UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 (Fee Required)

For Fiscal Year Ended December 31, 2002

Commission file number 1-7940

GOODRICH PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	76-0466193
(State of incorporation)	(I.R.S. Employer Identification No.)
808 Travis St., Suite 1320	77002
Houston, Texas	(Zip Code)
(Address of principal executive offices)

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

Title of each class	Name of each exchange on which registered
Securities registered pursuant to Section 12(b) of the Act:
Common Stock, $0.20 par value	New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Series A Preferred Stock, $1.00 par value	NASDAQ Small Cap

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.

	Net Reserves			Pre-Tax Present Value of Future Net Revenues (in millions)		After-Tax Standardized Measure of Discounted Future Net Revenues (in millions)
Category	Oil (Bbls)	Gas (Mcf)	Bcfe(1)
December 31, 2002
Proved Developed	2,556,670	15,203,255	30.5	$	68.06
Proved Undeveloped	4,884,670	13,866,295	43.2		83.30
Total Proved	7,441,340	29,069,550	73.7	$	151.36	$	124.3
December 31, 2001
Proved Developed	3,399,610	16,692,390	37.1	$	42.39
Proved Undeveloped	5,350,810	17,263,860	49.4		36.50
Total Proved	8,750,420	33,956,250	86.5	$	78.89	$	73.12

(1) Estimated by the Company using a conversion ratio of 1.0 Bbl/6.0 Mcf.

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:

	Oil		Gas		Net
	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)
Louisiana	46.00	23.39	30.00	12.43	76.00	35.82
Michigan	—	—	5.00	0.05	5.00	0.05
New Mexico	—	—	1.00	0.03	1.00	0.03
Texas	14.00	7.01	3.00	0.20	17.00	7.21
Total Productive Wells	60.00	30.40	39.00	12.71	99.00	43.11

(1) Does not include royalty or overriding royalty interests.

(2) Net working interest.

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.

	Gross	Net
Developed acreage
Louisiana	11,569	6,662
Michigan	1,920	19
Texas	1,181	440
New Mexico	640	19
Undeveloped acreage
Offshore Australia	98,841	17,306
Louisiana	7,331	3,633
Texas	499	263
Total	121,981	28,342

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.)

	Year Ended December 31,
	2002		2001		2000
	Gross	Net	Gross	Net	Gross	Net
Development Wells:
Productive	—	—	4.00	3.39	3.00	1.77
Non-Productive	—	—	—	—	1.00	49
Total	—	—	4.00	3.39	4.00	2.26
Exploratory Wells:
Productive	2.00	1.13	1.00	17	2.00	93
Non-Productive	—	—	2.00	1.40	2.00	1.00
Total	2.00	1.13	3.00	1.57	4.00	1.93
Total Wells:
Productive	2.00	1.13	5.00	3.56	5.00	2.70
Non-Productive	—	—	2.00	1.40	3.00	1.49
Total	2.00	1.13	7.00	4.96	8.00	4.19

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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.

	2002		2001	2000
Net Production:
Natural gas (Mcf)		2,477,790	3,823,227	3,394,921
Oil (barrels)		451,564	581,680	571,766
Natural gas equivalents (Mcfe) (1)		5,187,174	7,313,307	6,825,517
Average Net Daily Production:
Natural gas (Mcf)		6,788	10,475	9,301
Oil (Bbls)		1,237	1,594	1,566
Natural gas equivalents (Mcfe) (1)		14,211	20,039	18,697
Average Sales Price Per Unit (2):
Natural gas (per Mcf)	$	3.08	3.97	3.95
Oil (per Bbl)	$	25.09	24.67	25.55
Other Data:
Lease operating expense (per Mcfe) (3)	$	1.50	0.90	0.69
Production taxes (per Mcfe).	$	0.32	0.26	0.32
DD & A (per Mcfe)	$	1.05	0.94	0.87
Exploration (per Mcfe)	$	0.22	0.57	0.41

(1) Estimated by the Company using a conversion ratio of 1.0 Bbl/6.0 Mcf.

(2) See “Results of Operations” under Item 7 for discussion of the effects of hedging on results.

(3) See “Results of Operations” under Item 7 for discussion of increase in lease operating expense in 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:

	Year Ended December 31,
	2002		2001		2000
Reliant Energy	45	%	56	%	48	%
Conoco, Inc	17	%	—		—
Shell Trading	17	%	—		—
Genesis Crude Oil, L.P.	5	%	22	%	27	%
Gulfmark Energy, Inc.	—		—		10	%

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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:

• historical production from the area compared with production from other similar producing areas;

• the assumed effects of regulations by governmental agencies;

• assumptions concerning future oil and gas prices; and

• assumptions concerning future operating costs, severance and excise taxes, development costs and workover and remedial costs.

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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:

• the quantities of oil and gas that are ultimately recovered;

• the production and operating costs incurred;

• the amount and timing of future development expenditures; and

• future oil and gas sales prices.

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:

• the amount and timing of actual production;

• supply and demand for oil and gas;

• increases or decreases in consumption; and

• changes in governmental regulations or taxation.

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:

	2002			2001
Quarter Ended	High		Low	High		Low
March 31	$	4.63	3.65	$	6.50	4.88
June 30	$	4.88	3.60	$	6.75	5.80
September 30	$	3.65	2.70	$	5.83	4.80
December 31	$	3.01	2.05	$	5.35	3.71

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.”

	Year Ended December 31,
	2002			2001		2000		1999		1998
Revenues	$	19,099,929		29,894,779		28,489,391		14,020,574		10,591,873
Lease Operating Expense and Production Taxes		9,421,375		8,441,973		6,913,968		3,591,427		2,821,515
Depletion, Depreciation and Amortization		5,452,341		6,844,751		5,953,641		4,743,608		4,094,447
Exploration		1,128,855		4,174,436		2,813,332		1,656,158		6,010,425
General and Administrative		4,467,641		3,134,865		2,518,228		1,989,703		2,399,332
Interest Expense		985,185		1,290,681		4,390,331		2,810,576		1,909,849
Total Costs and Expenses		21,797,476		25,687,242		24,712,518		15,330,062		18,311,421
Gain (Loss) on sale of assets		2,941,062		26,779		307,299		(519,495	)	4,206
Income taxes		88,648		1,487,070		(1,655,032	)	—		—
Net Income (Loss)		154,867		2,747,246		5,739,204		(1,828,983	)	(7,715,342	)
Preferred Stock Dividends		639,753		3,002,872		1,193,768		1,249,343		1,255,638
Income (Loss) Applicable to Common Stock		(484,886	)	(255,626	)	4,545,436		(3,078,326	)	(8,970,980	)
Basic Income (Loss) Per Average Common Share	$	(.03	)	(.01	)	.46		(.58	)	(1.71	)
Diluted Income (Loss) Per Average Common Share	$	(.03	)	(.01	)	.35		(.58	)	(1.71	)
Average Common Shares Outstanding Basic		17,908,182		17,351,375		9,903,248		5,288,011		5,243,105
Average Common Shares Outstanding Diluted		17,908,182		17,351,375		13,116,641		5,288,011		5,243,105
	December 31,
	2002			2001		2000		1999		1998
Selected Balance Sheet Data:
Total Assets	$	80,765,974		82,243,931		65,343,594		56,258,552		44,036,588
Total Long Term Debt		18,500,000		24,500,000		22,965,000		36,953,117		29,500,000
Stockholders’ Equity	$	46,806,116		47,920,547		32,605,216		6,411,044		4,959,388

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:

	2002			2001
	Production	Average Price		Production	Average Price
Gas (Mcf)	2,477,790	$	3.08	3,823,227	$	3.97
Oil (Bbls)	451,564	$	25.09	581,680	$	24.67

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:

	2001			2000
	Production	Average Price		Production	Average Price
Gas (Mcf)	3,823,227	$	3.97	3,394,921	$	3.95
Oil (Bbls)	581,680	$	24.67	571,766	$	25.55

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.

	Amount Due
(Millions of dollars)	Total		2003	2004-2006	2007-2008	After 2008
Long-term debt	$	18.5	—	18.5	—	—
Production Payment	$	1.2	0.5	0.7	—	—

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

18

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.

• Proved oil and natural gas reserves—Proved reserves are defined by the Securities and Exchange Commission (SEC) as those volumes of crude oil, condensate, natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered through existing wells with existing equipment and operating methods. Although the Company’s external engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of reserves requires the engineers to make a significant number of assumptions based on professional judgment. Estimated reserves are often subject to future revision, certain of which could be substantial, based on the availability of additional information, including: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in oil and natural gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions inherently lead to adjustments of depreciation rates utilized by the

19

Company. The Company cannot predict the types of reserve revisions that will be required in future periods.

• Successful efforts accounting—The Company utilizes the successful efforts method to account for exploration and development expenditures. Unsuccessful exploration wells are expensed and can have a significant effect on operating results. Successful exploration drilling costs and all development capital expenditures are capitalized and systematically charged to expense using the units of production method based on proved developed oil and natural gas reserves as estimated by engineers. The Company also uses proved developed reserves for calculating the amount of expense to recognize for future estimated dismantlement and abandonment costs.

• Impairment of properties—The Company continually monitors its long-lived assets recorded in Property, Plant and Equipment in the Consolidated Balance Sheet to make sure that they are presented fairly and accurately. The Company must evaluate its properties for potential impairment when circumstances indicate that the carrying value of an asset could exceed its fair value. Performing these evaluations requires a significant amount of judgment since the results are based on estimated future events. Such events include a projection of future oil and natural gas sales prices, an estimate of the ultimate amount of recoverable oil and natural gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels. The need to test a property for impairment can be based on several factors, including a significant reduction in sales prices for oil and/or natural gas, unfavorable adjustments to reserves, or other changes to contracts, environmental regulations or tax laws. The Company cannot predict the amount of impairment charges that may be recorded in the future.

• Income taxes—The Company is subject to income and other related taxes in areas in which it operates. When recording income tax expense, certain estimates are required by management due to timing and the impact of future events on when income tax expenses and benefits are recognized by the Company. The Company has recorded a deferred tax asset relating primarily to its tax operating loss carryforwards. The Company periodically evaluates its deferred tax asset to determine the likelihood of its realization. A valuation allowance has been recorded for the deferred tax asset to the extent that they are not likely to be realized based on management’s estimation.

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

20

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

21

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

23

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31, 2002			December 31, 2001
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	3,351,380		248,701
Accounts receivable
Trade and other, net of allowance		3,111,240		825,593
Accrued oil and gas revenue		3,141,968		3,456,210
Prepaid insurance and other		884,318		139,452
Fair value of oil and gas derivatives		—		13,000
Total current assets		10,488,906		4,682,956
PROPERTY AND EQUIPMENT
Oil and gas properties		105,971,168		108,019,749
Furniture, fixtures and equipment		567,908		321,393
		106,539,076		108,341,142
Less accumulated depletion, depreciation and amortization		(38,978,816	)	(33,247,502	)
Net property and equipment		67,560,260		75,093,640
OTHER ASSETS
Restricted cash		2,039,000		2,039,000
Deferred taxes		450,238		207,605
Other		227,570		220,730
Total other assets		2,716,808		2,467,335
TOTAL ASSETS	$	80,765,974		82,243,931
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	6,927,158		2,398,437
Accrued liabilities		1,564,583		1,693,674
Fair value of oil and gas derivatives		1,108,428		—
Current portion of other noncurrent liabilities		125,000		124,875
Total current liabilities		9,725,169		4,216,986
LONG TERM DEBT		18,500,000		24,500,000
OTHER NONCURRENT LIABILITIES
Production payment payable		978,321		1,264,729
Accrued abandonment costs		4,756,368		4,341,669
Total liabilities		33,959,858		34,323,384
STOCKHOLDERS’ EQUITY
Preferred stock; authorized 10,000,000 shares:
Series A convertible preferred stock, par value $1.00 per share; issued and outstanding 791,968 and 791,968 shares (liquidating preference $10 per share, aggregating to $7,919,680)		791,968		791,968
Common stock, par value $0.20 per share; authorized 50,000,000 shares; issued and outstanding 17,914,325 and 17,896,356 shares		3,582,864		3,579,271
Additional paid-in capital		52,333,738		52,279,331
Accumulated deficit		(9,223,359	)	(8,738,473	)
Accumulated other comprehensive income (loss)		(679,095	)	8,450
Total stockholders’ equity		46,806,116		47,920,547
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	80,765,974		82,243,931

See notes to consolidated financial statements.

24

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2002			2001		2000
REVENUES
Oil and gas sales	$	18,969,227		29,541,662		28,014,245
Other		130,702		353,117		475,146
Total revenues		19,099,929		29,894,779		28,489,391
COSTS AND EXPENSES
Lease operating expense		7,757,310		6,576,247		4,694,714
Production taxes		1,664,065		1,865,726		2,219,254
Depletion, depreciation and amortization		5,452,341		6,844,751		5,953,641
Exploration		1,128,855		4,174,436		2,813,332
Impairment of oil and gas properties		342,079		1,800,536		1,834,654
General and administrative		4,467,641		3,134,865		2,518,228
Interest expense		985,185		1,290,681		4,390,331
Other		—		—		250,000
Preferred dividend requirements of subsidiary		—		—		38,364
Total costs and expenses		21,797,476		25,687,242		24,712,518
GAIN ON SALES OF ASSETS		2,941,062		26,779		307,299
INCOME BEFORE INCOME TAXES		243,515		4,234,316		4,084,172
Income Taxes		88,648		1,487,070		(1,655,032	)
NET INCOME		154,867		2,747,246		5,739,204
Preferred stock dividends paid in cash		639,753		625,872		1,193,768
Conversion premium on Series B preferred stock		—		2,377,000		—
INCOME (LOSS) APPLICABLE TO COMMON STOCK	$	(484,886	)	(255,626	)	4,545,436
BASIC INCOME (LOSS) PER AVERAGE COMMON SHARE	$	(.03	)	(.01	)	.46
DILUTED INCOME (LOSS) PER AVERAGE COMMON SHARE	$	(.03	)	(.01	)	.35
AVERAGE COMMON SHARES OUTSTANDING—BASIC		17,908,182		17,351,375		9,903,248
AVERAGE COMMON SHARES OUTSTANDING—DILUTED		17,908,182		17,351,375		13,116,641

See notes to consolidated financial statements.

25

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2002			2001		2000
OPERATING ACTIVITIES
Net income	$	154,867		2,747,246		5,739,204
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization		5,452,341		6,844,751		5,953,641
Amortization of leasehold costs		351,719		1,017,426		1,007,636
Amortization of deferred debt financing costs		132,165		121,945		331,042
Deferred income taxes		88,648		1,487,070		(1,655,032	)
Impairment of oil and gas properties		342,079		1,800,536		1,834,654
Accrued interest and other charges on private placement borrowings		—		—		973,631
Amortization of debt discount		—		—		357,016
Amortization of production payment discount		91,110		119,728		230,649
Preferred dividends of subsidiary		—		—		38,364
Gain on sale of asset		(2,941,062	)	(26,779	)	(307,299	)
Director stock grant		30,000		30,000		30,000
Dry hole costs		—		1,604,226		475,130
Other		58,408		—		250,000
Net change in:
Accounts receivable		(1,971,405	)	513,719		(2,188,070	)
Prepaid insurance and other		(839,678	)	93,945		(181,323	)
Accounts payable		4,528,721		(645,041	)	331,728
Accrued liabilities		(129,091	)	81,709		(95,030	)
Other liabilities		—		—		(484,525	)
Net cash provided by operating activities		5,348,822		15,790,481		12,641,416
INVESTING ACTIVITIES
Proceeds from sales of assets		12,822,591		406,779		459,526
Acquisition of oil and gas properties		—		—		(1,198,631	)
Capital expenditures		(8,079,463	)	(32,252,774	)	(15,141,818	)
Net cash provided by (used in) investing activities		4,743,128		(31,845,995	)	(15,880,923	)
FINANCING ACTIVITIES
Proceeds from private placement of common stock		—		15,000,000		9,150,000
Principal payments of bank borrowings		(13,500,000	)	(13,690,000	)	(4,125,617	)
Proceeds from bank borrowings		7,500,000		15,225,000		—
Preferred stock dividends		(639,753	)	(626,331	)	(2,308,011	)
Exercise of stock purchase warrants		—		180,233		249,322
Exercise of stock options		28,000		11,563		201,319
Net change in restricted cash		—		(799,000	)	(1,240,000	)
Payment of debt and equity financing costs		—		(1,983,691	)	(431,557	)
Production payments		(377,518	)	(545,322	)	(653,415	)
Net cash provided by (used in) financing activities		(6,989,271	)	12,772,452		842,041
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		3,102,679		(3,283,062	)	(2,397,466	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		248,701		3,531,763		5,929,229
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	3,351,380		248,701		3,531,763
NON CASH INVESTING AND FINANCING ACTIVITIES
Conversion of net carrying amount of notes payable and accrued interest		—		—		10,130,349
Conversion of preferred stock of subsidiary		—		—		2,721,489

See notes to consolidated financial statements.

26

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

Years Ended December 31, 2002, 2001 and 2000

	Series A Preferred Stock					Series B Preferred Stock					Common Stock			Additional Paid-In Capital		Accumulated Deficit			Accumulated Other Comprehensive Income-			Total Stockholders’ Equity
Balance at January 1, 2000	796,318		$	796,318		665,759		$	665,759		5,417,171	$	1,083,434	$	18,156,114	$	(14,290,581	)	$	—		$	6,411,044
Net Income	—			—		—			—		—		—		—		5,739,204			—			5,739,204
Total Comprehensive Income	—			—		—			—		—		—		—		—			—			5,739,204
Issuance of Common Stock	—			—		—			—		2,533,333		506,667		8,643,333		—			—			9,150,000
Conversion of preferred stock of subsidiary to common stock	—			—		—			—		1,547,665		309,533		2,411,956		—			—			2,721,489
Exercise of director stock option	—			—		—			—		12,500		2,500		7,375		—			—			9,875
Conversion of notes payable	—			—		—			—		3,295,647		659,130		9,751,719		—			—			10,410,849
Preferred stock dividends	—			—		—			—		—		—		—		(2,308,011	)		—			(2,308,011	)
Exercise of common stock purchase warrants	—			—		—			—		252,022		50,403		198,919		—			—			249,322
Exercise of Employee Stock Options	—			—		—			—		245,698		49,140		142,304		—			—			191,444
Director Stock Grant	—			—		—			—		6,000		1,200		28,800		—			—			30,000
Conversion of Series B Preferred Stock to Common Stock	—			—		(4,920	)		(4,920	)	5,486		1,097		3,823		—			—			—
Conversion of Series A Preferred Stock to Common Stock	(4,350	)		(4,350	)	—			—		3,398		680		3,670		—			—			—
Balance at December 31, 2000	791,968		$	791,968		660,839		$	660,839		13,318,920	$	2,663,784	$	39,348,013	$	(10,859,388	)	$	—		$	32,605,216
Net Income	—			—		—			—		—		—		—		2,747,246			—			2,747,246
Cumulative Effect of Accounting Change, net of tax	—			—		—			—		—		—		—		—			(2,535,469	)		(2,535,469	)
Net Derivative Gain, net of tax	—			—		—			—		—		—		—		—			1,797,336			1,797,336
Reclassification Adjustment, net of tax	—			—		—			—		—		—		—		—			746,583			746,583
Total Comprehensive Income	—			—		—			—		—		—		—		—			—			2,755,696
Issuance of Common Stock	—			—		—			—		3,000,000		600,000		12,469,170		—			—			13,069,170
Preferred stock dividends	—			—		—			—		—		—		—		(626,331	)		—			(626,331	)
Exercise of common stock purchase warrants	—			—		—			—		375,296		75,059		105,174		—			—			180,233
Exercise of Employee Stock Options	—			—		—			—		7,500		1,500		10,063		—			—			11,563
Conversion of Series B Preferred Stock to Common Stock	—			—		(660,839	)		(660,839	)	1,189,510		237,902		317,937		—			—			(105,000	)
Director Stock Grant	—			—		—			—		5,130		1,026		28,974		—			—			30,000
Balance at December 31, 2001	791,968		$	791,968		—		$	—		17,896,356	$	3,579,271	$	52,279,331	$	(8,738,473	)	$	8,450		$	47,920,547
Net Income	—			—		—			—		—		—		—		154,867			—			154,867
Cumulative Effect of Accounting Change, net of tax	—			—		—			—		—		—		—		—			—			—
Net Derivative Gain, net of tax	—			—		—			—		—		—		—		—			(1,345,763	)		(1,345,763	)
Reclassification Adjustment, net of tax	—			—		—			—		—		—		—		—			658,218			658,218
Total Comprehensive Income	—			—		—			—		—		—		—		—			—			(532,678	)
Preferred stock dividends	—			—		—			—		—		—		—		(639,753	)		—			(639,753	)
Exercise of common stock purchase warrants	—			—		—			—		—		—		—		—			—			—
Exercise of Employee Stock Options	—			—		—			—		10,667		2,133		25,867		—			—			28,000
Conversion of Series B Preferred Stock to Common Stock	—			—		—			—		—		—		—		—			—			—
Director Stock Grant	—			—		—			—		7,302		1,460		28,540		—			—			30,000
Balance at December 31, 2002	791,968		$	791,968		—		$	—		17,914,325	$	3,582,864	$	52,333,738	$	(9,223,359	)	$	(679,095	)	$	46,806,116

See notes to consolidated financial statements

27

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2002

NOTE A—Description of Business

The Company is in the primary business of exploration and production of crude oil and natural gas. The Company’s subsidiaries have interests in such operations in four states, primarily in Louisiana and Texas.

NOTE B—Summary of Significant Accounting Policies

Principles of Consolidation—The consolidated financial statements include the financial statements of Goodrich Petroleum Corporation and its wholly-owned subsidiaries. Significant intercompany balances and transactions have been eliminated in consolidation.

Revenue Recognition—Revenues from the production of crude oil and natural gas properties in which the Company has an interest with other producers are recognized on the entitlements method. The Company records an asset or liability for natural gas balancing when the Company has purchased or sold more than its working interest share of natural gas production, respectively. At December 31, 2002 and 2001, the assets and liabilities for gas balancing were immaterial. Differences between actual production and net working interest volumes are routinely adjusted. These differences are not significant.

Property and Equipment—The Company uses the successful efforts method of accounting for exploration and development expenditures. Leasehold acquisition costs are capitalized. When proved reserves are found on an undeveloped property, leasehold cost is reclassified to proved properties. Significant undeveloped leases are reviewed periodically, and a valuation allowance is provided for any estimated decline in value. Cost of all other undeveloped leases is amortized over the estimated average holding period of the leases.

Costs of exploratory drilling are initially capitalized, but if proved reserves are not found, the costs are subsequently expensed. All other exploratory costs are charged to expense as incurred. Development costs are capitalized, including the cost of unsuccessful development wells.

The Company recognizes an impairment when the net of future cash inflows expected to be generated by an identifiable long-lived asset and cash outflows expected to be required to obtain those cash inflows is less than the carrying value of the asset. The Company performs this comparison for its oil and gas properties on a field-by-field basis using the Company’s estimates of future commodity prices. The amount of such loss is measured based on the difference between the discounted value of such net future cash flows and the carrying value of the asset. The Company recorded such impairments in 2002, 2001 and 2000 in the amounts of $342,000, $1,801,000 and $1,835,000 respectively. The impairments were generally the result of certain non-core fields depleting earlier than anticipated.

Depreciation and depletion of producing oil and gas properties are provided under the unit-of-production method. Proved developed reserves are used to compute unit rates for unamortized tangible and intangible development costs, and proved reserves are used for unamortized leasehold costs. Estimated dismantlement, abandonment, and site restoration costs, net of salvage value, are considered in determining depreciation and depletion provisions.

Gains and losses on disposals or retirements that are significant or include an entire depreciable or depletable property unit are included in income. All other dispositions, retirements, or abandonments are reflected in accumulated depreciation, depletion, and amortization.

28

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002

Cash and Cash Equivalents—Cash and cash equivalents include cash on hand, demand deposit accounts and temporary cash investments with maturities of ninety days or less at date of purchase.

Income Taxes—The Company follows the provisions of SFAS No. 109, Accounting for Income Taxes, which requires income taxes be accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

Earnings Per Share—Basic income per common share is computed by dividing net income available for common stockholders, for each reporting period by the weighted average number of common shares outstanding during the period. Diluted income per common share is computed by dividing net income available for common stockholders for each reporting period by the weighted average number of common shares outstanding during the period, plus the effects of potentially dilutive common shares.

Derivative Instruments and Hedging Activities—The Company utilizes derivative instruments such as futures, forwards, options, collars and swaps for purposes of hedging its exposure to fluctuations in the price of crude oil and natural gas and to hedge its exposure to changing interest rates.

Effective January 1, 2001, the Company adopted Statement of Financial Accounting Standard (SFAS 133), Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS 138. See also Note K for further information about the Company’s derivative instruments. In accordance with the transition provisions of SFAS 133, the Company recorded a cumulative adjustment of $2,535,000 (net of $1,365,000 in income taxes) in accumulated other comprehensive income to recognize at fair value all derivatives that were designated as cash flow hedging instruments. There was no cumulative effect on earnings. The fair value of a derivative instrument is recognized as an asset or liability in the Company’s Consolidated Balance Sheet. Upon entering into a derivative contract, the Company may designate the derivative as either a fair value hedge or a cash flow hedge, or decide that the contract is not a hedge, and thenceforth, mark the contract to market through earnings. The Company documents the relationship between the derivative instrument designated as a hedge and the hedged items, as well as its objective for risk management and strategy for use of the hedging instrument to manage the risk. Derivative instruments designated as fair value or cash flow hedges are linked to specific assets and liabilities or to specific firm commitments or forecasted transactions. The Company assesses at inception, and on an ongoing basis, whether a derivative instrument used as a hedge is highly effective in offsetting changes in the fair value or cash flows of the hedged item. A derivative that is not a highly effective hedge does not qualify for hedge accounting. Changes in the fair value of a qualifying fair value hedge are recorded in earnings along with the gain or loss on the hedged item. Changes in the fair value of a qualifying cash flow hedge are recorded in other comprehensive income, until earnings are affected by the cash flows of the hedged item. When the cash flow of the hedged item is recognized in the Statement of Income, the fair value of the associated cash flow hedge is reclassified from other comprehensive income into earnings.

Ineffective portions of a cash flow hedging derivative’s change in fair value are recognized currently in earnings. If a derivative instrument no longer qualifies as a cash flow hedge, hedge accounting is discontinued and the gain or loss that was recorded in other comprehensive income is recognized immediately in earnings.

29

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002

For the year ended December 31, 2000, prior to the adoption of SFAS No. 133, gains and losses from derivatives designated as hedges of sales were reported on the Statement of Income as an increase or reduction of oil and gas sales in the period related to the actual sale of product. Premiums paid on hedging contracts were amortized over the life of the contracts as a reduction to oil and gas sales.

Stock Based Compensation—The Company uses SFAS No. 123, Accounting for Stock-Based Compensation, which permits entities to recognize as expense, over the vesting period, the fair value of all stock-based awards on the date of grant. Alternatively, SFAS No. 123 also allows entities to continue to apply the provisions of APB Opinion No. 25, Accounting for Stock Issued to Employees, and provide pro forma net income and pro forma earnings per share and other disclosures for employee stock option grants made in 1995 and future years as if the fair-value-based method defined in SFAS No. 123 had been applied. The Company has elected to continue to apply the provisions of APB Opinion No. 25 and provide the disclosure provisions of SFAS No. 123. For stock based compensation that vests on a prorata basis where the award is fixed at the grant date, the Company has elected to amortize those costs using straight line method over the life of the award.

The Company applies APB Opinion No. 25 in accounting for its plans and, accordingly, no compensation cost has been recognized for its stock options in the financial statements. Had the Company determined compensation cost based on the fair value at the grant date for its stock options under SFAS No. 123, the Company’s net income (loss) would have been reduced to the pro forma amounts indicated below:

		2002			2001			2000
Net Income (loss)	As reported	$	154,867		$	2,747,246		5,739,204
	Pro forma		(792,230	)		2,063,595		5,040,410
Income (loss) applicable to	As reported		(484,886	)		(255,626	)	4,545,436
common stock	Pro forma		(1,431,983	)		(939,277	)	3,846,642
Basic income (loss)
per average common share	As reported		(0.03	)		(0.01	)	0.46
	Pro forma		(0.08	)		(0.05	)	0.39
Diluted income (loss)
per average common share	As reported		(0.03	)		(0.01	)	0.35
	Pro forma		(0.08	)		(0.05	)	0.29

Commitments and Contingencies—Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines and penalties, and other sources are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. Recoveries from third parties, which are probable of realization, are separately recorded, and are not offset against the related environmental liability.

Use of Estimates—Management of the Company has made a number of estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ from those estimates.

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

30

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002

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 will be recognized as a gain or loss in the Company’s earnings. The Company is currently unable to determine the effect of adopting FAS 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 statement 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

31

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002

annual and interim financial statements. Certain of the disclosure modifications are required for fiscal years ending after December 15, 2002 and are included in the notes to these consolidated financial statements.

NOTE C—Sale of Oil and Gas Properties to Related Party

On March 12, 2002, the Company, in an effort to monetize a portion of the value created in its Burrwood and West Delta 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 its Burrwood and West Delta 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 retained 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 and can be used for acquisitions, drilling, development and general corporate purposes until December 31, 2004. The investor group retains the option, during the two-year period, to convert the amount outstanding under the credit line, and/or provide cash on any unused credit to a maximum of $7.7 million through December 31, 2002, 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’s interest 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.

NOTE D—Public Offering

On February 1, 2001, the Company completed a public offering of 3,000,000 shares of its common stock at $5.00 per share resulting in net proceeds of approximately $13.2 million to the Company. The Company used the proceeds from the offering along with other available funds to reduce outstanding debt under its senior credit facility by approximately $13.7 million.

NOTE E—Exchange of Series B Preferred Stock

Prior to the public offering, the Company reached an agreement with all of the holders of its Series B preferred stock to exchange each share of Series B preferred stock for 1.8 shares of its common stock. Concurrent with the closing of the public offering, the Company exchanged all 660,839 shares of its Series B preferred stock into 1,189,510 shares of common stock. In connection with the conversion of the Series B preferred stock, a conversion premium in the amount of $2,377,000 was recorded to reflect the excess of the 1.8:1.0 conversion factor over the terms of the original preferred stock issuance. This one-time, non-cash charge was reflected as a preferred stock dividend to arrive at net income applicable to common stock and did not have an affect on total stockholders’ equity.

32

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002

NOTE F—Indebtedness

Indebtedness at December 31, 2002 and 2001 consists of the following:

	2002		2001
Bank Debt
Borrowings under credit facility, interest, at BNP Paribas prime plus 0.5% or Libor plus 2.5% (weighted average rate at December 31, 2002—5.7%); principal due November 8, 2004	$	18,500,000	24,500,000
Less current portion		—	—
Long-term debt, excluding current portion	$	18,500,000	24,500,000

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 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.

Interest paid during 2002, 2001 and 2000 amounted to $639,147, $849,725 and $2,182,724, respectively.

NOTE G—Income (Loss) Per Share

Net income (loss) was used as the numerator in computing both basic and diluted income (loss) per common share for the years ended December 31, 2002, 2001 and 2000. The following table reconciles the weighted average shares outstanding used for these computations.

	Year Ended December 31,
	2002	2001	2000
Basic Method	17,908,182	17,351,375	9,903,248
Dilutive Stock Warrants	—	—	2,842,858
Dilutive Stock Options.	—	—	370,535
Diluted Method	17,908,182	17,351,375	13,116,641

The Company’s Series A convertible preferred stock and its stock options are considered to be potential common stock. Additionally, stock purchase warrants issued in the 1999 Private Placement are also considered potential common stock. Approximately 798,000 stock options and 1,067,000 shares issuable in connection with the convertible preferred stock have not been included in the computation of diluted income per share in 2000, because to do so would have been antidilutive. No potential common stock amounts have been included in the

33

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002

computation of diluted per share in 2002 and 2001 because to do so would have been antidilutive. The calculation of the dilutive effects of potentially dilutive securities has been calculated under the treasury stock method.

NOTE H—Income Taxes

Income tax expense (benefit) for the years ending December 31, 2002, 2001 and 2000 consists of:

	Current		Deferred		Total
Year Ended December 31, 2002:
U.S. Federal	$	—	88,648		88,648
State		—	—		—
		—	88,648		88,648
Year Ended December 31, 2001:
U.S. Federal	$	—	1,487,070		1,487,070
State		—	—		—
		—	1,487,070		1,487,070
Year Ended December 31, 2000:
U.S. Federal	$	—	(1,655,032	)	(1,655,032	)
State		—	—		—
		—	(1,655,032	)	(1,655,032	)

The following is a reconciliation of the U.S. statutory income to the Company’s income (loss) before income taxes for the years ended December 31, 2002, 2001 and 2000:

	2002		2001	2000
U.S. statutory income tax	$	83,590	1,482,011	1,429,460
Increase in deductible temporary differences for which no benefit recorded		—	—	—
Change in the beginning of the year balance of the valuation allowance allocated to income tax expense		—	—	(3,089,767	)
Nondeductible expenses		5,058	5,059	5,275
	$	88,648	1,487,070	(1,655,032	)

34

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2002 and 2001 are presented below.

	2002			2001
Deferred tax assets:
Differences between book and tax basis of:
Operating loss carryforwards	$	14,234,869		12,878,565
Statutory depletion carryforward		7,034,566		6,695,115
AMT Tax credit carryforward		1,399,890		1,399,890
Asset related to hedging activities		387,950		—
Contingent liabilities		132,348		107,848
Other		258,264		229,798
Total gross deferred tax assets		23,447,887		21,311,216
Less valuation allowance		(17,641,358	)	(17,000,473	)
Net deferred tax assets		5,806,529		4,310,743
Deferred tax liability:
Differences between book and tax basis of:
Property and equipment		(5,356,291	)	(4,103,138	)
Total gross deferred liability		(5,356,291	)	(4,103,138	)
Net deferred tax asset	$	450,238		207,605

The valuation allowance for deferred tax assets increased $640,885 and increased $184,274 for the years ended December 31, 2002 and 2001, respectively. The increase in both years is primarily the result of changes in deferred tax assets. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based primarily upon the level of projections for future taxable income and the reversal of future taxable temporary differences over the periods which the deferred tax assets are deductible, management believes it is more likely than not the Company will realize the benefits of these deductible differences, net of the existing valuation allowance at December 31, 2002. The amount of the deferred tax assets considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carryforward period are reduced.

35

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002

The following table summarizes the amounts and expiration dates of operating loss and investment tax credit carryforwards:

Operating loss carryforwards
Expires	Amounts
2006	$  3,780,636
2007	8,860,622
2008	4,285,746
2009	3,247,494
2010	6,450,859
2011	600,706
2012	1,939,496
2018	4,530,029
2019	2,546,445
2020	372,409
2021	1,750
2022	4,054,863
	$40,671,055

An ownership change in accordance with Internal Revenue Code (IRC) (S)382, occurred in August 1995 and again in August 2000. The net operating losses (NOLs) generated prior to August 1995 are subject to an annual IRC (S)382 limitation of $1,682,797. The IRC (S)382 annual limitation for the ownership change in August 2000 is $3,647,700. The latter IRC (S)382 ownership change limitation is a cumulative limitation and does not eliminate or increase the limitation on the pre-August 1995 NOLs. The NOLs generated after August 1995 and prior to August 2000, are subject to an annual limitation of $3,647,700 less the annual amount utilized for pre-August 1995 NOLs. It should be noted that the same IRC (S)382 limitations apply to the alternative minimum tax net operating loss carryforwards depletion carryforwards, and alternative minimum tax credit carryforwards. The minimum tax credit carryforward (MTC) of $1,399,890 as of December 31, 2002, will not begin to be utilized until after the available NOLs have been utilized or expired and when regular tax exceeds the current year alternative minimum tax. Additionally, the statutory (percentage) depletion carryforward of $20,098,759 is considered a special deduction under FASB Statement 109. In accordance with Statement 109, the tax benefits of special deductions are generally recognized in the year they become deductible on the tax return. The unused annual IRC (S)382 limitations can be carried over to subsequent years.

NOTE I—Production Payment Obligation

A production payment was entered into by the Company to assist in the financing of the Lafitte field acquisition in September 1999. The original amount of the production payment obligation was $2,940,000, which was recorded as a production payment liability of $2,228,000 after a discount to reflect an effective rate of interest of 11.25%. At December 31, 2002 the remaining principal amount was $1,281,000 and the recorded liability was $978,000. Under the terms of the production payment the Company must make monthly cash payments which approximate the Company’s forty-nine percent share of 10% of the monthly gross oil and gas revenue of the Lafitte field.

The Company’s estimate as of December 31, 2002, based on expected production and prices and expected discount amortization is that projected payments will decrease the liability as follows: 2003, $521,000 and 2004, $760,000.

36

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002

NOTE J—Stockholders’ Equity

On February 1, 2001, the Company completed a public offering of 3,000,000 shares of its common stock at $5.00 per share resulting in net proceeds of approximately $13.2 million to the Company. The Company used the proceeds from the offering along with other available funds to reduce outstanding debt under its senior credit facility by approximately $13.7 million.

On October 23, 2000, the Company completed a private placement of 1,000,000 shares of common stock at $5.00 per share. Net proceeds from the private placement amounted to $4,650,000 and were used primarily to accelerate the development of the Company’s Burrwood and West Delta fields. An affiliate of a member of the Company’s board of directors received $250,000 in compensation for its service in placing the shares in the private placement.

On February 18, 2000, the Company completed a private placement of shares of its common stock resulting in net proceeds to the Company of $4,500,000. The Company issued 1,533,000 shares of common stock in its offering. The $4,500,000 in offering proceeds was used to assist in the acquisition and development of the Burrwood and West Delta fields, and to further develop the Lafitte field purchased in 1999.

Common Stock—At December 31, 2002 unissued shares of Goodrich common stock were reserved in the amount of 4,534,000 shares for the exercise of stock warrants issued in connection with the private placement transaction of September 23, 1999 and 330,013 shares for Series A convertible preferred stock.

Preferred Stock—The Series A convertible preferred stock has a par value of $1.00 per share with a liquidation preference of $10.00 per share, and is convertible at the option of the holder at any time, unless earlier redeemed, into shares of common stock of the Company at an initial conversion rate of .417 shares of common stock per share of Series A preferred. The Series A preferred stock also will automatically convert to common stock if the closing price for the Series A preferred stock exceeds $15.00 per share for ten consecutive trading days. The Series A preferred stock is redeemable in whole or in part, at $12.00 per share, plus accrued and unpaid dividends. Dividends on the Series A preferred stock accrue at an annual rate of 8% and are cumulative.

The Company issued 750,000 shares of Series B convertible preferred stock in connection with its acquisition of the La/Cal II properties on January 31, 1997. The Series B convertible preferred stock had a par value of $1.00 per share with a liquidation preference of $10.00 per share and ranked junior to the Series A preferred stock. The shares of Series B preferred stock were convertible at the option of the holder at any time, unless earlier redeemed, into shares of common stock of the Company at the conversion rate of 1.12 shares of common stock per share of Series B preferred stock. The Series B preferred stock was redeemable by the Company prior to January 31, 2001 at $10.00 per share. Dividends on the Series B preferred stock accrued at an annual rate of 8.25% and were cumulative.

The Company reached an agreement with all of the holders of its Series B preferred stock in 2001 to exchange each share of Series B for 1.8 shares of its common stock. Concurrent with the closing of its public offering (See Note E), the Company exchanged all 660,839 shares of its Series B preferred stock into 1,189,510 shares of common stock.

Stock Option and Incentive Programs—Goodrich currently has two plans, which provide for stock option and other incentive awards for the Company’s key employees, consultants and directors. The Goodrich Petroleum Corporation 1995 Stock Option Plan allows the Board of Directors to grant stock options, restricted

37

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002

stock awards, stock appreciation rights, long-term incentive awards and phantom stock awards, or any combination thereof, to key employees and consultants. The Goodrich Petroleum Corporation 1997 Director Compensation Plan provides for the grant of stock and options to each director who is not and has never been an employee of the Company. Additionally, the Company assumed certain outstanding stock options of Patrick as a result of the business combination in 1995.

The Goodrich plans authorize grants of options to purchase up to a combined total of 1,587,168 shares of authorized but unissued common stock. Stock options are generally granted with an exercise price equal to the stock’s fair market value at the date of grant, and all stock options granted under the 1995 Stock Option Plan generally have ten year terms and three year pro rata vesting.

In February 2003, the Company cancelled 1,016,500 outstanding options by issuing 125,157 shares of its common stock to the holders of such options. At the same time, the Company issued 150,000 restricted shares of its common stock, with a three year vesting period, to its employees under the Company’s existing incentive stock option and restricted stock awards plan. As a result of these transactions, the Company’s total shares and options outstanding will be reduced by 741,343 shares. Additionally, the Company will be required to record a charge of approximately $403,000 in the first quarter of 2003 related to the issuance of shares in lieu of rescinded options and to record periodic charges of approximately $40,000 per quarter beginning in the first quarter of 2003 and continuing through the first quarter of 2006 related to the vesting of the restricted stock.

The per share weighted average fair value of stock options granted during 2002, 2001 and 2000 was $2.43, $2.63 and $3.16 on the date of grant using the Black Scholes option-pricing model with the following weighted-average assumptions:

2002—expected dividend yield 0%, risk-free interest rate of 6%, and an expected life of 5 years; 2001—expected dividend yield 0%, risk-free interest rate of 6.0%, and an expected life of 6 years;

38

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002

Stock option transactions during 2002, 2001 and 2000 were as follows:

	Number of Options		Weighted Average Exercise Price		Range of Exercise Price	Weighted Average Remaining Contractual Life
			Total		Total	Total
Outstanding January 1, 2000	472,884				$0.75 to $24.00	8.5 yrs.
Granted—1995 Stock Option Plan	600,000		$	4.99
Granted—1997 Director Compensation Plan	12,000			4.88
Exercised—1995 Stock Option Plan	(245,696	)		.78
Exercised—1997 Director Stock Option Plan	(12,500	)		.79
Expiration of Options	(63,750	)		4.35
Outstanding December 31, 2000	762,938				$0.75 to $24.00	8.9 yrs.
Granted—1995 Stock Option Plan	710,000			5.79
Granted—1997 Director Compensation Plan	24,000			5.85
Exercised—1995 Stock Option Plan	(7,500	)		1.54
Expiration of Options	(24,376	)		7.67
Outstanding December 31, 2001	1,465,062				$0.75 to $18.00	8.7 yrs.
Granted—1995 Stock Option Plan	63,000			3.72
Granted—1997 Director Compensation Plan	24,000			4.11
Exercised—1995 Stock Option Plan	(10,677	)		2.63
Expiration of options	(5,333	)		2.63
Outstanding Dec. 31, 2002	1,536,062				$0.75 to $18.00	7.8 yrs
Exercisable December 31, 2000	129,356			7.59
Exercisable December 31, 2001	349,063			5.21
Exercisable December 31, 2002	764,917			5.32

NOTE K—Hedging Activities

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

39

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002

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.

As of December 31, 2002, $679,095 (net of $365,667 in income taxes) of deferred losses on derivative instruments accumulated in other comprehensive income are expected to be reclassified into earnings during the next twelve months. During 2002, $1,345,763 in net unrealized loss (net of $724,642 in income taxes) were recorded to accumulated other comprehensive income and $658,218 in net unrealized losses (net of $354,425 in income taxes) was reclassified from accumulated other comprehensive income to oil and gas sales as the cash flow of the hedged items was recognized. For the year ended December 31, 2002, the Company’s earnings were reduced by $63,667 from cash flow hedging ineffectiveness arising from the natural gas hedging contracts.

The Company has the option to terminate its outstanding oil and natural gas hedging contracts by paying the amount of the liability. The Company does not anticipate terminating any of its open contracts. The Company is exposed to credit losses in the event of nonperformance by the counterparties to its hedging contracts. The Company anticipates, however, that counterparties will be able to fully satisfy their obligations under the contracts. The Company does not obtain collateral to support financial instruments but monitors the credit standing of the counterparties.

Price fluctuations and volatile nature of markets

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

40

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002

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

Subsequent to December 31, 2002, the Company also entered into interest rate swaps to hedge against potential increases in interest rates. The Company has 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 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%.

NOTE L—Fair Value of Financial Instruments

The following presents the carrying amounts and estimated fair values of the Company’s financial instruments at December 31, 2002 and 2001.

	2002					2001
	Carrying Amount			Fair Value		Carrying Amount	Fair Value
Financial liabilities—
Long-term debt (including current maturities)	$	18,500,000		18,500,000		24,500,000	24,500,000
Production payment liability	$	978,321		978,321		1,264,729	1,264,729
Oil and gas derivative assets (liabilities)
Oil	$	(185,759	)	(185,759	)	—	—
Gas	$	(922,669	)	(922,669	)	13,000	13,000

The following methods and assumptions were used to estimate the fair value of each class of financial instruments:

Cash and cash equivalents, accounts receivable, restricted cash, accounts payables and accrued liabilities:    The carrying amounts approximate fair value because of the short maturity of those instruments. Therefore, these instruments were not presented in the table above.

Long term debt and other noncurrent liabilities:    The fair value is estimated using the discounted cash flow method based on the Company’s borrowing rates or similar types of financing arrangements.

Oil and gas derivatives:    The fair value is calculated based on the discounted cash flow expected to be received or paid on the derivative utilizing future posted market prices of the underlying product.

41

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002

NOTE M—Concentrations of Credit Risk and Significant 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:

	Year Ended December 31,
	2002		2001		2000
Reliant Energy	45	%	56	%	48	%
Conoco, Inc	17	%	—		—
Shell Trading	17	%	—		—
Genesis Crude Oil, L.P.	5	%	22	%	27	%
Gulfmark Energy, Inc.	—		—		10	%

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

NOTE N—Commitments and Contingencies

The U.S. Environmental Protection Agency (“EPA”) has identified the Company as a potentially responsible party (“PRP”) for the cost of clean-up of “hazardous substances” at an oil field waste disposal site in Vermilion Parish, Louisiana. The Company estimates that the remaining cost of long-term clean-up of the site will be approximately $3.5 million, with the Company’s percentage of responsibility estimated to be approximately 3.05%. As of 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.

In connection with the acquisition of its Burrwood and West Delta fields, the Company secured a performance bond and established an escrow account to be used for the payment of obligations associated with the plugging and abandonment of the wells, salvage and removal of platforms and related equipment, and the site restoration of the fields. Required escrowed outlays included an initial cash payment of $750,000 and monthly cash payments of $70,000 beginning June 1, 2000 and continuing until June 1, 2005. The escrow agreement was amended in the fourth quarter of 2001 to suspend monthly cash payments and cap the escrow account at its current balance of $2,039,000. In addition, as part of the purchase agreement, the Company agreed to shoot a 3-D seismic survey over the fields which was completed in the fourth quarter of 2001. The cost of the seismic survey was approximately $2,500,000.

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

42

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002

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.

NOTE O—Natural Gas and Crude Oil Cost Data

The following reflects the Company’s capitalized costs related to natural gas and oil activities at December 31, 2002, and 2001:

	2002			2001
Proved properties	$	101,016,271		102,730,448
Unproved properties		4,954,897		5,289,301
		105,971,168		108,019,749
Less accumulated depreciation and depletion		(38,558,059	)	(32,981,657	)
Net property and equipment	$	67,413,109		75,038,092

The following table reflects certain data with respect to cost incurred in natural gas and oil property acquisitions, exploration and development activities:

	Year Ended December 31,
	2002		2001	2000
Property acquisition
Proved	$	—	175,110	1,198,631	(a)
Unproved		—	2,186,111	820,200
Exploration		1,128,855	4,174,348	2,797,642
Development		7,843,730	28,972,446	13,862,296
	$	8,972,585	35,508,015	18,678,769

(a) Burrwood and West Delta fields acquisition

43

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002

NOTE P—Related Party Transactions

On June 1, 2001 the Company entered into a consulting agreement with Patrick E. Malloy, III, a member of the Company’s Board of Directors, under which Mr. Malloy provides the Company advice on hedging and financial matters. The contract, which expires in May 2003, pays Mr. Malloy $120,000 per year. The Company paid Mr. Malloy $120,000 in 2002 and $70,000 in 2001.

On March 12, 2002, the Company 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 its Burrwood and West Delta fields for $12 million to Malloy Energy Company, LLC, led by Patrick E. Malloy, III and participated in by Sheldon Appel and Josiah Austin, all members of the Company’s Board of Directors (Mr. Malloy is now Chairman of the Company’s Board of Directors). See Note C for further information regarding the sale.

NOTE Q—Supplemental Oil and Gas Reserve Information (Unaudited)

The supplemental oil and gas reserve information that follows is presented in accordance with SFAS No. 69, Disclosures about Oil and Gas Producing Activities. The schedules provide users with a common base for preparing estimates of future cash flows and comparing reserves among companies. Additional background information follows concerning the schedules.

Schedules 1 and 2—Estimated Net Proved Oil and Gas Reserves

Substantially all of the Company’s reserve information related to crude oil, condensate, and natural gas liquids and natural gas was compiled based on evaluations performed by Coutret and Associates, Inc. All of the subject reserves are located in the continental United States.

Many assumptions and judgmental decisions are required to estimate reserves. Quantities reported are considered reasonable but are subject to future revisions, some of which may be substantial, as additional information becomes available. Such additional knowledge may be gained as the result of reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes, and other factors.

Regulations published by the Securities and Exchange Commission define proved reserves as those volumes of crude oil, condensate, and natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those volumes expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are those volumes expected to be recovered as a result of making additional investments by drilling new wells on acreage offsetting productive units or recompleting existing wells.

Schedule 3—Standardized Measure of Discounted Future Net Cash Flows to Proved Oil and Gas Reserves

SFAS No. 69 requires calculation of future net cash flows using a ten percent annual discount factor and year end prices, costs, and statutory tax rates, except for known future changes such as contracted prices and legislated tax rates.

The calculated value of proved reserves is not necessarily indicative of either fair market value or present value of future cash flows because prices, costs, and governmental policies do not remain static; appropriate

44

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002

discount rates may vary; and extensive judgment is required to estimate the timing of production. Other logical assumptions would likely have resulted in significantly different amounts.

Schedule 3 also presents a summary of the principal reasons for change in the standard measure of discounted future net cash flows for each of the three years in the period ended December 31, 2002.

Schedule 1—Estimated Net Proved Gas Reserves (Mcf)

	Year Ended December 31,
	2002		2001		2000
Proved:
Balance, beginning of period	33,956,250		29,510,679		20,849,592
Revisions of previous estimates	29,807		6,070		708,580
Purchase of minerals in place	—		1,527,172		5,955,477
Extensions, discoveries, and other additions	3,848,920		6,735,556		5,546,322
Production	(2,477,790	)	(3,823,227	)	(3,394,921	)
Sale of minerals in place	(6,287,637	)	—		(154,371	)
Balance, end of period	29,069,550		33,956,250		29,510,679
Proved developed:
Beginning of period	16,692,390		22,251,970		13,945,540
End of period	15,203,255		16,692,390		22,251,970

Schedule 2—Estimated Net Proved Oil Reserves (Barrels)

	Year Ended December 31,
	2002		2001		2000
Proved:
Balance, beginning of period	8,750,420		6,789,358		5,738,997
Revisions of previous estimates	28,476		(5,602	)	74,369
Purchase of minerals in place	—		30,829		891,334
Extensions, discoveries, and other additions	120,970		2,517,515		665,911
Production	(451,564	)	(581,680	)	(571,766	)
Sale of minerals in place	(1,006,962	)	—		(9,487	)
Balance, end of period	7,441,340		8,750,420		6,789,358
Proved, developed:
Beginning of period	3,399,610		3,196,330		2,662,907
End of period	2,556,670		3,399,610		3,196,330

45

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

December 31, 2002

The following table summarizes the Company’s combined oil and gas reserve information on a Mcf equivalent basis. Estimates of oil reserves were converted using a conversion ratio of 1.0/6.0 Mcf.

	Year Ended December 31,
	2002	2001	2000
Estimated Net Proved Reserves (Mcfe):
Total Proved	73,717,590	86,458,770	70,246,827
Proved Developed	30,543,570	37,090,050	41,429,950

Schedule 3—Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves

	Year Ended December 31,
	2002			2001		2000
	(in thousands)
Future cash inflows	$	313,883		220,367		452,310
Production costs		(54,345	)	(59,906	)	(55,948	)
Development costs		(28,953	)	(35,673	)	(25,201	)
Future income tax expense		(44,292	)	(8,972	)	(101,113	)
Future net cash flows		186,293		115,816		270,048
10% annual discount for estimated timing of cash flows		(62,031	)	(42,694	)	(90,268	)
Standardized measure of discounted future net cash flows	$	124,262		73,122		179,780
Average year end prices:
Natural gas (per Mcf)	$	4.35		2.51		10.06
Crude oil (per Bbl)	$	28.80		17.91		26.10

The following are the principal sources of change in the standardized measure of discounted net cash flows for the years shown:

	Year Ended December 31,
	2002			2001		2000
	(in thousands)
Net changes in prices and production costs related to future production	$	84,143		(209,020	)	91,250
Sales and transfers of oil and gas produced, net of production costs		(9,548	)	(21,100	)	(21,100	)
Net change due to revisions in quantity estimates		413		(26	)	4,112
Net change due to extensions, discoveries and improved recovery		9,393		19,930		33,974
Net change due to purchase and sales of minerals-in-place		(25,314	)	1,562		39,485
Development costs incurred during the period		6,720		11,767		1,127
Net change in income taxes		(21,738	)	64,557		(56,485	)
Accretion of discount		7,889		25,011		9,241
Change in production rates (timing) and other		(818	)	661		(385	)
	$	51,140		(106,658	)	101,219

46

GOODRICH PETROLEUM CORPORATION

Consolidated Quarterly Income Information

(Unaudited)

	First Quarter			Second Quarter		Third Quarter		Fourth Quarter		Total
2002
Revenues	$	4,699,682		4,308,024		4,258,020		5,834,203		19,099,929
Costs and Expenses		5,594,856		5,596,170		4,796,331		5,810,119		21,797,476
Gain (loss) on sale of assets		2,836,501		87,700		(80,393	)	97,254		2,941,062
Income taxes		679,464		(420,156	)	(216,546	)	45,886		88,648
Net income (Loss)		1,261,863		(780,290	)	(402,158	)	75,452		154,867
Preferred stock dividends		154,798		168,223		158,366		158,366		639,753
Income (Loss) applicable to common Stock		1,107,065		(948,513	)	(560,524	)	(82,914	)	(484,886	)
Basic earnings (Loss) per average common share		.06		(.05	)	(.03	)	(.00	)	(.03	)
Diluted earnings (Loss) per average common share		.05		(.05	)	(.03	)	(.00	)	(.03	)
2001
Revenues	$	9,405,690		7,336,497		7,748,452		5,404,140		29,894,779
Costs and Expenses		5,936,133		6,375,295		5,650,079		7,725,735		25,687,242
Gain (loss) on sale of assets		38,380		33,606		—		(45,207	)	26,779
Income taxes		1,227,778		348,172		734,432		(823,312	)	1,487,070
Net income (Loss)		2,280,159		646,636		1,363,941		(1,543,490	)	2,747,246
Preferred stock dividends		2,534,908		158,367		154,798		154,799		3,002,872
Income (Loss) applicable to common Stock		(254,749	)	488,269		1,209,143		(1,698,289	)	(255,626	)
Basic earnings (Loss) per average common share		(.02	)	.03		.07		(.09	)	(.01	)
Diluted earnings (Loss) per average common share		(.02	)	.02		.06		(.09	)	(.01	)

The fourth quarter of 2002 and 2001 amount includes impairment of oil and gas properties of $342,000 and $1,801,000, respectively.

Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None

47

PART III

Item 10.    Directors and Executive Officers of the Registrant.

The Company’s executive officers and directors and their ages and positions as of March 15, 2003 are as follows:

Name	Age	Position
Patrick E. Malloy, III	60	Chairman of the Board of Directors
Walter G. “Gil” Goodrich	44	Vice Chairman, Chief Executive Officer and Director
Robert C. Turnham, Jr	45	President and Chief Operating Officer
D. Hughes Watler, Jr	54	Senior Vice President, Chief Financial Officer and Treasurer
Henry Goodrich	72	Chairman-Emeritus and Director
Sheldon Appel	69	Director
Josiah T. Austin	55	Director
Donald M. Campbell	63	Director
Michael Y. McGovern	51	Director
Michael J. Perdue	48	Director
Arthur A. Seeligson	44	Director

Patrick E. Malloy, III became Chairman of the Board of Directors in February 2003. He has been President and Chief Executive Officer of Malloy Enterprises, Inc., a real estate and investment holding company, and Malloy Real Estate, Inc. since 1973. In addition, Mr. Malloy served as a director of North Fork Bancorp (NYSE) from 1998 to 2002 and was Chairman of the Board of New York Bancorp (NYSE) from 1991 to 1998. He joined the Company’s Board in May 2000.

Walter G. “Gil” Goodrich became Vice Chairman of the Board of Directors in February 2003. He has served as the Company’s Chief Executive Officer since August 1995. Mr. Goodrich was Goodrich Oil Company’s Vice President of Exploration from 1985 to 1989 and its President from 1989 to August 1995. He joined Goodrich Oil Company as an exploration geologist in 1980. Gil Goodrich is the son of Henry Goodrich. He has served as one of the Company’s directors since August 15, 1995.

Robert C. Turnham, Jr. has served as the Company’s Chief Operating Officer since August 1995 and became President and Chief Operating Officer in February 2003. He has held various positions in the oil and natural gas business since 1981. From 1981 to 1984, Mr. Turnham served as a financial analyst for Pennzoil. In 1984, he formed Turnham Interests, Inc. to pursue oil and natural gas investment opportunities. From 1993 to August 1995, he was a partner in and served as President of Liberty Production Company, an oil and natural gas exploration and production company.

D. Hughes Watler, Jr. joined the Company as Senior Vice President, Chief Financial Officer and Treasurer in 2003. Mr. Watler is a former partner of Price Waterhouse LLP in their Houston and Tulsa offices, and was the Chief Financial Officer of Texoil, Inc, a public exploration & production company from 1992 to 1995, as well as XPRONET, a private international oil & gas exploration company from 1998 to 2002. From 1995 to 1998, Mr. Watler served as the Corporate Controller for TPC Corporation, a NYSE listed midstream natural gas company.

Henry Goodrich is the Chairman of the Board of Directors-Emeritus. He is a petroleum geologist with over 47 years experience in the oil and natural gas industry. Mr. Goodrich served as an exploration geologist with the Union Producing Company and McCord Oil Company. From 1971 to 1975, Mr. Goodrich was President, Chief Executive Officer and a partner of McCord-Goodrich Oil Company. In 1975, Mr. Goodrich formed Goodrich Oil Company. He was elected to the Company’s board in August 1995, and served as Chairman of the Board from March 1996 through February, 2003. Mr. Goodrich is also a director of Pan American Life Insurance Company. Henry Goodrich is the father of Gil Goodrich.

48

Sheldon Appel has been involved in real estate development and finance since 1955 when he formed the Sheldon Appel Company. Mr. Appel is a private investor and a former director of American Consumer Products and Beverly Hills Savings and Loan, both of which were listed on the NYSE. He has been one of the Company’s directors since August 1995.

Josiah T. Austin is the managing member of El Coronado Holdings, L.L.C., a privately owned investment holding company. He and his family own and operate agricultural properties in the state of Arizona and northern Sonora, Mexico through El Coronado Ranch & Cattle Company, L.L.C. and other entities. Mr. Austin presently serves on the Board of Directors of Monterey Bay Bancorp of Watsonville, California, and is a prior board member of New York Bancorp, Inc., which merged with North Fork Bancorporation in early 1998. He is an active investor in publicly traded financial institutions. He became one of the Company’s directors in 2002.

Donald M. Campbell is the Chief Executive Officer of Guaranty Finance Management L.L.C., which became the manager of Hambrecht and Quist Guaranty Finance L.L.C. on January 1, 2002. Prior to that time, Mr. Campbell served as the chief executive officer of Hambrecht & Quist Guaranty Finance L.L.C., and its predecessor entities, since 1985. Hambrecht and Quist Guaranty Finance L.L.C., is a subsidiary of JPMorgan Chase. He is also a director of the Moneda Chile Fund (listed on the Bermuda Stock Exchange) and Evergreen Forests Ltd. (listed on the New Zealand and Australian Stock Exchanges), and is the chairman of The New Zealand Investment Trust (listed on the London and New Zealand Stock Exchanges). He has been a financial officer of two public corporations, and has been a principal in the formation of four private companies in the United States. He has served as one of the Company’s directors since November 1999, when he was elected by the holders of the Company’s subsidiaries’ notes pursuant to the Company’s agreement with H&Q Guaranty as noteholder agent.

Michael Y. McGovern has been the Chief Executive Officer of Pioneer Companies Inc. since 2002. From 2000 to 2002, he was Chief Executive Officer of Coho Energy Resources, Inc. Prior to that time, he was the Managing Director for Pembrook Capital Corporation, Inc. from 1998 to January 2000, which provided advisory services to parties involved with distressed energy companies. He has also been a director and founding investor of Greystar Corporation since 1995, which provides production management services to oil and natural gas companies. He has served as one of the Company’s directors since September 1999, when he was elected by the holders of the Company’s subsidiaries’ notes pursuant to the Company’s agreement with H&Q Guaranty as noteholders agent.

Michael J. Perdue is currently Executive Vice President of Entrepreneurial Corporate Group and is President of its subsidiary, Entrepreneurial Capital Corporation. Prior to joining ECG in April 1999, Mr. Perdue served as Senior Vice President and Regional Manager of Zions Bancorporation from May 1998 to April 1999 and as Executive Vice President, Chief Operating Officer and a Director of FP Bancorp, Inc. and its wholly-owned subsidiary, First Pacific National Bank, from September 1993 until FP Bancorp’s acquisition by Zions Bancorporation in May 1998. He has also held senior management positions with Rampac, Inc., a real estate development company, and PacWest Bancorp. Mr. Perdue currently serves on the boards of the ECG affiliated companies. He was elected to the Company’s Board of Directors in January 2001.

Arthur A. Seeligson is currently engaged in the management of his personal investments. From 1991 to 1993, Mr. Seeligson was a Vice President, Energy Corporate Finance at Schroder Wertheim & Company, Inc. From 1993 to 1995, Mr. Seeligson was a Principal, Corporate Finance, at Wasserstein, Perella & Co. He was primarily engaged in the management of his personal investments from 1995 through 1997. He was a managing director with the investment banking firm of Harris, Webb & Garrison from 1997 to June 2000. He has served as one of the Company’s directors since August 1995.

49

Item 11.    Executive Compensation.

*

Item 12.    Security Ownership of Certain Beneficial Owners and Management.

*

Item 13.    Certain Relationships and Related Transactions.

*

* Reference is made to information under the captions “Executive Compensation”, “Security Ownership of Certain Beneficial Owners and Management”, and “Certain Relationships and Related Transactions”, in the Company’s Proxy Statement for the 2003 Annual Meeting of Stockholders.

PART IV

Item 14.    Controls and Procedures.

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

Based on their evaluation as of a date within 90 days of the filing of the Annual Report on form 10-K, the principal executive officer and principal financial officer of Goodrich Petroleum Corporation have concluded that the Company’s disclosure controls and procedures (as defined in rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934) are effective to ensure that the information required to the disclosed by Goodrich Petroleum Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

There were no significant changes in the Company’s internal controls or in other factors that could significantly affect those controls subsequent to the date of their most recent evaluation.

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PART IV

Item 15.    Exhibits, Financial Statement Schedules and Reports on Form 8-K.

(a)    1. Financial Statements

The following consolidated financial statements of Goodrich Petroleum Corporation are included in Part II, Item 8:

	Page
Independent Auditors’ Report	23
Consolidated Balance Sheets—December 31, 2002 and 2001	24
Consolidated Statements of Operations—Years ended December 31, 2002, 2001 and 2000	25
Consolidated Statements of Cash Flows—Years ended December 31, 2002, 2001 and 2000	26
Consolidated Statements of Stockholders’ Equity and Comprehensive Income —Years ended December 31, 2002, 2001 and 2000	27
Notes to Consolidated Financial Statements—Year ended December 31, 2002	28-46
Consolidated Quarterly Income Information (Unaudited)	47

2.    Financial Statement Schedules

The schedules for which provision is made in Regulation S-X are not required under the instructions contained therein, are inapplicable, or the information is included in the footnotes to the financial statements.

(b)    Reports on Form 8-K

None

(c)    Exhibits

3(i).1	Amended and Restated Certificate of Incorporation of Goodrich Petroleum Corporation dated March 12, 1998 (Incorporated by reference to Exhibit 3.1 of the Company’s First Amended Registration Statement on Form S-1 (Registration No. 333-47078) filed November 22, 2000.
3(ii).1	Bylaws of the Company, as amended and restated (Incorporated by reference to Exhibit 3.3 of the Company’s First Amended Registration Statement on Form S-1 (Registration No. 333-47078) filed November 22, 2000.
4.1	Specimen Common Stock Certificate (Incorporated by reference to Exhibit 4.6 of the Company’s Registration Statement filed February 20, 1996 on Form S-8 (File No. 33-01077)).
4.2	Credit Agreement between Goodrich Petroleum Company, L.L.C. and BNP Paribas dated November 9, 2001 (Incorporated by reference to Exhibit 4.2 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2001).
10.1	Goodrich Petroleum Corporation 1995 Stock Option Plan (Incorporated by reference to Exhibit 10.21 to the Company’s Registration Statement filed June 13, 1995 on Form S-4 (File No. 33-58631)).
10.2	Consulting Services Agreement between Patrick E. Malloy and Goodrich Petroleum Corporation dated June 1, 2001 (Incorporated by reference to Exhibit 10.3 of the Company’s Annual Report filed on Form 10-K for the year ended December 31, 2001).
10.3	Goodrich Petroleum Corporation 1997 Director Compensation Plan (Incorporated by reference to the Company’s Proxy Statement filed April 27, 1998).

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10.4	Form of Subscription Agreement dated September 27, 1999 (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated October 15, 1999).
10.5	Registration Statement on Form S-1 filed on September 29, 2000 (Registration No. 333-47078).
10.6	Registration Statement on Form S-3 filed on October 3, 2001 (Registration No. 333-70840).
*10.7	Purchase and Sale Agreement between Goodrich Petroleum Company, LLC and Malloy Energy Company, LLC, dated March 4, 2002.
21	Subsidiaries of the Registrant
	Goodrich Petroleum Corporation, Inc. of Louisiana—incorporated in the state of Nevada
	Subsidiaries of Goodrich Petroleum Company of Louisiana
	Drilling & Workover Company, Inc.—incorporated in state of Louisiana
	LECE, Inc.—incorporated in the state of Texas
	National Marketing Company—incorporated in state of Delaware
	Goodrich Petroleum Company LLC—incorporated in state of Louisiana
	Goodrich Petroleum Lafitte, LLC—incorporated in state of Louisiana
*23	Consent of KPMG LLP.
*99.1	Certification Pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
*99.2	Certification Pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

* Filed herewith.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		GOODRICH PETROLEUM CORPORATION     (Registrant)
	By:	/s/    WALTER G. GOODRICH
Date: March 27, 2003		Walter G. Goodrich Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:

Date: March 27, 2003

Signature	Title
/s/    WALTER G. GOODRICH         Walter G. Goodrich	Chief Executive Officer and Director (Principal Executive Officer)
/s/    D. HUGHES WATLER, JR.         D. Hughes Watler, Jr.	Senior Vice President, Treasurer and Chief Financial Officer (Principal Financial Officer)
/s/    KIRKLAND H. PARNELL         Kirkland H. Parnell	Vice President (Principal Accounting Officer)
/s/    PATRICK E. MALLOY, III       Patrick E. Malloy, III	Chairman of Board of Directors
/s/    SHELDON APPEL       Sheldon Appel	Director
/s/    HENRY GOODRICH       Henry Goodrich	Director
/s/    ARTHUR A. SEELIGSON       Arthur A. Seeligson	Director
/s/    DONALD M. CAMPBELL       Donald M. Campbell	Director
/s/    MICHAEL Y. MCGOVERN       Michael Y. McGovern	Director
/s/    MICHAEL J. PERDUE       Michael J. Perdue	Director
/s/    JOSIAH T. AUSTIN       Josiah T. Austin	Director

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CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Walter G. Goodrich, certify that:

1. I have reviewed this annual report on Form 10-K of Goodrich Petroleum Corporation;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report.

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 27, 2003

/s/ Walter G. Goodrich

Walter G. Goodrich

Chief Executive Officer

54

CERTIFICATION PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, D. Hughes Watler, Jr., certify that:

1. I have reviewed this annual report on Form 10-K of Goodrich Petroleum Corporation;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report.

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

d) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

e) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

f) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):

a. all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 27, 2003

/s/ D. Hughes Watler, Jr.

D. Hughes Watler, Jr.

Chief Financial Officer

55