(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~~November, 10, 2004, there were ~~20,380,885~~20,509,935 shares of Goodrich Petroleum Corporation common stock outstanding.


	June 30, 2004			December 31, 2003			September 30, 2004			December 31, 2003
	(unaudited)						(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	1,395,339		$	1,488,852		$	1,760,577		$	1,488,852
Cash held temporarily for stockholders		389,813			3,886,988			—			3,886,988
Accounts receivable
Trade and other, net of allowance		6,281,299			3,500,095			9,307,489			3,500,095
Accrued oil and gas revenue		2,576,976			2,829,082			2,594,019			2,829,082
Prepaid insurance and other		469,694			351,527			815,146			351,527

Total current assets		11,113,121			12,056,544			14,477,231			12,056,544

PROPERTY AND EQUIPMENT
Oil and gas properties (successful efforts method)		135,246,650			118,682,309			147,480,323			118,682,309
Furniture, fixtures and equipment		737,233			661,842			789,321			661,842

		135,983,883			119,344,151			148,269,644			119,344,151

Less accumulated depletion, depreciation and amortization		(49,822,466	)		(44,381,223	)		(53,000,150	)		(44,381,223	)

Net property and equipment		86,161,417			74,962,928			95,269,494			74,962,928

OTHER ASSETS
Restricted cash		2,039,000			2,039,000			2,039,000			2,039,000
Deferred taxes								1,750,000			—
Other		100,757			124,096			89,087			124,096

Total other assets		2,139,757			2,163,096			3,878,087			2,163,096

TOTAL ASSETS	$	99,414,295		$	89,182,568		$	113,624,812		$	89,182,568


	June 30, 2004			December 31, 2003			September 30, 2004			December 31, 2003
	(unaudited)						(unaudited)
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
Accounts payable	$	11,851,647		$	6,707,583		$	15,278,732		$	6,707,583
Accrued liabilities		1,519,917			1,483,329			4,048,385			1,483,329
Liability for funds held temporarily for stockholders		389,813			3,886,988			—			3,886,988
Fair value of oil and gas derivatives		2,671,120			1,257,442			6,684,610			1,257,442
Fair value of interest rate derivatives		71,076			277,938			147,236			142,515
Current portion of other non-current liabilities		91,605			91,600			91,605			91,600

Total current liabilities		16,595,178			13,704,880			26,250,568			13,569,457

LONG TERM DEBT		23,000,000			20,000,000			25,500,000			20,000,000

OTHER NON-CURRENT LIABILITIES
Production payment payable and other		495,012			704,643			427,468			704,643
Accrued abandonment costs		6,896,258			6,509,586			6,921,833			6,509,586
Fair value of oil and gas derivatives								961,485			—
Fair value of interest rate derivatives								154,266			135,423
Deferred taxes		—			204,465			—			204,465

Total liabilities		46,986,448			41,123,574			60,215,620			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			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
Common stock, par value $0.20 per share; authorized 50,000,000 shares; issued and outstanding 20,433,145 and 18,130,011 shares								4,086,629			3,626,002
Additional paid-in capital		54,292,714			53,359,023			54,253,303			53,359,023
Accumulated deficit		(3,640,481	)		(8,338,403	)
Retained earnings (deficit)								538,709			(8,338,403	)
Unamortized restricted stock awards		(1,124,954	)		(381,598	)		(1,160,183	)		(381,598	)
Accumulated other comprehensive income		(1,717,724	)		(997,998	)		(5,101,234	)		(997,998	)

Total stockholders’ equity		52,427,847			48,058,994			53,409,192			48,058,994

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	99,414,295		$	89,182,568		$	113,624,812		$	89,182,568


	Three Months Ended June 30,						Three Months Ended September 30,
	2004			2003			2004		2003
				(restated)					(restated)
REVENUES
Oil and gas revenues	$	9,350,878		$	7,824,380		$	12,152,085	$	7,979,339
Other		15,579			58,360			30,387		15,419

Total revenues		9,366,457			7,882,740			12,182,472		7,994,758

EXPENSES
Lease operating expense		1,642,560			1,511,104			1,887,265		1,290,878
Production taxes		593,929			515,959			889,324		566,864
Depletion, depreciation and amortization		2,480,350			2,063,791			3,219,746		2,186,782
Exploration		1,079,978			891,481			1,864,640		384,501
General and administrative		1,327,377			1,088,901			1,640,513		1,365,446
Interest expense		254,211			186,354			317,447		324,148

Total expenses		7,378,405			6,257,590			9,818,935		6,118,619

LOSS ON SALE OF ASSETS		(58,845	)		(216,185	)
GAIN (LOSS) ON SALE OF ASSETS AND LITIGATION JUDGMENT								2,045,748		8,438

INCOME BEFORE INCOME TAXES		1,929,207			1,408,965			4,409,285		1,884,577
Income taxes		(960,847	)		492,638			71,891		659,601

NET INCOME		2,890,054			916,327			4,337,394		1,224,976
Preferred stock dividends		158,203			158,366			158,201		158,366

NET INCOME APPLICABLE TO COMMON STOCK	$	2,731,851		$	757,961		$	4,179,193	$	1,066,610

NET INCOME PER SHARE - BASIC
NET INCOME	$	0.15		$	0.05		$	0.21	$	0.07

NET INCOME APPLICABLE TO COMMON STOCK	$	0.14		$	0.04		$	0.21	$	0.06

NET INCOME PER SHARE - DILUTED
NET INCOME	$	0.14		$	0.04		$	0.21	$	0.06

NET INCOME APPLICABLE TO COMMON STOCK	$	0.13		$	0.04		$	0.20	$	0.05

AVERAGE COMMON SHARES OUTSTANDING - BASIC		19,040,347			18,040,141			20,221,358		18,113,947
AVERAGE COMMON SHARES OUTSTANDING - DILUTED		21,038,770			20,388,050			21,091,390		20,587,056


	Six Months Ended June 30,						Nine Months Ended September 30,
	2004			2003			2004		2003
				(restated)					(restated)
REVENUES
Oil and gas revenues	$	20,177,404		$	14,571,663		$	32,329,489	$	22,551,001
Other		114,318			389,557			144,705		404,976

Total revenues		20,291,722			14,961,220			32,474,194		22,955,977

EXPENSES
Lease operating expense		3,191,378			3,268,289			5,078,643		4,559,167
Production taxes		1,289,001			1,046,863			2,178,325		1,613,727
Depletion, depreciation and amortization		5,234,197			4,125,114			8,453,944		6,311,896
Exploration		2,016,803			1,444,953			3,881,443		1,829,454
General and administrative		2,832,783			2,627,345			4,473,296		3,992,792
Interest expense		471,143			421,851			788,590		745,999

Total expenses		15,035,305			12,934,415			24,854,241		19,053,035

LOSS ON SALE OF ASSETS		(58,845	)		(237,267	)
GAIN (LOSS) ON SALE OF ASSETS AND LITIGATION JUDGMENT								1,986,903		(228,829	)

INCOME BEFORE INCOME TAXES		5,197,572			1,789,538			9,606,856		3,674,113
Income taxes		183,081			625,836			254,974		1,285,435

NET INCOME BEFORE CUMULATIVE EFFECT		5,014,491			1,163,702			9,351,882		2,388,678
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE NET OF TAX		—			(205,293	)		—		(205,293	)

NET INCOME		5,014,491			958,409			9,351,882		2,183,385
Preferred stock dividends		316,569			316,732			474,770		475,098

NET INCOME APPLICABLE TO COMMON STOCK	$	4,697,922		$	641,677		$	8,877,112	$	1,708,287

NET INCOME PER SHARE - BASIC
NET INCOME BEFORE CUMULATIVE EFFECT	$	0.27		$	0.06		$	0.49	$	0.13
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING		—			(0.01	)		—		(0.01	)

NET INCOME	$	0.27		$	0.05		$	0.49	$	0.12

NET INCOME APPLICABLE TO COMMON STOCK	$	0.25		$	0.04		$	0.46	$	0.09

NET INCOME PER SHARE - DILUTED
NET INCOME BEFORE CUMULATIVE EFFECT	$	0.24		$	0.06		$	0.47	$	0.12
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING		—			(0.01	)		—		(0.01	)

NET INCOME	$	0.24		$	0.05		$	0.47	$	0.11

NET INCOME APPLICABLE TO COMMON STOCK	$	0.23		$	0.03		$	0.44	$	0.08

AVERAGE COMMON SHARES OUTSTANDING - BASIC		18,726,959			18,005,931			19,228,728		18,042,332
AVERAGE COMMON SHARES OUTSTANDING - DILUTED		20,695,895			20,265,610			20,044,793		20,363,832


	Six Months Ended June 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
				(restated)						(restated)
OPERATING ACTIVITIES
Net income	$	5,014,491		$	958,409		$	9,351,882		$	2,183,385
Adjustments to reconcile net income to cash provided by operating activities
Adjustments to reconcile net income to cash provided by operating activities:
Depletion, depreciation and amortization		5,234,197			4,125,114			8,453,944			6,311,896
Deferred income taxes		183,081			515,292			254,974			1,174,893
Dry hole costs		—			675,000			—			809,249
Amortization of leasehold costs		537,808			267,334			1,013,482			361,863
Non-cash charge for stock issued for cancelled options		—			403,006			—			403,006
Cumulative effect of change in accounting principle		—			315,835			—			315,835
Loss on sale of assets		58,845			237,267			63,097			228,829
Other non-cash items		89,005			313,974
Other items, net								(129,860	)		364,622
Net change in:
Accounts receivable		(2,529,098	)		(1,440,925	)		(5,572,331	)		(2,290,967	)
Prepaid insurance and other		(118,167	)		(85,155	)		(463,619	)		(499,417	)
Accounts payable		5,144,064			(105,213	)		8,571,149			982,790
Accrued liabilities		36,588			18,642			2,565,056			523,271

Net cash provided by operating activities		13,650,814			6,198,580			24,107,774			10,869,255

INVESTING ACTIVITIES
Capital expenditures		(16,387,300	)		(10,672,182	)		(28,808,528	)		(15,371,275	)
Proceeds from sale of assets		—			283,561			8,895			341,176

Net cash used in investing activities		(16,387,300	)		(10,388,621	)		(28,799,633	)		(15,030,099	)

FINANCING ACTIVITIES
Principal payments of bank borrowings		(1,000,000	)		—			(1,000,000	)		—
Proceeds from bank borrowings		4,000,000			1,500,000			6,500,000			3,100,000
Exercise of stock warrants		122,897			10,000
Exercise of stock options and warrants								169,251			122,324
Production payments		(163,355	)		(218,087	)		(230,897	)		(307,411	)
Preferred stock dividends		(316,569	)		(316,732	)		(474,770	)		(475,098	)

Net cash provided by financing activities		2,642,973			975,181			4,963,584			2,439,815

NET DECREASE IN CASH AND CASH EQUIVALENTS		(93,513	)		(3,214,860	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS								271,725			(1,721,029	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD		1,488,852			3,351,380			1,488,852			3,351,380

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	1,395,339		$	136,520		$	1,760,577		$	1,630,351


	Series A Preferred Stock			Common Stock			Additional Paid - In Capital			Accumulated Deficit			Unamortized Restricted Stock Awards			Accumulated Other Comprehensive Income				Total Stockholders’ Equity			Series A Preferred Stock					Common Stock					Additional Paid – In Capital			Retained Earnings (Deficit)				Unamortized Restricted Stock Awards			Accumulated Other Comprehensive Income				Total Stockholders’ Equity
	Shares	Amount		Shares	Amount		Additional Paid - In Capital									Accumulated Other Comprehensive Income			Shares	Total Stockholders’ Equity			Amount			Shares		Amount								Retained Earnings (Deficit)				Unamortized Restricted Stock Awards			Accumulated Other Comprehensive Income				Total Stockholders’ Equity
										Accumulated Deficit	(Restated)										(Restated)												Additional Paid – In Capital						(Restated)											(Restated)
Balance at December 31, 2002	791,968	$	791,968	17,914,325	$	3,582,864	$	52,333,738		$	(11,422,436	)	Unamortized Restricted Stock Awards	$	—		$	(679,094	)		$	44,607,040		791,968		$	791,968		17,914,325		$	3,582,864		$	52,333,738		$	(11,422,436	)		$	—		$	(679,095	)		$	44,607,039
Net Income	—		—	—		—		—			958,409			—			—				958,409		—			—		—			—			—			2,183,385				—			—				2,183,385
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	)	—			—		—			—			—			—				—			(1,271,238	)			(1,271,238	)
Reclassification Adjustment	—		—	—		—		—			—			—			1,880,446				1,880,446		—			—		—			—			—			—				—			1,634,006				1,634,006

Total Comprehensive Income																					4,294,765																											2,546,153
Issuance and Amortization of Restricted Stock	—		—	4,331		866		1,010,250			—			(743,356	)		—				267,760		—			—		—			—			517,650			—				(407,428	)		—				110,222
Exercise of Stock Warrants	—		—	997,279		199,456		(76,559	)		—			—			—				122,897
Issuance of Common Stock																							—			—		125,157			25,032			377,974			—				—			—				403,006
Exercise of Stock Options and Warrants																							—			—		88,029			17,606			104,718			—				—			—				122,324
Preferred Stock Dividends	—		—	—		—		—			(316,569	)		—			—				(316,569	)	—			—		—			—			—			(475,098	)			—			—				(475,098	)

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
Balance at September 30, 2003																							791,968		$	791,968		18,127,511		$	3,625,502		$	53,334,080		$	(9,714,149	)		$	(407,428	)	$	(316,327	)		$	47,313,646

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																							—			—		—			—			—			9,351,882				—			—				9,351,882
Other Comprehensive Income (Loss); Net of Tax
Net Derivative (Loss), net of tax of $3,404,407																							—			—		—			—			—			—				—			(6,322,471	)			(6,322,471	)
Reclassification Adjustment, net of tax of $1,194,973																							—			—		—			—			—			—				—			2,219,235				2,219,235

Total Comprehensive Income																																																5,248,646
Issuance and Amortization of Restricted Stock																							—			—		4,331			866			1,184,790			—				(778,585	)		—				407,071
Exercise of Stock Options and Warrants																							—			—		2,298,803			459,761			(290,510	)		—				—			—				169,251
Preferred Stock Dividends																							—			—		—			—			—			(474,770	)			—			—				(474,770	)

Balance at September 30, 2004																							791,968		$	791,968		20,433,145		$	4,086,629		$	54,253,303		$	538,709			$	(1,160,183	)	$	(5,101,234	)		$	53,409,192

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~~nine-month period ended ~~June~~September 30, 2004 are not necessarily indicative of the results to be expected for the full year.

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~~its deferred tax valuation allowance in the ~~second quarter of~~nine months ended September 30, 2004 in the amount of ~~$1,636,000,~~$3,106,000, based on the anticipated reversal of temporary ~~differences.~~differences and utilization of tax operating loss carryforwards.

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~~nine months ended ~~June~~September 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				Three Months Ended September 30, 2003				Nine Months Ended September 30, 2003
	As Reported		As Restated		As Reported		As Restated		As Reported		As Restated		As Reported		As Restated
Depletion, Depreciation and Amortization	$	1,608,391	$	2,063,791	$	3,185,630	$	4,125,114	$	1,704,263	$	2,186,782	$	4,889,893	$	6,311,896
Income Taxes		652,028		492,638		954,657		625,836		828,483		659,601		1,783,640		1,285,435
Net Income		1,212,337		916,327		1,569,070		958,409		1,538,613		1,224,976		3,107,183		2,183,385
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
Net Income Applicable to Common Stock										1,380,247		1,066,610		2,632,085		1,708,287
Net Income per Average Common Share (Basic)										0.08		0.06		0.15		0.09
Net Income per Average Common Share (Diluted)										0.07		0.05		0.13		0.08

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.

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~~nine months ended ~~June~~September 30, 2004 and 2003, the Company recorded the following activity in the abandonment liability:

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:

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~~In October 2004, the FASB announced that it would defer the effective date for the expensing of stock options as proposed in the exposure draft ~~also includes the FASB’s tentative decisions regarding how equity-based awards are likely to be valued, expensed, and classified.~~for at least six months. The Company will continue to monitor developments with respect to the exposure draft to determine the potential impact on its financial statements.

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~~September 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.

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.

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~~September 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~~


Natural Gas	4^th Qtr 2004			1st Qtr 2005			2nd Qtr 2005			3rd Qtr 2005			4^th Qtr 2005
	Qty*	Price		Qty*	Price		Qty*	Price		Qty*	Price		Qty*	Price
	3,000	$	5.00	6,000	$	6.27	4,000	$	6.03	4,000	$	6.03	4,000	$	6.03
	3,000	$	5.94	2,000	$	7.70	2,000	$	6.50	2,000	$	6.50	2,000	$	6.70
* Quantity in MMBtu per day.

Crude Oil	4^th Qtr 2004			1st Qtr 2005			2nd Qtr 2005			3rd Qtr 2005			4^th Qtr 2005
	Qty**	Price		Qty**	Price		Qty**	Price		Qty**	Price		Qty**	Price
	700	$	28.20	500	$	33.28	500	$	35.00	500	$	34.65	500	$	34.50
	300	$	30.25	500	$	35.73	500	$	37.18	500	$	36.18	500	$	39.20

~~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;~~

~~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~~September 30, 2004, resulted in a liability of ~~$2,671,120.~~$7,646,095. As of ~~June~~September 30, 2004, ~~$1,671,524~~$4,281,073 (net of ~~$900,052~~$2,305,193 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~~nine months ended ~~June~~September 30, 2004, ~~$1,821,876~~$3,306,950 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~~nine months ended ~~June~~September 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~~September 30, 2004, the Company entered into the following ~~crude oil~~natural gas hedging contracts with BNP Paribas:

~~500 barrels of oil~~2,000 MMBtu per day “swap” at fixed price of ~~$35.73~~$8.14 for January 2005 through March 2005; ~~and~~

~~500 barrels of oil~~3,000 MMBtu per day “swap” at fixed price of ~~$35.00~~$6.55 for April 2005 through June 2005; ~~and~~

~~500 barrels of oil~~3,000 MMBtu per day “swap” at fixed price of ~~$37.18~~$6.50 for ~~April~~July 2005 through ~~June~~September 2005; ~~and~~

~~500 barrels of oil~~3,000 MMBtu 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~~$6.75 for October 2005 through December 2005

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

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~~September 30, 2004, resulted in a liability of ~~$71,076.~~$301,502. As of ~~June~~September 30, 2004, ~~$88,258~~$95,703 (net of ~~$47,524~~$51,333 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~~nine months ended ~~June~~September 30, 2004, ~~$58,570~~$107,258 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~~nine months ended ~~June~~September 30, 2004 and 2003, the Company’s earnings were not significantly affected by cash flow hedging ineffectiveness of interest rates.

Net income was used as the numerator in computing basic and diluted income per common share for the three months and ~~six~~nine months ended ~~June~~September 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,		Three Months Ended September 30,		Nine Months Ended September 30,
	2004	2003	2004	2003	2004	2003	2004	2003
Basic Method	19,040,347	18,040,141	18,726,959	18,005,931	20,221,358	18,113,947	19,228,728	18,042,332
Dilutive Stock Warrants	1,705,576	2,241,297	1,691,086	2,171,070	522,008	2,382,368	509,743	2,255,168
Dilutive Stock Options and Restricted Stock	292,847	106,612	277,850	88,609	348,024	90,741	306,322	66,332

Diluted Method	21,038,770	20,388,050	20,695,895	20,265,610	21,091,390	20,587,056	20,044,793	20,363,832

The computation of earnings per share for the three months and ~~six~~nine months ended ~~June~~September 30, 2004 and 2003 considered exercisable stock warrants, stock options and restricted ~~share awards~~stock 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,~~Pursuant to a May 2003 stock purchase agreement, the holders of ~~319,387 and 685,055~~2,369,527 warrants to purchase common stock elected a cashless exercise of such warrants resulting in the issuance of ~~252,033 and 620,935~~2,109,169 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 three separate installments which closed in January, April, and July ~~2004~~2004. There are no further exercises of warrants to be made pursuant to the stock purchase agreement (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:

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~~$110,000 in the ~~six~~nine months ended ~~June~~September 30, 2003 and ~~$268,000~~$407,000 in the ~~six~~nine months ended ~~June~~September 30, 2004. In the ~~six~~nine months ended ~~June~~September 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~~$158,000 for the value of ~~22,918~~28,918 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~~$145,000 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~~nine months ended ~~June~~September 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,						Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003			2004			2003			2004			2003
				(Restated)						(Restated)						(Restated)						(Restated)
Net income
As reported	$	2,890,054		$	916,327		$	5,014,491		$	958,409		$	4,337,394		$	1,224,976		$	9,351,882		$	2,183,385
Restricted stock compensation expense included in net income, net of tax		130,122			40,249			267,760			67,083			139,311			43,139			407,071			110,222
Stock based compensation expense at fair value, net of tax		(131,857	)		(45,367	)		(271,229	)		(77,320	)		(140,976	)		(84,086	)		(412,065	)		(140,932	)

Pro forma	$	2,888,319		$	911,209		$	5,011,022		$	948,172		$	4,335,729		$	1,184,029		$	9,346,888		$	2,152,675

Net income applicable to common stock
As reported	$	2,731,851		$	757,961		$	4,697,922		$	641,677		$	4,179,193		$	1,066,610		$	8,877,112		$	1,708,287
Restricted stock compensation expense included in net income, net of tax		130,122			40,249			267,760			67,083			139,311			43,139			407,071			110,222
Stock based compensation expense at fair value, net of tax		(131,857	)		(45,367	)		(271,229	)		(77,320	)		(140,976	)		(84,086	)		(412,065	)		(140,932	)

Pro forma	$	2,730,116		$	752,843		$	4,694,453		$	631,440		$	4,177,528		$	1,025,663		$	8,872,118		$	1,677,577

Net income per share
Net income applicable to common stock per share
As reported, basic	$	0.15		$	0.05		$	0.27		$	0.05		$	0.21		$	0.06		$	0.46		$	0.09
Pro forma, basic		0.15			0.05			0.27			0.05			0.21			0.06			0.46			0.09
As reported, diluted		0.14			0.05			0.24			0.05			0.20			0.05			0.44			0.08
Pro forma, diluted		0.14			0.04			0.24			0.05			0.20			0.05			0.44			0.08

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, 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:

The trial court also ordered the Company to pay $103,000 to the operator in recovery of defendant’s attorneys’ fees ~~reducing~~and provided for post-judgment interest to accrue on the ~~Company’s net amount~~ awarded ~~to approximately $2,065,000.~~damages and both parties’ attorneys’ fees through the date of ultimate payment. Either party ~~may appeal~~could have appealed the final judgment or ~~file~~filed a motion for a new trial within ninety days from the date of the final judgment. In September 2004, the time period for either party to appeal the judgment elapsed, therefore, the Company ~~has not recognized~~accrued a non-recurring gain in the ~~effect~~quarter ended September 30, 2004 in the amount of $2,050,000, reflecting the anticipated payment of the final judgment by the operator less the Company’s estimated expenses of the final judgment. In October 2004, the operator remitted a total of $2,118,000 to the Company in full satisfaction of the judgment, ~~in its financial statements. The timing~~including the net amount 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.

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.

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. There are no further exercises of warrants to be made pursuant to the stock purchase agreement (see Note E).

In October 2004, the Company sold its interests in several non-core properties in West Texas for gross proceeds of $2,175,000. The Company expects to report a non-recurring gain of approximately $850,000 on the sale of these properties in the fourth quarter of 2004.

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.

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

Total revenues for the three months ended ~~June~~September 30, 2004 amounted to ~~$9,366,000~~$12,182,000 compared to ~~$7,883,000~~$7,995,000 for the three months ended ~~June~~September 30, 2003. Oil and gas sales for the three months ended ~~June~~September 30, 2004 were ~~$9,351,000~~$12,152,000 compared to ~~$7,824,000~~$7,979,000 for the three months ended ~~June~~September 30, 2003. This increase resulted from a ~~23%~~30% increase in oil and gas production volumes, due to ~~several~~a number of successful well completions since the first quarter of 2003, ~~partially offset by higher hedge settlement payments.~~as well as an increase in average oil prices. Additionally, oil and gas revenues include sales of natural gas liquids in the amount of ~~$608,000~~$578,000 in the three months ended ~~June~~September 30, 2004 compared to ~~$86,000~~$306,000 in the three months ended ~~June~~September 30, 2003, resulting from processing a portion of the Company’s natural gas production beginning in ~~May 2003.~~July 2003 (sales of natural gas liquids are reflected in the calculation of average gas prices shown below). 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			Three Months Ended September 30, 2004			Three Months Ended September 30, 2003
	Production	Average Price		Production	Average Price		Production	Average Price		Production	Average Price
Gas (Mcf)	1,020,746	$	5.88	748,113	$	6.16	1,439,698	$	5.42	814,198	$	5.48
Oil (Bbls)	109,360	$	25.07	102,859	$	31.30	120,904	$	35.99	141,843	$	24.79

Other revenues for the three months ended ~~June~~September 30, 2004 were ~~$16,000~~$30,000 compared to ~~$58,000~~$15,000 for the three months ended ~~June~~September 30, 2003, with the ~~decrease~~increase primarily due to ~~a reduction in~~higher interest income and miscellaneous income.

Lease operating expense was ~~$1,643,000 for~~$1,887,000 in the three months ended ~~June~~September 30, 2004 versus ~~$1,511,000 for~~$1,291,000 in the three months ended ~~June~~September 30, 2003, resulting from cost increases experienced primarily in the Burrwood/West Delta and Lafitte fields as well as from having a larger number of producing wells. Production taxes were ~~$594,000~~$889,000 in the three months ended ~~June~~September 30, 2004 compared to ~~$516,000~~$567,000 in the ~~second~~third quarter of 2003, due to higher oil and gas sales in the 2004 period. Depletion, depreciation and amortization expense was ~~$2,480,000~~$3,220,000 for the three months ended ~~June~~September 30, 2004 versus ~~$2,064,000~~$2,187,000 for the three months ended ~~June~~September 30, 2003, with the increase due to higher equivalent units of production, and higher depletion rates. Exploration expense in the three months ended ~~June~~September 30, 2004 was ~~$1,080,000, primarily reflecting seismic costs in the Plumb Bob field,~~$1,865,000 compared to ~~$891,000~~$385,000 in the three months ended ~~June~~September 30, 2003, ~~which largely consisted of dry hole cost.~~with the increase primarily due to seismic costs in the St. Gabriel field and higher non-producing leasehold amortization expense.

General and administrative expenses amounted to ~~$1,327,000~~$1,641,000 in the three months ended ~~June~~September 30, 2004 versus ~~$1,089,000~~$1,365,000 in the ~~second~~third 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~~$1,074,000 in the three months ended ~~June~~

September 30, 2004 from ~~$521,000~~$616,000 in the three months ended ~~June~~September 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~~$139,000 in the ~~second~~third quarter of 2004 from ~~$40,000~~$43,000 in the ~~second~~third quarter of 2003. Partially offsetting these increases were ~~relatively small net~~ decreases in legal fees and other administrative expenses.

Interest expense was ~~$254,000~~$317,000 in the three months ended ~~June~~September 30, 2004 compared to ~~$186,000~~$324,000 in the ~~second~~third quarter of 2003, with the ~~increase~~decrease primarily ~~attributable to~~resulting from a ~~higher level of borrowings~~decline in the ~~second quarter~~amortization of ~~2004.~~prepaid debt costs.

~~Income taxes~~Gains and losses on asset sales and litigation judgement were a ~~benefit~~net gain of ~~$961,000~~$2,046,000 in the three months ended ~~June~~September 30, 2004 compared to ~~an expense of $493,000~~$8,000 in the three months ended ~~June~~September 30, 2003, with the increase due to a non-recurring gain resulting from the final judgment ordered by the trial judge in favor of the Company in its litigation against the operator of the Lafitte field.

Income tax expense was $72,000 in the three months ended September 30, 2004 compared to $660,000 in the three months ended September 30, 2003. The Company revised its deferred tax valuation allowance in the ~~second~~third quarter of 2004 in the amount of ~~$1,636,000,~~$1,471,000, based primarily on the anticipated ~~reversal~~utilization of ~~temporary differences,~~tax operating loss carryforwards, whereas in the three months ended ~~June~~September 30, 2003 income tax expense represented 35% of pre-tax income.

~~Six~~Nine months ended ~~June~~September 30, 2004 versus ~~six~~nine months ended ~~June~~September 30, 2003

Total revenues for the ~~six~~nine months ended ~~June~~September 30, 2004 amounted to ~~$20,292,000~~$32,474,000 compared to ~~$14,961,000~~$22,956,000 for the ~~six~~nine months ended ~~June~~September 30, 2003. Oil and gas sales for the ~~six~~nine months ended ~~June~~September 30, 2004 were ~~$20,177,000~~$32,329,000 compared to ~~$14,572,000~~$22,551,000 for the ~~six~~nine months ended ~~June~~September 30, 2003. This increase resulted from a 26% increase in oil and gas production volumes, due to ~~several~~a number of successful well completions since the first quarter of 2003, as well as ~~a small~~an increase in average oil and gas prices. Additionally, oil and gas revenues include sales of natural gas liquids in the amount of ~~$839,000~~$1,417,000 in the ~~six~~nine months ended ~~June~~September 30, 2004 compared to ~~$86,000~~$306,000 in the ~~six~~nine months ended ~~June~~September 30, 2003, resulting from processing a portion of the Company’s natural gas production beginning in ~~May 2003.~~July 2003 (sales of natural gas liquids are reflected in the calculation of average gas prices shown below). 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			Nine Months Ended September 30, 2004			Nine Months Ended September 30, 2003
	Production	Average Price		Production	Average Price		Production	Average Price		Production	Average Price
Gas (Mcf)	2,018,188	$	5.87	1,479,142	$	5.23	3,457,886	$	5.91	2,306,721	$	5.26
Oil (Bbls)	245,391	$	30.55	213,625	$	31.98	366,295	$	32.35	366,310	$	28.30

Other revenues for the ~~six~~nine months ended ~~June~~September 30, 2004 were ~~$114,000~~$145,000 compared to ~~$390,000~~$405,000 for the ~~six~~nine months ended ~~June~~September 30, 2003, with the decrease of ~~$276,000~~$260,000 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~~$5,079,000 in the ~~six~~nine months ended ~~June~~September 30, 2004 versus ~~$3,268,000 for~~$4,559,000 in the ~~six~~nine months ended ~~June~~September 30, 2003, with the ~~decrease~~increase resulting largely ~~due to the Company’s ongoing efforts to reduce costs on its operated properties notwithstanding~~from an increase in the number of producing wells. Production taxes were ~~$1,289,000~~$2,178,000 in the ~~six~~nine months ended ~~June~~September 30, 2004 compared to ~~$1,047,000~~$1,614,000 in the ~~six~~nine months ended ~~June~~September 30, 2003, due to higher oil and gas sales in the 2004 period. Depletion, depreciation and amortization expense was ~~$5,234,000~~$8,454,000 for the ~~six~~nine months ended ~~June~~

September 30, 2004 versus ~~$4,125,000~~$6,312,000 for the ~~six~~nine months ended ~~June~~September 30, 2003, with the increase due to higher equivalent units of production, and higher depletion rates. Exploration expense in the ~~six~~nine months ended ~~June~~September 30, 2004 was ~~$2,017,000,~~$3,881,000 compared to $1,829,000 in the nine months ended September 30, 2003, with the increase primarily ~~reflecting~~due to seismic costs in the Plumb Bob ~~field, compared to $1,445,000~~and St. Gabriel fields and higher non-producing leasehold amortization expense, partially offset by a decrease in ~~the six months ended June 30, 2003, which largely consisted of two~~ exploratory dry ~~holes.~~hole costs.

General and administrative expenses amounted to ~~$2,833,000~~$4,473,000 in the ~~six~~nine months ended ~~June~~September 30, 2004 versus ~~$2,627,000~~$3,993,000 in the ~~six~~nine months ended ~~June~~September 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~~$2,360,000 in the ~~six~~nine months ended

~~June~~ September 30, 2004 from ~~$948,000~~$1,523,000 in the ~~six~~nine months ended ~~June~~September 30, 2003, primarily due to an increase in the number of employees. Partially offsetting this increase ~~was~~were decreases in legal fees and certain other administrative expenses as well as a decrease in non-cash charges for employee equity compensation programs to ~~$268,000~~$407,000 in the ~~six~~nine months ended ~~June~~September 30, 2004 from ~~$470,000~~$513,000 in the ~~six~~nine months ended ~~June~~September 30, 2003. In the 2004 period, these non-cash charges consisted solely of vesting of restricted stock grants in the amount of ~~$268,000,~~$407,000, 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~~$110,000 related to the vesting of restricted stock grants.

Interest expense was ~~$471,000~~$789,000 in the ~~six~~nine months ended ~~June~~September 30, 2004 compared to ~~$422,000~~$746,000 in the ~~six~~nine months ended ~~June~~September 30, 2003, with the increase primarily attributable to a higher level of borrowings in the 2004 period.

Gains and losses on asset sales and litigation judgement were a net gain of $1,987,000 in the nine months ended September 30, 2004 compared to a net loss of $229,000 in the nine months ended September 30, 2003, with the increase due to a non-recurring gain resulting from the final judgment ordered by the trial judge in favor of the Company in its litigation against the operator of the Lafitte field.

Income tax expense was ~~$183,000~~$255,000 in the ~~six~~nine months ended ~~June~~September 30, 2004 compared to ~~$626,000~~$1,285,000 in the ~~six~~nine months ended ~~June~~September 30, 2003. The Company revised its deferred tax valuation allowance in the ~~second quarter of~~nine months ended September 30, 2004 in the amount of ~~$1,636,000,~~$3,106,000, based on the anticipated reversal of temporary differences and utilization of tax operating loss carryforwards, whereas in the ~~six~~nine months ended ~~June~~September 30, 2003 income tax expense represented 35% of pre-tax income.

Net cash provided by operating activities was ~~$13,651,000~~$24,108,000 in the ~~six~~nine months ended ~~June~~September 30, 2004, compared to ~~$6,199,000~~$10,869,000 in the ~~six~~nine months ended ~~June~~September 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 lease operating expenses, production taxes, and 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~~$5,100,000 in the ~~six~~nine months ended ~~June~~September 30, 2004, compared to a decrease of ~~$1,613,000~~$1,284,000 in the ~~six~~nine months ended ~~June~~September 30, 2003.

Net cash used in investing activities was ~~$16,387,000~~$28,800,000 in the ~~six~~nine months ended ~~June~~September 30, 2004, compared to ~~$10,389,000~~$15,030,000 in the ~~six~~nine months ended ~~June~~September 30, 2003. In the ~~six~~nine months ended ~~June~~September 30, 2004 capital expenditures totaled ~~$16,387,000,~~$28,809,000, as the Company participated in the drilling of two successful exploratory wells and one successful sidetrack well in the Burrwood/West Delta 83 field and incurred substantial drilling and leasehold acquisition costs in East Texas and Northwest Louisiana (see “Cotton Valley Drilling Program”). Offsetting these capital expenditures was a minor property sale in the amount of $9,000. In the ~~six~~nine months ended ~~June~~September 30, 2003, capital expenditures totaled ~~$10,672,000~~$15,371,000 and were partially offset by the sale of the Company’s interest in the South Drew field resulting in proceeds of ~~$284,000.~~$341,000.

Net cash provided by financing activities was ~~$2,643,000~~$4,964,000 in the ~~six~~nine months ended ~~June~~September 30, 2004, compared to ~~$975,000~~$2,440,000 in the ~~six~~nine months ended ~~June~~September 30, 2003. In the ~~six~~nine months ended ~~June~~September 30, 2004, net borrowings under the Company’s senior credit facility provided cash of ~~$3,000,000~~$5,500,000 and exercises of stock options and warrants provided cash of ~~$123,000,~~$169,000, while preferred stock dividends and production payments used cash of ~~$480,000.~~$705,000. In the ~~six~~nine months ended ~~June~~September 30, 2003, ~~net~~ borrowings under the Company’s senior credit facility provided cash of ~~$1,500,000~~$3,100,000 and exercises of stock warrants provided cash of ~~$10,000,~~$122,000, while preferred stock dividends and production payments used cash of ~~$535,000.~~$782,000.

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 remaining 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~~50% of the 2004 capital expenditure budget has been designated for exploration and development drilling activities in the Cotton Valley trend.

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~~October 31, 2004, the Company had acquired or farmed in leases totaling approximately ~~40,000~~45,000 gross acres, with an average working interest of approximately 80%, and is attempting to acquire additional acreage in the area. The Company has successfully drilled ~~a total of four~~8 operated wells targeting the Cotton Valley formation and ~~presently has two drillings rigs under contract~~projects that it will drill a total of 14 to 15 such wells by the end of 2004. For the wells completed to date, the Company estimates that the initial 30 day average gross production rate per well is approximately 900 Mcf of gas per day. This estimated average production rate for the initial 30 day period is consistent with the range originally projected by the Company prior to commencing its drilling activities in the ~~East Texas/Northwest Louisiana area~~Cotton Valley trend. Initial production from the Cotton Valley wells commenced in June 2004, and ~~anticipates~~taking into account the ~~possibility~~expected decline following the initial 30 day period, the current gross production from the 8 successfully completed wells is approximately 5,200 Mcf of ~~adding a third rig in~~gas per day, or 3,500 Mcf of gas per day net to the ~~second half of 2004.~~Company.

In East Texas, the Company commenced a drilling program in April 2004 and has drilled a total of ~~three~~6 successful wells on its operated acreage targeting the Cotton Valley formation. ~~Two of the drilled wells, in which the~~The Company has a 100% working interest ~~have been~~in four of the completed wells and ~~placed on production and a third well, in which the Company has~~ an 85% working interest in two of the completed wells. The Company currently has ~~been logged~~engaged two drilling rigs which are drilling new wells on its operated acreage in East Texas 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.~~third rig under contract.

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,~~two wells, which ~~is awaiting a gas meter installation, and is presently drilling another well.~~are currently in production. 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 gross 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)~~completed to date and anticipates that its working interests in the additional wells to be drilled in the field will range between 50% and 70%.

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~~interest 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~~Additionally, in the ~~current gross production is approximately 420 barrels~~third quarter of ~~oil per day and 650 Mcf of gas per day. The~~2004, the Company ~~is currently drilling~~drilled a successful sidetrack well to one of its other existing producing wells in the field, in which it has a 65% working interest. The Company’s share of the current production from these three wells is approximately 4,300 Mcf of gas per day and 425 barrels of oil per day. In the fourth quarter of 2004, the Company anticipates drilling an additional exploratory well on a prospect with a 42% working interest.

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 a 70% working interest in 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,

the Company also commenced a 3230 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.

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~~2004. Data acquisition was recently completed and the Company 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 a total of approximately $1.75 million for the acquisition of the rights and the 3-D seismic ~~survey.~~survey in 2004. Post 3-D development drilling activities are not expected to occur prior to 2005.

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~~In August 2004, the ~~next~~ borrowing base ~~redetermination will~~was redetermined to be ~~completed in the third quarter of 2004 once BNP Paribas evaluates production information on several recently completed oil and gas wells.~~$32,000,000. Borrowings outstanding under the senior credit facility were ~~$23,000,000~~$25,500,000 as of ~~June~~September 30, 2004 and ~~$24,000,000 as of August~~November 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 of up to $15 million 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~~September 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”).

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:

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~~September 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~~September 30, 2004, the Company’s open forward position on its outstanding commodity hedging contracts, all of which were with BNP Paribas, was as follows:

~~3,000 MMBtu~~** Quantity in Barrels 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~~

~~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~~day.

The fair value of the natural gas and oil hedging contracts in place at ~~June~~September 30, 2004, resulted in a liability of ~~$2,671,000.~~$7,646,000. Based on oil and gas pricing in effect at ~~June~~September 30, 2004, a hypothetical 10% increase in oil and gas prices would have increased the liability to ~~$4,546,000~~$11,963,000 while a hypothetical 10% decrease in oil and gas prices would have decreased the liability to ~~$796,000.~~$3,329,000. Subsequent to ~~June~~September 30, 2004, the Company entered into the following ~~crude oil~~natural gas hedging contracts with BNP Paribas:

~~500 barrels of oil~~2,000 MMBtu per day “swap” at fixed price of ~~$35.73~~$8.14 for January 2005 through March 2005; ~~and~~

~~500 barrels of oil~~3,000 MMBtu per day “swap” at fixed price of ~~$35.00~~$6.55 for April 2005 through June 2005; ~~and~~

~~500 barrels of oil~~3,000 MMBtu per day “swap” at fixed price of ~~$37.18~~$6.50 for ~~April~~July 2005 through ~~June~~September 2005; ~~and~~

~~500 barrels of oil~~3,000 MMBtu 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~~$6.75 for October 2005 through December 2005

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

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~~September 30, 2004, resulted in a liability of ~~$71,000.~~$302,000. Based on interest rates in effect at ~~June~~September 30, 2004, a hypothetical 10% increase or decrease in interest rates would not have a material effect on the liability.

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.

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.

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~~September 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~~September 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.

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.

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

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



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~~August 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~~Second Quarter 2004 Earnings Release.

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.


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)~~


		Page No.
PART 1 - FINANCIAL INFORMATION

Item 1. Financial Statements.

Consolidated Balance Sheets ~~June~~September 30, 2004 (Unaudited) and December 31, 2003		3-4

Consolidated Statements of Operations (Unaudited) Three Months Ended ~~June~~September 30, 2004 and 2003 Nine Months Ended September 30, 2004 and 2003		5

~~Six Months Ended June 30, 2004 and 2003~~6		6

Consolidated Statements of Cash Flows (Unaudited) ~~Six~~Nine Months Ended ~~June~~September 30, 2004 and 2003		7

Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Unaudited) ~~Six~~Nine Months Ended ~~June~~September 30, 2004 and 2003		8

Notes to Consolidated Financial Statements		~~9-16~~9-15

Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations.		~~17-22~~16-21

Item 3.Quantitative and Qualitative Disclosures About Market Risk.		~~23-24~~22-23

Item 4.Controls and Procedures.		2524

PART II - OTHER INFORMATION		25

Item 1.Legal Proceedings.		2625

Item 2.Changes in Securities.		2625

Item 3.Defaults Upon Senior Securities.		2625

Item 4.Submission of Matters to a Vote of Security Holders.		2625

Item 5.Other Information.		2625

Item 6.Exhibits and Reports on Form 8-K.		2625


	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


	Nine Months Ended September 30,
	2004			2003
Beginning balance	$	6,601,186		$	6,289,065
Accretion of liability		238,711			286,000
Liability for newly added wells		314,334			296,000
Abandonment costs incurred or sold		(140,793	)		(220,780	)

Ending balance		7,013,438			6,650,285
Less: current portion		(91,605	)		(125,000	)

	$	6,921,833		$	6,525,285


	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


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.

		None

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.


		GOODRICH PETROLEUM CORPORATION
		(Registrant)

~~August 11,~~November 10, 2004 ~~Date~~		/s/ Walter G. Goodrich
Date		Walter G. Goodrich, Vice Chairman & Chief Executive Officer

~~August 11,~~November 10, 2004 ~~Date~~		/s/ D. Hughes Watler, JrJr.
Date		D. Hughes Watler, Jr., Senior Vice President & Chief Financial Officer


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