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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

For Fiscal Year Ended December 31, 2003

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 April 9, 2004, there were 18,506,354 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 April 9, 2004, was approximately $45,337,000 based on a closing price of $6.75 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, 2003, the aggregate market value of Goodrich Petroleum Corporation common stock held by non-affiliates was $25,490,100.

Documents Incorporated By Reference

Portions of the registrant’s annual proxy statement, to be filed within 120 days after December 31, 2003, are incorporated by reference into Part III of this Form 10-K.

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GOODRICH PETROLEUM CORPORATION

FORM 10-K

December 31, 2003

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 transition zone of south Louisiana and in East Texas, north Louisiana and the Gulf Coast of Texas. The Company owns working interests in 85 active oil and gas wells located in 22 fields in four states. At December 31, 2003, Goodrich had estimated proved reserves of approximately 7.8 million barrels of oil and condensate and 30.9 billion cubic feet (“Bcf”) of natural gas, or an aggregate of 77.7 Bcf equivalent (“Bcfe”) with a pre-tax present value of future net revenues, discounted at 10%, of $214.6 million and an after-tax present value of future net revenues of $163.97 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 April 9, 2004, the Company had 37 employees.

Company Background and Business Strategy

Goodrich resulted from a business combination on August 15, 1995 between La/Cal Energy Partners (“La/Cal”) and Patrick Petroleum Company and subsidiaries (“Patrick”).

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:

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Oil and Gas Operations and Properties

The following is a summary description of the Company’s 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.

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 49 million barrels of oil and 144 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 21 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 monetized a portion of the value created in the two fields by selling 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, who was a member 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

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than thirty (30) defined productive sands, which have collectively produced in excess of 264 million barrels of oil and 319 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 26 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, five 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.

Pecan Lake Field.    The Pecan Lake field was discovered in 1944 by the Superior Oil Company. Geologically, the field is comprised of a relatively low relief, four-way closure and multiple stacked pay sands. The Pecan Lake field comprises approximately 870 gross leased acres in Cameron Parish, Louisiana. The field has produced from over 15 Miocene aged sands ranging in depths from 7,500 to 11,800 feet, which have been predominately gas and gas condensate reservoirs. These sand reservoirs are characterized by generally widespread development and strong waterdrive production mechanisms. The field has produced in excess of 354 Bcf of gas and 798,000 barrels of condensate. All of the field production to date has come from normal pressured reservoirs. The Company is the operator of two producing wells with working interests ranging from approximately 43% to 47%.

Isle St. Jean Charles Field.    Isle St. Jean Charles field is located in Terrebonne Parish, Louisiana. The field is a northwest extension of the Bayou Jean LaCroix field located in the southeastern area of the Parish. These fields are trapped on a four-way closure, downthrown on a major east-west trending down to the south fault.

Production is from multiple Miocene-aged sands, which are normally pressured and range in depth from 9,000 feet to 13,000 feet. The field was developed primarily in the 1950’s by Exxon and reservoirs have exhibited both depletion and water drive mechanisms. To date, this field has produced in excess of 57 Bcf of gas and 6.61 million barrels of oil and condensate. Goodrich owns an approximate 34% working interest in its leasehold of approximately 425 acres.

Bethany-Longstreet.    The Bethany-Longstreet field is located in Caddo and DeSoto Parishes in northwestern Louisiana and was discovered by several independent oil and gas companies in the late 1940’s and early 1950’s. The majority of the production in the field has come from the “Crane” zone of the Pettit formation which was developed primarily in the 1950’s and 1960’s. In July 2003, the Company obtained, via farmout, the right to drill and earn all rights, excluding exploration rights to the Crane zone of the Pettit formation, in approximately 18,000 acres in the field. The Company, will retain continuous drilling rights to the entire block so long as it drills at least one well every 120 days. For each productive well drilled under the agreement, the Company will earn an assignment of 160 acres. The Company has begun exploration and development drilling activities in the field and completed three successful wells as of December 31, 2003. The Company anticipates drilling additional wells on the block in 2004 and expects that its working interests in the wells will range between 50% and 70%.

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 Company reached an agreement with a subsequent owner to obtain certain rights in the field. The rights include oil and gas leases covering approximately 450 acres, 3-D seismic permits with oil and gas lease options covering approximately 17,000 acres, seven existing shut-in wellbores, where the Company has identified recompletion

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projects, and the rights to acquire related production facilities and pipelines upon establishment of production. The Company’s plans include a workover and well reactivation program, the shooting of a 32 square mile 3-D seismic survey and post 3-D exploitation and development drilling activities. The Company has begun workover drilling activities in the field and had restored production capability in three wells as of December 31, 2003. The 3-D seismic shoot began during the fourth quarter of 2003 and is expected to be completed in the second quarter of 2004. Based on its expected 70% working interest, the Company has budgeted net capital expenditures in the Plumb Bob field of up to $3.7 million in the full year 2004.

Other.    In July 2003, the Company acquired an 18% working interest in two non-operated exploratory prospects encompassing a total of approximately 1,100 acres adjacent to the Bayou Choupique field in Calcasieu Parish, Louisiana. Exploratory wells were drilled on each of the prospects in the third quarter of 2003 with one such well being successful and the other well being unsuccessful. Oil and gas production from the successful well commenced in November 2003. The Company anticipates that the operator will propose the drilling of an offset well to the successful well in the second quarter of 2004, at which time the Company will decide whether to make an election to participate.

The Company maintains ownership interests in acreage and wells in several additional fields in Louisiana, including the (i) City of Lake Charles field, located in Calcasieu Parish, (ii) Mosquito Bay field, located in Terrebonne Parish, (iii) Ada field, located in Bienville Parish, and (iv) Lake Raccourci field, located in Terrebonne Parish.

Texas

Goodrich presently has production operations in the eastern, western and southern regions of Texas, as more fully described in the three succeeding paragraphs. Additionally as indicated below under “East Texas Drilling Program”, the Company is currently undertaking a major new drilling initiative in several additional counties in the eastern portion of Texas.

Sean Andrew Field.    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. The Company is the operator of two wells in the field and holds an approximate 37.5% working interest.

Marholl Field.    The Marholl field is a Siluro-Devonian (Fussellman) field in Dawson County, Texas, discovered in 1995 through the use of 3-D seismic. The Company operates two wells in the field with an approximate 23% working interest.

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 four 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, which occurs at a depth of approximately 7,300 feet. In the fourth quarter of 2003, the Company commenced a waterflood project in the Mary Blevins field. As a result of the waterflood project, the Company anticipates enhanced production from the Mary Blevins field beginning in the second half of 2004.

East Texas Drilling Program.    In the first quarter of 2004, the Company commenced a new drilling initiative which is focused on the Cotton Valley trend in the East Texas Basin in Rusk, Panola and Smith Counties. As of April 9, 2004, the Company had acquired leases totaling approximately 15,000 gross acres and is attempting to acquire additional acreage in the area. The Company presently owns varying working interests ranging from 40% to 100% in the acquired leases and expects to commence a low risk drilling program which will target objectives primarily in the Cotton Valley formation. The Company has preliminarily budgeted total 2004 capital expenditures of approximately $6.5 million under this new drilling initiative. Depending on early results of the drilling program, the Company may elect to increase its level of lease acquisitions and drilling activities in the East Texas Basin.

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Other.    The Company maintains ownership interests in acreage and wells in several additional fields in Texas including the (i) Ackerly field, located in Dawson and Howard Counties, (ii) Lamesa Farms field, located in Dawson County, and (iii) Midway field, located in San Patricio County.

Australia

In the early 1990’s, the Company acquired non-operating interests in two offshore exploration permits in the Carnarvon Basin of Western Australia. In the first quarter of 2003, the Company participated in the drilling of an unsuccessful exploratory well on one of the permits. The Company subsequently relinquished its interests in both exploration permits and has no further plans with respect to any exploration and development operations in Australia.

Oil and Natural Gas Reserves

The following tables set forth summary information with respect to the Company’s proved reserves as of December 31, 2003 and 2002, as estimated by the Company by compiling reserve information, substantially all of which was prepared by the engineering firm of Coutret and Associates, Inc.

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, 2003, and 2002 used in such estimates averaged $6.42 and $4.35 per Mcf, respectively, of natural gas and $31.75 and $28.80 per Bbl, respectively, of crude oil/condensate.

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Productive Wells

The following table sets forth the number of active well bores in which the Company maintains ownership interests as of December 31, 2003:

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, 2003. Acreage in which the Company’s interest is limited to a royalty or overriding royalty interest is excluded from the table and does not include acreage acquired in the East Texas Basin (see “Texas – East Texas Drilling Program”) acquired subsequent to December 31, 2003.

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, 2003.

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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, Burrwood and West Delta 83 fields acquisitions in late 1999 and early 2000, were strategic acquisitions that fit the aforementioned profile, and account for the majority of the unit costs noted above in the periods presented above.

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 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.

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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.

Risk Factors

The Company’s Success is Dependent on Oil and Gas Prices.    Goodrich’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 its crude oil production are based on global market conditions. The continued threat of war in the Middle East and actions of OPEC and its maintenance of production constraints, as well as other economic, political, and environmental factors will continue to affect world supply. Natural gas prices fluctuate significantly in response to numerous factors including the U.S. economic environment, North American 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.

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Average oil and gas prices increased substantially from 2002 to 2003. The year 2002 began with lower commodity prices as a result of the global economic downturn and decreases in demand. During 2002, crude oil prices increased due to a combination of factors including fears of war in Iraq (and the resulting impact on the Middle East), Venezuelan strikes that reduced oil exports, and continued OPEC production discipline. Natural gas prices also increased throughout 2002 as U.S. productive capacity declined and as demand increased in the fourth quarter due, in part, to below–normal temperatures. Commodity prices ended 2002 at their highest levels for the year and continued at a relatively high level throughout 2003. 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 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 its exposure to price risk from changing commodity prices and has hedged a targeted portion of its anticipated production for 2004.

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

The Company’s Oil and Gas Reserve Information Is Estimated.    The proved oil and gas reserve information included in this document represents estimates. These estimates are based on reports prepared by consulting reserve engineers and were calculated using oil and gas prices as of December 31, 2003. These prices could change. 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 reserves:

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Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. Goodrich’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 Goodrich’s 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.

Oil and Gas Operations Are Subject to Various Economic Risks.    The oil and gas operations of Goodrich 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 Goodrich’s exploration, development and production activities to be unsuccessful. This could result in a total loss of Goodrich’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.

Drilling Oil and Gas Wells Could Involve Blowouts, Environmental Hazards and Other Risks.    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 Goodrich. 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 Goodrich’s properties. Additionally, some of Goodrich’s oil and gas operations are located in areas that are subject to weather disturbances such as hurricanes. Some of these disturbances can be severe enough to cause substantial damage to facilities and possibly interrupt production. In accordance with customary industry practices, Goodrich 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 financial position and results of operations of Goodrich.

Competition Within the Oil and Gas Industry is Intense.    The exploration and production business is highly competitive. Many of Goodrich’s competitors have substantially larger financial resources, staffs and facilities than Goodrich. These competitors include other independent oil and gas producers, as well as major oil companies.

Government Agencies Can Increase Costs and Can Terminate or Suspend Operations.    Goodrich’s business is subject to federal, state and local laws and regulations relating to the exploration for, and the development, production and transportation of, oil and gas, as well as environmental and safety matters. Many of these laws and regulations have become stricter in recent years. These laws and regulations often impose greater liability on a larger number of potentially responsible parties. Under some circumstances, the State of Louisiana

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may require the operations of Goodrich on state leases to be suspended or terminated. These circumstances include Goodrich’s failure to pay royalties and its failure to comply with safety and environmental regulations. This could have a material adverse effect on Goodrich’s financial condition and operations.

Item 3.    Legal Proceedings.

The U.S. Environmental Protection Agency (“EPA”) has identified the Company as a potentially responsible party (“PRP”) for the cost of clean-up of “hazardous substances” at an oil field waste disposal site in Vermilion Parish, Louisiana. The Company estimates that the remaining cost of long-term clean-up of the site will be approximately $3.5 million, with the Company’s percentage of responsibility estimated to be approximately 3.05%. As of December 31, 2003, the Company had paid $321,000 in costs related to this matter and accrued $122,500 for the remaining liability. These costs have not been discounted to their present value. The EPA and the PRPs will continue to evaluate the site and revise estimates for the long-term clean-up of the site. There can be no assurance that the cost of clean-up and the Company’s percentage responsibility will not be higher than currently estimated. In addition, under the federal environmental laws, the liability costs for the clean-up of the site is joint and several among all PRPs. Therefore, the ultimate cost of the clean-up to the Company could be significantly higher than the amount presently estimated or accrued for this liability.

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

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

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 and Related Stockholder Matters.

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

At April 9, 2004, the number of holders of record of the Company’s common stock without determination of the number of individual participants in security position was 1,743 with 18,506,354 shares outstanding. High and low sales prices for the Company’s common stock for each quarter during the calendar years 2003 and 2002 are as follows:

The Company has not paid a cash dividend on its common stock and does not intend to pay such a dividend in the foreseeable future.

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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, 2003, 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 Item 7, “Management’s Discussion And Analysis Of Financial Condition And Results Of Operations.” As indicated in note A of the Company’s financial statements, the Company has restated its previously reported Depletion, Depreciation and Amortization expense and Exploration expense for the years ended December 31, 2001 and 2002. The tax-effected amounts of these adjustments resulted in changes in the Company’s previously reported Net Income (Loss) for both years.

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

General

The Company was created by the combination of Patrick Petroleum Company (“Patrick”) and La/Cal Energy Partners, a partnership in which it had a controlling interest (“La/Cal”), in August 1995. The combination was a reverse merger in which the Company’s current management gained control of the combined company, renamed it Goodrich Petroleum Corporation and assumed Patrick’s New York Stock Exchange listing.

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 year ended December 31, 2003. These trends largely reflect the results of Goodrich’s successful 2003 drilling program as the Company increased its capital expenditures in 2003 to approximately 250% of the 2002 level. Additionally, the Company benefited from a strong commodity pricing environment in 2003.

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Restatement of 2001 and 2002 Financial Statements

In the course of preparing its 2003 year-end financial statements, the Company discovered a systematic error in the calculations of its non-cash depletion, depreciation and amortization expense since 1997. Accordingly, the Company has restated its previously reported depletion, depreciation and amortization expense for the years ended December 31, 2001 and 2002. Additionally, the Company has restated exploration expense due to a charge of $109,675 that was recorded in 2002 that should have been recorded in 2001. The tax-effected amounts of these adjustments resulted in changes in the Company’s previously reported Statement of Operations and Balance Sheet for both years as follows:

The tax-adjusted cumulative effect of the error on non-cash depletion, depreciation and amortization expense in years prior to December 31, 2001 resulted in a reduction of stockholders’ equity as of January 1, 2001 in the amount of $580,854 and in changes in the Company’s previously reported Statement of Operations and Balance Sheet for the two years prior thereto as follows:

Results of Operations

Year ended December 31, 2003 versus year ended December 31, 2002—Total revenues for the year ended December 31, 2003 amounted to $32,698,000 compared to $19,100,000 for the year ended December 31, 2002. Oil and gas sales for the year ended December 31, 2003 were $32,221,000 compared to $18,969,000 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. Additionally, oil and gas revenues in 2003 include sales of natural gas liquids in the amount of $762,000,

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resulting from processing a portion of the Company’s natural gas production beginning in May 2003. The following table presents the production volumes and pricing information for the comparative periods, with the average oil and gas prices including 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 was $6,248,000 for the year ended December 31, 2003 versus $7,757,000 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 were $2,315,000 in the year ended December 31, 2003 compared to $1,664,000 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 was $9,075,000 for the year ended December 31, 2003 versus a restated amount of $7,263,000 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.

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 $2,121,000 in the year ended December 31, 2003 compared to a deferred tax benefit of $507,000 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.

Year ended December 31, 2002 versus year ended December 31, 2001—Total revenues in 2002 amounted to $19,100,000 and were $10,796,000 (36%) lower than total revenues in 2001 due primarily to a 30% decline in production volumes resulting largely from the sale of a 30% interest in the Burrwood/West Delta 83 fields on

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March 12, 2002 and lower natural gas prices, partially offset by slightly higher oil prices. Oil and gas sales were $18,969,000 for the twelve months ended 2002, compared to $29,542,000 for the twelve months ended December 31, 2001, or $10,573,000 lower due to lower oil and gas production volumes, primarily the result of the March 2002 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”). Oil and gas revenues were also reduced during the period due to a majority of the Company’s oil and gas production being shut in temporarily as a result of Hurricane Isidore and Hurricane Lili in September and October 2002. Oil sales were reduced by $274,000 and gas sales were reduced by $739,000 for the year ended December 31, 2002, compared to reductions of $89,000 for oil sales and $972,000 for gas sales in the year ended December 31, 2001 as a result of settlement of the Company’s outstanding oil and gas futures contracts. The Company recorded a gain of $2,941,000 primarily due to the sale of a 30% interest in the Burrwood/West Delta 83 fields for the twelve months ended December 31, 2002, compared to a gain of $27,000 for the twelve months ended December 31, 2001.

The following table reflects the production volumes and pricing information for the periods presented:

Lease operating expense was $7,757,000 for 2002 compared to $6,576,000 for 2001, or $1,181,000 higher, due primarily to significantly increased costs associated with salt water disposal in the Burrwood/West Delta 83 fields, final billings from the prior operator of the Company’s Second Bayou field, higher well insurance costs and transition costs associated with the Company assuming operations of its oil and gas properties from a contract operator in June 2002, partially offset by the March 2002 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”). Work was completed at the end of the second quarter to alleviate higher costs associated with compression and salt water disposal. Production taxes in 2002 were $1,664,000 compared to $1,866,000 or $202,000 lower due to lower oil and gas sales during 2002. Restated depletion, depreciation and amortization expense was $7,263,000 in 2002 versus $7,524,000 in 2001, with the decrease due primarily to lower production volumes in 2002 versus 2001.

The Company incurred $1,019,000 of exploration expense in 2002 compared to $4,284,000 in 2001, or $3,265,000 lower, due primarily to dry hole and seismic costs of $-0- and $130,000 respectively in 2002, compared to $1,604,000 and $994,000 respectively in 2001.

The Company recorded an impairment in the recorded value of certain oil and gas properties in 2002 in the amount of $342,000 due primarily to a sooner than anticipated depletion of reserves in non-core fields. This compares to an impairment of $1,801,000 recorded in 2001.

General and administrative expenses amounted to $4,468,000 for the twelve months ended December 31, 2002 versus $3,135,000 in 2001 or $1,333,000 higher, due primarily to legal costs of $983,000 attributable to litigation against the operator and joint owner of the Company’s Lafitte field and added salaries associated with the Company assuming operations from its contract operator.

Interest expense was $985,000 in the twelve months ended December 31, 2002 compared to $1,291,000 in the twelve months ended December 31, 2001, or $306,000 lower, due primarily to lower average debt outstanding, reflecting debt reduction from proceeds of a property sale, and a lower average effective interest rate for the twelve months ended December 31, 2002.

The Company recorded a deferred tax benefit of $507,000 in 2002 compared to the recording of a deferred tax expense (not requiring current cash payment) of $1,211,000 in 2001 with the decrease entirely attributable to the pre-tax loss in 2002.

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Preferred stock dividends were $640,000 in 2002 compared to $3,003,000 in 2001. In 2002, such amount consisted solely of cash dividends paid on the Company’s Series A preferred stock whereas the 2001 amount includes cash dividends paid on the Company’s Series A preferred stock in the amount of $626,000, as well as a non-cash charge related to the conversion of the Company’s Series B preferred stock into common stock in the amount of $2,377,000.

Liquidity and Capital Resources

Net cash provided by operating activities was $17,048,000 in the year ended December 31, 2003, compared to $5,349,000 in the year ended December 31, 2002 and $15,790,000 in the year ended December 31, 2001. 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 decrease in the 2002 period reflects substantially lower oil and gas revenues due to the March 2002 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”). The operating cash flow amounts are net of changes in current assets and current liabilities, which resulted in a $519,000 decrease in working capital in the year ended December 31, 2003, compared to increases of $1,589,000 and $44,000 in the years ended December 31, 2002 and 2001, respectively.

Net cash used in investing activities was $19,500,000 in the year ended December 31, 2003, compared to net cash provided by investing activities of $4,743,000 in the year ended December 31, 2002 and net cash used in investing activities of $31,846,000 in the year ended December 31, 2001. 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”). In the year ended December 31, 2001, capital expenditures totaled $32,253,000 as Goodrich participated in the drilling of seven new wells and completed minor property sales totaling $407,000.

Net cash provided by financing activities was $589,000 in the year ended December 31, 2003, compared to net cash used in financing activities of $6,989,000 in the year ended December 31, 2002 and net cash provided by financing activities of $12,772,000 in the year ended December 31, 2001. In the year ended December 31, 2003, net borrowings under the Company’s senior credit facility provided cash of $1,500,000 toward funding of capital expenditures, 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”). In the year ended December 31, 2001, the Company completed a public stock offering resulting in net cash proceeds of $13,069,000 while net borrowings under the Company’s senior credit facility provided additional cash of $1,482,000 and preferred stock dividends, production payments and restricted cash funding required cash of $1,971,000.

For the year 2004, the Company has preliminarily budgeted total capital expenditures of approximately $25 million, which includes the Company’s share of the subsequent exploration and development costs related to two recent property acquisitions in Louisiana, as further described below (see “Recent Property Acquisitions”). Subject to current economics and financial resources, the Company expects to finance its capital expenditures out of operating cash flow and available bank credit, as further described below (see “Senior Credit Facility”). The Company’s senior credit facility includes certain financial covenants with which the Company was in compliance as of December 31, 2003. 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.

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Recent Property Acquisitions

In the third quarter of 2003, the Company announced its acquisition of interests in two non-producing properties in Louisiana that required minimal initial expenditures. Pursuant to the first acquisition, the Company obtained, via farmout, the right to drill and earn all rights, excluding exploration rights to the Crane zone of the Pettit formation, in approximately 18,000 acres in the Bethany-Longstreet field in northwest Louisiana. The Company will retain continuous drilling rights to the entire block so long as it drills at least one well every 120 days. For each productive well drilled under the agreement, the Company will earn an assignment to 160 acres. The Company has begun exploration and development drilling activities in the field and had completed three successful wells as of December 31, 2003. The Company anticipates drilling additional wells on the block in 2004 and expects that its working interests in the wells will range between 50% and 70%.

Under the second acquisition, the Company obtained certain rights in the Plumb Bob field located in St. Martin Parish in southern Louisiana. The rights include oil and gas leases covering approximately 450 acres, 3-D seismic permits with oil and gas lease options covering approximately 17,000 acres, seven existing shut-in wellbores, where the Company has identified recompletion projects, and the rights to acquire related production facilities and pipelines upon establishment of production. The Company’s plans include a workover and well reactivation program, the shooting of a 32 square mile 3-D seismic survey and post 3-D exploitation and development drilling activities. The Company has begun workover drilling activities in the field and had restored production capability in three wells as of December 31, 2003. The 3-D seismic shoot began during the fourth quarter of 2003 and is expected to be completed in the second quarter of 2004. Based on its expected 70% working interest, the Company has budgeted net capital expenditures in the Plumb Bob field of up to $3.7 million in the full year 2004.

Sale of Oil and Gas Properties to Related Party

On March 12, 2002, the Company monetized a portion of the value created in its Burrwood/West Delta 83 fields by selling 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, who was a member 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. The credit line is subordinate to the Company’s senior credit facility and can be used for acquisitions, drilling, development and general corporate purposes until December 31, 2004. MEC retains the option to convert the amount outstanding under the credit line, and/or provide cash on any unused credit, into 30% of the Company’s working interests in any acquisition(s) the Company makes in Louisiana prior to January 1, 2005. MEC has elected to participate for 30% of the Company’s working interest in the two Louisiana property acquisitions announced by the Company in the third quarter of 2003 (see “Recent Property Acquisitions”). Since the Company has made no borrowings under the MEC credit line to date, MEC funded its share of the acquisition costs and will fund its share of the subsequent capital costs related to these acquisitions on a direct basis, rather than by converting borrowings under the credit line.

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.

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

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redetermined to be $28,000,000 and BNP Paribas and the Company agreed to extend the term of the senior credit facility for an additional two years, subject to periodic redeterminations of the borrowing base. The Company’s borrowings outstanding under the credit facility amounted to $20,000,000 as of December 31, 2003 and $19,000,000 as of April 9, 2004.

Interest on borrowings under the senior credit facility accrue 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. As extended, the senior credit facility will mature on December 29, 2006. 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 requires the Company to monitor tangible net worth and maintain a current ratio and an interest coverage ratio above prescribed levels. As of December 31, 2003, the Company was in compliance with all such requirements. Substantially all the Company’s assets are pledged to secure the senior credit facility.

In February 2003, the Company entered into three separate interest rate swaps with BNP Paribas covering a three year period, 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”).

Contractual Obligations

At December 31, 2003, the Company had the following contractual obligations outstanding under its long term debt, production payment and operating lease agreements (as of December 31, 2003, 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 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.

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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 July 2003, the FASB undertook to review whether mineral interests in properties (mineral leases) held by oil and gas companies should be recorded and disclosed as intangible assets under the guidance of SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets. The FASB is considering whether an oil and gas company’s investment in mineral leases should be classified as intangible assets. SFAS No. 141 and SFAS No. 142 established new accounting guidelines for both finite lived intangible assets and indefinite lived intangible assets. Under SFAS No. 141 and SFAS No. 142, intangible assets should be separately reported on the Balance Sheet, with accompanying disclosures in the notes to the financial statements. SFAS No. 142 does not change the accounting prescribed in SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, and is silent about whether its disclosure provisions apply to oil and gas companies. The Company does not believe that SFAS No. 141 and SFAS No. 142 change the classification and disclosure of oil and gas mineral leases and it continues to classify these assets as part of Property, Plant and Equipment in the Consolidated Balance Sheet and it does not provide the additional disclosures for these assets. The EITF has added the discussion of oil and gas mineral leases to its agenda, which may result in a change in the recording and disclosure of oil and gas mineral leases. Should the EITF determine that oil and gas mineral leases are intangible assets, the Company would reclassify $6,409,000 and $6,563,000 as intangible undeveloped mineral interests at December 31, 2003 and 2002, respectively. In addition, a reclassification of $5,879,000 and $4,925,000 would be made as intangible developed mineral interests at December 31, 2003 and 2002, respectively. Both intangible assets would be presented net of accumulated amortization. Historically, undeveloped mineral leases have been amortized over the life of the lease period, while developed mineral leases have been amortized using the units of production method over the expected life of proved reserves. The amounts included herein are based on the Company’s understanding of the issue on the EITF’s agenda. If all mineral leases associated with oil and gas properties are deemed to be intangible assets in accordance with SFAS No. 141 and SFAS No. 142 by the EITF:

In March 2004, the FASB issued an exposure draft on accounting for stock-based compensation. The exposure draft reflects the FASB’s tentative conclusion that the fair value of stock options should be expensed in

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companies’ financial statements for years ending after December 31, 2004. The exposure draft also includes the FASB’s tentative decisions regarding how equity-based awards are likely to be valued, expensed, and classified. The Company will continue to monitor developments with respect to the exposure draft to determine the potential impact on its financial statements.

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, 2003, 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, 2003, the Company’s open forward position on its outstanding commodity hedging contracts, all of which were with BNP Paribas, was as follows:

Crude Oil

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

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

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

Natural Gas

3,000 MMBtu per day “swap” at $5.00 for January 2004 through December 2004

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 2004. The fair value of the crude oil and natural gas hedging contracts in place at December 31, 2003 resulted in a liability of $1,257,000. Hedge ineffectiveness results from differences in the NYMEX contract terms and the physical location, grade and quality of the Company’s oil and gas production. Based on oil and gas pricing in effect at December 31, 2003, a hypothetical 10% increase in oil and gas prices would have increased the liability to $2,800,000 while a hypothetical 10% decrease in oil and gas prices would have resulted in a $320,000 asset. Subsequent to December 31, 2003, the Company entered into the following crude oil and natural gas hedging contracts with BNP Paribas:

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

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

3,000 MMBtu per day “swap” at $6.20 for November 2004 through December 2004

6,000 MMBtu per day “swap” at $6.27 for January 2005 through March 2005

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.

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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. The first interest rate swap, which has an effective date of February 26, 2003 and a maturity date of February 26, 2004 is for $18,000,000 with a LIBOR swap rate of 1.53%. The second interest rate swap, which has an effective date of February 26, 2004 and a maturity date of November 8, 2004, is for $18,000,000 with a LIBOR swap rate of 2.25%. The third interest rate swap, which has an effective date of November 8, 2004 and a maturity date of February 26, 2006, is for $18,000,000 with a LIBOR swap rate of 3.46%. The fair value of the interest rate swap contracts in place at December 31, 2003, resulted in a liability of $278,000. Based on interest rates at December 31, 2003, a hypothetical 10% increase or decrease in interest rates would not have a material effect on the liability. Subsequent to December 31, 2003, the Company entered into a fourth interest rate swap contract with BNP Paribas, which has an effective date of February 26, 2006 and a maturity date of February 26, 2007, for $23,000,000 with a LIBOR swap rate of 4.08%.

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

INDEPENDENT AUDITORS’ REPORT

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, 2003 and 2002, 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, 2003. 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 auditing standards generally accepted in the United States of America. 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, 2003 and 2002, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

As described in Note A, the Company has restated its 2002 and 2001 consolidated financial statements.

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 and, effective January 1, 2001, the Company changed its method of accounting for derivative instruments and hedging activities.

KPMG LLP

Shreveport, Louisiana

April 9, 2004

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

See notes to consolidated financial statements

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS