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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended March 31, 2004

Or

For the transition period from              to             

Commission File Number: 1-7940

Goodrich Petroleum Corporation

(Exact name of registrant as specified in its charter)

(713) 780-9494

(Registrant’s telephone number, including area code)

None

(Former name, former address and former fiscal year, if changed since last report.)

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.    x  Yes    ¨  No

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

At May 12, 2004, there were 19,127,289 shares of Goodrich Petroleum Corporation common stock outstanding.

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GOODRICH PETROLEUM CORPORATION

INDEX TO FORM 10-Q

March 31, 2004

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets

See notes to consolidated financial statements.

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets (Continued)

See notes to consolidated financial statements.

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Statements of Operations

(Unaudited)

See notes to consolidated financial statements.

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(Unaudited)

See notes to consolidated financial statements.

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Statements of Stockholders’ Equity and Comprehensive Income

Three Months Ended March 31, 2004 and 2003

(Unaudited)

See notes to consolidated financial statements.

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

March 31, 2004 and 2003

(Unaudited)

NOTE A - Basis of Presentation

The consolidated financial statements of Goodrich Petroleum Corporation (“Goodrich” or “the Company”) included in this Form 10-Q have been prepared, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission and, accordingly, certain information normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States has been condensed or omitted. The consolidated financial statements reflect all normal recurring adjustments that, in the opinion of management, are necessary for a fair presentation.

The accompanying consolidated financial statements of the Company should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2003.

The results of operations for the three-month period ended March 31, 2004 are not necessarily indicative of the results to be expected for the full year.

Restatement of 2003 Financial Statements

In the course of preparing its 2003 year-end financial statements, the Company discovered a systematic error in the calculations of its non-cash depletion, depreciation and amortization expense since 1997. Essentially, the Company had been allocating the acquisition and development costs of its oil and gas properties over total proved reserves in each field rather than segregating the costs between those costs to be allocated over proved developed reserves versus those costs to be allocated over total proved reserves. Accordingly, the Company has restated its previously reported depletion, depreciation and amortization expense for the three months ended March 31, 2003. Such restated amounts reflect reallocations of the purchase price of three oil and gas property acquisitions completed prior to January 1, 2001, based upon analyses of contemporaneous documentation from the time of the acquisitions. The tax-effected amounts of the adjustments resulted in changes in the Company’s previously reported Statement of Operations as follows:

The tax-adjusted cumulative effect of the error on non-cash depletion, depreciation and amortization expense in years prior to December 31, 2002 resulted in a reduction of stockholders’ equity as of January 1, 2003 in the amount of $2,199,077. The restatement adjustments had no impact on cash flow from operating, investing or financing activities.

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NOTE B – New Accounting Pronouncements

Effective January 1, 2003, the Company adopted SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability must be recorded in the periods in which the obligation meets the definition of a liability, which is generally when the asset is placed in service. Prior to the adoption of SFAS No. 143, the Company recorded liabilities for the abandonment of oil and gas properties only in its two largest fields, with such liabilities amounting to $4,881,000 as of December 31, 2002. In accordance with the transition provisions of SFAS No. 143, the Company recorded an adjustment to recognize additional estimated liabilities for the abandonment of oil and gas properties, as of January 1, 2003, in the amount of $1,408,000, and additional oil and gas properties, net of accumulated depletion, depreciation and amortization, in the amount of $1,092,000. Any subsequent difference between costs incurred upon settlement of an asset retirement obligation and the recorded liability will be recognized as a gain or loss in the Company’s earnings. To recognize the cumulative effect of this change in accounting principle, the Company recorded a charge to earnings as of January 1, 2003 in the amount of $205,000, reflecting the $316,000 difference between the adjustments to the liability and asset accounts, net of the related income tax effect. For the three months ended March 31, 2004 and 2003, the Company recorded the following activity in the abandonment liability:

In April 2003, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133, Accounting for Derivatives and Hedging Activities. This statement (1) clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative, (2) clarifies when a derivative contains a financing component, and (3) amends the definition of an underlying derivative to conform to Financial Accounting Standards Board Interpretation No. 45. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003, with all provisions applied prospectively. The Company adopted SFAS No. 149, effective July 1, 2003, and the adoption had no impact on its financial statements.

In July 2003, the FASB undertook to review whether mineral interests in properties (mineral leases) held by oil and gas companies should be recorded and disclosed as intangible assets under the guidance of SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets. The FASB is considering whether an oil and gas company’s investment in mineral leases should be classified as intangible assets. SFAS No. 141 and SFAS No. 142 established new accounting guidelines for both

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finite lived intangible assets and indefinite lived intangible assets. Under SFAS No. 141 and SFAS No. 142, intangible assets should be separately reported on the balance sheet, with accompanying disclosures in the notes to the financial statements. SFAS No. 142 does not change the accounting prescribed in SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, and is silent about whether its disclosure provisions apply to oil and gas companies. The Company does not believe that SFAS No. 141 and SFAS No. 142 change the classification and disclosure of oil and gas mineral leases and it continues to classify these assets as part of Property and Equipment in the Consolidated Balance Sheet and it does not provide the additional disclosures for these assets. The EITF has added the discussion of oil and gas mineral leases to its agenda, which may result in a change in the recording and disclosure of oil and gas mineral leases. Should the EITF determine that oil and gas mineral leases are intangible assets, the Company would reclassify $7,374,000 and $6,409,000 as intangible undeveloped mineral interests at March 31, 2004 and December 31, 2003, respectively. In addition, a reclassification of $6,160,000 and $5,879,000 would be made as intangible developed mineral interests at March 31, 2004 and December 31, 2003, respectively. Both intangible assets would be presented net of accumulated amortization. Historically, undeveloped mineral leases have been amortized over the life of the lease period, while developed mineral leases have been amortized using the units of production method over the expected life of proved reserves. The amounts included herein are based on the Company’s understanding of the issue on the EITF’s agenda. If all mineral leases associated with oil and gas properties are deemed to be intangible assets in accordance with SFAS No. 141 and SFAS No. 142 by the EITF:

In March 2004, the FASB issued an exposure draft on accounting for stock-based compensation. The exposure draft reflects the FASB’s tentative conclusion that the fair value of stock options should be expensed in companies’ financial statements for years ending after December 31, 2004. The exposure draft also includes the FASB’s tentative decisions regarding how equity-based awards are likely to be valued, expensed, and classified. The Company will continue to monitor developments with respect to the exposure draft to determine the potential impact on its financial statements.

NOTE C – Senior Credit Facility

On November 9, 2001, the Company established a three-year $50,000,000 senior credit facility with BNP Paribas, with an initial borrowing base of $25,000,000. In December 2003, the borrowing base was redetermined to be $28,000,000 and BNP Paribas and the Company agreed to extend the term of the senior credit facility for an additional two years, subject to periodic redeterminations of the borrowing base. As extended, the credit facility will mature on December 29, 2006. Borrowings outstanding under the senior credit facility as of March 31, 2004 were $19,000,000.

Interest on borrowings under the senior credit facility accrue at a rate calculated, at the option of the Company, as either the BNP Paribas base rate plus 0.00% to 0.50%, or LIBOR plus 1.50%—2.50%,

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depending on borrowing base utilization. Interest on LIBOR-rate borrowings is due and payable on the last day of its respective interest period. Accrued interest on each base-rate borrowing is due and payable on the last day of each quarter. The credit facility requires that the Company pay a 0.375% per annum commitment fee, payable in quarterly installments based on the Company’s borrowing base utilization. Prior to maturity, no payments are required so long as the maximum borrowing base amount exceeds the amounts outstanding under the credit facility. The credit facility requires the Company to monitor tangible net worth and maintain certain financial statement ratios at certain levels. As of March 31, 2004, the Company was in compliance with all such requirements. Substantially all the Company’s assets are pledged to secure the senior credit facility.

As indicated in Note D, the Company entered into three separate interest rate swaps with BNP Paribas in February 2003, covering a three year period commencing in February 2003, and in February 2004, the Company entered into another interest rate swap with BNP Paribas, covering a one year period commencing in February 2006.

NOTE D – Hedging Activities

The Company utilizes commodity hedges in the form of fixed price swaps, whereby the Company receives a fixed price and pays a floating price based on NYMEX quoted prices. As of March 31, 2004, the Company’s open forward position on its outstanding natural gas and crude oil hedging contracts and its interest rate swap contracts, all of which were with BNP Paribas, were as follows:

Natural Gas

3,000 MMBtu per day “swap” at fixed price of $5.00 for April 2004 through December 2004; and

3,000 MMBtu per day “swap” at fixed price of $5.41 for April 2004 through October 2004

Crude Oil

700 barrels of oil per day “swap” at fixed price of $28.59 for April 2004 through June 2004; and

300 barrels of oil per day “swap” at fixed price of $30.92 for April 2004 through June 2004; and

700 barrels of oil per day “swap” at fixed price of $28.20 for July 2004 through December 2004; and

300 barrels of oil per day “swap” at fixed price of $30.25 for July 2004 through December 2004

The fair value of the natural gas and oil hedging contracts in place at March 31, 2004, resulted in a liability of $2,466,081. As of March 31, 2004, $1,555,093 (net of $837,357 in income taxes) of deferred losses on derivative instruments accumulated in other comprehensive income are expected to be reclassified into earnings during the next twelve months. In the three months ended March 31, 2004, $382,015 in realized losses (net of $205,701 in income taxes) was reclassified from accumulated other comprehensive income to oil and gas sales as the cash flow of the hedged items was recognized. For the three months ended March 31, 2004 and 2003, the Company’s earnings were not materially affected by cash flow hedging ineffectiveness arising from the oil and gas hedging contracts. Subsequent to March 31, 2004, the Company entered into the following natural gas and crude oil hedging contracts with BNP Paribas:

3,000 MMBtu per day “swap” at fixed price of $6.20 for November 2004 through December 2004; and

6,000 MMBtu per day “swap” at fixed price of $6.27 for January 2005 through March 2005; and

500 barrels of oil per day “swap” at fixed price of $33.28 for January 2005 through March 2005

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Interest Rate Swaps

The Company has a variable-rate debt obligation that exposes the Company to the effects of changes in interest rates. To partially reduce its exposure to interest rate risk, the Company entered into three separate interest rate swaps with BNP Paribas in February 2003 covering a three year period which are designated as cash flow hedges (one of the interest rate swaps has now expired). The first interest rate swap, which had an effective date of February 26, 2003, expired on its maturity date of February 26, 2004, and was for $18,000,000 with a LIBOR swap rate of 1.53%. The second interest rate swap, which has an effective date of February 26, 2004 and a maturity date of November 8, 2004, is for $18,000,000 with a LIBOR swap rate of 2.25%. The third interest rate swap, which has an effective date of November 8, 2004 and a maturity date of February 26, 2006, is for $18,000,000 with a LIBOR swap rate of 3.46%. In February 2004, the Company entered into a fourth interest rate swap contract with BNP Paribas, which has an effective date of February 26, 2006 and a maturity date of February 26, 2007, for $23,000,000 with a LIBOR swap rate of 4.08%. The fair value of the interest rate swap contracts in place at March 31, 2004, resulted in a liability of $627,129. As of March 31, 2004, $153,390 (net of $82,595 in income taxes) of deferred losses on derivative instruments accumulated in other comprehensive income are expected to be reclassified into earnings during the next twelve months. In the three months ended March 31, 2004, $10,765 of previously deferred losses (net of $5,796 in income taxes) was reclassified from accumulated other comprehensive income to interest expense as the cash flow of the hedged items was recognized. For the three months ended March 31, 2004 and 2003, the Company’s earnings were not significantly affected by cash flow hedging ineffectiveness of interest rates.

NOTE E – Net Income Per Share

Net income was used as the numerator in computing basic and diluted income per common share for the three months ended March 31, 2004 and 2003. The following table reconciles the weighted-average shares outstanding used for these computations.

The computation of earnings per share for the three months ended March 31, 2004 and 2003 considered exercisable stock warrants and stock options to the extent that the exercise of such securities would have been dilutive. The computation of earnings per share for the three months ended March 31, 2004 and 2003 did not consider preferred stock which is convertible into shares of common stock because the effect of such conversion would have been antidilutive. In January 2004, the holders of 319,387 warrants to purchase common stock elected a cashless exercise of such warrants resulting in the issuance of 252,033 shares of the Company’s common stock and, in April 2004, the holders of 685,055 warrants to purchase common stock elected a cashless exercise of such warrants resulting in the issuance of 620,935 shares of the Company’s common stock (see Note G).

In February 2003, the Company issued 125,157 shares of its common stock to the holders of 1,016,500 outstanding stock options in exchange for the cancellation of such options (at the time of cancellation, the options were antidilutive). At the same time, the Company agreed to issue 150,000 restricted shares of its common stock, with a three year vesting period, to its employees under the Company’s restricted

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stock awards plan. The Company recorded a non-cash charge to earnings in February 2003 in the amount of $403,000 related to the issuance of shares in lieu of cancelled options. The granting of the restricted stock awards in February 2003 resulted in a charge to a contra equity account and a credit to additional paid-in capital in the amount of $483,000 related to the value of such awards. The contra equity account is being amortized to earnings as periodic non-cash charges to general and administrative expenses over the three year vesting period of the restricted stock awards and resulted in a non-cash charge to earnings in the first quarter of 2003 of approximately $27,000. In July and October 2003, the Company granted an additional 11,500 restricted share awards to its employees and recorded a charge to the contra equity account for the value of such shares in the amount of $54,000. For the three months ended March 31, 2004, the Company recorded non-cash charges to earnings for the amortization of the aggregate awards of 161,500 restricted shares in the amount of $75,000. The Company will be required to record recurring non-cash charges to earnings of approximately $42,000 per quarter, through the first quarter of 2006, related to the periodic vesting of the 2003 restricted stock awards.

In February 2004, the Company agreed to issue an additional 166,300 restricted shares of its common stock, with a three year vesting period, to its employees under the Company’s restricted stock awards plan. At the time of this grant, the Company recorded a charge to a contra equity account and a credit to additional paid-in capital in the amount of $1,134,000 related to the value of such awards. The contra equity account is being amortized to earnings as periodic non-cash charges to general and administrative expenses over the three year vesting period of the restricted stock awards and resulted in a non-cash charge to earnings in the first quarter of 2004 of approximately $59,000. The Company will be required to record incremental recurring non-cash charges to earnings of approximately $88,000 per quarter, through the first quarter of 2007, related to the periodic vesting of the 2004 restricted stock awards.

The Company applies APB Opinion No. 25 in accounting for its stock compensation plans and, accordingly, no compensation cost has been recognized for its stock options in the financial statements. Had the Company determined compensation cost based on the fair value at the grant date for its stock options under SFAS No. 123, net income for the three months ended March 31, 2004 and 2003 would have been reduced to the pro forma amounts indicated below.

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NOTE F - Commitments and Contingencies

The U.S. Environmental Protection Agency (“EPA”) has identified the Company as a potentially responsible party (“PRP”) for the cost of clean-up of “hazardous substances” at an oil field waste disposal site in Vermilion Parish, Louisiana. The Company estimates that the remaining cost of long-term clean-up of the site will be approximately $3.5 million, with the Company’s percentage of responsibility estimated to be approximately 3.05%. As of March 31, 2004, the Company had paid $321,000 in costs related to this matter and accrued $122,500 for the remaining liability. These costs have not been discounted to their present value. The EPA and the PRPs will continue to evaluate the site and revise estimates for the long-term clean-up of the site. There can be no assurance that the cost of clean-up and the Company’s percentage responsibility will not be higher than currently estimated. In addition, under the federal environmental laws, the liability costs for the clean-up of the site is joint and several among all PRPs. Therefore, the ultimate cost of the clean-up to the Company could be significantly higher than the amount presently estimated or accrued for this liability.

In connection with the acquisition of its Burrwood and West Delta fields, the Company secured a performance bond and established an escrow account to be used for the payment of obligations associated with the plugging and abandonment of the wells, salvage and removal of platforms and related equipment, and the site restoration of the fields. Required escrowed outlays included an initial cash payment of $750,000 and monthly cash payments of $70,000 beginning June 1, 2000 and continuing until June 1, 2005. The escrow agreement was amended in the fourth quarter of 2001 to suspend monthly cash payments and cap the escrow account at its current balance of $2,039,000.

On February 8, 2000, the Company commenced a suit against the operator and joint owner of the Lafitte field, alleging certain items of misconduct and violations of the agreements associated primarily with the

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joint acquisition of and unfettered access to a license to 3-D seismic data over the field. The operator counter-claimed against Goodrich on the grounds that Goodrich was obligated to post a bond to secure the plugging and abandonment obligations in the field. On November 1, 2002 the 125^th Judicial District Court of Harris County, Texas, ruled in favor of the Company stating (1) The Sale and Assignment between the Company and the operator assigned the same rights to the 3-D seismic data that the operator had pursuant to the operator’s data use license agreement from Texaco Exploration and Production, Inc. (“TEPI”); and (2) Also pursuant to the terms of the Sale and Assignment, Goodrich is required to post 49% of the bond liability to TEPI at such time that TEPI requests it. A jury trial commenced in September 2003. On October 29, 2003, the jury found the operator and joint owner to be in breach of the Sale and Assignment and awarded a wholly-owned subsidiary of the Company damages in the amount of $537,500. The jury’s verdict has not yet been certified by the trial judge nor has the court made a determination on the Company’s claim for reimbursement of legal fees and other expenses related to the case. The timing of the outcome of these rulings is presently uncertain, however, the Company does not anticipate that the rulings will ultimately have a significant adverse impact on the Company’s operations or financial position.

The Company is party to additional lawsuits arising in the normal course of business. The Company intends to defend these actions vigorously and believes, based on currently available information, that adverse results or judgments from such actions, if any, will not be material to its financial position or results of operations.

NOTE G – Funds Held Temporarily for Stockholders

Pursuant to a May 2003 stock purchase agreement, the Company acted as agent for certain stockholders to facilitate a sale of shares in January 2004 and April 2004. In that capacity, the Company temporarily received funds totaling $3,886,988 from the purchasing stockholders in December 2003, which are reflected on the Company’s December 31, 2003 balance sheet in both cash and current liabilities. In accordance with the stock purchase agreement, the Company transferred the funds to the selling stockholders in January 2004 upon the sale of the shares. Similarly, the Company temporarily received additional funds totaling $3,886,988 from the purchasing stockholders in March 2004, which are reflected on the Company’s March 31, 2004 balance sheet in both cash and current liabilities. In accordance with the stock purchase agreement, the Company transferred the funds to the selling stockholders in April 2004 upon the sale of the shares. A portion of the shares of common stock sold by the selling stockholders in both January 2004 and April 2004 resulted from the cashless exercise of warrants to purchase common stock (see Note E).

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Management’s Discussion and Analysis of Financial

Condition and Results of Operations

The following discussion is intended to assist in understanding the Company’s financial position, results of operations and cash flows for each of the periods presented. The Company’s Annual Report on Form 10-K for the year ended December 31, 2003 includes a description of the Company’s critical accounting policies and certain other detailed information that should be referred to in conjunction with the following discussion.

Changes in Results of Operations

Three months ended March 31, 2004 versus three months ended March 31,2003

Total revenues for the three months ended March 31, 2004 amounted to $10,925,000 compared to $7,078,000 for the three months ended March 31, 2003. Oil and gas sales for the three months ended March 31, 2004 were $10,827,000 compared to $6,747,000 for the three months ended March 31, 2003. This increase resulted from a 23% increase in oil and gas production volumes, due to several successful well completions since the first quarter of 2003, as well as higher average prices for oil and gas. Additionally, oil and gas revenues in the first quarter of 2004 include sales of natural gas liquids in the amount of $231,000, resulting from processing a portion of the Company’s natural gas production beginning in May 2003. The following table presents the production volumes and pricing information for the comparative periods, with the average oil and gas prices reflecting the results of the Company’s commodity hedging program as further described under “Quantitative and Qualitative Disclosures About Market Risk – Commodity Hedging Activity.”

Other revenues for the three months ended March 31, 2004 were $99,000 compared to $331,000 for the three months ended March 31, 2003, with the decrease of $232,000 primarily due to the absence of prospect fees received on two drilling prospects in the first quarter of 2003.

Lease operating expense was $1,549,000 for the three months ended March 31, 2004 versus $1,757,000 for the three months ended March 31, 2003, with the decrease largely due to the Company’s ongoing efforts to reduce costs on its operated properties since replacing a contract operator in June 2002. Production taxes were $695,000 in the three months ended March 31, 2004 compared to $531,000 in the first quarter of 2003, due to higher oil and gas sales in the 2004 period. Depletion, depreciation and amortization expense was $2,754,000 for the three months ended March 31, 2004 versus $2,061,000 for the three months ended March 31, 2003, with the increase due to higher equivalent units of production, and higher depletion rates. Exploration expense in the three months ended March 31, 2004 was $937,000, primarily reflecting $540,000 of seismic costs in the Plumb Bob field, compared to $553,000 in the three months ended March 31, 2003, which largely consisted of two exploratory dry holes.

General and administrative expenses amounted to $1,505,000 in the three months ended March 31, 2004 versus $1,538,000 in the first quarter of 2003. The most significant factor in this variance resulted from non-cash charges for employee equity compensation programs declining to $135,000 in the first quarter

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of 2004 from $430,000 in the first quarter of 2003. In the 2004 period, these non-cash charges consisted solely of vesting of restricted stock grants, whereas in the 2003 period, such amounts included charges of $403,000 related to the issuance of 125,157 shares of common stock in lieu of 1,016,500 cancelled stock options and $27,000 related to the initial vesting of restricted stock grants. Offsetting this decrease were increases in the Company’s insurance, payroll and other administrative expenses in the first quarter of 2004 compared to the first quarter of 2003.

Interest expense was $217,000 in the three months ended March 31, 2004 compared to $235,000 in the first quarter of 2003, with the decrease primarily attributable to a lower effective interest rate in the first quarter of 2004.

Liquidity and Capital Resources

Net cash provided by operating activities was $7,175,000 in the three months ended March 31, 2004 compared to $628,000 in the three months ended March 31, 2003. The increase in the 2004 period reflects higher oil and gas revenues and lower lease operating expenses, partially offset by an increase in exploration expenses. The operating cash flow amounts are net of changes in current assets and current liabilities, which resulted in an increase in working capital of $887,000 in the three months ended March 31, 2004, compared to a decrease of $2,471,000 in the three months ended March 31, 2003.

Net cash used in investing activities was $5,683,000 in the three months ended March 31, 2004, compared to $3,952,000 in the three months ended March 31, 2003. In the first quarter of 2004, capital expenditures totaled $5,683,000, as the Company participated in the drilling of two successful exploratory wells in the Burrwood/West Delta 83 field and made substantial leasehold acquisitions in East Texas (see “Cotton Valley Drilling Program”). In the first quarter of 2003, capital expenditures totaled $4,219,000 and were partially offset by the sale of the Company’s interest in the South Drew field resulting in proceeds of $267,000.

Net cash used in financing activities was $1,120,000 in the three months ended March 31, 2004 compared to net cash provided by financing activities of $1,242,000 in the three months ended March 31, 2003. In the first quarter of 2004, cash was used for debt repayments of $1,000,000 and preferred stock dividends and production payments of $243,000, while exercises of stock warrants provided cash of $123,000. In the first quarter of 2003, net borrowings under the Company’s senior credit facility provided cash of $1,500,000, while preferred stock dividends and production payments used cash of $258,000.

For the year 2004, the Company has preliminarily budgeted total capital expenditures of approximately $25 million, which includes the Company’s share of the subsequent exploration and development costs related to a recent property acquisition in South Louisiana (see “Recent Property Acquisition”) as well as a new drilling initiative undertaken in the Cotton Valley trend of East Texas and Northwest Louisiana (see “Cotton Valley Drilling Program”). Subject to current economics and financial resources, the Company expects to finance its capital expenditures out of operating cash flow and available bank credit, as further described below (see “Senior Credit Facility”).

Cotton Valley Drilling Program

In the first quarter of 2004, the Company commenced a new drilling initiative which is focused on the Cotton Valley trend in the East Texas Basin in and around Rusk, Panola and Smith Counties, Texas, and DeSoto and Caddo Parishes, Louisiana. As of April 30, 2004, the Company had acquired leases totaling

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approximately 35,000 gross acres, with an average working interest of approximately 80%, and is attempting to acquire additional acreage in the area. In April 2004, the Company commenced a lower risk drilling program which will target objectives primarily in the Cotton Valley formation. The Company has preliminarily budgeted total 2004 capital expenditures of approximately $6.5 million under this new drilling initiative. Depending on early results of the drilling program, the Company may elect to increase its level of lease acquisitions and drilling activities in the Cotton Valley trend.

The Company’s initiative in this area began in the third quarter of 2003, when it obtained, via farmout, the right to drill and earn all rights, excluding exploration rights to the Crane zone of the Pettit formation, in approximately 18,000 acres in the Bethany-Longstreet field in Northwest Louisiana. The Company will retain continuous drilling rights to the entire block so long as it drills at least one well every 120 days. For each productive well drilled under the agreement, the Company will earn an assignment to 160 acres. The Company has begun exploration and development drilling activities in the field and completed three successful wells in the Hosston formation in the fourth quarter of 2003. The Company also commenced drilling its initial exploratory well targeting the Cotton Valley formation in the first quarter of 2004 and logged approximately 100 feet of pay in the well in April 2004. The well is expected to be completed and placed on production in the second quarter of 2004. The Company has a 70% working interest in the four Bethany-Longstreet wells drilled to date and anticipates that its working interests in the additional wells to be drilled in the field will range between 50% and 70%.

Recent Property Acquisition

In the third quarter of 2003, the Company obtained certain rights in the Plumb Bob field located in St. Martin Parish in South Louisiana. The rights include oil and gas leases covering approximately 450 acres, 3-D seismic permits with oil and gas lease options covering approximately 17,000 acres, seven existing shut-in wellbores, where the Company has identified recompletion projects, and the rights to acquire related production facilities and pipelines upon establishment of production. The Company’s plans include a workover and well reactivation program, the shooting of a 32 square mile 3-D seismic survey and post 3-D exploitation and development drilling activities in which the Company has a 70% working interest. The Company has begun workover drilling activities in the field and restored production capability in three wells in the fourth quarter of 2003. The 3-D seismic shoot began during the fourth quarter of 2003 and is expected to be completed in the second quarter of 2004. Based on the results of the 3-D seismic survey, the Company will determine the extent of its drilling and remaining workover plans in the field.

Senior Credit Facility

On November 9, 2001, the Company established a three-year $50,000,000 senior credit facility with BNP Paribas, with an initial borrowing base of $25,000,000. In December 2003, the borrowing base was redetermined to be $28,000,000 and BNP Paribas and the Company agreed to extend the term of the senior credit facility for an additional two years, subject to periodic redeterminations of the borrowing base. As extended, the credit facility will mature on December 29, 2006. Borrowings outstanding under the senior credit facility were $19,000,000 as of March 31, 2004 and $21,000,000 as of May 12, 2004.

Interest on borrowings under the senior credit facility accrue at a rate calculated, at the option of the Company, as either the BNP Paribas base rate plus 0.00% to 0.50%, or LIBOR plus 1.50% to 2.50%, depending on borrowing base utilization. Interest on LIBOR-rate borrowings is due and payable on the last day of its respective interest period. Accrued interest on each base-rate borrowing is due and payable on the last day of each quarter. The credit facility requires that the Company pay a 0.375% per annum

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commitment fee, payable in quarterly installments based on the Company’s borrowing base utilization. Prior to maturity, no payments are required so long as the maximum borrowing base amount exceeds the amounts outstanding under the credit facility. The credit facility requires the Company to monitor tangible net worth and maintain certain financial statement ratios at certain levels. As of March 31, 2004, the Company was in compliance with all such requirements. Substantially all the Company’s assets are pledged to secure the senior credit facility.

In February 2003, the Company entered into three separate interest rate swaps with BNP Paribas, covering a three year period commencing in February 2003, and in February 2004, the Company entered into a fourth interest rate swap with BNP Paribas, covering a one year period commencing in February 2006 (see “Quantitative and Qualitative Disclosures About Market Risk – Debt and debt-related derivatives”).

New Accounting Pronouncements

Effective January 1, 2003, the Company adopted SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability must be recorded in the periods in which the obligation meets the definition of a liability, which is generally when the asset is placed in service. Prior to the adoption of SFAS No. 143, the Company recorded liabilities for the abandonment of oil and gas properties only in its two largest fields, with such liabilities amounting to $4,881,000 as of December 31, 2002. In accordance with the transition provisions of SFAS No. 143, the Company recorded an adjustment to recognize additional estimated liabilities for the abandonment of oil and gas properties, as of January 1, 2003, in the amount of $1,408,000, and additional oil and gas properties, net of accumulated depletion, depreciation and amortization, in the amount of $1,092,000. Any subsequent difference between costs incurred upon settlement of an asset retirement obligation and the recorded liability will be recognized as a gain or loss in the Company’s earnings. To recognize the cumulative effect of this change in accounting principle, the Company recorded a charge to earnings as of January 1, 2003 in the amount of $205,000, reflecting the $316,000 difference between the adjustments to the liability and asset accounts, net of the related income tax effect.

In April 2003, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133, Accounting for Derivatives and Hedging Activities. This statement (1) clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative, (2) clarifies when a derivative contains a financing component, and (3) amends the definition of an underlying derivative to conform to Financial Accounting Standards Board Interpretation No. 45. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003, with all provisions applied prospectively. The Company adopted SFAS No. 149, effective July 1, 2003, and the adoption had no impact on its financial statements.

In July 2003, the FASB undertook to review whether mineral interests in properties (mineral leases) held by oil and gas companies should be recorded and disclosed as intangible assets under the guidance of SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets. The FASB is considering whether an oil and gas company’s investment in mineral leases should be classified as intangible assets. SFAS No. 141 and SFAS No. 142 established new accounting guidelines for both finite lived intangible assets and indefinite lived intangible assets. Under SFAS No. 141 and SFAS No. 142, intangible assets should be separately reported on the Balance Sheet, with accompanying disclosures in the notes to the financial statements. SFAS No. 142 does not change the accounting prescribed in SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, and is silent

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about whether its disclosure provisions apply to oil and gas companies. The Company does not believe that SFAS No. 141 and SFAS No. 142 change the classification and disclosure of oil and gas mineral leases and it continues to classify these assets as part of Property and Equipment in the Consolidated balance sheet and it does not provide the additional disclosures for these assets. The EITF has added the discussion of oil and gas mineral leases to its agenda, which may result in a change in the recording and disclosure of oil and gas mineral leases. Should the EITF determine that oil and gas mineral leases are intangible assets, the Company would reclassify $7,374,000 and $6,409,000 as intangible undeveloped mineral interests at March 31, 2004 and December 31, 2003, respectively. In addition, a reclassification of $6,160,000 and $5,879,000 would be made as intangible developed mineral interests at March 31, 2004 and December 31, 2003, respectively. Both intangible assets would be presented net of accumulated amortization. Historically, undeveloped mineral leases have been amortized over the life of the lease period, while developed mineral leases have been amortized using the units of production method over the expected life of proved reserves. The amounts included herein are based on the Company’s understanding of the issue on the EITF’s agenda. If all mineral leases associated with oil and gas properties are deemed to be intangible assets in accordance with SFAS No. 141 and SFAS No. 142 by the EITF:

In March 2004, the FASB issued an exposure draft on accounting for stock-based compensation. The exposure draft reflects the FASB’s tentative conclusion that the fair value of stock options should be expensed in companies’ financial statements for years ending after December 31, 2004. The exposure draft also includes the FASB’s tentative decisions regarding how equity-based awards are likely to be valued, expensed, and classified. The Company will continue to monitor developments with respect to the exposure draft to determine the potential impact on its financial statements.

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Quantitative and Qualitative Disclosures About Market Risk

Commodity Hedging Activity

The Company enters into futures contracts or other hedging agreements from time to time to manage the commodity price risk for a portion of its production. The Company considers these to be hedging activities and, as such, monthly settlements on these contracts are reflected in its oil and natural gas sales. The Company’s strategy, which is administered by the Hedging Committee of the Board of Directors, and reviewed periodically by the entire Board of Directors, has been to hedge between 30% and 70% of its production. As of March, 31, 2004, all of the commodity hedges utilized by the Company were in the form of fixed price swaps, where the Company receives a fixed price and pays a floating price based on NYMEX quoted prices. As of March 31, 2004, the Company’s open forward position on its outstanding commodity hedging contracts, all of which were with BNP Paribas, was as follows:

Natural Gas

3,000 MMBtu per day “swap” at fixed price of $5.00 for April 2004 through December 2004; and

3,000 MMBtu per day “swap” at fixed price of $5.41 for April 2004 through October 2004

Crude Oil

700 barrels of oil per day “swap” at fixed price of $28.59 for April 2004 through June 2004; and

300 barrels of oil per day “swap” at fixed price of $30.92 for April 2004 through June 2004; and

700 barrels of oil per day “swap” at fixed price of $28.20 for July 2004 through December 2004; and

300 barrels of oil per day “swap” at fixed price of $30.25 for July 2004 through December 2004

The fair value of the natural gas and oil hedging contracts in place at March 31, 2004, resulted in a liability of $2,466,000. Based on oil and gas pricing in effect at March 31, 2004, a hypothetical 10% increase in oil and gas prices would have increased the liability to $4,475,000 while a hypothetical 10% decrease in oil and gas prices would have decreased the liability to $832,000. Subsequent to March 31, 2004, the Company entered into the following natural gas and crude oil hedging contracts with BNP Paribas:

3,000 MMBtu per day “swap” at fixed price of $6.20 for November 2004 through December 2004; and

6,000 MMBtu per day “swap” at fixed price of $6.27 for January 2005 through March 2005; and

500 barrels of oil per day “swap” at fixed price of $33.28 for January 2005 through March 2005

Debt and debt-related derivatives

In February 2003, the Company entered into three separate interest rate swaps with BNP Paribas covering a three year period (one of the interest rate swaps has now expired). The first interest rate swap, which had an effective date of February 26, 2003, expired on its maturity date of February 26, 2004, and was for $18,000,000 with a LIBOR swap rate of 1.53%. The second interest rate swap, which has an effective date of February 26, 2004 and a maturity date of November 8, 2004, is for $18,000,000 with a LIBOR swap rate of 2.25%. The third interest rate swap, which has an effective date of November 8, 2004 and a maturity date of February 26, 2006, is for $18,000,000 with a LIBOR swap rate of 3.46%. In February 2004, the Company entered into a fourth interest rate swap contract with BNP Paribas, which has an effective date of February 26, 2006 and a maturity date of February 26, 2007, for $23,000,000 with a LIBOR swap rate of 4.08%. The fair value of the interest rate swap contracts in place at March 31, 2004, resulted in a liability of $627,000. Based on interest rates at March 31, 2004, a hypothetical 10% increase or decrease in interest rates would not have a material effect on the liability.

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Price fluctuations and the volatile nature of markets

Despite the measures taken by the Company to attempt to control price risk, the Company remains subject to price fluctuations for natural gas and oil sold in the spot market. Prices received for natural gas sold on the spot market are volatile due primarily to seasonality of demand and other factors beyond the Company’s control. Domestic oil and gas prices could have a material adverse effect on the Company’s financial position, results of operations and quantities of reserves recoverable on an economic basis.

Disclosure Regarding Forward-Looking Statement

Certain statements in this Quarterly Report on Form 10-Q regarding future expectations and plans for future activities may be regarded as “forward looking statements” within the meaning of Private Securities Litigation Reform Act of 1995. They are subject to various risks, such as financial market conditions, operating hazards, drilling risks and the inherent uncertainties in interpreting engineering data relating to underground accumulations of oil and gas, as well as other risks discussed in detail in the Company’s Annual Report on Form 10-K and other filings with the Securities and Exchange Commission. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct.

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Controls and Procedures

The Company, under the direction of its chief executive officer and chief financial officer, has established controls and procedures to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the company’s financial reports and to other members of senior management and the Board of Directors.

Based on their evaluation as of March 31, 2004, the chief executive officer and chief financial officer of Goodrich Petroleum Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of March 31, 2004 to ensure that the information required to be disclosed by Goodrich Petroleum Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

Except for changes implemented by the Company to correct the material weakness in internal controls reported in the Company’s Annual Report on Form 10-K for the year ended December, 31, 2003, there were no significant changes in the Company’s internal controls or in other factors that could significantly affect those controls subsequent to the date of their most recent evaluation.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

Item 2. Changes in Securities.

None

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Submission of Matters to a Vote of Security Holders.

None.

Item 5. Other Information.

Not applicable.

Item 6. Exhibits and Reports on Form 8-K.

None.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

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