UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-Q

     (Mark one)

OR

Commission file number 0-9592

RANGE RESOURCES CORPORATION

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 o

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

56,945,673 Common Shares were outstanding on April 30, 2004.

Table of Contents

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” or “Range”). 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.

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RANGE RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS
(In thousands)

See accompanying notes.

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RANGE RESOURCES CORPORATION

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

See accompanying notes.

4

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited, in thousands)

See accompanying notes.

5

RANGE RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited, in thousands)

See accompanying notes.

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RANGE RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

(1) ORGANIZATION AND NATURE OF BUSINESS

     The Company is engaged in the exploration, development 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”). Range is a Delaware Corporation whose common stock is listed on the New York Stock Exchange.

     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 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 with remaining receipts reducing receivables. Although receivables are concentrated in the oil and gas industry, the Company does not view this as an unusual credit risk. The Company provides for allowance for doubtful accounts for specific receivables judged unlikely to be collected based on the age of the receivable, the Company’s experience with the debtor, potential offsets to the amount owed and economic conditions. The Company had allowances for doubtful accounts relating to its exploration and production of $1.0 million in each of the periods ended at March 31, 2004 and December 31, 2003, respectively.

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 and NGLs are converted to gas equivalent basis (“mcfe”) at the rate of six mcf per barrel. The depletion, depreciation and amortization (“DD&A”) rates were $1.38 and $1.51 per mcfe in the quarters ended March 31, 2004 and 2003, respectively. Unproved properties had a net book value of $10.3 million and $12.2 million at March 31, 2004 and December 31, 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 Statement

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of Financial Accounting Standards No. 144 “Accounting for Impairment or Disposal of Long-Lived Assets.” 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.

Transportation and Field Assets

     The Company’s gas transportation and 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 and are recorded as an offset to direct operating expenses. These revenues approximated $500,000 in each of the three month periods ended March 31, 2004 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.

Independent Producer Finance

     Historically, IPF acquired dollar denominated overriding 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 with the remaining receipts reducing receivables. Currently, all receipts are being recognized as a return of capital except for income received on investments having a zero book balance. Receivables classified as current represent the return expected within 12 months. The receivables are evaluated quarterly and provisions for uncollectible amounts are established based on a valuation of the royalty interest in the oil and gas properties. At March 31, 2004, the receivable balance was $16.5 million offset by a valuation allowance of $5.5 million for a net receivable balance of $11.0 million. At December 2003, the receivable balance was $22.2 million offset by a valuation allowance of $9.6 million for a net receivable balance of $12.6 million. The decline in the valuation allowance from December 2003 is due to the sale of certain investments, where the receivable amounts and the valuation allowance amounts were eliminated. 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 first quarter of 2004, IPF revenues of $33,000 were offset by $171,000 of interest and administrative expenses and a $529,000 increase in the valuation allowance. During the same period of the prior year, revenues of $539,000 were offset by $359,000 of interest and administrative expenses, and a $259,000 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.

Other Assets

     The cost of issuing debt is capitalized and included in other assets on the Company’s Consolidated Balance Sheets. 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 March 31, 2004 and December 31, 2003, these capitalized costs totaled $2.2 million and $2.4 million, respectively. At March 31, 2004, other assets included $2.2 million unamortized debt issuance costs, $578,000 of long-term deposits, $1.9 million of marketable securities held in a deferred compensation plan and a $5.6 million insurance claim receivable related to certain offshore properties. The insurance claim is under normal review by the insurance carrier and, therefore, full collection of the receivable is not assured.

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 March 31, 2004 and December 31, 2003 were not significant.

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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 the past, certain of the interest rate swaps, because of the 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 as such transactions are settled. Changes in the value of the ineffective portion of all open hedges are recognized in earnings as they occur. At March 31, 2004, the Company reflected an unrealized net pre-tax commodity hedging loss on its balance sheet of $96.3 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 $96.3 million unrealized pre-tax loss at March 31, 2004, $76.3 million of losses would be reclassified to earnings over the next twelve month period and $20.0 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 commodity hedging losses (changes in realized prices did not match the changes in the hedge price) of $1.6 million and gains of $804,000 for the three months ended March 31, 2004 and March 31, 2003, respectively. Interest expense includes ineffective interest hedging gains of $799,000 and losses of $71,000 for the three months ended March 31, 2004 and March 31, 2003, respectively. Unrealized hedging losses at March 31, 2004 are shown on the Company’s Consolidated Balance Sheets as net unrealized hedging losses of $96.6 million (including $268,000 of losses on interest rate swaps) and OCI losses of $58.0 million (net of taxes) (see Note 7).

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. Depletion of oil and gas properties is determined using estimates of proved oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including estimates of future recoverable reserves and commodity prices. Other estimates which may significantly impact the Company’s financial statements involve IPF receivables, deferred tax valuation allowances, fair value of derivatives and asset retirement obligations.

Recent Accounting Pronouncements

     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

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15, 2003 and are effective in 2004 for VIEs in which the Company holds a variable interest that it acquired prior to February 1, 2003. The Interpretation had no effect on the Company’s financial statements.

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 ended March 31, 2004 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):

(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 an asset retirement obligation in the period in which the liability is incurred, if a reasonable estimate of the obligation 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 asset retirement obligations recorded by the Company relate to the plugging and abandonment of oil and gas wells.

     The estimated liability is based on historical experience in plugging and abandoning wells, estimated remaining lives of those wells, 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

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abandonment requirements. At the time of abandonment, the Company will likely 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 three months ended March 31, 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.

     A reconciliation of the Company’s liability for plugging and abandonment costs for the three months ended March 31, 2004 and 2003 is as follows (in thousands):

(4) ACQUISITIONS AND DISPOSITIONS

     Acquisitions are accounted for as purchases, and accordingly, the results of operations are included in the Company’s Statements of Operations from the respective date of acquisition. Purchase prices are assigned to acquired assets and assumed liabilities based on their estimated fair value at acquisition. The Company purchased various properties for $3.3 million and $6.0 million during the three months ended March 31, 2004 and 2003, respectively. The purchases include $1.8 million and $5.0 million for proved oil and gas reserves, respectively, with the remainder representing unproved acreage.

     In December 2003, the Company purchased producing oil and gas properties covering 38,000 gross (32,000 net) acres of leases which are adjacent to the Company’s Conger Field properties in West Texas. The purchase price was $88.0 million and the Company recorded $81.0 million to oil and gas properties, $4.6 million to transportation and field assets and facilities, $207,000 to inventory and $2.1 million additional asset retirement obligations. This acquisition was funded through the bank credit facility.

     During the first quarter of 2004, the Company sold non-strategic properties for proceeds of $2.3 million. Proceeds from the disposal of miscellaneous properties depreciated on a group basis are credited to net book value with no immediate effect on income.

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(5) SUPPLEMENTAL CASH FLOW INFORMATION

(6) INDEBTEDNESS

     The Company had the following debt outstanding as of the dates shown below (in thousands) (interest rates at March 31, 2004, excluding the impact of interest rate swaps, are shown parenthetically):

     Interest paid in cash during the three months ended March 31, 2004 and 2003 totaled $6.4 million and $7.1 million, respectively. No interest expense was capitalized during the three months ended March 31, 2004 and 2003.

Senior Credit Facility

     In 2002, the Company entered into an amended and restated $225.0 million revolving bank facility (the “Senior Credit Facility”) which is secured by substantially all of the assets of the Company (excluding the assets of 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. At of March 31, 2004, the outstanding balance under the Senior Credit Facility was $171.1 million and there was $68.9 million of borrowing capacity available. Effective March 31, 2004, the borrowing base was increased from $225.0 million to $240.0 million and the commitment was increased from $225.0 million to $375.0 million. 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

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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. The Company may elect, from time to time, to convert all or any part of its 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 3.1% and 3.4% for the three months ended March 31, 2004 and 2003, respectively. A commitment fee is paid on the undrawn balance based on an annual rate of 0.375% to 0.50%. At March 31, 2004, the commitment fee was 0.375% and the interest rate margin was 1.75%. At April 30 2004, the interest rate (including applicable margin) was 3.3%.

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 March 31, 2004, the Company’s portion of the outstanding balance owed under the Great Lakes Credit Facility was $67.5 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 1.5% to 2.0% per annum depending on the amounts outstanding on the loan, plus all outstanding letters of credit, divided by the borrowing base. 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 March 31, 2004, 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 2.9% and 3.5% for the three months ended March 31, 2004 and 2003, respectively. After hedging (see Note 7), the rate was 5.3% and 6.0% for the three months ended March 31, 2004 and 2003, respectively. At April 30, 2004, the interest rate was 2.9% excluding hedges and 5.3% after hedging.

8-3/4% Senior Subordinated Notes due 2007

     In 1997, the Company sold $125 million of 8-3/4% Senior Subordinated Notes due 2007 (the “8-3/4% Notes”). In August 2003, the Company redeemed the outstanding 8-3/4% Notes at 102.9% of principal amount, plus accrued interest. The aggregate redemption price, including the premium, was $70.8 million.

7-3/8% Senior Subordinated Notes due 2013

     In July 2003, the Company issued $100.0 million of 7-3/8% Senior Subordinated Notes due 2013 (the “7-3/8% Notes”). The Company pays interest on the 7-3/8% Notes semi-annually each January and July. The 7-3/8% Notes mature in July 2013 and are guaranteed by certain of the Company’s subsidiaries (the “Subsidiary Guarantors”). The 7-3/8% Notes were issued at a discount which is amortized into interest expense over the life of the 7-3/8% Notes. 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 the plus accrued and unpaid interest. 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

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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 issued $55.0 million 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 mature in 2007 and are subject to redemption at the Company’s option, in whole or in part, at redemption prices from 102.0% of the principal amount as of March 31, 2004, 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. The 6% Debentures are unsecured general obligations and are subordinated to all of the Company’s senior indebtedness. During the three month period ended March 31, 2003, $880,000 of the 6% Debentures 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. On April 30, 2004, $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 5-3/4% Trust Convertible Preferred Securities (the “Trust Preferred Securities”). Each Trust Preferred Security was convertible at the holder’s option into shares of the Company’s common stock, at a conversion price of $23.50 per share. Distributions on the Trust Preferred Securities were recorded as interest expense. In September 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. In December 2003, the remaining Trust Preferred Securities were redeemed for cash.

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 March 31, 2004. Under the Senior Credit Facility, common and preferred dividends are permitted, subject to the provisions of the restricted payment basket. 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. In addition, there is a separate restricted basket that allows for the proceeds from the issuance of the 7-3/8% Notes to be used to repurchase junior securities. Approximately $39.5 million was available under the Senior Credit Facility’s restricted payment basket on March 31, 2004 and $5.5 million available under the separate restricted basket. The terms of the 7-3/8% Notes limit restricted payments (including dividends) to the greater of $20.0 million or a formula based on earnings since the issuance of the notes. The 7-3/8% Notes also include a separate restricted payments basket of $25.0 million to repurchase junior securities. At March 31, 2004, approximately $17.9 million was available under the 7-3/8% Notes restricted payments basket and $2.0 million under the separate basket.

(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.

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The following table sets forth the book and estimated fair values of financial instruments as of March 31, 2004 and December 31, 2003 (in thousands):

     A portion of future oil and gas sales is periodically hedged through the use of swap and collar contracts. Realized gains and losses on these instruments are reflected in the contract month being hedged as an adjustment to oil and gas revenue. At times, the Company seeks to manage interest rate risk 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 March 31, 2004, the Company had open hedging contracts covering 44.4 Bcf of gas at prices averaging $4.11 per Mmbtu, 1.1 million barrels of oil at prices averaging $25.65 per barrel and 0.6 million barrels of NGLs at prices averaging $20.84 per barrel. The Company also has collars covering 16.6 Bcf of gas at weighted averaged floor and cap prices of $4.25 to $6.47 per mcf and 1.6 million barrels of oil at weighted average floor and cap prices of $24.23 to $30.55 per barrel. The fair value, represented by the estimated amount that would be realized upon termination, based on a comparison of the contract prices and a reference price generally New York Mercantile Exchange (“NYMEX”) on March 31, 2004, was a net unrealized pre-tax loss of $96.3 million. The contracts expire monthly through December 2006. 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 decreased by $16.9 million and $25.9 million due to hedging in the three months ended March 31, 2004 and 2003, respectively. Other revenues in the Consolidated Statements of Operations were decreased for ineffective hedging losses of $1.6 million and gains of $804,000 in the three months ended March 31, 2004 and 2003, respectively.

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          The following schedule shows the effect of closed oil and gas hedges since January 1, 2003 (in thousands):

     Through Great Lakes, the Company uses interest rate swap agreements to manage the interest rate risk under the Great Lakes Credit Facility. 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 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 are recognized as an adjustment to interest expense during the period in which the cash flows related to the interest payments are made. The ineffective portion of the changes in fair value of the interest rate swaps is recorded in interest expense in the period incurred. Interest expense was decreased by $799,000 and increased by $71,000 for ineffective hedging gains and losses in the three months ended March 31, 2004 and 2003, respectively. At March 31, 2004, Great Lakes had seven interest rate swap agreements totaling $110.0 million, of which 50% is consolidated by 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 of 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 1.8% which expire in June 2006. The fair value of the swaps at March 31, 2004 was a net loss of $536,000, 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 $96.6 million and appear as short-term and long-term unrealized derivative gains and losses on the balance sheet. Hedging activities are conducted with major financial and commodities trading institutions which management believes are acceptable credit risks. At times, such risks may be concentrated with certain counterparties. The creditworthiness of the counterparties is subject to periodic review.

     The following table sets forth qualitative information of derivative instruments at March 31, 2004 (in thousands):

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(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, including 100 million shares of common stock and 10 million shares of preferred stock. Stockholders’ equity was $267.5 million at March 31, 2004. In September 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. Each share is non-voting. 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, cause the Convertible Preferred to convert, in whole but not in part, into 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, 2002 to March 31, 2004:

(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:

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     In 1999, shareholders approved a stock option plan (the “1999 Plan”) providing for the issuance of options of 1.4 million common shares. Subsequently, shareholders voted to increase the number of options issuable to 8.75 million. All options issued under the 1999 Plan through May 2002 vest over 4 years and have a maximum term of 10 years, while options issued after May 2002 vest over a three year period and have a maximum term of five years. During the three months ended March 31, 2004, 1.3 million options were granted to eligible employees at exercise prices ranging from $10.48 to $11.10 a share. At March 31, 2004, 4.3 million options were outstanding at exercise prices ranging from $1.94 to $11.10 a share.

     In 1994, shareholders approved the Outside Directors’ Stock Option Plan (the “Directors’ Plan”). In 2000, shareholders voted to increase 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 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 March 31, 2004, 204,000 options were outstanding under the Directors’ Plan at exercise prices ranging from $2.81 to $6.00 a share.

     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 the plan since 1999. Options issued under the 1989 Plan vested over a three year period and expire in ten years. At March 31, 2004, 148,650 options remained outstanding under the 1989 Plan at exercise prices ranging from $2.63 to $7.63 a share. The last of these options 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. In January 2004, all outstanding options were exercised and the plan was terminated.

     In total, approximately 4.7 million options were outstanding at March 31, 2004 at exercise prices of $1.94 to $11.10 a share as follows:

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     In 1997, shareholders approved a plan (the “Stock Purchase Plan”) authorizing the sale of 900,000 shares of common stock to officers, directors, employees and consultants. In 2001, shareholders voted to increase 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 $26,000 in the three months ended March 31, 2003. Through March 31, 2004, 1,377,319 shares have been sold under the Stock Purchase Plan. At March 31, 2004, there were no rights outstanding to purchase shares.

     During 2003, the Company issued 234,000 restricted shares of its common stock as a compensation to directors, officers and employees of the Company. The restricted share grants included 136,000 issued to directors and 98,000 to officers and employees with vesting over a three year period. The Company recorded compensation expense of $116,500 during the first three months ended March 31, 2004 related to these grants.

(11) DEFERRED COMPENSATION

     In 1996, the Board of the Company adopted a deferred compensation plan (the “Plan”). The Plan allows certain senior employees and directors to defer all or a portion of their salaries and bonuses and invests such amounts 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. The carrying value of the deferred compensation liability is adjusted to fair value each reporting period by a charge or credit to general and administrative expense 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 Consolidated Balance Sheets. 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 related to the Company stock held in the Rabbi Trust of $4.4 million and $386,000 in the three months ended March 31, 2004 and 2003, respectively.

(12) BENEFIT PLAN

     The Company maintains a 401(k) Plan that permits employees to contribute a portion of their salary, subject to Internal Revenue limitations, on a pre-tax basis. Historically, the Company has made discretionary contributions of its 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 2003, 2002 and 2001, the Company contributed common stock valued at $610,000, $602,000 and $554,000 at then market values, respectively, 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 and may, at any time, diversify out of the Company’s common stock based on their personal investment strategy.

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(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 March 31, 2004 and December 31, 2003 were as follows (in thousands):

     At December 31, 2003, deferred tax assets exceeded deferred tax liabilities by $9.0 million with $24.6 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, 2003. At March 31, 2004, deferred tax assets exceeded deferred tax liabilities by $14.8 million with $34.3 million of deferred tax assets related to hedging losses in OCI.

     At December 31, 2003, the Company had regular net operating loss (“NOL”) carryovers of $188.8 million and alternative minimum tax (“AMT”) NOL carryovers of $161.0 million that expire between 2012 and 2021. At December 31, 2003, the Company had an AMT credit carryover of $2.4 million 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):

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     Options to purchase 19,500 shares and 2.6 million shares of common stock were outstanding but not included in the computations of diluted net income per share for the three months ended March 31, 2004 and 2003, respectively, because the exercise prices of the options were greater than the average market price of the common shares and would be anti-dilutive to the computations. The 6% Debentures and the 5.9% Preferred were also not included because their inclusion would have been anti-dilutive.

(15) MAJOR CUSTOMERS

     The Company markets its production on a competitive basis. Gas is sold under various types of arrangements ranging from short-term contracts that are cancelable within 30 days or less to life of well contracts. 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 and may be changed on 30 days notice. For the three months ended March 31, 2004, three customers, Duke Energy Field Services, Inc., ConocoPhillips Company and Louis Dreyfus Natural Gas Corp., accounted for 16%, 13% and 13%, 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):

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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 three months ended March 31, 2004 and 2003 (in thousands):

(18) GAIN ON RETIREMENT OF SECURITIES

     In the first quarter of the 2003, $400,000 of the Trust Preferred Securities were repurchased for cash and $880,000 of the 6% Debentures was exchanged for common stock. A gain of $150,000 was recorded on the cash transaction and a $465,000 conversion expense was recorded on the exchange transaction.

(19) SUBSEQUENT EVENT

     On April 30, 2004, the Company announced the acquisition of a privately held company owning producing oil and gas properties in the Permian Basin for $22.5 million. The Company does not expect the acquisition to have a material impact on the Company’s business or results of operations.

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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 what is reported in the financial statements and related footnote disclosures. 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, fair value of derivatives, asset retirement obligations, the deferred compensation plan, contingencies and litigation 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.

Property, Plant and Equipment

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

     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 and impairments to value are charged to expense.

     The Company monitors its long-lived assets recorded in Property, plant and equipment in the Consolidated Balance Sheet to insure 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

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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.

Derivatives

     The Company uses commodity derivative contracts to manage its exposure to oil and gas price volatility. The Company accounts for its commodity derivatives in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”). 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. This may result in significant volatility to current period income. For derivatives qualifying as hedges, the effective portion of any changes in fair value is recognized in stockholders’ equity as other comprehensive income (“OCI”) and then reclassified to earnings when the transaction is consummated. This may result in significant volatility in stockholders’ equity. The fair value of open hedging contracts is an estimated amount that could be realized upon termination.

     The commodity derivatives used by the Company include commodity swaps and collars. While there is a risk that the financial benefit of rising prices may not be captured, management believes the benefits of stable and predictable cash flow are important. Among these benefits are: more efficient utilization of existing personnel and planning for future staff additions, the flexibility to enter into long term projects requiring substantial committed capital, smoother and more efficient execution of the Company’s ongoing drilling and production enhancement programs, more consistent returns on invested capital, and better access to bank and other credit markets. Through Great Lakes, the Company also has interest rate swap agreements to protect against the volatility of variable interest rates under its credit facility.

Asset Retirement Obligations

     The Company has significant obligations to remove tangible equipment and restore land or seabed at the end of oil and gas production operations. The Company’s removal and restoration obligations are primarily associated with plugging and abandoning wells and removing and disposing of offshore oil and gas platforms. Estimating the future asset removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as well as regulatory, political, environmental, safety and public relations considerations.

     Asset retirement obligations are not unique to the Company or to the oil and gas industry and in 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations,” (“SFAS 143”). The Company adopted this statement effective January 1, 2003, as discussed in Note 4 to the Consolidated Financial Statements. SFAS 143 significantly changed the method of accruing for costs an entity is legally obligated to incur related to the retirement of fixed assets (“asset retirement obligations” or “ARO”). Primarily, the new statement requires the Company to record a separate liability for the discounted present value of the Company’s asset retirement obligations, with an offsetting increase to the related oil and gas properties on the Company’s Consolidated Balance Sheet.

     Inherent in the present value calculation are numerous assumptions and judgments including the ultimate retirement costs, inflation factors, credit adjusted discount rates, timing of retirement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. In addition, increases in the discounted ARO liability resulting from the passage of time will be reflected as accretion expense in the Consolidated Statement of Operations.

     SFAS 143 required a cumulative adjustment to reflect the impact of implementing the statement had the rule been in effect since inception. The Company, therefore, calculated the cumulative accretion expense on the ARO

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liability and the cumulative depletion expense on the corresponding property balance. The sum of this cumulative expense was compared to the depletion expense originally recorded. Because the historically recorded depletion expense was higher than the cumulative expense calculated under SFAS 143, the difference resulted in a $4.5 million gain, net of tax, which the Company recorded as cumulative effect of change in accounting principle on January 1, 2003.

Deferred 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 2003, deferred tax assets exceeded deferred tax liabilities by $9.0 million with $24.6 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. Currently, none of the consolidated tax returns of the Company are under audit or review by the IRS.

Contingent Liabilities

     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.

Bad Debt Expense

     The Company periodically assesses the recoverability of all material trade and other receivables to determine their collectability. At IPF, receivables are evaluated quarterly and provisions for uncollectible amounts are established. Such provisions for uncollectible amounts are recorded when management believes that a receivable is not recoverable based on current estimates of expected discounted cash flows.

Revenues

     The Company recognizes revenues from the sale of products and services in the period delivered. Revenues are sensitive to changes in prices received for our products. A substantial portion of production is sold at prevailing market prices, which fluctuate in response to many factors that are outside of the Company’s control. Imbalances in the supply and demand for oil and natural gas can have dramatic effects on prices. Political instability and availability of alternative fuels could impact worldwide supply, while economic factors can impact demand. At IPF, payments believed to relate to return are recognized as income. Currently, all receipts are being recognized as a return of capital.

Other

     The Company records a write down of marketable securities when the decline in market value is considered to be other than temporary. Third party reimbursements for administrative overhead costs incurred by the Company

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in its role as operator of oil and gas properties are applied to reduce general and administrative expense. Salaries and other employment costs of those employees working on the Company’s exploration efforts are expensed as exploration expense. The Company does not capitalize general and administrative expense or interest expense.

Liquidity and Capital Resources

     During the three months ended March 31, 2004, the Company spent $29.8 million on development, exploration, and acquisitions. During the three month period ending March 31, 2004, debt declined $9.6 million. At March 31, 2004, the Company had $913,000 in cash, total assets of $842.3 million and, a debt to capitalization ratio of 56.6%. Available borrowing capacity at March 31, 2004 was $68.9 million on the Senior Credit Facility and $90.0 million on the Great Lakes Credit Facility. Long-term debt at March 31, 2004 totaled $348.6 million, including $171.1 million of Senior Credit Facility debt, $67.5 million of Great Lakes Credit Facility debt, $98.4 million of 7-3/8% Notes and $11.6 million of 6% Debentures.

     Cash is required to fund capital expenditures necessary to offset inherent declines in production and proven reserves which is typical in the oil and gas industry. Future success in growing reserves and production will be highly dependent on capital resources available and the success of finding or acquiring additional reserves. The Company believes that net cash generated from operating activities and unused committed borrowing capacity under the credit facilities combined with the oil and gas price hedges currently in place will be adequate to satisfy near term financial obligations and liquidity needs. However, long-term 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 industry. A material drop in oil and gas prices or a reduction in production and reserves would reduce the Company’s ability to fund capital expenditures, reduce debt, meet financial obligations and remain profitable. 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 buy properties and sell production at prices which provide an attractive return and the highly competitive nature of the industry. The Company’s ability to expand its reserve base is, in part, dependent on obtaining sufficient capital through internal cash flow, borrowings or the issuance of debt or equity securities. There can be no assurance that internal cash flow and other capital sources will provide sufficient funds to maintain 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 March 31, 2004. Under the Senior Credit Facility, common and preferred dividends are permitted, subject to the terms of the restricted payment basket. 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 occurring since December 31, 2001. Approximately $39.5 million was available under the Senior Credit Facility’s restricted payment basket on March 31, 2004. The terms of the 7-3/8% Notes limit restricted payments (including dividends) to the greater of $20.0 million or a formula based on 50% of net income since October 1, 2003 and 100% of net cash proceeds from common stock issuances. Approximately $17.9 million was available under the 7-3/8% Notes restricted payment basket on March 31, 2004.

Cash Flow

     The Company’s principal sources of cash are operating cash flow, and bank borrowings and at times, issuance of debt and equity securities. The Company’s cash flow is highly dependent on oil and gas prices. The Company has entered into hedging swap agreements covering 44.4 Bcf of gas, 1.1 million barrels of oil and 0.6 million barrels of NGLs for the remainder of 2004 through the end of 2006. The Company also has collars covering 16.6 Bcf of gas and 1.6 million barrels of oil. The $26.6 million of capital expenditures in the three months ended March 31, 2004 was funded with internal cash flow. Net cash provided by operations for the three months ended March 31, 2004 and 2003 was $32.2 million and $16.1 million, respectively. Cash flow from operations was higher than the prior year due to higher prices and volumes partially offset by higher exploration and direct operating expenses. Net cash used in investing for the three months ended March 31, 2004 and 2003 was $23.2 million and $24.0 million, respectively. The 2004 period included $22.8 million of additions to oil and gas properties offset by $2.3 million of proceeds. The 2003 period included $20.2 million of additions to oil and gas properties. Net cash provided by (used in) financing for the three months ended March 31, 2004 and 2003 was ($8.7 million) and $7.9 million, respectively. During the first three months of 2004, total debt decreased $9.6 million. Senior Credit Facility

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debt declined $7.1 million and the Great Lakes Credit Facility decreased $2.5 million. The net decrease in debt was the result of excess cash flows.

Dividends to Stockholders

     On April 12, 2004, the Board of Directors declared a dividend of one cent per share on the Company’s common stock, payable on May 31, 2004 to stockholders of record at the close of business on May 14, 2004. Also, in January 2004, the Company paid common stock dividends of $565,000.

Capital Requirements

     The 2004 capital budget is approximately $126.0 million (excluding acquisitions) and based on current projections, the Company expects to fund its capital budget with internal cash flow. During the three months ended March 31, 2004, $29.8 million of development, exploration and acquisition spending was funded with internal cash flow.

Banking

     The Company maintains two separate revolving bank credit facilities: a $375.0 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 April 30, 2004, the Senior Credit Facility had a $240.0 million borrowing base of which $46.6 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 $92.0 million was available.

Hedging – Oil and Gas Prices

     The Company enters into hedging agreements to reduce the impact of oil and gas price volatility on its operations. At March 31, 2004, swaps were in place covering 44.4 Bcf of gas at prices averaging $4.11 per Mmbtu, 1.1 million barrels of oil at prices averaging $25.65 per barrel and 0.6 million barrels of NGLs at prices averaging $20.84 per barrel. The Company also has collars covering 16.6 Bcf of gas at weighted average floor and cap prices of $4.25 to $6.47 per mcf and 1.6 million barrels of oil at prices of $24.23 to $30.55 per barrel. Their fair value at March 31, 2004 (the estimated amount that would be realized on termination based on contract price and a reference price, generally NYMEX) was a net unrealized pre-tax loss of $96.3 million. 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 in other revenue as it occurs. Net decreases to oil and gas revenues from hedging were $16.9 million and $25.9 million for the three months ended March 31, 2004 and 2003, respectively.

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     At March 31, 2004, the following commodity derivative contracts were outstanding:

Interest Rates

     At March 31, 2004, the Company had $348.6 million of debt outstanding. Of this amount, $110.0 million bore interest at fixed rates averaging 7.2%. Senior Credit Facility debt and Great Lakes Credit Facility debt totaling $238.6 million bore interest at floating rates which averaged 2.9% at March 31, 2004. At times, the Company enters into interest rate swap agreements to limit the impact of interest rate fluctuations on its floating rate debt. At March 31, 2004, 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 expires in June 2005 and $35.0 million at 1.8% which expire in June 2006. The fair value of the swaps, based on then current quotes for equivalent agreements at March 31, 2004 was a net loss of $536,000, of which 50% is consolidated at the Company. The 30 day LIBOR rate on March 31, 2004 was 1.1%.

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 three months of 2004, the Company received an average of $32.15 per barrel of oil and $5.21 per mcf of gas before hedging compared to $31.44 per barrel of oil and $6.08 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 2003, the Company experienced a modest overall increase in 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 2004.

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Results of Operations

     Volumes and sales data:

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     The following table identifies certain items included in the results of operations and is presented to assist in comparing the first quarter 2004 to the same period of the prior year. The table should be read in conjunction with the following discussions of results of operations (in thousands):

Comparison of 2004 to 2003

Overview

     The first quarter of 2004 resulted in a quarter of solid production growth derived from our successful drilling program and a full quarter of production from the December 2003 Conger Field acquisition. Production was 15% higher than the first quarter of last year and 7.7% higher than the previous quarter. Realized oil and gas prices were 3% higher in the first quarter of 2004 when compared to the first quarter of 2003.

     The Company spent approximately $30 million during the first quarter of 2004 as part of our $126 million capital spending program (excluding acquisitions). Drilling success was achieved in each of the Company’s divisions during the first quarter of 2004 and the quarter ended with fifteen rigs running. Debt decreased $9.6 million during the first quarter of 2004 through the application of operating cash flow and proceeds of $2.3 million from the sale of non-strategic producing properties. Cash operating expenses decreased from the same quarter of the prior year, but prices of some oil field goods and services, particularly tubular goods, have noticeably increased. The Company’s basic business strategy of pursuing consistent drill bit growth supplemented by complementary acquisitions remains in place and is evident in the first quarter of 2004 operating and financial performance.

Quarters Ended March 31, 2004 and 2003

     Net income in the first quarter of 2004 totaled $6.6 million, compared to $9.5 million in the prior year period. The first quarter of 2003 includes a favorable effect of $4.5 million on adoption of a new accounting principle. Production increased to 177.4 Mmcfe per day, a 15% increase from the prior year period. The production increase was due primarily to the December 2003 Conger Field acquisition and the recent success of the Company’s drilling program. Oil and gas revenues also increased due to a 3% increase in average realized prices to $4.05 per mcfe. The average prices realized for oil increased 3% to $24.38 per barrel, increased 5% for gas to $4.15 per mcf and decreased 6% for NGLs to $18.99 per barrel. Production expenses increased 5% to $10.0 million as a result of higher workover expenses and additional costs related to the Conger Field properties acquired in December 2003. Production expenses (excluding production taxes) per mcfe produced averaged $0.62 in 2004 versus $0.69 in 2003. Production taxes averaged $0.26 per mcfe in 2004 versus $0.25 per mcfe in 2003. Production taxes are paid on market prices not on hedged prices.

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     Transportation and gathering net revenues are reflected net of expenses. Total net revenues declined 54% to $467,000 in 2004. The major components of the decline include lower transportation and marketing revenues ($283,000), higher marketing expenses ($64,000), additional gas transportation system employee expense related to the Conger Field acquisition ($196,000) and higher gas processing expenses ($59,000). Gain on retirement of securities in 2003 includes $150,000 gain on the sale of $400,000 of Trust Preferred Securities offset by a $465,000 conversion expense related to an $880,000 exchange of 6% Debentures.

     Other income reflected a loss of $2.3 million in the first quarter of 2004 versus income of $849,000 in the first quarter of 2003. The 2004 period includes $1.6 million of ineffective hedging losses and $192,000 loss on asset retirement obligations. Other income for 2004 also includes IPF revenues of $33,000 offset by $169,000 of administrative costs, $1,600 of interest and $529,000 increase to the valuation account. Other income in the 2003 period included $804,000 of ineffective hedging gains and $88,000 of gains on asset sales. Other income for 2003 also included IPF revenues of $539,000 offset by $258,000 of administrative costs, $101,000 of interest and a $259,000 increase in the valuation allowance.

     Exploration expense increased $1.1 million to $3.6 million in 2004 due to higher dry hole costs ($829,000) and higher seismic costs ($126,000). General and administrative expenses increased $4.0 million in the quarter with higher non-cash mark-to-market expense relating to the deferred compensation plan. The mark-to-market deferred compensation adjustment included in general and administrative expense was $4.4 million in the three months ended March 31, 2004 versus $386,000 in the same period of the prior year. (See Note 11 to the consolidated financial statements).

     Interest expense decreased 25% to $4.1 million primarily due to lower debt balances, interest rates and higher gains on ineffective interest hedging. Total debt was $348.6 million and $374.8 million at March 31, 2004 and 2003, respectively. The average interest rates, including fixed and variable rate debt (excluding hedging), were 4.3% and 5.0% at March 31, 2004 and 2003, respectively.

     DD&A increased 6% periods from the first quarter of 2003 due to higher production. Accretion expense of $1.1 million is included in DD&A in each of the three month periods ending March 31, 2004 and 2003. The DD&A rate per mcfe for the first quarter of 2004 was $1.38, a $0.13 decrease from the rate for the first quarter of 2003. The decrease is due to lower amortization of unproved property ($0.02), lower accretion expense ($0.01) and lower average depletion rates ($0.10). The DD&A rate is determined based on year-end reserves and the associated net book value and, to a lesser extent, depreciation on other assets owned.

     Income taxes reflected an expense of $3.9 million in the first quarter of 2004 versus $4.1 million in the first quarter of 2003. The first quarter of 2003 included $917,000 deferred tax expense associated with prior periods’ percentage depletion carryover.

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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 $96.3 million unrealized pre-tax loss included in OCI at March 31, 2004, $76.3 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 March 31, 2004, the Company had oil and gas swap hedges in place covering 44.4 Bcf of gas, 1.1 million barrels of oil and 0.6 million barrels of NGLs at prices averaging $4.11 per Mmbtu, $25.65 per barrel and $20.84 per barrel, respectively. The Company also has collars covering 16.6 Bcf of gas at weighted average floor and cap prices of $4.25 and $6.47 per mcf and 1.6 million barrels of oil at weighted average floor and cap prices of $24.23 to $30.55 per barrel. 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 $96.3 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 three months ended March 31, 2004 were $16.9 million and $25.9 million for the three months ended March 31, 2003.

     In the first three months of 2004, a 10% reduction in oil and gas prices, excluding amounts fixed through hedging transactions, would have reduced revenue by $8.2 million. If oil and gas future prices at March 31, 2004 had declined 10%, the unrealized hedging loss at that date would have decreased $37.8 million.

     Interest rate risk. At March 31, 2004, the Company had $348.6 million of debt outstanding. Of this amount, $110.0 million bore interest at fixed rates averaging 7.2%. Senior Credit Facility debt and the Great Lakes Credit Facility debt totaling $238.6 million bore interest at floating rates averaging 2.9%. At March 31, 2004 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 $268,000 at that date. A 1% increase or decrease in short-term interest rates would cost or save the Company approximately $1.8 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 management, including its Chief Executive Officer and Chief Financial Officer, of the effectiveness of the Company’s disclosure controls and procedures (as defined in 13a-15(e) of the Securities Exchange Act of 1934 (the “Exchange Act”)). Based on that evaluation, the Chief Executive Officer and 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 this report. There were no changes in the Company’s internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the Company’s last fiscal quarter that have materially affected or are reasonably likely to materially affect the Company’s internal control over financial reporting.

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

     None.

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Item 6. Exhibits and Reports on Form 8-K

     (a) Exhibits:

     (b) Reports on Form 8-K

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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.

May 4, 2004

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EXHIBIT INDEX

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