UNITED STATES
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 quarterly period ended September 30, 2003

OR

[  ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from           to
	Commission file number 0-9592

RANGE RESOURCES CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	34-1312571
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

777 Main Street, Suite 800
Ft. Worth, Texas
(Address of principal executive offices)

76102
(Zip Code)

Registrant’s telephone number, including area code: (817) 870-2601

          Former name, former address and former fiscal year, if changed since last report: Not applicable

          Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the 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 [  ]

          Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes [X] No [  ]

56,210,770 Common Shares were outstanding on October 31, 2003.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
	Item 1. FINANCIAL STATEMENTS
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED STATEMENTS OF OPERATIONS
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
	Item 4. CONTROLS AND PROCEDURES
PART II. OTHER INFORMATION
	Item 1. Legal Proceedings
	Item 2. Changes in Securities and Use of Proceeds
	Item 6. Exhibits and Reports on Form 8-K
SIGNATURES
EXHIBIT INDEX
EX-3.1.5 Certificate of Correction to Certificate
EX-3.1.6 Certificate of Correction to Certificate
EX-3.2.1 Amended and Restated By-laws
EX-4.2 Certificate of Designation
EX-10.1.2 Fifth Amendment to Credit Agreement
EX-31.1 Certification of CEO - Section 302
EX-31.2 Certification of CFO - Section 302
EX-32.1 Certification of CEO - Section 906
EX-32.2 Certification of CFO - Section 906

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

     The financial statements included herein should be read in conjunction with the latest Form 10-K for Range Resources Corporation (the “Company”). The statements are unaudited but reflect all adjustments which, in the opinion of management, are necessary to fairly present the Company’s financial position and results of operations. All adjustments are of a normal recurring nature unless otherwise noted. These financial statements, including selected notes, have been prepared in accordance with the applicable rules of the Securities and Exchange Commission (the “SEC”) and do not include all of the information and disclosures required by accounting principles generally accepted in the United States for complete financial statements.

2

RANGE RESOURCES CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands)

		December 31,			September 30,
		2002			2003
					(Unaudited)
Assets
Current assets
	Cash and equivalents	$	1,334		$	1,635
	Accounts receivable, net		26,832			36,483
	IPF receivables, net (Note 2)		6,100			4,800
	Unrealized derivative gain (Note 2)		4			164
	Inventory and other		3,084			5,564
	Deferred tax asset, net (Note 13)		—			14,956
			37,354			63,602
IPF receivables, net (Note 2)			18,351			9,695
Unrealized derivative gain (Note 2)			13			310
Oil and gas properties, successful efforts method (Note 16)			1,154,549			1,260,068
	Accumulated depletion and depreciation		(590,143	)		(619,260	)
			564,406			640,808
Transportation and field assets (Note 2)			34,143			36,004
	Accumulated depreciation and amortization		(16,071	)		(18,223	)
			18,072			17,781
Deferred tax asset, net (Note 13)			15,785			—
Other (Note 2)			4,503			4,353
		$	658,484		$	736,549
Liabilities and Stockholders’ Equity
Current liabilities
	Accounts payable	$	27,044		$	30,465
	Asset retirement obligation (Note 3)		—			8,335
	Accrued liabilities		9,678			12,059
	Accrued interest		4,449			1,962
	Unrealized derivative loss (Note 2)		26,035			31,849
			67,206			84,670
Senior debt (Note 6)			115,800			94,300
Non-recourse debt (Note 6)			76,500			71,500
Subordinated notes (Note 6)			90,901			112,656
Trust preferred securities - manditorily redeemable security of subsidiary			84,840			1,411
Deferred taxes, net (Note 13)			—			12,918
Unrealized derivative loss (Note 2)			9,079			15,783
Deferred compensation liability (Note 11)			8,049			12,732
Asset retirement obligation (Note 3)			—			47,507
Commitments and contingencies (Note 8)
Stockholders’ equity (Notes 9 and 10)
	Preferred stock, $1 par, 10,000,000 shares authorized, 5.9% cumulative convertible preferred stock, 1,000,000 shares issued and outstanding at September 30, 2003, entitled in liquidation to $50.0 million		—			50,000
	Common stock, $.01 par, 100,000,000 shares authorized, 54,991,611 and 56,157,834 issued and outstanding, respectively		550			561
	Capital in excess of par value		391,082			397,425
	Stock held by employee benefit trust, 1,324,537 and 1,700,992 shares, respectively, at cost (Note 11)		(6,188	)		(8,543	)
	Retained earnings (deficit)		(158,059	)		(127,342	)
	Deferred compensation expense		(125	)		(132	)
	Other comprehensive income (loss) (Note 2)		(21,151	)		(28,897	)
			206,109			283,072
		$	658,484		$	736,549

See accompanying notes.

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RANGE RESOURCES CORPORATION

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

				Three Months						Nine Months
				Ended September 30,						Ended September 30,
				2002			2003			2002			2003
Revenues
	Oil and gas sales			$	48,112		$	55,723		$	141,021		$	165,326
	Transportation and processing				1,037			841			2,735			2,808
	IPF income (Note 2)				1,313			297			3,476			1,264
	Gain on retirement of securities (Note 18)				1,050			18,572			3,080			18,712
	Other				(125	)		723			(3,369	)		(262	)
					51,387			76,156			146,943			187,848
Expenses
	Direct operating				10,516			11,120			29,658			36,792
	IPF				808			578			4,758			1,764
	Exploration				1,814			3,633			9,257			8,773
	General and administrative (Note 11)				3,080			5,493			12,283			15,652
	Debt conversion expense (Note 6)				—			—			—			465
	Interest expense and dividends on trust preferred				5,845			7,705			17,476			18,424
	Depletion, depreciation and amortization				19,716			21,869			57,120			64,112
					41,779			50,398			130,552			145,982
Income before income taxes and accounting change					9,608			25,758			16,391			41,866
Income taxes (Note 13)
		Current			23			6			68			4
		Deferred			363			9,015			(4,550	)		15,571
					386			9,021			(4,482	)		15,575
Income before cumulative effect of change in accounting principle					9,222			16,737			20,873			26,291
	Cumulative effect of change in accounting principle (net of taxes of $2.4 million) (Note 3)				—			—			—			4,491
Net income					9,222			16,737			20,873			30,782
Preferred stock dividends (Note 9)					—			(65	)		—			(65	)
Net income available to common shareholders				$	9,222		$	16,672		$	20,873		$	30,717
Earnings Per Common Share (Note 14):
	Net income available to common shareholders			$	0.17		$	0.31		$	0.39		$	0.49
			Cumulative effect of change in accounting principle		—			—			—			0.08
	Net income per common share			$	0.17		$	0.31		$	0.39		$	0.57
	Earnings per common share – assuming dilution			$	0.17		$	0.29		$	0.38		$	0.47
			Cumulative effect of change in accounting principle		—			—			—			0.08
	Net income per common share – assuming dilution			$	0.17		$	0.29		$	0.38		$	0.55

See accompanying notes.

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RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited, in thousands)

					Nine Months Ended
					September 30,
					2002			2003
Cash flows from operations
	Net income				$	20,873		$	30,782
	Adjustments to reconcile net income to net cash provided by operations:
		Cumulative effect of change in accounting principle, net				—			(4,491	)
		Deferred income tax expense (benefit)				(4,550	)		15,571
		Depletion, depreciation and amortization				57,120			64,112
		Write-down of marketable securities				1,220			—
		Unrealized hedging (gains) losses				2,771			(62	)
		Allowance for bad debts				2,818			1,109
		Exploration expense				9,257			8,773
		Amortization of deferred issuance costs and discount				670			1,052
		Gain on retirement of securities				(3,107	)		(19,292	)
		Debt conversion and extinguishment expense				—			465
		Deferred compensation adjustments				1,677			2,593
		Loss (gain) on sale of assets				(292	)		118
		Changes in working capital:
			Accounts receivable			(1,009	)		(10,363	)
			Inventory and other			(1,366	)		(1,688	)
			Accounts payable			3,724			3,647
			Accrued liabilities			(1,416	)		1,180
				Net cash provided by operations		88,390			93,506
Cash flows from investing
	Oil and gas properties					(70,641	)		(75,528	)
	Field service assets					(1,822	)		(1,939	)
	IPF investments					(3,942	)		(1,545	)
	IPF repayments					9,729			10,926
	Exploration expense					(9,257	)		(8,773	)
	Asset sales					880			370
				Net cash used in investing		(75,053	)		(76,489	)
Cash flows from financing
	Borrowings on credit facilities					111,800			198,100
	Repayments on credit facilities					(116,900	)		(224,600	)
	Issuance of senior notes					—			98,272
	Debt issuance costs					(984	)		(1,850	)
	Other debt repayments					(10,802	)		(88,733	)
	Issuance of common stock					632			2,095
				Net cash used in financing		(16,254	)		(16,716	)
Increase (decrease) in cash and cash equivalents						(2,917	)		301
Cash and equivalents, beginning of period						3,380			1,334
Cash and equivalents, end of period					$	463		$	1,635

See accompanying notes.

5

RANGE RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

(1) ORGANIZATION AND NATURE OF BUSINESS

     The Company is engaged in the development, exploration and acquisition of oil and gas properties primarily in the Southwestern, Gulf Coast and Appalachian regions of the United States. The Company seeks to increase its reserves and production primarily through drilling and complementary acquisitions. The Company holds its Appalachian oil and gas assets through a 50% owned joint venture, Great Lakes Energy Partners L.L.C. (“Great Lakes”).

     The Company operates in an environment with numerous financial and operating risks, including, but not limited to, the inherent risks of the search for, development and production of oil and gas, the ability to sell production at prices which provide an attractive return, the highly competitive nature of the industry, and the ability to drill and acquire reserves on an attractive basis. The Company’s ability to expand its reserve base is, in part, dependent on obtaining sufficient capital through internal cash flow, borrowings or the issuance of debt or equity securities. A material drop in oil and gas prices or a reduction in production and reserves would reduce its ability to fund capital expenditures through internally generated cash flow.

(2)  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

     The accompanying consolidated financial statements include the accounts of the Company, wholly-owned subsidiaries and a 50% pro rata share of the assets, liabilities, income and expenses of Great Lakes. Liquid investments with original maturities of 90 days or less are considered cash equivalents. Certain reclassifications have been made to the presentation of prior periods to conform to current year presentation. These financial statements are unaudited but, in the opinion of management, reflect all adjustments necessary for a fair presentation of the results for the periods presented. All such adjustments are of a normal recurring nature unless disclosed otherwise.

Revenue Recognition

     The Company recognizes revenues from the sale of products and services in the period delivered. Payments received at Independent Producer Finance (“IPF”) relating to return on investment are recognized as income; while remaining receipts reduce receivables. Although receivables are concentrated in the oil 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 $835,000 and $896,000 at December 31, 2002 and September 30, 2003, respectively.

6

Marketable Securities

     Holdings of equity securities that qualify as available-for-sale are recorded at fair value. The Company owns approximately 18% of a small exploration and production company. Based on its analysis, the Company determined that the investment had no determinable value at June 30, 2002 and the book value of the investment was fully reserved. This exploration and production company is currently in Chapter 11 bankruptcy proceedings.

Independent Producer Finance

     Historically, IPF acquired royalties in oil and gas properties from small producers. The royalties are accounted for as receivables because the investment is recovered from a percentage of revenues until a specified return is received. Payments received that relate to the return on investment are recognized as income, while remaining receipts reduce receivables. Receivables classified as current represent the return expected within 12 months. All receivables are evaluated quarterly and provisions for uncollectible amounts are established based on a valuation of its royalty interest in the oil and gas properties. At December 31, 2002 and September 30, 2003, IPF’s valuation allowance totaled $12.6 million and $8.6 million, respectively. The receivables are non-recourse and are from small operators who have limited access to capital and the property interests backing the receivables frequently lack diversification. During the third quarter of 2003, IPF revenues were $297,000 offset by $222,000 of administrative costs, $30,000 of interest and a $326,000 increase in the valuation allowance. During the same period of the prior year, revenues were $1.3 million offset by $391,000 of general and administrative expenses, $241,000 of interest and a $176,000 increase in the valuation allowance. Since 2001, IPF has not entered into any new investment agreements and therefore, the portfolio has declined due to collections.

Oil and Gas Properties

     The Company follows the successful efforts method of accounting. Exploratory drilling costs are capitalized pending determination of whether a well is successful. Exploratory wells subsequently determined to be dry holes are charged to expense. Costs resulting in exploratory discoveries and all development costs, whether successful or not, are capitalized. Geological and geophysical costs, delay rentals and unsuccessful exploratory wells are expensed. Depletion is provided on the unit-of-production method. Oil is converted to gas equivalent basis (“mcfe”) at the rate of six mcf per barrel. The depletion, depreciation and amortization (“DD&A”) rates were $1.42 and $1.49 per mcfe in the quarters ended September 30, 2002 and 2003, respectively, and $1.39 and $1.49 for the nine months ended September 30, 2002 and 2003, respectively. Unproved properties had a net book value of $19.0 million and $15.5 million at December 31, 2002 and September 30, 2003, respectively.

     The Company’s long-lived assets are reviewed for impairment quarterly for events or changes in circumstances that indicate that the carrying amount of an asset may not be recoverable in accordance with SFAS No. 144. The review is done by determining if the historical cost of proved properties less the applicable accumulated DD&A is less than the estimated expected undiscounted future cash flows. The expected future cash flows are estimated based on management’s plans to continue to produce and develop proved reserves. Expected future cash flow from the sale of production of reserves is calculated based on estimated future prices. Management estimates prices based upon market related information including published futures prices. The estimated future level of production is based on assumptions surrounding future levels of prices and costs, field decline rates, market demand and supply, and the economic and regulatory climates. When the carrying value exceeds such cash flows, an impairment loss is recognized for the difference between the estimated fair value and the carrying value of the assets.

7

Transportation, Processing and Field Assets

     The Company’s gas gathering systems are generally located in proximity to certain of its principal fields. Depreciation on these systems is provided on the straight-line method based on estimated useful lives of 10 to 15 years. The Company receives third party income for providing certain field services which are recognized as earned. These revenues approximated $500,000 in each of the three month periods ended September 30, 2002 and 2003. Depreciation on the field assets is calculated on the straight-line method based on estimated useful lives of five to seven years. Buildings are depreciated over 10 to 15 years.

Other Assets

     The cost of issuing debt is 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 December 31, 2002 and September 30, 2003, these capitalized costs totaled $3.0 million and $2.3 million, respectively. At September 30, 2003, Other assets included $2.3 million unamortized debt issuance costs, $582,000 of long-term deposits, and $1.5 million of marketable securities held in a deferred compensation plan.

Gas Imbalances

     The Company uses the sales method to account for gas imbalances, recognizing revenue based on cash received rather than gas produced. A liability is recognized when the imbalance exceeds the estimate of remaining reserves. Gas imbalances at December 31, 2002 and September 30, 2003 were immaterial.

Derivative Financial Instruments and Hedging

     The Company enters into contracts to reduce the impact of volatile oil and gas prices. These contracts generally qualify as cash flow hedges; however, certain of the contracts have an ineffective portion (changes in realized prices that do not match the changes in hedge price) which is recognized in earnings. Historically, the Company’s hedging program was based on fixed price swaps. In the second quarter of 2003, the hedging program was modified to include collars which establish a minimum floor price and a predetermined ceiling price. Gains or losses on open contracts are recorded in Other comprehensive income (loss) (“OCI”). The Company also enters into swap agreements to reduce the risk of changing interest rates. These agreements qualify as cash flow hedges whereby changes in the fair value of the swaps are reflected as an adjustment to OCI to the extent the swaps are effective and are recognized in income as an adjustment to interest expense in the period covered for the ineffective portion. In prior periods, certain of the interest rate swaps, because of an option feature, did not qualify as interest rate hedges which required the changes in fair value to be reported in interest expense.

     Derivatives are recorded on the balance sheet as assets or liabilities at fair value. For derivatives qualifying as hedges, the effective portion of changes in fair value is recognized in Stockholders’ equity as OCI and reclassified to earnings when the transaction is closed (settled). Changes in the value of the ineffective portion of all open hedges are recognized in earnings as they occur. At September 30, 2003, the Company reflected an unrealized net pre-tax hedging loss on its balance sheet of $46.3 million. This accounting can greatly increase the volatility of earnings and stockholders’ equity for companies that have hedging programs, such as the Company’s hedging program. Earnings are affected by the ineffective portion of a hedge contract (changes in realized prices that do not match the changes in the hedge price). Ineffective gains or losses are recorded in Other revenue while the hedge contract is open and may increase or reverse until settlement of the contract. Stockholders’ equity is affected by the increase or decrease in OCI. Typically, when oil and gas prices increase, OCI decreases. Of the $46.3 million unrealized pre-tax loss at September 30, 2003, $30.8 million of losses would be reclassified to earnings over the next twelve month period and $15.5 million in later periods, if prices remained constant. Actual amounts that will be reclassified will vary as a result of future changes in prices.

     Other revenues in the Consolidated Statements of Operations reflected ineffective hedging losses of $419,000 and gains of $1.1 million for the three months ended September 30, 2002 and September 30, 2003, respectively, and losses of $2.6 million and $178,000 for the nine months ended September 30, 2002 and 2003, respectively. Interest expense includes ineffective interest hedging losses of $262,000 and gains of $157,000 for the three months ended September 30, 2002 and September 30, 2003, respectively, and losses of $190,000 and gains of

8

$240,000 for the nine months ended September 30, 2002 and 2003, respectively. Unrealized hedging losses at September 30, 2003 are shown on the Company’s balance sheet as net unrealized hedging losses of $47.2 million (including $880,000 of losses on interest rate swaps) and OCI losses of $28.9 million (net of taxes) (see Note 7).

Comprehensive Income

     Comprehensive income is defined as changes in Stockholders’ equity from non-owner sources, which is calculated below (in thousands):

		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2002			2003			2002			2003
Net income		$	9,222		$	16,737		$	20,873		$	30,782
	Net amount of hedging (gain) loss reclassified to earnings		(3,484	)		12,257			(18,849	)		53,512
	Change in unrealized losses, net		(9,220	)		10,496			(28,920	)		(61,123	)
	Defaulted hedge contracts, net		—			—			(672	)		—
	Unrealized loss (gain) from available-for-sale securities		397			(12	)		256			(135	)
Comprehensive income (loss)		$	(3,085	)	$	39,478		$	(27,312	)	$	23,036

Use of Estimates

     The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect reported assets, liabilities, revenues and expenses, as well as disclosure of contingent assets and liabilities. Actual results could differ from those estimates. Estimates which may significantly impact the financial statements include oil and gas reserves, impairment tests on oil and gas properties, IPF valuation allowance and the fair value of derivatives.

Recent Accounting Pronouncements

     In April 2002, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards No. 145 “Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement 13 and Technical Corrections” (“SFAS 145”). As a result, gains from early extinguishment of debt will be reported in income from continuing operations. The Company adopted the provisions of SFAS 145 as of January 1, 2003. This adoption resulted in the reclassification of extraordinary gain on sale of securities totaling $1.1 million to revenue in the three months and $3.1 million in the nine months ended September 30, 2002, with no change to reported net income.

     In January 2003, the FASB issued Interpretation No. 46 “Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51” (the “Interpretation”). The Interpretation will significantly change whether entities included in its scope are consolidated by their sponsors, transferors, or investors. The Interpretation introduces a new consolidation model – the variable interest model – which determines control (and consolidation) based on potential variability in gains and losses of the entity being evaluated for consolidation. These provisions apply immediately to variable interests in Variable Interest Entities (“VIEs”) created after January 15, 2003 and are effective beginning in the third quarter of 2003 for VIEs in which the Company holds a variable interest that it acquired prior to February 1, 2003. At the October 8, 2003, FASB meeting, the Board agreed to a broad-based deferral of the effective date of the Interpretation for public companies until after December 31, 2003. The Company is still evaluating the impact of this new interpretation.

     In May 2003, the FASB issued Statement of Financial Accounting Standards No. 150 “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity” (“SFAS 150”). SFAS 150 established standards for classification and measurement in the statement of financial position of certain financial instruments with characteristics of both liabilities and equity. It requires classification of a financial instrument that is within its scope as a liability (or an asset in some circumstances). SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after September 15, 2003. As the Company’s 5-3/4% Trust Convertible Preferred Securities (“Trust

9

Preferred Securities”) are currently presented as a long-term liability in the consolidated financial statements, the adoption of SFAS 150 is not expected to have a material impact on the Company’s consolidated financial statements.

     The FASB and representatives of the accounting staff of the SEC are engaged in discussions on the issue of whether the FASB’s No. 141 and 142, issued effective for June 30, 2001, called for mineral rights held under lease or other contractual arrangements to be classified in the balance sheet as intangible assets and accompanied by specific footnote disclosures. Historically, the Company and all other oil and gas companies have included the cost of these oil and gas leasehold interests as part of oil and gas properties. Although most of the Company’s oil and gas property interests are held under oil and gas leases, this interpretation, if adopted, is not expected to have a material impact on the Company’s financial condition or its results of operations.

     In the event this interpretation is adopted, a substantial portion of acquisition costs of oil and gas properties since June 30, 2001 would be separately classified on the balance sheets as intangible assets. As of September 30, 2003, the Company has expended approximately $25.2 million on the acquisition of oil and gas leasehold interests since June 30, 2001. Some additional direct costs of other oil and gas leases acquired since that date could also be categorized as intangible under this interpretation. Results of operations would not be affected by this interpretation, if adopted, since these costs would continue to be depleted in accordance with successful efforts accounting for oil and gas companies. Another possible effect of this interpretation, if adopted, could be a change in some of the financial measurements used in financial covenants of debt instruments that focus on tangible assets. The Company does not believe that its debt covenants would be materially affected by the adoption of this accounting interpretation.

Pro Forma Stock Based Compensation

     The Company has adopted the disclosure-only provisions of SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”). Accordingly, no compensation cost has been recognized for the stock option plans because the exercise prices of employee stock options equals the market prices of the underlying stock on the date of grant. If compensation cost had been determined based on the fair value at the grant date for awards in the three months and the nine months ended September 30, 2002 and 2003, consistent with the provisions of SFAS 123, the Company’s net income and earnings per share would have been reduced to the pro forma amounts indicated below (in thousands, except per share data):

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2002		2003		2002		2003
Net income, as reported -		$	9,222	$	16,737	$	20,873		30,782
Deduct: Pro forma stock based employee compensation, net of related tax effects			287		346		836		1,171
Pro forma net income		$	8,935	$	16,391	$	20,037	$	29,611
Earnings per share:
	Basic-as reported	$	0.17	$	0.31	$	0.39	$	0.57
	Basic-pro forma	$	0.17	$	0.30	$	0.38	$	0.55
	Diluted-as reported	$	0.17	$	0.29	$	0.38	$	0.55
	Diluted-pro forma	$	0.16	$	0.28	$	0.37	$	0.53

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(3)  ASSET RETIREMENT OBLIGATION

     Beginning in 2003, Statement of Financial Accounting Standards No. 143 “Asset Retirement Obligations” (“SFAS 143”) requires the Company to recognize an estimated liability for the plugging and abandonment of its oil and gas wells and associated pipelines and equipment. Previously, the Company had recognized a plugging and abandonment obligation primarily for its offshore properties. This liability was shown netted against oil and gas properties on the balance sheet. Under SFAS 143, the Company now recognizes a liability for asset retirement obligations in the period in which they are incurred, if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. SFAS 143 requires the Company to consider estimated salvage value in the calculation of DD&A. Consistent with industry practice, historically the Company had assumed the cost of plugging and abandonment on its onshore properties would be offset by salvage value received. The adoption of SFAS 143 resulted in (i) an increase of total liabilities because retirement obligations are required to be recognized, (ii) an increase in the recognized cost of assets because the retirement costs are added to the carrying amount of the long-lived asset, and (iii) an increase in DD&A expense, because of the accretion of the retirement obligation and increased basis. The majority of the asset retirement obligations recorded by the Company relate to the plugging and abandonment of oil and gas wells. The decline in the current portion of the asset retirement obligation in the current period is the result of a reassessment of the timing of certain oil and gas well abandonments.

     The estimated liability is based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells based on reserves estimates, external estimates as to the cost to plug and abandon the wells in the future, and federal and state regulatory requirements. The liability is discounted using an assumed credit-adjusted risk-free interest rate of 9%. Revisions to the liability could occur due to changes in estimates of plugging and abandonment costs, changes in the risk-free interest rate or remaining lives of the wells, or if federal or state regulators enact new plugging and abandonment requirements. At the time of abandonment, the Company may be required to recognize a gain or loss on abandonment based on actual costs incurred.

     The adoption of SFAS 143 as of January 1, 2003 resulted in a cumulative effect gain of $4.5 million (net of income taxes of $2.4 million) or $0.08 per share which is included in income in the nine months ended September 30, 2003. The adoption resulted in a January 1, 2003 cumulative effect adjustment to record (i) a $37.3 million increase in the carrying values of proved properties, (ii) a $21.0 million decrease in accumulated depletion, (iii) a $2.3 million increase in current plugging and abandonment liabilities, (iv) a $49.1 million increase in non-current plugging and abandonment liabilities, and (v) a $2.4 million decrease in deferred tax assets. The pro forma effects of the application of SFAS 143, as if the statement had been adopted net-of-tax on January 1, 2002 (rather than January 1, 2003), including an associated proforma asset retirement obligation on that date of $48.3 million, are presented below (in thousands, except per share data):

		Pro Forma				Pro Forma
		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2002		2003		2002		2003
Net income		$	9,016	$	16,737	$	24,731	$	30,782
Earnings per share - basic		$	0.17	$	0.31	$	0.47	$	0.57
	- diluted	$	0.16	$	0.29	$	0.45	$	0.55

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

Asset retirement obligation, December 31, 2002	$	—
Cumulative effect adjustment		51,390
Liabilities incurred		2,126
Liabilities settled		(1,120	)
Accretion expense		3,446
Asset retirement obligation, September 30, 2003	$	55,842

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(4) ACQUISITIONS

     Acquisitions are accounted for under the purchase method. Purchase prices are assigned to acquired assets and assumed liabilities based on their estimated fair value at acquisition. The Company purchased various properties for $9.5 million and $12.4 million during the nine months ended September 30, 2002 and 2003, respectively. These purchases include $4.4 million and $8.0 million for proved oil and gas reserves, respectively, while the remainder represents unproved acreage.

(5) SUPPLEMENTAL CASH FLOW INFORMATION

		Nine Months Ended
		September 30,
		2002		2003
		(in thousands)
Non-cash investing and financing activities:
Common stock issued
	Under benefit plans	$	1,545	$	2,694
	Exchanged for fixed income securities		8,359		1,370
Preferred stock issued		$	—	$	50,000
Cash used in operating activities:
Income taxes paid		$	68	$	4
Interest paid			19,622		19,621

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(6) INDEBTEDNESS

     The Company had the following debt and Trust Preferred Securities outstanding as of the dates shown below (in thousands) (interest rates at September 30, 2003, excluding the impact of interest rate swaps, are shown parenthetically):

			December 31,		September 30,
			2002		2003
Senior debt:
	Senior Credit Facility (2.9%)		$	115,800	$	94,300
Non-recourse debt:
	Great Lakes Credit Facility (2.9%)			76,500		71,500
Subordinated debt:
	8-3/4% Senior Subordinated Notes due 2007			69,281		—
	6% Convertible Subordinated Debentures due 2007			21,620		14,354
	7-3/8% Senior Subordinated Notes due 2013			—		100,000
	Discount on 7-3/8% Senior Subordinated Notes due 2013			—		(1,698	)
				90,901		112,656
		Total debt		283,201		278,456
Trust Preferred Securities– mandatorily redeemable securities of subsidiary				84,840		1,411
		Total	$	368,041	$	279,867

     Interest paid in cash during the three months ended September 30, 2002 and 2003 totaled $7.7 million and $7.0 million, respectively. Interest paid in cash during the nine months ended September 30, 2002 and 2003 totaled $19.6 million and $17.6 million, respectively. No interest expense was capitalized during the three months or the nine months ended September 30, 2002 and 2003.

Senior Credit Facility

     In 2002, the Company entered into an amended and restated $225.0 million secured revolving bank facility (the “Senior Credit Facility”) which is secured by substantially all of the assets of the Company (excluding the Company’s interest in Great Lakes). The Senior Credit Facility provides for a borrowing base subject to redeterminations semi-annually each April and October and pursuant to certain unscheduled redeterminations. As of September 30, 2003, the outstanding balance under the Senior Credit Facility was $94.3 million and there was approximately $75.7 million of borrowing capacity available. Effective October 1, 2003, the borrowing base was increased from $170.0 million to $180.0 million and there was approximately $83.6 million of borrowing capacity available. The loan matures on January 1, 2007. Borrowings under the Senior Credit Facility can either be base rate loans or LIBOR loans. On all base rate loans, the rate per annum is equal to the lesser of (i) the maximum rate (the “weekly ceiling” as defined in Section 303 of the Texas Finance Code or other applicable laws if greater) (the “Maximum Rate”) or, (ii) the sum of (A) the higher of (1) the prime rate for such date, or (2) the sum of the federal funds effective rate for such date plus one-half of one percent (0.50%) per annum, plus a base rate margin of between 0.25% to 1.0% per annum depending on the total outstanding under the Senior Credit Facility relative to the borrowing base under the Senior Credit Facility. On all LIBOR loans, the Company pays a varying rate per annum equal to the lesser of (i) the Maximum Rate, or (ii) the sum of the quotient of (A) the LIBOR base rate, divided by (B) one minus the reserve requirement applicable to such interest period, plus a LIBOR margin of between 1.50% and 2.25% per annum depending on the total outstanding under the Senior Credit Facility relative to the borrowing base under the Senior Credit Facility. The Company may elect, from time to time, to convert all or any part of its

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LIBOR loans to base rate loans or to convert all or any part of its base rate loans to LIBOR loans. The weighted average interest rate (including applicable margin) was 3.8% and 2.8% for the three months ended September 30, 2002 and 2003, respectively, and 4.0% and 3.2% for the nine months ended September 30, 2002 and 2003, respectively. A commitment fee is paid on the undrawn balance based on an annual rate of 0.375% to 0.50%. At September 30, 2003, the commitment fee was 0.375% and the interest rate margin was 1.75%. At October 31, 2003, the interest rate (including applicable margin) was 2.9%.

Great Lakes Credit Facility

     The Company consolidates its proportionate share of borrowings on the Great Lakes’ $275.0 million secured revolving bank facility (the “Great Lakes Credit Facility”). The Great Lakes Credit Facility is non-recourse to the Company and provides for a borrowing base subject to redeterminations semi-annually each April and October and pursuant to certain unscheduled redeterminations. As of September 30, 2003, the Company’s portion of the outstanding balance owed under the Great Lakes Credit Facility was $71.5 million. The loan matures on January 1, 2007. Any advance under the commitment may be a base rate loan or a Eurodollar loan. On all base rate loans the Company pays a varying rate per annum equal to the lesser of (i) the maximum nonusurious rate of interest under applicable law, or (ii) the sum of the base rate plus a base rate margin of between 0.25% to 0.75% per annum depending on the amounts outstanding on the loan, plus all outstanding letters of credit, divided by the borrowing base under the Great Lakes Credit Facility. On all Eurodollar loans, the Company pays a varying rate per annum equal to the lesser of (i) the maximum nonusurious rate of interest under applicable law, or (ii) the Eurodollar rate plus a Eurodollar margin of between 1.50% to 2.0% per annum depending on the amounts outstanding on the loan, plus all outstanding letters of credit, divided by the borrowing base under the Great Lakes Credit Facility. Great Lakes may elect, from time to time, to convert all or any part of its Eurodollar loans to base rate loans or to convert all or any part of its base rate loans to Eurodollar loans. Cash distributions to members of the joint venture are limited by a covenant contained in the Great Lakes Credit Facility. A commitment fee is paid on the undrawn balance at an annual rate of 0.25% to 0.50%. At September 30, 2003, the commitment fee was 0.375% and the interest rate margin was 1.75%. The average interest rate on the Great Lakes Credit Facility, excluding hedges, was 3.9% and 2.8% for the three months ended September 30, 2002 and 2003, respectively, and 3.9% and 3.1% for the nine months then ended, respectively. After hedging (see Note 7), the rate was 7.0% and 4.9% for the three months ended September 30, 2002 and 2003, respectively, and 7.0% and 5.4% for the nine months ended September 30, 2002 and 2003, respectively. At October 31, 2003, the interest rate was 2.9% excluding hedges and 5.1% after hedging.

8-3/4% Senior Subordinated Notes due 2007

     In 1997, the Company sold $125 million in aggregate principal amount of its 8-3/4% Senior Subordinated Notes due 2007 (the “8-3/4% Notes”). Interest on the 8-3/4% Notes was payable semi-annually in arrears in January and July of each year. On August 20, 2003, the Company completed the redemption of its outstanding 8-3/4% Notes at approximately 102.9% of principal amount, plus accrued interest. Interest on the notes ceased to accrue on the redemption date. The aggregate redemption price, including the premium, was $70.8 million. The premium of $2.0 million is included in interest expense in the Company’s Statement of Operations in the third quarter of 2003. The redemption was financed by the issuance of the 7-3/8% Senior Subordinated Notes due 2013.

7-3/8% Senior Subordinated Notes due 2013

     On July 21, 2003, the Company issued $100.0 million aggregate principal amount of the Company’s 7-3/8% Senior Subordinated Notes due 2013. The offering of the 7-3/8% Senior Subordinated Notes due 2013, on July 21, 2003, was not registered under the Securities Act of 1933, as amended (the “Securities Act”) or under any state securities laws because the 7-3/8% Senior Subordinated Notes due 2013 were only offered to qualified institutional buyers and to non-U.S. persons outside the United States in compliance with Rule 144A and Regulation S under the Securities Act (the “Outstanding Notes”). On October 23, 2003, $100,000,000 aggregate principal amount of the Outstanding Notes were exchanged for $100,000,000 aggregate principal amount of the Company’s 7-3/8% Senior Subordinated Notes due 2013 issued in a registered exchange offer for which a registration statement on Form S-4 was filed under the Securities Act (the “Exchange Notes”) as required by the Registration Rights Agreement, by and among the Company and UBS Securities LLC, Banc One Capital Markets, Inc., Credit Lyonnais Securities (USA) Inc., and McDonald Investments (the “Registration Rights Agreement”). The Exchange Notes are

14

identical to the Outstanding Notes except that the Exchange Notes are registered under the Securities Act and do not have restrictions on transfer, registration rights or provisions for additional interest. As used in this Form 10-Q, the term “7-3/8% Notes” refer to both the Outstanding Notes and the Exchange Notes. The Company will pay interest on the 7-3/8% Notes semi-annually in arrears in January and July of each year, starting in January 2004. The 7-3/8% Notes mature in July 2013. The 7-3/8% Notes are guaranteed by certain of the Company’s subsidiaries (the “Subsidiary Guarantors”). The 7-3/8% Notes were issued at a discount which will be amortized over the life of the 7-3/8% Notes in interest expense.

     The Company may redeem the 7-3/8% Notes, in whole or in part, at any time on or after July 15, 2008, at redemption prices from 103.7% of the principal amount as of July 15, 2008, and declining to 100.0% on July 15, 2011 and thereafter. Prior to July 15, 2006, the Company may redeem up to 35% of the original aggregate principal amount of the notes at a redemption price of 107.4% of the principal amount thereof plus accrued and unpaid interest, if any, with the proceeds of certain equity offerings. If the Company experiences a change of control, the Company may be required to repurchase all or a portion of the 7-3/8% Notes at 101% of the principal amount thereof plus accrued and unpaid interest, if any. The 7-3/8% Notes and the guarantees by the Subsidiary Guarantors are general, unsecured obligations and are subordinated to the Company’s and the Subsidiary Guarantors senior debt and will be subordinated to future senior debt that the Company and the Subsidiary Guarantors are permitted to incur under the senior credit facilities and the indenture governing the 7-3/8% Notes.

6% Convertible Subordinated Debentures due 2007

     In 1996, the Company sold $55.0 million aggregate principal amount of 6% Convertible Subordinated Debentures due 2007 (the “6% Debentures”). Interest on the 6% Debentures is payable semi-annually each February and August. The 6% Debentures are convertible into shares of the Company’s common stock at the option of the holder at any time prior to maturity, unless previously redeemed or repurchased, at a conversion price of $19.25 per share, subject to adjustment in certain events. The 6% Debentures will mature in 2007. The 6% Debentures are subject to redemption at the Company’s option, in whole or in part, at redemption prices from 102.5% of the principal amount as of September 30, 2003, and declining to 101.0% in 2006. Upon a change of control, the Company is required to offer to repurchase each holder’s 6% Debenture at a purchase price equal to 100% of the principal amount thereof, plus accrued and unpaid interest to the date of repurchase. The 6% Debentures are unsecured general obligations and are subordinated to all of the Company’s senior indebtedness.

     During the three months ended September 30, 2002, $800,000 face amount of the 6% Debentures were repurchased for cash at a discount. During the nine months ended September 30, 2002, $7.1 million of 6% Debentures were retired in exchange for 1,165,700 shares of the Company’s common stock and $815,000 were repurchased for cash at a discount. During the nine month period ended September 30, 2003, $880,000 was retired in exchange for 128,793 shares of the Company’s common stock. The Company recorded a $465,000 conversion expense related to this exchange (see discussion below). For both the three month and nine month periods ending September 30, 2003, $6.4 million of the 6% Debentures were repurchased for cash at a discount. On October 31, 2003, $11.6 million of the 6% Debentures was outstanding.

5-3/4%Trust Preferred Securities – manditorily redeemable securities of subsidiary

     In 1997, the Company issued $120.0 million of the Trust Preferred Securities through a newly-formed affiliate Lomak Financing Trust (the “Trust”). The Trust issued 2,400,000 shares of the Trust Preferred Securities at $50 per share. Each Trust Preferred Security is convertible at the holder’s option into shares of the Company’s common stock, at a conversion price of $23.50 per share. The Trust invested the $120 million of proceeds in the 5-3/4% convertible junior subordinated debentures (the “Junior Debentures”). The sole assets of the Trust are the Junior Debentures. The Junior Debentures and the related Trust Preferred Securities mature in November 2027. The Company and the Trust may redeem the Junior Debentures and the Trust Preferred Securities, respectively, in whole or in part. As of September 30, 2003, the price at which these redemptions could be made was approximately 102.9% of the principal amount. The premium declines proportionally every 12 months until November 2007, when the redemption price becomes fixed at 100% of the principal amount. If any Junior Debentures are redeemed prior to the scheduled maturity date, the Trust must redeem Trust Preferred Securities having an aggregate liquidation amount equal to the aggregate principal amount of the Junior Debentures the Company redeems. The Company has guaranteed the payments of distributions and other payments on the Trust Preferred Securities only if and to the extent that the Trust has funds available. The Company’s guarantee, when taken together with the Company’s

15

obligation under the Junior Debentures and related indenture and declaration of trust, provides a full and unconditional guarantee on a subordinated basis of amounts due on the Trust Preferred Securities.

     The accounts of the Trust are included in the consolidated financial statements after eliminations. Distributions of the Trust are recorded as Interest expense in the Consolidated Statement of Operations, are tax deductible and are subject to limitations in the Senior Credit Facility as described below. During the nine months ended September 30, 2002, $2.4 million of Trust Preferred Securities were retired in exchange for 283,200 shares of common stock. In addition, during the three months ended September 30, 2002, $2.5 million of the Trust Preferred Securities were repurchased for cash at a discount. On September 23, 2003, the Company exchanged $10.2 million in cash and $50.0 million of a newly issued 5.9% cumulative convertible preferred stock (the “Convertible Preferred”) for $79.5 million of the Trust Preferred Securities held by the largest holder of the Trust Preferred Securities. The Convertible Preferred was exempt from registration under Section 3(a)(9) of the Securities Act because the Convertible Preferred was only exchanged by the Company with that holder and no commission or other remuneration was paid or given directly or indirectly for soliciting such exchange. The Company paid approximately $550,000 in consulting fees for financial advice regarding the restructuring of the Company's balance sheet. On October 31, 2003, $1.4 million of the Trust Preferred Securities was outstanding.

Debt Covenants

     The debt agreements contain covenants relating to net worth, working capital, dividends and financial ratios. The Company was in compliance with all covenants at September 30, 2003. Under the Senior Credit Facility, common and preferred dividends are permitted. The Senior Credit Facility provides for a restricted payment basket of $20.0 million plus 50% of net income (excluding Great Lakes) plus 66-2/3% of distributions, dividends or payments of debt from or proceeds from sales of equity interests of Great Lakes plus 66-2/3% of net cash proceeds from common stock issuances. Approximately $43.1 million was available under the Senior Credit Facility’s restricted payment basket on September 30, 2003.

Induced Conversions

     In September 2002, the Emerging Issues Task Force (“EITF”) issued EITF Issue No. 02-15, Determining Whether Certain Conversions of Convertible Debt to Equity Securities are Within the Scope of FASB Statement No. 84 “Induced Conversions of Convertible Debt” (“SFAS 84”). SFAS 84 was issued to amend APB Opinion No. 26, “Early Extinguishment of Debt” to exclude from its scope convertible debt that is converted to equity securities of the debtor pursuant to conversion privileges different from those included in the terms of the debt at issuance, and the change in conversion privileges is effective for a limited period of time, involves additional consideration, and is made to induce conversion. SFAS 84 applies only to conversions that both (a) occur pursuant to changed conversion privileges that are exercisable only for a limited period of time and (b) include the issuance of all of the equity securities issuable pursuant to conversion privileges included in the terms of the debt at issuance for each debt instrument that is converted. The Task Force reached a consensus that SFAS 84 applies to all conversions that both (a) occur pursuant to changed conversion privileges that are exercisable only for a limited period of time and (b) include the issuance of all of the equity securities issuable pursuant to conversion privileges included in the terms of the debt at issuance for each debt instrument that is converted, regardless of the party that initiates the offer. This consensus should be applied prospectively to debt conversions completed after September 11, 2002. Since 1999, the Company has retired certain of the 6% Debentures and the Trust Preferred Securities, each of which are convertible into the Company’s common stock, by either purchasing securities for cash or issuing common stock in exchange for such securities. Since the exchanges of common stock for these convertible debt securities were at relative market values, the convertible securities were retired at a discount to face value. Under the provisions of SFAS 84, when an inducement is issued to retire convertible debt, the face value of the convertible debt security shall be charged to Stockholders’ equity (common stock and paid in capital), the shares of common stock issued in excess of the shares that would have been issued under the terms of the debt instrument are expensed at the market value of such shares and an offsetting increase to paid in capital will also be recorded. Therefore, instead of recording gains on retirements of such securities acquired at discounts to face value, an expense will be recorded. There will be no difference in Stockholders’ equity from the change in methods of recording the transactions.

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(7) FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES

     The Company’s financial instruments include cash and equivalents, receivables, payables, debt and commodity and interest rate derivatives. The book value of cash and equivalents, receivables and payables is considered representative of fair value because of their short maturity. The book value of bank borrowings is believed to approximate fair value because of their floating rate structure.

     The following table sets forth the book and estimated fair values of financial instruments as of December 31, 2002 and September 30, 2003 (in thousands):

			December 31, 2002						September 30, 2003
			Book			Fair			Book			Fair
			Value			Value			Value			Value
Assets
	Cash and equivalents		$	1,334		$	1,334		$	1,635		$	1,635
	Marketable securities			1,040			1,040			1,464			1,464
	Interest swaps			—			—			150			150
	Commodity derivatives			17			17			324			324
		Total		2,391			2,391			3,573			3,573
Liabilities
	Commodity derivatives			(32,964	)		(32,964	)		(46,602	)		(46,602	)
	Interest rate swaps			(2,150	)		(2,150	)		(1,030	)		(1,030	)
	Long-term debt(1)			(283,201	)		(279,894	)		(278,456	)		(274,237	)
	Trust Preferred Securities(1)			(84,840	)		(52,177	)		(1,412	)		(1,073	)
		Total		(403,155	)		(367,185	)		(327,500	)		(322,942	)
		Net financial instruments	$	(400,764	)	$	(364,794	)	$	(323,927	)	$	(319,369	)

(1) Fair value based on quotes received from brokerage firms. Quotes for September 30, 2003 were 96% for the 7-3/8% Notes, 98% for the 6% Debentures and 76% for the Trust Preferred Securities.

     A portion of future oil and gas sales is periodically hedged through the use of swap and collar contracts. In the second quarter of 2003, the hedging program was modified to include collars, which assume a minimum floor price and a predetermined ceiling price. 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 through the use of swaps. Gains and losses on interest rate swaps are included as an adjustment to interest expense in the relevant periods.

     At September 30, 2003, the Company had hedging swap contracts covering 60.0 Bcf of gas at prices averaging $4.10 per mcf and 1.5 million barrels of oil at prices averaging $24.92 per barrel. The Company also has collars covering 0.6 Bcf of gas at prices of $4.00-$6.75 and 0.6 million barrels of oil at prices of $24.00-$27.71. The fair value, represented by the estimated amount that would be realized upon termination, based on contract prices versus the New York Mercantile Exchange (“NYMEX”) price on September 30, 2003, was a net unrealized pre-tax loss of $46.3 million. The contracts expire monthly through December 2006. Gains or losses on open and closed contracts are determined as the difference between the contract price and the reference price, which are closing prices on the NYMEX. Transaction gains and losses on settled contracts 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 increased by $3.5 million and decreased by $12.3 million due to hedging in the three months ended September 30, 2002 and 2003, respectively. Oil and gas revenues were increased by $18.8 million and decreased by $53.5 million due to hedging in the nine months ended September 30, 2002 and 2003, respectively.

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          The following schedule shows the effect of closed oil and gas hedges since January 1, 2002 and the value of open contracts at September 30, 2003 (in thousands):

Quarter			Hedging Gain/
Ended			(Loss)
Closed Contracts
	2002
March 31			$	11,727
June 30				3,638
September 30				3,484
December 31				(1,059	)
		Subtotal		17,790
	2003
March 31				(25,890	)
June 30				(15,365	)
September 30				(12,257	)
		Subtotal		(53,512	)
	Total realized loss		$	(35,722	)
Open Contracts
	2003
December 31				(8,042	)
	2004
March 31				(8,474	)
June 30				(7,467	)
September 30				(6,859	)
December 31				(6,457	)
		Subtotal		(29,257	)
	2005
March 31				(4,254	)
June 30				(1,522	)
September 30				(1,389	)
December 31				(1,984	)
		Subtotal		(9,149	)
	2006
March 31				(6	)
June 30				62
September 30				69
December 31				45
		Subtotal		170
	Total unrealized loss		$	(46,278	)

     Through Great Lakes, the Company uses interest rate swap agreements to manage the risk that future cash flows associated with interest payments on amounts outstanding under the variable rate Great Lakes Credit Facility may be adversely affected by volatility in market interest rates. Under the interest swap agreements, the Company agrees to pay an amount equal to a specified fixed rate of interest times a notional principal amount, and to receive in return, a specified variable rate of interest times the same notional principal amount. Changes in the fair value of the

18

Company’s interest rate swaps, which qualify for cash flow hedge accounting treatment, are reflected as adjustments to OCI to the extent the swaps are effective and will be recognized as an adjustment to interest expense during the period in which the cash flows related to the Company’s interest payments are made. The ineffective portion of the changes in fair value of the Company’s interest rate swaps is recorded in interest expense in the period incurred. Interest expense also includes the fair value effect of non-qualifying interest rate swaps. At September 30, 2003, Great Lakes had seven interest rate swap agreements totaling $110.0 million, of which 50% is consolidated at the Company. These swaps consist of two agreements totaling $45.0 million at 7.1% which expire in May 2004, two agreements totaling $20.0 million at rates averaging 2.3% which expire in December 2004, one agreement for $10.0 million at 1.4% which expires in June 2005 and two agreements totaling $35.0 million at rates averaging 1.8% which expire in June 2006. The fair value of these swaps at September 30, 2003 approximated a net loss of $1.8 million, of which 50% is consolidated at the Company.

     The combined fair value of net unrealized losses on oil and gas hedges and net losses on interest rate swaps totaled $47.2 million and appear as short-term and long-term Unrealized derivative gains and short-term and long-term Unrealized derivative losses 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 periodic review.

(8) COMMITMENTS AND CONTINGENCIES

     The Company is involved in various legal actions and claims arising in the ordinary course of business which, in the opinion of management, are likely to be resolved without material adverse effect on the Company’s financial position or results of operations.

(9) STOCKHOLDERS’ EQUITY

     The Company has authorized capital stock of 110 million shares, which includes 100 million shares of common stock and 10 million shares of preferred stock. Stockholders’ equity was $283.1 million at September 30, 2003. On September 23, 2003, the Company issued 1.0 million shares of Convertible Preferred, par value $1.00 and liquidation preference $50 per share. The Convertible Preferred is convertible into common stock at $8.50 per share. Beginning on September 30, 2007, the Company may, at its sole election, redeem the Convertible Preferred for cash at 103% and declines to 100% on September 30, 2012. Beginning on September 30, 2005, the Company may, at its sole election, cause the Convertible Preferred to convert, in whole but not in part, to common stock if, at the time, the common stock has closed at $11.90 or higher for 20 of the previous consecutive 30 trading days. Accrued dividends are cumulative and are payable quarterly in arrears. The following is a schedule of changes in the number of outstanding common shares from December 31, 2001 to September 30, 2003:

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			Twelve Months		Nine Months
			Ended		Ended
			December 31, 2002		September 30, 2003
Beginning Balance				52,643,275		54,991,611
Issuances:
	Employee benefit plans			417,661		441,938
	Stock options exercised			130,566		507,992
	Stock purchase plan			168,500		87,500
	Exchanges for:
		6% Debentures		1,165,700		128,793
		Trust Preferred Securities		283,200		—
		8-3/4% Notes		182,709		—
				2,348,336		1,166,223
Ending Balance				54,991,611		56,157,834

(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 of Directors (the “Board”). Information with respect to the option plans is summarized below:

		Inactive						Active
		Domain			1989			Directors’			1999
		Plan			Plan			Plan			Plan			Total
Outstanding on December 31, 2002			131,702			453,580			152,000			2,544,862			3,282,144
	Granted		—			—			56,000			1,574,400			1,630,400
	Exercised		(28,670	)		(167,981	)		(4,000	)		(307,841	)		(508,492	)
	Expired		—			(9,175	)		—			(428,314	)		(437,489	)
			(28,670	)		(177,156	)		52,000			838,245			684,419
Outstanding on September 30, 2003			103,032			276,424			204,000			3,383,107			3,966,563

     In 1999, shareholders approved a stock option plan (the “1999 Plan”). In May 2003, shareholders approved an increase in the number of options issuable to 8.75 million. All options issued under the 1999 Plan through May 2002 vest 25% per year beginning after one year and have a maximum term of 10 years. Options issued under the 1999 Plan after May 2002 vest 30%, 30% and 40% over a three year period and have a maximum term of five years. During the nine months ended September 30, 2003, 1.6 million options were granted to eligible employees under the 1999 Plan at exercise prices ranging from $5.83 to $6.50 a share. At September 30, 2003, 3.4 million options were outstanding under the 1999 Plan at exercise prices ranging from $1.94 to $6.67 a share.

     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 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. In May 2002, the term of the options was changed to five years with vesting immediately upon grant. Director’s options are granted upon initial election as a director and annually upon a director’s re-election at the annual meeting. At September 30, 2003, 204,000 options were outstanding under the Directors’ Plan at exercise prices ranging from $2.81 to $6.00 a share.

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     The Company 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 March 1999. Options issued under the 1989 Plan vested over a three year period and expire in five years. At September 30, 2003, 276,424 options remained outstanding under the 1989 Plan at exercise prices ranging from $2.63 to $7.63 a share. The last of these options will expire in 2009.

     The Domain stock option plan was adopted when that company was acquired in 1998, with existing Domain options becoming exercisable into the Company’s common stock. No options have been granted under this plan since the acquisition. At September 30, 2003, 103,032 options remained outstanding at an exercise price of $3.46 a share. The last of these options will expire in 2007.

     In total, approximately 4.0 million options were outstanding at September 30, 2003 at exercise prices of $1.94 to $7.63 a share as follows:

				Inactive				Active
Range of		Average		Domain		1989		Directors’		1999
Exercise Prices		Exercise Price		Plan		Plan		Plan		Plan		Total
$1.94 - $4.99		$	3.48		103,032		140,574		52,000		783,652		1,079,258
$5.00 - $7.63		$	5.93		—		135,850		152,000		2,599,455		2,887,305
	Total	$	5.20		103,032		276,424		204,000		3,383,107		3,966,563

     In 1997, shareholders approved a plan (the “Stock Purchase Plan”) authorizing the sale of 900,000 shares of common stock to officers, directors, key employees and consultants. In 2001, shareholders approved an increase in the number of shares authorized under the Stock Purchase Plan to 1.75 million. 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, all purchase rights have been granted at 75% of market. Due to the discount from market value, the Company recorded additional compensation expense of $126,000 and $122,000 in the nine months ended September 30, 2002 and 2003, respectively. Through September 30, 2003, 1,377,319 shares have been sold under the Stock Purchase Plan. At September 30, 2003, there were no rights outstanding to purchase shares.

(11) DEFERRED COMPENSATION

     In 1996, the Board of the Company adopted a deferred compensation plan (the “Plan”). The Plan gives certain senior employees the ability to defer all or a portion of their salaries and bonuses and invests in common stock of the Company or makes other investments at the employee’s discretion. The assets of the Plan are held in a rabbi trust (the “Rabbi Trust”) and, therefore, are available to satisfy the claims of the Company’s creditors in the event of bankruptcy or insolvency of the Company. The Company’s stock held in the Rabbi Trust is treated in a manner similar to treasury stock with an offsetting amount reflected as a deferred compensation liability of the Company and the carrying value of the deferred compensation liability is adjusted to fair value each reporting period by a charge or credit to operations in the General and administrative expense category on the Company’s Consolidated Statements of Operations. The assets of the Rabbi Trust, other than common stock of the Company, are invested in marketable securities and reported at market value in Other assets on the Company’s balance sheet. The Deferred Compensation liability on the Company’s balance sheet reflects the market value of the marketable securities and the Company’s common stock held in the Rabbi Trust. The cost of common stock held in the Rabbi Trust is shown as a reduction to Stockholders’ equity. Changes in the market value of the marketable securities are reflected in OCI, while changes in the market value of the common stock held in the Rabbi Trust is charged or credited to General and administrative expense each quarter. The Company recorded mark-to-market expense (income) related to the Company stock held in the Rabbi Trust of ($1.2 million) and $898,000 in the three months ended September 30, 2002 and 2003, respectively. The Company recorded mark-to-market expense related to deferred compensation of $71,000 and $2.2 million in the nine months ended September 30, 2002 and 2003, respectively.

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(12) BENEFIT PLAN

     The Company maintains a 401(k) Plan for its employees. The 401(k) Plan permits employees to contribute up to 50% of their salary (subject to Internal Revenue limitations) on a pre-tax basis. Historically, the Company has made discretionary contributions of the Company’s common stock to the 401(k) Plan annually. All Company contributions become fully vested after the individual employee has three years of service with the Company. In 2000, 2001 and 2002, the Company contributed $483,000, $554,000 and $602,000 at then market value, respectively, of the Company’s common stock to the 401(k) Plan. The Company does not require that employees hold the contributed stock in their account. Employees have a variety of investment options in the 401(k) Plan. Employees may at any time diversify out of the Company’s common stock based on their personal investment strategy.

(13) 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 are measured using the enacted tax rates and regulations that will be in effect when the differences are expected to reverse. The significant components of deferred tax liabilities and assets on December 31, 2002 and September 30, 2003 were as follows (in thousands):

		December 31,		September 30,
		2002		2003
Deferred tax assets/(liabilities)
	Net unrealized loss on hedging	$	11,388	$	15,629
	Other		4,397		(13,591	)
	Net deferred tax asset	$	15,785	$	2,038

     At December 31, 2002, deferred tax assets exceeded deferred tax liabilities by $15.7 million with $11.4 million of deferred tax assets related to deferred hedging losses included in OCI. Based on the Company’s recent profitability and its current outlook, no valuation allowance was deemed necessary at December 31, 2002. At September 30, 2003, deferred tax assets exceeded deferred tax liabilities by $2.0 million with $15.6 million of deferred tax assets related to hedging losses in OCI.

     At December 31, 2002, the Company had regular net operating loss (“NOL”) carryovers of $218.2 million and alternative minimum tax (“AMT”) NOL carryovers of $198.5 million that expire between 2006 and 2022. At December 31, 2002, the Company had an AMT credit carryover of $665,000 which is not subject to limitation or expiration.

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(14)  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,						Nine Months Ended,
				September 30						September 30,
				2002			2003			2002			2003
Numerator:
	Income before cumulative effect of change in accounting principle			$	9,222		$	16,737		$	20,873		$	26,291
		Preferred stock			—			(65	)		—			(65	)
	Numerator for basic earnings per share before cumulative effect of change in accounting principle				9,222			16,672			20,873			26,226
		Cumulative effect of accounting change			—			—			—			4,491
	Numerator for basic earnings per share			$	9,222		$	16,672		$	20,873		$	30,717
	Income before cumulative effect of change in accounting principle			$	9,222		$	16,737		$	20,873		$	26,291
		Effect of dilutive securities:
		6% Debentures			—			194			—			—
		Trust Preferred Securities			—			703			—			—
	Numerator for diluted earnings per share before cumulative effect of change in accounting principle				9,222			17,634			20,873			26,291
	Cumulative effect of accounting change				—			—			—			4,491
	Numerator for diluted earnings per share after assumed conversions and cumulative effect of change in accounting principle			$	9,222		$	17,634		$	20,873		$	30,782
Denominator:
	Weighted average shares outstanding				54,765			56,022			54,101			55,636
		Stock held by employee benefit trust			(1,316	)		(1,607	)		(1,177	)		(1,485	)
	Weighted average shares, basic				53,449			54,415			52,924			54,151
	Effect of dilutive securities:
		Weighted average shares outstanding			54,765			56,022			54,101			55,636
		Employee stock options			323			517			333			433
		Common shares assumed issued for 6% Debentures			—			1,023			—			—
		Common shares assumed for Trust Preferred Securities			—			3,017			—			—
		Common shares assumed for Convertible Preferred			—			512			—			172
	Dilutive potential common shares for diluted earnings per share				55,088			61,091			54,434			56,241
	Earnings per share basic and diluted:
		Before cumulative effect of accounting change
			Basic	$	0.17		$	0.31		$	0.39		$	0.49
			Diluted	$	0.17		$	0.29		$	0.38		$	0.47
		After cumulative effect of accounting change
			Basic	$	0.17		$	0.31		$	0.39		$	0.57
			Diluted	$	0.17		$	0.29		$	0.38		$	0.55

     During the three months ended September 30, 2002 and 2003, 346,000 and 537,000 stock options were included in the computation of diluted earnings per share and for the nine months then ended, 356,000 and 454,000

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stock options were included in such computation. It is expected that the fourth quarter of 2003 will include the dilutive effect of approximately 5.8 million shares of the 5.9% Convertible Preferred.

(15)  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 or less. 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 three months ended September 30, 2003, two customers, Duke Energy Field Services, Inc. and Petrocom Energy Group, Ltd., accounted for 22% and 21%, respectively, of oil and gas revenues. Management believes that the loss of any one customer would not have a material long-term adverse effect on the Company. The creditworthiness of our customers is subject to periodic review.

(16)  OIL AND GAS ACTIVITIES

     The following summarizes selected information with respect to producing activities. Exploration costs include capitalized as well as expensed outlays (in thousands):

						Nine
			Year Ended			Months Ended
			December 31,			September 30,
			2002			2003
Book value
	Properties subject to depletion		$	1,135,590		$	1,244,527
	Unproved properties			18,959			15,541
		Total		1,154,549			1,260,068
	Accumulated depletion			(590,143	)		(619,260	)
		Net	$	564,406		$	640,808
Costs incurred(a)
	Development		$	66,284		$	63,327
	Exploration(b)			23,232			12,704
	Acquisition(c)			21,790			12,380
		Total	$	111,306		$	88,411

(a)	Excludes asset retirement costs of $2.1 million in the nine months ended September 30, 2003.
(b)	Includes $11,525 and $8,773 of exploration costs expensed in the year ended 2002 and the nine months ended September 30, 2003, respectively.
(c)	Includes $15,643 and $7,969 for producing and non-producing oil and gas reserves, the remainder represents acreage purchases for the year ended 2002 and the nine months ended September 30, 2003, respectively.

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(17)  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 50% interest in Great Lakes financial statements as of or for the nine months ended September 30, 2002 and 2003 (in thousands):

	September 30,		September 30,
	2002		2003
Balance Sheet
Current assets	$	7,882	$	10,603
Oil and gas properties, net		173,068		213,802
Transportation and field assets, net		15,456		14,711
Unrealized derivative gain		442		310
Other assets		143		293
Current liabilities		13,405		19,413
Unrealized derivative loss		2,787		4,535
Asset retirement obligation		—		17,880
Long-term debt		68,000		71,500
Members’ equity		112,799		126,391
Statement of Operations
Revenues	$	38,391	$	42,214
Direct operating expense		5,988		7,598
Exploration		1,963		1,483
G&A expense		1,387		1,443
Interest expense		4,037		3,179
DD&A		10,576		10,737
Pretax income		14,440		17,774
Cumulative effect of change in accounting principle (before income taxes)		—		1,601

(18)  GAIN ON RETIREMENT OF SECURITIES

     In the third quarter of the 2003, $6.4 million of the 6% Debentures and $3.5 million of the Trust Preferred Securities were repurchased for cash and a gain of $784,000 was recorded. In addition, the Company exchanged $10.2 million in cash and $50.0 million of its newly issued Convertible Preferred for $79.5 million of Trust Preferred Securities and a gain of $17.8 million was recorded. In the nine months of 2003, an additional $400,000 of Trust Preferred Securities and $500,000 of 8-3/4% Notes were repurchased for cash and $880,000 of 6% Debentures was exchanged for the Company’s common stock. A net gain of $143,900 was recorded on the cash transactions. The exchange transaction included conversion expense of $465,000. (See Note 6 regarding further guidance on SFAS 84 and accounting for gains on sale of securities). In the third quarter of 2002, $3.7 million of 8-3/4% Notes, $800,000 of 6% Debentures and $2.5 million of Trust Preferred Securities were repurchased for cash. In the first nine months of 2002, an additional $5.0 million of 6% Debentures were repurchased for cash. Also in the nine months of 2002, $2.4 million, $7.1 million, and $875,000 of Trust Preferred Securities, 6% Debentures, and 8-3/4% Notes, respectively, were exchanged for 1.6 million shares of the Company’s common stock. A gain of $3.1 million was recorded in the nine months ending September 30, 2002.

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Item 2.   MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Factors Affecting Financial Condition and Liquidity

Critical Accounting Policies

     The Company’s discussion and analysis of its financial condition and results of operation are based upon unaudited consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues, and expenses. Application of certain of the Company’s accounting policies, including those related to oil and gas revenues, oil and gas properties, income taxes, and litigation, bad debts, marketable securities, hedging and the deferred compensation plan, require significant estimates. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. The Company believes the following critical accounting policies affect its more significant judgments and estimates used in the preparation of its consolidated financial statements.

     The FASB and representatives of the accounting staff of the SEC are engaged in discussions on the issue of whether the FASB’s No. 141 and 142, issued effective for June 30, 2001, called for mineral rights held under lease or other contractual arrangements to be classified in the balance sheet as intangible assets and accompanied by specific footnote disclosures. Historically, the Company and all other oil and gas companies have included the cost of these oil and gas leasehold interests as part of oil and gas properties. Although most of the Company’s oil and gas property interests are held under oil and gas leases, this interpretation, if adopted, would not have a material impact on the Company’s financial condition or its results of operations.

     In the event this interpretation is adopted, a substantial portion of acquisition costs of oil and gas properties since September 30, 2001 would be separately classified on the balance sheets as intangible assets. As of September 30, 2003, the Company has expended approximately $25.2 million on the acquisition of oil and gas leasehold interests since June 30, 2001. Some additional direct costs of other oil and natural gas leases acquired since that date could also be categorized as intangible under this interpretation. Results of operations would not be affected by this interpretation, if adopted, since these costs would continue to be depleted in accordance with successful efforts accounting for oil and gas companies. Another possible effect of this interpretation, if adopted, would be a change in some of the financial measurements used in financial covenants of debt instruments that focus on tangible assets. The Company does not believe that its debt covenants would be materially affected by the adoption of this accounting interpretation.

     Proved oil and natural gas reserves – Proved reserves are defined by the SEC as those volumes of crude oil, condensate, natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered through existing wells with existing equipment and operating methods. Although the Company’s engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of reserves requires the engineers to make a significant number of assumptions based on professional judgment. Reserve estimates are updated at least annually and consider recent production levels and other technical information about each well. Estimated reserves are often subject to future revision, which could be substantial, based on the availability of additional information, including: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes, and other economic factors. Changes in oil and gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions in turn cause adjustments in the depletion rates utilized by the Company. The Company can not predict what reserve revisions may be required in future periods.

     Depletion rates are determined based on reserve quantity estimates and the capitalized costs of producing properties. As the estimated reserves are adjusted, the depletion expense for a property will change, assuming no change in production volumes or the costs capitalized. Estimated reserves are used as the basis for calculating the expected future cash flows from a property, which are used to determine whether that property may be impaired. Reserves are also used to estimate the supplemental disclosure of the standardized measure of discounted future net cash flows relating to its oil and gas producing activities and reserve quantities annual disclosure to the consolidated

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financial statements. Changes in the estimated reserves are considered changes in estimates for accounting purposes and are reflected on a prospective basis.

     Successful efforts accounting – The Company utilizes the successful efforts method to account for exploration and development expenditures. Unsuccessful exploration wells are expensed and can have a significant effect on operating results. Successful exploration drilling costs and all development costs are capitalized and systematically charged to expense using the units of production method based on proved developed oil and natural gas reserves as estimated by the Company’s and independent engineers. Proven leasehold costs are charged to expense using the units of production method based on total proved reserves. Unproved properties are assessed periodically within specific geographic areas and impairments to value are charged to expense.

     Impairment of properties – The Company monitors its long-lived assets recorded in Property, plant and equipment in the Consolidated Balance Sheet to make sure that they are fairly presented. The Company must evaluate its properties for potential impairment when circumstances indicate that the carrying value of an asset could exceed its fair value. A significant amount of judgment is involved in performing these evaluations since the results are based on estimated future events. Such events include a projection of future oil and gas sales prices, an estimate of the ultimate amount of recoverable oil and natural gas reserves that will be produced, the timing of future production, future production costs, and future inflation. The need to test a property for impairment can be based on several factors, including a significant reduction in sales prices for oil and/or gas, unfavorable adjustment to reserves, or other changes to contracts, environmental regulations, or tax laws. All of these factors must be considered when testing a property’s carrying value for impairment. The Company cannot predict whether impairment charges may be recorded in the future.

     Income taxes – The Company is subject to income and other similar taxes in all areas in which it operates. When recording income tax expense, certain estimates are required because: (a) income tax returns are generally filed months after the close of its calendar year; (b) tax returns are subject to audit by taxing authorities and audits can often take years to complete and settle; and (c) future events often impact the timing of when income tax expenses and benefits are recognized by the Company. The Company has deferred tax assets relating to tax operating loss carry forwards and other deductible differences. The Company routinely evaluates its deferred tax assets to determine the likelihood of their realization. A valuation allowance has not been recognized for deferred tax assets due to management’s belief that these assets are likely to be realized. At year-end 2002, deferred tax assets exceeded deferred tax liabilities by $15.8 million with $11.4 million of deferred tax assets related to deferred hedging losses included in OCI. Based on the Company’s projected profitability, no valuation allowance was deemed necessary.

     The Company occasionally is challenged by taxing authorities over the amount and/or timing of recognition of revenues and deductions in its various income tax returns. Although the Company believes that it has adequate accruals for matters not resolved with various taxing authorities, gains or losses could occur in future years from changes in estimates or resolution of outstanding matters.

     Legal, environmental, and other contingent matters – A provision for legal, environmental, and other contingent matters is charged to expense when the loss is probable and the cost can be reasonably estimated. Judgment is often required to determine when expenses should be recorded for legal, environmental, and contingent matters. In addition, the Company often must estimate the amount of such losses. In many cases, management’s judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. Management closely monitors known and potential legal, environmental, and other contingent matters, and makes its best estimate of when the Company should record losses for these based on available information.

     Other significant accounting policies requiring estimates – The Company recognizes revenues from the sale of products and services in the period delivered. The Company uses the sales method to account for gas imbalances. Revenues at IPF are recognized as earned. An allowance for doubtful accounts is provided for specific receivables which are unlikely to be collected. At IPF, all receivables are evaluated quarterly and provisions for uncollectible amounts are established. Such provisions for uncollectible amounts are recorded when management believes that a related receivable is not recoverable based on current estimates of expected discounted cash flows. The Company records a write down of marketable securities when the decline in market value is considered to be other than temporary. Change in the value of the ineffective position of all open hedges is recognized in earnings quarterly.

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The fair value of open hedging contracts is an estimated amount that could be realized upon termination. The Company stock held in the deferred compensation plan is treated as treasury stock and the carrying value of the deferred compensation is adjusted to fair value each reporting period by a charge or credit to operations in general and administrative expense. As of January 1, 2003, the accounting for expected future costs to retire long-lived assets changed with the adoption of SFAS 143.

Liquidity and Capital Resources

     During the nine months ended September 30, 2003, the Company spent $88.4 million on development, exploration, and acquisitions. During the period, debt and Trust Preferred Securities decreased $88.2 million. At September 30, 2003, the Company had $1.6 million in cash, total assets of $736.5 million and, including the Trust Preferred Securities as debt, a debt to capitalization ratio of 49.7%. Available borrowing capacity on the credit facilities at September 30, 2003 was $75.7 million on the Senior Credit Facility and $82.0 million on the Great Lakes Credit Facility. Long-term debt at September 30, 2003 totaled $279.9 million. This included $94.3 million of Senior Credit Facility debt, $71.5 million of Great Lakes Credit Facility net debt, a net $98.3 million of 7-3/8% Notes, $14.3 million of 6% Debentures, and $1.4 million of Trust Preferred Securities.

     During the nine months ended September 30, 2003, $9.8 million of cash and 129,000 shares of the Company’s common stock were used to retire $7.3 million of 6% Debentures, $3.9 million of Trust Preferred Securities and $500,000 of 8-3/4% Notes. A $927,600 gain on retirement was recorded on the cash repurchases and a conversion expense of $465,000 was recorded on the exchanges for common stock. In addition on September 23, 2003, $10.2 million of cash and $50.0 million of the newly issued Convertible Preferred was exchanged for $79.5 million of Trust Preferred Securities. A gain of $17.8 million was recorded on the transaction.

7-3/8% Notes Issuance

     On July 21, 2003, the Company issued $100.0 million principal amount of the Company’s Outstanding Notes. The offering of the Outstanding Notes was not registered under the Securities Act or under any state securities laws because Outstanding Notes were only offered to qualified institutional buyers and to non-U.S. persons outside the United States in compliance with Rule 144A and Regulation S under the Securities Act. On October 23, 2003, $100,000,000 aggregate principal amount of the Outstanding Notes were exchanged for $100,000,000 aggregate principal amount of the Exchange Notes as required by the Registration Rights Agreement. The Exchange Notes are identical to the Outstanding Notes except that the Exchange Notes are registered under the Securities Act and do not have restrictions on transfer, registration rights or provisions for additional interest

Convertible Preferred Issuance

     On September 23, 2003, the Company issued 1.0 million shares of Convertible Preferred, par value $1.00 and liquidation preference $50 per share and paid $10.2 million cash in exchange for $79.5 million of Trust Preferred Securities. The Convertible Preferred is convertible into common stock at $8.50 per share. Beginning on September 30, 2007, the Company may, at its sole election, redeem the Convertible Preferred for cash at 103% and declines to 100% in 2012. In addition, beginning on September 30, 2005, the Company may, at its sole election, cause the Convertible Preferred to convert, in whole but not in part, to common stock of the Company if, at the time, the common stock has closed at $11.90 or higher for 20 of the previous consecutive 30 trading days. Annual cumulative dividends are payable quarterly in arrears.

     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.

     The debt agreements contain covenants relating to net worth, working capital, dividends, and financial ratios. The Company was in compliance with all covenants at September 30, 2003. Under the Senior Credit Facility, common and preferred dividends are permitted. The Senior Credit Facility provides for a restricted payment basket of $20.0 million plus 50% of net income (excluding Great Lakes) plus 66-2/3% of distributions, dividends or payments of debt from or proceeds from sales of equity interests of Great Lakes plus 66-2/3% of net cash proceeds from common stock

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issuances. Approximately $43.1 million was available under the Senior Credit Facility’s restricted payment basket on September 30, 2003.

     The following summarizes the Company’s contractual financial obligation at September 30, 2003 and their future maturities (in thousands):

	Less than		1-3		After
	1 Year		Years		3 Years		Total
Long-term debt	$	—	$	—	$	281,565	$	281,565
Non-cancelable lease obligations		452		2,663		299		3,414
Contract to purchase seismic data		215		1,076		—		1,291
	$	667	$	3,739	$	281,864	$	286,270

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 swap agreements covering 60.0 bcf of gas and 1.5 million barrels of oil for the remainder of 2003 through the end of 2006. The $77.5 million of capital expenditures in the nine months ended September 30, 2003 was funded with internal cash flow. Net cash provided by operations for the nine months ended September 30, 2002 and 2003 was $88.4 million and $93.5 million, respectively. Cash flow from operations was higher than the prior year due to higher prices and volumes and lower exploration expense partially offset by higher direct operating expenses. Accounts receivable increased $9.7 million from December 31, 2002 due to higher prices and volumes. These receivables will be collected in the fourth quarter of 2003. Net cash used in investing for the nine months ended September 30, 2002 and 2003 was $75.1 million and $76.5 million, respectively. The 2002 period included $70.6 million of additions to oil and gas properties. The 2003 period included $75.5 million of additions to oil and gas properties partially offset by $9.4 million of net IPF receipts and lower exploration expenditures. Net cash provided by financing in the nine months ended September 30, 2002 and 2003 was $16.3 million and $16.7 million, respectively. During the first nine months of 2003, total debt, including Trust Preferred Securities decreased $88.2 million. Senior Credit Facility debt and Great Lakes Credit Facility debt decreased $26.5 million, subordinated debt (8-3/4% Notes, 7-3/8% Notes, and 6% Debentures) increased $21.7 million and the Trust Preferred Securities decreased $83.4 million. The net decrease in debt was the result of excess cash flows and the exchange of the Trust Preferred Securities for the Convertible Preferred.

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Capital Requirements

     The 2003 capital budget is approximately $105.0 million (excluding acquisitions) and based on current projections, the Company expects to fund its capital budget with internal cash flow. During the nine months ended September 30, 2003, $77.5 million of capital expenditures was funded with internal cash flow.

Banking

     The Company maintains two separate revolving bank credit facilities: a $225.0 million Senior Credit Facility and a $275.0 million Great Lakes Credit Facility (of which 50% is consolidated at the Company). Each facility is secured by substantially all the borrowers’ assets. The Great Lakes Credit Facility is non-recourse to the Company. As Great Lakes is 50% owned, half of its borrowings are consolidated in the Company’s financial statements. Availability under the facilities is subject to borrowing bases set by the banks semi-annually and in certain other circumstances. Redeterminations, other than increases, require the approval of 75% of the lenders while, increases require unanimous approval.

     At October 31, 2003, the Senior Credit Facility had a $180.0 million borrowing base of which $82.7 million was available. The Great Lakes Credit Facility, half of which is consolidated at the Company, had a $225.0 million borrowing base, of which $84.0 million was available.

Hedging

Oil and Gas Prices

     The Company enters into hedging agreements to reduce the impact of oil and gas price fluctuations. The Company’s current policy, when futures prices justify, is to hedge 50% to 75% of projected production. At September 30, 2003, swaps were in place covering 60.0 Bcf of gas at prices averaging $4.10 per Mmbtu and 1.5 million barrels of oil at prices averaging $24.92 per barrel. The Company also has collars covering 0.6 Bcf of gas at prices of $4.00-$6.75 and 0.6 million barrels of oil at prices of $24.00-$27.71. Their fair value at September 30, 2003 (the estimated amount that would be realized on termination based on contract versus NYMEX prices) was a net unrealized pre-tax loss of $46.3 million. Gains or losses on open and closed hedging transactions are determined based on the difference between the contract price and a reference price, generally closing prices on the NYMEX. Gains and losses are determined monthly and are included as increases or decreases in oil and gas revenues in the period the hedged production is sold. An ineffective portion (changes in contract prices that do not match changes in the hedge price) of open hedge contracts is recognized in earnings as it occurs. Net decreases to Oil and gas revenues from hedging for the three months ended September 30, 2003 were $12.3 million and Oil and gas revenues were increased by $3.5 million from hedging for the three months ended September 30, 2002.

     At September 30, 2003, the following commodity derivative contracts were outstanding:

			Average
		Volume	Hedge
Contract Type	Period	Hedged	Price
Natural Gas
Swaps	October-December 2003	95,291 MMBtu/day	$4.06
Swaps	2004	89,440 MMBtu/day	$4.05
Swaps	2005	48,945 MMBtu/day	$4.19
Swaps	2006	1,644 MMBtu/day	$4.80
Collars	January-December 2005	1,644 MMBtu/day	$4.00-$6.75
Crude Oil
Swaps	October-December 2003	4,114 Bbl/day	$25.03
Swaps	2004	2,337 Bbl/day	$24.93
Swaps	2005	750 Bbl/day	$24.73
Collars	January-December 2004	1,628 Bbl/day	$24.00-$27.71

Interest Rates

     At September 30, 2003, the Company had $279.9 million of debt (including Trust Preferred Securities) outstanding. Of this amount, $114.0 million bore interest at fixed rates averaging 7.2%. Senior Credit Facility debt and Great Lakes Credit Facility debt totaling $165.8 million bore interest at floating rates which averaged 2.9% at September 30, 2003. At times, the Company enters into interest rate swap agreements to limit the impact of interest rate fluctuations on its floating rate debt. At September 30, 2003, Great Lakes had interest rate swap agreements totaling $110.0 million, 50% of which is consolidated at the Company. These swaps consist of $45.0 million at 7.1% which expire in May 2004, $20.0 million at rates averaging 2.3% which expire in December 2004, $10.0 million at 1.4% which expire in June 2005, $35.0 million at rates averaging 1.8% which expire in June 2006. The fair value of the swaps, based on then current quotes for equivalent agreements at September 30, 2003 was a net loss of $1.8 million, of which 50% is consolidated at the Company. The 30 day LIBOR rate on September 30, 2003 was 1.1%.

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Debt Reduction

     The Company has taken a number of steps since 1998 to strengthen its financial position. These steps included the application of excess cash flow toward debt repayment, sale of assets and the exchange of common stock for debt. These initiatives have helped reduce the Senior Credit Facility debt from $365.2 million to $94.3 million and total debt (including Trust Preferred Securities) from $727.2 million to $279.9 million at September 30, 2003. At September 30, 2003, the debt to capitalization ratio was 49.7% compared to 64.1% at December 31, 2002.

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 2003, the Company received an average of $28.47 per barrel of oil and $5.31 per mcf of gas before hedging compared to $22.51 per barrel of oil and $2.82 per mcf of gas in the same period of the prior year. Although certain of the Company’s costs and expenses are affected by general inflation, inflation does not normally have a significant effect on the Company. During 2002, the Company experienced a slight decline in certain drilling and operational costs when compared to the prior year. Increases in commodity prices can cause inflationary pressures specific to the industry to also increase certain costs. The Company expects an increase in these costs in 2003.

Results of Operations

     Volumes and sales data:

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2002		2003		2002		2003
Production:
	Crude oil and liquid (bbls)		577,928		600,401		1,671,646		1,814,140
	Natural gas (mcfs)		10,447,053		11,040,493		31,020,256		32,018,400
Average daily production:
	Crude oil (bbls)		5,096		5,526		4,999		5,589
	NGLs (bbls)		1,186		1,000		1,125		1,056
	Natural gas (mcfs)		113,555		120,005		113,627		117,284
	Total (mcfes)		151,246		159,162		150,367		157,155
Average sales prices (excluding hedging):
	Crude oil (per bbl)	$	25.43	$	27.42	$	22.51	$	28.47
	NGLs (per bbl)	$	13.49	$	17.64	$	12.39	$	18.76
	Natural gas (per mcf)	$	2.99	$	4.75	$	2.82	$	5.31
Average sales price (including hedging):
	Crude oil (per bbl)	$	22.05	$	23.76	$	22.32	$	23.51
	NGLs (per bbl)	$	13.49	$	17.64	$	12.39	$	18.76
	Natural gas (per mcf)	$	3.48	$	3.81	$	3.44	$	3.87
	Total (per mcfe)	$	3.46	$	3.81	$	3.44	$	3.85

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     The following table identifies certain items included in the results of operations and is presented to assist in comparing the third quarter and year to date 2003 to the same periods of the prior year. The table should be read in conjunction with the following discussions of results of operations (in thousands):

		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2002			2003			2002			2003
Increase (decrease) in revenues:
	Write-down of marketable securities	$	—		$	—		$	(1,220	)	$	—
	Gains on retirement of securities		1,050			18,572			3,080			18,712
	Ineffective portion of commodity hedges gain (loss)		(419	)		1,093			(2,581	)		(178	)
	(Loss) gain from sales of assets		266			(275	)		292			(118	)
	Realized hedging gains (losses)		3,484			(12,257	)		18,849			(53,512	)
		$	4,381		$	7,133		$	18,420		$	(35,096	)
Increase (decrease) to expenses:
	Mark-to-market deferred compensation adjustment	$	(1,249	)	$	898		$	71		$	2,195
	Bad debt expense accrual		75			75			75			225
	Adjustment to IPF valuation allowance		176			326			2,743			884
	Call premium on 8.75% Notes		—			2,006			—			2,006
	Non-qualifying interest rate swaps		262			(157	)		190			(240	)
		$	(736	)	$	3,148		$	3,079		$	5,070
Cumulative effect of change in accounting principle (net of tax)		$	—		$	—		$	—		$	4,491

Comparison of 2002 to 2003

Quarters Ended September 30, 2002 and 2003

     Net income in the third quarter of 2003 totaled $16.7 million, compared to $9.2 million in the prior year period. The third quarter of 2003 includes a tax expense of $9.0 million versus a tax expense in the prior year period of $386,000. 2003 includes an $18.6 million gain on retirement of securities versus a gain of $1.1 million in the prior year. Production increased to 159.2 Mmcfe per day, a 5% increase from the prior year period. The production increase was due primarily to the recent success of the Company’s drilling program. Revenues also increased due to a 10% increase in average realized prices to $3.81 per mcfe. The average prices received for oil increased 8% to $23.76 per barrel, increased 9% for gas to $3.81 per mcf and increased 31% for NGLs to $17.64 per barrel. Production expenses increased 6% to $11.1 million as a result of higher production taxes. Production taxes averaged $0.10 per mcfe in 2002 versus $0.16 per mcfe in 2003. Production taxes are paid on market prices not on hedged prices. Operating costs, including production taxes, per mcfe produced averaged $0.76 in 2003 versus $0.76 in 2002.

     Transportation and processing net revenues declined 19% to $841,000 in 2003 with increased gas marketing expenses and lower transportation revenues. IPF recorded income of $297,000, a decrease of $1.0 million from the 2002 period due to a smaller portfolio balance. 2002 IPF expenses included a $176,000 increase in the valuation allowance adjustment. IPF expenses in 2003 include a $326,000 increase in the valuation allowance. During the quarter ended September 30, 2003, IPF expenses included $222,000 of administrative costs and $30,000 of interest, compared to prior year period administrative expenses of $391,000 and interest of $241,000.

     Exploration expense increased $1.8 million to $3.6 million in 2003 primarily due to higher seismic expense ($1.1 million) and, to a lesser extent, dry hole costs ($281,000). General and administrative expenses increased $2.4 million in the quarter with higher mark-to-market expense relating to the deferred compensation plan and higher salaries and wages. The mark-to-market deferred compensation adjustment included in general and administrative expense was $898,000 in the three months ended September 30, 2003 versus income of $1.2 million in the same period of the prior year. (See Note 11 to the consolidated financial statements).

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     Other income reflected a loss of $125,000 in the third quarter of 2002 and income of $723,000 in the third quarter of 2003. The 2003 period included $1.1 million of ineffective hedging gains partially offset by $275,000 of losses on asset sales and a $142,000 loss on abandonment liability. The 2002 period included $419,000 of ineffective hedging losses partially offset by $266,000 of gains on asset sales. Interest expense increased 24% to $7.7 million primarily due to the $2.0 million call premium on the 8.75% Notes and the write off of unamortized debt issuance costs included in the third quarter of 2003. Total debt was $364.7 million and $279.9 million at September 30, 2002 and 2003, respectively. The average interest rates (excluding hedging) were 5.3% and 4.6%, respectively, at September 30, 2002 and 2003 including fixed and variable rate debt.

     DD&A increased 11% from the third quarter of 2002 with higher production and an additional $1.2 million of accretion expense related to the adoption of the new accounting principle (see Note 3 to the consolidated financial statements). The DD&A rate per mcfe for the third quarter of 2003 was $1.49, a $0.07 increase from the rate for the third quarter of 2002. This increase is due to higher accretion expense ($0.08 per mcfe) offset by slightly lower depreciation. The DD&A rate is determined based on year-end reserves and the net book value associated with them and, to a lesser extent, depreciation on other assets owned.

     Income taxes reflected an expense of $386,000 in the third quarter of 2002 versus $9.0 million in the third quarter of September 30, 2003. (See Note 13 to the consolidated financial statements).

Nine Months Ended September 30, 2002 and 2003

     Net income for the nine months ended September 30, 2003 totaled $30.8 million compared to $20.9 million for the comparable period of 2002. The nine months ended September 2003 includes tax expenses of $15.6 million versus a tax benefit of $4.5 million in the prior year. 2003 includes a gain of $18.7 million on retirement of securities versus a gain of $3.1 million in the prior year. 2003 also includes $4.5 million gain on adoption of a new accounting principle. Production for the nine months ended September 30, 2003 increased to 157.2 Mmcfe per day, an increase of 5% from the prior year period. The production increase was due to higher production in the Appalachian and Southwest divisions and higher production at West Cameron 45 somewhat offsetting natural production declines in other Gulf Coast wells. Revenues increased primarily due to higher prices which averaged $3.85 per mcfe. The average prices received for oil increased 5% to $23.51 per barrel, 13% for gas to $3.87 per mcf and 51% for NGLs to $18.76 per barrel. Production expenses increased 24% to $36.8 million as a result of higher production taxes, costs from new wells and higher workover costs in the Gulf of Mexico. Operating cost (including production taxes) per mcfe produced averaged $0.86 in 2003 versus $0.72 in 2002.

     Transportation and processing revenues increased 3% to $2.8 million. IPF recorded income of $1.3 million, a decrease of $2.2 million from 2002. IPF revenue declined from the previous year due to a smaller portfolio balance. 2002 IPF expenses included $2.7 million of unfavorable valuation allowance adjustments. IPF expenses for the nine months ended September 2003 included $884,000 of unfavorable valuation allowance adjustments. During the nine months ended September 30, 2003, IPF expenses included $689,000 of administrative costs and $191,000 of interest, compared to prior year period administrative expenses of $1.3 million and interest of $754,000.

     Exploration expense decreased $484,000 to $8.8 million, primarily due to lower dry hole costs ($2.2 million) partially offset by higher seismic costs ($1.5 million). General and administrative expenses increased 27% to $15.7 million in the nine months ended September 30, 2003 due to higher compensation related expenses and legal and other professional fees. The mark-to-market deferred compensation adjustment included in general and administrative expense is an expense of $71,000 in the nine months ended September 30, 2002 and $2.2 million in the comparable period of 2003.

     Other income reflected a loss of $3.4 million in 2002 and a loss of $262,000 in 2003. The 2002 period included $2.6 million of ineffective hedging losses and a $1.2 million write down of marketable securities. The 2003 period included a $178,000 million ineffective hedging loss and an $118,000 loss on the sale of assets. Interest expense increased 5% to $18.4 million with the $2.0 million call premium on the 8.75% Notes somewhat offset by lower outstanding debt and lower interest rates.

     DD&A increased 12% from the same period of the prior year with higher production and an additional $3.5 million of accretion expense related to the adoption of the new accounting principle. The per mcfe DD&A rate for the

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nine months ended September 30, 2003 was $1.49, a $0.10 increase from the rate for the same period of the prior year with higher accretion expense ($0.08 per mcfe) and higher amortization of unproved property.

     Income taxes reflected a benefit of $4.5 million in the nine months ended September 30, 2002 versus tax expenses of $15.6 million in the same period of 2003.

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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 an indicator of reasonably possible losses. This forward-looking information provides indicators of how the Company 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. The Company’s major market risk exposure is to oil and gas prices. Realized prices are primarily driven by worldwide prices for oil and spot market prices for North American 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, the Company receives a fixed price for its production and pays market prices to the counterparty. Hedging is intended to reduce the impact of oil and gas price fluctuations. In the second quarter of 2003, the hedging program was modified to include collars which assume a minimum floor price and predetermined ceiling price. 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 OCI. The gains and losses realized as a result of hedging are substantially offset in the cash market when the commodity is delivered. Of the $46.3 million unrealized pre-tax loss included in OCI at September 30, 2003, $30.8 million of losses would be reclassified to earnings over the next twelve month period if prices remained constant. The actual amounts that will be reclassified will vary as a result of changes in prices. The Company does not hold or issue derivative instruments for trading purposes.

     As of September 30, 2003, the Company had oil and gas swap hedges in place covering 60.0 Bcf of gas and 1.5 million barrels of oil. The Company also has collars covering 0.6 Bcf of gas at prices of $4.00-$6.75 and 0.6 million barrels of oil at prices of $24.00-$27.71. Their fair value, represented by the estimated amount that would be realized on termination, based on contract versus NYMEX prices, approximated a net unrealized pre-tax loss of $46.3 million at that date. These contracts expire monthly through December 2006. 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 as increases or decreases to oil and gas revenues in the period the hedged production is sold. Any ineffective portion of such hedges is recognized in earnings as it occurs. Net realized losses relating to these derivatives for the nine months ended September 30, 2003 were $53.5 million and net realized gains were $18.8 million for the nine months ended September 30, 2002.

     In the first nine months of 2003, a 10% reduction in oil and gas prices, excluding amounts fixed through hedging transactions, would have reduced revenue by $21.7 million. If oil and gas future prices at September 30, 2003 had declined 10%, the unrealized hedging loss at that date would have decreased $31.9 million.

     Interest rate risk. At September 30, 2003, the Company had $279.9 million of debt (including Trust Preferred Securities) outstanding. Of this amount, $114.0 million bore interest at fixed rates averaging 7.2%. Senior Credit Facility debt and the Great Lakes Credit Facility debt totaling $165.8 million bore interest at floating rates averaging 2.9%. At September 30, 2003 Great Lakes had interest rate swap agreements totaling $110.0 million (See Note 7), 50% of which is consolidated at the Company, which had a fair value loss (the Company’s share) of $880,000 at that date. A 1% increase or decrease in short-term interest rates would cost or save the Company approximately $1.1 million in annual interest expense.

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Item 4. CONTROLS AND PROCEDURES.

     As of the end of the period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Exchange Act Rule 13a-14(c) and Rule 15d-14(c). Based upon that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective in timely alerting them to material information relating to the Company (including its consolidated subsidiaries) required to be included in the Company’s periodic filings with the SEC. No significant changes in the Company’s internal controls or other factors that could affect these controls have occurred subsequent to the date of such evaluation.

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.

Item 2. Changes in Securities and Use of Proceeds

     (c)

     On September 23, 2003, the Company exchanged $10.2 million in cash and $50 million of the Company’s newly issued Convertible Preferred for $79.5 million of its Trust Preferred Securities. The sections of this Form 10-Q entitled “Part I-Item 1-Note (6)-5-3/4% Trust Preferred Securities-mandatorily redeemable securities of subsidiary” and “Part I-Item 1-Note (9)” are incorporated by reference into Part II-Item 2(c) of this Form 10-Q.

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Item 6. Exhibits and Reports on Form 8-K

               (a)  Exhibits:

3.1.1	Restated Certificate of Incorporation of Lomak Petroleum, Inc. (“Lomak”) (incorporated by reference to Exhibit 3.1.1 to the Range Resources Corporation (the “Company”) Form S-4 (File No. 333-108516) as filed with the Securities and Exchange Commission (the “SEC”) on September 4, 2003)
3.1.2	Certificate of Amendment to the Certificate of Incorporation dated June 20, 1997 (incorporated by reference to Exhibit 3.1.11 to the Company’s Form 10-Q (File No. 001-12209) as filed with SEC on August 6, 2003)
3.1.3	Certificate of Amendment to the Certificate of Incorporation of Lomak dated August 25, 1998 (incorporated by reference to Exhibit 3.1 to the Company’s Form S-8 (File No. 333-62439) as filed with the SEC on August 28, 1998)
3.1.4	Certificate of Amendment to the Certificate of Incorporation of the Company dated May 24, 2000 (incorporated by reference to Exhibit 3.1.12 to the Company’s Form 10-Q (File No. 001-12209) as filed with the SEC on May 7, 2003)
3.1.5*	Certificate of Correction to Certificate of Amendment to the Certificate of Incorporation of the Company filed with the Secretary of State of the State of Delaware on June 26, 1997
3.1.6*	Certificate of Correction to Certificate of Amendment to the Certificate of Incorporation of the Company filed with the Secretary of State of the State of Delaware on May 25, 2000
3.2.1*	Amended and Restated By-laws of the Company dated July 14, 2003
4.1.1	Form of 7-3/8% Senior Subordinated Note due 2013 (contained as an exhibit to Exhibit 4.1.2 hereto)
4.1.2	Indenture dated July 21, 2003 by and among the Company, as issuer, the Subsidiary Guarantors (as defined therein), as guarantors, and Bank One, National Association, as trustee (incorporated by reference to Exhibit 4.4.2 to the Company’s Form 10-Q (File No. 001-12209) as filed with the SEC on August 6, 2003)
4.1.3	Registration Rights Agreement dated July 21, 2003 by and between the Company and UBS Securities LLC, Banc One Capital Markets, Inc., Credit Lyonnais Securities (USA) Inc. and McDonald Investments Inc. (incorporated by reference to Exhibit 4.4.3 to the Company’s Form 10-Q (File No. 001-12209) as filed with the SEC on August 6, 2003)
4.2*	Certificate of Designation of the 5.90% Cumulative Convertible Preferred Stock of the Company
10.1.1	Fourth Amendment to Amended and Restated Credit Agreement dated July 15, 2003 by and among the Company, Bank One, NA, the Lenders (as defined therein), Bank One, NA, as Administrative Agent, Fleet National Bank, as Co-Documentation Agent, Fortis Capital Corp., as Co-Documentation Agent, JPMorgan Chase Bank, as Co-Syndication Agent, Credit Lyonnais, New York Branch, as Co-Syndication Agent, Banc One Capital Markets, Inc., as Joint Lead Arranger and Joint Bookrunner, and JPMorgan Securities, Inc., as Joint Lead Arranger and Joint Bookrunner (incorporated by reference to Exhibit 10.6.5 to the Company’s Form S-4 (File No. 333-108516) as filed with the SEC on September 4, 2003)
10.1.2*	Fifth Amendment to Amended and Restated Credit Agreement dated September 4, 2003 by and among the Company, Bank One, NA, the Lenders (as defined therein), Bank One, NA, as Administrative Agent, Fleet National Bank, as Co-Documentation Agent, Fortis Capital Corp., as Co-Documentation Agent, JPMorgan Chase Bank, as Co-Syndication Agent, Credit Lyonnais, New York Branch, as Co-Syndication Agent, Banc One Capital Markets, Inc., as Joint Lead Arranger and Joint Bookrunner, and JPMorgan Securities, Inc. as Joint Lead Arranger and Joint Bookrunner
31.1*	Certification by the President and Chief Executive Officer of the Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification by the Chief Financial Officer of the Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1*	Certification by the President and Chief Executive Officer of the Company Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2*	Certification by the Chief Financial Officer of the Company Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

* filed herewith

               (b)  Reports on Form 8-K

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On July 11, 2003, the Company filed a Current Report on Form 8-K, pursuant to Item 5 of Form 8-K, regarding the adoption of Statement of Financial Accounting Standards No. 145.

On July 11, 2003, the Company filed a Current Report on Form 8-K, pursuant to Item 9 of Form 8-K, announcing its second quarter of 2003 production volumes.

On July 17, 2003, the Company filed a Current Report on Form 8-K, pursuant to Item 5 of Form 8-K, regarding the proposed issuance and subsequent pricing of $100.0 million of senior subordinated notes due 2013.

On July 22, 2003, the Company filed a Current Report on Form 8-K, pursuant to Item 5 of Form 8-K, announcing the completion of the private placement of $100.0 million of 7-3/8% senior subordinated notes due 2013 and its election to redeem all of the outstanding 8-3/4% senior subordinated notes due 2007.

On August 7, 2003, the Company filed a Current Report on Form 8-K, pursuant to Item 9 of Form 8-K, furnishing the Company’s press release announcing its second quarter of 2003 results.

On August 21, 2003, the Company filed a Current Report on Form 8-K, pursuant to Item 5 of Form 8-K, announcing the completion of its previously announced redemption of its outstanding 8-3/4% senior subordinated notes due 2007.

On August 28, 2003, the Company filed a Current Report on Form 8-K, pursuant to Item 5 of Form 8-K, announcing the adoption of Statement of Financial Accounting Standards No. 143 and its effect on the twelve months ended 2000, 2001 and 2002.

On September 19, 2003, the Company filed a Current Report on Form 8-K, pursuant to Item 5 of Form 8-K, announcing its agreement to exchange $10.2 million in cash and $50.0 million of a new 5.9% cumulative convertible preferred stock for $79.5 million of its outstanding 5.75% trust convertible preferred securities.

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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 thereunto duly authorized.

RANGE RESOURCES CORPORATION
By:	/s/ ROGER S. MANNY
	Roger S. Manny
	Senior Vice President and Chief Financial Officer
	(Principal Financial Officer and duly authorized
	to sign this report on behalf of the Registrant)

November 4, 2003

39

EXHIBIT INDEX

Exhibit Number	Description of Exhibit
3.1.1	Restated Certificate of Incorporation of Lomak Petroleum, Inc. (“Lomak”) (incorporated by reference to Exhibit 3.1.1 to the Range Resources Corporation (the “Company”) Form S-4 (File No. 333-108516) as filed with the Securities and Exchange Commission (the “SEC”) on September 4, 2003)
3.1.2	Certificate of Amendment to the Certificate of Incorporation dated June 20, 1997 (incorporated by reference to Exhibit 3.1.11 to the Company’s Form 10-Q (File No. 001-12209) as filed with the SEC on August 6, 2003)
3.1.3	Certificate of Amendment to the Certificate of Incorporation of Lomak dated August 25, 1998 (incorporated by reference to Exhibit 3.1 to the Company’s Form S-8 (File No. 333-62439) as filed with the SEC on August 28, 1998)
3.1.4	Certificate of Amendment to the Certificate of Incorporation of the Company dated May 24, 2000 (incorporated by reference to Exhibit 3.1.12 to the Company’s Form 10-Q (File No. 001-12209) as filed with the SEC on May 7, 2003)
3.1.5*	Certificate of Correction to Certificate of Amendment to the Certificate of Incorporation of the Company filed with the Secretary of State of the State of Delaware on June 26, 1997
3.1.6*	Certificate of Correction to Certificate of Amendment to the Certificate of Incorporation of the Company filed with the Secretary of State of the State of Delaware on May 25, 2000
3.2.1*	Amended and Restated By-laws of the Company dated July 14, 2003
4.1.1	Form of 7-3/8% Senior Subordinated Note due 2013 (contained as an exhibit to Exhibit 4.1.2 hereto)
4.1.2	Indenture dated July 21, 2003 by and among the Company, as issuer, the Subsidiary Guarantors (as defined therein), as guarantors, and Bank One, National Association, as trustee (incorporated by reference to Exhibit 4.4.2 to the Company’s Form 10-Q (File No. 001-12209) as filed with the SEC on August 6, 2003)
4.1.3	Registration Rights Agreement dated July 21, 2003 by and between the Company and UBS Securities LLC, Banc One Capital Markets, Inc., Credit Lyonnais Securities (USA) Inc. and McDonald Investments Inc. (incorporated by reference to Exhibit 4.4.3 to the Company’s Form 10-Q (File No. 001-12209) as filed with the SEC on August 6, 2003)
4.2*	Certificate of Designation of the 5.90% Cumulative Convertible Preferred Stock of the Company
10.1.1	Fourth Amendment to Amended and Restated Credit Agreement dated July 15, 2003 by and among the Company, Bank One, NA, the Lenders (as defined therein), Bank One, NA, as Administrative Agent, Fleet National Bank, as Co-Documentation Agent, Fortis Capital Corp., as Co-Documentation Agent, JPMorgan Chase Bank, as Co-Syndication Agent, Credit Lyonnais, New York Branch, as Co-Syndication Agent, Banc One Capital Markets, Inc., as Joint Lead Arranger and Joint Bookrunner, and JPMorgan Securities, Inc., as Joint Lead Arranger and Joint Bookrunner (incorporated by reference to Exhibit 10.6.5 to the Company’s Form S-4 (File No. 333-108516) as filed with the SEC on September 4, 2003)
10.1.2*	Fifth Amendment to Amended and Restated Credit Agreement dated September 4, 2003 by and among the Company, Bank One, NA, the Lenders (as defined therein), Bank One, NA, as Administrative Agent, Fleet National Bank, as Co-Documentation Agent, Fortis Capital Corp., as Co-Documentation Agent, JPMorgan Chase Bank, as Co-Syndication Agent, Credit Lyonnais, New York Branch, as Co-Syndication Agent, Banc One Capital Markets., Inc, as Joint Lead Arranger and Joint Bookrunner, and JPMorgan Securities, Inc. as Joint Lead Arranger and Joint Bookrunner
31.1*	Certification by the President and Chief Executive Officer of the Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification by the Chief Financial Officer of the Company Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1*	Certification by the President and Chief Executive Officer of the Company Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2*	Certification by the Chief Financial Officer of the Company Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

* filed herewith