Goodrich Petroleum 10-Q 2003 Q2 Quarterly report

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 June 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 August 12, 2003, there were 18,122,511 shares of Goodrich Petroleum Corporation common stock outstanding.

GOODRICH PETROLEUM CORPORATION

FORM 10-Q

June 30, 2003

INDEX

		Page No.
	PART 1—FINANCIAL INFORMATION
Item 1.	Financial Statements.
	Consolidated Balance Sheets
	June 30, 2003 (Unaudited) and December 31, 2002	3-4
	Consolidated Statements of Operations (Unaudited)
	Three Months Ended June 30, 2003 and 2002	5
	Six Months Ended June 30, 2003 and 2002	6
	Consolidated Statements of Cash Flows (Unaudited)
	Six Months Ended June 30, 2003 and 2002	7
	Consolidated Statements of Stockholders’ Equity (Unaudited)
	Six Months Ended June 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.	17-22
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	23-24
Item 4.	Controls and Procedures	25
	PART II—OTHER INFORMATION	26-27
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.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets

	June 30, 2003			December 31, 2002
	(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	136,520		$	3,351,380
Accounts receivable
Trade and other, net of allowance		3,532,554			3,111,240
Accrued oil and gas revenue		4,161,579			3,141,968
Prepaid insurance and other		294,473			884,318
Total current assets		8,125,126			10,488,906
PROPERTY AND EQUIPMENT
Oil and gas properties (successful efforts method)		116,262,753			105,971,168
Furniture, fixtures and equipment		632,020			567,908
		116,894,773			106,539,076
Less accumulated depletion, depreciation, and amortization		(41,259,315	)		(38,978,816	)
Net property and equipment		75,635,458			67,560,260
OTHER ASSETS
Restricted cash		2,039,000			2,039,000
Deferred taxes		—			450,238
Other		60,352			227,570
Total other assets		2,099,352			2,716,808
TOTAL ASSETS	$	85,859,936		$	80,765,974

See notes to consolidated financial statements.

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets (Continued)

	June 30, 2003			December 31, 2002
	(Unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	6,821,945		$	6,927,158
Accrued liabilities		1,583,225			1,564,583
Fair value of oil and gas derivatives		1,035,678			1,108,428
Fair value of interest rate derivatives		414,923			—
Current portion of other non-current liabilities		125,000			125,000
Total current liabilities		9,980,771			9,725,169
LONG TERM DEBT		20,000,000			18,500,000
OTHER NON-CURRENT LIABILITIES
Production payment payable and other		917,841			978,321
Accrued abandonment costs		6,397,708			4,756,368
Deferred taxes		247,487			—
Total liabilities		37,543,807			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 and 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 18,049,482 and 17,914,325 shares		3,609,896			3,582,864
Additional paid-in capital		53,202,712			52,333,738
Accumulated deficit		(7,971,021	)		(9,223,359	)
Unamortized restricted stock awards		(415,917	)		—
Accumulated other comprehensive income		(901,509	)		(679,095	)
Total stockholders’ equity		48,316,129			46,806,116
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	85,859,936		$	80,765,974

See notes to consolidated financial statements.

4

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Statement of Operations (Unaudited)

	Three Months Ended June 30,
	2003			2002
REVENUES
Oil and gas revenues	$	7,824,380		$	4,185,649
Other		58,360			122,375
Total revenues		7,882,740			4,308,024
EXPENSES
Lease operating expense		1,511,104			2,038,770
Production taxes		515,959			402,158
Depletion, depreciation and amortization		1,608,391			1,247,873
Exploration		891,481			314,662
General and administrative		1,088,901			1,377,284
Interest expense		186,354			215,423
Total costs and expenses		5,802,190			5,596,170
GAIN (LOSS) ON SALE OF ASSETS		(216,185	)		87,700
INCOME (LOSS) BEFORE INCOME TAXES		1,864,365			(1,200,446	)
Income taxes		652,028			(420,156	)
NET INCOME (LOSS)		1,212,337			(780,290	)
Preferred stock dividends		158,366			168,223
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK	$	1,053,971		$	(948,513	)
NET INCOME (LOSS) PER COMMON SHARE—BASIC
NET INCOME (LOSS)	$	0.07		$	(0.04	)
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK	$	0.06		$	(0.05	)
NET INCOME (LOSS) PER COMMON SHARE—DILUTED
NET INCOME (LOSS)	$	0.06		$	(0.04	)
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK	$	0.05		$	(0.05	)
AVERAGE COMMON SHARES OUTSTANDING—BASIC		18,040,141			17,907,380
AVERAGE COMMON SHARES OUTSTANDING—DILUTED		20,353,013			17,907,380

See notes to consolidated financial statements.

5

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Statement of Operations (Unaudited)

	Six Months Ended June 30,
	2003			2002
REVENUES
Oil and gas revenues	$	14,571,662		$	8,878,467
Other		389,557			129,239
Total revenues		14,961,219			9,007,706
EXPENSES
Lease operating expense		3,268,289			4,025,818
Production taxes		1,046,863			801,747
Depletion, depreciation and amortization		3,185,630			2,851,174
Exploration		1,444,953			760,420
General and administrative		2,627,346			2,220,027
Interest expense		421,851			531,840
Total costs and expenses		11,994,932			11,191,026
GAIN (LOSS) ON SALE OF ASSETS		(237,267	)		2,924,201
INCOME BEFORE INCOME TAXES		2,729,020			740,881
Income taxes		954,657			259,308
NET INCOME BEFORE CUMULATIVE EFFECT		1,774,363			481,573
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE NET OF TAX		(205,293	)		—
NET INCOME		1,569,070			481,573
Preferred stock dividends		316,732			323,021
NET INCOME APPLICABLE TO COMMON STOCK	$	1,252,338		$	158,552
NET INCOME PER COMMON SHARE—BASIC
NET INCOME BEFORE CUMULATIVE EFFECT	$	0.10		$	0.03
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING		(0.01	)		—
NET INCOME	$	0.09		$	0.03
NET INCOME APPLICABLE TO COMMON STOCK	$	0.07		$	0.01
NET INCOME PER COMMON SHARE—DILUTED
NET INCOME BEFORE CUMULATIVE EFFECT	$	0.09		$	0.02
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING		(0.01	)		—
NET INCOME	$	0.08		$	0.02
NET INCOME APPLICABLE TO COMMON STOCK	$	0.06		$	0.01
AVERAGE COMMON SHARES OUTSTANDING—BASIC		18,005,931			17,901,868
AVERAGE COMMON SHARES OUTSTANDING—DILUTED		20,239,856			20,272,839

See notes to consolidated financial statements

6

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Statement of Cash Flows (Unaudited)

	Six Months Ended June 30,
	2003			2002
OPERATING ACTIVITIES
Net income	$	1,569,070		$	481,573
Adjustments to reconcile net income to cash provided by operating activities:
Depletion, depreciation and amortization		3,185,630			2,851,174
Deferred income taxes		844,115			259,308
Dry hole cost		675,000			—
Amortization of leasehold costs		267,334			223,035
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		237,267			(2,924,201	)
Other non-cash items		313,974			120,506
Net change in:
Accounts receivable		(1,440,925	)		1,663,654
Prepaid insurance and other		(85,155	)		(714,643	)
Accounts payable		(105,213	)		501,143
Accrued liabilities		18,642			(647,664	)
Net cash provided by operating activities		6,198,580			1,813,885
INVESTING ACTIVITIES
Capital expenditures		(10,672,182	)		(1,980,356	)
Proceeds from sale of assets		283,561			12,902,985
Net cash provided by (used in) investing activities		(10,388,621	)		10,922,629
FINANCING ACTIVITIES
Principal payments of bank borrowings		—			(13,000,000	)
Proceeds from bank borrowings		1,500,000			1,000,000
Exercise of stock options and warrants		10,000			28,000
Production payments		(218,087	)		(178,868	)
Preferred stock dividends		(316,732	)		(323,021	)
Net cash provided by (used in) financing activities		975,181			(12,473,889	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(3,214,860	)		262,625
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		3,351,380			248,701
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	136,520		$	511,326

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GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Statements of Stockholders’ Equity and Other Comprehensive Income

Six Months Ended June 30, 2003 and 2002

(Unaudited)

	Series A Preferred Stock			Common Stock			Additional Paid-In		Accumulated			Unamortized Restricted			Accumulated Other Comprehensive			Total Stockholders’
	Shares	Amount		Shares	Amount		Capital		Deficit			Stock Awards			Income			Equity
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	—		—	—		—		—		481,573			—			—			481,573
Other Comprehensive Income (Loss); Net of Tax
Net Derivative Loss	—		—	—		—		—		—			—			(106,889	)		(106,889	)
Reclassification Adjustment	—		—	—		—		—		—			—			(214,636	)		(214,636	)
Total Comprehensive Income	—		—	—		—		—		—			—			—			160,048
Preferred Stock Dividends	—		—	—		—		—		(323,021	)		—			—			(323,021	)
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 June 30, 2002	791,968	$	791,968	17,914,325	$	3,582,864	$	52,333,738	$	(8,579,921	)	$	—		$	(313,075	)	$	47,815,574
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	—		—	—		—		—		1,569,070			—			—			1,569,070
Other Comprehensive Income (Loss); Net of Tax										—
Net Derivative Loss	—		—	—		—		—		—			—			(630,699	)		(630,699	)
Reclassification Adjustment	—		—	—		—		—		—			—			408,285			408,285
Total Comprehensive Income	—		—	—		—		—		—			—			—			1,346,656
Issuance and Amortization of Restricted Stock	—		—	—		—		483,000		—			(415,917	)		—			67,083
Issuance of Common Stock	—		—	125,157		25,032		377,974		—			—			—			403,006
Preferred Stock Dividends	—		—	—		—		—		(316,732	)		—			—			(316,732	)
Exercise of Stock Warrants	—		—	10,000		2,000		8,000		—			—			—			10,000
Balance at June 30, 2003	791,968	$	791,968	18,049,482	$	3,609,896	$	53,202,712	$	(7,971,021	)	$	(415,917	)	$	(901,509	)	$	48,316,129

8

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

June 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 six-month periods ended June 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 six months ended June 30, 2003, the Company recorded additional charges to depletion expense in the amounts of $189,000 for the accretion of the abandonment liability and $64,000 for the completion of new wells and reduced the abandonment liability by $19,000 related to the sale of a property. 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 June 30, 2002 were $5,933,000 and $6,115,000, respectively. Pro forma net income for the three month and six month periods ended June 30, 2002, assuming SFAS No. 143 had been applied retroactively, was as follows:

	Three Months Ended June 30, 2002			Six Months Ended June 30, 2002
Net income (loss)
As reported	$	(780,290	)	$	481,573
Pro forma		(809,194	)		359,221
Net income (loss) applicable to common stock
As reported	$	(948,513	)	$	158,552
Pro forma		(977,417	)		36,200
Net income (loss) per share
As reported, basic	$	(.04	)	$	.03
Pro forma, basic		(.05	)		.02
As reported, diluted		(.04	)		.02
Pro forma, diluted		(.05	)		.02

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 is currently evaluating the potential impact of SFAS No. 149 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 June 30, 2003, the Company had no financial instruments within the scope of SFAS No. 150.

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

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On March 12, 2002, the Company monetized a portion of the value created in its Burrwood/West Delta fields by selling 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/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, as well as Josiah Austin, who subsequently became a member of the Company’s Board of Directors (Mr. Malloy is now 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 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 to convert the amount outstanding under the credit line, and/or provide cash on any unused credit to a maximum of $5.0 million through December 31, 2004, 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 $5.0 million through December 31, 2004, or thirty percent (30%) of any potential acquisition(s).

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 redetermination. 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 third quarter of 2003 once BNP Paribas completes its evaluation of production information on several new oil and gas wells completed in the first and second quarters of 2003. The Company’s borrowings outstanding under the credit facility amounted to $20,000,000 as of June 30, 2003.

Interest on borrowings under the senior credit facility 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 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

11

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. Except for one financial covenant, for which the Company has obtained a waiver for the quarter ended June 30, 2003, the Company is in substantial 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 reduced to 3.40%, in the six months ended June 30, 2003.

NOTE E—Hedging Activities

As of June 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 July through December 2003; and

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

Crude Oil

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

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

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

The fair value of the natural gas and oil hedging contracts in place at June 30, 2003, resulted in a liability of $1,036,000. As of June 30, 2003, $673,000 (net of $363,000 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 six months ended June 30, 2003, $408,000 of previously deferred losses (net of $219,000 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 six months ended June 30, 2003, the Company’s earnings were not significantly affected by cash flow hedging ineffectiveness arising from the oil and gas hedging contracts.

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

12

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 six months ended June 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 June 30, 2003 of $415,000. There were no settlements under the interest rate swaps in the six months ended June 30, 2003, therefore, there were no previously deferred amounts recognized in earnings.

NOTE F—Net Income Per Share

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

	Three months ended June 30,		Six months ended June 30,
	2003	2002	2003	2002
Basic Method	18,040,141	17,907,380	18,005,931	17,901,868
Dilutive Stock Warrants	2,241,297	—	2,171,070	2,302,745
Dilutive Stock Options	71,575	—	62,855	68,226
Diluted Method	20,353.013	17,907,380	20,239,856	20,272,839

The computation of earnings per share for the three months and six months ended June 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 six months ended June 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.

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 existing incentive stock option and restricted stock awards plan. In the first quarter of 2003, the Company recorded a non-cash charge to earnings of $403,000 related to the issuance of shares in lieu of cancelled options and a charge to a contra equity account for the

13

value of the restricted stock awards in the amount of $483,000. The contra equity account is being amortized to earnings over the three year vesting period of the restricted stock awards and resulted in a non-cash charge to earnings in the six months ended June 30, 2003 of $67,000. The Company will be required to record recurring non-cash charges to earnings of approximately $40,000 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 six month periods ended June 30, 2003 and 2002 would have reduced to the pro forma amounts indicated below.

	Three Months Ended June 30,
	2003		2002
Net income(loss) before cumulative effect
As reported	$	1,212,337	$	(780,290	)
Pro forma		1,171,390		(933,392	)
Net income (loss) applicable to common stock
As reported	$	1,053,971	$	(948,513	)
Pro forma		1,013,024		(1,101,615	)
Net income (loss) per share
As reported, basic	$	.07	$	(.04	)
Pro forma, basic		.06		(.05	)
As reported, diluted		.06		(.04	)
Pro forma, diluted		.06		(.05	)

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	Six Months Ended June 30,
	2003		2002
Net income before cumulative effect
As reported	$	1,774,363	$	481,573
Pro forma		1,753,890		173,613
Net income (loss) applicable to common stock
As reported	$	1,252,338	$	158,552
Pro forma		1,231,865		(149,408	)
Net income per share
As reported, basic	$	.10	$	.03
Pro forma, basic		.10		.01
As reported, diluted		.09		.02
Pro forma, diluted		.09		.01

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 June 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.

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

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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 the trial is scheduled to commence on August 18, 2003. The ultimate outcome of 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.

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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 June 30, 2003 versus three months ended June 30, 2002

Total revenues for the three months ended June 30, 2003 amounted to $7,883,000 compared to $4,308,000 for the three months ended June 30, 2002. Oil and gas sales for the three months ended June 30, 2003 were $7,824,000 compared to $4,186,000 for the three months ended June 30, 2002. This increase resulted from higher prices for oil and gas as well as an increase in gas production volumes, primarily due to two Burrwood/West Delta wells completed in the second half of 2002, partially offset by a decline in oil production volumes. These results reflect only 5 days production from the Company’s late June 2003 completion of an exploratory well on its Tunney prospect in the Burrwood/West Delta field. The following table presents the production volumes and pricing information for the comparative periods, with the average oil and gas prices reflecting 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 June 30, 2003			Three months ended June 30, 2002
	Production	Average Price		Production	Average Price
Gas (Mcf)	748,113	$	6.16	487,903	$	2.85
Oil (Bbls)	102,859		31.30	113,400		24.63

Other revenues for the three months ended June 30, 2003 were $58,000 compared to $122,000 for the three months ended June 30, 2002, with the decrease primarily due to a reduction in interest income.

Lease operating expense was $1,511,000 for the three months ended June 30, 2003 versus $2,039,000 for the three months ended June 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, partially offset by an increase in production volumes. Production taxes were $516,000 in the three months ended June 30, 2003 compared to $402,000 in the three months ended June 30, 2002, due to an increase in production volumes partially offset by a reduction in tax rates. Depletion, depreciation and amortization expense was $1,608,000 for the three months ended June 30, 2003 versus $1,248,000 for the three months ended June 30, 2002, with the

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increase due to both higher production volumes and higher depletion rates. Exploration expense in the three months ended June 30, 2003 was $891,000 versus $315,000 in the three months ended June 30, 2002, due primarily to the Company recognizing dry hole cost of $575,000 related to an exploratory well in Australia which commenced drilling in March 2003 and was abandoned in April 2003.

General and administrative expenses amounted to $1,089,000 in the three months ended June 30, 2003 versus $1,377,000 in the three months ended June 30, 2002. The most significant factor in this variance was a reduction in legal expenses partially offset by increases in insurance costs and other administrative expenses. Higher legal expenses in the second quarter of 2002 were associated with litigation against the operator of the Lafitte field involving a contract dispute.

Interest expense was $186,000 in the three months ended June 30, 2003 compared to $215,000 in the three months ended June 30, 2002, with the decrease primarily attributable to a lower effective interest rate in the 2003 period.

Six months ended June 30, 2003 versus six months ended June 30, 2002

Total revenues for the six months ended June 30, 2003 amounted to $14,961,000 compared to $9,008,000 for the six months ended June 30, 2002. Oil and gas sales for the six months ended June 30, 2003 were $14,572,000 compared to $8,878,000 for the six months ended June 30, 2002. This increase resulted from higher prices for oil and gas as well as an increase in gas production volumes, primarily due to two Burrwood/West Delta wells completed in the second half of 2002, partially offset by a decline in oil production volumes. These results reflect only 5 days production from the Company’s late June 2003 completion of an exploratory well on its Tunney prospect in the Burrwood/West Delta field. The following table presents the production volumes and pricing information for the comparative periods, with the average oil and gas prices reflecting the results of the Company’s commodity hedging program as further described under “Quantitative and Qualitative Disclosures About Market Risk—Commodity Hedging Activity.”

	Six months ended June 30, 2003			Six months ended June 30, 2002
	Production	Average Price		Production	Average Price
Gas (Mcf)	1,479,142	$	5.23	1,220,085	$	2.76
Oil (Bbls)	213,625		31.98	246,980		22.33

Other revenues for the six months ended June 30, 2003 were $390,000 compared to $129,000 for the six months ended June 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 $3,268,000 for the six months ended June 30, 2003 versus $4,026,000 for the six months ended June 30, 2002, with the decrease due to the March 2002 sale of an interest in the Company’s Burrwood/West Delta fields (see below “Sale of Oil and

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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 $1,047,000 in the six months ended June 30, 2003 compared to $802,000 in the six months ended June 30, 2002, due to an increase in production volumes partially offset by a reduction in tax rates. Depletion, depreciation and amortization expense was $3,186,000 for the six months ended June 30, 2003 versus $2,851,000 for the six months ended June 30, 2002, with the increase due to both higher production volumes and higher depletion rates. Exploration expense in the six months ended June 30, 2003 was $1,445,000 versus $760,000 in the six months ended June 30, 2002, due primarily to the Company recognizing dry hole cost of $675,000 related to an exploratory well in Australia which commenced drilling in March 2003 and was abandoned in April 2003.

General and administrative expenses amounted to $2,627,000 in the six months ended June 30, 2003 versus $2,220,000 in the six months ended June 30, 2002. The most significant factors in this variance were a non-cash charge 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 a non-cash charge of $67,000 related to the initial vesting of 150,000 shares of restricted common stock, with a three year vesting period, that were issued in February 2003.

Interest expense was $422,000 in the six months ended June 30, 2003 compared to $532,000 in the six months ended June 30, 2002, with the decrease primarily attributable to a lower effective interest rate in the 2003 period.

Liquidity and Capital Resources

Net cash provided by operating activities was $6,199,000 in the six months ended June 30, 2003 compared to $1,814,000 in the six months ended June 30, 2002. While net cash flow from operations, before changes in working capital, substantially increased in the six months ended June 30, 2003, net changes in current assets and current liabilities resulted in a $1,613,000 decrease in working capital in the six months ended June 30, 2003 compared to a $802,000 increase in working capital in the six months ended June 30, 2002.

Net cash used in investing activities was $10,389,000 in the six months ended June 30, 2003 compared to net cash provided by investing activities of $10,923,000 in the six months ended June 30, 2002. In the six months ended June 30, 2003, capital expenditures totaled $10,672,000 as the Company participated in the drilling of five new wells in its Burrwood/West Delta and Lafitte fields (four of which were successfully completed). In the same period, the Company sold its interests in the South Drew field in Louisiana and a property in the Ackerly field in Texas for gross proceeds of $284,000. In the three months ended June 30, 2002, total capital expenditures were $1,980,000, which were more than offset by proceeds from property sales of $12,903,000, 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”).

Net cash provided by financing activities was $975,000 in the six months ended June 30, 2003 compared to net cash used in financing activities of $12,474,000 in the six months ended June

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30, 2002. In the six months ended June 30, 2003, net borrowings under the Company’s senior credit facility provided cash of $1,500,000 toward funding of capital expenditures, while preferred stock dividends and production payments required cash of $535,000. In the six months ended June 30, 2002, net repayments under the Company’s senior credit facility reduced cash by $12,000,000, while preferred stock dividends and production payments required additional cash of $502,000. The cash resources for the net debt repayments in the six months ended June 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 full year 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. Subject to current economics and available 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”).

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 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/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, as well as Josiah Austin, who subsequently became a member of the Company’s Board of Directors (Mr. Malloy is now 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 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 to convert the amount outstanding under the credit line, and/or provide cash on any unused credit to a maximum of $5.0 million through December 31, 2004, 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 $5.0 million through December 31, 2004, or thirty percent (30%) of any potential acquisition(s).

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

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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 redetermination. 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 third quarter of 2003 once BNP Paribas completes its evaluation of production information on several new oil and gas wells completed in the first and second quarters of 2003. The Company’s borrowings outstanding under the credit facility amounted to $20,000,000 as of June 30, 2003 and $21,000,000 as of August 12, 2003.

Interest on borrowings under the senior credit facility 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% 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 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. Except for one financial covenant, for which the Company has obtained a waiver for the quarter ended June 30, 2003, the Company is 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

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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 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 is currently evaluating the potential impact of SFAS No. 149 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 June 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 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 June 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 July through December 2003; and

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

Crude Oil

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

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

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

The fair value of the natural gas and oil hedging contracts in place at June 30, 2003, resulted, in a liability of $1,036,000. The hedging contracts summarized above represent approximately 47% of the Company’s estimated net oil and gas production volumes for the remainder of 2003. Based on oil and gas pricing in effect at June 30, 2003, a hypothetical 2% increase or decrease in oil and gas prices would not have had a material effect on the Company’s financial statements.

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

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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 June 30, 2003, resulted in a liability of $415,000.

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 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 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 June 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-14(c) and 15d-14(c) under the Securities Exchange Act of 1934) were effective as of June 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

The Annual Meeting of Stockholders of the Company was held on June 23, 2003. Set forth below is a brief description of each matter acted upon at the meeting and the number of votes cast for, against or withheld, and abstaining or not voting as to each matter.

Election of Class II Directors

	FOR	WITHHELD
Henry Goodrich	12,578,901	152,803
Patrick E. Malloy, III	12,582,600	149,104
Michael J. Perdue	12,659,156	72,548

Ratification of the appointment of KPMG LLP as the Company’s independent auditors for 2003

FOR	AGAINST	WITHHELD
12,661,617	65,802	4,286

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.

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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 9036 of the Sarbanes-Oxley Act of 2002.

(b) Reports on Form 8-K

(i) On May 13, 2003, the Company filed a Form 8-K containing its First Quarter 2003 Earnings Release.

(ii) On May 19, 2003, the Company filed a Form 8-K announcing that certain investors, including insiders of the Company, had entered into a purchase agreement to buy certain shares and warrants of the Company over a thirteen month period of time from a group of selling stockholders led by Hambrecht & Quist Guaranty Finance, LLC.

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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)
August 12, 2003	/s/    WALTER G. GOODRICH
Date	Walter G. Goodrich, Vice Chairman & Chief Executive Officer

August 12, 2003	/s/    D. HUGHES WATLER, JR.
Date	D. Hughes Watler, Jr., Senior Vice President & Chief Financial Officer

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