TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
	Item 1. Financial Statements
		CONSOLIDATED BALANCE SHEETS
		CONSOLIDATED STATEMENTS OF INCOME
		CONSOLIDATED STATEMENTS OF CASH FLOWS
		NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
	Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
PART II. OTHER INFORMATION
	Item 1. Legal Proceedings
	Item 2. Changes in Securities and Use of Proceeds
	Item 3. Not applicable
	Item 4. Not applicable
	Item 5. Not applicable
	Item 6. Exhibits and Reports on Form 8-K
SIGNATURES

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, 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           

51,959,160 Common Shares were outstanding on November 1, 2001.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

     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 latest 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

RANGE RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS
(In thousands)

				December 31,			September 30,
				2000			2001
							(Unaudited)
	Assets
Current assets
		Cash and equivalents		$	2,485		$	4,801
		Accounts receivable			33,221			29,912
		IPF receivables (Note 4)			20,800			11,000
		Unrealized hedging gain (Note 2)			—			39,051
		Inventory and other			5,580			3,629
					62,086			88,393
IPF receivables (Note 4)					28,128			32,887
Unrealized hedging gain (Note 2)					—			13,755
Oil and gas properties, successful efforts (Note 15)					1,014,939			1,076,737
		Accumulated depletion			(443,097	)		(495,651	)
					571,842			581,086
Transportation and field assets (Note 2)					33,593			34,154
		Accumulated depreciation			(12,339	)		(14,199	)
					21,254			19,955
Other (Note 2)					5,855			3,569
				$	689,165		$	739,645
			Liabilities and Stockholders’ Equity
Current liabilities
		Accounts payable		$	26,744		$	16,298
		Accrued liabilities			11,341			19,347
		Accrued interest			7,774			4,215
					45,859			39,860
Senior debt (Note 6)					89,900			95,000
Non-recourse debt (Note 6)					113,009			102,501
Subordinated notes (Note 6)					162,550			121,840
Trust Preferred (Note 6)					92,640			90,290
Commitments and contingencies (Note 8)					—			—
Deferred taxes (Note 12)					—			23,302
Stockholders’ equity (Notes 9 and 10)
		Preferred stock, $1 par, 10,000,000 shares authorized, $2.03 convertible preferred, 219,935 and 2,935 outstanding			220			3
		Common stock, $.01 par, 100,000,000 shares authorized, 49,187,682 and 51,644,231 outstanding			492			516
		Capital in excess of par value			363,625			372,204
		Retained earnings (deficit)			(178,223	)		(138,291	)
		Other comprehensive income (loss) (Note 2)			(907	)		32,420
					185,207			266,852
				$	689,165		$	739,645

See accompanying notes.

3

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited, in thousands except per share data)

		Three Months					Nine Months
		Ended September 30,					Ended September 30,
		2000		2001			2000			2001
Revenues
	Oil and gas sales	$	40,581	$	49,719		$	117,426		$	162,599
	IPF		3,077		1,218			8,137			7,189
	Transportation and processing		813		915			4,326			2,616
	Interest and other		348		(181	)		(895	)		3,137
			44,819		51,671			128,994			175,541
Expenses
	Direct operating		9,452		10,151			27,718			34,497
	Exploration		858		1,239			2,278			3,684
	IPF		1,083		794			3,590			2,816
	General and administrative		2,665		3,090			7,314			10,015
	Interest		9,634		7,267			30,238			24,360
	Depletion, depreciation and amortization		17,424		19,330			52,746			56,967
			41,116		41,871			123,884			132,339
Pretax income			3,703		9,800			5,110			43,202
Income taxes (Note 12)
	Current		208		—			(886	)		(51	)
	Deferred		—		3,430			—			4,958
			208		3,430			(886	)		4,907
Income before extraordinary item			3,495		6,370			5,996			38,295
Gain on retirement of securities (Note 17)			4,261		319			14,776			1,646
Net income		$	7,756	$	6,689		$	20,772		$	39,941
Comprehensive income (Note 2)		$	7,766	$	21,703		$	19,733		$	73,268
Earnings per share, basic and diluted (Note 13)
	Before extraordinary item	$	0.09	$	0.12		$	0.19		$	0.76
	After extraordinary item	$	0.19	$	0.13		$	0.55		$	0.79

See accompanying notes.

4

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited, in thousands)

					Nine Months Ended September 30,
					2000			2001
Cash flow from operations
	Net income				$	20,772		$	39,941
	Adjustments to reconcile to
		net cash provided by operations:
			Deferred taxes			—			5,844
			Depletion, depreciation and amortization			52,746			56,967
			Writedown of marketable securities			—			1,398
			Unrealized hedging gains			—			(2,929	)
			Adjustment to IPF receivables			(1,132	)		(1,847	)
			Amortization of deferred offering costs			1,277			1,776
			(Gain) on retirement of securities			(14,914	)		(2,585	)
			(Gain) loss on sale of assets			1,208			(1,169	)
			Changes in working capital:
				Accounts receivable		(6,650	)		3,213
				Inventory and other		4,301			954
				Accounts payable		(3,825	)		(4,511	)
				Accrued liabilities		(6,963	)		(3,017	)
				Net cash provided by operations		46,820			94,035
Cash flow from investing
	Oil and gas properties					(34,659	)		(62,293	)
	IPF investments					(4,560	)		(10,037	)
	IPF repayments					18,543			16,926
	Asset sales					25,117			1,940
				Net cash provided by (used in) investing		4,441			(53,464	)
Cash flow from financing
		Repayment of debt				(62,607	)		(39,655	)
		Preferred dividends				(1,434	)		(9	)
		Issuance of common stock				1,419			1,409
				Net cash used in financing		(62,622	)		(38,255	)
Change in cash						(11,361	)		2,316
Cash and equivalents, beginning of period						12,937			2,485
Cash and equivalents, end of period					$	1,576		$	4,801

See accompanying notes.

5

RANGE RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) ORGANIZATION AND NATURE OF BUSINESS

     Range Resources Corporation (“Range”) is engaged in the development, acquisition and exploration of oil and gas properties primarily in the Southwestern, Gulf Coast and Appalachian regions of the United States. The Company also provides financing to small oil and gas producers through a wholly-owned subsidiary, Independent Producer Finance (“IPF”). The Company seeks to increase its reserves and production principally through development drilling and acquisitions. In 1999, Range and FirstEnergy Corp. (“FirstEnergy”) contributed their Appalachian oil and gas assets to an equally owned joint venture, Great Lakes Energy Partners L.L.C. (“Great Lakes”).

     After ten years of rapid growth and uninterrupted profitability, Range concluded a series of disasterous acquisitions in 1997 and 1998. Due to the poor performance of the acquired properties, substantial write-downs were required and the Company was forced to retrench. Staff was sharply reduced, capital expenditures cut, assets sold and a program of exchanging common stock for fixed income securities initiated. Since year-end 1998, parent company bank debt has been reduced 74% to $95.0 million. Total debt, including Trust Preferred, has been reduced 44% to $409.6 million. As a result, the Company’s financial position has stabilized. The Company expects to continue to retire debt with internal cash flow and may exchange additional stock or equity-linked securities for indebtedness. Stockholders could be materially diluted if a substantial amount of fixed income securities are exchanged for stock. While such exchanges reduce stockholders’ proportionate ownership, management believes they enhance financial flexibility and will ultimately increase the value of the Company’s stock.

     With its financial strength largely restored, the Company has refocused on increasing production and reserves. As part of this effort, the Company’s entire exploration and production effort was placed under the conrol of a newly hired Executive Vice President in early 2001. Due to reserve revisions and asset sales, reserves and production fell in 1999 and 2000. While the Company does not expect to achieve full reserve replacement in 2001, projects currently underway should position it to accelerate production growth by the end of the year and to increase reserves in 2002.

     The Company believes it has sufficient liquidity and cash flow to meet its obligations. However, a material decline in oil and gas prices or a reduction in production and reserves would reduce its ability to fund capital expenditures, meet its financial obligations and reduce leverage. In addition, the Company’s high depletion, depreciation and amortization (“DD&A”) rate may make it difficult to remain profitable if oil and gas prices decline. The Company operates in an environment with numerous financial and operating risks, including, but not limited to, the ability to acquire reserves on an attractive basis, the inherent risks of the search for, development and production of oil and gas, the ability to sell production at prices which provide a satisfactory return and the highly competitive nature of the industry. The Company’s ability to expand its reserve base is, in part, dependent on obtaining sufficient capital through internal cash flow, borrowings or the issuance of debt or equity securities.

(2) 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 delivered. Revenues at IPF are recognized as received. Although receivables are concentrated in the oil and gas industry, the Company does not view this as an unusual credit risk. The Company had allowances for doubtful accounts relating to its exploration and production business of $1.7 million at December 31, 2000 and September 30, 2001. At the same dates, IPF had valuation allowances of $15.3 million and $15.3 million, respectively. A further decrease in oil prices could cause an increase in IPF’s valuation allowances and a corresponding decrease in income.

6

Marketable Securities

     The Company has adopted Statement of Financial Accounting Standards (“SFAS”) No. 115, “Accounting for Certain Investments.” Pursuant to SFAS 115, the Company’s holdings of equity securities qualify as available-for-sale and are recorded at fair value. Unrealized gains and losses are reflected in Stockholders’ equity as a component of Other comprehensive income. A decline in the market value of a security below cost deemed other than temporary is charged to earnings. Realized gains and losses are reflected in income. During the first and third quarters of 2001, the Company determined that the decline in the market value of an equity security it holds was other than temporary and losses of $1.3 million and $50,000 were recorded as reductions 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, the joint venture owns 4,700 miles of gas gathering and transportation lines and a leasehold position of approximately 1.1 million gross (992,000 net) acres. Great Lakes has 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 royalties in oil and gas properties from smaller producers. The royalties are accounted for as receivables because the investment is recovered from an agreed 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 are considered a return of capital and reduce receivables. Receivables classified as current represent the return of capital expected to be received within twelve months. All receivables are evaluated quarterly and provisions for uncollectible amounts are established. At September 30, 2001, IPF’s valuation allowance totaled $15.3 million. On certain receivables, income is recorded at rates below those specified due to an assessment of risk. Due to favorable oil and gas prices during the last nine months of 2000 and the first six months of 2001, certain of these receivables may generate all or a greater than anticipated percentage of contract returns. As a result, $1.9 million of increases in receivables were recorded as additional income in the nine months ended September 30, 2001. During the third quarter and nine months of 2001, IPF expenses were comprised of $406,000 and $1.3 million of general and administrative costs and $388,000 and $1.5 million of interest, respectively. During the same periods the prior year, expenses were comprised of $307,000 and $918,000 of general and administrative costs and $776,000 and $2.7 million of interest. IPF recorded reversals of its valuation allowance of $1.0 million and $1.7 million in the quarter and nine months ended September 30, 2000. In the quarter ending September 30, 2001, IPF recorded an increase in its valuation allowance of $473,000. The valuation allowance at the December 2000 and September 30, 2001 was the same.

Oil and Gas Properties

     The Company follows the successful efforts method of accounting. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Costs resulting 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 $1.20 and $1.34 per mcfe in the quarters ended September 30, 2000 and 2001, and $1.21 and $1.33 for the nine months, respectively. Unproved properties had a net book value of $49.5 million and $32.9 million at December 31, 2000 and September 30, 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 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 of three to five years. Buildings are depreciated over ten years.

7

Security Issuance Costs

     Expenses associated with the issuance of debt are capitalized and included in Other assets on the balance sheet. These costs are generally amortized over the expected life of the related securities. When a security is retired prior to maturity, related unamortized costs are expensed. At September 30, 2001, such capitalized costs totaled $3.2 million.

Gas Imbalances

     The Company uses the sales method to account for gas imbalances, recognizing revenue based on cash received rather than gas produced. At December 31, 2000 and September 30, 2001, gas imbalance liabilities of $318,000 and $114,000 were included in Accrued liabilities, respectively.

Comprehensive Income

     The Company follows SFAS No. 130, “Reporting Comprehensive Income,” defined as changes in Stockholders’ equity from nonowner sources. The following is a calculation of comprehensive income (in thousands):

			Three Months Ended					Nine Months Ended
			September 30,					September 30,
			2000		2001			2000			2001
Net income			$	7,756	$	6,689		$	20,772		$	39,941
	Add: Change in unrealized gain
		Gross		4		23,098			(1,045	)		50,784
		Tax effect		—		(8,084	)		—			(17,457	)
	Less: Realized gain
		Gross		6		—			6			—
		Tax effect		—		—			—			—
Comprehensive income			$	7,766	$	21,703		$	19,733		$	73,268

Use of Estimates

     The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect reported assets, liabilities, revenues and expenses, as well as disclosure of contingent assets and liabilities. Actual results could differ from these estimates.

Recent Accounting Pronouncements

     Beginning 2001, SFAS No. 133, “Accounting for Derivatives”, required that derivatives be recorded on the balance sheet as assets or liabilities at fair value. Changes in the fair value of all derivatives are recognized immediately in earnings unless the derivative qualifies as a hedge of future cash flows. For derivatives qualifying as hedges of future cash flows, the effective portion of any changes in fair value is recognized in a component of stockholders’ equity called other comprehensive income (“OCI”) and then reclassified to earnings when the underlying anticipated transaction is consummated. Any ineffective portion of such hedges is recognized in earnings as it occurs. On adopting SFAS No. 133 on January 1, 2001, the Company recorded $72.1 million of Unrealized hedging loss on its balance sheet and an offsetting deficit in OCI. Due to the decline in oil and gas prices since year-end, this loss had become a $52.8 million Unrealized gain by September 30, 2001. SFAS No. 133 tends to increase earnings volatility in independent oil companies.

     The Company enters into contracts to reduce the effect of fluctuations in oil and gas prices. These contracts qualify as cash flow hedges. Prior to 2001, gains and losses were determined monthly and included in oil and gas revenues in the period the hedged production was sold. Starting in 2001, gains or losses on open contracts are recorded either in current period income or in OCI. The Company also enters into swap agreements to reduce the risk of changing interest rates. These agreements qualify as fair value hedges and related income or expense is recorded as an adjustment to interest expense in the period covered.

8

     Interest and other revenues in the Income Statement was decreased by $321,000 for ineffective hedging losses and increased for ineffective hedging gains of $2.9 million in the three months and nine months ended September 30, 2001, respectively. Unrealized hedging gains of $52.8 million and OCI of $32.4 million, net of taxes, were recorded on the balance sheet at September 30, 2001. See Note 7.

(3) ACQUISITIONS

     All acquisitions have been accounted for as purchases. Purchase prices were allocated to acquired assets based on 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 $1.7 million and $2.7 million during the nine months ended September 30, 2000 and 2001, respectively.

(4) IPF RECEIVABLES

     At December 31, 2000 and September 30, 2001, IPF had net receivables of $48.9 million and $43.9 million, respectively. The receivables represent overriding royalty interests payable from an agreed-upon share of revenues until a specified return is achieved. The royalties constitute property interests that serve as security for receivables. On certain IPF receivables, income has been recorded at rates below those specified in the contract based on an assessment of risk. Due to favorable oil and gas prices during the last nine months of 2000 and the first half of 2001, some of these receivables may generate a greater proportion of their contractual return. In the first half of 2001, the book value of the affected receivables was increased and approximately $1.9 million was recorded as additional income. The Company estimates that $11.0 million of receivables at September 30, 2001 will be repaid in the next twelve months and has classified them as current. IPF receivables reflected valuation allowances of $15.3 million at both December 31, 2000 and September 30, 2001. A further decrease in the price of oil could cause an increase in IPF’s valuation allowances and a corresponding decrease in income.

(5) DISPOSITIONS

     In June 2000, the Company sold a gas processing plant for $19.7 million and recorded a $716,000 loss.

     The following table presents unaudited pro forma operating results as if the sale of the gas plant occurred January 1, 2000 (in thousands, except per share data):

	Pro Forma
	Nine Months Ended
	September 30
	2000		2001
Revenues	$	127,447	$	175,541
Net income		21,249		39,941
Earnings per share – basic and diluted		0.56		0.79
Total assets		685,876		739,645
Stockholders’ equity		159,666		266,852

Pro forma results have been prepared for comparative purposes only. They do not purport to present actual results that would have been achieved or to be indicative of future results.

9

(6) INDEBTEDNESS

     The Company had the following debt and Trust Preferred outstanding as of the dates shown. Interest rates at September 30, 2001, excluding the impact of hedging, are shown parenthetically:

			December 31,			September 30,
			2000			2001
			(In thousands)
Senior debt
		Parent credit facility (5.2%)	$	89,900		$	95,000
		Other (6.2%)		14			12
				89,914			95,012
	Less amounts due within one year			(14	)		(12	)
				89,900			95,000
Non-recourse debt
		Great Lakes credit facility (5.3%)		84,509			81,001
		IPF credit facility (5.5%)		28,500			21,500
				113,009			102,501
Subordinated debt
	8.75% Senior Subordinated Notes due 2007			125,000			90,000
	6% Convertible Subordinated Debentures due 2007			37,550			31,840
				162,550			121,840
Total debt				365,459			319,341
Trust preferred				92,640			90,290
Total			$	458,099		$	409,631

     Subsequent to September 30, 2001, the Company repurchased an additional $7.5 million face amount of 8.75% Notes and exchanged $1.0 million of the Notes for common stock. In addition, the Company also repurchased, at a discount, an additional $500,000 face amount of Trust Preferred for cash.

     Interest paid in cash during the three months ended September 30, 2000 and 2001 totaled $13.9 million and $11.0 million, respectively. Interest paid in cash during the nine months ended September 30, 2000 and 2001 totaled $36.1 million and $28.1 million, respectively. The Company does not capitalize interest expense.

Senior debt

     The Company maintains a $225.0 million secured revolving bank facility (the “Parent Facility”). The Parent Facility provides for a borrowing base subject to semi-annual redeterminations in April and October. On October 31, 2001, the borrowing base was $120.0 million of which $23.9 million was available. Redeterminations are based on a variety of factors, including the bank’s projection of future cash flows. Redeterminations 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 Facility is LIBOR plus 1.50% to 2.25%, depending on outstandings. At September 30, 2001, the commitment fee was 0.50% and the interest rate margin was 2.25%. The weighted average interest rate on the Facility was 9.0% and 5.9% for the three months ended September 30, 2000 and 2001, and 8.7% and 7.0% for the nine months then ended, respectively. At October 31, 2001, the interest rate was 4.3%.

Non-recourse debt

     The Company consolidates its proportionate share of borrowings on Great Lakes’ $275.0 million secured revolving bank facility (the “Great Lakes Facility”). The Great Lakes Facility is non-recourse to Range and provides for

10

a borrowing base subject to semi-annual redeterminations in April and October. On October 31, 2001, the borrowing base was $200.0 million of which $45.0 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 Great Lakes Facility is LIBOR plus 1.50% to 2.00%, depending on outstandings. A commitment fee is paid quarterly on the undrawn balance at an annual rate of 0.25% to 0.50%. At September 30, 2001, the commitment fee was 0.50% and the interest rate margin was 1.88%. The average interest rate on the Great Lakes Facility, excluding interest rate hedges, was 8.6% and 5.9% for the three months ended September 30, 2000 and 2001, and 8.5% and 6.9% for the nine months then ended, respectively. After hedging (see Note 7), the rate was 8.7% and 7.4% for the quarters and 8.5% and 7.8% for the nine months ended September 30, 2000 and 2001, respectively. At October 31, 2001, the interest rate was 4.4%.

     IPF has a $100.0 million secured revolving credit facility (the “IPF Facility”). The IPF Facility is non-recourse to Range and matures in January 2004. The borrowing base under the IPF Facility is subject to semi-annual redeterminations in April and October. On October 31, 2001, the borrowing base was $35 million of which $10.5 million was available. The IPF Facility bears interest at LIBOR plus 1.75% to 2.25% depending on outstandings. Interest expense on the Facility is included in IPF expenses in the statements of income and amounted to $776,000 and $388,000 for the three months, and $2.7 million and $1.5 million for the nine months ended September 30, 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 the IPF Facility was 8.8% and 5.8% for the three months, and 8.4% and 6.9% for the nine months ended September 30, 2000 and 2001, respectively. As of October 31, 2001, the interest rate was 5.0%.

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 104.375% of principal, declining 1.46% each January 15 to par in 2005. The Notes are unsecured general obligations subordinated to all senior debt (as defined). Interest is payable semi-annually in January and July. During the three months and nine months ended September 30, 2001, respectively, the Company repurchased $10.0 million and $35.0 million, face amount of the 8.75% Notes at a discount. The cash flow statement reflects a $35.3 million Repayment of debt relating to these repurchases. The gain on these repurchases is included as a Gain on retirement of securities on the Income statement. The repurchased notes are held in treasury and may be reissued. Subsequent to September 30, 2001, the Company repurchased an additional $7.5 million face amount of the 8.75% Notes and exchanged $1.0 million of the Notes for common stock. As of October 31, 2001, $81.5 million of the 8.75% Notes remained outstanding.

     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. Interest is payable semi-annually in February and August. The 6% Debentures mature in 2007 and are redeemable at 103.5% of principal, declining 0.5% each February through 2007. The 6% Debentures are unsecured general obligations subordinated to all senior indebtedness (as defined), including the 8.75% Notes. During the quarters ended September 30, 2000 and 2001, $9.2 million and $1.5 million of 6% Debentures were retired at a discount in exchange for 1.7 million and 225,711 shares of common stock, respectively. During the nine months ended September 30, 2000 and 2001, $10.7 million and $5.7 million of 6% Debentures were retired at a discount in exchange for 2.1 million and 758,597 shares of common stock, respectively. Exchanges are not reflected on the cash flow statement. Extraordinary gains, net of taxes, of $2.9 million and $214,000 were recorded in the 2000 and 2001 quarters, and $3.6 million and $862,000 for the nine months ended September 30, 2000 and 2001, respectively. As of October 31, 2001, $31.8 million of the 6% Debentures remained outstanding.

Trust preferred

     In 1997, a special purpose affiliate (the “Trust”) issued $120 million of 53/4% Trust Convertible Preferred Securities (the “Trust Preferred”), represented by 2,400,000 Trust Preferred shares priced at $50. The Trust Preferred is convertible into common stock at a price of $23.50 a share. The Trust invested the proceeds in 53/4% convertible junior subordinated debentures issued by the Company (the “Junior Debentures”), its sole asset. The Junior Debentures and the Trust Preferred mature in 2027. The Junior Debentures and the Trust Preferred are redeemable in whole or in part at 104.025% of principal, declining 0.58% each November to par in 2007.

     The Company guarantees payment on the Trust Preferred to the extent the Trust has funds available. Such guarantee, taken together with other obligations, provides a full subordinated guarantee of the Trust Preferred. The Company has the right, at its sole discretion, to suspend payment of all distributions on the Trust Preferred for five years without triggering a default. The accounts of the Trust are included in Range’s consolidated financial statements after eliminations. Distributions are recorded as interest expense, are deductible for tax purposes and are

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subject to limitations in the Parent Facility. In the quarter ended September 30, 2000, $2.9 million of Trust Preferred was reacquired at a discount in exchange for 291,150 shares of common stock. No such exchanges were accomplished in the quarter ended September 30, 2001. During the nine months ended September 30, 2000 and 2001, $20.3 million and $2.4 million of Trust Preferred was reacquired at a discount in exchange for 2.7 million and 230,708 shares of common stock, respectively. An extraordinary gain, net of tax, of $1.4 million was recorded for the third quarter of 2000, and $11.2 million and $619,000 for the nine months ended September 30, 2000 and 2001, respectively. The exchange transactions are not reflected on the cash flow statement because no cash was involved. Subsequent to September 30, 2001, the Company repurchased at a discount an additional $500,000 face amount of the Trust Preferred for cash. As of October 31, 2001, $89.8 million face amount of the Trust Preferred was outstanding.

     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 September 30, 2001. Under the most restrictive covenant, $4.9 million of dividends or other restricted payments could be paid at September 30, 2001. Under the Parent Facility common dividends are prohibited and dividends may not be paid on the Trust Preferred unless certain ratio requirements are met.

(7) FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES

     The Company’s financial instruments include cash and equivalents, accounts receivable, accounts payable, debt obligations and commodity and interest rate hedges. The book value of cash and equivalents and accounts receivable and payable are considered to be representative of fair value because of their short maturity. The book values of borrowings under the Parent Facility, the Great Lakes Facility, and the IPF Facility are believed to 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 swap or option contracts. Realized gains and losses on these instruments are reflected in the contract month being hedged as an adjustment to oil and gas revenue. At times, the Company seeks to manage interest rate risk on its credit facilities through the use of swaps. Gains and losses on these 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 financial instruments (in thousands):

			December 31, 2000						September 30, 2001
			Book			Fair			Book			Fair
			Value			Value			Value			Value
Assets
	Cash and equivalents		$	2,485		$	2,485		$	4,801		$	4,801
	Marketable securities			2,028			2,028			1,536			1,536
	Commodity swaps			—			—			55,688			55,688
		Total		4,513			4,513			62,025			62,025
Liabilities
	Commodity swaps			—			(72,090	)		—			—
	Interest rate swaps			—			(879	)		(2,883	)		(2,883	)
	Long-term debt			(365,459	)		(348,257	)		(319,340	)		(305,080	)
	Trust Preferred			(92,640	)		(53,268	)		(90,290	)		(45,145	)
		Total		(458,099	)		(474,494	)		(412,513	)		(353,108	)
		Net financial instruments	$	(453,586	)	$	(469,981	)	$	(350,488	)	$	(291,083	)

     At September 30, 2001, the Company had hedging contracts covering 42.2 Bcf of gas at prices averaging $4.12 per Mmbtu and 1.2 million barrels of oil averaging $25.93 per barrel. Their fair value, represented by the estimated amount that would be realized upon termination, approximated a net unrealized gain of $55.7 million. The contracts expire monthly through December 2003. Gains or losses on open and closed hedging transactions are determined as the difference between the contract price and the reference price, generally closing prices on the New York Mercantile Exchange (“NYMEX”). Transaction gains and losses are determined monthly and are included as increases or decreases to oil and gas revenues in the period the hedged production is sold. Oil and gas revenues were decreased by $17.7 million relating to these derivatives for the quarter ended September 30, 2000. An $8.5 million increase in oil and gas revenues occurred in the quarter ended September 30, 2001 due to these derivatives. Oil and

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gas revenues were decreased for the nine months ended September 30, 2000 and 2001 totaling $29.2 million and $20.2 million for the nine months then ended, respectively for these derivatives.

     The following schedule shows the effect of close oil and gas hedges for the five quarters ended September 30, 2001 and the projected impact of open contracts as of that date based on the futures prices.

			Hedging Gains
			(Losses) and
Quarter Ended			Exposure
Closed contracts:
	March 31, 2000		$	(1,562	)
	June 30, 2000			(9,960	)
	September 30, 2000			(17,668	)
	December 31, 2000			(13,996	)
	March 31, 2001			(23,440	)
	June 30, 2001			(5,250	)
	September 30, 2001			8,450
		Total	$	(63,426	)
Open Contracts:
	December 31, 2001			14,084
	March 31, 2002			9,783
	September 30, 2002			7,923
	September 30, 2002			7,261
	December 31, 2002			6,747
	March 31, 2003			2,730
	September 30, 2003			2,464
	September 30, 2003			2,447
	December 31, 2003			2,249
		Total	$	55,688

     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. Neither the parent company nor IPF had interest rate swaps in effect. At September 30, 2001, Great Lakes had nine interest rate swap agreements totaling $100.0 million. Two agreements totaling $45.0 million at LIBOR rates of 7.1% expire in May 2004. Two agreements totaling $20.0 million at 6.2% expire in December 2002. Five agreements totaling $35.0 million at rates of 4.8%, 4.7%, 4.6%, 4.5% and 4.5% expire in June of 2003. The fair value of the swaps at September 30, 2001 was a net loss of $2.9 million based on then current quotes. 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 value of this option is marked to market each quarter. For the quarter and nine months ended September 30, 2001, the related losses were insignificant.

     The combined fair value of oil and gas hedging contracts and interest rate swaps, totaling $52.8 million, appear as an Unrealized hedging gain on the balance sheet. Hedging activities are conducted with major financial or commodities trading institutions which management believes are acceptable credit risks. At times, such risks may be concentrated with certain counterparties. The creditworthiness of these counterparties is subject to continuing review.

(8) COMMITMENTS AND CONTINGENCIES

     The Company is involved in various legal actions and claims arising in the ordinary course of business. In the opinion of management, such litigation and claims are likely to be resolved without material adverse effect on the Company’s financial position or results of operations. In 1998, a Domain stockholder filed an action alleging that the terms of the Company’s merger into Range were unfair. The suit was dismissed without prejudice in March 2001.

     In 2000, a royalty owner filed suit asking for class action certification against Great Lakes and the Company in New York, alleging that gas was sold to affiliates and gas marketers at low prices, inappropriate post production expenses reduced proceeds to the royalty owners, and that royalty owners’ share of gas was improperly accounted for.

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     The action sought proper accounting, an amount equal to the difference in prices paid and the highest obtainable prices, punitive damages and attorneys’ fees. This action is in an early stage of development.

(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 price of $9.50. The $2.03 Preferred is currently redeemable at a price of $25.75 a share, and is exchangeable at the Company’s option 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 and nine months ended September 30, 2001, $120,000 and $5.4 million of the $2.03 Preferred was exchanged for 17,959 and 766,889 shares of common stock. Only 2,935 shares remained outstanding at September 30, 2001, having a liquidation preference of $73,375. Gains on exchanges of $2.03 Preferred are not included in net income but they are included in income available to common shareholders. Exchange transactions are not reflected on the cash flow statement because no cash was involved.

     The following is a schedule of changes in outstanding common shares:

						Nine
			Year Ended			Months Ended
			December 31, 2000			September 30, 2001
Beginning Balance				37,901,789			49,187,682
Issuances:
	Compensation			289,714			238,817
	Stock options exercised			241,637			223,594
	Exchanges for 6% Debentures			2,496,789			758,597
		Trust Preferred		3,231,548			230,708
		$2.03 Preferred		4,583,993			766,889
	Stock Purchase Plan			343,422			238,000
	In lieu of dividends			106,597			—
	Other			(7,807	)		(56	)
				11,285,893			2,456,549
Ending Balance				49,187,682			51,644,231

Supplemental disclosures of non-cash investing and financing activities

		Nine Months Ended
		September 30,
		2000		2001
		(In thousands)
Common stock issued
	Under benefit plans	$	329	$	1,197
	In exchange for fixed income securities	$	22,379	$	10,652

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(10) STOCK OPTION AND PURCHASE PLANS

     The Company has four stock option plans, of which two are active, and a stock purchase plan. Under these plans, incentive and non-qualified options and stock purchase rights are issued to directors, officers, and employees pursuant to decisions of the Compensation Committee of the Board. Information with respect to the stock option plans is summarized below:

		Inactive						Active
		Domain			1989			Directors'			1999
		Plan			Plan			Plan			Plan			Total
Outstanding at December 31, 2000			248,965			1,182,893			136,000			665,200			2,233,058
	Granted		—			—			56,000			734,350			790,350
	Exercised		(111,481	)		(59,113	)		—			(53,000	)		(223,594	)
	Expired/canceled		—			(580,643	)		(24,000	)		(70,500	)		(675,143	)
			(111,481	)		(639,756	)		32,000			610,850			(108,387	)
Outstanding at September 30, 2001			137,484			543,137			168,000			1,276,050			2,124,671

     Two years ago, shareholders approved the 1999 Stock Option Plan (the “1999 Plan”) providing for the issuance of options on 1.4 million common shares. In May 2001, shareholders approved an increase in the number of options issuable to 3.4 million shares. All options issued under the 1999 Plan vest 25% per year beginning a year after grant and expire in 10 years. During the nine months ended September 30, 2001, 734,350 options were granted under the 1999 Plan at exercise prices of $6.40 to $6.67 a share. At September 30, 2001, 1.3 million options were outstanding under the 1999 Plan at exercise prices of $1.94 to $6.67.

     In 1994, shareholders approved the Outside Directors’ Stock Option Plan (the “Directors’ Plan”). In 2000, Shareholders approved an increase in the number of options issuable under the Directors’ Plan to 300,000, extended the term of the options to ten years and set the vesting period at 25% per year beginning a year after grant. During the nine months ended September 30, 2001, 56,000 options were granted under the Director’s Plan at exercise prices of $5.52 to $6.00 a share. At September 30, 2001, 168,000 options were outstanding under the Directors’ Plan at exercise prices of $2.81 to $16.88.

     The Company also maintains the 1989 Stock Option Plan (the “1989 Plan”) which authorized the issuance of options on 3.0 million common shares. No options have been granted under this plan since the 1999 Plan was adopted. Options issued under the 1989 Plan vest 30% after one year, 60% after two years and 100% after three years and expire in 5 years. At September 30, 2001, 543,137 options remained outstanding under the 1989 Plan at exercise prices of $2.63 to $17.75 a share.

     The Domain stock option plan was adopted when that Company was acquired with existing Domain options becoming exercisable into Range common stock. Since that time, no further options have been granted under the Plan. At September 30, 2001, 137,484 options remained outstanding under the Plan at a price of $3.46 a share.

     In total, 2.1 million options were outstanding at September 30, 2001 at exercise prices of $1.94 to $17.75 a share as follows:

				Inactive				Active
Range of		Average		Domain		1989		Directors'		1999
Exercise Prices		Exercise Price		Plan		Plan		Plan		Plan		Total
$  0.01 - $  4.99		$	2.52		137,484		378,787		64,000		524,200		1,104,471
5.00 -     9.99			6.69		—		163,850		56,000		751,850		971,700
10.00 -   14.99			11.25		—		—		24,000		—		24,000
15.00 -   18.00			16.89		—		500		24,000		—		24,500
	Total				137,484		543,137		168,000		1,276,050		2,124,671

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     In 1997, shareholders approved a Stock Purchase Plan (the “Stock Purchase Plan”) authorizing the sale of 900,000 shares of common stock to officers, directors, key employees and consultants. Under the Stock Purchase Plan, the right to purchase shares at prices ranging from 50% to 85% of market value may be granted. To date, purchase rights have been granted at 75% of market. In May 2001, shareholders approved an increase in the number of shares authorized under the Plan to 1,750,000. Through September 30, 2001, 1,096,319 shares have been sold under the Plan for $4.6 million. At September 30, 2001, rights to purchase 228,000 shares were outstanding.

(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 late 2000, the Company contributed $483,000 of common stock to the Plan.

(12) INCOME TAXES

     The Company follows SFAS No. 109, “Accounting for Income Taxes,” pursuant to which the liability method is used. Under this method, deferred tax assets and liabilities are determined based on differences between financial reporting and tax bases of assets and liabilities and each 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 following were the estimated tax benefits giving rise to deferred tax assets and liabilities (in thousands):

Deferred tax assets
	Net operating loss carryover		$	66,870
	Percentage depletion carryover			4,895
	AMT credits and other			660
		Total deferred tax assets		72,425
Deferred tax liabilities
	Depreciation			(62,249	)
	Net deferred tax asset		$	10,176
	Valuation allowance		$	(10,176	)

     A valuation allowance on the net deferred tax asset was established due to the uncertainty of whether future taxable income would be sufficient to utilize the net deferred tax asset. Increased oil and gas prices in early 2001 allowed the reversal of the valuation allowance during the first half of 2001. Therefore, income taxes will be recorded at a statutory rate for financial reporting. However, use of the Company’s tax loss carryover, percentage depletion carryover and AMT credits, will cause such statutory taxes to be deferred for the foreseeable future.

     At December 31, 2000, the Company had regular net operating loss (NOL) carryovers of $191 million including alternative minimum tax (“AMT”) NOL carryovers of $171 million that expire between 2001 and 2020. AMT NOL’s generally offset taxable income and to such extent, no income tax payments are required. Regular NOL’s utilized in amounts in excess of AMT NOL’s generate an alternative minimum tax payment, which can be offset by AMT credits. NOL’s generated prior to a change of control are subject to limitations. The Company experienced several change of control events between 1994 and 1998 due to acquisitions. Consequently the use of $34.6 million of NOL’s is limited to $10.6 million per year. Remaining NOL’s are not limited. At December 31, 2000, the Company had a statutory depletion carryover of $4.9 million and an AMT credit carryovers of $660,000 which are not subject to limitation or expiration.

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     The following table sets forth the year of expiration of NOL (pretax) carryovers which generate the largest component of the deferred tax assets listed above:

		NOL Carryover Amount
Expiration		Regular		AMT
		(in thousands)
	2001	$	1,180	$	1,180
	2002		558		480
	2003		488		422
	2004		666		136
	2005		522		353
Thereafter			187,644		168,902
	Total	$	191,058	$	171,473

(13) EARNINGS PER 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 September 30,						Nine Months Ended September 30,
			2000			2001			2000			2001
Numerator:
		Income before extraordinary item	$	3,495		$	6,370		$	5,996		$	38,295
		Gain on retirement of $2.03 Preferred		1,020			24			3,344			556
		Preferred dividends		(449	)		(1	)		(1,434	)		(9	)
		Numerator for earnings per share, before extraordinary item		4,066			6,393			7,906			38,842
		Extraordinary item Gain on retirement of securities, net		4,261			319			14,776			1,646
		Numerator for earnings per share, basic and diluted	$	8,327		$	6,712		$	22,682		$	40,488
Denominator:
	Weighted average shares, basic			44,336			51,507			41,459			50,875
		Dilutive potential common shares Stock options		198			184			128			214
		Denominator for diluted earnings per share		44,534			51,691			41,587			51,089
Earnings per share, basic and diluted:
		Before extraordinary item	$	0.09		$	0.12		$	0.19		$	0.76
		After extraordinary item	$	0.19		$	0.13		$	0.55		$	0.79

     During the three months ended September 30, 2000 and 2001, 198,000 and 184,000 stock options were included in the computation of diluted earnings per share and for the nine months then ended, 128,000 and 214,000 stock options were included in such computation. 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 fixed income securities. Existing common stockholders may be materially diluted if substantial exchanges are consummated. The extent of dilution will depend on the number of shares and price at which common stock is issued, the price at which newly issued securities are convertible into common stock, and the price at which fixed income securities are reacquired.

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(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. Virtually all gas production is sold under market sensitive contracts. Oil purchasers may be changed on 30 days notice. The price for oil is generally equal to a posted price set by major purchasers in the area. The Company sells to oil purchasers on the basis of price and service. For the nine months ended September 30, 2001, four customers accounted for 10% or more of oil and gas revenues. Management believes that the loss of any one customer would not have a material adverse effect.

     From the inception of the Great Lakes joint venture through June 30, 2001, Great Lakes sold approximately 90% of its gas production to FirstEnergy at prices based on the close of NYMEX contracts each month plus a basis differential. Effective July 1, 2001, Great Lakes began selling its gas to several different companies including FirstEnergy. Over the next twelve months, Great Lakes expects to sell roughly 37% of its gas to FirstEnergy, with the remaining 63% being sold to eight companies. Currently 91% of Great Lakes gas is sold at prices based on the close of NYMEX contracts each month plus a basis differential. The remainder is sold at a fixed price.

(15) OIL AND GAS ACTIVITIES

     The following summarizes selected information with respect to producing activities:

						Nine
			Year Ended			Months Ended
			December 31,			September 30,
			2000			2001
Oil and gas properties
	Subject to depletion		$	965,416		$	1,043,845
	Unproved			49,523			32,892
		Total		1,014,939			1,076,737
	Accumulated depletion			(443,097	)		(495,651	)
		Net	$	571,842		$	581,086
Costs incurred
	Acquisition		$	4,701		$	7,603	(a)
	Development			46,032			55,087
	Exploration			4,498			3,684
		Total	$	55,231		$	66,374

(a)  Includes $2.7 million for oil and gas reserves, the remainder represents acreage purchases.

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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 interest in Great Lakes consolidated in the Company’s financial statements:

	As of or for the
	Nine month period ended
	September 30, 2001
	(In thousands)
Current assets	$	17,782
Oil and gas properties		154,298
Transportation and field assets		17,061
Other assets		125
Current liabilities		7,991
Long-term debt		81,001
Deferred taxes		1,833
Members’ equity		99,743
Revenues		37,661
Net income		8,959

(17) EXTRAORDINARY ITEM

     During the nine months ended September 30, 2001, 989,305 shares of common stock were exchanged for $5.7 million of 6% Debentures and $2.4 million of Trust Preferred. An extraordinary gain of $1.6 million, net of $886,000 of deferred taxes, was recorded because these securities were reacquired at a discount. In addition, 766,889 shares of common stock were exchanged for $5.4 million of $2.03 Preferred.

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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 nine months ended September 30, 2001, the Company spent $66.4 million on development, exploration and acquisitions. Debt, Trust Preferred and $2.03 Preferred were reduced by a total of $53.9 million. At September 30, 2001, the Company had $4.8 million in cash, total assets of $739.6 million and, including the Trust Preferred as debt, a debt to capitalization (including debt, deferred taxes and stockholders’ equity) ratio of 59%. Available borrowing capacity on the Company’s bank lines at September 30, 2001 was $20.0 million at the parent, a net $19.0 million at Great Lakes and $7.8 million at IPF. Long-term debt at September 30, 2001 totaled $409.6 million. This included $95.0 million of parent bank borrowings, a net $81.0 million at Great Lakes, $21.5 million at IPF, $90.0 million of 8.75% Notes, $31.8 million of 6% Debentures and $90.3 million of Trust Preferred.

     During the nine months ended September 30, 2001, 989,305 shares of common stock were exchanged for $5.7 million of 6% Debentures and $2.4 million of Trust Preferred. A $1.6 million extraordinary gain, after $886,000 deferred taxes, was recorded as the Debentures and Trust Preferred were acquired at a discount. In addition, 766,889 common shares were exchanged for $5.4 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 assurance that internal cash flow and other capital sources will provide sufficient funds to maintain planned capital expenditures.

Cash Flow

     The Company’s principal sources of cash are operating cash flow and bank borrowings. The Company’s cash flow is highly dependent on oil and gas prices. The Company has entered into hedging agreements covering approximately 70%, 50%, and 20% of its anticipated production on an mcfe basis from proved reserves for the remainder of 2001, 2002, and 2003, respectively. The $62.3 million of capital expenditures in the nine months ended September 30, 2001 were funded entirely with internal cash flow. Net cash provided by operations for the nine months ended September 30, 2000 and 2001 was $46.8 million and $94.0 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 (provided by) investing for the nine months ended September 30, 2000 and 2001 was $(4.4) million and $53.5 million, respectively. The 2000 period included $34.7 million of additions to oil and gas properties and $4.6 million of IPF investments, more than offset by $18.5 million of IPF receipts and $25.1 million in asset sales. The 2001 period included $62.3 million of additions to oil and gas properties and $10.0 million of IPF investments, partially offset by $16.9 million of IPF receipts and $1.9 million in asset sales. Net cash used in financing for the nine months ended September 30, 2000 and 2001 was $62.6 million and $38.3 million, respectively. During the first nine months of 2001, recourse debt decreased by $10.5 million, total debt decreased by $48.5 million and the $2.03 convertible preferred stock decreased by $5.4 million for a total decline of $53.9 million in fixed income securities. The reduction in debt was the result of applying excess cash flow, proceeds from asset sales combined with exchanges of common stock.

Capital Requirements

     During the nine months ended September 30, 2001, $62.3 million of capital expenditures was spent primarily on development projects, representing 66% of internal cash flow. The Company manages its capital budget with the goal of funding it entirely 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 at or below internal cash flow.

Banking

     The Company maintains three separate revolving credit facilities: a $225.0 million facility at the parent company; a $100.0 million facility at IPF and a $275.0 million facility at Great Lakes. Each facility is secured by substantially all of the assets of the borrower. The IPF and Great Lakes facilities are non-recourse to Range. As Great Lakes is 50% owned, half of the borrowings on its facility are consolidated in Range’s financial statements.

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     Availability under the facilities is subject to borrowing bases set by the banks semi-annually and in certain other circumstances. The borrowing bases are dependent on a number of factors, primarily the lenders’ assessment of the future cash flows. Redeterminations require approval of 75% of the lenders, increases require unanimous approval.

     At October 31, 2001, there was availability under each of the Company’s facilities. At the parent, a $120.0 million borrowing base was in effect of which $23.9 million was available. At IPF, a $35.0 million borrowing base was in effect, of which $10.5 million was available. At Great Lakes, half of which is consolidated at Range, a $200.0 million borrowing base was in effect, of which $45.0 million was available.

Hedging

Oil and Gas Prices

     The Company regularly enters into hedging agreements to reduce the impact of fluctuations in oil and gas prices. The Company’s current policy is to hedge between 50% and 75% of projected production from existing proved reserves on a rolling 12 to 18 month basis. At September 30, 2001, hedges were in place covering 42.2 Bcf of gas at prices averaging $4.12 per Mmbtu and 1.2 million barrels of oil at prices averaging $25.93 per barrel. Their fair value at September 30, 2001, the estimated amount that is calculated based on then current prices, was a net unrealized gain of $55.7 million. The contracts expire monthly through December 2003 and cover approximately 70% of anticipated fourth quarter 2001 production, 50% of 2002 production, and 20% of 2003 production. Gains or losses on both realized and unrealized hedging transactions are determined as the difference between contract price and a reference price, generally NYMEX. Hedging gains and losses that are closed and settled monthly are included in oil and gas revenues in the period the associated production is sold. Net decreases to oil and gas revenues from hedging for the nine months ended September 30, 2000 and 2001 were $29.2 and $20.2 million, respectively.

Interest Rates

     At September 30, 2001, Range had $409.6 million of debt (including Trust Preferred) outstanding. Of this amount, $212.1 million bore interest at fixed rates averaging 7.1%. Bank debt totaling $197.5 million bore interest at floating rates which averaged 5.3% at that date. At times, the Company enters into hedges to limit the impact of interest rate fluctuations on its floating rate debt. At September 30, 2001, Great Lakes had interest rate swap agreements totaling $100.0 million. Two agreements totaling $45.0 million at rates of 7.1% expire in May 2004, two agreements of $20.0 million each at 6.2% expire in December 2002, and five agreements totaling $35.0 million at rates of 4.8%, 4.7%, 4.6%, 4.5% and 4.5% expire in June 2003. The fair value of the swaps, based on then current quotes for equivalent agreements at September 30, 2001, was a net loss of $2.9 million. The 30-day LIBOR rate on September 30, 2001 was 2.6%. A 1% increase or decrease in short-term interest rates on the floating-rate debt outstanding (excluding amounts fixed through hedging transactions) at September 30, 2001 would cost or save the Company approximately $1.5 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 values of these options are marked to market quarterly. In the three months and nine months ended September 30, 2001, such losses were insignificant.

Capital Restructuring Program

     As more fully described in Note 1, the Company took a number of steps beginning in late 1998 to strengthen its financial position. These steps included the sale of assets and the exchange of common stock for fixed income securities. These initiatives have helped reduce parent company bank debt to $95.0 million and total debt (including Trust Preferred) to $409.6 million at September 30, 2001. While the Company believes its financial position has stabilized, debt remains too high. To return to its historical posture of consistent profitability and growth, the Company believes it should further reduce debt. The Company currently believes it has sufficient cash flow and liquidity to meet its obligations for at least the next twelve months. However, a significant drop in oil and gas prices or a reduction in production or reserves would reduce the Company’s ability to fund capital expenditures and meet its financial obligations.

Inflation and Changes in Prices

     The Company’s revenues, the value of its assets, its ability to obtain bank loans or additional capital on attractive terms have been and will continue to be affected by changes in oil and gas prices. Oil and gas prices are subject to significant fluctuations that are beyond the Company’s ability to control or predict. During the first nine months of 2001, the Company received an average of $25.85 per barrel of oil and $3.82 per mcf of gas after hedging.

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     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, industry specific inflationary pressure has built up over the past 18 months due to favorable conditions in the industry. Should conditions remain favorable, inflationary pressures specific to the industry may continue.

Results of Operations

     The following table identifies certain unusual items included in net income, and presents net income excluding their effect. The table should be read in conjunction with the following discussions of results of operations.

		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2000			2001			2000			2001
		(In thousands)						(In thousands)
Net income as reported		$	7,756		$	6,689		$	20,772		$	39,941
Unusual items:
	Writedown of marketable securities		—			50			—			1,360
	Adjustment to IPF receivables and loss reserve		(1,007	)		473			(1,735	)		(1,847	)
	Effect of SFAS 133		—			321			—			(2,929	)
	Loss (gain) from sales of assets		(701	)		(103	)		1,208			(1,169	)
	Reversal of tax provision		—			—			(1,101	)		—
	Deferred tax on above items		—			(259	)		—			800
	Gain on retirement of securities		(4,261	)		(319	)		(14,776	)		(1,646	)
			(5,969	)		163			(16,404	)		(5,431	)
Net income on a recurring basis		$	1,787		$	6,852		$	4,368		$	34,510

Comparison of 2001 to 2000

     Quarters Ended September 30, 2000 and 2001

     Net income for the third quarter of 2001 totaled $6.7 million, compared to $7.8 million for the comparable period in 2000. The third quarter of the prior year included a $4.3 million gain on retirement of securities. Production rose to 153.1 Mmcfe per day, a 1% increase from the prior year period. Revenues benefited from a 21% increase in average prices per mcfe to $3.53. The average prices received for oil increased 2.6% to $25.27 per barrel and 32% for gas to $3.40 per mcf. Production expenses increased $699,000 to $10.2 million as a result of significantly higher production taxes and workover costs in the Gulf of Mexico. Operating cost per mcfe produced averaged $0.72 in 2001 versus $0.68 in 2000. This increase is primarily due to increased workover costs and costs related to new development wells.

     Transportation and processing revenues increased 13% to $915,000 with lower NGL prices and lower plant volumes more than offset by higher crude oil premiums. IPF’s revenues declined to $1.2 million, a 60% decrease from the 2000 period, after a $472,000 addition to the valuation allowance. During the quarter ended September 30, 2001, IPF expenses included $406,000 of administrative costs and $482,000 of interest, compared to prior year period administrative expenses of $307,000 and interest of $976,000.

     Exploration expense increased $381,000 to $1.2 million, primarily due to additional seismic activity. General and administrative expenses increased 16% to $3.1 million in the quarter, primarily due to higher employee costs and legal fees.

     Interest and other income decreased by $529,000 from a positive $348,000 to a loss of $181,000. The 2001 period included $321,000 of ineffective hedging losses and $103,000 of gains on asset sales. The 2000 period included

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$701,000 of gains on asset sales. Interest expense decreased 25% to $7.3 million as a result of the lower outstanding debt and falling interest rates. Total debt was $482.9 million and $409.6 million at September 30, 2000 and 2001, respectively. The average interest rates, were 7.9% and 6.2%, respectively, at September 30, 2000 and 2001 which includes both fixed and valuable rate debt.

     Depletion, depreciation and amortization (“DD&A”) increased 11% from the third quarter of 2000 as lower proved reserves caused the depletion rate to increase from $1.20 to $1.34 per mcfe. The Company currently expects its DD&A rate for the remainder of 2001 to approximate $1.34 per mcfe. The high DD&A rate will make it difficult for the Company to remain profitable if commodity prices fall.

     Nine Month periods ended September 30, 2000 and 2001

     Net income for the nine months ended September 30, 2001 totaled $39.9 million, compared to $20.8 million for the comparable period in 2000. The nine month period of the prior year included $14.8 million gain on retirement of securities. Production increased to 152.3 Mmcfe per day, a 1% increase from the prior year period. Revenues benefited from a 38% increase in average prices per mcfe to $3.91. The average prices received for oil increased 17% to $25.85 per barrel and for gas increased 48% to $3.82 per mcf. Production expenses increased $6.8 million to $34.5 million as a result of significantly higher production taxes and increased workover costs. Therefore, operating cost per mcfe produced averaged $0.83 in 2001 versus $0.67 in 2000.

     Transportation and processing revenues decreased 40% to $2.6 million as the benefit of higher NGL prices was more than offset by the impact the sale of a gas processing plant in June 2000. IPF’s $7.2 million of revenues declined 12% from that reported in the 2000 period. The 2001 period included $1.9 million of additional income as the balances on certain receivables were increased to reflect their full contractual rate of return. During the nine months ended September 30, 2001, IPF expenses included $1.3 million of administrative costs and $1.8 million of interest. During the comparable period of 2000, IPF expenses included $918,000 of administrative costs and $3.3 million of interest.

     Exploration expense increased 62% to $3.7 million, primarily due to seismic activity. General and administrative expenses increased 37% to $10.0 million due to additional personnel, occupancy cost and additional costs incurred by having duplicate administrative functions at Great Lakes and Range.

     Interest and other income increased from a loss of $895,000 to a gain of $3.1 million. The 2001 period included $2.9 million of ineffective hedging gains and $1.2 million of gains on asset sales, partially offset by a $1.4 million writedown of marketable securities. The 2000 period included $1.2 million of losses on asset sales. Interest expense decreased 19% to $24.4 million primarily as a result of the lower average outstandings and falling interest rates. Average outstandings on the Parent Facility were $132.0 million and $88.7 million for the nine months ended September 30, 2000 and 2001, respectively and the average interest rates were 8.7% and 7.0%, respectively.

     Depletion, depreciation and amortization increased 8% from the 2000 period as lower proved reserves caused the depletion rate to increase from $1.21 to $1.33 per mcfe.

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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 indicators of expected future losses, but rather indicators of risks. This forward-looking information provides indicators of how Range views and manages its ongoing market risk exposures. The Company’s market risk sensitive instruments were entered into for purposes other than trading.

     Commodity Price Risk. Range’s major market risk exposure is to oil and gas pricing. Realized pricing is primarily driven by worldwide prices for oil and spot market prices for U.S. gas production. Oil and gas prices have been volatile and unpredictable for many years. The Company periodically enters into hedging arrangements with respect to its oil and gas production. Pursuant to these swaps, Range receives a fixed price and pays market prices to the counterparty. This hedging is intended to reduce the impact of price fluctuations. Realized gains or losses are generally recognized in oil and gas revenues when the associated production occurs. Starting in 2001, gains or losses on open contracts are recorded either in current period income or Other comprehensive income. The gains or losses realized as a result of hedging are substantially offset in the cash market when the commodity is delivered.

     As of September 30, 2001, Range had oil and gas hedges in place covering 42.2 Bcf of gas and 1.2 million barrels of oil. Their fair value, represented by the estimated amount that would be realized on termination, was a net unrealized gain of $55.7 million at September 30, 2001. These contracts expire monthly through December 2003 and cover approximately 70%, 50% and 20% of anticipated production on an mcfe basis from existing proved reserves for the remainder of 2001, 2002 and 2003, respectively. Gains or losses on open and closed hedging transactions are determined as the difference between the contract price and the reference price, generally closing prices on the NYMEX. Transaction gains and losses are determined monthly and are included in oil and gas revenues in the period the hedged production is sold. Net realized losses incurred relating to these swaps for the nine months ended September 30, 2000 and 2001 were $29.2 million and $20.2 million, respectively.

     In the first nine months of 2001, a 10% reduction in oil and gas prices, excluding amounts fixed through hedging transactions, would have reduced revenue by $3.4 million. If oil and gas future prices at September 30, 2001 had declined by 10%, the unrealized hedging gain at that date would have been increased by $14.4 million.

     At September 30, 2001, Range had $409.6 million of debt (including Trust Preferred) outstanding. Of this amount, $212.1 million bears interest at fixed rates averaging 7.1%. Senior debt and non-recourse debt totaling $197.5 million bears interest at floating rates averaging 5.3% at that date. At September 30, 2001, Great Lakes had nine interest rate swap agreements totaling $100.0 million (See Note 7). The fair value of the swaps at September 30, 2001 was a net loss of $2.9 million based on then quotes for equivalent agreements. A 1% increase or decrease in short-term interest rates on the floating-rate debt outstanding (excluding amounts fixed through hedging transactions) at September 30, 2001 would cost or save the Company approximately $1.5 million in annual interest expense.

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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 suit alleging that the terms of the Merger were unfair. The suit was dismissed without prejudice in March 2001. In February 2000, a royalty owner filed suit asking for class certification against Great Lakes and the Company in New York, alleging that gas was sold to affiliates and gas marketers at low prices and inappropriate post production expenses reduced proceeds to the royalty owners and that the royalty owners’ share of gas was improperly accounted for. The action sought a proper accounting, an amount equal to the difference in prices paid and the highest obtainable prices, punitive damages and attorneys’ fees. While the outcome is uncertain, 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 and nine months ended September 30, 2001, Range issued common stock in exchange for fixed income securities. The shares of common stock issued in such exchanges were exempt from registration under Section 3(a)(9) of the Securities Act of 1933. During the quarter and nine months ended September 30, 2001, a total of $1.5 million and $5.7 million face value of the 6% Debentures were retired in exchange for 225,711 and 758,597 shares of common stock and a total of $120,000 and $5.4 million face value of $2.03 Preferred was retired in exchange for 17,959 and 766,889 shares of common stock, respectively. During the nine months ended September 30, 2001, $2.4 million face value of Trust Preferred were exchanged for 230,708 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 – None
		(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

November 6, 2001

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