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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

For Fiscal Year Ended December 31, 2004

Commission file number 1-7940

GOODRICH PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code is (713) 780-9494

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x        No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

At March 24, 2005, there were 21,050,430 shares of Goodrich Petroleum Corporation common stock outstanding. The aggregate market value of shares of common stock held by non-affiliates of the registrant as of March 24, 2005, was approximately $168,534,600 based on a closing price of $19.53 per share on the New York Stock Exchange on such date.

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

At June 30, 2004, the aggregate market value of Goodrich Petroleum Corporation common stock held by non-affiliates was $71,198,700.

Documents Incorporated By Reference

Portions of the registrant’s annual proxy statement, to be filed within 120 days after December 31, 2004, are incorporated by reference into Part III of this Form 10-K.

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GOODRICH PETROLEUM CORPORATION

FORM 10-K

December 31, 2004

INDEX

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PART I

Items 1 and 2.    Business and Properties.

General

Goodrich Petroleum Corporation and subsidiaries (“Goodrich” or the “Company”) is an independent oil and gas company engaged in the exploration, exploitation, development and production of oil and natural gas properties primarily in the Cotton Valley trend of East Texas and Northwest Louisiana and in the transition zone of South Louisiana. The Company owns working interests in 89 active oil and gas wells located in 18 fields in four states. At December 31, 2004, Goodrich had estimated proved reserves of approximately 5.6 million barrels of oil and condensate and 67.7 billion cubic feet (“Bcf”) of natural gas, or an aggregate of 101.21 Bcf equivalent (“Bcfe”) with a pre-tax present value of future net revenues, discounted at 10%, of $241.5 million and an after-tax present value of future net revenues of $180.7 million.

The Company’s principal executive offices are located at 808 Travis Street, Suite 1320, Houston, Texas 77002. The Company also has an office in Shreveport, Louisiana. At March 24, 2005, the Company had 52 employees.

Business Strategy

The Company’s business strategy is to provide long term growth in net asset value per share, through the growth and expansion of its oil and gas reserves and production. The Company focuses on adding reserve value through the careful evaluation and aggressive pursuit of oil and gas drilling and acquisition opportunities. Economic analyses are prepared on each drilling and acquisition opportunity with criteria of adding net present value for every dollar invested. In addition, the Company implements an active hedging program designed to partially reduce commodity price risks in an effort to realize the desired economic returns.

Several of the key elements of Goodrich’s business strategy are the following:

The Company maintains a website at http://www.goodrichpetroleum.com. However, the information on the website does not constitute part of this Annual Report.

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Oil and Gas Operations and Properties

Cotton Valley Drilling Program

Overview.    In the first quarter of 2004, the Company commenced a major new initiative which is focused on a relatively low risk development drilling program in the Cotton Valley trend of East Texas and Northwest Louisiana. The Company spent approximately two-thirds of its total 2004 capital expenditures of $47 million on this drilling and leasehold program and has preliminarily committed a similar percentage of its total 2005 capital expenditure budget of approximately $75 million to the program. As of December 31, 2004, the Company had acquired or farmed in leases totaling approximately 45,000 gross acres, with an average working interest of approximately 85%, and is attempting to acquire additional acreage in the area. As of December 31, 2004, the Company had successfully drilled 14 operated wells targeting the Cotton Valley formation. Subsequent to December 31, 2004, the Company had successfully drilled and/or completed an additional four Cotton Valley wells. As of March 24, 2005, the Company was in the process of drilling another four Cotton Valley wells. The Company’s current Cotton Valley drilling activities are centered about three primary leasehold areas in East Texas and one field in Northwest Louisiana as further described below.

Dirgin-Beckville.    The Dirgin-Beckville area is located in Panola County, Texas. The Company has acquired leases totaling approximately 5,000 gross acres with an average working interest of approximately 90%. As of December 31, 2004, the Company had successfully completed four Cotton Valley wells in the Dirgin-Beckville area.

North Minden.    The North Minden area is located in Rusk County, Texas. The Company has acquired leases totaling approximately 18,000 gross acres with a working interest of 100%. As of December 31, 2004, the Company had successfully completed seven Cotton Valley wells in the North Minden area.

South Henderson.    The South Henderson area is located in Rusk County, Texas. The Company has acquired leases totaling approximately 4,000 gross acres with a working interest of nearly 100%. As of December 31, 2004, the Company had one Cotton Valley well drilling in the South Henderson area.

Bethany-Longstreet.    The Bethany-Longstreet field is located in Caddo and DeSoto Parishes in Northwest Louisiana. The Company commenced a drilling program targeting the Cotton Valley formation in the first quarter of 2004 and had successfully completed three Cotton Valley wells as of December 31, 2004. 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 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.

Production and Reserves.    For all Cotton Valley wells completed to date, the Company estimates that the initial average gross production rate per well is approximately 1,350 Mcf equivalent (“Mcfe”) of gas per day. This estimated average 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 production period, the current gross production from the successfully completed wells is approximately 8,500 Mcfe of gas per day, or 5,300 Mcfe per day net to the Company. The Company’s independent reserve engineering firm has estimated that the average gross ultimate reserve of the Cotton Valley wells drilled and completed to date is approximately 1.0 Bcf equivalent (“Bcfe”) per well. The estimated ultimate gross reserve of the most recent nine wells, using a refined completion technique, is approximately 1.25 Bcfe per well.

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The following is a summary description of the Company’s other oil and gas properties.

Louisiana

The majority of the Company’s proved oil and natural gas reserves are in the transition zone of the south Louisiana producing region. This region refers to the geographic area that covers the onshore and in-land waters of south Louisiana lying in the southern half of Louisiana, which is one of the most prolific oil and natural gas producing sedimentary basins. The region generally contains sedimentary sandstones, which are of high qualities of porosity and permeabilities. There is a myriad of types of reservoir traps found in the region. These traps are generally formed by faulting, folding and subsurface salt movement, or a combination of one or more of these conditions.

The formations found in the southern Louisiana producing region range in depth from 1,000 feet to 20,000 feet below the surface. These formations range from the Sparta and Frio formations in the northern part of the region to Miocene and Pleistocene in the southern part of the region. The Company’s production comes predominately from Miocene and Frio age formations.

Burrwood and West Delta 83 Fields.    The Burrwood and West Delta 83 fields, located in Plaquemines Parish, Louisiana, were discovered in 1955 by Chevron. The fields lie upthrown to a large down-to-the southeast growth fault system with the structure striking northeast-southwest and dipping northwestward in a counter-regional direction. The fields have collectively produced over 50 million barrels of oil and 150 Bcf of natural gas. The productive sands are Miocene and Pliocene age sands ranging in depth from 6,300 feet to approximately 11,700 feet. There are currently 19 active producing wells in the fields.

Goodrich acquired a 95% working interest in approximately 8,600 acres of the Burrwood and West Delta 83 fields through an acquisition that closed on March 2, 2000 with an effective date of January 1, 2000. On March 12, 2002, the Company sold a 30% working interest in the existing production and shallow rights, and a 15% working interest in the deep rights below 10,600 feet, in such fields for $12 million to Malloy Energy Company, LLC (“MEC”) led by Patrick E. Malloy, III and participated in by Sheldon Appel, each of whom were members of the Company’s Board of Directors at that time, as well as Josiah Austin, who subsequently became a member of the Company’s Board of Directors. Mr. Malloy is currently Chairman of the Company’s Board of Directors and Mr. Appel retired from the Board of Directors in February 2004. For a further discussion of this transaction, see Note C of the Company’s consolidated financial statements in Item 8.

Lafitte Field.    The Lafitte field is located in Jefferson Parish, Louisiana and was discovered in 1935 by Texaco. The Lafitte field is a large, north-south elongated salt dome anticline feature. There are currently more than thirty (30) defined productive sands, which have collectively produced in excess of approximately 265 million barrels of oil and 320 Bcf of natural gas. The productive sands are Miocene and Pliocene age sands ranging in depth from 3,000 feet to approximately 12,000 feet. There are currently 25 active producing wells in the field. In September 1999, the Company acquired a non-operated working interest of approximately 49% in the Lafitte field with respect to the field’s leases, surface facilities and equipment and a non-operated working interest of approximately 45% in the active producing wells. In November 1999, the Company acquired additional interests, resulting in a field-wide non-operated working interest of approximately 49%.

Second Bayou Field.    The Second Bayou field is located in Cameron Parish, Louisiana and was discovered in 1955 by the Sun Texas Company. Goodrich is the operator of eight producing wells, three of which are dually completed, and has an average working interest of approximately 31% in 1,395 gross acres. To date, the field has produced over 425 Bcf of natural gas and 3.6 million barrels of oil from multiple Miocene aged sands ranging from 4,000 to 15,200 feet.

Plumb Bob.    The Plumb Bob field is located in St. Martin Parish in southern Louisiana and was originally discovered by Texaco in 1939. Apache acquired the field from Texaco in a large divesture package in 1995 and did not drill any additional wells in the field prior to the time it was abandoned in 1997. In September 2003, the

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Company reached an agreement with a subsequent owner to obtain certain rights in the field. The rights include a 70% working interest in oil and gas leases covering approximately 450 acres and 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 and evaluation of the seismic data was completed in late 2004 and the Company will soon determine the extent of its drilling and remaining workover plans in the field.

St. Gabriel.    The St. Gabriel field is located in Ascension and Iberville Parishes in southern Louisiana and was originally discovered by Shell Oil Company in 1939. 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 field. 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 expected to be completed in April 2005.

Other.    The Company maintains ownership interests in acreage and wells in several additional fields in Louisiana, including the (i) Ada field, located in Bienville Parish, (ii) Lake Raccourci field, located in Terrebonne Parish and (iii) Pecan Lake field, located in Cameron Parish.

Texas

In addition to the areas in Texas indicated previously under “Cotton Valley Drilling Program”, the Company presently has production operations in the eastern and southern regions of Texas, as more fully described below.

Mary Blevins Field.    The Mary Blevins field is located in Smith County, Texas. It was a new discovery that is fault separated from Hitts Lake field, which was discovered in 1953 by Sun Oil. Currently, there are two producing wells in the field in which Goodrich serves as operator, having an approximate 48% working interest in 782 gross acres. To date, Hitts Lake has produced over 14 million barrels of oil and Mary Blevins has produced over 551,000 barrels of oil from the Paluxy B sands, which occur at a depth of approximately 7,300 feet.

Marholl and Sean Andrew Fields.    The Marholl field is a Siluro-Devonian (Fussellman) field in Dawson County, Texas, discovered in 1995 through the use of 3-D seismic. Prior to selling its interest in the field in October 2004, the Company operated two wells in the field with an approximate 23% working interest. The Sean Andrew field in Dawson County, Texas was discovered by the Company in 1994 utilizing the Company’s 375 square mile 3-D seismic database in West Texas. Prior to selling its interest in the field in October 2004, the Company was the operator of two wells in the field and held an approximate 37.5% working interest. In October 2004, the Company sold its operated interests in both the Marholl and Sean Andrew fields, along with its non-operated interests in the Ackerly field, located in Dawson and Howard Counties, to third parties for gross proceeds of $2.1 million and recognized a non-recurring gain of $877,000 on the sale.

Other.    The Company maintains ownership interests in acreage and/or wells in several additional fields in Texas including the (i) Midway field, located in San Patricio County and (ii) Mott Slough field, located in Wharton County.

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Oil and Natural Gas Reserves

The following tables set forth summary information with respect to the Company’s proved reserves as of December 31, 2004 and 2003, as estimated by the Company by compiling reserve information derived from the evaluations performed by Netherland Sewell & Associates, Inc. as of December 31, 2004, and by Coutret and Associates, Inc. as of December 31, 2003.

Reserve engineering is a subjective process of estimating underground accumulations of crude oil, condensate and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and natural gas sales prices may differ from those assumed in these estimates. Therefore, the pre-tax Present Value of Future Net Revenues amounts shown above should not be construed as the current market value of the oil and natural gas reserves attributable to the Company’s properties.

In accordance with the guidelines of the Securities and Exchange Commission (SEC), the engineers’ estimates of future net revenues from the Company’s properties and the pre-tax Present Value of Future Net Revenues thereof are made using oil and natural gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. The prices as of December 31, 2004, and 2003 used in such estimates averaged $6.14 and $6.42 per Mcf, respectively, of natural gas and $42.72 and $31.75 per Bbl, respectively, of crude oil/condensate.

Productive Wells

The following table sets forth the number of active well bores in which the Company maintains ownership interests as of December 31, 2004:

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Productive wells consist of producing wells and wells capable of production, including gas wells awaiting pipeline connections. A gross well is a well in which the Company maintains an ownership interest, while a net well is deemed to exist when the sum of the fractional working interests owned by the Company equals one. Wells that are completed in more than one producing horizon are counted as one well. Of the gross wells reported above, eight had multiple completions.

Acreage

The following table summarizes the Company’s gross and net developed and undeveloped natural gas and oil acreage under lease as of December 31, 2004. Acreage in which the Company’s interest is limited to a royalty or overriding royalty interest is excluded from the table.

Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to the extent that would permit the production of commercial quantities of natural gas or oil, regardless of whether or not such acreage contains proved reserves. As is customary in the oil and gas industry, the Company can retain its interest in undeveloped acreage by drilling activity that establishes commercial production sufficient to maintain the leases or by payment of delay rentals during the remaining primary term of such a lease. The natural gas and oil leases in which the Company has an interest are for varying primary terms; however, most of the Company’s developed lease acreage is beyond the primary term and is held so long as natural gas or oil is produced.

Operator Activities

The Company operates a majority in value of its producing properties, and will generally seek to become the operator of record on properties it drills or acquires in the future.

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Drilling Activities

The following table sets forth the drilling activities of the Company for the last three years. (As denoted in the following table, “Gross” wells refers to wells in which a working interest is owned, while a “net” well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one.)

Net Production, Unit Prices and Costs

The following table presents certain information with respect to oil, gas and condensate production attributable to the Company’s interests in all of its fields, the revenue derived from the sale of such production, average sales prices received and average production costs during each of the years in the three-year period ended December 31, 2004.

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The Company’s acquisition strategy for the Gulf Coast Basin calls for the acquisition of mature oil and gas fields with declining production profiles, established production histories and multiple productive sands that have been overlooked and/or starved of capital. Acquisitions of this type generally require significant lease operation, exploration and capital expenditure cash outlays during initial years of ownership. The Company’s Lafitte and Burrwood/West Delta 83 acquisitions in 1999 and 2000, were strategic acquisitions that fit the aforementioned profile, and account for the majority of the unit costs in the periods presented above. The impact of the Cotton Valley drilling program in East Texas and Northwest Louisiana will begin to affect the Company’s unit costs to a greater extent in 2005 and are expected to result in a gradual decrease in lease operating and exploration expenses and a gradual increase in DD&A expense.

Oil and Gas Marketing and Major Customers

Marketing.    Goodrich’s natural gas production is sold under spot or market-sensitive contracts to various gas purchasers on short-term contracts. Goodrich’s natural gas condensate is sold under short-term rollover agreements based on current market prices. The Company’s crude oil production is marketed to several purchasers based on short-term contracts.

Customers.    Due to the nature of the industry, the Company sells its oil and natural gas production to a limited number of purchasers and, accordingly, amounts receivable from such purchasers could be significant. Revenues from these sources as a percent of total revenues for the periods presented were as follows:

Competition

The oil and gas industry is highly competitive. Major and independent oil and gas companies, drilling and production acquisition programs and individual producers and operators are active bidders for desirable oil and gas properties, as well as the equipment and labor required to operate those properties. Many competitors have financial resources substantially greater than those of the Company, and staffs and facilities substantially larger than those of the Company. The availability of a ready market for the oil and gas production of the Company will depend in part on the cost and availability of alternative fuels, the level of consumer demand, the extent of domestic production of oil and gas, the extent of importation of foreign oil and gas, the cost of and proximity to pipelines and other transportation facilities, regulations by state and federal authorities and the cost of complying with applicable environmental regulations.

Regulations

The availability of a ready market for any natural gas and oil production depends upon numerous factors beyond the Company’s control. These factors include regulation of natural gas and oil production, federal and state regulations governing environmental quality and pollution control, state limits on allowable rates of production by a well or proration unit, the amount of natural gas and oil available for sale, the availability of

adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. For

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example, a productive natural gas well may be “shut-in” because of an oversupply of natural gas or the lack of an available natural gas pipeline in the areas in which the Company may conduct operations. State and federal regulations generally are intended to prevent waste of natural gas and oil, protect rights to produce natural gas and oil between owners in a common reservoir, control the amount of natural gas and oil produced by assigning allowable rates of production and control contamination of the environment. Pipelines are subject to the jurisdiction of various federal, state and local agencies as well.

Environmental Matters

The Company’s operations are subject to numerous stringent and complex laws and regulations at the federal, state and local levels governing the discharge of materials into the environment or otherwise relating to environmental protection. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements, and the imposition of injunctions to force future compliance.

The Oil Pollution Act of 1990 (“OPA 90”) and its implementing regulations impose a variety of requirements related to the prevention of oil spills, and liability for damages resulting from such spills in United States waters. OPA 90 imposes strict, joint and several liability on responsible parties for oil removal costs and a variety of public and private damages, including natural resource damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operation regulation. If a party fails to report a spill or to cooperate fully in a cleanup, liability limits likewise do not apply. Even if applicable, the liability limits for offshore facilities require the responsible party to pay all removal costs, plus up to $75 million in other damages. For onshore facilities, the total liability limit is $350 million. OPA 90 also requires a responsible party at an offshore facility to submit proof of its financial ability to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill.

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, and analogous state laws impose strict, joint and several liability on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These parties include the owner or operator of the site where the release occurred, and those that disposed or arranged for the disposal of hazardous substances found at the site. Responsible parties under CERCLA may be subject to joint and several liability for remediation costs at the site, and may also be liable for natural resource damages. Additionally, it is not uncommon for neighboring landowners and other third parties to file tort claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. See existing environmental matters discussed in Item 3—Legal Proceedings.

State statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. In addition, there are state statutes, rules and regulations governing conservation matters, including the unitization or pooling of oil and gas properties, establishment of maximum rates of production from oil and gas wells and the spacing, plugging and abandonment of such wells. Such statutes and regulations may limit the rate at which oil and gas could otherwise be produced from the Company’s properties and may restrict the number of wells that may be drilled on a particular lease or in a particular field.

Management believes that the Company is in substantial compliance with current applicable federal and state environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on its operations or financial condition.

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Risk Factors

The Company’s actual production, revenues and expenditures related to its reserves are likely to differ from its estimates of proved reserves. The Company may experience production that is less than estimated and drilling costs that are greater than estimated in its reserve reports. These differences may be material.

The proved oil and gas reserve information included in this report are estimates. These estimates are based on reports prepared by consulting reserve engineers and were calculated using oil and gas prices as of December 31, 2004. These prices will change and may be lower at the time of production than those prices that prevailed at the end of 2004. Petroleum engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner.

Estimates of economically recoverable oil and gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, including:

Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating proved reserves:

Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. The Company’s actual production, revenues and expenditures with respect to reserves will likely be different from estimates and the differences may be material. The discounted future net cash flows included in this document should not be considered as the current market value of the estimated oil and gas reserves attributable to its properties. As required by the SEC, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as:

In addition, the 10% discount factor, which is required by the SEC to be used to calculate discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and gas industry in general.

Natural gas and oil prices are volatile, and low prices have had in the past and could have in the future a material adverse impact on the Company’s business.

The Company’s success will depend on the market prices of oil and gas. These market prices tend to fluctuate significantly in response to factors beyond the Company’s control. The prices the Company receives for

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its crude oil production are based on global market conditions. The general pace of global economic growth, the continued instability in the Middle East and actions of the Organization of Petroleum Exporting Countries, or OPEC, and its maintenance of production constraints, as well as other economic, political, and environmental factors will continue to affect world supply and prices. Domestic natural gas prices fluctuate significantly in response to numerous factors including U.S. economic conditions, weather patterns, other factors affecting demand such as substitute fuels, the impact of drilling levels on crude oil and natural gas supply, and the environmental and access issues that limit future drilling activities for the industry.

Average oil and gas prices increased substantially from 2002 to 2003 and from 2003 to 2004. The Company expects that commodity prices will continue to fluctuate significantly in the future.

Changes in commodity prices significantly affect the Company’s capital resources, liquidity and expected operating results. Price changes directly affect revenues and can indirectly impact expected production by changing the amount of funds available to the Company to reinvest in exploration and development activities. Reductions in oil and gas prices not only reduce revenues and profits, but could also reduce the quantities of reserves that are commercially recoverable. Significant declines in prices could result in non-cash charges to earnings due to impairment. The Company uses derivative financial instruments to hedge a portion of its exposure to changing commodity prices and the Company has hedged a targeted portion of its anticipated production for 2005.

The Company’s use of oil and gas price hedging contracts may limit future revenues from price increases and result in significant fluctuations in its net income.

The Company use hedging transactions with respect to a portion of its oil and gas production to achieve more predictable cash flow and to reduce its exposure to price fluctuations. While the use of hedging transactions limits the downside risk of price declines, their use may also limit future revenues from price increases.

The Company’s results of operations may be negatively impacted by its financial derivative instruments and fixed price forward sales contracts in the future and these instruments may limit any benefit the Company would receive from increases in the prices for natural gas and oil. For the years ended December 31, 2004, 2003 and 2002, the Company realized a loss on settled financial derivatives of $6.17 million, $2.70 million and $1.01 million, respectively.

In the year ended December 31, 2004, the Company recognized in earnings an unrealized gain on derivative instruments in the amount of $2,317,000. This gain was recognized because the Company’s natural gas hedges were deemed to be ineffective for the fourth quarter of 2004, accordingly, the changes in fair value of such hedges could no longer be reflected 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 likewise be exposed to volatility in earnings resulting from changes in the fair value of its hedges.

Delays in development or production curtailment affecting the Company’s material properties may adversely affect its financial position and results of operations.

The size of the Company’s operations and its capital expenditure budget limits the number of wells that the Company can develop in any given year. Complications in the development of any single material well may result in a material adverse affect on the Company’s financial condition and results of operations. In addition, a relatively small number of wells contribute a substantial portion of the Company’s production. If the Company were to experience operational problems resulting in the curtailment of production in any of these wells, the Company’s total production levels would be adversely affected, which would have a material adverse affect on its financial condition and results of operations.

Because the Company’s operations require significant capital expenditures, the Company may not have the funds available to replace reserves, maintain production or maintain interests in its properties.

The Company must make a substantial amount of capital expenditures for the acquisition, exploration and development of oil and gas reserves. Historically, the Company has paid for these expenditures with cash from

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operating activities, proceeds from debt and equity financings and asset sales. The Company’s revenues or cash flows could be reduced because of lower oil and gas prices or for other reasons. If the Company’s revenues or cash flows decrease, it may not have the funds available to replace reserves or maintain production at current levels. If this occurs, the Company’s production will decline over time. Other sources of financing may not be available to the Company if the Company’s cash flows from operations are not sufficient to fund its capital expenditure requirements. Where the Company is not the majority owner or operator of an oil and gas property, such as the Lafitte field, the Company may have no control over the timing or amount of capital expenditures associated with the particular property. If the Company cannot fund such capital expenditures, its interests in some properties may be reduced or forfeited.

The Company may have difficulty financing its planned growth.

The Company has experienced and expects to continue to experience substantial capital expenditure and working capital needs, particularly as a result of its drilling program. In the future, the Company expects that it will require additional financing, in addition to cash generated from operations, to fund planned growth. The Company cannot be certain that additional financing will be available on acceptable terms or at all. In the event additional capital resources are unavailable, the Company may curtail drilling, development and other activities or be forced to sell some of its assets on an untimely or unfavorable basis.

If the Company is not able to replace reserves, it may not be able to sustain production at present levels.

The Company’s future success depends largely upon its ability to find, develop or acquire additional oil and gas reserves that are economically recoverable. Unless the Company replaces the reserves it produce through successful development, exploration or acquisition activities, its proved reserves will decline over time. In addition, approximately 63% of the Company’s total estimated proved reserves by volume at December 31, 2004 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling operations. The Company may not be able to successfully find and produce reserves economically in the future. In addition, it may not be able to acquire proved reserves at acceptable costs.

The Company may incur substantial impairment writedowns.

If management’s estimates of the recoverable reserves on a property are revised downward or if natural gas and oil prices decline, it may be required to record additional non-cash impairment writedowns in the future, which would result in a negative impact to its financial position. The Company reviews its proved oil and gas properties for impairment on a depletable unit basis when circumstances suggest there is a need for such a review. To determine if a depletable unit is impaired, the Company compares the carrying value of the depletable unit to the undiscounted future net cash flows by applying management’s estimates of future oil and gas prices to the estimated future production of oil and gas reserves over the economic life of the property. Future net cash flows are based upon the Company’s independent reservoir engineers’ estimates of proved reserves. In addition, other factors such as probable and possible reserves are taken into consideration when justified by economic conditions. For each property determined to be impaired, the Company recognizes an impairment loss equal to the difference between the estimated fair value and the carrying value of the property on a depletable unit basis.

Fair value is estimated to be the present value of expected future net cash flows. Any impairment charge incurred is recorded in accumulated depreciation, depletion, impairment and amortization to reduce the Company’s recorded basis in the asset. Each part of this calculation is subject to a large degree of judgment, including the determination of the depletable units’ estimated reserves, future cash flows and fair value. The Company recorded no impairment in the year ended December 31, 2004, however, it recorded annual impairments of $0.34 million and $0.34 million, respectively, for the years ended December 31, 2003 and 2002.

Management’s assumptions used in calculating oil and gas reserves or regarding the future cash flows or fair value of the Company’s properties are subject to change in the future. Any change could cause impairment

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expense to be recorded, impacting the Company’s net income or loss and its basis in the related asset. Any change in reserves directly impacts the Company’s estimate of future cash flows from the property, as well as the property’s fair value. Additionally, as management’s views related to future prices change, the change will affect the estimate of future net cash flows and the fair value estimates. Changes in either of these amounts will directly impact the calculation of impairment.

A majority of the Company’s production, revenue and cash flow from operating activities are derived from assets that are concentrated in a geographic area.

Approximately 54% of the Company’s estimated proved reserves at December 31, 2004 and a substantially higher percentage of its production were associated with its core South Louisiana properties (primarily, Burrwood and West Delta 83 fields, Lafitte field, Second Bayou field, Plumb Bob field and Lake Raccourci field). Accordingly, if the level of production from these properties substantially declines, it could have a material adverse effect on the Company’s overall production level and its revenue.

The oil and gas business involves many uncertainties, economic risks and operating risks that can prevent the Company from realizing profits and can cause substantial losses.

The Company’s oil and gas operations are subject to the economic risks typically associated with exploration, development and production activities, including the necessity of significant expenditures to locate and acquire properties and to drill exploratory wells. In conducting exploration and development activities, the presence of unanticipated pressure or irregularities in formations, miscalculations or accidents may cause the Company’s exploration, development and production activities to be unsuccessful. This could result in a total loss of the Company’s investment in a particular property. If exploration efforts are unsuccessful in establishing proved reserves and exploration activities cease, the amounts accumulated as unproved costs would be charged against earnings as impairments. In addition, the cost and timing of drilling, completing and operating wells is often uncertain.

The nature of the oil and gas business involves certain operating hazards such as well blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, formations with abnormal pressures, pollution, releases of toxic gas and other environmental hazards and risks. Any of these operating hazards could result in substantial losses to the Company. As a result, substantial liabilities to third parties or governmental entities may be incurred. The payment of these amounts could reduce or eliminate the funds available for exploration, development or acquisitions. These reductions in funds could result in a loss of the Company’s properties. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of such risks and losses. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on the Company’s financial position and results of operations.

The Company’s debt instruments impose restrictions on the Company that may affect the Company’s ability to successfully operate its business.

The Company’s senior credit facility contains customary restrictions, including covenants limiting the Company’s ability to incur additional debt, grant liens, make investments, consolidate, merge or acquire other businesses, sell assets, pay dividends and other distributions and enter into transactions with affiliates. The Company also is required to meet specified financial ratios under the terms of its credit facility. These restrictions may make it difficult for the Company to successfully execute its business strategy or to compete in its industry with companies not similarly restricted.

The Company may be unable to identify liabilities associated with the properties that it acquires or obtain protection from sellers against them.

The acquisition of properties requires the Company to assess a number of factors, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are

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inexact and inherently uncertain. In connection with the assessments, the Company performs a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of the Company’s due diligence, it may not inspect every well, platform or pipeline. The Company cannot necessarily observe structural and environmental problems, such as pipeline corrosion, when an inspection is made. The Company may not be able to obtain contractual indemnities from the seller for liabilities that it created. The Company may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with its expectations.

The Company is subject to complex laws and regulations, including environmental regulations that can adversely affect the cost, manner or feasibility of doing business.

Development, production and sale of natural gas and oil in the U.S. are subject to extensive laws and regulations, including environmental laws and regulations. The Company may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include:

Under these laws and regulations, it could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. Failure to comply with these laws and regulations also may result in the suspension or termination of its operations and subject the Company to administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that substantially increase the Company’s costs. Accordingly, any of these liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect the Company’s financial condition and results of operations.

Competition in the oil and gas industry is intense, and the Company is smaller and has a more limited operating history than some of its competitors.

The Company competes with major and independent natural gas and oil companies for property acquisitions. The Company also competes for the equipment and labor required to operate and to develop these properties. Some of the Company’s competitors have substantially greater financial and other resources than the Company. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than the Company can, which would adversely affect its competitive position. These competitors may be able to pay more for natural gas and oil properties and may be able to define, evaluate, bid for and acquire a greater number of properties than the Company can. The Company’s ability to acquire additional properties and develop new and existing properties in the future will depend on its ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.

The Company’s success depends on its management team and other key personnel, the loss of any of whom could disrupt its business operations.

The Company’s success will depend on its ability to retain and attract experienced engineers, geoscientists and other professional staff. The Company depends to a large extent on the efforts, technical expertise and continued employment of these personnel and members of its management team. If a significant number of them resign or become unable to continue in their present role and if they are not adequately replaced, the Company’s business operations could be adversely affected.

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Some of the Company’s operations are exposed to the additional risk of tropical weather disturbances.

Some of the Company’s production and reserves are located in South Louisiana. Operations in this area are subject to tropical weather disturbances. Some of these disturbances can be severe enough to cause substantial damage to facilities and possibly interrupt production. For example, Hurricane Ivan impacted the Company’s South Louisiana operations in September 2004 causing property damage to certain facilities in the Company’s Burrwood and West Delta 83 fields, a substantial portion of which was covered by insurance. Additionally, oil and gas production in those fields was completely or partially shut-in for approximately 10 days reducing the Company’s overall production volumes in the third quarter of 2004 by approximately 5%. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of these risks.

Terrorist attacks or similar hostilities may adversely impact the Company’s results of operations.

The impact that future terrorist attacks or regional hostilities (particularly in the Middle East) may have on the energy industry in general, and on the Company in particular, is unknown. Uncertainty surrounding military strikes or a sustained military campaign may affect the Company’s operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants and refineries, could be direct targets of, or indirect casualties of, an act of terror or war. The terrorist attacks on September 11, 2001 and the changes in the insurance markets attributable to such attacks have made certain types of insurance more difficult for the Company to obtain. There can be no assurance that insurance will be available to the Company without significant additional costs. Instability in the financial markets as a result of terrorism or war could also affect the Company’s ability to raise capital.

Item 3.    Legal Proceedings.

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

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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.

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

None.

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PART II

Item 5.    Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

The Company’s common stock is traded on the New York Stock Exchange under the symbol “GDP”.

At March 24, 2005, the number of holders of record of the Company’s common stock without determination of the number of individual participants in security positions was 1,681 with 21,050,430 shares outstanding. High and low sales prices for the Company’s common stock for each quarter during the calendar years 2004 and 2003 are as follows:

Dividends

The Company has neither declared nor paid any cash dividends on its common stock and does not anticipate declaring any dividends in the foreseeable future. The Company expects to retain its cash for the operation and expansion of its business, including exploration, development and production activities. In addition, the Company’s senior bank credit facility contains restrictions on the payment of dividends to the holders of common stock. For additional information, see “Item 7. Management’s Discussion And Analysis Of Financial Condition And Results Of Operations.”

Issuer Repurchases of Equity Securities

The Company made no repurchases of its common stock in the year ended December 31, 2004.

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Item 6.    Selected Financial Data.

Selected Statement of Operations Data:

The following table sets forth selected financial data of the Company for each of the years in the five-year period ended December 31, 2004, which information has been derived from the Company’s audited financial statements. This information should be read in connection with and is qualified in its entirety by the more detailed information in the Company’s financial statements under Item 8 below and in “Item 7. Management’s Discussion And Analysis Of Financial Condition And Results Of Operations.”

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Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operation.

General

The Company is an independent oil and gas company engaged in the exploration, exploitation, development and production of oil and natural gas properties primarily in the Cotton Valley trend of East Texas and Northwest Louisiana and in the transition zone of South Louisiana. The Company owns working interests in 89 active oil and gas wells located in 18 fields in four states. At December 31, 2004, Goodrich had estimated proved reserves of approximately 5.6 million barrels of oil and condensate and 67.7 billion cubic feet (“Bcf”) of natural gas, or an aggregate of 101.21 Bcf equivalent (“Bcfe”) with a pre-tax present value of future net revenues, discounted at 10%, of $241.5 million and an after-tax present value of future net revenues of $180.7 million.

The Company seeks to increase shareholder value by growing its oil and gas reserves, production revenues and operating cash flow. In the Company’s opinion, on a long term basis, growth in oil and gas reserves and production, on a cost-effective basis, are the most important indicators of performance success for an independent oil and gas company such as Goodrich.

Management strives to increase the Company’s oil and gas reserves, production and cash flow through a balanced program of capital expenditures involving acquisition, exploitation and exploration activities. The Company generally does not make capital commitments beyond one year. Goodrich develops an annual capital expenditure budget which is reviewed and approved by its board of directors on a quarterly basis and revised throughout the year as circumstances warrant. The Company takes into consideration its projected operating cash flow and externally available sources of financing, such as bank debt, when establishing its capital expenditure budget.

The Company places primary emphasis on its internally generated operating cash flow in managing its business. For this purpose, operating cash flow is defined as cash flow from operating activities as reflected in the Company’s Statement of Cash Flows. Management considers operating cash flow a more important indicator of its financial success than other traditional performance measures such as net income.

The Company’s revenues and operating cash flow are dependent on the successful development of its inventory of capital projects, the volume and timing of its production, as well as commodity prices for oil and gas. Such pricing factors are largely beyond the Company’s control, however, Goodrich employs commodity hedging techniques in an attempt to minimize the volatility of short term commodity price fluctuations on its earnings and operating cash flow.

As further described under “Results of Operations” below, the Company achieved significant increases in oil and gas production volumes and operating cash flows in the years ended December 31, 2003 and 2004. These trends largely reflect the results of Goodrich’s successful drilling program as the Company increased its capital expenditures from $8.1 million in 2002, to $19.9 million in 2003 and $47.5 million in 2004. The Company also benefited from a strong commodity pricing environment in both 2003 and 2004.

Results of Operations

Year ended December 31, 2004 versus year ended December 31, 2003—Total revenues from continuing operations for the year ended December 31, 2004 amounted to $47,330,000 compared to $32,140,000 for the year ended December 31, 2003. Oil and gas sales for the year ended December 31, 2004 were $44,861,000

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compared to $31,663,000 for the year ended December 31, 2003. This increase resulted from a 25% increase in oil and gas production volumes, due to several successful well completions since the first quarter of 2003, as well as increase in average oil and gas prices. 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.”

Unrealized gain on derivatives, which is not reflected in the above calculation of average prices, amounted to $2,317,000 in the year ended December 31, 2004, compared to zero in the year ended December 31, 2003. The 2004 amount arose because the Company’s natural gas hedges were deemed to be ineffective for the fourth quarter of 2004, 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 likewise be exposed to volatility in earnings resulting from changes in the fair value of its hedges.

Other revenues for the year ended December 31, 2004 were $151,000 compared to $477,000 for the year ended December 31, 2003, with the decrease primarily due to the absence of prospect fees received on two drilling prospects in the first quarter of 2003.

Lease operating expense from continuing operations was $7,402,000 for the year ended December 31, 2004 versus $6,099,000 for the year ended December 31, 2003, with the increase largely resulting from an increase in the number of producing wells. Production taxes from continuing operations were $3,105,000 in the year ended December 31, 2004 compared to $2,288,000 in the year ended December 31, 2003, due to an increase in production volumes. Depletion, depreciation and amortization expense from continuing operations was $11,562,000 for the year ended December 31, 2004 versus $8,995,000 for the year ended December 31, 2003, with the increase due to higher production volumes and depletion rates. Exploration expense in the year ended December 31, 2004 was $4,426,000 versus $2,249,000 in the year ended December 31, 2003, with the increase primarily due to seismic costs in the Plumb Bob and St. Gabriel fields and higher non-producing leasehold amortization expense, partially offset by a decrease in exploratory dry hole costs.

The Company recorded no impairment in the recorded value of its oil and gas properties in the year ended December 31, 2004 whereas in the year ended December 31, 2003, it recorded an impairment in the amount of $336,000 due primarily to a sooner than anticipated depletion of reserves in certain fields.

General and administrative expenses amounted to $5,821,000 in the year ended December 31, 2004 versus $5,314,000 in the year ended December 31, 2003. The most significant factor in this variance resulted from an increase in the Company’s payroll and employee benefits expense to $2,200,000 in the year ended December 31, 2004 from $1,637,000 in the year ended December 31, 2003, primarily due to an increase in the number of employees. Partially offsetting this increase were decreases in legal fees and certain other administrative expenses.

Interest expense was $1,110,000 in the year ended December 31, 2004 compared to $1,051,000 in the year ended December 31, 2003, with the increase primarily attributable to a higher level of borrowings in the 2004 period.

Gains and losses on asset sales and litigation judgment were a net gain of $2,168,000 in the year ended December 31, 2004 compared to a net loss of $66,000 in the year ended December 31, 2003, with the increase

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primarily due to a non-recurring gain resulting from the final judgment ordered by the trial judge in favor of the Company in its litigation against the operator of the Lafitte field.

Income taxes attributable to continuing operations were a benefit of $1,707,000 in the year ended December 31, 2004 compared to an expense of $2,015,000 in the year ended December 31, 2003. The Company revised its deferred tax valuation allowance in the year ended December 31, 2004, based on the anticipated utilization of tax operating loss carryforwards and projected reversal of temporary differences, whereas in the year ended December 31, 2003 income tax expense represented 35% of pre-tax income attributable to continuing operations.

Income from discontinued operations, net of income taxes, was $750,000 in the year ended December 31, 2004 consisting largely of the pre-tax gain realized on the sale of the Company’s 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. The results of operations of these non-core properties, including the pre-tax gain of $877,000 realized on the sale, have been classified as discontinued operations in the consolidated statement of operations, net of income tax expense at a 35% rate.

Year ended December 31, 2003 versus year ended December 31, 2002—Total revenues from continuing operations for the year ended December 31, 2003 amounted to $32,140,000 compared to $18,633,000 for the year ended December 31, 2002. Oil and gas sales for the year ended December 31, 2003 were $31,663,000 compared to $18,502,000 for the year ended December 31, 2002. This increase resulted from a 21% increase in oil and gas production volumes, due to several successful well completions from late 2002 and into 2003, 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 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 year ended December 31, 2003 were $477,000 compared to $131,000 for the year ended December 31, 2002, with the increase primarily due to prospect fees received by the Company in the first quarter of 2003 on the sale of interests in its Spyglass II and Tunney drilling prospects.

Lease operating expense from continuing operations was $6,099,000 for the year ended December 31, 2003 versus $7,523,000 for the year ended December 31, 2002, with the decrease due primarily to the Company’s ongoing efforts to reduce costs on its operated properties since replacing a contract operator in June 2002. Production taxes from continuing operations were $2,288,000 in the year ended December 31, 2003 compared to $1,642,000 in the year ended December 31, 2002, due to an increase in production volumes as well as an increase in tax rates. Depletion, depreciation and amortization expense from continuing operations was $8,995,000 for the year ended December 31, 2003 versus $7,023,000 for the year ended December 31, 2002, with the increase substantially due to higher production volumes and rates. Exploration expense in the year ended December 31, 2003 was $2,249,000 versus $1,019,000 in the year ended December 31, 2002, due primarily to the Company recognizing dry hole costs during 2003 in the amounts of $675,000 and $141,000, respectively, related to non-operated exploratory wells drilled in offshore Australia and Calcasieu Parish, Louisiana, as well as an increase in seismic costs.

The Company recorded an impairment in the recorded value of certain oil and gas properties in the year ended December 31, 2003 in the amount of $336,000 due primarily to a sooner than anticipated depletion of reserves in non-core fields. This compares to an impairment of $342,000 recorded in the year ended December 31, 2002.

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General and administrative expenses amounted to $5,314,000 in the year ended December 31, 2003 versus $4,468,000 in the year ended December 31, 2002. The most significant factors in this variance were non-cash charges of $403,000 related to the February 2003 issuance of 125,157 shares of common stock in lieu of 1,016,500 cancelled stock options, $155,000 related to the initial vesting of employee stock awards of 161,500 shares of restricted stock made primarily in February 2003 and increased legal expenses of $82,000, associated with the Company’s litigation against the operator of the Lafitte field, as well as higher insurance, payroll and other administrative expenses.

Interest expense was $1,051,000 in the year ended December 31, 2003 compared to $985,000 in the year ended December 31, 2002, with the decrease in interest rates being virtually offset by an increase in borrowings.

The Company recorded deferred tax expense (not requiring cash payment) of $2,015,000 in the year ended December 31, 2003 compared to a deferred tax benefit of $496,000 in the year ended December 31, 2002, with the increase attributable to achieving pre-tax income in 2003. The Company’s effective tax rate was 35.1% in 2003 and 34.7% in 2002. The Company has established a deferred tax valuation allowance for those deferred tax assets that it does not expect to realize based on estimates of future taxable income and the impact of the Company’s tax attributes.

Liquidity and Capital Resources

Net cash provided by operating activities was $41,028,000 in the year ended December 31, 2004, compared to $17,048,000 in the year ended December 31, 2003 and $5,349,000 in the year ended December 31, 2002. The increase in the 2004 period reflects higher oil and gas revenues, partially offset by increases in lease operating expenses, production taxes and exploration expenses. The increase in the 2003 period reflects higher oil and gas revenues and lower lease operating expenses, partially offset by an increase in general and administrative expenses. The operating cash flow amounts reflect changes in current assets and current liabilities, which resulted in an increase in operating cash flow of $14,119,000 in the year ended December 31, 2004, a decrease of $519,000 in the year ended December 31, 2003, and an increase of $1,589,000 in the year ended December 31, 2002.

Net cash used in investing activities was $45,414,000 and $19,500,000 in the years ended December 31, 2004 and 2003, respectively, compared to net cash provided by investing activities of $4,743,000 in the year ended December 31, 2002. In the year ended December 31, 2004, capital expenditures totaled $47,501,000, as the Company incurred substantial drilling and leasehold acquisition costs in East Texas and Northwest Louisiana (see “Cotton Valley Drilling Program”) and participated in the drilling of two successful exploratory wells and one successful sidetrack well in the Burrwood/West Delta 83 field. Offsetting these capital expenditures were sales of non-core properties in West Texas and another minor property in the total amount of $2,087,000. In the year ended December 31, 2003, capital expenditures totaled $19,898,000 as the Company participated in the drilling of nine new wells in its Burrwood/West Delta 83, Lafitte and Bethany-Longstreet fields (eight of which were successfully completed). In the same period, the Company sold its interests in the South Drew field in Louisiana and two smaller properties in Texas for gross proceeds of $399,000. In the year ended December 31, 2002, capital expenditures totaled $8,079,000 as the Company participated in the drilling of two new wells, however, such expenditures were more than offset by proceeds from property sales of $12,823,000, primarily due to the sale of a 30% interest in the Company’s Burrwood/West Delta 83 fields as further described below (see “Sale of Oil and Gas Properties to Related Party”).

Net cash provided by financing activities was $6,346,000 and $589,000 in the years ended December 31, 2004 and 2003, respectively, compared to net cash used in financing activities of $6,989,000 in the year ended December 31, 2002. In the year ended December 31, 2004, net borrowings under the Company’s senior credit facility provided cash of $7,000,000 and exercises of stock options and warrants provided cash of $340,000, while preferred stock dividends and production payments used cash of $994,000. In the year ended December 31, 2003, net borrowings under the Company’s senior credit facility provided cash of $1,500,000 and exercises of

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stock options and warrants provided cash of $129,000, while preferred stock dividends and production payments required cash of $1,040,000. In the year ended December 31, 2002, net repayments under the Company’s senior credit facility reduced cash by $6,000,000, while preferred stock dividends and production payments required additional cash of $1,017,000. The cash resources for the net debt repayments in the year ended December 31, 2002 were provided by the sale of an interest in the Company’s Burrwood/West Delta 83 fields as further described below (see “Sale of Oil and Gas Properties to Related Party”).

For the year 2005, the Company has preliminarily budgeted total capital expenditures of approximately $75 million, of which approximately two-thirds 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”). Additionally, the Company is considering the possible issuance of debt or equity securities to provide additional financial resources for its capital expenditures and other general corporate purposes. The Company’s senior credit facility includes certain financial covenants with which the Company was in compliance as of December 31, 2004. The Company does not anticipate a lack of borrowing capacity under its senior credit facility in the foreseeable future due to an inability to meet any such financial covenants nor a reduction in its borrowing base.

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 December 31, 2004, the Company had acquired or farmed in leases totaling approximately 45,000 gross acres, with an average working interest of approximately 85%, and is attempting to acquire additional acreage in the area. As of December 31, 2004, the Company had successfully drilled 14 operated wells targeting the Cotton Valley formation. Subsequent to December 31, 2004, the Company had successfully drilled and/or completed an additional four Cotton Valley wells. As of March 24, 2005, the Company was in the process of drilling another four Cotton Valley wells. For the wells completed to date, the Company estimates that the average initial gross production rate per well is approximately 1,350 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 successfully completed wells is approximately 8,500 Mcfe of gas per day, or 5,300 Mcfe per day net to the Company.

In East Texas, the Company began leasing acreage in the first quarter of 2004 and commenced a drilling program in April 2004. As of December 31, 2004, the Company had drilled a total of 11 successful wells on its operated acreage targeting the Cotton Valley formation. The Company has a 100% working interest in seven of the completed wells and an 85% working interest in four of the completed wells. The Company currently has engaged three drilling rigs which are drilling new wells on its operated acreage in East Texas.

In Northwest Louisiana, the Company commenced a drilling program targeting the Cotton Valley formation in the first quarter of 2004 and had successfully completed three Cotton Valley wells as of December 31, 2004. 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—In the second quarter of 2004, the Company successfully completed two exploratory wells in the Burrwood/West Delta 83 fields in Plaquemines Parish, Louisiana. The first well was the Company’s initial Dempsey Prospect well, in which it has a 70% working interest and the second well was the Company’s initial Norton Prospect well, in which it has a 65% working interest. Additionally, in the third quarter of 2004, the Company drilled a successful sidetrack well to one of its other existing producing wells in the field, in which it has a 65% working interest. As of December 31, 2004, the Company’s share of production from these three wells was approximately 1,630 Mcf of gas per day and 245 barrels of oil per day.

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 and evaluation of the seismic data was completed in late 2004 and the Company will soon determine the extent of its drilling and remaining workover plans in the field.

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 expected to be completed in April 2005.

Senior Credit Facility

On November 9, 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. Borrowings outstanding under the senior credit facility were $27,000,000 as of December 31, 2004. 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. The credit facility precludes the payment of dividends on the Company’s common stock and requires the Company to maintain a working capital 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 December 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 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 (see “Liquidity and Capital Resources”). 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

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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. As of March 24, 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 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”).

Sale of Oil and Gas Properties to Related Party

On March 12, 2002, the Company sold a 30% working interest in the existing production and shallow rights in its Burrwood/West Delta 83 fields, and a 15% working interest in the deep rights below 10,600 feet, in such fields for $12 million to Malloy Energy Company, LLC (“MEC”) led by Patrick E. Malloy, III and participated in by Sheldon Appel, each of whom were members of the Company’s Board of Directors at that time, as well as Josiah Austin, who subsequently became a member of the Company’s Board of Directors. Mr. Malloy is currently Chairman of the Company’s Board of Directors and Mr. Appel retired from the Board of Directors in February 2004. The sale price was determined by discounting the present value of the acquired interest in the fields’ proved, probable and possible reserves using prevailing oil and gas prices. The Company retained an approximate 65% working interest in the existing production and shallow rights, and a 32.5% working interest in the deep rights after the close of the transaction. In conjunction with the sale, MEC provided a $7.7 million line of credit which reduced to $5.0 million on January 1, 2003 and expired, according to its terms, on December 31, 2004. MEC was also granted an option to participate on a proportionate cost basis in up to 30% of the Company’s working interests in any acquisitions the Company made in Louisiana on or before December 31, 2004. Pursuant to this option, MEC acquired a 30% working interest in three non-producing field acquisitions made by the Company in Louisiana during 2003 and 2004. Such interests acquired were in the Bethany-Longstreet and Plumb Bob fields in 2003 and in the St. Gabriel field in 2004. In accordance with industry standard joint operating agreements, the Company bills MEC for its share of the capital and operating costs of the three fields on a monthly basis. The Company recorded a non-recurring gain of approximately $2.4 million in the first quarter of 2002 as a result of the MEC sale. The proceeds were used to reduce outstanding debt under its senior credit facility.

Contractual Obligations

At December 31, 2004, the Company had the following contractual obligations outstanding under its long term debt, production payment and operating lease agreements (as of December 31, 2004, the Company had no material purchase obligations for goods or services that were not incurred in the ordinary course of business):

Critical Accounting Policies and Estimates

Critical accounting policies are defined as those that are reflective of significant judgments and uncertainties and potentially result in materially different results under different assumptions and conditions. The Company has prepared its consolidated financial statements in conformity with accounting principles generally accepted in the United States, which require management to make estimates and assumptions that affect the reported amounts in these financial statements and accompanying notes. Actual results could differ from those estimates under

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different assumptions or conditions. Application of certain of the Company’s accounting policies requires a significant amount of estimates. These accounting policies are described below.

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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. As of January 1, 2003, the adoption of SFAS No. 143 resulted in the Company recording a cumulative effect of an accounting change in the amount of $205,000. The estimation of the liability involves the projection of future costs to plug and abandon individual wells. These estimates are based on current costs inflated to the end of the well’s economic life and discounted back to the well’s origination date. The liability will be accreted at the estimated discount rate to the expected cash required to settle the liability. The estimate requires management’s judgment with respect to the future plugging and abandonment costs, the life of the well, and the inflation and discount factors used. Changes in these estimates can significantly impact the amount of the 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 December 31, 2003, 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 is effective for interim or annual reporting periods that begin after June 15, 2005, and requires the expensing of new, modified or repurchased stock-based compensation awards issued after that date. Previously issued stock-based compensation awards, which are unvested as of June 15, 2005, 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, beginning in the third quarter of 2005.

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Off-Balance Sheet Arrangements

The Company does not currently utilize any off-balance sheet arrangements to enhance its liquidity and capital resource positions, or for any other purpose.

Item 7A.    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 December, 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 December 31, 2004, 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 30% to 70% 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 December 31, 2004 resulted in a liability of $1,834,000. Based on oil and gas pricing in effect at December 31, 2004, a hypothetical 10% increase in oil and gas prices would have increased the liability to $5,519,000 while a hypothetical 10% decrease in oil and gas prices would have decreased the liability to an asset of $1,842,000. Subsequent to December 31, 2004, the Company entered into the following crude oil and natural gas hedging contracts with BNP Paribas:

Gas

2,000 MMBtu per day “swap” at $6.655 per MMBtu for April 2005 through March 2006

4,000 MMBtu per day “swap” at $7.00 per MMBtu for April 2005 through March 2006

8,000 MMBtu per day “swap” at $7.1825 per MMBtu for January 2006 through March 2006

4,000 MMBtu per day “swap” at $6.665 per MMBtu for April 2005 through December 2006

Oil

300 barrels per day “swap” at $45.80 per barrel for January 2006 through March 2006

400 barrels per day “swap” at $48.71 per barrel for April 2006 through December 2006

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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 crude 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 crude 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.

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 (two of the contracts have 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 had an effective date of February 26, 2004, expired on its maturity date of November 8, 2004, and was 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, is for $23,000,000 with a LIBOR swap rate of 4.08%. The fair value of the interest rate swap contracts in place at December 31, 2004 resulted in a liability of $162,000. Based on interest rates at December 31, 2004, a hypothetical 10% increase or decrease in interest rates would not have a material effect on the liability.

Disclosure Regarding Forward-Looking Statement

This Annual Report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included in this Annual Report on Form 10-K regarding reserve estimates, planned capital expenditures, future oil and gas production and prices, future drilling activity, the Company’s financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. 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. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary from one another. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revisions of such estimates and such revisions could change the schedule of any further production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Additional important factors that could cause actual results to differ materially from the Company’s expectations include changes in oil and gas prices, changes in regulatory or environmental policies, production difficulties, transportation difficulties and future drilling results. All subsequent written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by such factors.

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Item 8.    Financial Statements and Supplementary Data.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Goodrich Petroleum Corporation:

We have audited the accompanying consolidated balance sheets of Goodrich Petroleum Corporation and Subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations, cash flows and stockholders’ equity and other comprehensive income for each of the years in the three-year period ended December 31, 2004. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Goodrich Petroleum Corporation and Subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles.

As discussed in Note B to the consolidated financial statements, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations.

KPMG LLP

Shreveport, Louisiana

March 24, 2005

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS