UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2004

Or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT 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 checkmark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).    ¨  Yes    x  No

At August 10, 2004, there were 20,380,885 shares of Goodrich Petroleum Corporation common stock outstanding.

GOODRICH PETROLEUM CORPORATION

INDEX TO FORM 10-Q

June 30, 2004

	Page No.
PART 1 - FINANCIAL INFORMATION
Item 1. Financial Statements.
Consolidated Balance Sheets June 30, 2004 (Unaudited) and December 31, 2003	3-4
Consolidated Statements of Operations (Unaudited) Three Months Ended June 30, 2004 and 2003	5
Six Months Ended June 30, 2004 and 2003	6
Consolidated Statements of Cash Flows (Unaudited) Six Months Ended June 30, 2004 and 2003	7
Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Unaudited) Six Months Ended June 30, 2004 and 2003	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
Item 1. Legal Proceedings.	26
Item 2. Changes in Securities.	26
Item 3. Defaults Upon Senior Securities.	26
Item 4. Submission of Matters to a Vote of Security Holders.	26
Item 5. Other Information.	26
Item 6. Exhibits and Reports on Form 8-K.	26

2

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets

	June 30, 2004			December 31, 2003
	(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	1,395,339		$	1,488,852
Cash held temporarily for stockholders		389,813			3,886,988
Accounts receivable
Trade and other, net of allowance		6,281,299			3,500,095
Accrued oil and gas revenue		2,576,976			2,829,082
Prepaid insurance and other		469,694			351,527
Total current assets		11,113,121			12,056,544
PROPERTY AND EQUIPMENT
Oil and gas properties (successful efforts method)		135,246,650			118,682,309
Furniture, fixtures and equipment		737,233			661,842
		135,983,883			119,344,151
Less accumulated depletion, depreciation and amortization		(49,822,466	)		(44,381,223	)
Net property and equipment		86,161,417			74,962,928
OTHER ASSETS
Restricted cash		2,039,000			2,039,000
Other		100,757			124,096
Total other assets		2,139,757			2,163,096
TOTAL ASSETS	$	99,414,295		$	89,182,568

See notes to consolidated financial statements.

3

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets (Continued)

	June 30, 2004			December 31, 2003
	(unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	11,851,647		$	6,707,583
Accrued liabilities		1,519,917			1,483,329
Liability for funds held temporarily for stockholders		389,813			3,886,988
Fair value of oil and gas derivatives		2,671,120			1,257,442
Fair value of interest rate derivatives		71,076			277,938
Current portion of other non-current liabilities		91,605			91,600
Total current liabilities		16,595,178			13,704,880
LONG TERM DEBT		23,000,000			20,000,000
OTHER NON-CURRENT LIABILITIES
Production payment payable and other		495,012			704,643
Accrued abandonment costs		6,896,258			6,509,586
Deferred taxes		—			204,465
Total liabilities		46,986,448			41,123,574
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 19,131,621 and 18,130,011 shares		3,826,324			3,626,002
Additional paid-in capital		54,292,714			53,359,023
Accumulated deficit		(3,640,481	)		(8,338,403	)
Unamortized restricted stock awards		(1,124,954	)		(381,598	)
Accumulated other comprehensive income		(1,717,724	)		(997,998	)
Total stockholders’ equity		52,427,847			48,058,994
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	99,414,295		$	89,182,568

See notes to consolidated financial statements.

4

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Statements of Operations

(Unaudited)

	Three Months Ended June 30,
	2004			2003
				(restated)
REVENUES
Oil and gas revenues	$	9,350,878		$	7,824,380
Other		15,579			58,360
Total revenues		9,366,457			7,882,740
EXPENSES
Lease operating expense		1,642,560			1,511,104
Production taxes		593,929			515,959
Depletion, depreciation and amortization		2,480,350			2,063,791
Exploration		1,079,978			891,481
General and administrative		1,327,377			1,088,901
Interest expense		254,211			186,354
Total expenses		7,378,405			6,257,590
LOSS ON SALE OF ASSETS		(58,845	)		(216,185	)
INCOME BEFORE INCOME TAXES		1,929,207			1,408,965
Income taxes		(960,847	)		492,638
NET INCOME		2,890,054			916,327
Preferred stock dividends		158,203			158,366
NET INCOME APPLICABLE TO COMMON STOCK	$	2,731,851		$	757,961
NET INCOME PER SHARE - BASIC
NET INCOME	$	0.15		$	0.05
NET INCOME APPLICABLE TO COMMON STOCK	$	0.14		$	0.04
NET INCOME PER SHARE - DILUTED
NET INCOME	$	0.14		$	0.04
NET INCOME APPLICABLE TO COMMON STOCK	$	0.13		$	0.04
AVERAGE COMMON SHARES OUTSTANDING - BASIC		19,040,347			18,040,141
AVERAGE COMMON SHARES OUTSTANDING - DILUTED		21,038,770			20,388,050

See notes to consolidated financial statements.

5

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Statements of Operations

(Unaudited)

	Six Months Ended June 30,
	2004			2003
				(restated)
REVENUES
Oil and gas revenues	$	20,177,404		$	14,571,663
Other		114,318			389,557
Total revenues		20,291,722			14,961,220
EXPENSES
Lease operating expense		3,191,378			3,268,289
Production taxes		1,289,001			1,046,863
Depletion, depreciation and amortization		5,234,197			4,125,114
Exploration		2,016,803			1,444,953
General and administrative		2,832,783			2,627,345
Interest expense		471,143			421,851
Total expenses		15,035,305			12,934,415
LOSS ON SALE OF ASSETS		(58,845	)		(237,267	)
INCOME BEFORE INCOME TAXES		5,197,572			1,789,538
Income taxes		183,081			625,836
NET INCOME BEFORE CUMULATIVE EFFECT		5,014,491			1,163,702
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE NET OF TAX		—			(205,293	)
NET INCOME		5,014,491			958,409
Preferred stock dividends		316,569			316,732
NET INCOME APPLICABLE TO COMMON STOCK	$	4,697,922		$	641,677
NET INCOME PER SHARE - BASIC
NET INCOME BEFORE CUMULATIVE EFFECT	$	0.27		$	0.06
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING		—			(0.01	)
NET INCOME	$	0.27		$	0.05
NET INCOME APPLICABLE TO COMMON STOCK	$	0.25		$	0.04
NET INCOME PER SHARE - DILUTED
NET INCOME BEFORE CUMULATIVE EFFECT	$	0.24		$	0.06
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING		—			(0.01	)
NET INCOME	$	0.24		$	0.05
NET INCOME APPLICABLE TO COMMON STOCK	$	0.23		$	0.03
AVERAGE COMMON SHARES OUTSTANDING - BASIC		18,726,959			18,005,931
AVERAGE COMMON SHARES OUTSTANDING - DILUTED		20,695,895			20,265,610

See notes to consolidated financial statements.

6

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(Unaudited)

	Six Months Ended June 30,
	2004			2003
				(restated)
OPERATING ACTIVITIES
Net income	$	5,014,491		$	958,409
Adjustments to reconcile net income to cash provided by operating activities
Depletion, depreciation and amortization		5,234,197			4,125,114
Deferred income taxes		183,081			515,292
Dry hole costs		—			675,000
Amortization of leasehold costs		537,808			267,334
Non-cash charge for stock issued for cancelled options		—			403,006
Cumulative effect of change in accounting principle		—			315,835
Loss on sale of assets		58,845			237,267
Other non-cash items		89,005			313,974
Net change in:
Accounts receivable		(2,529,098	)		(1,440,925	)
Prepaid insurance and other		(118,167	)		(85,155	)
Accounts payable		5,144,064			(105,213	)
Accrued liabilities		36,588			18,642
Net cash provided by operating activities		13,650,814			6,198,580
INVESTING ACTIVITIES
Capital expenditures		(16,387,300	)		(10,672,182	)
Proceeds from sale of assets		—			283,561
Net cash used in investing activities		(16,387,300	)		(10,388,621	)
FINANCING ACTIVITIES
Principal payments of bank borrowings		(1,000,000	)		—
Proceeds from bank borrowings		4,000,000			1,500,000
Exercise of stock warrants		122,897			10,000
Production payments		(163,355	)		(218,087	)
Preferred stock dividends		(316,569	)		(316,732	)
Net cash provided by financing activities		2,642,973			975,181
NET DECREASE IN CASH AND CASH EQUIVALENTS		(93,513	)		(3,214,860	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		1,488,852			3,351,380
CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	1,395,339		$	136,520

See notes to consolidated financial statements.

7

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Statements of Stockholders’ Equity and Comprehensive Income

Six Months Ended June 30, 2004 and 2003

(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
										(Restated)									(Restated)
Balance at December 31, 2002	791,968	$	791,968	17,914,325	$	3,582,864	$	52,333,738		$	(11,422,436	)	$	—		$	(679,094	)	$	44,607,040
Net Income	—		—	—		—		—			958,409			—			—			958,409
Other Comprehensive Income (Loss); Net of Tax
Net Derivative (Loss), net of tax of $339,607	—		—	—		—		—			—			—			(630,699	)		(630,699	)
Reclassification Adjustment, net of tax of $219,846	—		—	—		—		—			—			—			408,285			408,285
Total Comprehensive Income																				735,995
Issuance and Amortization of Restricted Stock	—		—	—		—		483,000			—			(415,917	)		—			67,083
Issuance of Common Stock	—		—	135,157		27,032		385,974			—			—			—			413,006
Preferred Stock Dividends	—		—	—		—		—			(316,732	)		—			—			(316,732	)
Balance at June 30, 2003	791,968	$	791,968	18,049,482	$	3,609,896	$	53,202,712		$	(10,780,759	)	$	(415,917	)	$	(901,508	)	$	45,506,392
Balance at December 31, 2003	791,968	$	791,968	18,130,011	$	3,626,002	$	53,359,023		$	(8,338,403	)	$	(381,598	)	$	(997,998	)	$	48,058,994
Net Income	—		—	—		—		—			5,014,491			—			—			5,014,491
Other Comprehensive Income (Loss); Net of Tax
Net Derivative (Loss)	—		—	—		—		—			—			—			(2,600,172	)		(2,600,172	)
Reclassification Adjustment	—		—	—		—		—			—			—			1,880,446			1,880,446
Total Comprehensive Income																				4,294,765
Issuance and Amortization of Restricted Stock	—		—	4,331		866		1,010,250			—			(743,356	)		—			267,760
Exercise of Stock Warrants	—		—	997,279		199,456		(76,559	)		—			—			—			122,897
Preferred Stock Dividends	—		—	—		—		—			(316,569	)		—			—			(316,569	)
Balance at June 30, 2004	791,968	$	791,968	19,131,621	$	3,826,324	$	54,292,714		$	(3,640,481	)	$	(1,124,954	)	$	(1,717,724	)	$	52,427,847

See notes to consolidated financial statements.

8

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

June 30, 2004 and 2003

(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, 2003.

The results of operations for the six-month period ended June 30, 2004 are not necessarily indicative of the results to be expected for the full year.

Income Taxes

The Company follows the asset and liability method of accounting for deferred income taxes prescribed by SFAS No. 109, “Accounting for Income Taxes”. The statement provides for the recognition of a deferred tax asset for deductible temporary timing differences, capital and operating loss carryforwards, statutory depletion carryforward and tax credit carryforwards, net of a “valuation allowance”. The valuation allowance is provided for that portion of the asset for which it is deemed more likely than not that it will not be realized.

As discussed in Note F of the Consolidated Financial Statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, the Company established a deferred tax valuation allowance of $17.5 million as of December 31, 2003. The Company revised the valuation allowance in the second quarter of 2004 in the amount of $1,636,000, based on the anticipated reversal of temporary differences.

Restatement of 2003 Financial Statements

In the course of preparing its 2003 year-end financial statements, the Company discovered a systematic error in the calculations of its non-cash depletion, depreciation and amortization expense since 1997. Essentially, the Company had been allocating the acquisition and development costs of its oil and gas properties over total proved reserves in each field rather than segregating the costs between those costs to be allocated over proved developed reserves versus those costs to be allocated over total proved reserves. Accordingly, the Company has restated its previously reported depletion, depreciation and amortization expense for the three months and six months ended June 30, 2003. Such restated amounts reflect reallocations of the purchase price of three oil and gas property acquisitions completed prior to January 1, 2001, based upon analyses of contemporaneous documentation from the time of the acquisitions. The tax-effected amounts of the adjustments resulted in changes in the Company’s previously reported Statement of Operations as follows:

	Three Months Ended June 30, 2003				Six Months Ended June 30, 2003
	As Reported		As Restated		As Reported		As Restated
Depletion, Depreciation and Amortization	$	1,608,391	$	2,063,791	$	3,185,630	$	4,125,114
Income Taxes		652,028		492,638		954,657		625,836
Net Income		1,212,337		916,327		1,569,070		958,409
Income (Loss) Applicable to Common Stock		1,053,971		757,961		1,252,338		641,677
Basic Income (Loss) per Average Common Share		0.06		0.04		0.07		0.04
Diluted Income (Loss) per Average Common Share		0.05		0.04		0.06		0.03

9

The tax-adjusted cumulative effect of the error on non-cash depletion, depreciation and amortization expense in years prior to December 31, 2002 resulted in a reduction of stockholders’ equity as of January 1, 2003 in the amount of $2,199,077. The restatement adjustments had no impact on cash flow from operating, investing or financing activities.

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. 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. 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. For the six months ended June 30, 2004 and 2003, the Company recorded the following activity in the abandonment liability:

	Six Months Ended June 30,
	2004			2003
Beginning balance	$	6,601,186		$	6,289,065
Accretion of liability		155,752			189,000
Liability for newly added wells		230,925			64,000
Abandonment costs incurred or sold		—			(19,000	)
Ending balance		6,987,863			6,523,065
Less: current portion		(91,605	)		(125,000	)
	$	6,896,258		$	6,398,065

In July 2003, the FASB undertook to review whether leasehold interests in properties held by oil and gas companies should be recorded and disclosed as intangible assets under the guidance of SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets. Under SFAS No. 141

10

and SFAS No. 142, intangible assets should be separately reported on the Balance Sheet, with accompanying disclosures in the notes to the financial statements. SFAS No. 142 does not change the accounting prescribed in SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, and is silent about whether its disclosure provisions apply to oil and gas companies. The Company does not believe that SFAS No. 141 and SFAS No. 142 change the classification and disclosure of oil and gas mineral leases and it continues to classify these assets as part of Property and Equipment in the Consolidated Balance Sheet and it does not provide the additional disclosures for these assets. Should its oil and gas leases be reported as intangible assets, the Company would reclassify $10,104,000 and $6,409,000 as intangible undeveloped mineral interests at June 30, 2004 and December 31, 2003, respectively, and would reclassify $6,312,000 and $5,879,000 as intangible developed mineral interests at June 30, 2004 and December 31, 2003, respectively. Both intangible assets would be presented net of accumulated amortization. Historically, undeveloped oil and gas leases have been amortized over the life of the lease period, while developed leases have been amortized using the units of production method over the expected life of proved reserves. If oil and gas leases are deemed to be intangible assets in accordance with SFAS No. 141 and SFAS No. 142:

• These assets would not be included in Property and Equipment on the Consolidated Balance Sheet

• The Company does not believe that its net income or cash flows from operations would be materially affected because the amortization of these assets would not be different than the method currently used by the Company

• Disclosures required by SFAS No. 141 and SFAS No. 142 relative to intangible assets would be included in the notes to the financial statements

In March 2004, the FASB issued an exposure draft on accounting for stock-based compensation. The exposure draft reflects the FASB’s tentative conclusion that the fair value of stock options should be expensed in companies’ financial statements for years ending after December 31, 2004. The exposure draft also includes the FASB’s tentative decisions regarding how equity-based awards are likely to be valued, expensed, and classified. The Company will continue to monitor developments with respect to the exposure draft to determine the potential impact on its financial statements.

NOTE C – 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. In December 2003, the borrowing base was redetermined to be $28,000,000 and BNP Paribas and the Company agreed to extend the term of the senior credit facility to December 29, 2006, subject to periodic redeterminations of the borrowing base. The Company anticipates that the next borrowing base redetermination will be completed in the third quarter of 2004 once BNP Paribas evaluates production information on several recently completed oil and gas wells. Borrowings outstanding under the senior credit facility as of June 30, 2004 were $23,000,000.

Interest on borrowings under the senior credit facility accrue at a rate calculated, at the option of the Company, at either the BNP Paribas base rate plus 0.00% to 0.50%, or LIBOR plus 1.50%—2.50%, depending on borrowing base utilization. Interest on LIBOR-rate borrowings is due and payable on the last day of its respective interest period. Accrued interest on each base-rate borrowing is due and payable on the last day of each quarter. 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 June 30, 2004, the Company was in compliance with all such requirements. Substantially all the Company’s assets are pledged to secure the senior credit facility.

11

As indicated in Note D, the Company entered into three separate interest rate swaps with BNP Paribas in February 2003, covering a three year period commencing in February 2003, and in February 2004, the Company entered into another interest rate swap with BNP Paribas, covering a one year period commencing in February 2006.

NOTE D – Hedging Activities

The Company utilizes commodity hedges in the form of fixed price swaps, whereby the Company receives a fixed price and pays a floating price based on NYMEX quoted prices. As of June 30, 2004, 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

3,000 MMBtu per day “swap” at fixed price of $5.00 for July 2004 through December 2004;

3,000 MMBtu per day “swap” at fixed price of $5.41 for July 2004 through October 2004;

3,000 MMBtu per day “swap” at fixed price of $6.20 for November 2004 through December 2004; and

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

Crude Oil

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

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

500 barrels of oil per day “swap” at fixed price of $33.28 for January 2005 through March 2005

The fair value of the natural gas and oil hedging contracts in place at June 30, 2004, resulted in a liability of $2,671,120. As of June 30, 2004, $1,671,524 (net of $900,052 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, 2004, $1,821,876 in realized losses 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, 2004 and 2003, the Company’s earnings were not materially affected by cash flow hedging ineffectiveness arising from the oil and gas hedging contracts. Subsequent to June 30, 2004, the Company entered into the following crude oil hedging contracts with BNP Paribas:

500 barrels of oil per day “swap” at fixed price of $35.73 for January 2005 through March 2005; and

500 barrels of oil per day “swap” at fixed price of $35.00 for April 2005 through June 2005; and

500 barrels of oil per day “swap” at fixed price of $37.18 for April 2005 through June 2005; and

500 barrels of oil per day “swap” at fixed price of $34.65 for July 2005 through September 2005; and

500 barrels of oil per day “swap” at fixed price of $36.18 for July 2005 through September 2005; and

500 barrels of oil per day “swap” at fixed price of $34.50 for October 2005 through December 2005; and

250 barrels of oil per day “swap” at fixed price of $37.72 for October 2005 through December 2005

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 (one of the interest rate swaps has now expired). The first interest rate swap, which had an

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effective date of February 26, 2003, expired on its maturity date of February 26, 2004, and was 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%. In February 2004, the Company entered into a fourth interest rate swap contract with BNP Paribas, which has an effective date of February 26, 2006 and a maturity date of February 26, 2007, for $23,000,000 with a LIBOR swap rate of 4.08%. The fair value of the interest rate swap contracts in place at June 30, 2004, resulted in a liability of $71,076. As of June 30, 2004, $88,258 (net of $47,524 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, 2004, $58,570 of previously deferred losses was reclassified from accumulated other comprehensive income to interest expense as the cash flow of the hedged items was recognized. For the six months ended June 30, 2004 and 2003, the Company’s earnings were not significantly affected by cash flow hedging ineffectiveness of interest rates.

NOTE E – 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 six months ended June 30, 2004 and 2003. The following table reconciles the weighted-average shares outstanding used for these computations.

	Three Months Ended June 30,		Six Months Ended June 30,
	2004	2003	2004	2003
Basic Method	19,040,347	18,040,141	18,726,959	18,005,931
Dilutive Stock Warrants	1,705,576	2,241,297	1,691,086	2,171,070
Dilutive Stock Options and Restricted Stock	292,847	106,612	277,850	88,609
Diluted Method	21,038,770	20,388,050	20,695,895	20,265,610

The computation of earnings per share for the three months and six months ended June 30, 2004 and 2003 considered exercisable stock warrants, stock options and restricted share awards to the extent that the exercise of such securities would have been dilutive, however, such computation did not consider preferred stock which is convertible into shares of common stock because the effect of such conversion would have been antidilutive. In January and April 2004, the holders of 319,387 and 685,055 warrants to purchase common stock elected a cashless exercise of such warrants resulting in the issuance of 252,033 and 620,935 shares of the Company’s common stock, respectively. Subsequent to June 30, 2004, the holders of 1,365,085 warrants to purchase common stock elected a cashless exercise of such warrants resulting in the issuance of 1,236,201 shares of the Company’s common stock in July 2004 (see Note G).

In February 2003, the Company issued 125,157 shares of its common stock to employees holding 1,016,500 outstanding stock options in exchange for the cancellation of such options (at the time of cancellation, the options were antidilutive). Based on the value of the Company’s common stock at the time of the exchange, 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. At the same time, the Company commenced granting a series of restricted share awards, with three year vesting periods, to its employees under a stockholder approved equity compensation plan. Based on the value of the Company’s common stock at the time of the grants, those awards resulted in charges to a contra equity account and credits to additional paid-in capital in the following amounts:

• $483,000 for 150,000 restricted share awards granted in February 2003;

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• $54,000 for 11,500 restricted share awards granted in July and October 2003; and

• $1,134,000 for 166,300 restricted share awards granted in February 2004.

The charges to the contra equity account are being amortized to earnings as non-cash charges to general and administrative expenses over the three year vesting period of each restricted share award and resulted in non-cash charges to earnings of $67,000 in the six months ended June 30, 2003 and $268,000 in the six months ended June 30, 2004. In the six months ended June 30, 2004, the Company recorded a credit to the contra equity account and a charge to additional paid-in capital in the amount of $123,000 for the value of 22,918 non-vested restricted share awards that were forfeited by terminated employees. The amortization to earnings of restricted share awards has been adjusted to reflect such forfeitures. Assuming no additional restricted share awards or forfeitures, the Company will be required to record recurring non-cash charges to earnings of approximately $130,000 per quarter, related to the periodic vesting of the restricted share awards that have been issued to date.

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 months and six months ended June 30, 2004 and 2003 would have been reduced to the pro forma amounts indicated below.

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
				(Restated)						(Restated)
Net income
As reported	$	2,890,054		$	916,327		$	5,014,491		$	958,409
Restricted stock compensation expense included in net income, net of tax		130,122			40,249			267,760			67,083
Stock based compensation expense at fair value, net of tax		(131,857	)		(45,367	)		(271,229	)		(77,320	)
Pro forma	$	2,888,319		$	911,209		$	5,011,022		$	948,172
Net income applicable to common stock
As reported	$	2,731,851		$	757,961		$	4,697,922		$	641,677
Restricted stock compensation expense included in net income, net of tax		130,122			40,249			267,760			67,083
Stock based compensation expense at fair value, net of tax		(131,857	)		(45,367	)		(271,229	)		(77,320	)
Pro forma	$	2,730,116		$	752,843		$	4,694,453		$	631,440
Net income per share
As reported, basic	$	0.15		$	0.05		$	0.27		$	0.05
Pro forma, basic		0.15			0.05			0.27			0.05
As reported, diluted		0.14			0.05			0.24			0.05
Pro forma, diluted		0.14			0.04			0.24			0.05

NOTE F – 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

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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, 2004, the Company had paid $321,000 in costs related to this matter and accrued $122,500 for the remaining liability. These costs have not been discounted to their present value. The EPA and the PRPs will continue to evaluate the site and revise estimates for the long-term clean-up of the site. There can be no assurance that the cost of clean-up and the Company’s percentage responsibility will not be higher than currently estimated. In addition, under the federal environmental laws, the liability costs for the clean-up of the site is joint and several among all PRPs. Therefore, the ultimate cost of the clean-up to the Company could be significantly higher than the amount presently estimated or accrued for this liability.

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

On February 8, 2000, the Company commenced a suit against the operator and joint owner of the Lafitte field, alleging certain items of misconduct and violations of the agreements associated primarily with the joint acquisition of and unfettered access to a license to 3-D seismic data over the field. The operator counter-claimed against Goodrich on the grounds that Goodrich was obligated to post a bond to secure the plugging and abandonment obligations in the field. On November 1, 2002 the 125th 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 monetary damages as well as recovery of attorneys’ fees. On May 28, 2004, the trial court ordered a final judgment which awarded the Company a net sum of approximately $2,065,000 as follows:

1. $538,000 in damages;

2. $1,515,000 in recovery of plaintiff’s attorneys’ fees; and

3. Pre-judgment interest of approximately $115,000, which was calculated on the damages at a rate of 5%, per annum, compounded annually, from the date of the filing of the lawsuit on February 8, 2000 through May 27, 2004, the day preceding the date of the final judgment.

The trial court also ordered the Company to pay $103,000 to the operator in recovery of defendant’s attorneys’ fees, reducing the Company’s net amount awarded to approximately $2,065,000. Either party may appeal the final judgment or file a motion for a new trial within ninety days from the date of the final judgment, therefore, the Company has not recognized the effect of the judgment in its financial statements. The timing of the decision regarding appeal or a motion for a new trial is presently uncertain, however, the Company does not anticipate that the result of such a decision will ultimately have a significant adverse impact on the Company’s operations or financial position.

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

NOTE G – Funds Held Temporarily for Stockholders

Pursuant to a May 2003 stock purchase agreement, the Company acted as agent for certain stockholders to facilitate a sale of shares in three installments in January 2004, April 2004, and July 2004. In that capacity, the Company temporarily received funds totaling $3,886,988 from the purchasing stockholders in December 2003, which are reflected on the Company’s December 31, 2003 balance sheet in both cash and current liabilities. In accordance with the stock purchase agreement, the Company transferred the funds to the selling stockholders in January 2004 upon the sale of the shares. Similarly, the Company temporarily received additional funds for the final installment sale totaling $389,813 from the purchasing stockholders in June 2004, which are reflected on the Company’s June 30, 2004 balance sheet in both cash and current liabilities. In accordance with the stock purchase agreement, the Company transferred the funds to the selling stockholders in July 2004 upon the sale of the shares. A portion of the shares of common stock sold by the selling stockholders in January 2004, April 2004, and July 2004 resulted from the cashless exercise of warrants to purchase common stock (see Note E).

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Item 2. 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, 2003 includes a description of the Company’s critical accounting policies, estimates and other information that should be referred to in conjunction with the following discussion.

Changes in Results of Operations

Three months ended June 30, 2004 versus three months ended June 30, 2003

Total revenues for the three months ended June 30, 2004 amounted to $9,366,000 compared to $7,883,000 for the three months ended June 30, 2003. Oil and gas sales for the three months ended June 30, 2004 were $9,351,000 compared to $7,824,000 for the three months ended June 30, 2003. This increase resulted from a 23% increase in oil and gas production volumes, due to several successful well completions since the first quarter of 2003, partially offset by higher hedge settlement payments. Additionally, oil and gas revenues include sales of natural gas liquids in the amount of $608,000 in the three months ended June 30, 2004 compared to $86,000 in the three months ended June 30, 2003, resulting from processing a portion of the Company’s natural gas production beginning in May 2003. The following table presents the production volumes and pricing information for the comparative periods, with the average oil and gas prices 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, 2004			Three Months Ended June 30, 2003
	Production	Average Price		Production	Average Price
Gas (Mcf)	1,020,746	$	5.88	748,113	$	6.16
Oil (Bbls)	109,360	$	25.07	102,859	$	31.30

Other revenues for the three months ended June 30, 2004 were $16,000 compared to $58,000 for the three months ended June 30, 2003, with the decrease primarily due to a reduction in interest income.

Lease operating expense was $1,643,000 for the three months ended June 30, 2004 versus $1,511,000 for the three months ended June 30, 2003, resulting from having a larger number of producing wells. Production taxes were $594,000 in the three months ended June 30, 2004 compared to $516,000 in the second quarter of 2003, due to higher oil and gas sales in the 2004 period. Depletion, depreciation and amortization expense was $2,480,000 for the three months ended June 30, 2004 versus $2,064,000 for the three months ended June 30, 2003, with the increase due to higher equivalent units of production, and higher depletion rates. Exploration expense in the three months ended June 30, 2004 was $1,080,000, primarily reflecting seismic costs in the Plumb Bob field, compared to $891,000 in the three months ended June 30, 2003, which largely consisted of dry hole cost.

General and administrative expenses amounted to $1,327,000 in the three months ended June 30, 2004 versus $1,089,000 in the second quarter of 2003. The most significant factor in this variance resulted from an increase in the Company’s payroll and employee benefits expense to $742,000 in the three months ended June 30, 2004 from $521,000 in the three months ended June 30, 2003, primarily due to an increase in the number of employees. Additionally non-cash charges for employee equity compensation programs increased to $133,000 in the second quarter of 2004 from $40,000 in the second quarter of 2003. Partially offsetting these increases were relatively small net decreases in other administrative expenses.

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Interest expense was $254,000 in the three months ended June 30, 2004 compared to $186,000 in the second quarter of 2003, with the increase primarily attributable to a higher level of borrowings in the second quarter of 2004.

Income taxes were a benefit of $961,000 in the three months ended June 30, 2004 compared to an expense of $493,000 in the three months ended June 30, 2003. The Company revised its deferred tax valuation allowance in the second quarter of 2004 in the amount of $1,636,000, based on the anticipated reversal of temporary differences, whereas in the three months ended June 30, 2003 income tax expense represented 35% of pre-tax income.

Six months ended June 30, 2004 versus six months ended June 30, 2003

Total revenues for the six months ended June 30, 2004 amounted to $20,292,000 compared to $14,961,000 for the six months ended June 30, 2003. Oil and gas sales for the six months ended June 30, 2004 were $20,177,000 compared to $14,572,000 for the six months ended June 30, 2003. This increase resulted from a 26% increase in oil and gas production volumes, due to several successful well completions since the first quarter of 2003, as well as a small increase in average gas prices. Additionally, oil and gas revenues include sales of natural gas liquids in the amount of $839,000 in the six months ended June 30, 2004 compared to $86,000 in the six months ended June 30, 2003, resulting from processing a portion of the Company’s natural gas production beginning in May 2003. The following table presents the production volumes and pricing information for the comparative periods, with the average oil and gas prices 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, 2004			Six Months Ended June 30, 2003
	Production	Average Price		Production	Average Price
Gas (Mcf)	2,018,188	$	5.87	1,479,142	$	5.23
Oil (Bbls)	245,391	$	30.55	213,625	$	31.98

Other revenues for the six months ended June 30, 2004 were $114,000 compared to $390,000 for the six months ended June 30, 2003, with the decrease of $276,000 primarily due to the absence of prospect fees received on two drilling prospects in the first quarter of 2003.

Lease operating expense was $3,191,000 for the six months ended June 30, 2004 versus $3,268,000 for the six months ended June 30, 2003, with the decrease largely due to the Company’s ongoing efforts to reduce costs on its operated properties notwithstanding an increase in the number of producing wells. Production taxes were $1,289,000 in the six months ended June 30, 2004 compared to $1,047,000 in the six months ended June 30, 2003, due to higher oil and gas sales in the 2004 period. Depletion, depreciation and amortization expense was $5,234,000 for the six months ended June 30, 2004 versus $4,125,000 for the six months ended June 30, 2003, with the increase due to higher equivalent units of production, and higher depletion rates. Exploration expense in the six months ended June 30, 2004 was $2,017,000, primarily reflecting seismic costs in the Plumb Bob field, compared to $1,445,000 in the six months ended June 30, 2003, which largely consisted of two exploratory dry holes.

General and administrative expenses amounted to $2,833,000 in the six months ended June 30, 2004 versus $2,627,000 in the six months ended June 30, 2003. The most significant factor in this variance resulted from an increase in the Company’s payroll and employee benefits expense to $1,425,000 in the six months ended

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June 30, 2004 from $948,000 in the six months ended June 30, 2003, primarily due to an increase in the number of employees. Partially offsetting this increase was a decrease in non-cash charges for employee equity compensation programs to $268,000 in the six months ended June 30, 2004 from $470,000 in the six months ended June 30, 2003. In the 2004 period, these non-cash charges consisted solely of vesting of restricted stock grants in the amount of $268,000, whereas in the 2003 period, such amounts included 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 $67,000 related to the vesting of restricted stock grants.

Interest expense was $471,000 in the six months ended June 30, 2004 compared to $422,000 in the six months ended June 30, 2003, with the increase primarily attributable to a higher level of borrowings in the 2004 period.

Income tax expense was $183,000 in the six months ended June 30, 2004 compared to $626,000 in the six months ended June 30, 2003. The Company revised its deferred tax valuation allowance in the second quarter of 2004 in the amount of $1,636,000, based on the anticipated reversal of temporary differences, whereas in the six months ended June 30, 2003 income tax expense represented 35% of pre-tax income.

Liquidity and Capital Resources

Net cash provided by operating activities was $13,651,000 in the six months ended June 30, 2004, compared to $6,199,000 in the six months ended June 30, 2003. The increase in the 2004 period reflects higher oil and gas revenues and lower lease operating expenses, partially offset by an increase in exploration expenses. The operating cash flow amounts are net of changes in working capital, which resulted in an increase in operating cash flow of $2,533,000 in the six months ended June 30, 2004, compared to a decrease of $1,613,000 in the six months ended June 30, 2003.

Net cash used in investing activities was $16,387,000 in the six months ended June 30, 2004, compared to $10,389,000 in the six months ended June 30, 2003. In the six months ended June 30, 2004 capital expenditures totaled $16,387,000, as the Company participated in the drilling of two successful exploratory wells in the Burrwood/West Delta 83 field and incurred substantial drilling and leasehold acquisition costs in East Texas (see “Cotton Valley Drilling Program”). In the six months ended June 30, 2003, capital expenditures totaled $10,672,000 and were partially offset by the sale of the Company’s interest in the South Drew field resulting in proceeds of $284,000.

Net cash provided by financing activities was $2,643,000 in the six months ended June 30, 2004, compared to $975,000 in the six months ended June 30, 2003. In the six months ended June 30, 2004, net borrowings under the Company’s senior credit facility provided cash of $3,000,000 and exercises of stock warrants provided cash of $123,000, while preferred stock dividends and production payments used cash of $480,000. In the six months ended June 30, 2003, net borrowings under the Company’s senior credit facility provided cash of $1,500,000 and exercises of stock warrants provided cash of $10,000, while preferred stock dividends and production payments used cash of $535,000.

In July 2004, the Company announced that its Board of Directors had approved an increase in the Company’s 2004 capital expenditure budget from $25 million up to $45 million. The Board approved the increase in order to accelerate the development of the Company’s acreage in the Cotton Valley trend of East Texas and Northwest Louisiana (see “Cotton Valley Drilling Program”) and due to the Company’s improving projections for cash flow from operations. The Company expects to finance its 2004 capital expenditures through a combination of cash flow from operations and borrowings under existing and, possibly, expanded bank credit facilities (see “Senior Credit Facility”). Approximately two-thirds of the 2004 capital expenditure budget has been designated for exploration and development drilling activities in the Cotton Valley trend.

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Cotton Valley Drilling Program

In the first quarter of 2004, the Company commenced what it believes is a relatively low risk drilling initiative which is focused on the Cotton Valley trend in the East Texas Basin in and around Rusk, Panola and Smith Counties, Texas, and DeSoto and Caddo Parishes, Louisiana. As of July 31, 2004, the Company had acquired leases totaling approximately 40,000 gross acres, with an average working interest of approximately 80%, and is attempting to acquire additional acreage in the area. The Company has drilled a total of four operated wells targeting the Cotton Valley formation and presently has two drillings rigs under contract in the East Texas/Northwest Louisiana area and anticipates the possibility of adding a third rig in the second half of 2004.

In East Texas, the Company commenced a drilling program in April 2004 and has drilled a total of three successful wells targeting the Cotton Valley formation. Two of the drilled wells, in which the Company has a 100% working interest, have been completed and placed on production and a third well, in which the Company has an 85% working interest, has been logged and is awaiting completion operations. Additionally, the Company has a 40% working interest in an adjacent East Texas exploratory well which has been drilled by another operator and is presently awaiting further evaluation.

In Northwest Louisiana, the Company commenced a drilling program targeting the Cotton Valley formation in the first quarter of 2004 and has successfully completed one well, which is awaiting a gas meter installation, and is presently drilling another well. The Company’s initiative in this area began in the third quarter of 2003, when it obtained, via farmout, exploration rights to approximately 18,000 acres in the Bethany-Longstreet field (excluding the Crane zone of the Pettit formation). 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 began exploration and development drilling activities in the field and completed three successful wells in the Hosston formation in the fourth quarter of 2003. The Company has a 70% working interest in the five Bethany-Longstreet wells drilled (or drilling) to date and anticipates that its working interests in the additional wells to be drilled in the field will range between 50% and 70%.

South Louisiana Operations

Burrwood/West Delta 83 Fields

In the second quarter of 2004, the Company successfully completed two exploratory wells in the Burrwood/West Delta 83 fields in Plaquemines Parish, Louisiana. The first well was the Company’s initial Dempsey Prospect well, in which it has a 70% working interest. This well is now online and the current gross production is approximately 8,000 Mcf of gas per day and 350 barrels of oil per day. The second well was the Company’s initial Norton Prospect well, in which it has a 65% working interest. This well is now online and the current gross production is approximately 420 barrels of oil per day and 650 Mcf of gas per day. The Company is currently drilling a sidetrack well to one of its other existing producing wells in the field, in which it has a 65% working interest.

Plumb Bob Field

In the third quarter of 2003, the Company obtained certain rights in the Plumb Bob field located in St. Martin Parish, 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 identified recompletion projects, and the rights to acquire related production facilities and pipelines upon establishment of production. In the fourth quarter of 2003, the Company began workover drilling activities in the field and restored production capability in three wells. In the fourth quarter of 2003,

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the Company also commenced a 32 square mile 3-D seismic survey which was completed in the second quarter of 2004. Processing and evaluation of the seismic data will take place in the second half of 2004. Based on the evaluation of the seismic data, the Company will determine the extent of its drilling and remaining workover plans in the field.

St. Gabriel Field

In July 2004, the Company announced that it has entered into 3-D seismic permits and oil and gas lease options to acquire an approximate 30 square mile 3-D seismic survey over the St. Gabriel field in Ascension and Iberville Parishes, Louisiana. The Company commenced shooting the 3-D seismic survey in July 2004 and expects to receive the processed data by the end of the year. The Company has an approximate 70% working interest in the project and has budgeted approximately $1.75 million for the acquisition of the rights and the 3-D seismic survey. Post 3-D development drilling activities are not expected to occur prior to 2005.

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. In December 2003, the borrowing base was redetermined to be $28,000,000 and BNP Paribas and the Company agreed to extend the term of the senior credit facility to December 29, 2006, subject to periodic redeterminations of the borrowing base. The Company anticipates that the next borrowing base redetermination will be completed in the third quarter of 2004 once BNP Paribas evaluates production information on several recently completed oil and gas wells. Borrowings outstanding under the senior credit facility were $23,000,000 as of June 30, 2004 and $24,000,000 as of August 10, 2004 and the Company expects to have continuing liquidity to meet its working capital needs and capital expenditures. The Company has also entered into a non-binding agreement for a subordinated bank credit facility that would be available to finance the increased capital expenditures related to development of the Company’s acreage in the Cotton Valley trend (see “Liquidity and Capital Resources”).

Interest on borrowings under the existing 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. As of June 30, 2004, 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 commencing in February 2003, and in February 2004, the Company entered into a fourth interest rate swap with BNP Paribas, covering a one year period commencing in February 2006 (see “Quantitative and Qualitative Disclosures About Market Risk – Debt and debt-related derivatives”).

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

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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. 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. 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 July 2003, the FASB undertook to review whether leasehold interests in properties held by oil and gas companies should be recorded and disclosed as intangible assets under the guidance of SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets. Under SFAS No. 141 and SFAS No. 142, intangible assets should be separately reported on the Balance Sheet, with accompanying disclosures in the notes to the financial statements. SFAS No. 142 does not change the accounting prescribed in SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, and is silent about whether its disclosure provisions apply to oil and gas companies. The Company does not believe that SFAS No. 141 and SFAS No. 142 change the classification and disclosure of oil and gas mineral leases and it continues to classify these assets as part of Property and Equipment in the Consolidated Balance Sheet and it does not provide the additional disclosures for these assets. Should its oil and gas leases be reported as intangible assets, the Company would reclassify $10,104,000 and $6,409,000 as intangible undeveloped mineral interests at June 30, 2004 and December 31, 2003, respectively, and would reclassify $6,312,000 and $5,879,000 as intangible developed mineral interests at June 30, 2004 and December 31, 2003, respectively. Both intangible assets would be presented net of accumulated amortization. Historically, undeveloped oil and gas leases have been amortized over the life of the lease period, while developed leases have been amortized using the units of production method over the expected life of proved reserves. If oil and gas leases are deemed to be intangible assets in accordance with SFAS No. 141 and SFAS No. 142:

• These assets would not be included in Property and Equipment on the Consolidated Balance Sheet

• The Company does not believe that its net income or cash flows from operations would be materially affected because the amortization of these assets would not be different than the method currently used by the Company

• Disclosures required by SFAS No. 141 and SFAS No. 142 relative to intangible assets would be included in the notes to the financial statements

In March 2004, the FASB issued an exposure draft on accounting for stock-based compensation. The exposure draft reflects the FASB’s tentative conclusion that the fair value of stock options should be expensed in companies’ financial statements for years ending after December 31, 2004. The exposure draft also includes the FASB’s tentative decisions regarding how equity-based awards are likely to be valued, expensed, and classified. The Company will continue to monitor developments with respect to the exposure draft to determine the potential impact on its financial statements.

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Item 3. 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. As of June 30, 2004, all of the commodity hedges utilized by the Company were in the form of fixed price swaps, where the Company receives a fixed price and pays a floating price based on NYMEX quoted prices. The basis risk for the pricing differentials between the points the Company sells its production and the NYMEX locations is not hedged. Changes in the basis during the term of a hedge may cause ineffectiveness of the hedge. As of June 30, 2004, the Company’s open forward position on its outstanding commodity hedging contracts, all of which were with BNP Paribas, was as follows:

Natural Gas

3,000 MMBtu per day “swap” at fixed price of $5.00 for July 2004 through December 2004;

3,000 MMBtu per day “swap” at fixed price of $5.41 for July 2004 through October 2004;

3,000 MMBtu per day “swap” at fixed price of $6.20 for November 2004 through December 2004; and

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

Crude Oil

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

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

500 barrels of oil per day “swap” at fixed price of $33.28 for January 2005 through March 2005

The fair value of the natural gas and oil hedging contracts in place at June 30, 2004, resulted in a liability of $2,671,000. Based on oil and gas pricing in effect at June 30, 2004, a hypothetical 10% increase in oil and gas prices would have increased the liability to $4,546,000 while a hypothetical 10% decrease in oil and gas prices would have decreased the liability to $796,000. Subsequent to June 30, 2004, the Company entered into the following crude oil hedging contracts with BNP Paribas:

500 barrels of oil per day “swap” at fixed price of $35.73 for January 2005 through March 2005; and

500 barrels of oil per day “swap” at fixed price of $35.00 for April 2005 through June 2005; and

500 barrels of oil per day “swap” at fixed price of $37.18 for April 2005 through June 2005; and

500 barrels of oil per day “swap” at fixed price of $34.65 for July 2005 through September 2005; and

500 barrels of oil per day “swap” at fixed price of $36.18 for July 2005 through September 2005; and

500 barrels of oil per day “swap” at fixed price of $34.50 for October 2005 through December 2005; and

250 barrels of oil per day “swap” at fixed price of $37.72 for October 2005 through December 2005

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 (one of the interest rate swaps has now expired). The first interest rate swap, which had an effective date of February 26, 2003, expired on its maturity date of February 26, 2004, and was for $18,000,000 with a LIBOR swap rate of 1.53%. The second interest rate swap, which has an effective date of

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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%. In February 2004, the Company entered into a fourth interest rate swap contract with BNP Paribas, which has an effective date of February 26, 2006 and a maturity date of February 26, 2007, for $23,000,000 with a LIBOR swap rate of 4.08%. The fair value of the interest rate swap contracts in place at June 30, 2004, resulted in a liability of $71,000. Based on interest rates in effect at June 30, 2004, a hypothetical 10% increase or decrease in interest rates would not have a material effect on the liability.

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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Item 4. 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, 2004, 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 June 30, 2004 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.

Except for changes implemented by the Company to correct the material weakness in internal controls reported in the Company’s Annual Report on Form 10-K for the year ended December, 31, 2003, 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.

See Note F to Consolidated Financial Statements

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 8, 2004. 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 III Directors

	FOR	WITHHELD
Walter G. Goodrich	17,215,328	303,269
John T. Callaghan	17,261,577	257,020
Arthur A. Seeligson	17,249,429	269,168

Approval of amendments to the Company’s 1997 Nonemployee Directors Stock Option Plan

FOR	AGAINST	NON VOTE / WITHHELD
11,859,534	459,164	5,199,899

Ratification of the appointment of KPMG LLP as the Company’s independent auditors for 2004

FOR	AGAINST	WITHHELD
17,463,350	21,906	33,341

Item 5. Other Information.

Not applicable

Item 6. Exhibits and Reports on Form 8-K.

(a) Exhibits

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.
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.

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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.
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 April 16, 2004, the Company filed a Form 8-K report containing its Year-End 2003 Earnings Release.
	On May 17, 2004, the Company filed a Form 8-K report containing its First Quarter 2004 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)
August 11, 2004 Date	/s/ Walter G. Goodrich Walter G. Goodrich, Vice Chairman & Chief Executive Officer
August 11, 2004 Date	/s/ D. Hughes Watler, Jr D. Hughes Watler, Jr., Senior Vice President & Chief Financial Officer

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