UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2003

or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                  to                 

Commission File Number: 1-7940

Goodrich Petroleum Corporation

(Exact name of registrant as specified in its charter)

Delaware	76-0466193
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer ID. No.)
808 Travis Street, Suite 1320, Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)

(713) 780-9494

(Registrant’s telephone number, including area code)

None

(Former name, former address and former fiscal year, if changed since last report.)

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

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

At November 12, 2003, there were 18,130,011 shares of Goodrich Petroleum Corporation common stock outstanding.

1

GOODRICH PETROLEUM CORPORATION

FORM 10-Q

September 30, 2003

INDEX

	Page No.
PART 1 - FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets
September 30, 2003 (Unaudited) and December 31, 2002	3-4
Consolidated Statements of Operations (Unaudited)
Three Months Ended September 30, 2003 and 2002	5
Nine Months Ended September 30, 2003 and 2002	6
Consolidated Statements of Cash Flows (Unaudited)
Nine Months Ended September 30, 2003 and 2002	7
Consolidated Statements of Stockholders’ Equity (Unaudited)
Nine Months Ended September 30, 2003 and 2002	8
Notes to Consolidated Financial Statements	9-16
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	17-23
Item 3. Quantitative and Qualitative Disclosures about Market Risk	24-25
Item 4. Controls and Procedures	26
PART II - OTHER INFORMATION	27
Item 1. Legal Proceedings
Item 2. Changes in Securities and Use of Proceeds
Item 3. Defaults Upon Senior Securities
Item 4. Submission of Matters to a Vote of Security Holders
Item 5. Other Information
Item 6. Exhibits and Reports on Form 8-K

2

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets

	September 30, 2003			December 31, 2002
	(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	1,630,351		$	3,351,380
Accounts receivable
Trade and other, net of allowance		3,727,655			3,111,240
Accrued oil and gas revenue		4,816,520			3,141,968
Prepaid insurance and other		708,735			884,318
Total current assets		10,883,261			10,488,906
PROPERTY AND EQUIPMENT
Oil and gas properties (successful efforts method)		118,278,052			105,971,168
Furniture, fixtures and equipment		627,018			567,908
		118,905,070			106,539,076
Less accumulated depletion, depreciation, and amortization		(40,405,070	)		(38,978,816	)
Net property and equipment		78,500,000			67,560,260
OTHER ASSETS
Restricted cash		2,039,000			2,039,000
Deferred taxes		—			450,238
Other		24,308			227,570
Total other assets		2,063,308			2,716,808
TOTAL ASSETS	$	91,446,569		$	80,765,974

See notes to consolidated financial statements.

3

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets (Continued)

	September 30, 2003			December 31, 2002
	(Unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	7,909,948		$	6,927,158
Accrued liabilities		2,087,854			1,564,583
Fair value of oil and gas derivatives		200,107			1,108,428
Fair value of interest rate derivatives		350,212			—
Current portion of other non-current liabilities		125,000			125,000
Total current liabilities		10,673,121			9,725,169
LONG TERM DEBT		21,600,000			18,500,000
OTHER NON-CURRENT LIABILITIES
Production payment payable and other		820,073			978,321
Accrued abandonment costs		6,525,285			4,756,368
Deferred taxes		1,391,570			—
Total liabilities		41,010,049			33,959,858
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 shares (liquidation 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 18,127,511 and 17,914,325 shares		3,625,502			3,582,864
Additional paid-in capital		53,334,080			52,333,738
Accumulated deficit		(6,591,275	)		(9,223,359	)
Unamortized restricted stock awards		(407,428	)		—
Accumulated other comprehensive income		(316,327	)		(679,095	)
Total stockholders’ equity		50,436,520			46,806,116
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	91,446,569		$	80,765,974

See notes to consolidated financial statements.

4

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Statement of Operations (Unaudited)

	Three Months Ended September 30,
	2003		2002
REVENUES
Oil and gas revenues	$	7,979,339	$	4,239,650
Other		15,419		18,370
Total revenues		7,994,758		4,258,020
EXPENSES
Lease operating expense		1,290,878		1,779,529
Production taxes		566,864		354,573
Depletion, depreciation and amortization		1,704,263		1,201,020
Exploration		384,501		285,947
General and administrative		1,365,446		957,329
Interest expense		324,148		217,933
Total costs and expenses		5,636,100		4,796,331
GAIN (LOSS) ON SALE OF ASSETS		8,438		(80,393	)
INCOME (LOSS) BEFORE INCOME TAXES		2,367,096		(618,704	)
Income taxes		828,483		(216,546	)
NET INCOME (LOSS)		1,538,613		(402,158	)
Preferred stock dividends		158,366		158,366
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK	$	1,380,247	$	(560,524	)
NET INCOME (LOSS) PER COMMON SHARE - BASIC
NET INCOME (LOSS)	$	0.08	$	(0.02	)
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK	$	0.08	$	(0.03	)
NET INCOME (LOSS) PER COMMON SHARE - DILUTED
NET INCOME (LOSS)	$	0.07	$	(0.02	)
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK	$	0.07	$	(0.03	)
AVERAGE COMMON SHARES OUTSTANDING - BASIC		18,113,947		17,914,325
AVERAGE COMMON SHARES OUTSTANDING - DILUTED		20,587,056		17,914,325

See notes to consolidated financial statements.

5

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Statement of Operations (Unaudited)

	Nine Months Ended September 30,
	2003			2002
REVENUES
Oil and gas revenues	$	22,551,001		$	13,118,118
Other		404,976			147,609
Total revenues		22,955,977			13,265,727
EXPENSES
Lease operating expense		4,559,167			5,805,347
Production taxes		1,613,727			1,156,321
Depletion, depreciation and amortization		4,889,893			4,052,194
Exploration		1,829,454			1,046,367
General and administrative		3,992,792			3,177,356
Interest expense		745,999			749,773
Total costs and expenses		17,631,032			15,987,358
GAIN (LOSS) ON SALE OF ASSETS		(228,829	)		2,843,808
INCOME BEFORE INCOME TAXES		5,096,116			122,177
Income taxes		1,783,640			42,762
NET INCOME BEFORE CUMULATIVE EFFECT		3,312,476			79,415
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE NET OF TAX		(205,293	)		—
NET INCOME		3,107,183			79,415
Preferred stock dividends		475,098			481,387
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK	$	2,632,085		$	(401,972	)
NET INCOME PER COMMON SHARE - BASIC
NET INCOME BEFORE CUMULATIVE EFFECT	$	0.18		$	0.00
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING		(0.01	)		—
NET INCOME	$	0.17		$	0.00
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK	$	0.15		$	(0.02	)
NET INCOME PER COMMON SHARE - DILUTED
NET INCOME BEFORE CUMULATIVE EFFECT	$	0.16		$	0.00
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING		(0.01	)		—
NET INCOME	$	0.15		$	0.00
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK	$	0.13		$	(0.02	)
AVERAGE COMMON SHARES OUTSTANDING - BASIC		18,042,332			17,840,491
AVERAGE COMMON SHARES OUTSTANDING - DILUTED		20,363,832			17,840,491

See notes to consolidated financial statements.

6

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Statement of Cash Flows (Unaudited)

	Nine Months Ended September 30,
	2003			2002
OPERATING ACTIVITIES
Net income	$	3,107,183		$	79,415
Adjustments to reconcile net income to cash provided by operating activities:
Depletion, depreciation and amortization		4,889,893			4,052,194
Deferred income taxes		1,673,098			42,762
Dry hole cost		809,249			—
Amortization of leasehold costs		361,863			348,686
Non-cash charge for stock issued for cancelled options		403,006			—
Cumulative effect of change in accounting principle		315,835			—
(Gain) loss on sale of assets		228,829			(2,843,808	)
Other non-cash items		364,622			178,693
Net change in:
Accounts receivable		(2,290,967	)		(247,423	)
Prepaid insurance and other		(499,417	)		(748,523	)
Accounts payable		982,790			370,160
Accrued liabilities		523,271			(533,439	)
Net cash provided by operating activities		10,869,255			698,717
INVESTING ACTIVITIES
Capital expenditures		(15,371,275	)		(5,233,526	)
Proceeds from sale of assets		341,176			12,822,591
Net cash provided by (used in) investing activities		(15,030,099	)		7,589,065
FINANCING ACTIVITIES
Principal payments of bank borrowings		—			(13,000,000	)
Proceeds from bank borrowings		3,100,000			5,500,000
Exercise of stock options and warrants		122,324			28,000
Production payments		(307,411	)		(278,610	)
Preferred stock dividends		(475,098	)		(481,387	)
Net cash provided by (used in) financing activities		2,439,815			(8,231,997	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(1,721,029	)		55,785
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		3,351,380			248,701
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	1,630,351		$	304,486

See notes to consolidated financial statements.

7

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Statements of Stockholders’ Equity and Other Comprehensive Income

Nine Months Ended September 30, 2003 and 2002

(Unaudited)

	Series A Preferred Stock			Common Stock			Additional Paid - In Capital		Accumulated Deficit			Unamortized Restricted Stock Awards			Accumulated Other Comprehensive Income			Total Stockholders’ Equity
	Shares	Amount		Shares	Amount
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	—		—	—		—		—		79,415			—			—			79,415
Other Comprehensive Income (Loss); Net of Tax
Net Derivative Loss	—		—	—		—		—		—			—			(474,204	)		(474,204	)
Reclassification Adjustment	—		—	—		—		—		—			—			(51,977	)		(51,977	)
Total Comprehensive Income	—		—	—		—		—		—			—			—			(446,766	)
Preferred Stock Dividends	—		—	—		—		—		(481,387	)		—			—			(481,387	)
Director Stock Grant	—		—	7,302		1,460		28,540		—			—			—			30,000
Exercise of Stock Options	—		—	10,667		2,133		25,867		—			—			—			28,000
Balance at September 30, 2002	791,968	$	791,968	17,914,325	$	3,582,864	$	52,333,738	$	(9,140,445	)	$	—		$	(517,731	)	$	47,050,394
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
Net Income	—		—	—		—		—		3,107,182			—			—			3,107,182
Other Comprehensive Income (Loss); Net of Tax										—
Net Derivative Loss	—		—	—		—		—		—			—			(1,271,238	)		(1,271,238	)
Reclassification Adjustment	—		—	—		—		—		—			—			1,634,006			1,634,006
Total Comprehensive Income	—		—	—		—		—		—			—			—			3,469,950
Issuance of Common Stock	—		—	125,157		25,032		377,974		—			—			—			403,006
Issuance and Amortization of Restricted Stock	—		—	—		—		517,650		—			(407,428	)		—			110,222
Preferred Stock Dividends	—		—	—		—		—		(475,098	)		—			—			(475,098	)
Exercise of Stock Options and Warrants	—		—	88,029		17,606		104,718		—			—			—			122,324
Balance at September 30, 2003	791,968	$	791,968	18,127,511	$	3,625,502	$	53,334,080	$	(6,591,275	)	$	(407,428	)	$	(316,327	)	$	50,436,520

See notes to consolidated financial statements.

8

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

September 30, 2003 and 2002

(Unaudited)

NOTE A – Basis of Presentation

The consolidated financial statements of Goodrich Petroleum Corporation (“Goodrich” or “the Company”) included in this Form 10-Q have been prepared, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission and, accordingly, certain information normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States has been condensed or omitted. The consolidated financial statements reflect all normal recurring adjustments that, in the opinion of management, are necessary for a fair presentation.

The accompanying consolidated financial statements of the Company should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2002.

The results of operations for the three-month and nine-month periods ended September 30, 2003 are not necessarily indicative of the results to be expected for the full year.

NOTE B – New Accounting Pronouncements

Effective January 1, 2003, the Company adopted SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability must be recorded in the periods in which the obligation meets the definition of a liability, which is generally when the asset is placed in service. Prior to the adoption of SFAS No. 143, the Company recorded liabilities for the abandonment of oil and gas properties only in its two largest fields, with such liabilities amounting to $4,881,000 as of December 31, 2002. In accordance with the transition provisions of SFAS No. 143, the Company recorded an adjustment to recognize additional estimated liabilities for the abandonment of oil and gas properties, as of January 1, 2003, in the amount of $1,408,000, and additional oil and gas properties, net of accumulated depletion, depreciation and amortization, in the amount of $1,092,000. To recognize the cumulative effect of this change in accounting principle, the Company recorded a charge to earnings as of January 1, 2003 in the amount of $205,000, reflecting the $316,000 difference between the adjustments to the liability and asset accounts, net of the related income tax effect. In the nine months ended September 30, 2003, the Company increased the abandonment liability by $286,000 for accretion of the liability and $296,000 for the additional liability associated with the completion of new wells and reduced the liability by $221,000 due to the abandonment and sale of two properties. Any subsequent difference between costs incurred upon settlement of an asset retirement obligation and the recorded liability will be recognized as a gain or loss in the Company’s earnings.

9

The pro forma accrued abandonment costs as of January 1, 2002 and September 30, 2002 were $5,933,000 and $6,329,000, respectively. Pro forma net income for the three month and nine month periods ended September 30, 2002, assuming SFAS No. 143 had been applied retroactively, was as follows:

	Three months ended September 30, 2002			Nine months ended September 30, 2002
Net income (loss)
As reported	$	(402,158	)	$	79,415
Pro forma		(453,458	)		(94,237	)
Net loss applicable to common stock
As reported	$	(560,524	)	$	(401,972	)
Pro forma		(611,824	)		(575,624	)
Net income (loss) per share
As reported, basic	$	(0.02	)	$	0.00
Pro forma, basic		(0.03	)		(0.01	)
As reported, diluted		(0.02	)		0.00
Pro forma, diluted		(0.03	)		(0.01	)

In April 2003, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133, Accounting for Derivatives and Hedging Activities. This statement (1) clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative, (2) clarifies when a derivative contains a financing component, and (3) amends the definition of an underlying derivative to conform to Financial Accounting Standards Board Interpretation No. 45. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003, with all provisions applied prospectively. The Company adopted SFAS No. 149, effective July 1, 2003, and the adoption had no impact on its financial statements.

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify an instrument that is within its scope as a liability. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. As of September 30, 2003, the Company had no financial instruments within the scope of SFAS No. 150.

10

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

On March 12, 2002, the Company monetized a portion of the value created in its Burrwood/West Delta fields by selling a 30% working interest in the existing production and shallow rights, and a 15% working interest in the deep rights below 10,600 feet, in such fields for $12 million to Malloy Energy Company, LLC (“MEC”) led by Patrick E. Malloy, III and participated in by Sheldon Appel, both members of the Company’s Board of Directors, as well as Josiah Austin, who subsequently became a member of the Company’s Board of Directors (Mr. Malloy is currently Chairman of the Company’s Board of Directors). The sale price was determined by discounting the present value of the acquired interest in the fields’ proved, probable and possible reserves using prevailing oil and gas prices. The Company retained an approximate 65% working interest in the existing production and shallow rights, and a 32.5% working interest in the deep rights after the close of the transaction. In conjunction with the sale, MEC provided a $7.7 million line of credit, which reduced to $5.0 million on January 1, 2003. The credit line is subordinate to the Company’s senior credit facility and can be used for acquisitions, drilling, development and general corporate purposes until December 31, 2004. MEC retains the option to convert the amount outstanding under the credit line, and/or provide cash on any unused credit, into working interests in any acquisition(s) the Company may make in Louisiana prior to January 1, 2005. In the third quarter of 2003, the Company announced two Louisiana property acquisitions in which MEC has elected to participate for a 30% working interest. Since the Company has made no borrowings under the MEC credit line to date, MEC funded its share of the acquisition costs and will fund its share of the subsequent capital costs related to these acquisitions on a direct basis, rather than by converting borrowings under the credit line.

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

NOTE D – Senior Credit Facility

On November 9, 2001, the Company established a three-year $50,000,000 senior credit facility with BNP Paribas, with an initial borrowing base of $25,000,000, subject to periodic redeterminations. The latest redetermination was performed as of June 4, 2003 and resulted in a borrowing base of $23,000,000. The Company anticipates that the next borrowing base redetermination will be performed in the fourth quarter of 2003 once BNP Paribas completes its evaluation of production information on several recently completed oil and gas wells which were not included in the latest redetermination. The Company’s borrowings outstanding under the credit facility amounted to $21,600,000 as of September 30, 2003.

Interest on borrowings under the senior credit facility accrue at a rate calculated, at the option of the Company, at either the BNP Paribas base rate plus 0.00% to 0.50%, or LIBOR plus 1.50%—2.50%, depending on borrowing base utilization. Interest on LIBOR-rate borrowings is due and payable on the last day of its respective interest period. Accrued interest on each base-rate

11

borrowing is due and payable on the last day of each quarter. The credit facility requires that the Company pay a 0.375% per annum commitment fee, payable in quarterly installments based on the Company’s borrowing base utilization. Prior to maturity, no 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. As of September 30, 2003, the Company was in compliance with all such requirements. Substantially all the Company’s assets are pledged to secure the senior credit facility.

As indicated in Note E, the Company entered into three separate interest rate swaps with BNP Paribas in February 2003 covering a three year period, with the first interest rate swap having an effective date of February 26, 2003. As a result of this arrangement, the Company’s net interest rate on its borrowings under the senior credit facility was 3.82%, in the nine months ended September 30, 2003.

NOTE E – Hedging Activities

As of September 30, 2003, the Company’s open forward position on its outstanding natural gas and crude oil hedging contracts and its interest rate swap contracts, all of which were with BNP Paribas, were as follows:

Natural Gas

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

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

Crude Oil

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

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

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

The fair value of the natural gas and crude oil hedging contracts in place at September 30, 2003, resulted in a liability of $200,000. As of September 30, 2003, $130,000 (net of $70,000 in income taxes) of deferred losses on derivative instruments accumulated in other comprehensive income are expected to be reclassified into earnings during the next twelve months. In the nine months ended September 30, 2003, $1,627,000 of previously deferred losses (net of $876,000 in income taxes) was reclassified from accumulated other comprehensive income to oil and gas sales as the cash flow of the hedged items was recognized. For the nine months ended September 30, 2003, the Company’s earnings were not significantly affected by cash flow hedging ineffectiveness arising from the crude oil and gas hedging contracts. Subsequent to September 30, 2003, the Company entered into the following crude oil hedging contract with BNP Paribas:

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

12

Interest Rate Swaps

The Company has a variable-rate debt obligation that exposes the Company to the effects of changes in interest rates. To partially reduce its exposure to interest rate risk, the Company entered into three separate interest rate swaps with BNP Paribas in February 2003 covering a three year period which are designated as cash flow hedges. The first interest rate swap, which has an effective date of February 26, 2003 and a maturity date of February 26, 2004 is for $18,000,000 with a LIBOR swap rate of 1.53%. The second interest rate swap, which has an effective date of February 26, 2004 and a maturity date of November 8, 2004, is for $18,000,000 with a LIBOR swap rate of 2.25%. The third interest rate swap, which has an effective date of November 8, 2004 and a maturity date of February 26, 2006, is for $18,000,000 with a LIBOR swap rate of 3.46%. The fair value of the effective portions of the interest rate swaps and changes thereto is deferred in other comprehensive income and is subsequently reclassified into interest expense in the periods in which the hedged interest payments on the variable-rate debt affect earnings. For the nine months ended September 30, 2003, the income effect from cash flow hedging ineffectiveness of interest rates was immaterial. The fair value of the interest rate swaps are estimated using LIBOR forward curve rates obtained from BNP Paribas. The estimated fair value approximates the values based on quotes from BNP Paribas and resulted in a liability at September 30, 2003 of $350,000. In the nine months ended September 30, 2003, $7,000 of previously deferred losses on the interest rate swap (net of $4,000 in income taxes) was reclassified from accumulated other comprehensive income to interest expense.

NOTE F – Net Income Per Share

Net income was used as the numerator in computing basic and diluted income per common share for the three months and nine months ended September 30, 2003 and 2002. The following table reconciles the weighted-average shares outstanding used for these computations.

	Three months ended September 30,		Nine months ended September 30,
	2003	2002	2003	2002
Basic Method	18,113,947	17,914,325	18,042,332	17,840,491
Dilutive Stock Warrants	2,382,368	—	2,255,169	—
Dilutive Stock Options	90,741	—	66,332	—
Diluted Method	20,587,056	17,914,325	20,363,832	17,840,491

The computation of earnings per share for the three months and nine months ended September 30, 2003 and 2002 considered exercisable stock warrants and stock options to the extent that the exercise of such securities would have been dilutive. The computation of earnings per share for the three months and nine months ended September 30, 2003 and 2002 did not consider preferred stock which is convertible into shares of common stock because the effect of such conversion would have been antidilutive.

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In February 2003, the Company issued 125,157 shares of its common stock to the holders of 1,016,500 outstanding stock options in exchange for the cancellation of such options (at the time of cancellation, the options were antidilutive). At the same time, the Company agreed to issue 150,000 restricted shares of its common stock, with a three year vesting period, to its employees under the Company’s restricted stock awards plan. The Company recorded a non-cash charge to earnings in February 2003 in the amount of $403,000 related to the issuance of shares in lieu of cancelled options. The issuance of the restricted stock awards in February 2003 had no effect on current earnings as the Company recorded a charge to a contra equity account and a credit to additional paid-in capital in the amount of $483,000 related to the value of such awards. The contra equity account is being amortized to earnings as periodic non-cash charges to general and administrative expenses over the three year vesting period of the restricted stock awards. In July 2003, the Company issued an additional 7,500 restricted shares of its common stock to its employees and recorded a charge to the contra equity account for the value of such shares in the amount of $35,000. For the nine months ended September 30, 2003, the Company recorded non-cash charges to earnings for the amortization of the aggregate awards of 157,500 restricted shares in the amount of $110,000. The Company will be required to record recurring non-cash charges to earnings of approximately $43,000 per quarter, through the first quarter of 2006, related to the periodic vesting of the restricted stock.

The Company applies APB Opinion No. 25 in accounting for its stock compensation plans and, accordingly, no compensation cost has been recognized for its stock options in the financial statements. Had the Company determined compensation cost based on the fair value at the grant date for its stock options under SFAS No. 123, net income for the three month and nine month periods ended September 30, 2003 and 2002 would have been reduced to the pro forma amounts indicated below.

	Three months ended September 30,
	2003		2002
Net income (loss)
As reported	$	1,538,613	$	(402,158	)
Pro forma		1,497,666		(555,260	)
Net income (loss) applicable to common stock
As reported	$	1,380,246	$	(560,524	)
Pro forma		1,339,300		(713,626	)
Net income (loss) per share
As reported, basic	$	0.08	$	(0.02	)
Pro forma, basic		0.08		(0.03	)
As reported, diluted		0.07		(0.02	)
Pro forma, diluted		0.07		(0.03	)

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	Nine months ended September 30,
	2003		2002
Net income (loss)
As reported	$	3,107,183	$	79,415
Pro forma		3,076,473		(382,525	)
Net income (loss) applicable to common stock
As reported	$	2,632,085	$	(401,972	)
Pro forma		2,601,375		(863,912	)
Net income (loss) per share
As reported, basic	$	0.17	$	0.00
Pro forma, basic		0.17		(0.02	)
As reported, diluted		0.15		0.00
Pro forma, diluted		0.15		(0.02	)

NOTE G – 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 September 30, 2003, the Company had paid $321,000 in costs related to this matter and accrued $122,500 for the remaining liability. These costs have not been discounted to their present value. The EPA and the PRPs will continue to evaluate the site and revise estimates for the long-term clean-up of the site. There can be no assurance that the cost of clean-up and the Company’s percentage responsibility will not be higher than currently estimated. In addition, under the federal environmental laws, the liability costs for the clean-up of the site is joint and several among all PRPs. Therefore, the ultimate cost of the clean-up to the Company could be significantly higher than the amount presently estimated or accrued for this liability.

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

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On February 8, 2000, the Company commenced a suit against the operator and joint owner of the Lafitte field, alleging certain items of misconduct and violations of the agreements associated primarily with the joint acquisition of and unfettered access to a license to 3-D seismic data over the field. The operator 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. A jury trial commenced in September 2003. On October 29, 2003, the jury found the operator and joint owner to be in breach of the Sale and Assignment and awarded a wholly-owned subsidiary of the Company damages in the amount of $537,500. The jury’s verdict has not yet been certified by the trial judge nor has the court made a determination on the Company’s claim for reimbursement of legal fees and other expenses related to the case. The timing of the outcome of these rulings is presently uncertain, however, the Company does not anticipate that the rulings will ultimately have a significant adverse impact on the Company’s operations or financial position.

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

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Management’s Discussion and Analysis of Financial

Condition and Results of Operations

The following discussion is intended to assist in understanding the Company’s financial position, results of operations and cash flows for each of the periods presented. The Company’s Annual Report on Form 10-K for the year ended December 31, 2002 includes a description of the Company’s critical accounting policies and certain other detailed information that should be referred to in conjunction with the following discussion.

Changes in Results of Operations

Three months ended September 30, 2003 versus three months ended September 30, 2002

Total revenues for the three months ended September 30, 2003 amounted to $7,995,000 compared to $4,258,000 for the three months ended September 30, 2002. Oil and gas sales for the three months ended September 30, 2003 were $7,979,000 compared to $4,240,000 for the three months ended September 30, 2002. This increase resulted from a 40% increase in oil and gas production volumes, primarily due to added production from one successful exploratory well and one successful development well completed in June and July 2003, respectively, in the Burrwood/West Delta field, as well as higher prices for oil and gas. The following table presents the production volumes and pricing information for the comparative periods, with the average oil and gas prices including the results of the Company’s commodity hedging program as further described under “Quantitative and Qualitative Disclosures About Market Risk – Commodity Hedging Activity.”

	Three months ended September 30, 2003			Three months ended September 30, 2002
	Production	Average Price		Production	Average Price
Gas (Mcf)	814,198	$	5.04	561,258	$	3.32
Oil (Bbls)	141,843		27.34	101,951		23.29

Other revenues for the three months ended September 30, 2003 were $15,000 compared to $18,000 for the three months ended September 30, 2002, with the decrease primarily due to a reduction in interest income.

Lease operating expense was $1,291,000 for the three months ended September 30, 2003 versus $1,780,000 for the three months ended September 30, 2002, with the decrease resulting from the Company’s ongoing efforts to reduce costs on its operated properties since replacing a contract operator in June 2002, as well as a non-recurring credit of approximately $262,000 in third quarter lease operating expense. Production taxes were $567,000 in the three months ended September 30, 2003 compared to $355,000 in the three months ended September 30, 2002, due to an increase in production volumes partially offset by a reduction in tax rates. Depletion, depreciation and amortization expense was $1,704,000 for the three months ended September 30, 2003 versus $1,201,000 for the three months ended September 30, 2002, with the increase

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substantially due to higher production volumes. Exploration expense in the three months ended September 30, 2003 was $385,000 versus $286,000 in the three months ended September 30, 2002, due primarily to the Company recognizing dry hole cost in August 2003 of $134,000 related to a non-operated exploratory well in Calcasieu Parish, Louisiana.

General and administrative expenses amounted to $1,365,000 in the three months ended September 30, 2003 versus $957,000 in the three months ended September 30, 2002. The most significant factor in this variance was an increase in legal expenses to $446,000 in the 2003 period from $119,000 in the 2002 period, due to litigation against the operator of the Lafitte field involving a contract dispute. Higher insurance, payroll and other administrative expenses were lesser contributing factors to the increase.

Interest expense was $324,000 in the three months ended September 30, 2003 compared to $218,000 in the three months ended September 30, 2002, with the increase primarily attributable to a higher level of borrowings in the 2003 period.

Nine months ended September 30, 2003 versus nine months ended September 30, 2002

Total revenues for the nine months ended September 30, 2003 amounted to $22,956,000 compared to $13,266,000 for the nine months ended September 30, 2002. Oil and gas sales for the nine months ended September 30, 2003 were $22,551,000 compared to $13,118,000 for the nine months ended September 30, 2002. This increase resulted from a 16% increase in oil and gas production volumes, due to several successful well completions in the 2003 period, as well as higher prices for oil and gas. The following table presents the production volumes and pricing information for the comparative periods, with the average oil and gas prices including the results of the Company’s commodity hedging program as further described under “Quantitative and Qualitative Disclosures About Market Risk – Commodity Hedging Activity.”

	Nine months ended September 30, 2003			Nine months ended September 30, 2002
	Production	Average Price		Production	Average Price
Gas (Mcf)	2,306,721	$	5.13	1,812,619	$	2.88
Oil (Bbls)	366,310		29.23	346,808		22.75

Other revenues for the nine months ended September 30, 2003 were $405,000 compared to $148,000 for the nine months ended September 30, 2002, with the increase primarily due to prospect fees received by the Company in the first quarter of 2003 on the sale of interests in its Spyglass II and Tunney drilling prospects.

Lease operating expense was $4,559,000 for the nine months ended September 30, 2003 versus $5,805,000 for the nine months ended September 30, 2002, with the decrease due primarily to the March 2002 sale of an interest in the Company’s Burrwood/West Delta fields (see below “Sale of Oil and Gas Properties to Related Party”) as well as the Company’s ongoing efforts to reduce costs on its operated properties since replacing a contract operator in June 2002. Production taxes were $1,614,000 in the nine months ended September 30, 2003 compared to $1,156,000 in

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the nine months ended September 30, 2002, due to an increase in production volumes partially offset by a reduction in tax rates. Depletion, depreciation and amortization expense was $4,890,000 for the nine months ended September 30, 2003 versus $4,052,000 for the nine months ended September 30, 2002, with the increase substantially due to higher production volumes. Exploration expense in the nine months ended September 30, 2003 was $1,829,000 versus $1,046,000 in the nine months ended September 30, 2002, due primarily to the Company recognizing dry hole costs in the amounts of $675,000 and $134,000, respectively, related to non-operated exploratory wells drilled in offshore Australia and Calcasieu Parish, Louisiana.

General and administrative expenses amounted to $3,993,000 in the nine months ended September 30, 2003 versus $3,177,000 in the nine months ended September 30, 2002. The most significant factors in this variance were non-cash charges of $403,000 related to the February 2003 issuance of 125,157 shares of common stock in lieu of 1,016,500 cancelled stock options and $110,000 related to the initial vesting of employee stock awards of 157,500 shares of restricted stock made in February and July 2003, as well as higher insurance, payroll and other administrative expenses.

Interest expense was $746,000 in the nine months ended September 30, 2003 compared to $750,000 in the nine months ended September 30, 2002, with the decrease in interest rates being virtually offset by an increase in borrowings.

Liquidity and Capital Resources

Net cash provided by operating activities was $10,869,000 in the nine months ended September 30, 2003 compared to $699,000 in the nine months ended September 30, 2002. This increase reflects higher oil and gas revenues and lower lease operating expenses in the 2003 period, partially offset by an increase in general and administrative expenses. The operating cash flow amounts are net of changes in current assets and current liabilities, which resulted in a $1,284,000 decrease in working capital in the nine months ended September 30, 2003, compared to a decrease of $1,159,000 in the nine months ended September 30, 2002.

Net cash used in investing activities was $15,030,000 in the nine months ended September 30, 2003 compared to net cash provided by investing activities of $7,589,000 in the nine months ended September 30, 2002. In the nine months ended September 30, 2003, capital expenditures totaled $15,371,000 as the Company participated in the drilling of six new wells in its Burrwood/West Delta and Lafitte fields (five of which were successfully completed). In the same period, the Company sold its interests in the South Drew field in Louisiana and two smaller properties in Texas for gross proceeds of $341,000. In the nine months ended September 30, 2002, total capital expenditures were $5,234,000, which were more than offset by proceeds from property sales of $12,823,000, primarily due to the sale of an interest in the Company’s Burrwood/West Delta fields as further described below (see “Sale of Oil and Gas Properties to Related Party”).

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Net cash provided by financing activities was $2,440,000 in the nine months ended September 30, 2003 compared to net cash used in financing activities of $8,232,000 in the nine months ended September 30, 2002. In the nine months ended September 30, 2003, net borrowings under the Company’s senior credit facility provided cash of $3,100,000 toward funding of capital expenditures, while preferred stock dividends and production payments required cash of $783,000. In the nine months ended September 30, 2002, net repayments under the Company’s senior credit facility reduced cash by $7,500,000, while preferred stock dividends and production payments required additional cash of $760,000. The cash resources for the net debt repayments in the nine months ended September 30, 2002 were provided by the sale of an interest in the Company’s Burrwood/West Delta fields as further described below (see “Sale of Oil and Gas Properties to Related Party”).

For the fourth quarter of 2003, the Company anticipates making capital expenditures totaling approximately $5 million, which includes the Company’s share of the subsequent exploration and development costs related to two recent property acquisitions in Louisiana, as further described below (see “Recent Property Acquisitions”). Subject to current economics and financial resources, the Company expects to finance its capital expenditures out of operating cash flow and available bank credit, as further described below (see “Senior Credit Facility”).

Recent Property Acquisitions

In the third quarter of 2003, the Company announced its acquisition of interests in two non-producing properties in Louisiana that required minimal initial expenditures. Pursuant to the first acquisition, the Company obtained, via farmout, the right to drill and earn all rights, excluding exploration rights to the Crane zone of the Pettit formation, in approximately 18,000 acres in the Bethany-Longstreet field in northwest Louisiana. The Company, will retain continuous drilling rights to the entire block so long as it drills at least one well every 120 days. For each productive well drilled under the agreement, the Company will earn an assignment to 160 acres. The Company has begun exploration and development drilling activities on the farmout acreage and anticipates drilling up to 13 wells on the block through the end of 2004. The gross cost of each well is estimated to be approximately $600,000 and the Company expects that its working interests in the wells will range between 50% and 70%.

Under the second acquisition, the Company obtained certain rights in the Plumb Bob field located in St. Martin Parish in southern Louisiana. The rights include oil and gas leases covering approximately 450 acres, 3-D seismic permits with oil and gas lease options covering approximately 17,000 acres, seven existing shut-in wellbores, where the Company has identified recompletion projects, and the rights to acquire related production facilities and pipelines upon establishment of production. The Company’s plans include a workover and well reactivation program, the shooting of a 32 square mile 3-D seismic survey and post 3-D exploitation and development drilling activities. The 3-D seismic shoot is anticipated to begin during the fourth quarter of 2003 and be completed by the end of the first quarter of 2004. Based on its expected 70% working interest, the Company has budgeted net capital expenditures in the Plumb Bob field of approximately $1.5 million in the fourth quarter of 2003 and up to $4.5 million in the full year of 2004.

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Sale of Oil and Gas Properties to Related Party

On March 12, 2002, the Company monetized a portion of the value created in its Burrwood/West Delta fields by selling a 30% working interest in the existing production and shallow rights, and a 15% working interest in the deep rights below 10,600 feet, in such fields for $12 million to Malloy Energy Company, LLC (“MEC”) led by Patrick E. Malloy, III and participated in by Sheldon Appel, both members of the Company’s Board of Directors, as well as Josiah Austin, who subsequently became a member of the Company’s Board of Directors (Mr. Malloy is currently Chairman of the Company’s Board of Directors). The sale price was determined by discounting the present value of the acquired interest in the fields’ proved, probable and possible reserves using prevailing oil and gas prices. The Company retained an approximate 65% working interest in the existing production and shallow rights, and a 32.5% working interest in the deep rights after the close of the transaction. In conjunction with the sale, MEC provided a $7.7 million line of credit which reduced to $5.0 million on January 1, 2003. The credit line is subordinate to the Company’s senior credit facility and can be used for acquisitions, drilling, development and general corporate purposes until December 31, 2004. MEC retains the option to convert the amount outstanding under the credit line, and/or provide cash on any unused credit, into working interests in any acquisition(s) the Company may make in Louisiana prior to January 1, 2005. MEC has elected to participate for a 30% working interest in the two Louisiana property acquisitions announced by the Company in the third quarter of 2003 (see “Recent Property Acquisitions”). Since the Company has made no borrowings under the MEC credit line to date, MEC funded its share of the acquisition costs and will fund its share of the subsequent capital costs related to these acquisitions on a direct basis, rather than by converting borrowings under the credit line.

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

Senior Credit Facility

On November 9, 2001, the Company established a three-year $50,000,000 senior credit facility with BNP Paribas, with an initial borrowing base of $25,000,000, subject to periodic redeterminations. The latest redetermination was performed as of June 4, 2003 and resulted in a borrowing base of $23,000,000. The Company anticipates that the next borrowing base redetermination will be performed information in the fourth quarter of 2003 once BNP Paribas completes its evaluation of production information on several recently completed oil and gas wells which were not included in the latest redetermination. The Company’s borrowings outstanding under the credit facility amounted to $21,600,000 as of September 30, 2003 and November 12, 2003.

Interest on borrowings under the senior credit facility accrue at a rate calculated, at the option of the Company, at either the BNP Paribas base rate plus 0.00% to 0.50%, or LIBOR plus 1.50% to 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

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borrowing is due and payable on the last day of each quarter. The credit facility requires that the Company pay a 0.375% per annum commitment fee, payable in quarterly installments based on the Company’s borrowing base utilization. Prior to maturity, no 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. As of September 30, 2003, the Company was in compliance with all such requirements. Substantially all the Company’s assets are pledged to secure the senior credit facility.

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

Critical Accounting Policies and Estimates

Critical accounting policies are defined as those that are reflective of significant judgements and uncertainties and potentially result in materially different results under different assumptions and conditions. The Company has prepared its consolidated financial statements in conformity with accounting principles generally accepted in the United States, which require management to make estimates and assumptions that affect the reported amounts in these financial statements and accompanying notes. Actual results could differ from those estimates under different assumptions or conditions. The Company has disclosed its critical accounting policies in its 2002 Annual Report on Form 10-K, and this disclosure should be read in conjunction with this Form 10-Q. Other than the change as described in the following paragraph, there have been no changes in these identified critical policies, nor have there been any initially adopted accounting policies having a material impact on reported financial results.

Effective January 1, 2003, the Company adopted SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability must be recorded in the periods in which the obligation meets the definition of a liability, which is generally when the asset is placed in service. As of January 1, 2003, the adoption of SFAS No. 143 resulted in the Company recording a cumulative effect of an accounting change in the amount of $205,000. The estimation of the liability involves the projection of future costs to plug and abandon individual wells. These estimates are based on current costs inflated to the end of the well’s economic life and discounted back to the well’s origination date. The liability will be accreted at the estimated discount rate to the expected cash required to settle the liability. The estimate requires management’s judgment with respect to the future plugging and abandonment costs, the life of the well, and the inflation and discount factors used. Changes in these estimates can significantly impact the amount of the liability.

New Accounting Pronouncements

In April 2003, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS No. 149

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amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS No. 133, Accounting for Derivatives and Hedging Activities. This statement (1) clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative, (2) clarifies when a derivative contains a financing component, and (3) amends the definition of an underlying derivative to conform to Financial Accounting Standards Board Interpretation No. 45. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003, with all provisions applied prospectively. The Company adopted SFAS No. 149, effective July 1, 2003, and the adoption had no impact on its financial statements.

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify an instrument that is within its scope as a liability. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. As of September 30, 2003, the Company had no financial instruments within the scope of SFAS No. 150.

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Quantitative and Qualitative Disclosures About Market Risk

Commodity Hedging Activity

The Company enters into futures contracts or other hedging agreements from time to time to manage the commodity price risk for a portion of its production. The Company considers these to be hedging activities and, as such, monthly settlements on these contracts are reflected in its crude oil and natural gas sales. The Company’s strategy, which is administered by the Hedging Committee of the Board of Directors, and reviewed periodically by the entire Board of Directors, has been to hedge between 30% and 70% of its production. 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. As of September 30, 2003, 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 with a no cost collar of $3.50 and $5.19 per Mmbtu for October 2003 through December 2003; and

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

Crude Oil

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

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

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

The fair value of the natural gas and crude oil hedging contracts in place at September 30, 2003, resulted, in a liability of $200,000. The hedging contracts summarized above fall within the Company’s targeted range of 30% to 70% of its estimated net oil and gas production volumes for the remainder of 2003. Based on oil and gas pricing in effect at September 30, 2003, a hypothetical 10% increase or decrease in oil and gas prices would not have had a material effect on the Company’s financial statements. Subsequent to September 30, 2003, the Company entered into the following crude oil hedging contract with BNP Paribas:

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

The above contract falls within the targeted range of 30% to 70% of estimated net crude oil production volumes for the hedged period. The Company presently has no hedges in place on any of its estimated net gas production volumes for 2004.

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Debt and Debt-Related Derivatives

In February 2003, the Company entered into three separate interest rate swaps with BNP Paribas covering a three year period. The first interest rate swap, which has an effective date of February 26, 2003 and a maturity date of February 26, 2004 is for $18,000,000 with a LIBOR swap rate of 1.53%. The second interest rate swap, which has an effective date of February 26, 2004 and a maturity date of November 8, 2004, is for $18,000,000 with a LIBOR swap rate of 2.25%. The third interest rate swap, which has an effective date of November 8, 2004 and a maturity date of February 26, 2006, is for $18,000,000 with a LIBOR swap rate of 3.46%. The fair value of the interest rate swap contracts in place at September 30, 2003, resulted in a liability of $350,000.

Price Fluctuations and the Volatile Nature of Markets

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

Disclosure Regarding Forward-Looking Statement

Certain statements in this quarterly report on Form 10-Q regarding future expectations and plans for future activities may be regarded as “forward looking statements” within the meaning of Private Securities Litigation Reform Act of 1995. They are subject to various risks, such as financial market conditions, operating hazards, drilling risks and the inherent uncertainties in interpreting engineering data relating to underground accumulations of oil and gas, as well as other risks discussed in detail in the Company’s Annual Report on Form 10-K and other filings with the Securities and Exchange Commission. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct.

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Controls and Procedures

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

Based on their evaluation as of September 30, 2003, the chief executive officer and chief financial officer of Goodrich Petroleum Corporation have concluded that the Company’s disclosure controls and procedures (as defined in rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of September 30, 2003 to ensure that the information required to be disclosed by Goodrich Petroleum Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

There were no 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 II. OTHER INFORMATION

Item 1. Legal Proceedings

Not applicable.

Item 2. Changes in Securities

None.

Item 3. Defaults Upon Senior Securities

None.

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

None.

Item 5. Other Information

Not applicable.

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

Exhibit 31.1. Certification by Chief Executive Officer Pursuant to 15 U.S.C. Section 7241, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Exhibit 31.2. Certification by Chief Financial Officer Pursuant to 15 U.S.C. Section 7241, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Exhibit 32.1. Certification by Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Exhibit 32.2. Certification by Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(b) Reports on Form 8-K

On August 18, 2003, the Company filed a Form 8-K report containing its Second Quarter 2003 Earnings Release.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	GOODRICH PETROLEUM CORPORATION                           (registrant)
November 12, 2003 Date	/s/ Walter G. Goodrich
	Walter G. Goodrich       Vice Chairman & Chief Executive Officer

November 12, 2003 Date	/s/ D. Hughes Watler, Jr.
	D. Hughes Watler, Jr.       Senior Vice President & Chief Financial Officer

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