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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

For Fiscal Year Ended December 31, 2002

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

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 15, 2003, there were 18,039,482 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 15, 2003, was approximately $21,235,000 based on a closing price of $3.66 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 28, 2002, the aggregate market value of Goodrich Petroleum Corporation common stock held by non-affiliates was $21,059,000.

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 north Louisiana, the Gulf Coast of Texas and East Texas. The Company owns working interests in 99 active oil and gas wells located in 20 fields in four states. The Company also owns overriding royalty interest in five oil and gas wells. At December 31, 2002, Goodrich had estimated proved reserves of approximately 7.4 million barrels of oil and condensate and 29.1 billion cubic feet (“Bcf”) of natural gas, or an aggregate of 73.7 Bcf equivalent (“Bcfe”) with a pre-tax present value of future net revenues, discounted at 10%, of $151.4 million and an after-tax Standardized Measure value of $124.3 million.

The Company’s principal executive offices are located at 808 Travis Street, Suite 1320, Houston, Texas 77002. The Company also has offices in Shreveport, Louisiana. At March 15, 2003, the Company had 37 employees.

Company Background

Goodrich resulted from a business combination on August 15, 1995 between La/Cal Energy Partners (“La/Cal”) and Patrick Petroleum Company and subsidiaries (“Patrick”). La/Cal was a privately held independent oil and gas partnership formed in July 1993 engaged in the development, production and acquisition of oil and natural gas properties, primarily in southern Louisiana. Patrick was a NYSE listed independent oil and gas company engaged in the exploration, production, development and acquisition of oil and natural gas properties in the continental United States. Patrick’s oil and gas operations and properties were primarily located in West Texas and Michigan at the time of the combination, with additional operations and properties in certain western states.

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 Fields.    The Burrwood and West Delta 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

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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 fields through an acquisition that closed on March 2, 2000 with an effective date of January 1, 2000. On March 12, 2002, the Company, in an effort to monetize a portion of the value created in the two fields and enhance its liquidity position, completed the sale of a thirty percent (30%) working interest in the existing production and shallow rights, and a fifteen percent (15%) working interest in the deep rights below 10,600 feet, in the fields for $12 million to Malloy Energy Company, LLC led by Patrick E. Malloy, III and participated in by Sheldon Appel, both members of the Company’s Board of Directors (Mr. Malloy is now Chairman of the Company’s Board of Directors), as well as Josiah Austin, who subsequently became a member of the Company’s Board of Directors. 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 retains an approximate sixty-five percent (65%) working interest in the existing production and shallow rights, and a thirty-two and one-half percent (32.5%) working interest in the deep rights after the close of the transaction. In conjunction with the sale, the investor group provided a $7.7 million line of credit. The $7.7 million line of credit, which reduced to $5.0 million on January 1, 2003, is subordinate to the Company’s senior credit facility. The line of credit can be used for acquisitions, drilling, development and general corporate purposes until December 31, 2004. The investor group retains the option, through December 31, 2004, to convert the amount outstanding under the credit line, and/or provide cash on any unused credit to a maximum of $7.7 million in the first year, reduced to $5.0 million after December 31, 2002, into working interests in any acquisition(s) the Company may make in Louisiana prior to January 1, 2005. The conversion of the credit facility will be on a pro-rata basis with the Company and may not exceed a maximum of $7.7 million, reduced to $5.0 million after December 31, 2002, or thirty percent (30%) of any potential acquisition(s). To date, no borrowings have been made under the credit facility.

The Company recorded a non-recurring gain of approximately $2.4 million in the first quarter of 2002 as a result of the sale. The proceeds were used to reduce outstanding debt under its senior credit facility.

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 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 24 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, four of which are dually completed, and has an average working interest of approximately 29% 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, approximately 42 miles southeast of Lake Charles, Louisiana. The field has produced from over 15 Miocene 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 four producing wells with working interests ranging from approximately 43% to 47%.

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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 acquired its approximate 34% working interest in its leasehold of approximately 425 acres through both acreage acquisitions and a farmout. The Company operates the one dually-completed well in the field.

Lake Raccourci Field.    The Lake Raccourci field located in Terrebonne Parish, Louisiana was discovered by a predecessor to Exxon in 1949, with the field extended to the south by a predecessor to Amoco in 1958. Geologically, the field is a large four-way dipping closure, which is cross-cut by numerous northeast-southwest striking down to the south faults. The field has produced from a minimum of 18 different Miocene age sandstones, ranging in depth from 9,000 to 16,500 feet. These normally and abnormally pressured reservoirs exhibit depletion, water and combination drive mechanisms, and have produced in excess of 834 billion cubic feet of gas and 20 million barrels of oil and condensate.

Goodrich acquired its average 27% working interest in the field through a farmout from a predecessor to Apache in July 1996 and a separate farmout from Exxon. In December 2001, the Company purchased Exxon’s interest in one of the wells in the field. The Company controls approximately 1,079 acres in the field, which currently has seven producing wells.

Other.    The Company maintains ownership interests in acreage and wells in several additional fields in Louisiana, including the (i) Opelousas field, located in St. Landry Parish, (ii) Sibley field, located in Webster Parish, (iii) City of Lake Charles field, located in Calcasieu Parish, (iv) South Drew field, located in Ouachita Parish, (v) Mosquito Bay field, located in Terrebonne Parish, (vi) Kings Ridge field, located in Lafourche Parish, and (vii) Ada field, located in Bienville Parish

Texas

Goodrich explores and has production in the western, eastern and southern regions 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.

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, (iii) Midway field, located in San Patricio County, and (iv) Mott Slough field, located in Wharton County.

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Australia

Goodrich has interests in two offshore exploration permits in the Carnarvon Basin of Western Australia.

The Carnarvon Basin is two-thirds the size of the Gulf of Mexico and has produced in excess of 4.3 TCF and 550 million barrels of oil from less than 1,000 wells. The Carnarvon Basin retains significant exploration potential. Additional strengths of the basin include large inexpensive acreage blocks, vast available geological and geophysical data sets, existing and expanding petroleum infrastructure and increasing domestic demands for natural gas.

EP-395.    Goodrich Petroleum has a 6.9% non-operated working interest in an approximate 240 square kilometer Exploration Permit. Since 1995 the partners have reprocessed the original 2-D seismic data sets, shot an approximate 38 square km 3-D seismic survey, and shot an approximate additional 93 km of high quality 2-D seismic.

EP-397.    This Permit covers 160 square kilometers in which the Company has a 33% non-operated working interest. The 130 km of available seismic has been reprocessed and interpreted with several prospect leads. The Company is scheduled to participate in a well on EP-397, its Banjo Prospect, during the first half of 2003. The Company has already paid its estimated share of the dry hole costs in escrow for the well in the amount of approximately $650,000.

Oil and Natural Gas Reserves

The following tables set forth summary information with respect to the Company’s proved reserves as of December 31, 2002 and 2001, 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 all 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 estimated oil and natural gas reserves attributable to the Company’s properties.

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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, 2002, and 2001 used in such estimates averaged $4.35 and $2.51 per Mcf, respectively, of natural gas and $28.80 and $17.91 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, 2002:

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, seven 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, 2002. 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,

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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

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

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.)

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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, 2002.

The Company’s acquisition strategy 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 fields acquisitions in late 1999 and early 2000, were strategic acquisitions that fit the aforementioned profile, and account for the increased 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:

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Effective January 1, 2003, the Company contracted with Louis Dreyfus Corporation as its major gas purchaser in lieu of Reliant Energy.

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.

Environmental Regulation

Various federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect the Company’s operations and costs as a result of their effect on oil and gas development, exploration and production operations. It is not anticipated that the Company will be required in the near future to expend amounts that are material in relation to its total capital expenditures program by reason of environmental laws and regulations but, inasmuch as such laws and regulations are frequently changed by both federal and state agencies, the Company is unable to predict the ultimate cost of continued compliance. Additionally, see existing EPA 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.

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

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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, the continuing economic crisis in Venezuela (a major oil exporter), 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.

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 the year at their highest levels and have remained strong in 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 the Company has hedged a substantial portion of its anticipated production for 2003.

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, 2002. 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:

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

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.

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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 foreign, 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 may require the operations of Goodrich on state leases to be suspended or terminated. These circumstances include Goodrich’s failure to pay royalties, Goodrich’s 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, 2002, 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 has 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. The Court has not determined whether TEPI has already issued the request that would require the Company to post 49% of the bond liability to TEPI. However, in a statement to the Court, TEPI stated that whatever may be the obligation between the operator and Goodrich regarding the requirement, if any, for Goodrich to post a bond in favor of the operator covering Goodrich’s P&A obligations, TEPI does not claim that it is entitled to any bond unless and until the operator’s total shareholder value (as defined in the Purchase and Sale Agreement between the operator and TEPI) falls below $80 million. The damages portion of the suit is ongoing and it is too early to predict a likely outcome, however, this action is not expected to have a significantly adverse impact on the operations or financial position of the Company.

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 March 15, 2003 the number of holders of record of the Company’s common stock without determination of the number of individual participants in security position was 1,648 with 18,039,482 shares outstanding. High and low sales prices for the Company’s common stock for each quarter during the calendar years 2002 and 2001 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, 2002, 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.”

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.

Results of Operations

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

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production volumes resulting largely from the sale of thirty percent (30%) of Burrwood and West Delta fields on 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 sale of a thirty percent (30%) interest in the Burrwood and West Delta fields. 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 thirty percent (30%) interest in the Burrwood and West Delta 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 and West Delta 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 on June 1, 2002, partially offset by the sale of a thirty percent (30%) working interest in the Burrwood and West Delta fields on March 12, 2002. 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. Depletion, depreciation and amortization was $5,452,000 in 2002 versus $6,845,000 in 2001, or $1,393,000 lower, due primarily to lower production volumes in 2002 versus 2001.

The Company incurred $1,129,000 of exploration expense in 2002 compared to $4,174,000 in 2001, or $3,045,000 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 2002 amount includes $223,000 of non cash expenses associated with the amortization of deferred debt financing costs and amortization of the discount associated with the production payment liability recorded in connection with the Lafitte field acquisition. These non-cash expenses totaled $242,000 in 2001.

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The Company recorded deferred tax expense (not requiring current cash payment) of $89,000 in 2002 compared to the recording of a deferred tax expense of $1,487,000 in 2001 based primarily on the utilization of net operating loss carryforwards.

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.

Year ended December 31, 2001 versus year ended December 31, 2000 —Total revenues in 2001 amounted to $29,895,000 and were $1,406,000 (5%) higher than total revenues in 2000 due primarily to higher oil and gas sales. Oil and gas sales were $29,542,000 for the twelve months ended 2001, compared to $28,014,000, or $1,528,000 higher due to higher oil and gas production volumes partially offset by lower oil prices. Oil sales were reduced by $89,000 and gas sales were reduced by $972,000 for the year ended December 31, 2001 compared to reductions of $2,461,000 for oil sales and $441,000 for gas sales in the year ended December 31, 2000 as a result of settlement of the Company’s outstanding futures contracts. The Company recorded a gain on the sale of certain non-core oil and gas properties of $27,000 for the twelve months ended December 31, 2001 compared to a gain of $307,000 for the twelve months ended December 31, 2000.

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

Lease operating expense was $6,576,000 for 2001 compared to $4,695,000 for 2000, or $1,881,000 higher, due primarily to a full twelve months of costs at Burrwood and West Delta fields in the 2001 period, compared to ten months in the prior period and an increased number of net properties. Production taxes in 2001 were $1,866,000 compared to $2,219,000 or $353,000 lower due to severance tax exemptions received on certain production in the Burrwood and West Delta fields. Depletion, depreciation and amortization was $6,845,000 in 2001 versus $5,954,000 in 2000, or $891,000 higher, due to increased oil and gas production.

The Company incurred $4,174,000 of exploration expense in 2001 compared to $2,813,000 in 2000, or $1,361,000 higher, due primarily to dry hole and seismic costs of $1,604,000 and $994,000 respectively in 2001, compared to $796,000 and $475,000 respectively in 2000.

The Company recorded an impairment in the recorded value of certain oil and gas properties in 2001 in the amount of $1,801,000 due primarily to a sooner than anticipated depletion of reserves in two non-core fields. This compares to an impairment of $1,835,000 recorded in 2000.

General and administrative expenses amounted to $3,135,000 for 2001 versus $2,518,000 in 2000 with the increase due mostly to higher legal expenses.

Interest expense was $1,291,000 in the twelve months ended December 31, 2001 compared to $4,390,000 in the twelve months ended December 31, 2000, or $3,099,000 lower, due primarily to lower average debt outstanding and a lower average effective interest rate for the twelve months ended December 31, 2001. The 2001 amount includes $242,000 of non cash expenses associated with the amortization of deferred debt financing costs and amortization of the discount associated with the production payment liability recorded in connection with the Lafitte field acquisition. The 2000 amount includes $919,000 of non cash expenses associated with the amortization of financing costs and debt discount in connection with the September 1999 private placement and amortization of the discount associated with the production payment liability recorded in connection with the Lafitte field acquisition.

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The Company recorded deferred tax expense (not requiring cash payment) of $1,487,000 in 2001 compared to the recording of a deferred tax benefit of $1,655,000 in 2000.

During 2001 the Company paid dividends of $626,000 on its Series A preferred stock. Also in 2001, the Company exchanged each share of its Series B preferred stock for 1.8 shares of its common stock and recorded a conversion premium on the income statement as dividends, of $2,377,000 to reflect the excess of the 1.8 conversion factor over the terms of the original preferred stock issuance. For the period ended December 31, 2000, the Company paid an aggregate of approximately $1.8 million of dividend arrearages and $580,000 of regular quarterly (third and fourth quarter 2000) dividends on its outstanding series of preferred stock. At December 31, 2001 and 2000, the Company was current as to dividends on its preferred stock. The Company also accrued non-cash dividends on its Goodrich—Louisiana Series A Preferred units, prior to conversion, of $38,000 that is reflected as preferred dividends of subsidiary in the statement of operations for the 2000 period.

Liquidity and Capital Resources

Net cash provided by operating activities was $5,349,000 or 66% lower due primarily to lower production volumes, the majority of which was due to the sale of thirty percent (30%) of the Burrwood and West Delta fields in 2002, compared to $15,790,000 in 2001 and $12,641,000 in 2000. The accompanying consolidated statements of cash flows identify major differences between net income (loss) and net cash provided by operating activities for each of the years presented.

Net cash provided by investing activities amounted to $4,743,000 consisting of $8,079,000 of capital expenditures and $12,823,000 in proceeds from the sale of oil and gas properties in 2002 compared to net cash used in investing activities of $31,846,000 in 2001 and $15,881,000 in 2000. In 2002 the Company participated in the drilling of only two wells, whereas in 2001, a total of seven wells were drilled. Net cash used in investing activities for 2001 consists of capital expenditures of $32,253,000 and proceeds from the sale of oil and gas properties and equipment of $407,000. Net cash used in investing activities for the twelve months ended December 31, 2000, reflects capital expenditures totaling $15,142,000, cash paid in connection with the acquisition of oil and gas properties of $1,199,000 and proceeds from the sale of oil and gas properties of $460,000. For 2003, the Company anticipates making capital expenditures totaling approximately $20 million, which will be primarily directed toward the drilling of up to fifteen gross wells. The Company expects to finance its capital expenditures out of operating cash flow and available bank credit, as further described below.

Net cash used in financing activities was $6,989,000 in 2002 compared to $12,772,000 provided in 2001 and $842,000 provided in 2000. The 2002 amounts consist of pay downs by the Company under its line of credit of $13,500,000. The 2002 amounts also include proceeds from bank borrowings of $7,500,000, preferred stock dividends of $640,000 and the exercise of employee stock options of $28,000. The 2002 amount also includes production payments of $378,000. The 2001 amount consists of proceeds from the issuance of common stock of $15,000,000 and pay downs by the Company under its line of credit of $13,690,000. The 2001 amount also includes proceeds from bank borrowings of $15,225,000, the payment of debt financing and public offering costs of $1,984,000, changes in restricted cash of $799,000, and production payments of $545,000. In addition, the 2001 amount includes preferred stock dividends of $626,000 and proceeds from the exercise of stock warrants and employee stock options of $180,000 and $12,000, respectively. The 2000 amount includes proceeds from the issuance of common stock of $9,150,000 and paydowns by the Company under its line of credit of $4,125,000. The 2000 amount includes preferred stock dividends of $2,308,000, changes in restricted cash of $1,240,000 and proceeds from the exercise of stock purchase warrants and director and employee stock options of $451,000. The 2000 amount also includes production payments of $653,000 and payment of debt and equity financing costs of $432,000.

Credit Facility

On November 9, 2001 the Company established a $50,000,000 credit facility with BNP Paribas, with an initial borrowing base of $25,000,000. The current borrowing base of $23,000,000 will remain effective until the

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next borrowing base redetermination, which is scheduled to be made on or before March 31, 2003. Interest on borrowings will accrue at a rate calculated, at the option of the Company, as either the BNP Paribas base rate plus 0.00% to 0.50%, or LIBOR plus 1.50%—2.50%, 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 will mature on November 8, 2004. The credit facility requires that the Company pay a 0.375% per annum commitment fee, payable in quarterly installments based on the Company’s borrowing base utilization. Prior to maturity, no payments are required so long as the maximum borrowing base amount exceeds the amounts outstanding under the credit facility. The credit facility requires the Company to monitor tangible net worth and maintain certain financial statement ratios at certain levels. Substantially all the Company’s assets are pledged to secure the credit facility. Borrowings under the credit facility amounted to $18,500,000 at December 31, 2002, and were subsequently increased to $20,000,000 as of March 15, 2003.

Burrwood and West Delta Field Performance Bond and Escrow Account

In connection with the March 2, 2000 Burrwood and West Delta fields acquisition, the Company secured a performance bond and established an escrow account to be used for the payment of obligations associated with the plugging and abandonment of the wells, salvage and removal of platforms and related equipment, and the site restoration of the fields. The fully funded escrow account in the amount of $2,039,000 is shown on the Balance Sheet as restricted cash.

Contractual Obligations and Guarantees—The Company is obligated to make future cash payments under its borrowing agreements. Total principal payments due after 2002 under such contractual obligations are shown below.

Accounting Matters

The Company adopted Statement of Financial Accounting Standards (SFAS) No. 141, “Business Combinations” (“SFAS No. 141”) immediately upon release and SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS No. 142”) on January 1, 2002. SFAS No. 141 requires that all business combinations be accounted for under the purchase method of accounting and that certain acquired intangible assets in a business combination be recognized and reported as assets apart from goodwill. SFAS No. 142 requires that amortization of goodwill be replaced with periodic tests of the goodwill’s impairment at least annually in accordance with the provisions of SFAS No. 142 and that intangible assets other than goodwill be amortized over their useful lives. The Company does not have any identified intangible assets nor any goodwill as of December 31, 2002 or December 31, 2001. The adoption of SFAS No. 141 and 142 had no significant impact on the Company’s financial statements.

In July 2001, the FASB issued 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. When the liability is initially recorded, the Company will increase the carrying amount of the related long-lived asset by an amount equal to the original liability. The liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related long-lived asset. Upon adoption of SFAS No. 143 on January 1, 2003, the Company will recognize transition adjustments for existing asset retirement obligations, long-lived assets and accumulated depreciation, all net of related income tax effects, as the cumulative effect of a change in accounting principle. After adoption, any difference between costs incurred upon settlement of an asset retirement obligation and the recorded liability

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will be recognized as a gain or loss in the Company’s earnings. The Company is currently unable to determine the effect of adopting SFAS No. 143 on its financial statements.

In October 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which supercedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of, and the accounting and reporting provisions of APB Opinion No. 30, Reporting the Results of Operations—Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual, and Infrequently Occurring Events and Transactions. The Company adopted the provision of SFAS No. 144 effective January 1, 2002. The adoption of SFAS No. 144 had no impact on the Company.

The Company adopted Emerging Issues Task Force (EITF) Issue 02-3 in the fourth quarter 2002. This consensus requires that the results of energy trading activities be recorded on a net margin basis. The adoption had no impact on the Company’s financial statements.

In November 2002, the FASB issued Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirement for Guarantees, Including Indirect Guarantees of Indebtedness to Others, an Interpretation of FASB Statements No. 5, 57 and 107 and a rescission of FASB Interpretation No. 34. This Interpretation elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees issued. The Interpretation also clarifies that a guarantor is required to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken. The initial recognition and measurement provisions of the Interpretation are applicable to guarantees issued or modified after December 31, 2002 and are not expected to have a material effect on the Company’s financial statements. The disclosure requirements are effective for financial statements of interim and annual periods ending after December 15, 2002.

In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation – Transition and Disclosure, an amendment of FASB Statement No. 123. This Statement amends FASB Statement No. 123, Accounting for Stock-Based Compensation, to provide alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement No. 123 to require prominent disclosures in both annual and interim financial statements. Certain of the disclosure modifications are required for fiscal years ending after December 15, 2002.

Critical accounting policies—In preparing the financial statements of the Company in accordance with accounting principles generally accepted in the United States of America, management must make a number of estimates and assumptions related to the reporting of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. 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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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 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. A portion of the Company’s hedging arrangements are in the form of costless collars, whereby a floor and a ceiling are fixed. It is the Company’s belief that the benefits of the downside protection afforded by these costless collars outweigh the costs incurred by losing potential upside when commodity prices increase. The remainder of the hedges utilized by the Company are in the form of fixed price swaps, where the Company receives a fixed price and pays a floating price. On January 1, 2001, the Company adopted a formal policy with respect to hedging arrangements in accordance with accounting pronouncements. The Company does not expect its hedging policy or future hedging practice to differ materially from its historical practice. The Company has no plans to engage in speculative activity not supported by production.

The Company’s futures contract agreements provide for separate contracts tied to the New York Mercantile Exchange (“NYMEX”) light sweet crude oil and natural gas futures contracts. The contracts contain either specific prices or price ranges known as “collars” that are settled monthly based on the differences between the contract price or price ranges and the average NYMEX prices for each month applied to the related contract

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volumes. To the extent the average NYMEX price exceeds the contract price, the Company pays the difference, and to the extent the contract price exceeds the average NYMEX price, the Company receives the difference.

As of December 31, 2002, the Company’s open forward position on its outstanding natural gas and crude oil hedging contracts, all of which were with BNP Paribas, were as follows:

Natural Gas

3000 MMBtu per day “swap” at $3.50 for January 2003 through February 2003; and

3000 MMBtu per day with a no cost collar of $3.50 and $5.19 per Mmbtu for January through December 2003; and

3000 MMBtu per day “swap” at $4.06 for January 2003 through December 2003.

Crude Oil

300 barrels of oil per day “swap” at $28.80 for January 2003 through February 2003; and

200 barrels of oil per day “swap” at $29.07 for January 2003 through February 2003; and

100 barrels of oil per day “swap” at $28.95 for January 2003 through February 2003; and

300 barrels of oil per day “swap” at $27.45 for March 2003 through May 2003; and

200 barrels of oil per day “swap” at $29.08 for March 2003 through May 2003

The fair value of the natural gas and oil hedging contracts in place at December 31, 2002, resulted, in a liability of $1,108,000.

The Company entered into the following crude oil hedging contracts, all of which were with BNP Paribas, subsequent to December 31, 2002.

300 barrels of oil per day “swap” at $32.58 for March 2003 through May 2003; and

300 barrels of oil per day “swap” at $28.47 for June 2003 through December 2003; and

200 barrels of oil per day “swap” at $29.32 for June 2003 through December 2003; and

200 barrels of oil per day “swap” at $29.97 for June 2003 through December 2003

Price fluctuations and the volatile nature of markets

Despite the measures the Company has taken to attempt to control price risk, it remains subject to price fluctuations for oil and natural gas sold in the spot market. Prices received for natural gas sold in the spot market are volatile due primarily to seasonality of demand and other factors beyond the Company’s control. Oil and natural gas prices can change dramatically primarily as a result of the balance between supply and demand. The Company’s average natural gas price received for the year ending December 31, 2002, was $3.08 per Mcf, down from $3.97 per Mcf in 2001 and down from $3.95 per Mcf in 2000. The Company’s average oil price received for the year ended December 31, 2002, was $25.09, up from an average price received of $24.67 in 2001 and down from an average price received of $25.55 in 2000. There can be no assurance that prices will not decline from current levels. Declines in domestic oil and natural 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. Based on oil and gas pricing in effect at December 31, 2002, a hypothetical 2% increase or decrease in oil and gas pricing would not have had a material effect on the Company’s financial statements.

Debt and debt-related derivatives

Subsequent to December 31, 2002, the Company entered into three separate interest rate swaps with BNP Paribas over 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

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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%.

Subsequent to implementing the interest rate swap, interest on the Company’s senior credit facility with BNP Paribas will accrue at a rate calculated at the LIBOR swap rate plus 1.5%—2.5%, depending on borrowing base utilization, with respect to the notional debt amount of $18,000,000.

For debt over and above the $18,000,000 hedged under the interest rate swaps, the Company is exposed to interest rate risk on its short-term and long-term debt with variable interest rates. Based on the overall interest rate exposure on variable rate debt at December 31, 2002, a hypothetical 2% increase in the interest rates would increase interest expense by approximately $365,000.

Disclosure Regarding Forward-Looking Statements

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, 2002 and 2001, and the related consolidated statements of operations, cash flows and stockholders’ equity and comprehensive income for each of the years in the three-year period ended December 31, 2002. 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, 2002 and 2001, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note B to the consolidated financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative instruments and hedging activities.

KPMG LLP

Shreveport, Louisiana

March 21, 2003

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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

See notes to consolidated financial statements.

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS