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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, 2005

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 9, 2005, there were 21,050,430 shares of Goodrich Petroleum Corporation common stock outstanding.

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GOODRICH PETROLEUM CORPORATION

INDEX TO FORM 10-Q

March 31, 2005

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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, 2005 and 2004

(Unaudited)

See notes to consolidated financial statements.

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

March 31, 2005 and 2004

(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, 2004.

The results of operations for the three-month period ended March 31, 2005 are not necessarily indicative of the results to be expected for the full year.

Discontinued Operations

In October 2004, the Company sold its operated interests in the Marholl and Sean Andrew fields, along with its non-operated interests in the Ackerly field, all of which were located in West Texas, for gross proceeds of approximately $2,100,000. The Company realized a pre-tax gain of $877,000 on the sale of these non-core properties. Prior period results of operations of these sold properties have been presented as discontinued operations in the accompanying consolidated statement of operations. Results for these properties reported as discontinued operations for the three months ended March 31, 2004 were as follows:

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

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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, 2005 and 2004, 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 May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify an instrument that is within its scope as a liability. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and is effective at the beginning of the first interim period beginning after June 15, 2003, although in November 2003, the FASB deferred certain provisions of SFAS No. 150. As of March 31, 2005, the Company had no financial instruments within the scope of SFAS No. 150.

In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment, a revision of SFAS No. 123, Accounting for Stock-Based Compensation. The revised statement requires the expensing of new, modified or repurchased stock-based compensation awards issued after June 15, 2005. Previously issued stock-based compensation awards, which are unvested as of that date, must also be accounted for in accordance with the revised statement. The revised statement provides for the use of either a closed-form model or open-form lattice model for the valuation of stock option awards. The Company plans to follow the “modified prospective application” to the adoption of the revised statement and is currently evaluating the potential impact that the adoption of the revised statement will have on its financial statements. In April 2005, the SEC adopted a rule permitting registrants to delay the expensing of options, pursuant to SFAS No. 123R, to the first annual period beginning after June 15, 2005. Accordingly, the Company will implement the provisions of SFAS No. 123R in its financial statements, effective January 1, 2006.

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NOTE C – Senior Credit Facility

In November 2001, the Company established a $50,000,000 senior credit facility with BNP Paribas, with an initial borrowing base of $25,000,000 and a three year term. 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 to December 2006, subject to periodic redeterminations of the borrowing base. In August 2004, the borrowing base was redetermined to be $32,000,000. Interest on borrowings accrues at a rate calculated, at the option of the Company, at either the BNP Paribas base rate plus 0.00% to 0.50%, or LIBOR plus 1.50%—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 commitment fee, payable in quarterly installments based on the Company’s borrowing base utilization. Prior to maturity, no principal payments are required so long as the maximum borrowing base amount exceeds the amounts outstanding under the credit facility.

In February 2005, the borrowing base of the senior credit facility was redetermined to be $44,000,000 and the credit facility was amended to increase its size to $65,000,000 and to extend its term to February 25, 2008. The amended senior credit facility includes a second tranche, which provides for additional term borrowings of up to $15,000,000 to further finance development of the Company’s acreage in the Cotton Valley trend of East Texas and Northwest Louisiana. On February 25, 2005, $7,500,000 was advanced under the second tranche with the remainder to be advanced in two equal installments of $3,750,000 at the option of the Company and with the approval of BNP Paribas. Interest on borrowings under the second tranche accrues at a quarterly rate of LIBOR plus 5.0% and principal will be due on February 25, 2008.

The credit facility precludes the payment of dividends on the Company’s common stock and requires the Company to maintain an adjusted current ratio (as defined) of not less than 1.0:1.0, an interest coverage ratio for the trailing four quarters of at least 3.0 times, and a tangible net worth of not less than the sum of $53,392,838, plus 50% of the Company’s cumulative net income after September 30, 2004, plus 100% of the net proceeds of any equity issuance by the Company after September 30, 2004. As of March 31, 2005, the Company was in compliance with all such requirements, after giving effect to a waiver received from BNP Paribas with respect to non-compliance with the adjusted current ratio covenant at March 31, 2005. Substantially all the Company’s assets are pledged to secure the senior credit facility. As of March 31, 2005, the Company’s outstanding borrowings under the senior credit facility were $35,500,000, including $7,500,000 initially advanced under the second tranche. In May 2005, the credit agreement was amended to allow the Company to redraw the $7,500,000 initially advanced under the second tranche provided it is repaid within 30 days of a public stock offering (see Note G).

In February 2003, the Company entered into three separate interest rate swaps with BNP Paribas covering a three year period, as further described below, and in February 2004, entered into another interest rate swap with BNP Paribas for an additional one year period (see “Quantitative and Qualitative Disclosures About Market Risk—Debt and debt-related derivatives”).

NOTE D – Hedging Activities

Commodity Hedging Activity

The Company enters into swap 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 crude 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

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of Directors, has been to hedge between 30% and 70% of its production. As of March, 31, 2005, 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. Hedge ineffectiveness results from differences in the NYMEX contract terms and the physical location, grade and quality of the Company’s oil and gas production. As of March 31, 2005, the Company’s open forward position on its outstanding commodity hedging contracts, all of which were with BNP Paribas, was as follows:

The hedging contracts summarized above are based on floating NYMEX contract prices and fall within the Company’s targeted range of estimated net oil and gas production volumes for the applicable periods of 2005. The fair value of the crude oil and natural gas hedging contracts in place at March 31, 2005 resulted in a net liability of $15,267,000. As of March 31, 2005, $4,197,000 (net of $2,260,000 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, 2005, $1,388,000 of previously deferred losses (net of $747,000 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. In the three months ended March 31, 2005, the Company recognized in earnings an unrealized loss on derivative instruments in the amount of $10,423,000. This loss was recognized because the Company’s natural gas hedges were deemed to be ineffective for the first quarter of 2005, accordingly, the changes in fair value of such hedges could no longer be reflected in other comprehensive income. For the three months ended March 31, 2004, the Company’s earnings were not significantly affected by cash flow hedging ineffectiveness arising from the crude oil and gas hedging contracts. Subsequent to March 31, 2005, the Company entered into the following crude oil and natural gas hedging contracts with BNP Paribas:

Gas - 3,000 MMBtu per day “swap” at $6.94 per MMBtu for April 2006 through December 2006

Oil - 400 barrels per day “swap” at $52.88 per barrel for January 2006 through December 2006

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 (two of the interest rate swaps have now expired). The unexpired 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 another interest rate swap contract with BNP Paribas, which has an effective date of February 26, 2006

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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, 2005, resulted in an asset of $113,000. As of March 31, 2005, $60,000 (net of $32,000 in income taxes) of deferred gains 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, 2005, $33,000 of previously deferred losses (net of $18,000 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, 2005 and 2004, 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, 2005 and 2004. 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, 2005 and 2004 considered exercisable stock warrants and stock options to the extent that the exercise of such securities would have been dilutive under the treasury stock method. The computation of earnings per share for the three months ended March 31, 2005 and 2004 did not consider preferred stock which is convertible into shares of common stock because the effect of such conversion would have been antidilutive.

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). Based on the value of the Company’s common stock at the time of the exchange, 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. At the same time, the Company commenced granting a series of restricted share awards, with three year vesting periods, to its employees under a stockholder approved equity compensation plan. Based on the value of the Company’s common stock at the time of the grants, those awards resulted in charges to a contra equity account and credits to additional paid-in capital in the following amounts:

The charges to the contra equity account are being amortized to earnings as non-cash charges to general and administrative expenses over the three year vesting period of each restricted share award and

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resulted in non-cash charges to earnings of $243,000 and $59,000 in the three months ended March 31, 2005 and 2004, respectively. In the year ended December 31, 2004, the Company recorded a credit to the contra equity account and a charge to additional paid-in capital in the amount of $157,000 for the value of 28,918 non-vested restricted share awards that were forfeited by terminated employees. The amortization to earnings of restricted share awards has been adjusted to reflect such forfeitures. Assuming no additional restricted share awards or forfeitures, the Company will be required to record recurring non-cash charges to earnings of approximately $300,000 per quarter, related to the periodic vesting of the restricted share awards that have been issued to date.

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, 2005 and 2004 would have been reduced to the pro forma amounts indicated below.

NOTE F - Commitments and Contingencies

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.

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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 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 125th 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 monetary damages as well as recovery of attorneys’ fees. On May 28, 2004, the trial court ordered a final judgment which awarded the Company a net sum of approximately $2,065,000 as follows:

The trial court also ordered the Company to pay $103,000 to the operator in recovery of defendant’s attorneys’ fees and provided for post-judgment interest to accrue on the awarded damages and both parties’ attorneys’ fees through the date of ultimate payment. Either party could have appealed the final judgment or filed a motion for a new trial within ninety days from the date of the final judgment. In September 2004, the time period for either party to appeal the judgment elapsed, therefore, the Company accrued a non-recurring gain in the quarter ended September 30, 2004 in the amount of $2,050,000, reflecting the anticipated payment of the final judgment by the operator less the Company’s estimated expenses of the final judgment. In October 2004, the operator remitted a total of $2,118,000 to the Company in full satisfaction of the judgment, including the net amount of post-judgment interest.

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 –Subsequent Events

In April 2005, the Company filed a prospectus supplement for a public offering of 2,800,000 shares of its common stock. Net proceeds of the offering would be used primarily to fund an accelerated Cotton Valley trend drilling program in East Texas and Northwest Louisiana. In the event that the offering is unsuccessful, the Company will seek other financing alternatives.

In May 2005, the Company plugged and abandoned an exploratory well drilled on its Port Hudson prospect in East Baton Rouge Parish, Louisiana. Through March 31, 2005, the Company had incurred net costs of $642,000 applicable to this well. This amount has been expensed as dry hole costs in the accompanying financial statements for the three months ended March 31, 2005. The Company will expense its remaining share of the dry hole costs, estimated to be approximately $800,000, in the second quarter of 2005.

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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, 2004 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, 2005 versus three months ended March 31, 2004 — Total revenues from continuing operations for the three months ended March 31, 2005 amounted to $13,140,000 compared to $10,764,000 for the three months ended March 31, 2004. Oil and gas sales for the three months ended March 31, 2005 were $13,011,000 compared to $10,666,000 for the three months ended March 31, 2004. This increase resulted from a 7% increase in oil and gas production volumes, due to several successful well completions since the first quarter of 2004, as well as higher average prices for oil and gas. The following table presents the production volumes and pricing information for the comparative periods, with the average oil and gas prices including realized gains and losses on 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, 2005 were $129,000 compared to $99,000 for the three months ended March 31, 2004.

Lease operating expense from continuing operations was $2,244,000 for the three months ended March 31, 2005 versus $1,515,000 for the three months ended March 31, 2004, with the increase due to an increase in production volumes as well as unanticipated expenses on a non-producing field in South Louisiana. Production taxes from continuing operations were $786,000 in the three months ended March 31, 2005 compared to $687,000 in the first quarter of 2004, with the increase due to higher production volumes. Depletion, depreciation and amortization expense from continuing operations was $5,846,000 for the three months ended March 31, 2005 versus $2,707,000 for the three months ended March 31, 2004, with the increase due to higher equivalent units of production and higher depletion rates resulting from an increase in net capitalized development costs and a reduction at year end 2004 in proved developed reserves. Exploration expense in the three months ended March 31, 2005 was $1,524,000 compared to $937,000 in the three months ended March 31, 2004, with the increase mainly due to dry hole costs in the amount of $642,000 applicable to an exploratory well drilled in East Baton Rouge Parish, Louisiana, which was plugged and abandoned in May 2005. The Company will expense its remaining share of the dry hole costs, estimated to be approximately $800,000 in the second quarter of 2005.

General and administrative expenses amounted to $1,620,000 in the three months ended March 31, 2005 versus $1,505,000 in the first quarter of 2004. The most significant factor in this variance resulted from an increase in the Company’s payroll and employee benefits expense to $1,062,000 in the three months ended March 31, 2005 from $783,000 in the three months ended March 31, 2004, primarily due to an increase in the number of employees. Partially offsetting this increase were decreases in certain other administrative expenses.

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Interest expense was $307,000 in the three months ended March 31, 2005 compared to $217,000 in the three months ended March 31, 2004, with the increase primarily attributable to an increase in the level of borrowings.

Unrealized loss on derivatives amounted to $10,423,000 in the three months ended March 31, 2005, compared to zero in the three months ended March 31, 2004. The 2005 amount arose because the Company’s natural gas hedges were deemed to be ineffective under accounting rules for the first quarter of 2005, which resulted in the changes in fair value of such hedges being reflected in earnings rather than in other comprehensive income, a component of stockholders’ equity. To the extent that the Company’s hedges are not deemed to be effective in the future, the Company will be exposed to volatility in earnings resulting from changes in the fair value of its hedges.

Net gains on asset sales were $151,000 in the three months ended March 31, 2005 compared to zero in the three months ended March 31, 2004 and primarily resulted from the sale of a marginally producing 3 well field in South Louisiana.

Income taxes from continuing operations were a benefit of $3,308,000 in the three months ended March 31, 2005 compared to an expense of $1,119,000 in the three months ended March 31, 2004. The amounts in both periods essentially represented 35% of pre-tax income (loss) attributable to continuing operations.

Liquidity and Capital Resources

Net cash provided by operating activities was $10,127,000 in the three months ended March 31, 2005 compared to $7,175,000 in the three months ended March 31, 2004. The increase in the 2005 period reflects higher oil and gas revenues, partially offset by an increase in lease operating 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 $2,034,000 in the three months ended March 31, 2005, compared to an increase of $887,000 in the three months ended March 31, 2004.

Net cash used in investing activities was $20,642,000 in the three months ended March 31, 2005, compared to $5,683,000 in the three months ended March 31, 2004. In the first quarter of 2005, capital expenditures totaled $20,772,000, as the Company incurred substantial drilling and leasehold acquisition costs in East Texas and Northwest Louisiana (see “Cotton Valley Drilling Program”). 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 in South Louisiana and commenced its Cotton Valley Drilling Program.

Net cash provided by financing activities was $8,448,000 in the three months ended March 31, 2005 compared to net cash used in financing activities of $1,120,000 in the three months ended March 31, 2004. In the first quarter of 2005, net borrowings under the Company’s senior credit facility provided cash of $8,272,000 and exercises of stock warrants and options provided cash of $458,000, while preferred stock dividends and production payments used cash of $282,000. 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.

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In April 2005, the Company announced that its board of directors had authorized an increase in its 2005 capital expenditure budget to approximately $95 million, subject to quarterly approval. Approximately two-thirds of the 2005 capital expenditure budget is expected to be focused on a relatively low risk development drilling program in the Cotton Valley trend of East Texas and Northwest Louisiana (see “Cotton Valley Drilling Program”) and the remainder on the Company’s existing properties and new exploration programs. Subject to current economics and financial resources, the Company expects to finance its 2005 capital expenditures through a combination of cash flow from operations and borrowings under its existing bank credit facility which was expanded in February 2005 (see “Senior Credit Facility”).

In April 2005, the Company also filed a prospectus supplement for a public offering of 2,800,000 shares of its common stock. Net proceeds of the offering would be used primarily to fund an accelerated Cotton Valley trend drilling program in East Texas and Northwest Louisiana. In the event that the offering is unsuccessful, the Company will seek other financing alternatives.

Cotton Valley Drilling Program

In the first quarter of 2004, the Company commenced what it believes is a relatively low risk drilling program which is focused on the Cotton Valley trend in the East Texas Basin in and around Rusk and Panola Counties, Texas, and DeSoto and Caddo Parishes, Louisiana. As of May 5, 2005, the Company had acquired or farmed in leases totaling approximately 48,000 gross acres, with an average working interest of approximately 90%, and is attempting to acquire additional acreage in the area. As of May 5, 2005, the Company had successfully drilled 23 operated wells targeting the Cotton Valley formation. For the wells completed and placed on production to date, the Company estimates that the average initial gross production rate per well is approximately 1,600 Mcfe of gas per day. This estimated average initial gross production rate is consistent with the range originally projected by the Company prior to commencing its drilling activities in the Cotton Valley trend. Initial production from the Cotton Valley wells commenced in June 2004, and taking into account the expected decline following the initial 30 day period, the current gross production from the wells placed in production is approximately 12,900 Mcfe of gas per day.

In East Texas, the Company began leasing acreage in the first quarter of 2004 and commenced a drilling program in April 2004. As of May 5, 2005, the Company had drilled a total of 19 successful wells in East Texas on its operated acreage targeting the Cotton Valley formation. The Company has a 100% working interest in 11 of the completed wells and an 86% working interest in eight of the completed wells.

In Northwest Louisiana, the Company commenced a drilling program targeting the Cotton Valley formation in the first quarter of 2004 and has currently completed three Cotton Valley wells. The Company’s initiative in this area began in the third quarter of 2003, when it obtained, via farmout, exploration rights to approximately 18,000 gross acres in the Bethany-Longstreet field. The Company retains continuous drilling rights to the entire block so long as it drills at least one well within 120 days from previous operations. For each productive well drilled under the agreement, the Company earns an assignment to 160 acres. The Company began exploration and development drilling activities in the field and completed three successful wells in a shallower formation in the fourth quarter of 2003. The Company has a 70% working interest in the Bethany-Longstreet field.

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South Louisiana Operations

Burrwood/West Delta 83 Fields — During the first quarter of 2005, the initial well on the Company’s Tunney prospect in the Burrwood/West Delta 83 field went off production from the initial zone due to reservoir depletion and was recompleted in two sands in a dual completion in April 2005. Upon completion of an additional flowline, the Company expects combined gross production from the recompleted zones will be approximately 1,750 Bbls of oil per day and 3,500 Mcf per day. The Company owns an approximate 40% working interest in the well.

Plumb Bob Field — In the third quarter of 2003, the Company obtained certain rights in the Plumb Bob field located in St. Martin Parish, Louisiana. The rights include a 70% working interest in oil and gas leases covering approximately 450 acres, 3-D seismic permits with oil and gas lease options covering approximately 17,000 acres. In the fourth quarter of 2003, the Company began workover drilling activities in the field and restored production capability in three wells, one of which is currently producing. In the fourth quarter of 2003, the Company also commenced a 30 square mile 3-D seismic survey which was completed in the second quarter of 2004. Processing of the seismic data was completed in late 2004 and evaluation of the data is ongoing.

St. Gabriel Field — In July 2004, the Company announced that it had acquired a 70% working interest in 3-D seismic permits and oil and gas lease options enabling it to acquire an approximate 30 square mile 3-D seismic survey over the St. Gabriel field in Ascension and Iberville Parishes, Louisiana. The Company commenced shooting the 3-D seismic survey in July 2004 and data acquisition was completed in September 2004. Processing of the data was completed in November 2004 and evaluation of the data is ongoing.

Senior Credit Facility

In November 2001, the Company established a $50,000,000 senior credit facility with BNP Paribas, with an initial borrowing base of $25,000,000 and a three year term. 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 to December 29, 2006, subject to periodic redeterminations of the borrowing base. In August 2004, the borrowing base was redetermined to be $32,000,000. Interest on borrowings accrues at a rate calculated, at the option of the Company, at either the BNP Paribas base rate plus 0.00% to 0.50%, or LIBOR plus 1.50%—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 commitment fee, payable in quarterly installments based on the Company’s borrowing base utilization. Prior to maturity, no principal payments are required so long as the maximum borrowing base amount exceeds the amounts outstanding under the credit facility.

In February 2005, the borrowing base of the senior credit facility was redetermined to be $44,000,000 and the credit facility was amended to increase its size to $65,000,000 and to extend its term to February 25, 2008. The amended senior credit facility includes a second tranche, which provides for additional term borrowings of up to $15,000,000 to further finance development of the Company’s acreage in the Cotton Valley trend of East Texas and Northwest Louisiana. On February 25, 2005, $7,500,000 was advanced under the second tranche with the remainder to be advanced in two equal installments of $3,750,000 at the option of the Company and with the approval of BNP Paribas. Interest on borrowings under the second tranche accrues at a quarterly rate of LIBOR plus 5.0% and principal will be due on February 25, 2008.

The credit facility precludes the payment of dividends on the Company’s common stock and requires the Company to maintain an adjusted current ratio (as defined), an interest

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coverage ratio for the trailing four quarters of at least 3.0 times, and a tangible net worth of not less than the sum of $53,392,838, plus 50% of the Company’s cumulative net income after September 30, 2004, plus 100% of the net proceeds of any equity issuance by the Company after September 30, 2004. As of March 31, 2005, the Company was in compliance with all such requirements, after giving effect to a waiver received from BNP Paribas with respect to the adjusted current ratio covenant. The Company sought and obtained the waiver of non-compliance with the current ratio covenant in its credit agreement for the first quarter 2005, which states that the Company must maintain a defined current ratio of 1.00 to 1.00, as adjusted to include borrowing capacity with current assets and to exclude any current liability for derivatives, other non-cash charges and current maturities. The current ratio deficit occurred due to the Company’s accelerated drilling activities, primarily in the Cotton Valley Trend. The Company believes it can avoid future deficiencies in its current ratio by replacing borrowing capacity through the pay down of current borrowings with proceeds from equity offerings or alternate financings, increases in borrowing base resulting from the addition of new developed reserves or adjusting the timing of its capital expenditures. The Company is in compliance with all of its other bank covenants. Substantially all the Company’s assets are pledged to secure the senior credit facility. As of March 31, 2005 and May 9, 2005, the Company’s outstanding borrowings under the senior credit facility were $35,500,000 and $39,500,000, respectively, including $7,500,000 initially advanced under the second tranche. In May 2005, the credit agreement was amended to allow the Company to redraw the $7,500,000 initially advanced under the second tranche provided it is repaid within 30 days of a public stock offering.

In February 2003, the Company entered into three separate interest rate swaps with BNP Paribas covering a three year period, as further described below, and in February 2004, entered into another interest rate swap with BNP Paribas for an additional one year period (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 May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify an instrument that is within its scope as a liability. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and is effective at the beginning of the first interim period beginning after June 15, 2003, although in November 2003, the FASB deferred certain provisions of SFAS No. 150. As of March 31, 2005, the Company had no financial instruments within the scope of SFAS No. 150.

In December 2004, the FASB issued SFAS No. 123R, Share-Based Payment, a revision of SFAS No. 123, Accounting for Stock-Based Compensation. The revised statement requires the expensing of new, modified or repurchased stock-based compensation awards issued after June 15, 2005. Previously issued stock-based compensation awards, which are unvested as of that date, must also be accounted for in accordance with the revised statement. The revised statement provides for the use of either a closed-form model or open-form lattice model for the valuation of stock option awards. The Company plans to follow the “modified prospective application” to the adoption of the revised statement and is currently evaluating the potential impact that the adoption of the revised statement will have on its financial statements. In April 2005, the SEC adopted a rule permitting registrants to delay the expensing of options, pursuant to SFAS No. 123R, to the first annual period beginning after June 15, 2005. Accordingly, the Company will implement the provisions of SFAS No. 123R in its financial statements, effective January 1, 2006.

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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 crude 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, 2005, 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, 2005, the Company’s open forward position on its outstanding commodity hedging contracts, all of which were with BNP Paribas, was as follows:

The hedging contracts summarized above fall within the Company’s targeted range of its estimated net oil and gas production volumes for the applicable periods of 2005. The fair value of the crude oil and natural gas hedging contracts in place at March 31, 2005 resulted in a liability of $15,267,000. Based on oil and gas pricing in effect at March 31, 2005, a hypothetical 10% increase in oil and gas prices would have increased the liability to $23,567,000 while a hypothetical 10% decrease in oil and gas prices would have decreased the liability to $6,993,000. Subsequent to March 31, 2005, the Company entered into the following crude oil and natural gas hedging contracts with BNP Paribas:

Gas - 3,000 MMBtu per day “swap” at $6.94 per MMBtu for April 2006 through December 2006

Oil - 400 barrels per day “swap” at $52.88 per barrel for January 2006 through December 2006

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 unexpired 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 another 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, 2005, resulted in an asset of $113,000. Based on interest rates at March 31, 2005, 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, 2005, 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, 2005 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.

There were no 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.

For a description of the Company’s legal proceedings, see Note F to the Consolidated Financial Statements included in Part I, Item 1 of this quarterly report on Form 10-Q, and Part I, Item 3 of the Company’s Form 10-K filed on March 25, 2005.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

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.

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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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