reduce receivables and are reported as a return of capital on the statement of cash flows. Receivables classified as current represent returns of capital expected to be received within twelve months. Periodically, IPF’s receivables are reviewed and provisions for amounts believed uncollectible are established. At March 31, 2001, the valuation allowance totaled $15.2 million. On certain of IPF’s receivables, income has historically been recorded at rates below those specified in the contract based on an assessment of the recoverability of the specified return. Due to favorable oil and gas prices over the past 12 to 18 months, it now appears likely that at least some of these receivables will generate their full contract return. At March 31, 2001, the book value of the affected receivables was increased to reflect the full amount due and an approximately $1.1 million increase was recorded as additional income in the first quarter. During the quarter, IPF expenses were comprised of $519,000 of general and administrative costs and $691,000 of interest. During the prior year period, IPF expenses were comprised of $287,000 of general and administrative costs and $970,000 of interest. IPF recorded a valuation allowance of $603,000 and $-0- against its revenues during the quarters ended March 31, 2000 and 2001, respectively.
Oil and Gas Properties
The Company follows the successful efforts method of accounting for its oil and gas properties. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory drilling costs which result in discoveries and development costs are capitalized. 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 six Mcf per barrel. Depletion rates were $1.15 and $1.37 per Mcfe in the first quarters of 2000 and 2001, respectively. Unproved properties had a net book value of $49.5 million and $40.6 million at December 31, 2000 and March 31, 2001, respectively.
Transportation and Field Assets
The Company’s gas gathering systems are located in proximity to certain of its principal fields. Depreciation on these systems is provided on the straight-line method based on estimated useful lives of four to fifteen years. The Company sold its only remaining gas processing facility in June 2000. See Note 5.
The Company receives fees for providing certain field services which are recognized as earned. Depreciation on the associated assets is calculated on the straight-line method based on estimated useful lives ranging from one to five years. Buildings are depreciated over seven to twenty-five years.
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Security Issuance Costs
Expenses associated with the issuance of debt and trust preferred are capitalized and included in Other Assets on the balance sheet. These costs are amortized on the effective interest method over the expected life of the related securities. When a security is reacquired, related unamortized issuance costs are expensed.
Gas Imbalances
The Company uses the sales method to account for gas imbalances, recognizing revenue based on cash received rather than the proportionate share of gas produced. At March 31, 2001, a gas imbalance liability of $318,000 was included in Accrued liabilities on the Balance Sheet.
Comprehensive Income
The Company has adopted SFAS No. 130, “Reporting Comprehensive Income,” requiring the disclosure of comprehensive income and its components. Comprehensive income is defined as changes in stockholders’ equity from nonowner sources including net income, unrealized hedging losses and changes in the fair value of marketable securities. The following is a calculation of comprehensive income (in thousands):
| Three Months Ended March 31, | ||||||||||
| 2000 | 2001 | |||||||||
| Net income | $ | 4,281 | $ | 18,512 | ||||||
| Add: Change in unrealized gain | ||||||||||
| Gross | 3 | 40,063 | ||||||||
| Tax effect | — | — | ||||||||
| Less: Realized gain | ||||||||||
| Gross | 3 | — | ||||||||
| Tax effect | — | — | ||||||||
| Comprehensive income | $ | 4,287 | $ | 58,575 | ||||||
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, disclosure of contingent assets and liabilities and the reported amounts of revenues and expenses. Actual results could differ from those estimates.
Recent Accounting Pronouncements
In 1998, SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” was issued. As modified by SFAS No. 137 and SFAS No. 138, SFAS No. 133 establishes accounting standards requiring that derivative instruments be recorded on the balance sheet as either an asset or liability measured at fair value. Changes in their fair value must be recognized currently in earnings unless specific criteria are met. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the income statement, to the extent effective, and requires that companies document and assess the effectiveness of transactions that receive hedge accounting. SFAS No. 133 is effective for fiscal years beginning after June 15, 2000. It cannot be applied retroactively.
The Company adopted SFAS No. 133 on January 1, 2001, recording $72.1 million of Unrealized hedging losses on the Balance Sheet with an offsetting amount in Other comprehensive income. SFAS No. 133, in part, allows special hedge accounting for fair value and cash flow hedges. The gain or loss on a derivative instrument designated and qualifying as a fair value hedging instrument as well as the offsetting loss or gain on the hedged item attributable to the hedged risk must be recognized currently in earnings in the same accounting period. The effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument must be reported as a component of other comprehensive income and be reclassified into earnings in the same period
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or periods during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings.
The Company enters into interest rate swap agreements to reduce the risk of changes in the debt’s fair value attributable to changes in the LIBOR rate. These swap agreements qualify as fair value hedges. Accordingly, income or expense resulting from such agreements is recorded as an adjustment to interest expense in the period covered. The Company also enters into contracts to reduce the effects of fluctuations in oil and gas prices. These contracts qualify as cash flow hedges. Prior to 2001, gains and losses were determined monthly and were included in oil and gas revenues in the period the hedged production was sold. With the adoption of SFAS No. 133, gains or losses will be recorded as described above. SFAS No. 133 will almost certainly increase volatility in earnings and other comprehensive income.
SFAS No. 133 requires that commodity contracts be evaluated to determine whether they are “normal purchases or normal sales.” Certain contracts do not meet this definition and therefore are considered derivative instruments. However, the contracts that do not meet the definition may be designated as cash flow hedges of the underlying commodity sales. Based on contracts in effect on March 31, 2001, Interest and other revenues in the Income Statement was increased by $2.3 million of hedging gains in the first quarter, and Unrealized hedging liabilities of $29.8 million and Other comprehensive loss of $32.1 million were recorded on the Balance Sheet. See Note 7.
(3) ACQUISITIONS
All acquisitions have been accounted for as purchases. Purchase prices were allocated to acquired assets based on their estimated fair value at acquisition. Acquisitions have been funded with internal cash flow, bank borrowings and the issuance of debt and equity securities. The Company purchased various properties for consideration of $50,000 and $3.5 million during the quarters ended March 31, 2000 and 2001, respectively.
Unaudited Pro Forma Financial Information
The following table presents unaudited pro forma operating results as if the sale of the Sterling Plant had occurred on January 1, 2000 (in thousands, except per share data):
| Pro Forma | ||||
| Three Months Ended | ||||
| March 31, 2000 | ||||
| Revenues | $ | 41,399 | ||
| Net income | 3,741 | |||
| Earnings per share – basic and diluted | 0.11 | |||
| Total assets | 727,479 | |||
| Stockholders’ equity | 147,360 | |||
The pro forma results have been prepared for comparative purposes only and do not purport to present actual results that would have been achieved had the divestiture been made on January 1, 2000 or to be indicative of future results.
(4) IPF RECEIVABLES
At December 31, 2000 and March 31, 2001, IPF had net receivables of $48.9 million and $42.8 million, respectively. The receivables result from the purchase of overriding royalty interests payable from an agreed-upon share of revenues until a specified rate of return has been achieved. The royalties constitute property interests that serve as security for the receivables. On Certain of IPF’s receivables, income has historically been recorded at rates below those specified in the contract based on an assessment of the recoverability of the specified return. Due to favorable oil and gas prices over the past 12 to 18 months, it now appears likely that at least some of these receivables will generate their full contract return. At March 31, 2001, the book value of the affected receivables was increased to reflect the full amount due and an approximately $1.1 million increase was recorded as additional income in the first quarter. The Company estimates that $13.0 million of receivables at March 31, 2001 will be repaid in the next twelve months and has classified them as current. The net receivables reflect valuation allowances
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for estimated uncollectible amounts associated with the long-term portion of IPF’s receivables of $15.3 million and $15.2 million at December 31, 2000 and March 31, 2001, respectively.
(5) DISPOSITIONS
In June 2000, the Company sold the Sterling Plant for $19.7 million and recorded a $716,000 loss.
(6) INDEBTEDNESS
The Company had the following debt and company-obligated preferred securities of subsidiary trust (“Trust Preferred”) outstanding as of the dates shown. Interest rates, excluding the impact of interest rate swaps, at March 31, 2001 are shown parenthetically:
| December 31, | March 31, | ||||||||||
| 2000 | 2001 | ||||||||||
| (In thousands) | |||||||||||
| Senior debt | |||||||||||
| Credit Facility (7.4%) | $ | 89,900 | $ | 76,800 | |||||||
| Other (6.2%) | 14 | 14 | |||||||||
| 89,914 | 76,814 | ||||||||||
| Less amounts due within one year | (14 | ) | (14 | ) | |||||||
| Senior debt, net | 89,900 | 76,800 | |||||||||
| Non-recourse debt | |||||||||||
| Great Lakes credit facility (7.2%) | 84,509 | 78,006 | |||||||||
| IPF credit facility (7.5%) | 28,500 | 20,000 | |||||||||
| Non-recourse debt | 113,009 | 98,006 | |||||||||
| Subordinated notes | |||||||||||
| 8.75% Senior Subordinated Notes due 2007 | 125,000 | 125,000 | |||||||||
| 6% Convertible Subordinated Debentures due 2007 | 37,550 | 35,940 | |||||||||
| Subordinated notes | 162,550 | 160,940 | |||||||||
| Total debt | 365,459 | 335,746 | |||||||||
| Trust Preferred | 92,640 | 92,640 | |||||||||
| Total debt and Trust Preferred | $ | 458,099 | $ | 428,386 | |||||||
Interest paid during the quarters ended March 31, 2000 and 2001 totaled $14.9 million and $12.2 million, respectively. The Company does not capitalize interest expense.
Senior debt
The Company maintains a $225 million secured revolving bank facility (the “Parent Facility”), which provides for a borrowing base subject to semi-annual redeterminations in April and October and under certain other conditions. On May 1, 2001, the borrowing base was $115 million of which $37.8 million was available. Redeterminations are based on a variety of factors, including the discounted present value of the banks’ projection of estimated future net cash flows and require approval by 75% of the lenders. Interest is payable the earlier of quarterly or as LIBOR notes mature. The loan matures in February 2003. A commitment fee is paid quarterly on the undrawn balance at an annual rate of 0.25% to 0.50%. The interest rate on the Parent Facility is LIBOR plus 1.50% to 2.25%, depending on amounts outstanding. The weighted average interest rate on these borrowings, excluding interest rate swaps, was 8.3% and 8.2% for the quarters ended March 31, 2000 and 2001, respectively. After the impact of hedging, the rate was 8.1% and 8.2%
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for the quarters ended March 31, 2000 and 2001, respectively.
Non-recourse debt
The Company consolidates its proportionate share of the outstandings on Great Lakes’ $275 million secured revolving bank facility (the “Great Lakes Facility”). The Great Lakes Facility is non-recourse to Range and provides for a borrowing base, which is subject to redeterminations semi-annually in April and October. On May 1, 2001, the borrowing base was $200 million of which $45 million was available. Interest is payable the earlier of quarterly or as LIBOR notes mature. The loan matures in September 2003. The interest rate on the facility is LIBOR plus 1.50% to 2.00%, depending on amounts outstanding. A commitment fee is paid quarterly on the undrawn balance at an annual rate of 0.25% to 0.50%. The weighted average interest rate on these borrowings, excluding interest rate swaps, was 8.3% and 8.1% for the quarters ended March 31, 2000 and 2001, respectively. After the impact of hedging, the rate was 8.3% and 8.4% for the quarters ended March 31, 2000 and March 31, 2001, respectively.
IPF has a $100 million secured revolving credit facility (the “IPF Facility”). The IPF Facility is non-recourse to Range and matures in January 2004. The borrowing base under the IPF Facility is subject to semi-annual redeterminations. On May 1, 2001, the borrowing base was $30.0 million of which $8.6 million was available. The IPF Facility bears interest at LIBOR plus 1.75% to 2.25% depending on outstandings. Interest expense on the IPF Facility is included in IPF expenses in the Statements of Income and amounted to $1.0 million and $528,000 for the quarters ended March 31, 2000 and 2001, respectively. A commitment fee is paid quarterly on the undrawn balance at an annual rate of 0.375% to 0.50%. The weighted average interest rate on these borrowings was 7.6% and 8.2% for the quarters ended March 31, 2000 and 2001, respectively.
Subordinated Notes
The 8.75% Senior Subordinated Notes Due 2007 (the “8.75% Notes”) are redeemable beginning January 15, 2002, in whole or in part, at a price of 104.375% of principal, declining to par in 2005. The Notes are unsecured general obligations and are subordinated to all senior debt (as defined) including borrowings under the Parent Facility. The Notes are guaranteed by the Company’s subsidiaries. Interest is payable semi-annually in January and July.
The 6% Convertible Subordinated Debentures Due 2007 (the “6% Debentures”) are convertible into common stock at the option of the holder at any time at a price of $19.25 per share, subject to adjustment in certain circumstances. Interest is payable semi-annually in February and August. The Debentures mature in 2007 and are currently redeemable at 103.5% of principal, declining 0.5% annually in February through 2007. The Debentures are unsecured general obligations subordinated to all senior indebtedness (as defined), including the 8.75% Notes and the Parent Facility. During the quarters ended March 31, 2000 and 2001, $300,000 and $1.6 million of 6% Debentures were retired at a discount in exchange for 90,000 and 192,546 shares of common stock, respectively. Extraordinary gains of $100,000 and $432,000 were recorded in the 2000 and 2001 quarters, respectively.
Trust Preferred
In 1997, a special purpose affiliate (the “Trust”) issued $120 million of 5 3/4% Trust Convertible Preferred Securities (the “Trust Preferred”), represented by 2,400,000 Trust Preferred shares priced at $50 each. Each Trust Preferred share is convertible at the holder’s option into 2.1277 shares of common stock, representing a conversion price of $23.50 per share. The Trust invested the proceeds in 5 3/4% convertible junior subordinated debentures issued by the Company (the “Junior Debentures”), its sole asset. The Junior Debentures and the Trust Preferred mature in November 2027. The Junior Debentures and the Trust Preferred can currently be redeemed in whole or in part at a price of 104.025% of principal. The redemption price declines annually in November reaching par in 2007.
The Company guarantees payments on the Trust Preferred to the extent the Trust has funds available. Such guarantee, when taken together with Range’s other obligations, provides a full subordinated guarantee of the Trust Preferred. The accounts of the Trust are included in Range’s consolidated financial statements after appropriate eliminations. Distributions on the Trust Preferred are recorded as interest expense, are deductible for tax purposes and are subject to limitations in the Parent Facility. During the quarter ended March 31, 2000, $6.2 million of Trust Preferred was acquired at a discount in exchange for 946,000 shares of common stock. An extraordinary gain of $3.4 million was recorded.
The debt agreements contain various covenants relating to net worth, working capital maintenance, restrictions on dividends and financial ratios. The Company was in compliance with all covenants at March 31, 2001. Under its
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most restrictive covenant, which includes preferred as well as common dividends, $4.9 million of dividends or other restricted payments could be made at March 31, 2001. Under the Parent Facility, if certain ratio requirements are not met, payments of dividends on the Trust Preferred become restricted. The Parent Facility prohibits common dividends.
(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 their short maturity. The Company believes that the book values of its borrowings under the Parent Facility, the Great Lakes Facility, and the IPF Facility approximate fair value because of their floating rate structure.
A portion of the Company’s future oil and gas sales is periodically hedged through the use of futures, option or swap contracts. Gains and losses on these instruments are reflected in the contract month being hedged as an adjustment to oil and gas revenue. The Company also seeks to manage interest rate risk on its credit facilities through the use of interest rate swaps. Gains and losses on the swaps are included as an adjustment to interest expense in the relevant periods.
The following table sets forth the book and estimated fair values of the Company’s financial instruments (in thousands):
| December 31, 2000 | March 31, 2001 | |||||||||||||||||
| Book | Fair | Book | Fair | |||||||||||||||
| Value | Value | Value | Value | |||||||||||||||
| Assets | ||||||||||||||||||
| Cash and equivalents | $ | 2,485 | $ | 2,485 | $ | 1,524 | $ | 1,524 | ||||||||||
| Marketable securities | 2,028 | 2,028 | 1,625 | 1,625 | ||||||||||||||
| Total | 4,513 | 4,513 | 3,149 | 3,149 | ||||||||||||||
| Liabilities | ||||||||||||||||||
| Commodity swaps | — | (72,090 | ) | (28,465 | ) | (28,465 | ) | |||||||||||
| Interest rate swaps | — | (1,029 | ) | (1,679 | ) | (1,679 | ) | |||||||||||
| Long-term debt | (365,459 | ) | (348,257 | ) | (335,746 | ) | (324,942 | ) | ||||||||||
| Trust Preferred | (92,640 | ) | (53,268 | ) | (92,640 | ) | (57,511 | ) | ||||||||||
| Total | (458,099 | ) | (474,644 | ) | (458,530 | ) | (412,597 | ) | ||||||||||
| Net financial instruments | $ | (453,586 | ) | $ | (470,131 | ) | $ | (455,381 | ) | $ | (409,448 | ) | ||||||
At March 31, 2001, the Company had hedging contracts covering 31.6 Bcf of gas and 610,000 barrels of oil at prices ranging from $3.37 to $5.93 per Mmbtu (averaging $4.16) and $27.00 to $33.71 per barrel (averaging $28.36). Their fair value, represented by the estimated amount that would be required to terminate the contracts, approximated a net loss of $28.5 million. These contracts expire monthly through December 2002. Gains or losses on hedging transactions are determined as the difference between the contract price and the reference price, generally closing prices on the New York Mercantile Exchange (“NYMEX”). Transaction gains and losses are determined monthly and are included in oil and gas revenues in the period the hedged production is sold. Net losses incurred relating to these derivatives for the quarters ended March 31, 2000 and 2001 totaled $1.6 million and $23.4 million, respectively.
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In June 2000, the Company repriced 4.1 Bcf of gas hedges from an average price of $2.59 to $3.00 per Mmbtu. In exchange, an average of 22,700 Mmbtu per day from April 2001 through March 2002 was hedged at an average price of $3.20 per Mmbtu. While the Company’s payment requirements were affected, under generally accepted accounting principles the $6.0 million of estimated net losses on the repriced transactions were recorded in the period in which they would have been recorded if no repricing had occurred. A deferred loss and associated liability of $6.0 million were recorded on the Balance Sheet at June 30, 2000. At March 31, 2001, only $1.8 million of the liability remained. The following schedule shows the effect of the hedge position for the three quarters ended March 31, 2001 and at March 31, 2001 including the repriced hedges:
| Hedging Gain (Loss) Exposure | ||||||||||||||
| (In thousands) | ||||||||||||||
| Impact on | Repricing's | |||||||||||||
| Oil & Gas | Impact on | Impact on | ||||||||||||
| Quarter Ended | Revenue | Cash Flow | Cash Flow | |||||||||||
| Closed contracts: | ||||||||||||||
| September 30, 2000 | $ | (17,668 | ) | $ | 1,527 | $ | (16,141 | ) | ||||||
| December 31, 2000 | (13,996 | ) | 51 | (13,945 | ) | |||||||||
| March 31, 2001 | (23,440 | ) | 102 | (23,338 | ) | |||||||||
| (55,104 | ) | 1,680 | (53,424 | ) | ||||||||||
| Open Contracts: | ||||||||||||||
| June 30, 2001 | (7,990 | ) | (461 | ) | (8,451 | ) | ||||||||
| September 30, 2001 | (8,340 | ) | (466 | ) | (8,806 | ) | ||||||||
| December 31, 2001 | (7,622 | ) | (466 | ) | (8,088 | ) | ||||||||
| March 31, 2002 | (3,203 | ) | (455 | ) | (3,658 | ) | ||||||||
| June 30, 2002 | 283 | — | 283 | |||||||||||
| September 30, 2002 | 232 | — | 232 | |||||||||||
| December 31, 2002 | 208 | — | 208 | |||||||||||
| (26,432 | ) | (1,848 | ) | (28,280 | ) | |||||||||
| Total | $ | (81,536 | ) | $ | (168 | ) | $ | (81,704 | ) | |||||
Interest rate swaps are accounted for on the accrual basis. Income or expense resulting from these agreements is recorded as an adjustment to interest expense in the period covered. At March 31, 2001, Great Lakes had four interest rate swap agreements totaling $65 million. Two agreements totaling $45 million at LIBOR rates of 7.09% expire in May 2004. Two agreements totaling $10 million at 6.20% and 6.22% expire in December 2002. The fair value of the swaps at March 31, 2001 was a net loss of $1.7 million and is based on then current quotes for equivalent agreements. On March 31, 2001, the 30-day LIBOR rate was 5.1%. As discussed in Note 6, interest on the Parent Facility is based on LIBOR plus a margin. The agreements expiring in May 2004 and December 2002 may be terminated at the counterparty’s option in May 2002 and December 2001, respectively. The counterparty’s option is marked to market each period. In the first quarter of 2001, such amount was insignificant.
The combined fair values of the oil and gas hedging contracts and interest rate swaps totaling $30.1 million appear as an Unrealized hedging liability in the Balance Sheet. These hedging activities are conducted with major financial or commodities trading institutions which management believes are acceptable credit risks. At times, such risks may be concentrated with certain counterparties or groups of counterparties. The credit worthiness of these counterparties is subject to continuing review.
(8) COMMITMENTS AND CONTINGENCIES
The Company is involved in various legal actions and claims arising in the ordinary course of business. In the opinion of management, such litigation and claims are likely to be resolved without material adverse effect on the Company’s financial position or results of operations.
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In 1998, a Domain stockholder filed an action alleging that the terms of the Merger were unfair. Range was alleged to have aided and abetted certain breaches of fiduciary duty by the other defendants. On March 14, 2001, the suit was dismissed without prejudice.
In February 2000, a royalty owner filed suit asking for a class action certification against Great Lakes in New York, alleging that gas was sold to affiliates and gas marketers at low prices, inappropriate post production expenses reduced proceeds to the royalty owners, and that the royalty owners’ share of gas was improperly accounted for. The action sought a proper accounting, an amount equal to the difference in prices paid and the highest obtainable prices, punitive damages and attorneys’ fees. While the outcome is uncertain, Great Lakes believes the suit will be resolved without material adverse effect on its financial position or results of operations.
(9) STOCKHOLDERS’ EQUITY
In 1995, the Company issued 1,150,000 shares of $2.03 Convertible Exchangeable Preferred Stock, (the “$2.03 Preferred”) for $28.8 million. The $2.03 Preferred is convertible into common stock at a conversion price of $9.50. The $2.03 Preferred is currently redeemable at a price of $25.75 a share, and is exchangeable for 8.125% Convertible Subordinated Notes. Through December 31, 2000, $23.2 million of the $2.03 Preferred had been exchanged for 4.6 million shares of common stock. During the quarter ended March 31, 2001, $5.3 million of the $2.03 Preferred was exchanged for 747,176 shares of common stock. Only 8,235 shares remain outstanding, having a liquidation preference of $205,875. No gains on exchanges of $2.03 Preferred are included in net income as it is an equity security. However, gains on exchanges are included in income available to common shareholders. See Note 13.
Supplemental disclosures of non-cash investing and financing activities
| Three Months Ended March 31, | ||||||||
| 2000 | 2001 | |||||||
| (In thousands) | ||||||||
| Common stock issued under benefit plans | $ | 82 | $ | 1,173 | ||||
| Common stock exchanged for convertible securities | $ | 2,812 | $ | 5,970 | ||||
(10) STOCK OPTION AND PURCHASE PLANS
The Company has four stock option plans (two of which are currently active) and a stock purchase plan. Under these plans, incentive and non-qualified options and stock purchase rights can be issued to directors, officers, and employees pursuant to decisions of the Compensation Committee of the Board. Information with respect to the stock option plans is summarized below:
| 1999 | 1989 | Directors' | Domain | ||||||||||||||||||
| Option | Option | Option | Option | ||||||||||||||||||
| Plan | Plan | Plan | Plan | Total | |||||||||||||||||
| Outstanding at December 31, 2000 | 665,200 | 1,182,893 | 136,000 | 248,965 | 2,233,058 | ||||||||||||||||
| Granted | 734,350 | — | — | — | 734,350 | ||||||||||||||||
| Exercised | — | (15,137 | ) | — | (93,385 | ) | (108,522 | ) | |||||||||||||
| Expired/canceled | (2,500 | ) | (141,742 | ) | — | — | (144,242 | ) | |||||||||||||
| Outstanding at March 31, 2001 | 1,397,050 | 1,026,014 | 136,000 | 155,580 | 2,714,644 | ||||||||||||||||
In May 1999, Shareholders approved the 1999 Stock Incentive Plan (the “1999 Option Plan”) providing for the issuance of options on up to 1.4 million shares of common stock. All options issued under the 1999 Option Plan vest 25% per year beginning one year after grant and expire in 10 years. During the quarter ended March 31, 2001, 734,350 options were granted under the Plan at exercise prices ranging from $6.40 to $6.67. At March 31, 2001, 1.4 million options were outstanding under the Plan at exercise prices ranging from $1.94 to $6.67.
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The Company also maintains the 1989 Stock Option Plan (the “1989 Option Plan”) which authorizes the issuance of options on up to 3.0 million shares of common stock. No options have been granted under this plan since March 1999. All options issued under the 1989 Option Plan vest 30% after one year, 60% after two years and 100% after three years and expire in 5 years. At March 31, 2001, 1.0 million options were outstanding under the Plan at exercise prices ranging from $2.63 to $18.00.
In 1994, Shareholders approved the Outside Directors’ Stock Option Plan (the “Directors’ Plan”). In May 2000, Shareholders approved an increase in the number of options which could be issued under this Plan to 300,000 shares, extended the term of the options to ten years and setting the vesting period at 25% per year beginning one year after grant. At March 31, 2001, 136,000 options were outstanding under the Plan at exercise prices ranging from $2.81 to $16.88.
In the Domain acquisition, its stock option plan was adopted. Since that time, no options have been granted under the Plan and existing options became exercisable into Range common stock. At March 31, 2001, 155,580 options were outstanding under the Plan at prices ranging from $0.01 to $3.46.
In total, 2.7 million options were outstanding at March 31, 2001 at exercise prices ranging from $0.01 to $18.00 as follows:
| Average | 1999 | 1989 | Directors' | Domain | ||||||||||||||||||||||||||||
| Exercise Prices | Exercise Price | Plan | Plan | Plan | Plan | Total | ||||||||||||||||||||||||||
| $ | 0.01 | – | $ | 4.99 | $ | 2.47 | 603,700 | 434,538 | 64,000 | 155,580 | 1,257,818 | |||||||||||||||||||||
| 5.00 | – | 9.99 | 6.79 | 793,350 | 230,176 | — | — | 1,023,526 | ||||||||||||||||||||||||
| 10.00 | – | 14.99 | 11.86 | — | 25,000 | 48,000 | — | 73,000 | ||||||||||||||||||||||||
| 15.00 | – | 18.00 | 17.31 | — | 336,300 | 24,000 | — | 360,300 | ||||||||||||||||||||||||
| Total | 1,397,050 | 1,026,014 | 136,000 | 155,580 | 2,714,644 | |||||||||||||||||||||||||||
In 1997, Shareholders approved the 1997 Stock Purchase Plan (the “Stock Purchase Plan”) authorizing the sale of up to 900,000 shares of common stock to officers, directors, key employees and consultants. Under the Plan, the right to purchase shares at prices ranging from 50% to 85% of market value may be granted. To date, all purchase rights have been granted at 75% of market value. In May 2000, Shareholders approved an increase in the number of shares authorized for issuance under the Plan to 1,250,000. From inception through March 31, 2001, a total of 908,319 shares have been sold under the Plan for $3.9 million. At March 31, 2001, rights to purchase 10,000 shares remained outstanding and purchase rights to 331,681 shares remained available for grant.
(11) BENEFIT PLAN
The Company maintains a 401(k) Plan for its employees. The Plan permits employees to contribute up to 15% of their salary on a pre-tax basis. The Company makes discretionary contributions to the Plan annually. In 2000, the Company contributed $483,000 of common stock (valued at market) to the Plan.
(12) INCOME TAXES
The Company follows SFAS Statement No. 109, “Accounting for Income Taxes,” pursuant to which the liability method is used in accounting for 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 regulations that will be in effect when the differences are expected to reverse. At December 31, 2000, the Company had a $72.0 million deferred tax asset. Utilization of this asset is dependent on future taxable income. As significant uncertainty existed in prior periods regarding the amount and timing of future taxable income, a full valuation allowance was recorded. Assuming that product prices remain at current levels or increase, the Company expects to realize enough taxable income to fully utilize the assets during 2001 and anticipates having a deferred tax liability by year-end. Therefore, the Company will provide for deferred taxes on income in subsequent quarters, after taxes on current income exceed the valuation allowance.
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At December 31, 2000, the Company had regular net operating loss carryovers of $191 million and alternative minimum tax (“AMT”) net operating loss (“NOLs”) carryovers of $171 million that expire between 2001 and 2020. Although NOLs generally are not limited in their use, those generated prior to a year in which a change of control occurs are subject to limitations imposed by the Internal Revenue Service. The Company has experienced such a change of control in past years, primarily due to acquisitions. Of those NOLs so affected, their use is limited to $10.6 million per year. NOLs generated in post change years have no such limitation. The Company also has a statutory depletion carryover of $5.6 million and an AMT credit carryover of $660,000 which are not subject to limitations or expiration.
The following table sets forth the year of expiration and amounts for the NOL carryovers:
| NOL Carryover Amount | ||||||||
| Expiration | Regular | AMT | ||||||
| (in thousands) | ||||||||
| 2001 | $ | 1,180 | $ | 1,180 | ||||
| 2002 | 558 | 480 | ||||||
| 2003 | 488 | 422 | ||||||
| 2004 | 666 | 136 | ||||||
| Thereafter | 188,166 | 169,255 | ||||||
| Total | $ | 191,058 | $ | 171,473 | ||||
(13) EARNINGS PER COMMON SHARE
The following table sets forth the computation of basic and diluted earnings per common share (in thousands except per share amounts):
| Three Months Ended March 31, | |||||||||||
| 2000 | 2001 | ||||||||||
| Numerator: | |||||||||||
| Income before extraordinary item | $ | 748 | $ | 18,080 | |||||||
| Gain on retirement of $2.03 Preferred | 1,114 | 529 | |||||||||
| Preferred dividends | (520 | ) | (4 | ) | |||||||
| Numerator for earnings per share, before extraordinary item | 1,342 | 18,605 | |||||||||
| Extraordinary item | |||||||||||
| Gain on retirement of securities, net | 3,533 | 432 | |||||||||
| Numerator for earnings per share, basic and diluted | $ | 4,875 | $ | 19,037 | |||||||
| Denominator: | |||||||||||
| Weighted average shares, basic | 39,006 | 50,186 | |||||||||
| Dilutive potential common shares | |||||||||||
| Stock options | 153 | 202 | |||||||||
| Denominator for diluted earnings per share | 39,159 | 50,388 | |||||||||
| Earnings per share: | |||||||||||
| Before extraordinary item, basic and diluted | $ | 0.03 | $ | 0.37 | |||||||
| After extraordinary item, basic and diluted | $ | 0.12 | $ | 0.38 | |||||||
During the three months ended March 31, 2000 and 2001, 153,461 and 393,798 stock options were included in the computation of diluted earnings per share. All remaining stock options, the 6% Debentures, Trust Preferred and the $2.03 Preferred were not included because their inclusion would have been antidilutive.
The Company has and will continue to consider exchanging common stock or other equity-linked securities for certain of its fixed income securities. Existing common stockholders may be materially diluted if substantial exchanges
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are consummated. The extent of dilution will depend on the number of shares and price at which common stock is issued, the price at which newly issued securities are convertible into common stock, and the price at which fixed income securities are reacquired.
(14) MAJOR CUSTOMERS
The Company markets its production on a competitive basis. Gas is sold under various types of contracts ranging from life-of-the-well to short-term contracts that are cancelable within 30 days. Prior to hedging, virtually all gas production is currently sold under market sensitive contracts. Oil purchasers may be changed on 30 days notice. The price received is generally equal to a posted price set by major purchasers in the area. The Company sells to oil purchasers on the basis of price and service. For the quarter ended March 31, 2001, three customers 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.
Great Lakes sells over 90% of its gas production to FirstEnergy, at prices based on the close of NYMEX contracts each month plus a basis differential. In September 2000, the parties amended the base contract to have its term automatically renewed for one-month periods through June 30, 2001. The amendments identified gas marketing services to be performed by FirstEnergy and defined the service fees to be paid by Great Lakes. Additionally, terms and conditions of the gas purchase agreement were further defined, including pricing, delivery points and projected volumes.
(15) OIL AND GAS ACTIVITIES
The following summarizes selected information with respect to producing activities:
| Three | ||||||||||
| Year Ended | Months Ended | |||||||||
| December 31, | March 31, | |||||||||
| 2000 | 2001 | |||||||||
| Oil and gas properties: | ||||||||||
| Subject to depletion | $ | 965,416 | $ | 988,439 | ||||||
| Unproved | 49,523 | 40,583 | ||||||||
| Total | 1,014,939 | 1,029,022 | ||||||||
| Accumulated depletion | (443,097 | ) | (460,342 | ) | ||||||
| Net oil and gas properties | $ | 571,842 | $ | 568,680 | ||||||
| Costs incurred: | ||||||||||
| Acquisition | $ | 4,701 | $ | 3,517 | (a) | |||||
| Development | 49,006 | 10,856 | ||||||||
| Exploration | 4,498 | 1,126 | ||||||||
| Total costs incurred | $ | 58,205 | $ | 15,499 | ||||||
| (a) | Includes only $269,000 of acquisitions of oil and gas reserves. The remainder represents purchases of acreage and associated costs. |
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(16) INVESTMENT IN GREAT LAKES
The Company owns 50% of Great Lakes and consolidates its proportionate interest in the joint venture’s assets, liabilities, revenues and expenses. The following table summarizes the Company’s interest in selected financial data from Great Lakes’ financial statements:
| At or for | ||||
| the period ended | ||||
| March 31, 2001 | ||||
| (In thousands) | ||||
| Current assets | $ | 6,521 | ||
| Oil and gas properties, net | 146,200 | |||
| Transportation and field assets, net | 17,267 | |||
| Other assets | 450 | |||
| Current liabilities | 16,048 | |||
| Long-term debt | 78,006 | |||
| Deferred taxes | (16 | ) | ||
| Members’ equity | 76,400 | |||
| Revenues | 12,961 | |||
| Net income | 5,094 | |||
(17) EXTRAORDINARY ITEM
During the three months ended March 31, 2001, 192,546 shares of common stock were exchanged for $1.6 million of 6% Debentures. An extraordinary gain net of costs of $432,000 was recorded because the Debentures were retired at a discount. In addition, 747,176 shares of common stock were exchanged for $5.3 million of $2.03 Preferred.
Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Factors Affecting Financial Condition and Liquidity
Liquidity and Capital Resources
During the three months ended March 31, 2001, the Company spent $15.5 million on development, exploration and acquisitions. Debt (including Trust Preferred) and $2.03 Preferred decreased by $35.0 million, including $5.3 million face value of $2.03 Preferred retired at a discount. At March 31, 2001, the Company had $1.5 million in cash, total assets of $676.5 million and a debt (including Trust Preferred) to book capitalization ratio of 71.0%. Unused bank borrowing capacity at March 31, 2001 was $38.2 million at the parent company, $22.0 million (the Company’s 50% interest) at Great Lakes and $17.0 million at IPF.
Long-term debt (including Trust Preferred) at March 31, 2001 totaled $428.4 million and included $76.8 million of bank borrowings at the parent company, $78.0 million (the Company’s 50% interest) at Great Lakes and $20.0 million at IPF, as well as $125.0 million of 8.75% Senior Notes, $36.0 million of 6% Debentures and $92.6 million of Trust Preferred.
During the three months ended March 31, 2001, 192,546 shares of common stock were exchanged for $1.6 million of 6% Debentures. A $432,000 extraordinary after-tax gain was recorded as the Debentures were acquired at a discount. In addition, 747,176 common shares were exchanged for $5.3 million of $2.03 Preferred.
The Company believes its capital resources are adequate to meet its requirements for at least the next twelve months. However, future cash flows are subject to a number of variables including the level of production and prices as well as various economic conditions that have historically affected the oil and gas business. There can be no
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assurance that internal cash flow and other capital sources will provide sufficient funds to maintain planned capital expenditures.
Cash Flow
The Company’s principal sources of cash are operating cash flow and bank borrowings. The Company’s cash flow is highly dependent on oil and gas prices. The Company has entered into hedging agreements covering approximately 61% and 16% of its anticipated production on an Mcfe basis for the remainder of 2001 and for 2002, respectively. The $15.5 million of capital expenditures in the three months ended March 31, 2001 were funded entirely with internal cash flow.
Net cash provided by operations for the quarters ended March 31, 2000 and 2001 was $2.7 million and $33.3 million, respectively. Cash flow from operations increased as higher realized prices and lower interest expense more than offset increasing direct operating and general and administrative expenses.
Net cash used in investing for the quarters ended March 31, 2000 and 2001 was $1.4 million and $6.5 million, respectively. The 2000 period included $6.1 million of additions to oil and gas properties partially offset by $3.6 million of IPF receipts and $1.1 million in asset sales. The 2001 period included $14.1 million of additions to oil and gas properties, partially offset by $7.3 million of IPF receipts and $304,000 in asset sales.
Net cash used in financing for the quarters ended March 31, 2000 and 2001 was $10.2 million and $27.7 million, respectively. During the first quarter of 2001, recourse debt decreased by $14.7 million and total debt (including Trust Preferred) decreased by $29.7 million. The reduction in debt was the result of applying excess cash flow and proceeds from the sale of assets to debt repayment and exchanges of common stock.
Capital Requirements
During the three months ended March 31, 2001, $15.5 million of capital was expended, primarily on development projects. This represented approximately 41% of internal cash flow. The Company manages its capital budget with the goal of funding it with internal cash flow. Development and exploration activities are highly discretionary, and, for the foreseeable future, management expects such activities to be maintained at levels below internal cash flow. Remaining cash flow should be available for debt reduction.
Bank Facilities
The Parent Facility is secured by oil and gas properties. At May 1, 2001, the borrowing base on the Parent Facility was $115.0 million of which $37.8 million was available. The borrowing base is subject to redetermination each April and October, as well as under special circumstances. The borrowing base is dependent on a number of factors, including the lenders’ discounted present value of estimated future net cash flow from production. Borrowing base redeterminations require approval of 75% of the lenders; redeterminations which result in an increase require 100% approval.
The Company expects to further reduce bank borrowings with internal cash flow and, possibly, asset sales. During the three months ended March 31, 2001, the Company sold properties for $304,000. There are currently no plans or agreements to sell any material assets.
The Company consolidates 50% of amounts outstanding under Great Lakes’ bank facility. The Great Lakes Facility is non-recourse to Range, provides for a borrowing base subject to semi-annual redetermination and is secured by substantially all of the joint venture’s assets. At May 1, 2001 Great Lakes’ borrowing base was $200.0 million of which $45.0 million was available. Borrowing base redeterminations require the approval of all lenders.
IPF maintains a $100.0 million revolving credit facility. The IPF Facility is secured by substantially all of IPF’s assets and is non-recourse to Range. IPF’s borrowing base is subject to semi-annual redeterminations in April and October. On May 1, 2001, the IPF borrowing base was $30.0 million, of which $8.6 million was available.
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Oil and Gas Hedging
The Company regularly enters into hedging agreements to reduce the impact of fluctuations in oil and gas prices. All such contracts are entered into solely to hedge price and to limit volatility. The Company’s current policy is to hedge between 50% and 75% of its production on a rolling twelve to eighteen month basis. At March 31, 2001, hedges were in place covering 31.6 Bcf of gas and 610,000 barrels of oil at prices ranging from $3.37 to $5.93 per Mmbtu (averaging $4.16) and from $27.00 to $33.71 per barrel (averaging $28.36). Their fair value, represented by the estimated amount that would be required to terminate them, was a net loss of $28.5 million at March 31, 2001. The contracts expire monthly through December 2002 and cover approximately 61% of anticipated remaining 2001 production and 16% of 2002 production. Gains or losses on hedging transactions are determined as the difference between the contract price and a reference price, generally closing prices on the NYMEX. Transaction gains and losses are determined monthly and are included in oil and gas revenues in the period the hedged production is sold. Net losses relating to derivatives for the three months ended March 31, 2000 and 2001 approximated $1.6 and $23.4 million, respectively.
In June 2000, the Company repriced 4.1 Bcf of gas hedges upwards to $3.00 per Mmbtu. In exchange, an average of 22,700 Mmbtu per day from April 2001 through March 2002 was hedged at an average price of $3.20 per Mmbtu. While the payment requirement relating to the repriced hedges was affected, under generally accepted accounting principles the $6.0 million of estimated net losses deferred were recorded as if no repricing occurred. A deferred loss and associated liability of $6.0 million was recorded on the Balance Sheet at June 30, 2000. At March 31, 2001, only $1.8 million of the liability remained.
Interest Rate Hedging
At March 31, 2001, Range had $428.4 million of debt (including Trust Preferred) outstanding. Of this amount, $253.6 million bears interest at fixed rates averaging 7.3%. Senior debt and non-recourse debt totaling $174.8 million bears interest at floating rates which averaged 7.3% at March 31, 2001. At March 31, 2001, Great Lakes had four interest rate swap agreements totaling $65 million. Two agreements totaling $45 million at rates of 7.09% expire in May 2004. Two agreements of $10 million each at 6.20% and 6.22% expire in December 2002. The fair value of the swaps at March 31, 2001 was a net loss of $1.7 million and is based on then current quotes for equivalent agreements. The 30-day LIBOR rate on March 31, 2001 was 5.1%. A 1% increase or decrease in short-term interest rates on the floating-rate debt outstanding at March 31, 2001 would cost or save the Company approximately $1.7 million in annual interest expense. The agreements expiring in May 2004 and December 2002 may be terminated at the counterparty’s option in May 2002 and December 2001, respectively. The counterparty’s option is marked to market each period. In the first quarter of 2001, such amount was insignificant.
Capital Restructuring Program
As more fully described in Note 1, the Company took a number of steps beginning in 1998 to strengthen its financial position, including the sale of assets and the exchange of common stock for fixed rate securities. These initiatives have resulted in reducing parent company bank debt to $76.8 million and total debt (including Trust Preferred) to $428.4 million at March 31, 2001. While the Company believes these steps have stabilized its financial position, debt remains too high. To return to its historical posture of consistent profitability and growth, the Company believes it must further reduce debt. The Company currently believes it has sufficient liquidity and cash flow to meet its obligations for the next twelve months; however, a drop in oil and gas prices or a reduction in production or reserves would reduce the ability to fund capital expenditures and meet its obligations.
Inflation and Changes in Prices
The Company’s revenues and the value of its assets have been and will continue to 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 prices. Oil and gas prices are subject to significant fluctuations that are beyond the Company’s ability to control or predict. During the first three months of 2001, the Company received an average of $26.87 per barrel of oil and $4.23 per Mcf of gas after hedging. Although certain of the Company’s costs and expenses are affected by the general inflation, inflation does not normally have a significant effect on the Company. However, the Company has noted some inflationary pressure due to favorable conditions in the oil industry. Should conditions in the oil industry remain favorable, inflationary pressures specific to the industry have and may continue to accelerate.
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Results of Operations
The following table identifies certain unusual items included in net income, and presents net income excluding the effect of such items. The table should be read in conjunction with the following discussions of results of operations.
| Three Months Ended March 31, | |||||||||
| 2000 | 2001 | ||||||||
| (In thousands) | |||||||||
| Net income as reported | $ | 4,281 | $ | 18,512 | |||||
| Impact of hedging, net | 1,562 | 21,175 | |||||||
| Unusual items: | |||||||||
| Writedown of marketable securities | — | 1,310 | |||||||
| Adjustment to IPF receivables | — | (1,097 | ) | ||||||
| Loss (gain) from sales of assets | 307 | (298 | ) | ||||||
| Gain on retirement of securities, net | (3,533 | ) | (354 | ) | |||||
| (3,226 | ) | (439 | ) | ||||||
| As adjusted | $ | 2,617 | $ | 39,248 | |||||
Comparison of 2001 to 2000
Quarters Ended March 31, 2000 and 2001
Net income for the first quarter of 2001 totaled $18.5 million, compared to $4.3 million for the comparable period in 2000. Net income excluding the impact of hedging losses and unusual items would have been $39.2 million compared to $2.6 million for the comparable period in 2000. Production increased to 151,023 Mcfe per day, a 1% increase from the prior year period. Revenues benefited from a 50% increase in average prices per Mcfe to $4.27. The average prices received for oil increased 36% to $26.87 per barrel and for gas increased 56% to $4.23 per Mcf. Production expenses increased $3.4 million to $12.6 million in the quarter as a result of significantly higher production taxes and increased workover costs in the Gulf of Mexico. Operating cost per Mcfe produced averaged $0.68 in 2000 versus $0.93 in 2001. Approximately 52% of the increase related to production taxes.
Transportation, processing and marketing revenues decreased 51% to $981,000. The benefit to processing revenues of higher NGL prices was more than offset by the Sterling Plant sale in April 2000. IPF’s $3.6 million of revenues rose 89% over that reported in the 2000 period. The 2001 period included $1.1 million of additional income as certain receivables were increased to reflect their full contractual rate of return. During the quarter ended March 31, 2001, IPF expenses included $519,000 of administrative costs and $691,000 of interest.
Exploration expense increased 23% to $1.1 million, primarily due to higher seismic activity. General and administrative expenses increased 53% to $3.5 million in the first quarter of 2001. The increase was primarily due to additional personnel and outsourcing costs.
Interest and other income increased from $(50,000) to $1.5 million. The 2001 period included $2.3 million of unrealized hedging gains and $298,000 of gains on asset sales, partially offset by a $1.3 million writedown of marketable securities. The 2000 period included $307,000 of losses on asset sales. Interest expense decreased 12% to $9.1 million primarily as a result of the lower average amounts outstanding. Average outstandings on the Parent Facility were $144 million and $97.6 million for the three months ended March 31, 2000 and 2001, respectively and the weighted average interest rates, excluding interest rate swaps, were 8.3% and 8.2%, respectively.
Depletion, depreciation and amortization (“DD&A”) increased 3% from the first quarter of 2000 as a result of the mix of production. However, lower proved reserves caused the depletion rate to increase from $1.15 to $1.37 per
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Mcfe. The Company currently estimates that its DD&A rate for the remainder of 2001 will approximate $1.33 per Mcfe. The high DD&A rate will make it difficult for the Company to remain profitable if commodity prices fall sharply.
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about the Company’s potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how Range views and manages its ongoing market risk exposures. All of the Company’s market risk sensitive instruments were entered into for purposes other than trading.
Commodity Price Risk. Range’s major market risk exposure is in the pricing applicable to its oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to U.S. natural gas production. Pricing for oil and gas production has been volatile and unpredictable for many years. The Company periodically enters into financial hedging activities with respect to a portion of its projected oil and gas production through financial swaps whereby Range will receive a fixed price for its production and pay a variable market price to the contract counterparty. These financial hedging activities are intended to reduce the impact of oil and gas price fluctuations. Realized gains and losses from the settlement of these hedges are recognized in oil and gas revenues when the associated production occurs. The gains and losses realized as a result of hedging are substantially offset in the cash market when the commodity is delivered. Range does not hold or issue derivative instruments for trading purposes.
As of March 31, 2001, Range had oil and gas hedges in place covering 31.6 Bcf of gas and 610,000 barrels of oil. Their fair value, represented by the estimated amount that would be required to terminate the contracts, was a net loss of approximately $28.5 million at March 31, 2001. These contracts expire monthly through December and cover approximately 61% of anticipated 2001 production and 16% of 2002 production. Gains or losses on hedging transactions are determined as the difference between the contract price and the reference price, generally closing prices on the NYMEX. Transaction gains and losses are determined monthly and are included in oil and gas revenues in the period the hedged production is sold. Net losses incurred relating to these derivatives for the three months ended March 31, 2000 and 2001 approximated $1.6 million and $23.4 million, respectively.
The Company seeks to reduce the volatility of its oil and gas revenue through hedging transactions. Should the price of a commodity decline, the revenue received from the sale of the product tends to decline to a corresponding extent. The decline in revenue is then partially offset based on the amount of production hedged and the hedge price. In the first quarter of 2001, a 10% reduction in oil and gas prices would have reduced revenue by $8.2 million, offset by a reduction in hedging losses of $7.5 million. If oil and gas future prices at March 31, 2001 had declined by 10%, the hedging loss exposure at that date would have been reduced by $16.2 million.
At March 31, 2001, Range had $428.4 million of debt (including Trust Preferred) outstanding. Of this amount, $253.6 million bears interest at fixed rates averaging 7.3%. Senior debt and non-recourse debt totaling $174.8 million bears interest at floating rates which averaged 7.3% for the three months then ended. At March 31, 2001, Great Lakes had four interest rate swap agreements totaling $65 million. Two agreements totaling $45 million at rates of 7.09% expire in May 2004. Two agreements of $10 million each at 6.20% and 6.22% expire in December 2002. The fair value of the swaps at March 31, 2001 was a net loss of $1.7 million and is based on then current quotes for equivalent agreements. The 30-day LIBOR rate on March 31, 2001 was 5.1%. The agreements expiring in May 2004 and December 2002 may be terminated at the counterparty’s option in May 2002 and December 2001, respectively. The counterparty’s option is marked to market each period. In the first quarter of 2001, such amount was insignificant. A 1% increase or decrease in short-term interest rates on the floating-rate debt outstanding at March 31, 2001 would cost or save the Company approximately $1.7 million in annual interest expense.
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GLOSSARY
The terms defined in this glossary are used throughout this Form 10-K.
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.
Credit Facility. The Range Resources Corporation $225 million revolving bank facility.
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.
LIBOR. London Interbank Offer Rate, the rate of interest at which banks offer to lend to one another in the wholesale money markets in the City of London. This rate is a yardstick for lenders involved in high value transactions.
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.
Merger. The acquisition via merger of Domain Energy Corporation by Lomak Petroleum, Inc. in August 1998. Simultaneously, Lomak’s name was changed to Range Resources Corporation.
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.
Oil and gas royalty trust. An arrangement whereby typically, the creating company conveys a net profits interest in certain of its oil and gas properties to the newly created trust and then distributes ownership units in the trust to its unitholders. The function of the trust is to serve as agent to distribute income from the net profits interest to its unitholders.
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Present Value. The present value, discounted at 10%, of future net cash flows from estimated proved reserves, using constant prices and costs in effect on the date of the report (unless such prices or costs are subject to change pursuant to contractual provisions).
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.
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PART II. OTHER INFORMATION
Item 1. Legal Proceedings
The Company is involved in various legal actions and claims arising in the ordinary course of business. In the opinion of management, such litigation and claims are likely to be resolved without material adverse effect on its financial position or results of operations.
In 1998, a Domain stockholder filed an action alleging that the terms of the Merger were unfair. Range was alleged to have aided and abetted certain breaches of fiduciary duty by the other defendants. On March 14, 2001, the suit was dismissed without prejudice.
In February 2000, a royalty owner filed suit asking for a class action certification against Great Lakes in New York, alleging that gas was sold to affiliates and gas marketers at low prices, inappropriate post production expenses reduced proceeds to the royalty owners, and that the royalty owners’ share of gas was improperly accounted for. The action sought a proper accounting for all gas sold, an amount equal to the difference in prices paid and the highest obtainable prices, punitive damages and attorneys’ fees. While the outcome is uncertain, Great Lakes believes the suit will be resolved without material adverse effect on its financial position or result of operations.
| Item 2. | Changes in Securities and Use of Proceeds | ||||||
| (a) | Not applicable | ||||||
| (b) | Not applicable | ||||||
| (c) | At various times during the quarter ended March 31, 2001, Range issued common stock in exchange for convertible securities. The shares of common stock issued in such exchanges were exempt from registration under Section 3(a)(9) of the Securities Act of 1933. During the quarter ended March 31, 2001, a total of $1.6 million face value of the 6% Debentures were retired in exchange for 192,546 shares of common stock and a total of $5.3 million face value of $2.03 Preferred was retired in exchange for 747,176 shares of common stock. | ||||||
| (d) | Not applicable. | ||||||
| Item 3. | Not applicable | ||||||
| Item 4. | Not applicable. | ||||||
| Item 5. | Not applicable | ||||||
| Item 6. | Exhibits and Reports on Form 8-K | ||||||
| (a) | Exhibits | ||||||
| The items listed on the accompanying index to exhibits are filed as part of this Quarterly Report on Form 10-Q. | |||||||
| (b) | Reports on Form 8-K – None | ||||||
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned.
| RANGE RESOURCES CORPORATION | ||||
| By: | /s/ Eddie M. LeBlanc | |||
| Eddie M. LeBlanc | ||||
| Chief Financial Officer | ||||
| May 8, 2001 | ||||
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EXHIBIT TABLE
| Exhibit Number | Description of Exhibit | Sequentially Numbered Page |
||
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