Exhibit 99.1

Contact:
Robert C. Turnham, Jr., President		Traded: NYSE (GDP)
David R. Looney, Chief Financial Officer

FOR IMMEDIATE RELEASE

GOODRICH PETROLEUM ANNOUNCES SECOND QUARTER
FINANCIAL RESULTS AND OPERATIONAL UPDATE

	•		Production Volumes for the Quarter Grew 8% Sequentially and 22% Over the Prior Year Period to a Record 82.1 MMcfe/day, Exceeding Guidance
	•		Lease Operating Expenses Were Reduced to $0.94 per Mcfe for the Quarter — a 29% Reduction from the First Quarter and a 25% Reduction from the Prior Year Period
	•		Record Haynesville Shale Production Levels, Accounting for Approximately 20% of Total Second Quarter Production
	•		Record $27.2 Million in Settlements from Realized Derivative Contracts

Houston, Texas — August 5, 2009. Goodrich Petroleum Corporation (NYSE: GDP) today announced financial and operating results for the quarter ended June 30, 2009.

PRODUCTION

Net production volumes in the second quarter increased by approximately 22% to 7.5 billion cubic feet equivalent (“Bcfe”), or an average of approximately 82,100 Mcfe per day, versus 6.1 Bcfe, or an average of approximately 67,100 Mcfe per day in the second quarter of 2008. Average net daily production volumes for the second quarter increased sequentially by approximately 8% versus the first quarter of 2009. Virtually all of net production volumes for the quarter came from Cotton Valley trend wells in East Texas and North Louisiana, including approximately 20% from the Haynesville Shale formation, up from 5% in the first quarter of 2009.

The Company currently expects net daily production volumes will average between 78,000 and 82,000 Mcfe per day for the third quarter of 2009, which includes the impact of delayed completions on up to four wells drilled but not completed in 2009.

NET INCOME

Net income applicable to common stock for the second quarter of 2009 was a loss of $36.5 million ($(1.02) per share) compared to a second quarter 2008 loss of $40.6 million ($(1.27) per share). Results

for the second quarter of 2009 included a $23.5 million pre tax non-cash impairment charge for oil and natural gas properties primarily associated with the Caddo Pine Island field in Caddo Parish, Louisiana. The second quarter also included a net $2.6 million gain on derivatives not designated as hedges, with over $27.2 million in realized gains on our natural gas derivative contracts being partially offset by unrealized losses of $24.4 million on natural gas derivative contracts and a $0.2 million loss on our interest rate derivative contracts. By contrast, the second quarter of 2008 included a $48.9 million loss on derivatives not designated as hedges (comprised of a $2.0 million realized loss and a $46.9 million non-cash, unrealized loss).

CASH FLOW

Earnings before interest, taxes, DD&A, non-cash general and administrative expenses and exploration (“EBITDAX”), decreased 19% to approximately $37.3 million for the second quarter, compared to $46.4 million in the same period of the prior year. The primary reason for the decrease in EBITDAX was due to natural gas prices being down approximately 67% on a unit basis from the prior year period (see the accompanying table for a reconciliation of EBITDAX, a non-GAAP measure, to net cash provided by operating activities).

Discretionary cash flow (“DCF”), defined as net cash provided by operating activities before changes in working capital, was $33.0 million in the quarter, second only in the Company’s history to the $41.5 million in DCF realized in the prior year period. Net cash provided by operating activities was $27.1 million for the quarter, down from the prior year period’s $39.9 million, once again due to decreased price realizations (see the accompanying table for a reconciliation of discretionary cash flow, a non-GAAP measure, to net cash provided by operating activities).

REVENUES

Total revenues for the second quarter, which do not include realized gains of $27.2 million on natural gas derivatives not designated as hedges, decreased by approximately 60% to $26.3 million, versus $65.2 million for the same period in the prior year. Average net oil and natural gas prices received in the second quarter were $3.33 per Mcf of natural gas versus $10.18 per Mcf of natural gas in the prior year period and $52.98 per barrel of oil in the second quarter of 2009 versus $121.51 per barrel in the prior year period. On an Mcfe basis, the blended price was $3.51 per Mcfe in the second quarter of 2009 versus $10.62 per Mcfe in the prior year period. Total revenues and average prices received in the second quarter of 2009 do not include realized gains of $27.2 million received on the Company’s settled natural gas derivatives, none of which were designated as hedges during the quarter.

OPERATING INCOME

Operating income, defined as revenues minus operating expenses, dropped to a loss of $53.9 million in the second quarter of 2009, versus income of $16.1 million for the prior year period. The significant decrease in operating income from the prior year period was primarily a function of the previously mentioned $23.5 million non-cash impairment charge incurred during the quarter as well as lower oil and natural gas prices.

OPERATING EXPENSES

Lease operating expenses (LOE) totaled $7.0 million in the quarter, or $0.94 per Mcfe of production, versus $7.7 million, or $1.26 per Mcfe for the prior year period. LOE per Mcfe for the quarter was down 25% from the second quarter of 2008, and approximately 29% from the first quarter of 2009. The majority of the LOE improvements occurred in the areas of salt water disposal (SWD) and compression costs, where the company realized significant benefits in the quarter from recently installed SWD systems and renegotiated compression contracts. Additionally, the impact of the Haynesville Shale production volumes began to surface in the quarter, as the per unit rate of LOE from the Haynesville Shale production is significantly less than our historical LOE rate.

General and administrative (G&A) expenses totaled $6.7 million for the quarter, or $0.90 per Mcfe, versus $5.9 million, or $0.97 per Mcfe, during the prior year period. G&A expenses were down on a per unit basis over the prior year period as the Company grew production volumes faster than the rate of increase of G&A. Additionally, G&A expenses were down from the first quarter of 2009 on both an absolute basis (from $7.1 million in the first quarter) and a per unit basis (from $1.04 in the first quarter), Included in G&A expenses, the Company recorded a non-cash expense related to stock based compensation for its officers, employees and directors of $1.6 million during the quarter, which was up slightly from the prior year period.

Production and other taxes, which are tied directly to oil and natural gas price levels, were $1.0 million, or $0.14 per Mcfe, in the second quarter of 2009 versus $2.3 million, or $0.38 per Mcfe in the prior year period. Transportation expenses were down slightly from the prior year period (from $0.39 per Mcfe to $0.35 per Mcfe), while Exploration expense increased to $3.0 million in the second quarter of 2009, or $0.40 per Mcfe, versus $1.8 million, of $0.29 per Mcfe in the prior year period. Exploration expense was negatively impacted during the current quarter as a result of $1.1 million in early termination fees incurred when we released two of our operated rigs approximately 50 days prior to the expiration of their respective contracts.

A non-cash Impairment charge of $23.5 million was incurred during the second quarter of 2009, primarily due to the write down of the carrying value of the Caddo Pine Island field, where the Company’s wells drilled over the last 12 months have yielded reserve quantities insufficient to justify the costs of those reserves. No such impairment charges were incurred in the prior year period.

CAPITAL EXPENDITURES

The Company conducted drilling and/or completion operations on 12 gross (9 net) wells in the quarter with a 100% success rate. Capital expenditures for the quarter totaled $65.3 million, down approximately 30% from the prior year period, which was $93.6 million. Of the $65.3 million in capital expenditures for the quarter, approximately $60.9 million, or 93% of the total was associated with the drilling and/or completion of 23 gross wells, versus $85.6 million expended for drilling and completion of 46 gross wells during the prior year period. Additionally, approximately $1.8 million was spent on leasehold acquisitions, and approximately $2.4 million was associated with facilities and other costs during the second quarter of 2009.

For the remainder of 2009, the Company is estimating that capital expenditures will be approximately $75 million, bringing full year capital expenditures near its previously announced budget of $230 million.

LIQUIDITY

As the Company exited the second quarter of 2009 with approximately $25.0 million in cash, we now expect to make slight draws on our bank revolver between now and the end of the year to help fund our remaining 2009 Capital Expenditure program. While the reduction in capital expenditures that we have seen thus far this year and expect to see for the remainder of the year have helped to preserve our cash and liquidity position, the concurrent slowdown in our activity levels has resulted in an outflow of funds related to the unwinding of our deficit working capital position. The Company estimates that since year end it has paid out approximately $25.0 million in additional funds over and above its capital expenditure bookings for the first half of this year, and expects an additional $15.0 to $20.0 million of such outflow in the second half of the year associated with the continued reduction in capital expenditures referenced above.

The Company’s current borrowing base under its senior revolving credit facility is set at $175.0 million and currently has no balance outstanding. The borrowing base is expected to be reset in September based upon the bank review of the Company’s estimated reserves. The Company expects to finance its capital expenditures for the remainder of this year and into 2010 through a combination of available cash, cash flow from operations and borrowings under its senior revolving credit facility.

OPERATIONAL UPDATE

DRILLING

During the second quarter of 2009, the Company conducted drilling operations on 12 horizontal Cotton Valley trend wells, of which nine targeted the Haynesville Shale and three targeted the Cotton Valley Taylor sand. During the same period, the Company reached total depth on nine wells and added 17 wells to production. Of the wells added to production, 12 wells produced from the Haynesville Shale, one from the Cotton Valley Taylor sand, one from the James Lime and three from the Travis Peak. As of June 30, 2009, the Company had drilled and logged a total of 447 Cotton Valley trend wells, with a success rate in excess of 99%.

CORE PROPERTIES

Louisiana

Bethany-Longstreet Field, Caddo and DeSoto Parishes, Louisiana. In the Bethany Longstreet field, the Company conducted drilling operations on five Haynesville Shale horizontal wells during the quarter. In addition, the Company conducted completion operations on four and added a total of six wells to production during the quarter.

To date, the Company has completed and added to production a total of eight Haynesville Horizontal wells in the Bethany Longstreet field with an average initial production rate of 14,000 Mcf per day.

Within the existing joint venture with Chesapeake Energy (“Chesapeake”), the Company is currently running two rigs and conducting completion operations on two wells.

Also in the Bethany Longstreet field but outside of the existing joint venture with Chesapeake, the Company, as operator, has commenced drilling the Plants 26 H-1 (36% WI), which is a horizontal well targeting the Haynesville Shale formation.

Greenwood-Waskom Field, Caddo Parish, Louisiana. The Company, as operator, is also currently drilling the Trosper 2 H-1 (87.5% WI), its initial Haynesville Shale horizontal well in the Greenwood-Waskom field. The Company currently plans to drill one additional well in the field during the second half of 2009.

Texas

Beckville and Minden Fields, Panola and Rusk Counties, Texas

During the quarter, the Company conducted drilling operations on seven horizontal wells, four wells targeting the Haynesville Shale and three wells targeting the Cotton Valley Taylor sand. In addition, the Company completed and added to production three Haynesville Shale horizontal wells and one Cotton Valley Taylor sand well in the Beckville and Minden fields.

The Company’s most recent Haynesville Shale horizontal test, the Taylor Sealey 3H (100% WI), which was the Company’s initial well completed with both a desired lateral length and current flowback procedure, came online as previously reported at an initial production rate of 9.3 MMcf per day and had a 30-day average of approximately 6.5 MMcf/day.

In addition, this quarter the Company reached total depth on three other horizontal wells, one in the Haynesville Shale formation and two Cotton Valley Taylor sand wells. These wells will be completed in the future at the Company’s discretion.

Management Comments

Commenting on the second quarter results, W. “Gil” Goodrich, Vice Chairman and CEO said, “We are extremely pleased with our operational results in the second quarter. Not only did we exceed our previous guidance on production volume growth, which came in slightly above the upper end of our guidance, but we also achieved major breakthroughs on lease operating expenses, as we reduced our LOE to $0.94 per Mcfe on a per unit basis. In addition, we saw a significant expansion in Haynesville Shale production which grew from approximately 5% of total company volumes in the first quarter to approximately 20% of average daily volumes during the second quarter. Our 2009 hedging program again contributed meaningfully to our quarterly results with just over $27.0 million in cash receipts from realized natural gas hedges during the quarter, which is in addition to reported revenue of $26.0 million. All of the above combined for a solid quarter in discretionary cash flow, which was a near-record $33.0 million. Aside from our results at Caddo Pine Island field, which led to the impairment discussed herein, our drilling program in the first half of the year was extremely successful, as evidenced by the rapid production growth, largely the result of our new Haynesville Shale horizontal wells. We are also extremely pleased with the early results and performance from our initial Cotton Valley (Taylor Sand) horizontal wells. We are continuing to fine tune our horizontal drilling and completion methodologies, which will no doubt yield long term benefits to GDP shareholders. We have also begun to establish a hedging position for 2010 with 10,000 MMbtu per day placed in a costless collar with a floor of $6.00 per MMbtu and a ceiling of $7.15 per MMbtu. We still expect to exit 2009 with an extremely strong balance sheet, and we remain committed to providing superior growth at a reasonable cost going forward.”

OTHER INFORMATION

In this press release, the Company refers to two non-GAAP financial measures, EBITDAX and discretionary cash flow. Management believes that each of these measures is a good financial indicator of the Company’s ability to internally generate operating funds. Management also believes that these non-GAAP financial measures of cash flow provide useful information to investors because they are widely used by professional research analysts in the valuation and investment recommendations of companies within the oil and natural gas exploration and production industry. Neither discretionary cash flow nor EBITDAX should be considered an alternative to net cash provided by operating activities, as defined by GAAP.

Initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels.

Certain statements in this news release regarding future expectations and plans for future activities may be regarded as “forward looking statements” within the meaning of the Securities Litigation Reform Act. 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 natural 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.

Goodrich Petroleum is an independent oil and natural gas exploration and production company listed on the New York Stock Exchange. The majority of its properties are in Louisiana and Texas.

GOODRICH PETROLEUM CORPORATION
SELECTED INCOME DATA
(In Thousands, Except Per Share Amounts)

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
						(as adjusted)								(as adjusted)
Total Revenues		$	26,263			$	65,173			$	54,724			$	111,526
Operating Expenses
Lease operating expense			6,984				7,669				15,980				14,766
Production and other taxes			1,049				2,334				2,537				3,589
Transportation			2,591				2,386				5,179				4,256
Depreciation, depletion and amortization			36,537				29,033				70,195				54,118
Exploration			2,959				1,776				5,179				3,779
Impairment of oil and gas properties			23,490				—				23,490				—
General and administrative			6,713				5,920				13,770				11,360
Gain on sale of assets			(113	)			—				(113	)			—
Operating income (loss)			(53,947	)			16,055				(81,493	)			19,658
Other income (expense)
Interest expense			(5,298	)			(6,026	)			(10,506	)			(11,447	)
Interest income			144				—				383				—
Gain (loss) on derivatives not designated as hedges			2,556				(48,947	)			39,562				(73,434	)
			(2,598	)			(54,973	)			29,439				(84,881	)
Loss from continuing operations before income taxes			(56,545	)			(38,918	)			(52,054	)			(65,223	)
Income tax benefit			21,505				—				20,151				—
Loss from continuing operations			(35,040	)			(38,918	)			(31,903	)			(65,223	)
Discontinued operations:
Gain (loss) on sale of assets, net of tax			—				(120	)			—				280
Income (loss) from discontinued operations, net of tax			58				(101	)			65				284
			58				(221	)			65				564
Net loss			(34,982	)			(39,139	)			(31,838	)			(64,659	)
Preferred stock dividends			1,512				1,511				3,024				3,023
Net loss applicable to common stock		$	(36,494	)		$	(40,650	)		$	(34,862	)		$	(67,682	)
Loss per common share from continuing operations
Basic		$	(1.02	)		$	(1.26	)		$	(0.97	)		$	(2.14	)
Diluted		$	(1.02	)		$	(1.26	)		$	(0.97	)		$	(2.14	)
Income (loss) per common share from discontinued operations
Basic		$	—			$	(0.01	)		$	—			$	0.02
Diluted		$	—			$	(0.01	)		$	—			$	0.02
Net loss per common share applicable to common stock
Basic		$	(1.02	)		$	(1.27	)		$	(0.97	)		$	(2.12	)
Diluted		$	(1.02	)		$	(1.27	)		$	(0.97	)		$	(2.12	)
Weighted average common shares outstanding:
Basic			35,937				32,124				35,953				31,915
Diluted			35,937				32,124				35,953				31,915

GOODRICH PETROLEUM CORPORATION
Selected Cash Flow Data (In Thousands):

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
						(as adjusted)								(as adjusted)
Calculation of EBITDAX:
Revenue			26,263				65,173				54,724				111,526
Lease operating expense			(6,984	)			(7,669	)			(15,980	)			(14,766	)
Production and other taxes			(1,049	)			(2,334	)			(2,537	)			(3,589	)
Transportation			(2,591	)			(2,386	)			(5,179	)			(4,256	)
G&A — cash portion only			(5,141	)			(4,480	)			(10,567	)			(8,653	)
Realized gain (loss) on derivatives not designated as hedges			26,801				(1,949	)			47,827				(1,582	)
EBITDAX			37,299				46,355				68,288				78,680
Reconciliation of EBITDAX to Net Cash Provided by Operating Activities:
EBITDAX			37,299				46,355				68,288				78,680
EBITDAX — Discontinued Operations			58				(101	)			65				284
Exploration			(2,959	)			(1,776	)			(5,179	)			(3,779	)
Prospect amortization			1,377				885				2,901				2,449
Dry hole			—				—				101				—
Interest expense			(2,924	)			(3,900	)			(5,885	)			(7,217	)
Interest income			144				—				383				—
Current income taxes			31				—				35				—
Other non-cash items			—				21				—				—
Net changes in working capital			(5,910	)			(1,583	)			2,664				(13,321	)
Net cash provided by operating activities (GAAP)			27,116				39,901				63,373				57,096
Reconciliation of Discretionary Cash Flow to Net Cash Provided by Operating Activities:
Discretionary cash flow			33,026				41,484				60,709				70,417
Net changes in working capital			(5,910	)			(1,583	)			2,664				(13,321	)
Net cash provided by operating activities (GAAP)			27,116				39,901				63,373				57,096
			—								—				—

Selected Operating Data:

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
Production — Continuing Operations:
Natural gas (MMcf)			7,223				5,841				13,768				10,874
Oil and condensate (MBbls)			41				45				86				83
Total (Mmcfe)			7,469				6,109				14,287				11,375
Average sales price per unit:
Natural gas (per Mcf)		$	3.33			$	10.18			$	3.70			$	9.37
Oil (per Bbl)			52.98				121.51				42.75				109.70
Natural gas and oil (Mcfe)			3.51				10.62				3.83				9.76
Expenses per Mcfe:
Lease operating expense		$	0.94			$	1.26			$	1.12			$	1.30
Production and other taxes			0.14				0.38				0.18				0.32
Transportation			0.35				0.39				0.36				0.37
DD&A			4.89				4.75				4.91				4.76
Exploration			0.40				0.29				0.36				0.33
Impairment of oil and gas properties			3.14				—				1.64				—
General and administrative			0.90				0.97				0.96				1.00
Gain on sale of assets			(0.02	)			—				(0.01	)			—