Goodrich Petroleum 8-K Goodrich Petroleum Announces Year End and Fourth Quarter Financial Results and Operational Update

Exhibit 99.1

NEWS from

808 Travis, Suite 1320
Houston, Texas 77002
(713) 780-9494
Fax (713) 780-9254

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

FOR IMMEDIATE RELEASE

GOODRICH PETROLEUM ANNOUNCES YEAR END AND FOURTH QUARTER
FINANCIAL RESULTS AND OPERATIONAL UPDATE

• Production Volumes for the Year Set Record and Grow 51% Over 2007. Production Volumes for the Fourth Quarter Increase by 39% Versus the Prior Year Period. Guidance of 5 — 10% Sequential Quarterly Growth in 1Q’09

• Proved Reserves Grow by 12% to 402 Bcfe Using Year End 2008 SEC Pricing

• Drilled 127 Gross (76 Net) Wells in 2008 with a 98% Success Rate

• Acreage in the Cotton Valley Trend Increased 10% to Approximately 201,000 Gross (127,000 Net) Acres at Year End, with 100,000 Gross (63,000 Net) Acres Prospective for the Haynesville Shale

• Year End Cash and Short Term Investments of $148 Million Provide Liquidity for 2009

Houston, Texas — February 25, 2009. Goodrich Petroleum Corporation (NYSE: GDP) today announced financial and operating results for the year and fourth quarter ended December 31, 2008.

PRODUCTION

Net production volumes from continuing operations in the quarter increased by approximately 39% to 6.5 billion cubic feet equivalent (“Bcfe”), or approximately 70,400 Mcfe per day, versus 4.6 Bcfe, or approximately 50,500 Mcfe per day, in the prior year period. For the year, net production volumes increased by 51% to 24.2 Bcfe versus 16.0 Bcfe in 2007. Net production volumes for the fourth quarter increased sequentially by approximately 2% versus the third quarter of 2008, and were negatively impacted by the delays caused from the Company’s transition to horizontal development of the Haynesville Shale and the longer completion cycle for those wells. The Company added to production 12 wells in the fourth quarter versus 23 in the third quarter. Additionally, due primarily to the factors mentioned above, the Company had 13 wells awaiting pipelines and/or production facilities at the end of the year. Virtually all of the net production volumes for the quarter came from Cotton Valley trend wells in East Texas and North Louisiana, with less than 1% coming from the Haynesville Shale.

The Company currently expects net daily production volumes will increase sequentially by 5 — 10% in the first quarter of 2009 to an average of 74,000 to 77,500 Mcfe per day.

YEAR END RESERVES

The Company announced that it has received its fully engineered year end 2008 reserve report from Netherland, Sewell & Associates, Inc. with an effective date of December 31, 2008. Total proved reserves were 402 Bcfe, 97% natural gas and 38% developed. Proved developed reserves grew by 38% during the year, while total proved reserves grew by 12%, up from 358 Bcfe of proved reserves at year end 2007. The 402 Bcfe total includes approximately 63.4 Bcfe of negative revisions from the prior year end, 94% of which were price related, and 83% of which related to undeveloped reserves.

The reserves were calculated with an effective date of December 31, 2008 and using un-escalated pricing of $5.71 per MMbtu of natural gas and $41.00 per barrel of oil, subject to further reductions for quality and basis differentials. Proved reserves were almost exclusively located in the Company’s Cotton Valley trend, with the Company’s emerging Haynesville Shale play representing less than 2% of total reserves. Future net revenue before income tax expense from proved reserves at December 31, 2008 pricing is estimated to be $560 million, with pre-tax present worth discounted at 10% (“PV10”) of $170 million (see accompanying table for a reconciliation of PV10, a non-GAAP measure, to the Standardized Measure of discounted future net cash flows). The Standardized Measure of discounted future net cash flows from oil and gas reserves was $167.4 million as of December 31, 2008. When using a price of $7.50/MMbtu of natural gas and $67.50/barrel of crude oil, and after applying historic differentials, the year end reserves would have increased 30% to 467 Bcfe, with future net revenue of $1.3 billion and pre-tax present worth discounted at 10% of $496 million.

Reserve growth in 2008 was achieved exclusively through organic growth with the drillbit in the Cotton Valley trend. When including all revisions in the calculation, the Company replaced approximately 285% of its 2008 net production volumes of approximately 24.2 Bcfe. Prior to revisions, the Company replaced approximately 547% of its 2008 production.

All-in finding and development cost (“F&D”) for 2008 was $2.68 per Mcfe, with all-in F&D being defined as 2008 drilling and completion capital expenditures of $345.8 million, which excludes capital costs associated with undeveloped leasehold acquisition and facility costs of approximately $33.0 million, divided by proved reserve additions, prior to revisions, of 129.2 Bcfe (see accompanying table for a reconciliation of drilling and completion capital expenditures, a non-GAAP measure, to costs incurred in oil and gas property acquisition, exploration, and development activities).

Proved developed drillbit additions for wells drilled during 2008, and for which new reserves were designated as of December 31, 2008, were approximately 77.8 Bcfe before revisions. However, it should be noted that included in the total drilling and completion capital expenditures of $345.8 million were capital expenditures of approximately $34.2 million on wells which were drilling at year end 2007 and for which proved reserves were booked during 2007, as well as approximately $22.0 million of capital expenditures accrued and booked on wells in progress at the end of 2008 for which no new reserves were booked as of December 31, 2008.

NET INCOME

Net income applicable to common stock for the fourth quarter of 2008 was a loss of $0.3 million ($(0.01) per share) which compares to a fourth quarter 2007 loss applicable to common stock of $22.1 million ($(0.83) per share). Results for the fourth quarter of 2008 included a $40.5 million non-cash gain on derivatives not designated as hedges and a $27.5 million non-cash impairment charge to oil and gas properties at year end 2008 as a result of impairments primarily at the Company’s West Brachfield field, a

non-core area in East Texas. For the full year 2008, the Company reported net income applicable to common stock of $130.2 million, which included a $145.9 million gain on sale of assets (primarily related to the Chesapeake transaction) and a $54.0 million non-cash gain on derivatives not designated as hedges, versus a loss applicable to common stock of $51.1 million for 2007, which included a $16.1 million non-cash loss on derivatives not designated as hedges.

CASH FLOW

Earnings before interest, taxes, DD&A, non-cash general and administrative expenses and exploration (“EBITDAX”), increased 37% to approximately $26.9 million for the fourth quarter, compared to $19.7 million in the prior year period. EBITDAX for the year increased 97% to $146.7 million, compared to $74.6 million in the prior year period (see 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, increased to $17.4 million in the quarter, compared to $15.6 million in the prior year period. Note that DCF for the fourth quarter of 2008 was negatively impacted by approximately $4.7 million in adjustments related to final tax entries made in conjunction with the Company’s sale of assets in the third quarter of 2008. Discretionary cash flow increased to $113.8 million for the year, a 67% increase over the $68.1 million in the prior year period (note that DCF is not adjusted for discontinued operations). Net cash provided by operating activities was $107.0 million for the year, compared to $85.9 million for the prior year period (see 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 quarter increased by 36% to $44.1 million, versus $32.5 million for the prior year period. Revenues for the quarter decreased by 37% sequentially from the third quarter of 2008, due to a significant decline in oil and gas prices during the fourth quarter. Average net oil and gas prices received in the fourth quarter were $6.68 per Mcf of gas and $56.30 per barrel of oil. Total revenues and average prices received in the fourth quarter do not include realized gains of $1.3 million received on the Company’s settled oil and gas derivatives, none of which were designated as hedges during the quarter.

Total revenues for the year increased by 94% to $216.1 million versus $111.3 million for the prior year period. Average net oil and gas prices received for the year were $8.59 per Mcf of natural gas and $97.70 per barrel of oil, versus $6.69 per Mcf of natural gas and $71.83 per barrel of oil from the previous period. Total revenues and average prices received during the year do not include realized losses of $1.8 million paid on the Company’s settled oil and gas derivatives, none of which were designated as hedges during the year.

OPERATING INCOME

Operating income, defined as revenues minus operating expenses, totaled a loss of $32.2 million for the quarter versus an operating loss of $13.6 million for the prior year period, primarily due to the $27.5 million impairment charge taken during the fourth quarter of 2008 at the Company’s West Brachfield field, a non-core area in East Texas. Operating income for the year totaled $145.4 million, due largely to the previously mentioned gain on sale of assets of approximately the same amount, versus an operating loss for 2007 of $35.2 million.

OPERATING EXPENSES

Operating expenses were $76.4 million during the quarter, including the previously mentioned impairment charges. Lease operating expenses (“LOE”) totaled $9.0 million in the quarter, or $1.39 per Mcfe, versus $7.0 million, or $1.50 per Mcfe during the fourth quarter of 2007. For the year, LOE totaled $32.0 million in 2008, or $1.32 per Mcfe, versus $22.5 million, or $1.40 per Mcfe in 2007, with the decrease on a per unit basis due primarily to many of the fixed cost components of LOE being spread over the higher production volumes achieved by the Company. First quarter 2009 guidance for LOE is between $1.10 and $1.30 per Mcfe for core LOE and $0.05 to $0.15 per Mcfe for workovers, for a total of $1.15 — $1.45 per Mcfe. The Company currently has salt water disposal facilities in place in the North Minden field and Bethany Longstreet fields, and expects to have facilities in place in the Cotton South area of the Angelina River trend by the end of the first quarter, which should reduce per unit LOE going forward. Additionally, as the Company adds production volumes from the Haynesville Shale formation, LOE per Mcfe is expected to decline since Haynesville production does not require as much water handling or compression as compared to our traditional Cotton Valley trend production.

General and Administrative (G&A) expenses were $6.7 million during the quarter, or $1.03 per Mcfe, versus $5.0 million, or $1.08 per Mcfe during the corresponding quarter in 2007. Absolute G&A expenses were higher over the prior year period due primarily to a higher headcount at December 31, 2008. For the year, G&A expenses totaled $24.3 million, or $1.00 per Mcfe, versus $20.9 million, or $1.31 per Mcfe for the full year 2007, with the absolute increase in the year over year period due primarily to higher staffing levels associated with the Company’s increased levels of activity. For the quarter, the Company recorded non-cash general and administrative expenses related to stock based compensation for its officers, employees and directors of $1.5 million. For the full year, the Company recorded non-cash G&A expense related to stock based compensation of approximately $5.5 million, or approximately 23% of total G&A for the year.

CAPITAL EXPENDITURES

The Company drilled and cased 127 gross (76 net) wells during the year and conducted drilling or completion operations on 138 gross (82 net) wells in 2008 with a 98% success rate. The Company had to permanently abandon three wells during the year for mechanical reasons, otherwise the results would have been 100% successful.

Capital expenditures for the quarter and year totaled $99.5 million and $380.1 million respectively, compared to $84.4 million and $300.2 million in the prior year’s quarter and year respectively. Approximately 95%, or $94.3 million of the capital expenditures in the quarter and approximately 91%, or $345.8 million of the capital expenditures for the year were associated with drilling and completion costs. Of the total capital expenditures of $380.1 million, approximately $20.0 million in leasehold costs and $60.0 million in drilling and completion costs were incurred on 24 wells penetrating the Haynesville Shale formation, for which only approximately 4.7 Bcfe of Haynesville Shale reserves were booked at December 31, 2008 due to the various stages of completion of those wells.

For the year 2009, the Company has preliminarily budgeted total capital expenditures of approximately $300.0 million, of which approximately 65%, or $195.0 million, is expected to be focused on drilling horizontal wells in the Haynesville Shale program in East Texas and North Louisiana, where the Company and its partners plan to average approximately 5 rigs working throughout 2009. The remainder of the budgeted amount is earmarked for horizontal wells in the James Lime in the Angelina River trend, several Cotton Valley horizontal wells in East Texas, and various leasehold and infrastructure expenditures as needed across the Company’s entire acreage block.

COMMODITY HEDGE POSITION

As of December 31, 2008, the Company had 60,000 MMbtu per day hedged for all of calendar year 2009 via a combination of swaps and collars. As the swaps average $8.54 per MMbtu on a NYMEX adjusted basis, and the collars have floors averaging $8.75 per MMbtu, we calculate a weighted average minimum hedge price of $8.61 per MMbtu for our hedged volumes this year. Additionally, the Company has locked in its basis on future volumes, with 20,000 MMbtu per day basis hedged for calendar year 2009 at $0.38 and 40,000 MMbtu per day basis hedged for March through December 2009 at $0.52, for an average of $0.47 per MMbtu basis hedged for March through December of 2009.

LIQUIDITY

The Company exited 2008 with approximately $148 million in cash and short term investments and no borrowings under its senior bank revolving credit facility, where the Company currently has a borrowing base of $175 million. When considering the Company’s strong hedge position, its cash and short term investment balances at year end, and our previously stated 30 to 40% production growth forecast for 2009, we believe we will not need to draw under our bank credit facility, nor will we need to access the capital markets during 2009 in order to fund our current capital expenditure budget of $300 million for 2009. Rather, we expect to finance these expenditures through a combination of cash flow from operations and cash and short term investments on hand at December 31, 2008. This is predicated upon numerous assumptions as to oil and gas prices, drilling activity and resultant production additions, and many other factors which are subject to change and are outside of the Company’s control.

OPERATIONAL UPDATE

DRILLING

The Company completed and added to production 12 Cotton Valley trend wells during the fourth quarter. Through year end the Company had drilled and logged a total of 414 Cotton Valley trend wells, with a success rate in excess of 98%. The Company currently has five operated drilling rigs under contract and expects that number to decline to three by the fourth quarter of 2009.

During 2008, the Company initiated its drilling activities in the Haynesville Shale play of East Texas and North Louisiana, participating in a total of 24 wells in the last half of the year which penetrated the Haynesville Shale formation with either vertical or horizontal wellbores. As the majority of the wells completed by year end were vertical pilot hole penetrations meant primarily to validate the presence of the formation for future horizontal drilling opportunities, relatively minor proved reserves were booked in the play at December 31, 2008. As the Company expands its drilling operations in the Haynesville Shale as detailed below, a greater percentage of reserves and production should be attributable to this play over time. The Company has an interest in two operated and four non-operated Haynesville Shale horizontal wells currently being drilled.

ACREAGE

At year end, the Company had 203,000 gross (127,000 net) acres in the Cotton Valley trend in eight counties in Texas and three parishes in Louisiana, which currently yields approximately 2,000 possible drilling locations. Of the previously mentioned acreage, the Company believes approximately 100,000 gross (63,000 net) acres are currently prospective for Haynesville Shale development.

OPERATIONS

The Company’s fourth quarter production operations were impacted by delays resulting from (1) longer cycle times associated with the drilling of Haynesville Shale horizontal wells; (2) pipeline and infrastructure installation for the Company’s initial four discovery wells drilled on its Surprise prospect at Angelina River trend; and (3) third party pipeline and gathering system maintenance in the Beckville and Minden areas, all of which contributed to the Company having 25 wells either in the process of drilling or completion or awaiting pipeline connections at year end 2008. As a result, fourth quarter production volumes were lower than originally anticipated. As of the date of this release, the Company has recently brought onto production 16 of the 25 wells which were in process or awaiting pipeline installation as of December 31, 2008.

Drilling operations accelerated significantly in the Haynesville Shale trend during the fourth quarter, as the Company and its partners commenced or completed drilling operations on a total of 24 wells (fifteen vertical and nine horizontal) by the end of the fourth quarter. Additionally, the Company continued its traditional Cotton Valley trend operations, drilled and cased a total of 21 wells in the Cotton Valley, Travis Peak, or James Lime formations in the quarter.

At December 31, 2008, the Company had 398 wells producing in the Cotton Valley trend, including nine wells producing from vertical Haynesville Shale penetrations.

SPECIFIC FIELD ACTIVITIES

BETHANY-LONGSTREET FIELD, CADDO AND DESOTO PARISHES, LOUISIANA

The Company has drilled and completed its second horizontal Haynesville Shale well in the field, the Chesapeake Energy Corporation — Graham 14H-1 (50% working interest, or WI), a 4,600 foot lateral completed with ten frac stages. The well is producing on a reduced choke of 20/64 inch choke with a 24 hour production rate of 11,400 Mcf per day and a ten day average of 11,200 Mcf per day.

The Company has drilled and is expected to complete the Chesapeake Energy Corporation — Branch 11H-1 (50% WI) and ROTC 1H-1 (50% WI) wells in March 2009.

The Company anticipates drilling 17 gross (seven net) Haynesville Shale horizontal wells in Bethany-Longstreet field during 2009, and currently has three rigs running in the field.

LONGWOOD FIELD, CADDO PARISH, LOUISIANA

The initial horizontal Haynesville Shale well in the Longwood field has been completed, the Chesapeake Energy Corporation — Percy Sharp 7H-1 (50% WI). The well, which was drilled with an approximate 4,600 foot lateral, had eight of twelve frac stages pumped to completion and tested at 5,100 Mcf per day on a 22/64 inch choke, with an average of 4,300 Mcf per day over a twenty day period. Results to date indicate, the well’s estimated ultimate recovery (“EUR”) is at the low end of the Company’s previously stated estimated range of 4.5 – 8.5 Bcfe per well for a Haynesville Shale horizontal well.

The Company has drilled its Chesapeake Energy Corporation — Bohnert 28H-1 (50% WI) with a 4,500 foot lateral which is scheduled to be completed in March 2009, and is participating in the Exco Resources — Sharp 1H-1 (17% WI), which is currently drilling.

CADDO PINE ISLAND FIELD, CADDO PARISH, LOUISIANA

The Company has participated in the completion of the Matador Resources Company — Hall 9H-1 (50% WI) in northern Caddo Parish, Louisiana. The well tested at a rate of 2,600 Mcf per day on a 24/64 inch choke with 2,200 psi from a ten stage frac.

Caddo Pine Island comprises 2,900 net acres out of the Company’s 62,000 net acres prospective for the Haynesville Shale.

ANGELINA RIVER TREND, ANGELINA AND NACOGDOCHES COUNTIES, TEXAS

Surprise Prospect. In the third quarter of 2008, the Company acquired a 50% operated interest in approximately 5,000 gross acres in Nacogdoches County, Texas, targeting the Travis Peak, James Lime, Bossier and Haynesville Shale. Since closing the acquisition, the Company has drilled four wells and is currently drilling its fifth.

The Company has completed its Hill No. 1 (50% WI), a vertical Bossier Sand well, at 9,400 Mcf per day on a 16/64 inch choke with 7,150 psi.

The Company has completed its Tucker No. 1 (50% WI) in the Haynesville Shale. The well, which was a vertical test, encountered 200 feet of thickness in the Haynesville Shale, and had an initial production rate of approximately 600 Mcf per day. The well is currently being completed in the Bossier Shale and will ultimately be completed in the Travis Peak as well.

The Lilly No. 1 (50% WI) and Grigsby No. 1 (50% WI) have been drilled and completed in the Travis Peak, with initial production rates of 3,000 Mcf per day and 2,900 Mcf per day, respectively.

The Company is currently drilling its Lewis No. 1 (50% WI), with plans to test the Bossier and Haynesville Shales, as well as the Travis Peak.

Cotton South Prospect.The Company has completed its Mims 1H-1 (100% WI), a horizontal James Lime well with an approximate 6,000 foot lateral. The well had an initial production rate of 7,500 Mcf per day on a 26/64 inch choke and has averaged approximately 7,000 Mcf per day over a six day period. The Company has also participated for a 40% working interest in two Travis Peak wells during the fourth quarter, with an average initial production rate of 5,100 Mcf per day.

BECKVILLE AND MINDEN FIELDS, PANOLA AND RUSK COUNTIES, TEXAS

The Company has completed its initial horizontal Cotton Valley Taylor sand well, the G.T. Waldrop 3H-1 (100% WI), with an initial production rate of 4,800 Mcf per day on a 52/64 inch choke with 1,000 psi and approximately 23% of the frac fluid recovered to date. The well was drilled with an approximate 3,500 foot lateral and was completed with eight frac stages. The Company is currently drilling its second horizontal Cotton Valley Taylor sand well, the KF Carter B2-1H (100% WI), with current plans to drill a total of five horizontal Cotton Valley Taylor wells in 2009.

In the Haynesville Shale, the Company has now drilled seven vertical delineation wells, which encountered thicknesses ranging from 100 to 200 feet. The Lutheran Church 5H-1 (100% WI), the Company’s initial horizontal Haynesville Shale well in the field is currently drilling in the lateral section and is anticipated to be completed within 45 days. The Company encountered a mechanical problem while drilling the vertical section at 6,600 feet in the original wellbore, which caused the Company to abandon the shallow wellbore and re-drill the well. The Company is also currently drilling a second horizontal

Haynesville Shale well, the J.K. Williams 7H-1 (100% WI) and expects to complete it in the second quarter.

The Company has tested the Haynesville Shale in its Joe Bailey Hillin No. 1 (100% WI), a vertical well with approximately 100 feet of thickness in the Haynesville, at a rate of 1,300 Mcf per day. The Company has also tested the upper Bossier Shale in the well, which has approximately 180 feet of thickness, at 700 Mcf per day. The Company has plans to commingle the Haynesville Shale and Bossier Shale with the Cotton Valley, which had an initial production rate of 2,200 Mcf per day.

MANAGEMENT COMMENT

Commenting on the results, the Company’s Vice-Chairman and CEO Walter G. “Gil” Goodrich stated, “2008 was both a challenging and rewarding year for Goodrich Petroleum and its shareholders. With the discovery of the Haynesville Shale in northwest Louisiana last March, we immediately adjusted our drilling plans and initiated the drilling of approximately a dozen Haynesville Shale vertical delineation wells designed to prove up and de-risk our core acreage in northwest Louisiana and East Texas for the Haynesville Shale. These wells were highly successful in delineating and defining the prospectivity of the Haynesville Shale across approximately 63,000 net acres. The rapid implementation of the Haynesville Shale delineation plan allowed us to enact two significant transactions last summer, including the joint venture with Chesapeake Energy Corporation and a follow-on equity offering, which collectively brought in approximately $365 million and dramatically improved our balance sheet, as well as our inventory of development opportunities. We have now transitioned into the horizontal development phase for the Haynesville Shale and we are encouraged by our early initial results. We successfully grew production by 51% in 2008, even though approximately $60 million of our capital expenditures was spent on vertical delineation vertical wells and horizontal Haynesville Shale wells in which we had very little production or reserves at year end. Using a $7.50 per MMbtu price deck, our reserves would have grown by 30% versus 12% using year end SEC pricing of $5.71 per MMbtu of gas. In addition, we remained very active in the Angelina River trend for both the Travis Peak and the James Lime, where results have been very good. We also recently initiated a horizontal development plan for the Taylor Sand in the Cotton Valley in the Beckville and Minden fields and we are very pleased with the initial results. All of the accomplishments of 2008 have us extremely well positioned to continue with the execution of our strategy, further transitioning into horizontal development of the Haynesville Shale, while maintaining a solid balance sheet and weathering the current economic conditions. Naturally, if these poor market conditions persist, our drilling budget for the latter part of this year and into 2010 can be readily adjusted to meet such circumstances.”

OTHER INFORMATION

In this press release, the Company refers to several non-GAAP financial measures, EBITDAX, discretionary cash flow, Drilling and Completion capital expenditures, and Pre tax present worth discounted at 10%. Management believes that the first two of these measures are good financial indicators of the Company’s ability to internally generate operating funds, while the third is a useful measure of the Company’s annual drilling expenditures and the last is an alternative measure for valuing the Company’s proved reserves. Management also believes that these non-GAAP financial measures 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 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, nor should Drilling and Completion capital expenditures be

considered an alternative to Costs incurred in oil and gas property acquisition, exploration, and development activities, as defined by GAAP .

The Company has provided the alternative proved reserve estimates in this release assuming natural gas prices other than those in effect on December 31, 2008 solely for illustrative purposes to demonstrate hypothetically the effect that year end economic conditions have on the Company’s proved reserve estimates. The natural gas price used in one of these alternative presentations was selected by management based upon a review of longer term forward trading prices on the NYMEX, but does not necessarily reflect management’s views as to future prices. The United States Securities and Exchange Commission (“SEC”) has generally permitted oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under economic and operating conditions existing at the date of the report. Accordingly, the SEC guidelines may prohibit us from including these alternatively priced proved reserve estimates in filings with the SEC.

Initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. In particular, production from horizontal drilling in shale gas resource plays and tight gas plays that are stimulated with extensive pressure fracturing are typically characterized by significant early declines in production rates.

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 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 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						Year Ended
	December 31,						December 31,
	2008			2007			2008			2007
Total Revenues	$	44,149		$	32,477		$	216,051		$	111,305
Operating Expenses
Lease operating expense		9,019			6,965			31,950			22,465
Production and other taxes		1,843			1,276			7,542			2,272
Transportation		2,165			1,734			8,645			5,964
Depreciation, depletion and amortization		26,591			22,163			107,123			79,766
Exploration		2,563			1,499			8,404			7,346
Impairment of oil and gas properties		27,523			7,414			28,582			7,696
General and administrative		6,687			4,996			24,254			20,888
Loss (Gain) on sale of assets		(8	)		67			(145,876	)		(42	)
Other		—			—			—			109
Operating income (loss)		(32,234	)		(13,637	)		145,427			(35,159	)
Other income (expense)
Interest expense		(3,803	)		(3,938	)		(15,862	)		(11,870	)
Interest income		924			—			2,184			—
Gain (Loss) on derivatives not designated as hedges		41,504			(2,964	)		51,547			(6,439	)
		38,625			(6,902	)		37,869			(18,309	)
Income (loss) from continuing operations before income taxes		6,391			(20,539	)		183,296			(53,468	)
Income tax benefit (expense)		(4,427	)		345			(46,556	)		(3,034	)
Income (loss) from continuing operations		1,964			(20,194	)		136,740			(56,502	)
Discontinued operations:
Gain (loss) on disposal, net of tax		1			(161	)		29			9,662
Income (loss) from discontinued operations, net of tax		(771	)		(271	)		(531	)		1,807
		(770	)		(432	)		(502	)		11,469
Net income (loss)		1,194			(20,626	)		136,238			(45,033	)
Preferred stock dividends		1,512			1,512			6,047			6,047
Net income (loss) applicable to common stock	$	(318	)	$	(22,138	)	$	130,191		$	(51,080	)
Income (loss) per common share from continuing operations
Basic	$	0.05		$	(0.75	)	$	4.04		$	(2.21	)
Diluted	$	0.05		$	(0.75	)	$	3.49		$	(2.21	)
Income (loss) per common share from discontinued operations
Basic	$	(0.02	)	$	(0.02	)	$	(0.01	)	$	0.45
Diluted	$	(0.02	)	$	(0.02	)	$	(0.01	)	$	0.45
Net income (loss) per common share applicable to common stock
Basic	$	(0.01	)	$	(0.83	)	$	3.85		$	(2.00	)
Diluted	$	(0.01	)	$	(0.83	)	$	3.48		$	(2.00	)
Weighted average common shares outstanding:
Basic		35,904			26,771			33,806			25,578
Diluted		35,904			26,771			40,397			25,578

GOODRICH PETROLEUM CORPORATION

Selected Cash Flow Data (In Thousands):

	Three Months Ended						Year Ended
	December 31,						December 31,
	2008			2007			2008			2007
Calculation of EBITDAX:
Revenue		44,149			32,477			216,051			111,305
Lease operating expense		(9,019	)		(6,965	)		(31,950	)		(22,465	)
Production and other taxes		(1,843	)		(1,276	)		(7,542	)		(2,272	)
Transportation		(2,165	)		(1,734	)		(8,645	)		(5,964	)
G&A — cash portion only		(5,204	)		(3,964	)		(18,761	)		(15,606	)
Realized gain (loss) on derivatives not designated as hedges		988			1,141			(2,448	)		9,640
EBITDAX		26,906			19,679			146,705			74,638
Reconciliation of EBITDAX to Net Cash Provided by Operating Activities:
EBITDAX		26,906			19,679			146,705			74,638
EBITDAX — Discontinued Operations		28			32			397			5,779
Exploration		(2,563	)		(1,499	)		(8,404	)		(7,346	)
Prospect amortization		1,669			1,116			5,838			6,211
Dry Hole		312			—			312			—
Interest expense		(3,803	)		(3,938	)		(15,862	)		(11,870	)
Interest income		924			—			2,184			—
Current Income taxes		(6,688	)		—			(19,367	)		—
Other non-cash items		605			259			1,970			658
Net changes in working capital		(8,572	)		8,688			(6,734	)		17,855
Net cash provided by operating activities (GAAP)		8,818			24,337			107,039			85,925
Reconciliation of Discretionary Cash Flow to Net Cash Provided by Operating Activities:
Discretionary cash flow		17,390			15,649			113,773			68,070
Net changes in working capital		(8,572	)		8,688			(6,734	)		17,855
Net cash provided by operating activities (GAAP)		8,818			24,337			107,039			85,925

Selected Operating Data:

	Three Months Ended				Year Ended
	December 31,				December 31,
	2008		2007		2008		2007
Production — Continuing Operations:
Natural gas (MMcf)		6,212		4,435		23,174		15,281
Oil and condensate (MBbls)		44		34		167		118
Total (Mmcfe)		6,476		4,642		24,176		15,991
Average sales price per unit:
Natural gas (per Mcf)	$	6.68	$	6.60	$	8.59	$	6.69
Oil (per Bbl)		56.30		89.60		97.70		71.83
Natural gas and oil (per Mcfe)		6.79		6.97		8.91		6.92
Expenses per Mcfe:
Lease operating expense	$	1.39	$	1.50	$	1.32	$	1.40
Production and other taxes		0.28		0.32		0.31		0.14
Transportation		0.33		0.37		0.36		0.37
DD&A		4.11		4.77		4.43		4.99
Exploration		0.40		0.32		0.35		0.46
Impairment expense		4.25		1.60		1.18		0.48
General and administrative		1.03		1.08		1.00		1.31

GOODRICH PETROLEUM CORPORATION

Reconciliation of Non-GAAP Measures
(In Millions)

Capital Cost

Cost incurred in oil and gas property acquisition, exploration and development activities	$	422.2
Property acquisitions and unproved leasehold costs		(62.3	)
Exploration cost expensed		(2.2	)
Facilities and infrastructure		(4.5	)
Asset retirement obligations		(7.4	)
Capitalized drilling and completion cost	$	345.8

Oil and Gas Reserves Value

Pre-tax present worth discounted at 10% (PV-10)	$	169.8
Income taxes discounted at 10%		(2.4	)
Standardardized measure of oil and gas (SMOG)
	$	167.4