Exhibit 99.1

Item 6. Selected Financial Data

The following table sets forth our selected financial data and other operating information. The selected consolidated financial data in the table are derived from our consolidated financial statements. This data should be read in conjunction with the consolidated financial statements, related notes and other financial information included herein.

Statement of Operations Data:

	Year Ended December 31,
	2008			2007			2006			2005			2004
	(In thousands, except per share amounts)
Revenues:
Oil and gas revenues	$	215,369		$	110,691		$	73,933		$	34,986		$	3,759
Other		682			614			838			325			151
		216,051			111,305			74,771			35,311			3,910
Operating Expenses
Lease operating expense		31,950			22,465			12,688			3,494			306
Production and other taxes		7,542			2,272			3,345			2,136			205
Transportation		8,645			5,964			3,791			558			—
Depreciation, depletion and amortization		107,123			79,766			37,225			12,214			1,486
Exploration		8,404			7,346			5,888			5,697			955
Impairment of oil and gas properties		28,582			7,696			9,886			340			—
General and administrative		24,254			20,888			17,223			8,622			5,821
Gain on sale of assets		(145,876	)		(42	)		(23	)		(235	)		(50	)
Other		—			109			—			—			—
		70,624			146,464			90,023			32,826			8,723
Operating income (loss)		145,427			(35,159	)		(15,252	)		2,485			(4,813	)
Other income (expense):
Interest expense		(22,410	)		(17,878	)		(8,343	)		(2,359	)		(1,110	)
Interest Income		2,184			—			—			—			—
Gain (loss) on derivatives not designated as hedges		51,547			(6,439	)		38,128			(37,680	)		2,317
Loss on early extinguishment of debt		—			—			(612	)		—			—
		31,321			(24,317	)		29,173			(40,039	)		1,207
Income (loss) from continuing operations before income taxes		176,748			(59,476	)		13,921			(37,554	)		(3,606	)
Income tax (expense) benefit		(54,472	)		9,294			(4,940	)		13,144			8,594
Income (loss) from continuing operations		122,276			(50,182	)		8,981			(24,410	)		4,988
Discontinued operations including gain on sale of assets, net of income taxes		(502	)		11,469			(7,660	)		6,960			13,539
Net income (loss)		121,774			(38,713	)		1,321			(17,450	)		18,527
Preferred stock dividends		6,047			6,047			6,016			755			633
Preferred stock redemption premium		—			—			1,545			—			—
Net income (loss) applicable to common stock	$	115,727		$	(44,760	)	$	(6,240	)	$	(18,205	)	$	17,894
Income (loss) per common share from continuing operations:
Basic	$	3.61		$	(1.96	)	$	0.36		$	(1.05	)	$	0.26
Diluted	$	3.24		$	(1.96	)	$	0.35		$	(1.05	)	$	0.25
Income (loss) per common share from discontinued operations:
Basic	$	(0.01	)	$	0.45		$	(0.30	)	$	0.30		$	0.69
Diluted	$	(0.01	)	$	0.45		$	(0.30	)	$	0.30		$	0.66
Weighted average number of common shares outstanding:
Basic		33,806			25,578			24,948			23,333			19,552
Diluted		40,397			25,578			25,412			23,333			20,347

	Year Ended December 31,
	2008		2007		2006		2005		2004
	(In thousands)
Balance Sheet Data:
Total assets	$	1,038,287	$	589,233	$	478,573	$	296,526	$	127,977
Total long-term debt		226,723		185,449		165,216		30,000		27,000
Stockholders’ equity		665,348		312,781		228,026		181,589		65,307

1

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements

Certain statements in this report, including statements of our future plans, objectives, and expected performance of the Company, are forward-looking statements that are dependent upon certain events, risks and uncertainties that may be outside our control, and which could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to:

• planned capital expenditures;

• future drilling activity;

• our financial condition;

• business strategy;

• the market prices of oil and gas;

• economic and competitive conditions;

• legislative and regulatory changes; and

• financial market conditions and availability of capital.

There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates. The drilling of exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns. Lease and rig availability, complex geology and other factors can affect these risks. Although from time to time we make use of futures contracts, swaps, costless collars and fixed-price physical contracts to mitigate risk, fluctuations in oil and gas prices, or a prolonged continuation of low prices may adversely affect our financial position, results of operations and cash flows.

Overview

We are an independent oil and gas company engaged in the exploration, exploitation, development and production of oil and natural gas properties primarily in the Cotton Valley trend of East Texas and Northwest Louisiana, including the recently discovered Haynesville Shale play in the same general area. We operate as one segment as each of our operating areas have similar economic characteristics and each meet the criteria for aggregation as defined in the Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 131, Disclosures about Segments of an Enterprise and Related Information.

We seek to increase shareholder value by growing our oil and gas reserves, production revenues and operating cash flow. In our opinion, on a long term basis, growth in oil and gas reserves and production on a cost-effective basis are the most important indicators of performance success for an independent oil and gas company.

Management strives to increase our oil and gas reserves, production and cash flow through exploration and exploitation activities. We develop an annual capital expenditure budget which is reviewed and approved by our board of directors on a quarterly basis and revised throughout the year as circumstances warrant. We take into consideration our projected operating cash flow and externally available sources of financing, such as bank debt, when establishing our capital expenditure budget.

We place primary emphasis on our internally generated operating cash flow in managing our business. For this purpose, operating cash flow is defined as cash flow from operating activities as reflected in our Statement of Cash Flows. Management considers operating cash flow a more important indicator of our financial success than other traditional performance measures such as net income because operating cash flow considers only the cash expenses incurred during the period and excludes the non-cash impact of unrealized hedging gains and losses.

Our revenues and operating cash flow are dependent on the successful development of our inventory of capital projects with available capital, the volume and timing of our production, as well as commodity prices for oil and gas. Such pricing factors are largely beyond our control, however, we employ commodity hedging techniques in an attempt to minimize the volatility of short term commodity price fluctuations on our earnings and operating cash flow.

2

Cotton Valley Trend

Our relatively low risk development drilling program in the Cotton Valley trend is primarily centered in and around Rusk, Panola, Angelina, Nacogdoches, Cherokee, Harrison, Smith and Upshur Counties, Texas and DeSoto and Caddo Parishes, Louisiana. We continue to build our acreage position in the Cotton Valley trend and hold 201,203 gross acres as of December 31, 2008. As of year end 2008, we drilled and completed a cumulative total of 414 Cotton Valley trend wells with a success rate in excess of 98%. Our net production volumes from our Cotton Valley trend wells aggregated approximately 65,598 Mcfe per day in 2008, or approximately 99% of our total oil and gas production for the year.

2008 Haynesville Shale Transactions

Chesapeake Haynesville Joint Development

On June 16, 2008, we entered into a joint development agreement with Chesapeake Energy Corporation, or Chesapeake, to develop our Haynesville Shale acreage in the Bethany Longstreet and Longwood fields of Caddo and DeSoto Parishes, Louisiana. Chesapeake purchased the deep rights, including the Haynesville Shale, to approximately 10,250 net acres of oil and natural gas leasehold comprised of a 20% working interest in approximately 25,000 net acres in the Bethany Longstreet field and a 50% working interest in approximately 10,500 net acres in the Longwood field for net proceeds of $172.0 million. Chesapeake also purchased 7,500 net acres of deep rights in the Bethany Longstreet field from a third party (see Note 11 “Related Party Transactions” to our consolidated financial statements), bringing the ownership interest in the deep rights in both fields after closing to 50% each for us and Chesapeake. Chesapeake is the operator of the joint Haynesville Shale development. As a result of this transaction, we hold approximately 25,000 gross (12,500 net) acres in the deep rights in the Bethany Longstreet field and approximately 10,500 gross (5,250 net) acres in the deep rights in the Longwood field, both of which are currently believed to be prospective for the Haynesville Shale. Through our joint development arrangement with Chesapeake, we will continue to operate existing production and operate any new wells drilled to the base of the Cotton Valley sand, and Chesapeake will operate any wells drilled below the base of the Cotton Valley sand, including the Haynesville Shale.

We retained the shallow rights to the base of the Cotton Valley sand and the existing production and reserves with respect to our 70% working interest in the Bethany Longstreet field and our 100% working interest in the Longwood field. We also retained our interest in both the shallow and Haynesville Shale rights on all of our East Texas assets. During the third quarter of 2008, Chesapeake began drilling the Holland 17H No.1 as the first horizontal well on the joint acreage in Bethany Longstreet field. In the Longwood field, Chesapeake re-entered the Lona Johnson No.1 drilling it to the deeper Haynesville Shale as a horizontal well and recovered 154 feet of core from the formation to evaluate. During the fourth quarter of 2008, completion operations began on both of these wells and two horizontal Haynesville Shale development wells were spud in Bethany Longstreet field together with two Haynesville Shale wells in Longwood field. In 2009, we and Chesapeake plan to use approximately three rigs most of the year to drill 22 gross joint wells.

Caddo Parish Acquisition

On May 28, 2008, we acquired additional interests in the Cotton Valley trend, increasing our net exposure in the Haynesville Shale. We acquired approximately 3,665 net acres in Longwood field of Caddo Parish, Louisiana, through the issuance of 908,098 shares of our common stock valued at approximately $33.9 million. The purchase included interests in 25 gross wells, with approximately 1.1 Mmcfe per day of net production, and 5.2 Bcfe of proved reserves (77% developed) associated with the shallower Hosston and Cotton Valley formations. As of December 31, 2008, we had drilled and participated in three Haynesville wells.

Caddo Pine Island Acquisition

On June 10, 2008, we entered into a definitive agreement with a private company for the right to acquire over time a 50% non-operated interest in 5,800 gross (2,900 net) acres in the Caddo Pine Island field, north of and adjacent to our Longwood field in Caddo Parish, Louisiana. Total consideration paid was approximately $3.3 million, which was comprised of acreage costs for the 50% interest in the leasehold and the cost of a carried interest on the initial well drilled on the acreage. As of December 31, 2008, four wells had been drilled vertically to the Haynesville Shale on this acreage. In the fourth quarter of 2008, we re-entered two of these wells to drill them horizontally in the Haynesville Shale formation. Completion of the first horizontal well will start in the first quarter of 2009 and we expect to complete the other wells in the second quarter of 2009. In 2009, we plan to drill two additional horizontal Haynesville Shale wells on the acreage.

3

In connection with the Chesapeake joint development agreement, the Caddo Parish Acquisition and the Caddo Pine Island Acquisition, we have a total of approximately 22,000 net acres in North Louisiana which we believe to be prospective for the Haynesville Shale formation.

Initial Company Operated Haynesville Shale Drilling Program

As of December 31, 2008, we have been the operator on and drilled four vertical wells on our North Louisiana acreage and seven wells on our East Texas acreage, for a total of eleven vertical wells targeting the Haynesville Shale. In the fourth quarter of 2008, we began drilling our first operated horizontal Haynesville Shale well. We expect to complete this well in the first quarter of 2009. We expect that our development of the Haynesville Shale will continue in 2009 with the drilling and completion of nine company operated horizontal wells in East Texas.

Sale of South Louisiana Assets

On March 20, 2007, we completed the sale of substantially all of our assets in South Louisiana to a private company. The sale resulted in total proceeds of $72.3 million, net to us, after normal closing adjustments. We recognized a gain of $9.7 million (net of tax) in 2007. The effective date of the sale was July 1, 2006.

On August 4, 2008, we closed the sale of the St. Gabriel field to a private party for $0.1 million, resulting in a gain of $0.1 million. On August 12, 2008, we assigned our rights in the Bayou Bouillon field to a private party for a nominal amount. We realized a loss of $0.3 million. We continue to hold our interests in the Plumb Bob field. We have an asset retirement obligation of $1.4 million on the balance sheet for properties in the Plumb Bob field.

Overview of 2008 Results

• We achieved annual production volume growth of 51% with production growing from 16.0 Bcfe in 2007 to 24.2 Bcfe in 2008.

• We entered into an agreement with Chesapeake to jointly develop a portion of our Haynesville Shale acreage in Northwest Louisiana. We sold a portion of our interest in the Haynesville Shale deep rights at the Bethany Longstreet and Longwood fields to Chesapeake for net proceeds of $172.0 million resulting in a gain of $145.1 million. Chesapeake serves as operator for these properties.

• We established our presence in the Haynesville Shale play in Northwest Louisiana and East Texas and increased our ownership to approximately 63,000 net acres at December 31, 2008.

• We drilled and completed 126 gross (75.4 net) wells in 2008, as compared to 104 gross (64.65 net) wells in 2007.

• We raised net proceeds of $191.3 million from our equity offering in July 2008 and paid down all of the outstanding borrowings under our senior credit facility. We ended the year with $147.5 million in cash and short term investments.

• Estimated proved reserves grew 12% to approximately 402.3 Bcfe (approximately 390.4 Bcf of natural gas and 1.9 MMBbls of oil and condensate), with a PV-10 of $169.8 million (before discounted future income taxes of $2.4 million) and a standardized measure of $167.4 million, approximately 38% of which is developed.

• Capital expenditures totaled $380.1 million in 2008, versus $300.1 million in 2007.

• Our 2008 oil and gas revenues from continuing operations totaled $215.4 million compared to $110.7 million in 2007, a 95% increase.

• Net cash provided by operating activities increased $21.1 million from 2007, to $107.0 million in 2008.

• We reduced our total operating expenses by $0.90 per Mcfe from 2007 to 2008 excluding impairment expense and the impact of the $145.9 million gain on sale of assets during the third quarter of 2008 in making these calculations.

4

Summary Operating Information:

Continuing Operations	Year End December 31,										Year End December 31,
	2008		2007			Variance					2007			2006			Variance
	(In thousands, except for price data)
Revenues:
Natural gas	$	199,057	$	102,215		$	96,842		95	%	$	102,215		$	67,372		$	34,843		52	%
Oil and condensate		16,312		8,476			7,836		92	%		8,476			6,561			1,915		29	%
Natural gas, oil and condensate		215,369		110,691			104,678		95	%		110,691			73,933			36,758		50	%
Operating revenues		216,051		111,305			104,746		94	%		111,305			74,771			36,534		49	%
Operating expenses		70,624		146,464			(75,840	)	(52	)%		146,464			90,023			56,441		63	%
Operating income (loss)		145,427		(35,159	)		180,586		514	%		(35,159	)		(15,252	)		(19,907	)	(131	)%
Net income (loss) applicable to common stock		115,727		(44,760	)		160,487		359	%		(44,760	)		(6,240	)		(38,520	)	(617	)%
Net Production:
Natural gas (MMcf)		23,174		15,281			7,893		52	%		15,281			10,500			4,781		46	%
Oil and condensate (MBbls)		167		118			49		42	%		118			106			12		11	%
Total (MMcfe)		24,176		15,991			8,185		51	%		15,991			11,135			4,856		44	%
Average daily production (Mcfe/d)		66,054		43,811			22,243		51	%		43,811			30,507			13,304		44	%
Average Realized Sales Price Per Unit:
Natural gas (per Mcf)	$	8.59	$	6.69		$	1.90		28	%	$	6.69		$	6.42		$	0.27		4	%
Oil and condensate (per Bbl)		97.70		71.83			25.87		36	%		71.83			62.03			9.80		16	%
Average realized price (per Mcfe)		8.91		6.92			1.99		29	%		6.92			6.64			0.28		4	%

Results of Operations

For the year ended December 31, 2008, we reported net income applicable to common stock of $115.7 million, or $3.42 per share (basic) and $3.23 per share (diluted), on oil and gas revenues from continuing operations of $215.4 million. This compares to a net loss applicable to common stock of $44.8 million, or $1.75 per share (basic and diluted) for the year ended December 31, 2007, and a net loss applicable to common stock of $6.2 million, or $0.25 per share (basic and diluted) for the year ended December 31, 2006.

Some highlights for the year ended December 31, 2008 include:

• We recorded a $145.9 million gain on the sale of assets in a sale that closed in July 2008. This gain includes $145.1 million from the sale of a portion of our interest in the Haynesville Shale deep rights to Chesapeake.

• In conjunction with the decline in natural gas prices during late 2008, we recorded a $51.5 million gain on derivatives not designated as hedges for the year ended December 31, 2008. This includes a realized loss of $1.8 million and an unrealized gain of $55.4 million for our natural gas commodity contracts and a realized loss of $0.7 million and an unrealized loss of $1.4 million on our interest rate swaps.

• Our income tax expense for the year was reduced by a $15.3 million decrease in our valuation allowance related to our deferred tax assets. We released a majority of our valuation allowance in the third quarter of 2008 upon closing and recognizing a significant gain on the Chesapeake sale.

Operating Income

Year ended December 31, 2008 compared to year ended December 31, 2007

Revenues from continuing operations increased 94% compared to 2007, to a total of $216.1 million in 2008 due to a 51% increase in production and a 29% increase in the average realized price. Production increased year-to-year from 15,991 MMcfe to 24,176 MMcfe and our average realized price increased from $6.92 per Mcfe to $8.91 per Mcfe. The drilling and completion of 126 wells in the Cotton Valley trend resulted in the continued natural gas production growth for the company, even though we estimate we curtailed approximately 300 MMcfe of natural gas production in September 2008 as a result of Hurricane Ike. Operating expenses of $70.6 million for the year ended December 31, 2008, include the $145.9 million gain on sale of assets as a reduction in operating expenses and impairment expense of $28.6 million. Excluding the gain on sales of assets for 2008 and impairment expense for both 2008 and 2007, operating expenses of $187.9 million increased 35% or $49.1 million over 2007 operating expenses of $138.8 million (not including $7.7 million of impairment expense). This increase is a direct result of increased production from year-to-year. Although revenues were up significantly for the full year, we experienced a substantial reduction in revenues in the last half of 2008 versus the first half of the year, due to the substantial oil and natural gas price declines.

5

Year ended December 31, 2007 compared to year ended December 31, 2006

Operating revenues increased 49%, or $36.5 million, compared to 2006, to a total of $111.3 million in 2007 due to production increases and a slight increase in average realized price per Mcfe. Production increased 44% year-to-year from 11,135 MMcfe to 15,991 MMcfe and our average realized price increased 4% from $6.64 Mcfe to $6.92 per Mcfe. The drilling and completion of 95 wells in the Cotton Valley trend led to the gains in natural gas production for 2007. Operating expenses increased 63% to $146.5 million in 2007. The primary driver behind the $56.4 million increase in operating expenses was a $42.5 million increase in depreciation, depletion and amortization (“DD&A”) year-to-year.

	Year Ended December 31,									Year Ended December 31,
Operating Expenses (in thousands)	2008		2007		Variance					2007		2006		Variance
Lease operating expenses	$	31,950	$	22,465	$	9,485		42	%	$	22,465	$	12,688	$	9,777		77	%
Production and other taxes		7,542		2,272		5,270		232	%		2,272		3,345		(1,073	)	(32	)%
Transportation		8,645		5,964		2,681		45	%		5,964		3,791		2,173		57	%
Depreciation, depletion and amortization		107,123		79,766		27,357		34	%		79,766		37,225		42,541		114	%
Exploration		8,404		7,346		1,058		14	%		7,346		5,888		1,458		25	%
Impairment		28,582		7,696		20,886		271	%		7,696		9,886		(2,190	)	(22	)%
General and administrative		24,254		20,888		3,366		16	%		20,888		17,223		3,665		21	%
	Year Ended December 31,									Year Ended December 31,
Operating Expenses per Mcfe	2008		2007		Variance					2007		2006		Variance
Lease operating expenses	$	1.32	$	1.40	$	(0.08	)	(6	)%	$	1.40	$	1.14	$	0.26		23	%
Production and other taxes		0.31		0.14		0.17		121	%		0.14		0.30		(0.16	)	(53	)%
Transportation		0.36		0.37		(0.01	)	(3	)%		0.37		0.34		0.03		9	%
Depreciation, depletion and amortization		4.43		4.99		(0.56	)	(11	)%		4.99		3.34		1.65		49	%
Exploration		0.35		0.46		(0.11	)	(24	)%		0.46		0.53		(0.07	)	(13	)%
Impairment of oil and gas properties		1.18		0.48		0.70		146	%		0.48		0.89		(0.41	)	(46	)%
General and administrative		1.00		1.31		(0.31	)	(24	)%		1.31		1.55		(0.24	)	(15	)%

Operating Expenses

Year ended December 31, 2008 compared to year ended December 31, 2007

LOE decreased $0.08 per Mcfe, or 6%, on a per unit basis compared to 2007. Production gains of 51% year-over-year offset the impact of generally higher costs. On an absolute dollar basis, LOE increased $9.5 million or 42% for 2008 as compared to 2007. The largest cost components of LOE for 2008 include salt water disposal (“SWD”) costs of $9.7 million, compressor rental costs of $6.6 million and LOE for properties operated by others (“Non-Op”) of $2.0 million. SWD and compressor rental costs tend to fluctuate with production. As a result of increased production, SWD increased $3.0 million in 2008 ($9.7 million or $0.40 per Mcfe for 2008 versus $6.7 million or $0.42 per Mcfe for 2007). Compressor rental costs increased $2.1 million in 2008 ($6.6 million or $0.27 per Mcfe for 2008 versus $4.5 million or $0.28 per Mcfe for 2007). Both of these cost areas were relatively flat on a per Mcfe basis. Non-Op LOE also increased $1.1 million ($2.0 million or $0.08 per Mcfe for 2008 versus $0.9 million or $0.06 per Mcfe for 2007) due to a greater number of our properties being operated by others. The remaining $3.3 million increase year-to-year represents the increased cost of labor, services and chemicals partially offset by lower workover costs. Workover costs represented $0.16 per Mcfe of the LOE rate for 2007, while workover costs only represented $0.06 per Mcfe of the LOE rate for 2008, due to fewer workover projects slated for 2008.

Production and other taxes of $7.5 million for 2008 include production tax of $5.5 million and ad valorem tax of $2.0 million. For 2007, production and other taxes of $2.3 million include production tax of $1.1 million and ad valorem tax of $1.2 million. Production tax for 2008 is net of $3.2 million of accrued Tight Gas Sands (“TGS”) credits for our wells in the State of Texas, which credits equate to $0.13 per Mcfe of production. This compares to TGS credits of $3.9 million for 2007. These TGS credits allow for reduced and in many cases the complete elimination of severance taxes in the State of Texas for qualifying wells for up to ten years of production. We only accrue for such credits once we have been notified of the State’s approval. We also anticipate lower production tax rates in the future as we continue to add Cotton Valley trend wells to our production base and as credits are approved. Production taxes are higher for 2008 as the result of a 51% increase in production over 2007, as well as the higher prices received during the year.

6

Ad valorem taxes increased to $2.0 million for 2008 from $1.2 million for 2007. Ad valorem tax is assessed on the value of properties as of the first day of the year and is highly influenced by commodity prices for the prior several months. The number of properties we owned increased from January 1, 2007 to January 1, 2008 and the assessed values for our existing properties were higher year-to-year. The combination of these two factors led to the increase in ad valorem taxes year-to-year.

Transportation expense increased 45% to $8.6 million in 2008 compared to $6.0 million in 2007, as a result of a 51% increase in production year-to-year. The rate per Mcfe decreased slightly to $0.36 per Mcfe in 2008 from $0.37 the prior year.

DD&A expense increased to $107.1 million in 2008 from $79.8 million in 2007 due to a 51% increase in production year-to-year. The DD&A rate declined from $4.99 per Mcfe for 2007 to $4.43 per Mcfe for 2008. We calculated the first and second quarter 2008 DD&A rates using the December 31, 2007 reserves. During the third quarter of 2008, we engaged an independent engineering firm to fully engineer our June 30, 2008 proved reserve estimates. The mid-year reserve report was used to calculate the rate for the third and fourth quarters of 2008. The DD&A rate per Mcfe based on this report resulted in a DD&A rate of $4.17 per Mcfe and $4.11 per Mcfe for the third and fourth quarters of 2008, respectively. These rates are lower than the rates used for the first half of 2008 due to the cost effective drilling of wells in the first six months of 2008. We engaged the same firm to prepare a mid-year reserve report in 2007 as well as year-end reports since 2005.

Exploration expense for 2008 increased to $8.4 million from $7.3 million for 2007. The primary component of exploration expense for us is the amortization of undeveloped leasehold costs, which represented $5.8 million of the total. Exploration expenses on a per unit basis declined by 24% from $0.46 per Mcfe for 2007 to $0.35 per Mcfe for 2008. Exploration expenses include $0.3 million for exploratory dry hole costs.

We recorded impairment expense of $28.6 million in 2008, $27.5 million in connection with our independent engineer’s report on our reserves as of December 31, 2008. The expense relates to the Brachfield, Blocker, Alabama Bend and Gilmer Fields, which are located in non-core areas in North Louisiana and East Texas. We recorded an impairment expense of $7.7 million in 2007 for our Alabama Bend field and two wells in a non-core area of East Texas.

General and administrative (“G&A”) expense increased 16% to $24.3 million for 2008 compared to $20.9 million for 2007. G&A on a per unit basis decreased 24% to $1.00 per Mcfe resulting from a 51% increase in production volumes in 2008 as compared to 2007. This increase in costs results from a 33% increase in the number of employees from 86 at December 31, 2007 to 114 at December 31, 2008. Stock based compensation expense, which is a non-cash item, amounted to $5.5 million in 2008 compared to $5.3 million for 2007.

Year ended December 31, 2007 compared to year ended December 31, 2006

LOE for 2007 increased 78% to $22.5 million from $12.7 million for 2006. Generally higher operating costs, primarily SWD and compression costs, contributed to the majority of the increase in 2007. Most of our fields experienced increases in the cost of SWD due to rising fuel costs for trucking. We did see lower SWD costs for the year in the Beckville field, beginning in June 2007, when our East Texas low pressure gathering system (“LPGS”) in the Beckville field became operational. The LPGS lowers SWD costs by utilizing flowlines to pipe the water to the commercial SWD wells rather than hauling the water with trucks. Higher workover costs also contributed to the higher LOE. Workover costs rose $0.13 per Mcfe with increased activity in the Beckville and North Minden fields ($2.6 million or $0.16 per Mcfe in 2007 vs. $0.3 million or $0.03 per Mcfe in 2006).

Production and other taxes of $2.3 million for 2007 consist of production tax of $1.1 million and ad valorem tax of $1.2 million. Production and ad valorem taxes in 2006 were $2.9 million and $0.4 million, respectively. Production tax in 2007 included $3.9 million of accrued TGS credits for our wells in the State of Texas. Ad valorem tax is assessed on the value of properties as of the first day of the year. The number of properties we owned increased from January 1, 2006 to January 1, 2007 and the assessed values for our existing properties were higher year-to-year. The combination of these two factors led to the increase in ad valorem taxes year-to-year.

Transportation expense was $6.0 million in 2007 compared to $3.8 million for 2006 as production volumes increased 44 % year-over-year. The unit cost increased nine percent (from $0.34 per Mcfe in 2006 to $0.37 per Mcfe in 2007) due to an increase in production rates from fields requiring greater transportation, and due to several contracts entered into which transported gas to higher valued markets.

DD&A expense increased to $79.8 million in 2007 from $37.2 million for 2006 primarily due to a higher DD&A rate coupled with higher levels of production. Since we use the successful efforts method of accounting, our DD&A rate is primarily a function of our capitalized drilling, completion and facilities costs divided by our proved developed reserves. Beginning in late 2004/early 2005

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we embarked on an aggressive drilling program to fully develop our extensive East Texas / North Louisiana Cotton Valley trend acreage position during a period of record high costs for drilling and completion services. Additionally, to hold the majority of our acreage and thereby allow for the most prudent development plan going forward, we chose to drill many wells in the outlying areas of our acreage block, where per well results were less certain than in the initial established areas. Finally, many of our initial wells in certain fields required us to pay the costs of other industry partners to earn access to the full acreage position.

We calculated first and second quarter 2007 DD&A rates using the December 31, 2006 reserves, which did not recognize any impact of our 2007 Cotton Valley trend drilling program reserve additions. During 2007, we engaged NSA, our independent reserve engineers, to fully engineer our June 30, 2007 proved reserve estimates. This mid-year reserve report was used to calculate rates for the third and fourth quarters of 2007. As mentioned above, the DD&A rate per Mcfe based on this report was $4.77, which was lower than the rate used for the first half of this year primarily due to the inclusion of more wells drilled in our core areas during the first half of this year relative to the mix of wells in the December 31, 2006 reserve report.

Exploration expenses for 2007 increased to $7.3 million from $5.9 million for 2006. Exploration expenses on a per unit basis declined to $0.46 per Mcfe in 2007 from $0.53 per Mcfe in 2006. The increase in exploration expense year-to-year relates to an increase in leasehold amortization, a non-cash expense and the largest component of exploration expense. We increased our undeveloped acreage position from last year which resulted in higher leasehold cost amortization of $6.1 million for 2007, compared to $4.8 million in the same period last year.

We recorded an impairment expense of $7.7 million for the year ended December 31, 2007, $6.1 million of which related to our Alabama Bend field located in the other Cotton Valley trend leasehold area. We also recorded an impairment expense of $1.4 million and $0.3 million in the fourth and third quarters of 2007, respectively, related to two wells in a non-core area of East Texas. We recorded impairment expense in conjunction with the receipt of the independent engineer’s year-end and mid-year reports on reserves.

G&A expense increased to $20.9 million for 2007, compared to $17.2 million for 2006, resulting from generally higher compensation costs and a Louisiana franchise tax payment made under protest. G&A on a per unit basis decreased 17% as a result of higher production volumes in 2007. Salaries and benefits account for a large portion of total G&A. After the sale of substantially all of our properties in South Louisiana in March 2007, we had 74 employees. As of December 31, 2007, we had 86 employees. We paid $0.3 million in severance to employees in conjunction with the sale of all of our South Louisiana properties in March 2007. G&A for the year also includes a $0.3 million non-cash charge for the acceleration of vesting of options and restricted stock associated with the resignation of an officer of the Company effective August 30, 2007.

We accrued a liability for $1.0 million in March 2007, representing $0.4 million in penalties and interest and $0.6 million the State of Louisiana asserts we owe for franchise taxes (see Note 9 “Discontinued Operations” to our consolidated financial statements). While we paid this amount under protest in April 2007, we plan to pursue the reimbursement of the full $1.0 million. Should our efforts prevail, the amounts paid under protest would be refunded.

	Year Ended December 31,
	2008			2007			2006
	(In thousands)
Other Income (Expense):
Interest expense	$	(22,410	)	$	(17,878	)	$	(8,343	)
Interest Income		2,184			—			—
Gain (loss) on derivatives not designated as hedges		51,547			(6,439	)		38,128
Loss on early extinguishment of debt		—			—			(612	)
Income tax benefit (expense)		(54,472	)		9,294			(4,940	)
Gain on disposal, net of tax		29			9,662			—
Income (loss) from discontinued operations, net of tax		(531	)		1,807			(7,660	)
Average total borrowings		271,212			235,712			99,542
Weighted average interest rate		8.3	%		7.6	%		8.4	%

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Other Income (Expense)

Year ended December 31, 2008 compared to December 31, 2007

Interest expense increased by $4.5 million, or 25%, to $22.4 million for 2008 compared to $17.9 million for 2007 as a result of a higher average level of borrowings in 2008, and a slightly higher weighted average interest rate. We added a second lien term loan in January 2008 for $75.0 million, which carries a higher interest rate than both our Senior Credit Facility and our convertible senior notes. In July 2008, we paid off all amounts outstanding under our Senior Credit Facility with the proceeds from the sale of assets and an equity offering. We ended the year with no amounts outstanding under our Senior Credit Facility.

We invested the net proceeds from our equity offering and the sale of assets, both in July 2008, in money market funds and time deposits with certain acceptable institutions, subject to our newly implemented Short Term Investment Policy. The income earned on these investments during 2008 is reflected in the Interest income line.

Gain on derivatives not designated as hedges was $51.5 million for 2008, including a realized loss of $1.8 million and an unrealized gain of $55.4 million for the change in fair value of our natural gas commodity contracts. The decrease in natural gas prices experienced during the last half of 2008 led to substantial unrealized gains on our commodity contracts. The 2008 gain also includes a realized loss of $0.7 million and an unrealized loss of $1.4 million on our interest rate swap. As a comparison, 2007 includes an unrealized loss of $15.6 million for the changes in fair value of our commodity contracts, a realized gain of $9.5 million and a loss of $0.3 million on our interest rate swap. We will continue to be exposed to volatility in earnings resulting from changes in the fair value of our commodity contracts as we do not designate these contracts as hedges.

In July 2008, we realized a significant gain on the sale of assets related primarily to our sale of deep rights acreage to Chesapeake which helped generate income from continuing operations before taxes of $183.3 million for 2008. As a result of the significant gain generated by the sale, we believe that we will be in a position to utilize the majority of our net operating loss carryforwards when we file our 2008 tax return. We believe it is now more likely than not that we will be able to recognize our deferred tax assets associated with these net operating loss carryforwards. As a result, we released $15.3 million of our previously booked valuation allowance in the third quarter of this year. The impact of this is to reduce income tax expense for the year to a total of $54.2 million. Primarily as a result of the Chesapeake sale, our 2008 estimated income tax liability to the State of Louisiana is $10 million, which is included in the total of $54.2 million.

In a sale that closed March 20, 2007, we sold our assets in South Louisiana to a private company. We realized a gain of $9.7 million, net of tax, in 2007. In August 2008, we closed on the sale of our St. Gabriel field to a private company for $0.1 million. Also in August 2008, we assigned our rights in the Bayou Bouillon field to a private party for a nominal amount. We continue to hold our interests in the Plumb Bob field. Loss from discontinued operations, net of tax of $0.5 million for 2008 includes an impairment of our Plumb Bob field for $1.2 million before tax ($0.8 million net of tax) in connection with our independent engineer’s report on reserves as of December 31, 2008.

Year ended December 31, 2007 compared to December 31, 2006

Interest expense was $17.9 million for 2007, compared to $8.3 million for 2006, with the increase primarily attributable to a higher level of average borrowings in 2007. With the issuance of 3.25% convertible notes in December 2006, the weighted average interest rate fell slightly to 7.6% in 2007 compared to 8.4% in 2006.

Loss on derivatives not designated as hedges was $6.4 million for 2007, compared to a gain of $38.1 million for 2006. The loss in 2007 includes an unrealized loss of $15.6 million for the change in fair value of our gas and oil hedges, and a realized gain of $9.5 million for the effect of settled derivatives. The loss also includes an unrealized loss of $0.5 million and a realized gain of $0.2 million on our interest rate swap. We did not designate any of our oil and gas derivates as hedges for 2007. Our natural gas hedges were ineffective in 2006, and certain oil hedges were deemed ineffective in the fourth quarter of 2006 thereby rendering all of our commodity derivatives ineffective. For these ineffective hedges, we are required to reflect the changes in the fair value of the hedges in earnings rather than in accumulated other comprehensive loss, a component of stockholders’ equity. As applied to our hedging program, there must be a high degree of correlation between the actual prices received and the hedge prices to justify treatment as cash flow hedges pursuant to SFAS No. 133 Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”). We perform historical correlation analyses of the actual and hedged prices over an extended period of time. In the fourth quarter of 2006, we determined that certain of our oil hedges which had previously been effective, fell short of the effectiveness guidelines to be accounted for as cash flow hedges.

We retired our term loan in early December 2006 with the proceeds of the 3.25% convertible senior notes offering. In the fourth quarter of 2006, we fully amortized remaining deferred loan financing costs of $0.6 million incurred in connection with the initial funding of this loan and a subsequent amendment.

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Income tax benefit for 2007 was $3.2 million comprised of an income tax benefit on continuing operations of $9.3 million offset by income tax expense of $6.1 million related to discontinued operations. We increased our valuation allowance and reduced our net deferred tax asset to zero during 2007 after considering all available positive and negative evidence related to the realization of our deferred tax asset. Income tax expense on continuing operations of $4.9 million in 2006, which was non-cash, represents 35.5% of the pre-tax income in 2006.

In conjunction with the sale of our South Louisiana assets in March 2007, we realized a gain (loss) on disposal, net of tax, of $9.7 million ($14.9 million before tax). Income, net of tax on discontinued operations was $1.8 million for 2007 versus a loss of $7.7 million for 2006. This includes an impairment expense, before tax, of $0.4 million and $14.9 million for the years ended December 31, 2007 and 2006, respectively, on certain assets treated as held for sale. See Note 9 “Discontinued Operations” and Note 12 “Acquisitions and Divestitures” to our consolidated financial statements for further discussion of our discontinued operations.

Liquidity

Our principal requirements for capital are to fund our exploration and development activities and to satisfy our contractual obligations. These obligations include the repayment of debt and any amounts owing during the period relating to our hedging positions. Our uses of capital include the following:

• drilling and completing new natural gas and oil wells;

• constructing and installing new production infrastructure;

• acquiring and maintaining our lease position, specifically in the Cotton Valley trend;

• plugging and abandoning depleted or uneconomic wells.

Our capital budget for 2009 is $300 million. We continue to evaluate our capital budget throughout the year based in part upon availability of capital, status of our drilling operations and the outlook for oil and natural gas prices. Please see “Disruptions in the Credit and Capital Markets and Impact on Liquidity” below.

Future commitments

The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at December 31, 2008. In addition to the contractual obligations presented in the table, our Consolidated Balance Sheet at December 31, 2008 reflected accrued interest on our bank debt of $1.8 million payable in the first quarter of 2009. See Note 4 “Long-Term Debt” and Note 10 “Commitments and Contingencies” to our consolidated financial statements for additional information.

	Note	Payment due by Period
		Total		2009		2010		2011		2012		2013 and After
Contractual Obligations
Long term debt (1)	4	$	250,000	$	—	$	75,000	$	175,000	$	—	$	—
Interest on 3.25% notes	4		16,590		5,688		5,688		5,214		—		—
Office space leases	10		1,699		679		207		213		220		380
Office equipment leases	10		387		279		79		13		8		8
Drilling & operations contracts	10		49,261		27,675		9,174		7,956		4,456		—
Transportation contracts	10		3,831		1,804		1,926		101		—		—
Total contractual obligations		$	321,768	$	36,125	$	92,074	$	188,497	$	4,684	$	388

(1) The $175.0 million 3.25% convertible senior notes have a provision at the end of years 5, 10 and 15, for the investors to demand payment on these dates; the first such date is December 1, 2011.

(2) This table does not include the estimated liability for dismantlement, abandonment and restoration costs of oil and gas properties of $13.8 million. The Company records a separate liability for the fair value of this asset retirement obligation. See Note 3 “Asset Retirement Obligation” to our consolidated financial statements.

Capital Resources

We intend to fund our capital expenditure program, contractual commitments, including settlement of derivative contracts and future acquisitions with cash flows from our operations and borrowings under our revolving bank credit facility and second lien term loan. In the future, we may also access public markets to issue additional debt and/or equity securities.

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At December 31, 2008, we had excess borrowing capacity of $175.0 million under our revolving bank credit facility. Our primary sources of cash during 2008 were from net proceeds from the issuance of common stock of $191.3 million in July 2008, net proceeds from property sales of $175.1 million (primarily the Chesapeake transaction), funds generated from operations and bank borrowings. Cash was used primarily to fund exploration and development expenditures. We made aggregate cash payments of $13.0 million for interest and $14.8 million for income taxes in 2008. The table below summarizes the sources of cash during 2008, 2007 and 2006:

	Year Ended December 31,								Year Ended December 31,
Cash flow statement information:	2008			2007			Variance		2007			2006			Variance
	(In thousands)
Net Cash:
Provided by operating activities	$	107,039		$	85,925		$	21,114	$	85,925		$	65,133		$	20,792
Used in investing activities		(187,786	)		(219,193	)		31,407		(219,193	)		(258,737	)		39,544
Provided by financing activities		223,847			131,532			92,315		131,532			179,946			(48,414	)
Increase (decrease) in cash and cash equivalents	$	143,100		$	(1,736	)	$	144,836	$	(1,736	)	$	(13,658	)	$	11,922

At December 31, 2008, we had working capital of $109.8 million and long-term debt of $226.7 million . Our working capital position is primarily due to the remaining cash received from the equity offering and Chesapeake transaction in the third quarter of 2008.

Cash Flows

Year ended December 31, 2008 compared to year ended December 31, 2007

Operating activities. Cash flow from operations is dependent upon production volumes generated from our development, exploration and acquisition activities, the price of oil and natural gas and costs incurred in our operations. Our cash flow from operations is also impacted by changes in working capital. Net cash provided by operating activities was $107.0 million, an increase of $21.1 million, or 25%, from $85.9 million in 2007. Our operating revenues increased 94% in 2008 with a 51% increase in average daily production and a 29% increase in commodity prices as compared to 2007.

Investing activities. Net cash used in investing activities was $187.8 million for the year ended December 31, 2008, compared to $219.2 million for 2007. We received net proceeds of $175.1 million from sale of assets (primarily the Chesapeake transaction) compared to net proceeds of $72.3 million received from the sale of substantially all of our South Louisiana assets in 2007. Total capital expenditures of $362.8 million for 2008 increased $71.3 million from $291.5 million in 2007. We conducted drilling and completion operations on 126 gross wells in 2008 compared to 104 gross wells in 2007, an increase of 21%. Of the $362.8 million invested this year, we spent $328.8 million for drilling and completion activities, $28.6 million for leasehold acquisition, $4.2 million for facilities and infrastructure and $1.2 million for furniture, fixtures and equipment. We spent $273.8 million for drilling and completion activities and $14.3 million for facility installation activities in the Cotton Valley trend in 2007.

Financing activities. Net cash provided by financing activities was $223.8 million for 2008, an increase of $92.3 million over 2007. In January 2008, we borrowed $75.0 million on our Second Lien Term Loan and used $53.5 million of the borrowings to pay-off the balance on our revolving credit facility. In July 2008, we received net proceeds of $191.3 million from an equity offering. We used these proceeds to pay the full outstanding balance on our existing bank credit facility. We have zero borrowings outstanding under our Senior Credit Facility as of December 31, 2008.

Year ended December 31, 2007 compared to year ended December 31, 2006

Operating activities. Net cash provided by operating activities was $85.9 million, an increase of $20.8 million or 32% from $65.1 million in 2006. A 49% increase in operating revenues resulting from a 44% increase in production volumes from continuing operations contributed to the increased cash flow in 2007. Operating cash flow amounts are net of changes in our current assets and current liabilities, which provided additional cash flow of $17.9 million and $4.9 million for the years ended December 31, 2007 and 2006, respectively, with $12.5 million of the increase in 2007 due to a year-end prepay transaction. In late 2007, one of our physical purchasers advanced $12.5 million for gas to be delivered under contract in the first quarter of 2008.

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Investing activities. Net cash used in investing activities was $219.2 million for the year ended December 31, 2007, compared to $258.7 million for 2006. This includes $291.5 million in capital expenditures partially offset by $72.3 million in net proceeds from the sale of our South Louisiana assets. Of the $291.5 million, approximately $273.8 million was spent for drilling and completion activities and $14.3 million for facility installation activities in the Cotton Valley trend. We spent $211.0 million in 2006 for drilling, completion and facility installation activities.

Financing activities. Net cash provided by financing activities was $131.5 million in 2007 versus $179.9 million in 2006. The majority of our net financing cash flows came from the $123.8 million in proceeds from the issuance of common stock net of purchased capped call options, and $14.0 million in net proceeds from bank borrowings.

Disruptions in the Credit and Capital Markets and Impact on Liquidity

We have historically funded our operations from a combination of borrowings under our bank facilities, accessing the capital markets and cash flow from operations. There have been significant disruptions in the U.S. and global credit and capital markets. In recent months, the volatility and disruption have reached unprecedented levels. In some cases, the markets have exerted downward pressure on stock prices and credit capacity for certain issuers. We believe that with prices as of December 31, 2008, we can fund up to $300 million of capital expenditures in 2009 from available cash and cash flow from operations without borrowing under our senior credit facility. We have approximately $147.5 million of cash on hand and $175.0 million of undrawn capacity available under our senior credit facility that matures in February 2010. Availability under our credit facility is subject to semi-annual borrowing base redeterminations, set at the discretion of our lenders. Both we and our lenders also have the discretion to call for at least one additional redetermination per year. The borrowing base is calculated by our lenders based on their valuation of our proved reserves utilizing our reserve reports and their internal decisions. There is no assurance that we can sustain or increase our borrowing base, which if reduced will reduce our borrowing capacity. Because we control the timing of a substantial portion of our capital expenditures and will manage such expenditures accordingly, we do not anticipate an immediate need for borrowings under our senior credit facility or access to the capital markets for the duration of 2009. Accordingly, we may adjust our capital budget further based on further evaluations of our available funding, the status of our drilling operations and the outlook for oil and natural gas prices.

As our senior credit facility is set to expire in February 2010, we are planning to explore refinancing alternatives in the near future. Given the current state of the bank markets, there can be no assurance that a replacement facility will provide similar borrowing capacity, nor do we expect to replace the facility without paying materially higher fees and higher rates on drawn borrowings.

3.25% Convertible Senior Notes

In December 2006, we sold $175.0 million of 3.25% convertible senior notes (the “notes”) due in December 2026. The notes mature on December 1, 2026, unless earlier converted, redeemed or repurchased. The notes are our senior unsecured obligations and rank equally in right of payment to all of our other existing and future indebtedness. The notes accrue interest at a rate of 3.25% annually, and interest is paid semi-annually on June 1 and December 1. Interest payments on the notes began on June 1, 2007.

Before December 1, 2011, we may not redeem the notes. On or after December 11, 2011, we may redeem all or a portion of the notes for cash, and the investors may require us to repurchase the notes on each of December 11, 2011, 2016 and 2021. Upon conversion, we have the option to deliver shares at the applicable conversion rate, redeem in cash or in certain circumstances redeem in a combination of cash and shares. The notes are convertible into shares of our common stock at a rate equal to the sum of:

a) 15.1653 shares per $1,000 principal amount of notes (equal to a “base conversion price” of approximately $65.94 per share) plus,

b) an additional amount of shares per $1,000 of principal amount of notes equal to the incremental share factor (2.6762), multiplied by a fraction, the numerator of which is the applicable stock price less the “base conversion price” and the denominator of which is the applicable stock price.

Share Lending Agreement

In connection with the offering of the notes we agreed to lend an affiliate of Bear, Stearns & Co. (“BSC”) a total of 3,122,263 shares of our common stock under the Share Lending Agreement. Under this agreement, BSC is entitled to offer and sell the shares and use the sale to facilitate the establishment of a hedge position by investors in the notes. BSC will receive all proceeds from the

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common stock offerings and lending transactions under this agreement. BSC is obligated to return the shares to us in the event of certain circumstances, including the redemption of the notes or the conversion of the notes to shares pursuant to the terms of the indenture governing the notes.

The Share Lending Agreement also requires BSC to post collateral of our common stock if its credit rating is below either A3 by Moody’s Investors Service (“Moody’s”) or A- by Standard and Poor’s (“S&P”). As a result of the long term ratings downgrade of BSC in March 2008, BSC was required to return all or a portion of the borrowed shares or collateralize the return obligation with cash or highly liquid non-cash collateral. On March 20, 2008, BSC had returned 1,497,963 shares of the 3,122,263 originally borrowed shares and fully collateralized the remaining 1,624,300 borrowed shares with a cash collateral deposit of approximately $41.3 million. This amount represents the market value of the remaining borrowed shares at March 20, 2008. Under certain conditions, BSC is required to maintain collateral value in the amount at least equal to the market value of the outstanding borrowed shares. The 1,497,963 shares returned to us were recorded as treasury stock and retired in March 2008.

The 1,624,300 shares of common stock outstanding as of December 31, 2008, under the Share Lending Agreement are required to be returned to us in the future. The shares are treated in basic and diluted earnings per share as if they were already returned and retired. As a result, the shares of common stock lent under the Share Lending Agreement have no impact on the earnings per share calculation.

In May 2008, JP Morgan Chase & Co. completed its acquisition of The Bear Stearns Companies Inc. JP Morgan Chase & Co.’s credit rating exceeds that required by the Share Lending Agreement. Thus, collateral is no longer required. Should JP Morgan Chase & Co.’s credit ratings decline below either A3 by Moody’s or A- by S&P, it would be required to post collateral to support its obligation to return any remaining borrowed shares.

Senior Credit Facility

On November 17, 2005, we amended our existing credit agreement and entered into an amended and restated senior credit agreement (as amended, the “Senior Credit Facility”) and a term loan that expanded our borrowing capabilities. Total lender commitments under the Senior Credit Facility were $200 million, and the Senior Credit Facility matures on February 25, 2010. Revolving borrowings under the Senior Credit Facility are limited to, and subject to periodic redeterminations of the borrowing base. At December 31, 2008, we had a borrowing base of $175.0 million and no amounts outstanding under the Senior Credit Facility. Pursuant to the terms of our Senior Credit Facility, the next redetermination of our borrowing base will be March 31, 2009. Interest on revolving borrowings under the Senior Credit Facility accrues at a rate calculated, at our option, at the bank base rate plus 0.00% to 0.75%, or LIBOR plus 1.25% to 2.25%, depending on borrowing base utilization.

The terms of the Senior Credit Facility, as amended, require us to maintain certain covenants. Capitalized terms used, but not defined, here have the meanings assigned to them in the Senior Credit Facility. As of December 31, 2008, we were in compliance with all of the financial covenants of our Senior Credit Facility. The covenants in effect at December 31, 2008 include:

• Current Ratio of 1.0/1.0;

• Interest Coverage Ratio of not less than 3.0/1.0 for the trailing four quarters;

• Total Debt of no greater than 3.0 times EBITDAX for the trailing four quarters (EBITDAX is earnings before interest expense, income tax, DD&A, exploration expense and impairment of oil and gas properties. In calculating EBITDAX for this purpose, earnings include realized gains (losses) from derivatives, but exclude unrealized gains (losses) from derivatives. The 3.25% convertible senior notes are excluded from the calculation of Total Debt for the purpose of computing this ratio.); and

• Asset coverage ratio (defined as the present value of proved reserves discounted at 10% divided by total debt, excluding 3.25% convertible senior notes) of not less than 1.5 to 1.0.

Second Lien Term Loan

On January 16, 2008, we entered into a new Second Lien Term Loan Agreement which provides for a 3-year, non-revolving loan of $75.0 million and is due in a single maturity on December 31, 2010. We have no rights to prepay in the first year. Voluntary prepayment rights in the second year are at 101% of par, and thereafter at par. Interest on the Second Lien Term Loan accrues at a rate of LIBOR plus 550 basis points and is payable quarterly in arrears. As of December 31, 2008, we were in compliance with all of the financial covenants of our Second Lien Term Loan. The terms of the Second Lien Term Loan Agreement contain financial covenants which include:

• Asset coverage ratio (defined as the present value of proved reserves discounted at 10% divided by total debt, excludes 3.25% convertible senior notes) of not less than 1.5 to 1.0;

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• Total debt to EBITDAX ratio of not more than 3.0 to 1.0 (total debt to exclude the 3.25% convertible senior notes); and

• EBITDAX to interest expense ratio of not less than 3.0 to 1.0.

Capped Call Option Transactions

On December 10, 2007, we closed the public offering of 6,430,750 shares of our common stock at a price of $23.50 per share. Net proceeds from the offering were approximately $145.4 million after deducting the underwriters’ discount and estimated offering expenses. We used approximately $123.8 million of the net proceeds to pay off outstanding borrowings under our Senior Credit Facility and approximately $21.6 million of the net proceeds to purchase capped call options on shares of our common stock from affiliates of BSC and JP Morgan Securities Inc. The capped call option transactions covered, subject to customary anti-dilution adjustments, approximately 5.8 million shares of our common stock, and each of them was divided into a number of tranches with differing expiration dates. One third of the options will expire over each of three separate multi-day settlement periods beginning approximately 18 months, 24 months and 30 months from the closing of the offering, respectively.

The capped call option transactions are expected to result in our receipt, on a net share, cashless basis of a certain number of shares of our common stock if the market value per share of the common stock, as measured under the terms of the capped call option agreements, on the option expiration date for the relevant tranche is greater than the lower call strike price of the capped call option transactions. We refer to the amount by which the market value per share exceeds the lower call strike price as an “in-the-money amount” for the relevant tranche of the capped call option transaction. The in-the-money amount will never exceed the difference between the upper call strike price and the lower call strike price (i.e., it will be “capped”). The lower call strike price is $23.50, which corresponds to the price to the public in the equity offering and the upper call strike price is $32.90, which corresponds to 140% of the price to the public in the offering. Both lower and upper call strike prices are subject to customary anti-dilution and certain other adjustments. The number of shares of our common stock that we will receive from the option counterparties upon expiration of each tranche of the capped call option transactions will be equal to the in-the-money amount of that tranche divided by the market value per share of the common stock, as measured under the terms of the capped call option agreements, on the option expiration date for that tranche. If the stock price is equal to the upper call strike price of $32.90 on each of the settlement dates, we will recoup up to 1.6 million shares.

The capped call option agreements were separate transactions entered into by us with the option counterparties and were not part of the terms of the offering of common stock.

The capped call option agreements require an option counterparty to transfer their rights and obligations within 30 days if their credit rating is below either Baa1 by Moody’s or BBB+ by S&P. As a result of the ratings downgrade of BSC on March 14, 2008, BSC was obligated to transfer their rights and obligations under the capped call option agreement to a suitable counterparty (one with a credit rating of at least BBB+ by S&P and Baa1 by Moody’s within 30 days). BSC’s obligation to transfer its rights and obligations to an entity with a higher credit rating was cured by a ratings upgrade on March 24, 2008.

During the second quarter of 2008, BSC sold its position in the capped call options to Bank of America.

Equity Offering

On July 14, 2008, we closed the public offering of 3,121,300 shares of our common stock at a price of $64.00 per share. Net proceeds from the offering were approximately $191.3 million after deducting the underwriters’ discount and estimated offering expenses. We used approximately $96.0 million of the net proceeds to pay off outstanding borrowings under our Senior Credit Facility. We used the remaining net proceeds for general corporate purposes, including funding a portion of our remaining 2008 drilling program, other capital expenditures and working capital requirements.

14

Short Term Investments

The net proceeds from our July 2008 equity offering and the net proceeds from sale of assets were invested in short term investments. As of December 31, 2008, our short term investments amounted to $136.5 million. Prior to making these investments, our board of directors instituted a short term investment policy, to be implemented by our Chief Executive Officer and Chief Financial Officer. The short term investment policy was adopted to meet the following objectives:

• Preserve principal;

• Maintain liquidity;

• Diversify investment risk; and

• Maximize earnings on surplus funds consistent with the first three objectives.

This new policy also authorizes transactions only with institutions that meet the following criteria:

• Short-term debt ratings of at least A1 by Standard and Poor’s (S&P) and P1 by Moody’s;

• Long-term debt ratings of at least AA- by S&P and Aa3 by Moody’s; and

• Market capitalization of at least $25.0 billion for the parent company at the time of the transaction.

Also, funds on deposit at any one institution shall not exceed $100.0 million, unless previously approved by our Chief Financial Officer and Chief Executive Officer.

As of December 31, 2008, we held short term investments in money market funds with three institutions meeting all of these criteria. Short term investments as of December 31, 2008, carried maturities of fourteen days or less and are considered cash equivalents. We will continue to monitor these institutions in light of the current financial market crisis and in accordance with our policy.

Series B Convertible Preferred Stock

Our Series B Convertible Preferred Stock (the “Series B Convertible Preferred Stock”) was initially issued on December 21, 2005, in a private placement of 1,650,000 shares for net proceeds of $79.8 million (after offering costs of $2.7 million). Each share of the Series B Convertible Preferred Stock has a liquidation preference of $50 per share, aggregating to $82.5 million, and bears a dividend of 5.375% per annum. Dividends are payable quarterly in arrears beginning March 15, 2006. If we fail to pay dividends on our Series B Convertible Preferred Stock on any six dividend payment dates, whether or not consecutive, the dividend rate per annum will be increased by 1.0% until we have paid all dividends on our Series B Convertible Preferred Stock for all dividend periods up to and including the dividend payment date on which the accumulated and unpaid dividends are paid in full.

On January 23, 2006, the initial purchasers of the Series B Convertible Preferred Stock exercised their over-allotment option to purchase an additional 600,000 shares at the same price per share, resulting in net proceeds of $29.0 million, which was used to fund our 2006 capital expenditure program.

Each share is convertible at the option of the holder into our common stock, par value $0.20 per share (the “Common Stock”) at any time at an initial conversion rate of 1.5946 shares of Common Stock per share, which is equivalent to an initial conversion price of approximately $31.36 per share of Common Stock. Upon conversion of the Series B Convertible Preferred Stock, we may choose to deliver the conversion value to holders in cash, shares of Common Stock, or a combination of cash and shares of Common Stock.

If a fundamental change occurs, holders may require us in specified circumstances to repurchase all or part of the Series B Convertible Preferred Stock. In addition, upon the occurrence of a fundamental change or specified corporate events, we will under certain circumstances increase the conversion rate by a number of additional shares of Common Stock. A “fundamental change” will be deemed to have occurred if any of the following occurs:

• We consolidate or merge with or into any person or convey, transfer, sell or otherwise dispose of or lease all or substantially all of our assets to any person, or any person consolidates with or merges into us or with us, in any such event pursuant to a transaction in which our outstanding voting shares are changed into or exchanged for cash, securities, or other property; or

• We are liquidated or dissolved or adopt a plan of liquidation or dissolution.

A “fundamental change” will not be deemed to have occurred if at least 90% of the consideration in the case of a merger or consolidation under the first clause above consists of common stock traded on a U.S. national securities exchange and the Series B Preferred Stock becomes convertible solely into such common stock.

15

On or after December 21, 2010, we may, at our option, cause the Series B Convertible Preferred Stock to be automatically converted into that number of shares of Common Stock that are issuable at the then-prevailing conversion rate, pursuant to the Company Conversion Option. We may exercise our conversion right only if, for 20 trading days within any period of 30 consecutive trading days ending on the trading day before the announcement of our exercise of the option, the closing price of the Common Stock equals or exceeds 130% of the then-prevailing conversion price of the Series B Convertible Preferred Stock. The Series B Convertible Preferred Stock is non-redeemable by us.

We used the net proceeds of the offering of Series B Convertible Preferred Stock to fully repay all outstanding indebtedness under our senior revolving credit facility. The remaining net proceeds of the offering were added to our working capital to fund 2006 capital expenditures and for other general corporate purposes.

Summary of Critical Accounting Policies

The following summarizes several of our critical accounting policies. See a complete list in Note 1 “Description of Business and Significant Accounting Policies” to our consolidated financial statements.

Proved oil and natural gas reserves

Proved reserves are defined by the SEC as those volumes of crude oil, condensate, natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are volumes expected to be recovered through existing wells with existing equipment and operating methods. Although our external engineers are knowledgeable of and follow the guidelines for reserves as established by the SEC, the estimation of reserves requires the engineers to make a significant number of assumptions based on professional judgment. Estimated reserves are often subject to future revision, certain of which could be substantial, based on the availability of additional information, including: reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes and other economic factors. Changes in oil and natural gas prices can lead to a decision to start-up or shut-in production, which can lead to revisions to reserve quantities. Reserve revisions inherently lead to adjustments of depreciation rates used by us. We cannot predict the types of reserve revisions that will be required in future periods.

Successful efforts accounting

We use the successful efforts method to account for exploration and development expenditures and to calculate DD&A. Unsuccessful exploration wells, as well as other exploration expenditures such as seismic costs, are expensed and can have a significant effect on operating results. Successful exploration drilling costs, all development capital expenditures and asset retirement costs are capitalized and systematically charged to expense using the units of production method based on proved developed oil and natural gas reserves as estimated by engineers. Certain costs related to fields or areas that are not fully developed are charged to expense using the units of production method based on total proved oil and natural gas reserves.

Impairment of properties

We continually monitor our long-lived assets recorded in oil and gas properties in the Consolidated Balance Sheets to ensure that they are fairly presented. We must evaluate our properties for potential impairment when circumstances indicate that the carrying value of an asset could exceed its fair value. Performing these evaluations requires a significant amount of judgment since the results are based on estimated future events. Such events include a projection of future oil and natural gas sales prices, an estimate of the ultimate amount of recoverable proved and probable oil and natural gas reserves that will be produced from a field, the timing of this future production, future costs to produce the oil and natural gas, and future inflation levels. The need to test a property for impairment can be based on several factors, including a significant reduction in sales prices for oil and/or natural gas, unfavorable adjustments to reserves, or other changes to contracts, environmental regulations or tax laws. We cannot predict the amount of impairment charges that may be recorded in the future.

Asset retirement obligations

We are required to make estimates of the future costs of the retirement obligations of our producing oil and gas properties. This requirement necessitates us to make estimates of our property abandonment costs that, in some cases, will not be incurred until a substantial number of years in the future. Such cost estimates could be subject to significant revisions in subsequent years due to changes in regulatory requirements, technological advances and other factors which may be difficult to predict.

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Income taxes

We are subject to income and other related taxes in areas in which we operate. When recording income tax expense, certain estimates are required by management due to timing and the impact of future events on when income tax expenses and benefits are recognized by us. We periodically evaluate our tax operating loss and other carryforwards to determine whether a gross deferred tax asset, as well as a related valuation allowance, should be recognized in our financial statements. In July 2008, we realized a significant gain on sale of assets which helped generate income from continuing operations before taxes of $183.3 million for 2008. As a result of the significant gain generated by the sale, we believe that we will be in a position to utilize the majority of our net operating loss carryforwards when we file our 2008 tax return. We believe it is now more likely than not that we will be able to recognize our deferred tax assets associated with these net operating loss carryforwards. As a result, we released $15.3 million of our previously booked valuation allowance in the third quarter of this year.

FASB Interpretation No. 48 (“FIN 48”), Accounting for Uncertainty in Income Taxes, provides guidance on recognition and measurement of uncertainties in income taxes. FIN 48 requires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority. See Notes 1 and 6 to our consolidated financial statements.

Fair Value Measurement

Derivative instruments are carried at fair value. Recurring fair value measurements at interim periods and annually use quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data correlation or other means. These measurements fall within level 2 of the fair value hierarchy of SFAS 157.

Share-Based Compensation Plans

For all new, modified and unvested share-based payment transactions with employees, we measure at fair value and recognize as compensation expense over the requisite period. The fair value of each option award is estimated using a Black-Scholes option valuation model that requires us to develop estimates for assumptions used in the model. The Black-Scholes valuation model uses the following assumptions: expected volatility, expected term of option, risk-free interest rate and dividend yield. Expected volatility estimates are developed by us based on historical volatility of our stock. We use historical data to estimate the expected term of the options. The risk-free interest rate for periods within the expected life of the option is based on the U.S. Treasury yield in effect at the grant date. Our common stock does not pay dividends; therefore the dividend yield is zero.

New Accounting Pronouncements

See Note 1 “Description of Business and Significant Accounting Policies”- “New Accounting Pronouncements” to our consolidated financial statements.

Off-Balance Sheet Arrangements

We do not currently use any off-balance sheet arrangements to enhance our liquidity and capital resource positions, or for any other purpose.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Despite the measures taken by us to attempt to control price risk, we remain subject to price fluctuations for natural gas and crude 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 our control. Domestic crude oil and gas prices could have a material adverse effect on our financial position, results of operations and quantities of reserves recoverable on an economic basis.

We enter into futures contracts or other hedging agreements from time to time to manage the commodity price risk for a portion of our production. We consider these agreements to be hedging activities and, as such, monthly settlements on the contracts that qualify for hedge accounting are reflected in our crude oil and natural gas sales. Our 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 generally hedge between 30% and 70% of our production. As of December 31, 2008, the commodity hedges we use were in the form of:

(a) swaps, where we receive a fixed price and pay a floating price, based on NYMEX and field prices, and

17

(b) collars, where we receive the excess, if any, of the floor price over the reference price, based on NYMEX quoted prices, and pay the excess, if any, of the reference price over the ceiling price.

See Note 8 “Derivative Activities” to our consolidated financial statements for additional information. At December 31, 2008, we had the following commodity hedges in place (in millions):

Collars NYMEX)	Daily Volume	Total Volume	Average Floor/Cap
Natural gas (MMBtu)
1Q 2009	20,000	1,800,000	$	8.75 – $13.10
2Q 2009	20,000	1,820,000	$	8.75 – $13.10
3Q 2009	20,000	1,840,000	$	8.75 – $13.10
4Q 2009	20,000	1,840,000	$	8.75 – $13.10
Swaps (NYMEX)			Average Price
Natural gas (MMBtu)
1Q 2009	20,000	1,800,000	$	8.83
2Q 2009	20,000	1,820,000	$	8.83
3Q 2009	20,000	1,840,000	$	8.83
4Q 2009	20,000	1,840,000	$	8.83
Swaps (TexOk)			Price (1)
Natural gas (MMBtu)
1Q 2009	20,000	1,800,000	$	7.87
2Q 2009	20,000	1,820,000	$	7.87
3Q 2009	20,000	1,840,000	$	7.87
4Q 2009	20,000	1,840,000	$	7.87

(1) The index price is based upon Natural Gas Pipeline of America, TexOk (“NGPLTXOK”) zone as published in the Inside FERC. The comparable index price based on NYMEX was approximately $8.25/Mmbtu.

Our hedging contracts fall within our targeted range of 30% to 70% of our estimated net oil and gas production volumes for the applicable periods of 2009. The fair value of the natural gas hedging contracts in place at December 31, 2008, resulted in a current asset of $55.3 million. Based on gas pricing in effect at December 31, 2008, a hypothetical 10% increase in gas prices would have resulted in a current derivative asset of $42.5 million while a hypothetical 10% decrease in gas prices would have increased the current derivative asset to $69.2 million.

We have entered into the following contracts subsequent to December 31, 2008:

(a) A NGPLTXOK priced basis swap contract with the Bank of Montreal for 20,000 Mmbtu per day for the months of March through December 2009, locking in a fixed basis to the Company of $0.52 per Mmbtu, and

(b) A NGPLTXOK priced basis swap contract with BNP for 20,000 Mmbtu per day for the months of March through December 2009 locking in a fixed basis to the Company of $0.52 per Mmbtu.

Interest Rate Risk

We have a variable-rate debt obligation that exposes us to the effects of changes in interest rates. To partially reduce our exposure to interest rate risk, from time to time we enter into interest rate swap agreements. At December 31, 2008, we had the following interest rate swaps in place with BNP and BMO (in millions):

Effective Date	Maturity Date	Libor Swap Rate		Notional Amount (Millions)		Fair Value (Dollars)
2/26/2007	2/26/2009	4.860	%	$	40.0	$	(271,029	)
4/22/2008	4/22/2010	3.191	%		25.0		(515,584	)
4/22/2008	4/22/2010	3.191	%		50.0		(1,017,416	)
						$	(1,804,029	)

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The fair value of the interest rate swap contracts in place at December 31, 2008, resulted in a current liability of $1.2 million and a long term liability of $0.6 million. Based on interest rates at December 31, 2008, a hypothetical 10% increase in interest rates would have decreased the liability to $1.6 million whereas a 10% decrease in interest rates would have increased the liability to $2.0 million.

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Item 8. Financial Statements and Supplementary Data

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROLS

OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining effective internal control over financial reporting as defined in Rules 13a-15(f) under the Securities Exchange Act of 1934. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and board of directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.

We assessed the effectiveness of our internal control over financial reporting based on the framework in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation under the framework in Internal Control—Integrated Framework, we have concluded that our internal control over financial reporting was effective as of December 31, 2008. The effectiveness of our internal control over financial reporting as of December 31, 2008 has been audited by Ernst & Young LLP, an independent registered public accounting firm, as stated in their report which is included on page F-3.

Management of Goodrich Petroleum Corporation

20

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of

Goodrich Petroleum Corporation

We have audited the accompanying consolidated balance sheet of Goodrich Petroleum Corporation and subsidiaries as of December 31, 2008, and the related consolidated statements of operations, cash flows, stockholders’ equity, and comprehensive income (loss) for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Goodrich Petroleum Corporation and subsidiaries at December 31, 2008, and the consolidated results of their operations and their cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, the consolidated financial statements have been adjusted for the retrospective application of FASB Staff Position APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement) which became effective January 1, 2009.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Goodrich Petroleum Corporation’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2009 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 27, 2009, except for Note 1 as to which the date is September 16, 2009

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Goodrich Petroleum Corporation:

We have audited the accompanying consolidated balance sheet of Goodrich Petroleum Corporation and subsidiaries as of December 31, 2007, and the related consolidated statements of operations, stockholders’ equity and comprehensive income (loss), and cash flows for each of the years in the two-year period ended December 31, 2007. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Goodrich Petroleum Corporation and subsidiaries as of December 31, 2007, and the results of their operations and their cash flows for each of the years in the two-year period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, the consolidated financial statements have been adjusted for the retrospective application of Financial Accounting Standards Board Staff Position No. APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement), which became effective January 1, 2009.

/s/ KPMG LLP

March 13, 2008, except for Note 1, as to which the date is

September 16, 2009

22

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(In Thousands)

	December 31,
	2008			2007
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	147,548		$	4,448
Accounts receivable, trade and other, net of allowance		7,019			8,539
Accrued oil and gas revenue		15,595			12,200
Fair value of oil and gas derivatives		55,276			2,267
Assets held for sale		13			311
Prepaid expenses and other		2,778			904
Total current assets		228,229			28,669
PROPERTY AND EQUIPMENT:
Oil and gas properties (successful efforts method)		1,107,400			723,239
Furniture, fixtures and equipment		3,171			1,932
		1,110,571			725,171
Less: Accumulated depletion, depreciation and amortization		(304,236	)		(168,523	)
Net property and equipment		806,335			556,648
Deferred financing cost Deferred financing cost		3,723			3,916
TOTAL ASSETS	$	1,038,287		$	589,233
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	41,462		$	36,967
Accrued liabilities		52,928			32,565
Deferred tax liability current		18,931			—
Income taxes payable		1,383			—
Fair value of interest rate derivatives		1,187			384
Accrued abandonment costs		2,554			312
Deferred revenue		—			12,500
Total current liabilities		118,445			82,728
LONG-TERM DEBT		226,723			185,449
Accrued abandonment costs		11,250			5,868
Deferred income tax liability		15,904			—
Fair value of interest rate derivatives		617			—
Fair value of oil and gas derivatives		—			2,407
Total liabilities		372,939			276,452
Commitments and contingencies (See Note 10)
STOCKHOLDERS’ EQUITY:
Preferred stock: 10,000,000 shares authorized:
Series B convertible preferred stock, $1.00 par value, issued and outstanding 2,250,000		2,250			2,250
Common stock: $0.20 par value, 100,000,000 and 50,000,000 shares authorized, respectively; issued and outstanding 37,562,659 and 34,821,317 shares, respectively		7,188			6,340
Treasury stock (9,793 and 16,359 shares, respectively)		(293	)		(422	)
Additional paid in capital		600,125			364,262
Retained earnings (accumulated deficit)		56,078			(59,649	)
Total stockholders’ equity		665,348			312,781
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,038,287		$	589,233

See accompanying notes to consolidated financial statements.

23

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

	Year Ended December 31,
	2008			2007			2006
REVENUES:
Oil and gas revenues	$	215,369		$	110,691		$	73,933
Other		682			614			838
		216,051			111,305			74,771
OPERATING EXPENSES:
Lease operating expense		31,950			22,465			12,688
Production and other taxes		7,542			2,272			3,345
Transportation		8,645			5,964			3,791
Depreciation, depletion and amortization		107,123			79,766			37,225
Exploration		8,404			7,346			5,888
Impairment of oil and gas properties		28,582			7,696			9,886
General and administrative		24,254			20,888			17,223
Gain on sale of assets		(145,876	)		(42	)		(23	)
Other		—			109			—
		70,624			146,464			90,023
Operating income (loss)		145,427			(35,159	)		(15,252	)
OTHER INCOME (EXPENSE):
Interest expense		(22,410	)		(17,878	)		(8,343	)
Interest income		2,184			—			—
Gain (loss) on derivatives not designated as hedges		51,547			(6,439	)		38,128
Loss on early extinguishment of debt		—			—			(612	)
		31,321			(24,317	)		29,173
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		176,748			(59,476	)		13,921
INCOME TAX EXPENSE		(54,472	)		9,294			(4,940	)
INCOME (LOSS) FROM CONTINUING OPERATIONS		122,276			(50,182	)		8,981
DISCONTINUED OPERATIONS
Gain on sale of assets, net of tax (See Note 12)		29			9,662			—
Income (loss) on discontinued operations, net of tax (See Note 9)		(531	)		1,807			(7,660	)
		(502	)		11,469			(7,660	)
NET INCOME (LOSS)		121,774			(38,713	)		1,321
PREFERRED STOCK DIVIDENDS		6,047			6,047			6,016
PREFERRED STOCK REDEMPTION PREMIUM		—			—			1,545
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK	$	115,727		$	(44,760	)	$	(6,240	)
NET INCOME (LOSS) PER COMMON SHARE-BASIC
INCOME (LOSS) FROM CONTINUING OPERATIONS	$	3.61		$	(1.96	)	$	0.36
DISCONTINUED OPERATIONS	$	(0.01	)	$	0.45		$	(0.30	)
NET INCOME (LOSS)	$	3.60		$	(1.51	)	$	0.06
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK	$	3.42		$	(1.75	)	$	(0.25	)
NET INCOME (LOSS) PER COMMON SHARE-DILUTED
INCOME (LOSS) FROM CONTINUING OPERATIONS	$	3.24		$	(1.96	)	$	0.35
DISCONTINUED OPERATIONS	$	(0.01	)	$	0.45		$	(0.30	)
NET INCOME (LOSS)	$	3.23		$	(1.51	)	$	0.05
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK	$	3.23		$	(1.75	)	$	(0.25	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING-BASIC		33,806			25,578			24,948
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING-DILUTED		40,397			25,578			25,412

See accompanying notes to consolidated financial statements.

24

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

	Year Ended December 31,
	2008			2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	121,774		$	(38,713	)	$	1,321
Adjustments to reconcile net income (loss) to net cash provided by operating activities—
Depletion, depreciation, and amortization		107,123			79,766			52,642
Unrealized (gain) loss on derivatives not qualifying for hedge accounting		(53,995	)		16,079			(40,185	)
Deferred income taxes		34,835			(3,303	)		724
Dry hole costs		312			939			7,926
Amortization of leasehold costs		5,838			6,211			5,488
Impairment of oil and gas properties		29,751			9,223			24,790
Stock based compensation (non-cash)		5,493			5,282			5,962
Gain on sale of assets		(145,876	)		(14,792	)		(23	)
Loss on early extinguishment of debt		—			—			612
Other non-cash items		8,518			7,378			974
Change in assets and liabilities:
Accounts receivable, trade and other, net of allowance		1,467			1,105			(3,268	)
Deferred revenue		(12,500	)		12,500			—
Accrued oil and gas revenue		(3,395	)		(1,511	)		1,174
Accounts payable		4,495			5,022			4,689
Income taxes payable		1,383			—			—
Accrued liabilities		3,184			409			2,838
Prepaid expenses and other		(1,368	)		330			(531	)
Net cash provided by operating activities		107,039			85,925			65,133
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(362,847	)		(291,486	)		(261,435	)
Proceeds from sale of assets		175,061			72,293			2,698
Net cash used in investing activities		(187,786	)		(219,193	)		(258,737	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Principal payments of bank borrowings		(155,500	)		(173,000	)		(184,500	)
Proceeds from bank borrowings		190,000			187,000			181,000
Net proceeds from common stock offering		191,340			123,815			—
Excess tax benefit from stock based compensation		3,222			—			—
Exercise of stock options and warrants		2,819			203			406
Deferred financing costs		(1,498	)		(439	)		(5,598	)
Preferred stock dividends		(6,047	)		(6,047	)		(6,016	)
Proceeds from convertible note offering		—			—			175,000
Net proceeds from preferred stock offering		—			—			28,973
Redemption of preferred stock		—			—			(9,319	)
Other		(489	)		—			—
Net cash provided by financing activities		223,847			131,532			179,946
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		143,100			(1,736	)		(13,658	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		4,448			6,184			19,842
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	147,548		$	4,448		$	6,184
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
CASH PAID DURING THE YEAR FOR INTEREST	$	12,981		$	10,178		$	7,284
CASH PAID DURING THE YEAR FOR INCOME TAXES	$	14,778		$	—		$	—

See accompanying notes to consolidated financial statements.

25

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In Thousands)

	2008					2007					2006
	Shares		Amount			Shares		Amount			Shares		Amount
Series A Preferred Stock
Balance, beginning of year	—		$	—		—		$	—		792		$	792
Offering of preferred stock	—			—		—			—		(792	)		(792	)
Balance, end of year	—		$	—		—		$	—		—		$	—
Series B Preferred Stock
Balance, beginning of year	2,250		$	2,250		2,250		$	2,250		1,650		$	1,650
Issuance of preferred stock	—			—		—			—		600			600
Balance, end of year	2,250		$	2,250		2,250		$	2,250		2,250		$	2,250
Common Stock
Balance, beginning of year	34,821		$	6,340		28,218		$	5,049		24,805		$	4,961
Offering of common stock	4,030			806		6,431			1,286		—			—
Issuance of and amortization of restricted stock	53			11		108			(8	)	182			36
Exercise of stock options and warrants	141			28		57			12		66			44
Director stock grants	16			3		7			1		37			7
Shares pursuant to share lending agreement	(1,498	)		—		—			—		3,122			—
Redemption of Series A preferred stock	—			—		—			—		6			1
Balance, end of year	37,563		$	7,188		34,821		$	6,340		28,218		$	5,049
Treasury Stock
Balance, beginning of year	16		$	(422	)	—		$	—		—		$	—
Purchases	16			(485	)	40			(1,231	)	—			—
Retirements	(22	)		614		(24	)		809		—			—
Balance, end of year	10		$	(293	)	16		$	(422	)	—		$	—
Additional Paid in Capital
Balance, beginning of year			$	364,262				$	236,877				$	187,967
Offering of common stock				224,405					122,529					—
Issuance of and amortization of restricted stock				2,686					1,745					2,205
Stock based compensation				2,180					2,727					2,487
Excess tax benefit from stock based compensation				3,222					—					—
Exercise of stock options and warrants				2,791					192					295
Director stock grants				579					239					1,388
Offering of preferred stock				—					—					28,373
Redemption of Series A preferred stock				—					—					(6,983	)
Equity portion of Senior Convertible Notes and finance cost				—					(47	)				23,211
Reclassification from unamortized restricted stock upon adoption of FAS 123R				—					—					(2,066	)
Balance, end of year			$	600,125				$	364,262				$	236,877
Retained Earnings (Accumulated Deficit)
Balance, beginning of year				(59,649	)				(14,889	)				(8,649	)
Net income (loss)				121,774					(38,713	)				1,321
Preferred stock dividend				(6,047	)				(6,047	)				(6,016	)
Redemption of Series A preferred stock				—					—					(1,545	)
Balance, end of year			$	56,078				$	(59,649	)			$	(14,889	)
Unamortized Restricted Stock Awards
Balance, beginning of year			$	—				$	—				$	(2,066	)
Reclassification to APIC upon adoption of FAS 123R				—					—					2,066
Balance, end of year			$	—				$	—				$	—
Accumulated Other Comprehensive Loss
Balance, beginning of year			$	—				$	(1,261	)			$	(3,066	)
Other comprehensive loss				—					1,261					1,805
Balance, end of year			$	—				$	—				$	(1,261	)
Total Stockholders’ Equity at December 31			$	665,348				$	312,781				$	228,026

See accompanying notes to consolidated financial statements.

26

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In Thousands)

	Year Ended December 31,
	2008		2007			2006
Net income (loss)	$	121,774	$	(38,713	)	$	1,321
Other comprehensive income (loss):
Change in fair value of derivatives (1)		—		—			(1,025	)
Reclassification adjustment (2)		—		1,261			2,830
Other comprehensive income (loss)		—		1,261			1,805
Comprehensive income (loss)	$	121,774	$	(37,452	)	$	3,126
(1) Net of income tax benefit of:	$	—	$	—		$	552
(2) Net of income tax expense of:	$	—	$	679		$	1,524

See accompanying notes to consolidated financial statements.

27

GOODRICH PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—Description of Business and Significant Accounting Policies

We are in the primary business of exploration and production of crude oil and natural gas. We and our subsidiaries have interests in such operations, primarily in Texas and Louisiana.

Principles of Consolidation—The consolidated financial statements include the financial statements of Goodrich Petroleum Corporation and its wholly-owned subsidiaries. Significant intercompany balances and transactions have been eliminated in consolidation.

Presentation Change—The Consolidated Statement of Operations include a category of expense titled “Production and other taxes” which is a change from “Production taxes” in prior period presentations. The changed category includes ad valorem taxes as well as production taxes for which all comparative periods presented have been adjusted.

Use of Estimates—Our Management has made a number of estimates and assumptions relating to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ from those estimates.

Cash and Cash Equivalents—Cash and cash equivalents include cash on hand, demand deposit accounts and temporary cash investments with maturities of ninety days or less at date of purchase. As of December 31, 2008, we held short term investments in money market funds with three institutions meeting our short term investment policy criteria. As of December 31, 2008, short term investments totaled $136.5 million and carried maturities of fourteen days or less and are considered cash equivalents. We continue to monitor these institutions in light of the current financial market crisis and in accordance with our policy.

Allowance for Doubtful Accounts—We routinely assess the recoverability of all material trade and other receivables to determine their collectability. Many of our receivables are from a limited number of purchasers. Accordingly, accounts receivable from such purchases could be significant. Generally, our natural gas and crude oil receivables are collected within 30-60 days of production. We also have receivables from joint interest owners of properties we operate. We may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings.

We accrue a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated. As of December 31, 2008 and 2007, our allowance for doubtful accounts was immaterial.

Assets Held for Sale—Assets Held for Sale as of December 31, 2008, represents our remaining asset in South Louisiana, the Plumb Bob field. Assets held for sale as of December 31, 2007 represent our remaining assets in the St. Gabriel, Bayou Bouillon and Plumb Bob fields.

Property and Equipment—We follow the successful efforts method of accounting for exploration and development expenditures. Under this method, costs of acquiring unproved and proved oil and gas leasehold acreage are capitalized. When proved reserves are found on an unproved property, the associated leasehold cost is transferred to proved properties. Significant unproved leases are reviewed periodically, and a valuation allowance is provided for any estimated decline in value. Costs of all other unproved leases are amortized over the estimated average holding period of the leases.

Exploration expenditures, including geological and geophysical costs, delay rentals and exploratory dry hole costs are expensed as incurred. Costs of drilling exploratory wells are initially capitalized pending determination of whether proved reserves can be attributed to the discovery. If management determines that commercial quantities of hydrocarbons have not been discovered, capitalized costs associated with exploratory wells are expensed. Development costs are capitalized, including the costs of unsuccessful development wells.

Proved oil and gas properties are reviewed for impairment on a field-by-field basis when facts and circumstances indicate that their carrying amounts may not be recoverable. In performing this review, future net cash flows are calculated based on estimated future oil and gas sales revenues less future expenditures necessary to develop and produce the reserves. If the sum of these estimated future cash flows (undiscounted) is less than the carrying amount of the property, an impairment loss is recognized for the excess of the property’s carrying amount over its estimated fair value based on estimated discounted future cash flows. We perform this comparison using our estimates of future commodity prices and proved and probable reserves. For the years ended December 31, 2008, 2007 and 2006, we recorded impairments on continuing operations of $28.6 million, $7.7 million and $9.9 million, respectively.

28

GOODRICH PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Depreciation and depletion of producing oil and gas properties is calculated using the units-of-production method. Proved developed reserves are used to compute unit rates for unamortized tangible and intangible development costs, and proved reserves are used for unamortized leasehold costs. As described in Note 3, we follow the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”). Our capitalized asset retirement costs are amortized based upon units of production of proved reserves attributable to the properties to which the obligations relate. Some of these obligations relate to an individual producing well or group of producing wells and are amortized based on proved developed reserves attributable to that well or group of wells. Other asset retirement obligations may relate to an entire field or area that is not fully developed. Because these obligations relate to assets installed to service future development, they are amortized based on all proved reserves attributable to the field or area.

Gains and losses on disposals or retirements that are significant or include an entire depreciable or depletable property unit are included in income.

Furniture, fixtures and equipment consists of office furniture, computer hardware and software and leasehold improvements. Depreciation of these assets is computed using the straight-line method over their estimated useful lives, which vary from three to five years.

Asset Retirement Obligations—We follow SFAS 143 (see Note 3) which applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. SFAS 143 requires that we record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset.

Revenue Recognition— Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Revenues from the production of crude oil and natural gas properties in which we have an interest with other producers are recognized on the entitlements method. We record an asset or liability for natural gas balancing when we have purchased or sold more than our working interest share of natural gas production, respectively. At December 31, 2008, 2007 and 2006, the net assets for gas balancing were less than $0.1 million, $1.2 million and $1.5 million, respectively. Differences between actual production and net working interest volumes are routinely adjusted.

Derivative Instruments and Hedging Activities—We use derivative instruments such as futures, forwards, options, collars and swaps for purposes of hedging our exposure to fluctuations in the price of crude oil and natural gas and to hedge our exposure to changing interest rates. SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”), as amended, requires that all derivative instruments subject to the requirements of the statement be measured at fair value and recognized as assets or liabilities in the balance sheet. SFAS 133 also requires that changes in fair value be recognized currently in earnings unless specific hedge accounting criteria are met.

Fair Value Measurement—We adopted SFAS No. 157, Fair Value Measurements (“SFAS 157”) effective January 1, 2008 on a prospective basis. This statement defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles and expands disclosures about fair value measurements. Under SFAS 157, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. As of January 1, 2008, SFAS 157 was effective for all financial assets and liabilities subject to its provisions and certain nonfinancial assets and liabilities that are recognized or disclosed at fair value in the financial statements on a recurring basis. Our derivative instruments are carried at fair value and are therefore subject to the provisions of SFAS 157. In accordance with SFAS 157, we measure the fair value of our derivative instruments by applying the income approach, using inputs that are derived principally from observable market data. The adoption of SFAS 157 did not have a material impact on our financial statements. See Note 13.

Income Taxes—We follow the provisions of SFAS No. 109, Accounting for Income Taxes, (“SFAS 109”) as clarified by the Financial Accounting Standard Board (“FASB”) Interpretation No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”), which requires income taxes be accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized

29

GOODRICH PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

FIN 48 requires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more-likely-than-not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement with the relevant tax authority.

Earnings Per Share—Basic income per common share is computed by dividing net income available for common stockholders, for each reporting period by the weighted average number of common shares outstanding during the period. Diluted income per common share is computed by dividing net income available for common stockholders for each reporting period by the weighted average number of common shares outstanding during the period, plus the effects of potentially dilutive common shares calculated using the Treasury Stock method.

Commitments and Contingencies—Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines and penalties, and other sources are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. Recoveries from third parties, which are probable of realization, are separately recorded, and are not offset against the related environmental liability.

Concentration of Credit Risk—Due to the nature of the industry, we sell our oil and natural gas production to a limited number of purchasers and, accordingly, amounts receivable from such purchasers could be significant. Revenues from three purchasers accounted for 33%, 20% and 9% of oil and gas revenues for the year ended December 31, 2008. Revenues from three purchases accounted for 31%, 23% and 10% of oil and gas revenues for the year ended December 31, 2007. Revenues from two purchasers accounted for 35% and 15% of oil and gas revenues for the year ended December 31, 2006.

Share-Based Compensation Plan— We account for our stock based compensation in accordance with SFAS No. 123 (revised 2004), Share-Based Payment (“SFAS 123R”). SFAS 123R requires new, modified and unvested share-based payment transactions with employees to be measured at fair value and recognized as compensation expense over the requisite service period. The fair value of each option award is estimated using a Black-Scholes option valuation model that requires us to develop estimates for assumptions used in the model. The Black-Scholes valuation model uses the following assumptions: expected volatility, expected term of option, risk-free interest rate and dividend yield. Expected volatility estimates are developed by us based on historical volatility of our stock. We use historical data to estimate the expected term of the options. The risk-free interest rate for periods within the expected life of the option is based on the U.S. Treasury yield in effect at the grant date. Our common stock does not pay dividends; therefore, the dividend yield is zero. See Note 2.

New Accounting Pronouncements—In February 2007, the FASB issued SFAS 159, The Fair Value Option for Financial Assets and Financial Liabilities (“SFAS 159”). SFAS 159 provides companies with an option to report selected financial assets and liabilities at fair value. SFAS 159 is effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. We adopted SFAS 159 as of January 1, 2008. Adoption had no effect on our financial position or results of operations as we made no elections to report selected financial assets or liabilities at fair value.

In December 2007, the FASB issued SFAS 141(R), Business Combinations (“SFAS 141(R)”). This statement requires most identifiable assets, liabilities and noncontrolling interests acquired in a business combination (as defined in the statement) to be recorded at fair value on the acquisition date. This statement is effective for periods beginning on or after December 15, 2008, and earlier adoption is prohibited. SFAS 141(R) will be applied prospectively to business combinations occurring after January 1, 2009.

30

GOODRICH PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 (“SFAS 161”). SFAS 161 amends and expands the disclosure requirements of SFAS No. 133 by requiring enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. SFAS 161 will be effective as of January 1, 2009. As SFAS 161 provides only disclosure requirements, the adoption of this standard will not have an impact on our results of operations, cash flows or financial positions.

On May 9, 2008, the FASB issued FASB Staff Position Accounting Principles Board (“APB”) 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlements) (the “FSP”). The FSP requires the issuer of certain convertible debt instruments that may be settled in cash on conversion to separately account for the liability and equity components in a manner that reflects the issuer’s nonconvertible debt borrowing rate. The resulting debt discount would be amortized over the period the convertible debt is expected to be outstanding as additional non-cash interest expense. The effective date of the FSP is for financial statements issued for fiscal years beginning after December 15, 2008. The FSP does not permit earlier application, however does require retrospective application to all periods presented in the financial statements (with the cumulative effect of the change reported in retained earnings as of the beginning of the first period presented). Our $175 million 3.25% convertible senior notes due 2026 (see Note 4) is affected by this new standard.

We adopted the standard as of January 1, 2009.

The following table summarizes the effect of retrospective effect of the adoption of the standard on the consolidated balance sheets as of December 31, 2008 and 2007, respectively:

	Previously Reported		Adjustment		Adjusted
	($ in thousands)
December 31, 2008
Deferred financing cost	4,382		(659	)	3,723
Long-term debt	250,000		(23,277	)	226,723
Deferred income tax liability	7,988		7,916		15,904
Additional paid in capital	576,961		23,164		600,125
Retained earnings	64,540		(8,462	)	56,078
December 31, 2007
Deferred financing cost	4,801		(885	)	3,916
Long-term debt	215,500		(30,051	)	185,449
Additional paid in capital	341,098		23,164		364,262
Retained earnings	(65,651	)	6,002		(59,649	)

31

GOODRICH PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the retrospective effect of the adoption of the standard on the consolidated statements of operations for the years ended December 31, 2008, 2007 and 2006, respectively:

	Previously Reported		Adjustment		Adjusted
	($ in thousands, except per share data)
Year ended December 31, 2008
Interest Expense	15,862		6,548		22,410
Income tax expense	46,556		7,916		54,472
Net income (loss) applicable to common stock	130,191		(14,464	)	115,727
Net income (loss) applicable to common stock per share
Basic	3.85		(0.43	)	3.42
Diluted	3.48		(0.25	)	3.23
Year ended December 31, 2007
Interest Expense	11,870		6,008		17,878
Income tax expense (benefit)	3,034		(12,328	)	(9,294	)
Net income (loss) applicable to common stock	(51,080	)	6,320		(44,760	)
Net income (loss) applicable to common stock per share
Basic	(2.00	)	0.25		(1.75	)
Diluted	(2.00	)	0.25		(1.75	)
Year ended December 31, 2006
Interest Expense	7,845		498		8,343
Income tax expense (benefit)	5,120		(180	)	4,940
Net income (loss) applicable to common stock	(5,922	)	(318	)	(6,240	)
Net income (loss) applicable to common stock per share
Basic	(0.24	)	(0.01	)	(0.25	)
Diluted	(0.24	)	(0.01	)	(0.25	)

The adoption of the standard resulted in recording additional deferred tax liability, consequently recognizing a net deferred tax liability in 2006, and reducing the increase in the valuation allowance in 2007 when the net deferred tax asset was subsequently reduced to zero. See NOTE 6.

In December 2008, the Securities and Exchange Commission (“SEC”) issued a final rule adopting revisions to its oil and gas reporting disclosures. The revisions are intended to provide investors with a more meaningful and comprehensive information related to the determination and disclosure of oil and gas reserves information. The provisions of this final rule are effective for fiscal years ending on or after December 31, 2009. We are currently assessing the impact that this final rule will have on our financial statements.

NOTE 2—Share-Based Compensation Plans

In May 2006, our shareholders approved our 2006 Long-Term Incentive Plan (the “2006 Plan”), at our annual meeting of stockholders. The 2006 Plan replaces our previously adopted Goodrich Petroleum Corporation 1995 Stock Option Plan and 1997 Non-Employee Directors’ Stock Option Plan.

The 2006 Plan is intended to promote the interests of the Company, by providing a means by which Employees, Consultants and Directors may acquire or increase their equity interest in the Company and may develop a sense of proprietorship and personal involvement in the development and financial success of the Company, and to encourage them to remain with and devote their best efforts to the business of the Company, thereby advancing the interests of the Company and its stockholders. The Plan is also contemplated to enhance the ability of the Company and its Subsidiaries to attract and retain the services of individuals who are essential for the growth and profitability of the Company.

32

GOODRICH PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The 2006 Plan provides that the Compensation Committee shall have the authority to determine the Participants to whom stock options, restricted stock, performance awards, phantom shares and Stock Appreciation Rights may be granted. The 2006 Plan also provides for grants to non-employee directors.

No further awards will be granted under the previously adopted plans, however, those plans shall continue to apply to and govern awards made thereunder. Under the 2006 Plan, a maximum of 2.0 million new shares are reserved for issuance as awards of share options to officers, employees and non-employee directors. As of December 31, 2008, a total of 1,196,096 shares were available for future grants under the 2006 Plan.

Stock Options

The 2006 Plan provides that the option price of shares issued be equal to the market price on the date of grant. With the exception of option grants to non-employee directors which vest immediately, options vest ratably on the anniversary of the date of grant over a period of time, typically three years. All options expire ten years after the date of grant.

Option activity under our stock option plans as of December 31, 2008, and changes during the 12 months then ended were as follows:

	Shares		Weighted Average Exercise Price		Remaining Contractual Term	Aggregate Intrinsic Value
					(in years)	(in thousands)
Outstanding at January 1, 2008	949,333		$	20.95
Granted	162,000			21.59
Exercised	(141,200	)		19.97		$	6,191
Forfeited	—			—
Outstanding at December 31, 2008	970,133		$	21.20	6.45	$	8,488
Exercisable at December 31, 2008	630,800		$	20.25	6.37	$	6,118

The aggregate intrinsic value in the preceding table represents the total pre-tax intrinsic value (the difference between our closing stock price on the last trading day of the fourth quarter of 2008 and the exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on December 31, 2008. The amount of aggregate intrinsic value will change based on the fair market value of our stock. The total intrinsic value of options exercised during the year ended December 31, 2008, 2007, and 2006 was $6.2 million, $1.8 million and $1.7 million, respectively.

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number Outstanding at December 31, 2008	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price		Number Exercisable at December 31, 2008	Weighted Average Exercise Price
		(years)
$2.63 to $5.85	24,000	2.21	$	3.97	24,000	$	3.97
$16.46 and $19.78	307,300	6.11		18.08	307,300		18.08
$21.59 to $27.81	638,833	6.77		23.35	299,500		23.78
	970,133	6.45	$	21.20	630,800	$	20.25

33

GOODRICH PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Effective January 1, 2006 we adopted SFAS 123R, which required us to measure the cost of stock based compensation granted, including stock options and restricted stock, based on the fair market value of the award as of the grant date, net of estimated forfeitures. SFAS 123R supersedes SFAS 123 and APB 25. We adopted SFAS 123R using the modified prospective application method of adoption, which required us to record compensation cost related to unvested stock awards as of December 31, 2005, by recognizing the unamortized grant date fair value of these awards over the remaining service periods of those awards with no change in historical reported earnings. Awards granted after December 31, 2005, are valued at fair value in accordance with provisions of SFAS 123R and recognized on a straight line basis over the service periods of each award. We estimated forfeiture rates for all unvested awards based on our historical experience.

The per share weighted average fair value of stock options granted during the years ended December 31, 2008 and 2006, were $10.72 and $12.98, respectively, on the date of grant. There were no options granted in 2007.

The estimated fair value of the options granted during 2008, 2006 and prior years was calculated using a Black-Scholes Merton option pricing model (Black Scholes). There were no options granted in 2007. The following schedule reflects the various assumptions included in this model as it relates to the valuation of our options:

	2008		2006
Risk free interest rate	3.52	%	4.50-4.97	%
Weighted average volatility	53	%	54-57	%
Dividend yield	0	%	0	%
Expected years until exercise	5		5-6

The Black-Scholes model incorporates assumptions to value stock based awards. The risk-free rate of interest for periods within the expected term of the option is based on a zero-coupon U.S. government instrument over the expected term of the equity instrument. Expected volatility is based on the historical volatility of our common stock. We generally use the midpoint of the vesting period and the life of the grant to estimate employee option exercise timing (expected term) within the valuation model. This methodology is not materially different from our historical data on exercise timing. In the case of director options, we used historical exercise behavior. Employees and directors that have different historical exercise behavior with regard to option exercise timing and forfeiture rates are considered separately for valuation and attribution purposes.

As of December 31, 2008, $3.6 million of total unrecognized compensation cost related stock options is expected to be recognized over a weighted average period of approximately 3.8 years.

Restricted Stock

In 2003, we commenced granting a series of restricted share awards. Restricted shares awarded under the 2006 Plan typically have a vesting period of three years. During the vesting period, ownership of the shares cannot be transferred and the shares are subject to forfeiture if employment ends before the end of the vesting period. Certain restricted stock awards provide for accelerated vesting. Restricted shares are not considered to be currently issued and outstanding. The fair value of the awards of restricted shares, determined as the market value of the shares at the date of grant, is expensed ratably over the vesting period.

The January 1, 2006, balance of unamortized restricted stock awards of $2.1 million was reclassified against additional paid-in-capital upon adoption of SFAS 123R. For all periods after January 1, 2006, common stock par value will be recorded when the restricted (phantom) stock is issued and additional paid-in-capital will be increased as the restricted stock compensation cost is recognized for financial reporting purposes. Prior period financial statements have not been restated.

During 2008, 2007 and 2006, we granted 437,048, 13,000 and 215,629 shares of our common stock, under the plan, valued at $11.4 million, $0.4 million and $7.1 million, respectively at the time of issuance. During 2008, 2007 and 2006, $3.3 million, $2.6 million and $2.1 million, respectively, were charged to compensation expense related to the restricted share awards. The fair value of restricted stock vested during 2008, 2007, and 2006 were $2.1 million, $4.5 million and $1.4 million, respectively.

34

GOODRICH PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Restricted stock activity under our plan as of December 31, 2008, and changes during the year then ended were as follows:

	Number of Shares		Weighted Average Grant-Date Fair Value		Total Value
Unvested at January 1, 2008	108,251		$	33.60	$	3,637,508
Vested	(68,347	)		30.87		(2,109,849	)
Granted	437,048			26.15		11,427,062
Forfeited	(5,866	)		30.01		(176,055	)
Unvested at December 31, 2008	471,086		$	27.13	$	12,778,666

As of December 31, 2008, $11.4 million of total unrecognized compensation cost related to restricted stock is expected to be recognized over a weighted average period of approximately 2.4 years.

Total stock based compensation for the year ended December 31, 2008, of $5.9 million has been recognized as a component of general and administrative expenses in the accompanying Consolidated Financial Statements.

The following table summarizes the components of our stock based compensation programs recorded as expense (in thousands):

	Year Ended December 31,
	2008		2007		2006
Pretax stock option expense	$	2,181	$	2,727	$	2,487
Pretax restricted stock expense		3,312		2,555		2,092
Pretax director stock expense		440		252		1,383
Total pretax stock based compensation:	$	5,933	$	5,534	$	5,962

35

GOODRICH PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 3—Asset Retirement Obligations

We apply SFAS No. 143 which requires us to record the fair value of a liability associated with the retirement obligations of our tangible long-lived assets in the periods in which it is incurred. We capitalize the discounted fair value of the liability when initially incurred. The liability is accreted through accretion expense to its full fair value over the life of the long-lived asset. Accretion expense is included in Depreciation, depletion and amortization on our Consolidated Statement of Operations.

The reconciliation of the beginning and ending asset retirement obligation for the periods ending December 31, 2008 and 2007, is as follows (in thousands):

	December 31,
	2008			2007
Beginning balance	$	6,180		$	9,557
Liabilities incurred		2,305			2,710
Revisions in estimated liabilities		5,063			—
Liabilities settled		—			(41	)
Accretion expense		331			221
Dispositions		(75	)		(6,267	)
Ending balance	$	13,804		$	6,180
Current liability	$	2,554		$	312
Long term liability	$	11,250		$	5,868

During 2008, we determined that the costs of restoring well site locations and to a lesser extent the plug and abandonment of well bores had significantly increased. Due to these increases, we revised our previously estimated asset retirement obligation by a discounted $5.1 million. We expect accretion expense to increase in future periods. The Dispositions for 2007 represents the Asset Retirement Obligation for substantially all of our properties in South Louisiana sold to a private company. The ending balance at December 31, 2008 and 2007 includes $1.4 million and $0.3 million, respectively, for Assets Held for Sale. See Note 9.

NOTE 4—Long-Term Debt

Long-term debt consisted of the following balances (in thousands):

	December 31,			December 31,
	2008			2007
Senior Credit Facility	$	—		$	40,500
Second Lien Term Loan		75,000			—
3.25% Convertible Senior notes due 2026		175,000			175,000
Debt discount on notes		(23,277	)		(30,051	)
Total long-term debt	$	226,723		$	185,449

Senior Credit Facility

In 2005, we amended our existing credit agreement and entered into an amended and restated senior credit agreement (as amended, the “Senior Credit Facility”) and a term loan that expanded our borrowing capabilities. Total lender commitments under the Senior Credit Facility were $200 million, and the Senior Credit Facility matures on February 25, 2010. Revolving borrowings under the Senior Credit Facility are limited to, and subject to periodic redeterminations of the borrowing base. We paid off the total amount outstanding under the Senior Credit Facility in July, 2008 with proceeds from our equity offering. Interest on revolving borrowings under the Senior Credit Facility accrues at a rate calculated, at our option, at the bank base rate plus 0.00% to 0.75%, or LIBOR plus 1.25% to 2.25%, depending on borrowing base utilization. At December 31, 2008, we had a borrowing base of $175.0 million and no amounts outstanding under the Senior Credit Facility. Pursuant to the terms of our Senior Credit Facility, the next redetermination of our borrowing base will be March 31, 2009.

36

GOODRICH PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The terms of the Senior Credit Facility, as amended, require us to maintain certain covenants. Capitalized terms used, but not defined, here have the meanings assigned to them in the Senior Credit Facility. As of December 31, 2008 we were in compliance with all of the financial covenants of our Senior Credit Facility. The covenants in effect at December 31, 2008 include:

• Current Ratio of 1.0/1.0;

• Interest Coverage Ratio of not less than 3.0/1.0 for the trailing four quarters;

• Total Debt no greater than 3.0 times EBITDAX for the trailing four quarters (EBITDAX is earnings before interest expense, income tax, DD&A, exploration expense and impairment of oil and gas properties. In calculating EBITDAX for this purpose, earnings include realized gains (losses) from derivatives but exclude unrealized gains (losses) from derivatives. The 3.25% convertible senior notes are excluded from the calculation of Total Debt for the purpose of computing this ratio.); and

• Asset coverage ratio (defined as the present value of proved reserves discounted at 10% divided by total debt, excludes 3.25% convertible senior notes) of not less than 1.5 to 1.0.

Second Lien Term Loan

On January 16, 2008, we entered into a new Second Lien Term Loan Agreement which provides for a 3-year, secured, non-revolving loan of $75.0 million and is due in a single maturity on December 31, 2010. We have no rights to prepay in the first year. Voluntary prepayment rights in the second year are at 101% of par, and thereafter at par. Interest on the Second Lien Term Loan accrues at a rate of LIBOR plus 550 basis points and is payable quarterly in arrears. As of December 31, 2008, we were in compliance with all of the financial covenants of our Second Lien Term Loan. The terms of the Second Lien Term Loan Agreement contain financial covenants which include:

• Asset coverage ratio (defined as the present value of proved reserves discounted 10% to total debt, excludes 3.25% convertible senior notes) of not less than 1.5 to 1.0;

• Total debt to EBITDAX ratio of not more than 3.0 to 1.0 (total debt to exclude the 3.25% convertible senior notes); and

• EBITDAX to interest expense ratio of not less than 3.0 to 1.0.

Convertible Senior Notes

In December 2006, we sold $175.0 million of 3.25% convertible senior notes (the “notes”) due in December 2026. The notes mature on December 1, 2026, unless earlier converted, redeemed or repurchased. The notes are our senior unsecured obligations and rank equally in right of payment to all of our other existing and future indebtedness. The notes accrue interest at a rate of 3.25% annually, and interest is paid semi-annually on June 1 and December 1. Interest payments on the notes began on June 1, 2007.

Before December 1, 2011, we may not redeem the notes. On or after December 11, 2011, we may redeem all or a portion of the notes for cash, and the investors may require us to repurchase the notes on each of December 11, 2011, 2016 and 2021. Upon conversion, we have the option to deliver shares at the applicable conversion rate, redeem in cash or in certain circumstances redeem in a combination of cash and shares. The notes are convertible into shares of our common stock at a rate equal to the sum of:

a) 15.1653 shares per $1,000 principal amount of notes (equal to a “base conversion price” of approximately $65.94 per share) plus

b) an additional amount of shares per $1,000 of principal amount of notes equal to the incremental share factor (2.6762), multiplied by a fraction, the numerator of which is the applicable stock price less the “base conversion price” and the denominator of which is the applicable stock price.

37

GOODRICH PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2008 the $175.0 million notes were carried on the balance sheet as $151.7 million with a debt discount of $23.3 million. This remaining amount of debt discount will be amortized using the effective interest rate method based on the original 5 year term through December 1, 2011. Debt discount amortization taken on the original debt discount of $36.8 million was $6.8 million, $6.2 million and $0.5 million in the years 2008, 2007 and 2006 respectively. The effective interest rate on the liability component of the Senior Notes is 9%.

NOTE 5—Net Income (Loss) Per Common Share

Net income (loss) applicable to common stock was used as the numerator in computing basic and diluted income (loss) per common share for the years ended December 31, 2008, 2007 and 2006. The following table sets forth information related to the computations of basic and diluted income (loss) per share.

	Year Ended December 31,
	2008		2007			2006
	(Amounts in thousands, except per share data)
Basic income (loss) per share:
Income (loss) applicable to common stock	$	115,727	$	(44,760	)	$	(6,240	)
Average shares of common stock outstanding (1)		33,806		25,578			24,948
Basic income (loss) per share	$	3.42	$	(1.75	)	$	(0.25	)
Diluted income (loss) per share:
Income (loss) applicable to common stock	$	115,727	$	(44,760	)	$	(6,240	)
Dividends on convertible preferred stock (2)		6,047		—			—
Interest and amortization of loan cost on senior convertible notes, net of tax (3)		8,651		—			—
Diluted income (loss)	$	130,425	$	(44,760	)	$	(6,240	)
Average shares of common stock outstanding (1)		33,806		25,578			24,948
Assumed conversion of convertible preferred stock (2)		3,588		—			—
Assumed conversion of convertible senior notes (3)		2,654		—			—
Stock options, warrants and restricted stock (4)		349		—			464
Average diluted shares outstanding		40,397		25,578			25,412
Diluted income (loss) per share	$	3.23	$	(1.75	)	$	(0.25	)

(1) This amount does not include 1,624,300 shares in 2008 and 3,122,263 shares each in 2006 and 2007 of common stock outstanding under the Share Lending Agreement. See Note 7.

(2) Common shares issuable upon assumed conversion of our convertible preferred stock amounting to 3,587,850 shares and the accrued dividends on the preferred stock were not included in the computation of diluted loss per share for 2006 and 2007 as they would have not been dilutive.

(3) Common shares issuable upon assumed conversion of our convertible senior notes amounting to 2,653,927 shares and the accrued interest on the senior notes were not included in the computation of diluted loss per share for the periods presented in 2006 and 2007 as they would have not been dilutive.

(4) Common shares on assumed conversion of restricted stock and employee stock option stock in the amounts of 463,173 and 210,180 shares for the years 2006 and 2007 respectively, were not included in the computation of diluted loss per common share since their inclusion would have not been dilutive.

38

GOODRICH PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6—Income Taxes

Income tax (expense) benefit consisted of the following (in thousands):

	Year Ended December 31,
	2008			2007			2006
Current:
Federal	$	(5,331	)	$	(97	)	$	—
State		(10,813	)		—			—
		(16,144	)		(97	)		—
Deferred:
Federal		(37,192	)		3,303			(724	)
State		(866	)		—			—
		(38,058	)		3,303			(724	)
Total	$	(54,202	)	$	3,206		$	(724	)

The following is a reconciliation of the U.S. statutory income tax rate at 35% to our income (loss) before income taxes (in thousands):

	Year Ended December 31,
	2008			2007			2006
Income tax (expense) benefit from continuing operations
Tax at U.S. statutory income tax	$	(61,861	)	$	20,833		$	(4,872	)
Valuation allowance		15,268			(11,480	)		—
State income taxes-net of federal benefit		(7,895	)		—			—
Nondeductible expenses and other		16			(59	)		(68	)
		(54,472	)		9,294			(4,940	)
Income tax (expense) benefit from discontinued operations
Tax at U.S. statutory income tax		270			(6,088	)		4,216
		270			(6,088	)		4,216
Total tax benefit (expense)	$	(54,202	)	$	3,206		$	(724	)

39

GOODRICH PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are presented below (in thousands):

	December 31,
	2008			2007
Current deferred tax liabilities:
Derivative financial instruments	$	(18,931	)		—
Total current deferred tax liabilities		(18,931	)		—
Noncurrent deferred tax assets:
Operating loss carryforwards	$	2,627		$	18,725
Statutory depletion carryforward		7,034			7,034
AMT tax credit carryforward		6,854			1,523
Derivative financial instruments		216			184
Compensation		2,403			2,075
Contingent liabilities and other		1,235			5,215
Total gross noncurrent deferred tax assets		20,369			34,756
Less valuation allowance		(7,486	)		(22,752	)
Net noncurrent deferred tax assets		12,883			12,004
Noncurrent deferred tax liabilities:
Property and equipment		(17,680	)		(126	)
Bond discount		(2,960	)		(1,360	)
Debt Discount		(8,147	)		(10,518	)
Derivative financial instruments		—			—
Total noncurrent deferred tax liabilities		(28,787	)		(12,004	)
Net noncurrrent deferred tax asset (liability)	$	(15,904	)	$	—

The valuation allowance for deferred tax assets decreased by $15.3 million in 2008. This decrease was primarily due to a significant gain on sale of assets recognized in the third quarter. As a result of this gain on sale, we believe that we will be in a position to utilize the majority of our net operating loss carryforwards when we file our 2008 tax return. We believe it is now more likely than not that we will be able to recognize our deferred tax assets associated with these net operating loss carry forwards and have therefore released the previously booked valuation allowance.

As of December 31, 2008, we have net operating loss carryforwards of approximately $9.8 million for tax purposes which will expire in 2026. The Company also has a minimum tax credit carryforward of $6.9 million which will not begin to be used until after the available NOLs have been used or expired and when regular tax exceeds the current year alternative minimum tax.

Our stock based deferred compensation plans have generated $11.5 million of additional tax deductions through 2008. The Company realized $9.2 million ($3.2 million, net of tax) of these deductions in 2008 and the associated tax benefit was recorded as additional paid in capital. The remaining tax deductions are not currently recognized as a component of our deferred tax asset. They will be recognized when the net operating loss carryforward is utilized to offset future taxable income.

In July 2005, we received a Notice of Proposed Tax Due from the State of Louisiana asserting that we underpaid our Louisiana franchise taxes for the years 1998 through 2004 in the amount of $0.6 million. The Notice of Proposed Tax Due includes additional assessments of penalties and interest in the amount of $0.4 million for a total asserted liability of $1.0 million. In order to avoid future penalties and interest, the Company paid, under protest, $1.0 million to the State of Louisiana in April 2007 which payment was expensed in general and administrative expense in first quarter 2007. We plan to pursue the reimbursement of the full $1.0 million paid under protest. Should our efforts prevail, the taxes paid under protest would be refunded, at which time we would book a credit to general and administrative expense.

40

GOODRICH PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

The amount of unrecognized tax benefits did not materially change as of December 31, 2008. The amount of unrecognized tax benefits may change in the next twelve months; however we do not expect the change to have a significant impact on our results of operations or our financial position. We file a consolidated federal income tax return in the United States and various combined and separate filings in several state and local jurisdictions. With limited exceptions, we are no longer subject to U.S. Federal, state and local, or non-U.S. income tax examinations by tax authorities for years before 1992.

Our continuing practice is to recognize estimated interest and penalties related to potential underpayment on any unrecognized tax benefits as a component of income tax expense in the Consolidated Statement of Operations. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations before December 31, 2009.

NOTE 7—Stockholders’ Equity

Caddo Parish Acquisition for Common Stock

In May 2008, we acquired approximately 3,665 net acres in the Longwood field of Caddo Parish, Louisiana, through the issuance of 908,098 shares of our common stock valued at approximately $33.9 million. See Note 12.

Equity Offering

On July 14, 2008, we closed the public offering of 3,121,300 shares of our common stock at a price of $64.00 per share. Net proceeds from the offering were approximately $191.3 million after deducting the underwriters’ discount and estimated offering expenses. We used approximately $96.0 million of the net proceeds to pay off outstanding borrowings under our Senior Credit Facility. We used the remaining net proceeds for general corporate purposes, including the funding of a portion of our 2008 drilling program, other capital expenditures and working capital requirements.

Share Lending Agreement

In connection with the offering of our 3.25% notes in December 2006, we agreed to lend an affiliate of Bear, Stearns & Co. (“BSC”) a total of 3,122,263 shares of our common stock under the Share Lending Agreement. Under this agreement, BSC is entitled to offer and sell such shares and use the sale to facilitate the establishment of a hedge position by investors in the notes. BSC will receive all proceeds from the common stock offerings and lending transactions under this agreement. BSC is obligated to return the shares to us in the event of certain circumstances, including the redemption of the notes or the conversion of the notes to shares of our common stock pursuant to the terms of the indenture governing the notes.

The Share Lending Agreement also requires BSC to post collateral if its credit rating is below either A3 by Moody’s Investors Service (“Moody’s”) or A- by Standard and Poor’s (“S&P”). As a result of the long term ratings downgrade of BSC in March 2008, BSC was required to return all or a portion of the borrowed shares or collateralize the return obligation with cash or highly liquid non-cash collateral. On March 20, 2008, BSC had returned 1,497,963 shares of the 3,122,263 originally borrowed shares and fully collateralized the remaining 1,624,300 borrowed shares with a cash collateral deposit of approximately $41.3 million. This amount represents the market value of the remaining borrowed shares at March 20, 2008. Under certain conditions, BSC is required to maintain collateral value in the amount at least equal to the market value of the outstanding borrowed shares. The 1,497,963 shares returned to us were recorded as treasury stock and retired in March 2008.

In May 2008, JP Morgan Chase & Co. completed its acquisition of and assumed all counterparty liabilities of The Bear Stearns Companies Inc. JP Morgan Chase & Co.’s credit rating exceeds that required by the Share Lending Agreement. Thus, collateral is no longer required.

The 1,624,300 shares of common stock outstanding as of December 31, 2008, under the Share Lending Agreement are required to be returned to us in the future. The shares are treated in basic and diluted earnings per share as if they were already returned and retired. As a result, the shares of common stock lent under the Share Lending Agreement have no impact on the earnings per share calculation.

41

GOODRICH PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Capped Call Option Transactions

On December 10, 2007, we closed the public offering of 6,430,750 shares of our common stock at a price of $23.50 per share. Net proceeds from the offering were approximately $145.4 million after deducting the underwriters’ discount and estimated offering expenses. We used approximately $123.8 million of the net proceeds to pay off outstanding borrowings under our Senior Credit Facility, and approximately $21.6 million of the net proceeds to purchase capped call options on shares of our common stock from affiliates of BSC and J.P. Morgan Securities Inc. The capped call option transactions covered, subject to customary anti-dilution adjustments, approximately 5.8 million shares of our common stock, and each of them was divided into a number of tranches with differing expiration dates. One third of the options will expire over each of three separate multi-day settlement periods beginning approximately 18 months, 24 months and 30 months from the closing of the offering, respectively.

The capped call option transactions are expected to result in our receipt, on a net share, cashless basis of a certain number of shares of our common stock if the market value per share of the common stock, as measured under the terms of the capped call option agreements, on the option expiration date for the relevant tranche is greater than the lower call strike price of the capped call option transactions. We refer to the amount by which the market value per share exceeds the lower call strike price as an “in-the-money amount” for the relevant tranche of the capped call option transaction. The in-the-money amount will never exceed the difference between the upper call strike price and the lower call strike price (i.e., it will be “capped”). The lower call strike price is $23.50, which corresponds to the price to the public in the equity offering and the upper call strike price is $32.90, which corresponds to 140% of the price to the public in the offering. Both lower and upper call strike prices are subject to customary anti-dilution and certain other adjustments. The number of shares of our common stock that we will receive from the option counterparties upon expiration of each tranche of the capped call option transactions will be equal to the in-the-money amount of that tranche divided by the market value per share of the common stock, as measured under the terms of the capped call option agreements, on the option expiration date for that tranche. If the stock price is equal to the upper call strike price of $32.90 on each of the settlement dates, we will recoup up to 1.6 million shares.

The capped call option agreements were separate transactions entered into by us with the option counterparties and were not part of the terms of the offering of common stock.

The capped call option agreements require an option counterparty to transfer their rights and obligations within 30 days if their credit rating is below either Baa1 by Moody’s or BBB+ by S&P. As a result of the ratings downgrade of BSC on March 14, 2008, BSC was obligated to transfer their rights and obligations under the capped call option agreement to a suitable counterparty (one with a credit rating of at least BBB+ by S&P and Baa1 by Moody’s) within 30 days. BSC’s obligation to transfer its rights and obligations to an entity with a higher credit rating was cured by a ratings upgrade on March 24, 2008.

During the second quarter of 2008, BSC sold its position in the capped call options to Bank of America.

Preferred Stock

Our Series B Convertible Preferred Stock (the “Series B Convertible Preferred Stock”) was initially issued on December 21, 2005, in a private placement of 1,650,000 shares for net proceeds of $79.8 million (after offering costs of $2.7 million). Each share of the Series B Convertible Preferred Stock has a liquidation preference of $50 per share, aggregating to $82.5 million, and bears a dividend of 5.375% per annum. Dividends are payable quarterly in arrears beginning March 15, 2006. If we fail to pay dividends on our Series B Convertible Preferred Stock on any six dividend payment dates, whether or not consecutive, the dividend rate per annum will be increased by 1.0% until we have paid all dividends on our Series B Convertible Preferred Stock for all dividend periods up to and including the dividend payment date on which the accumulated and unpaid dividends are paid in full.

42

GOODRICH PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

On January 23, 2006, the initial purchasers of the Series B Convertible Preferred Stock exercised their over-allotment option to purchase an additional 600,000 shares at the same price per share, resulting in net proceeds of $29.0 million, which was used to fund our 2006 capital expenditure program.

Each share is convertible at the option of the holder into our common stock, par value $0.20 per share (the “Common Stock”) at any time at an initial conversion rate of 1.5946 shares of Common Stock per share, which is equivalent to an initial conversion price of approximately $31.36 per share of Common Stock. Upon conversion of the Series B Convertible Preferred Stock, we may choose to deliver the conversion value to holders in cash, shares of Common Stock, or a combination of cash and shares of Common Stock.

If a fundamental change occurs, holders may require us in specified circumstances to repurchase all or part of the Series B Convertible Preferred Stock. In addition, upon the occurrence of a fundamental change or specified corporate events, we will under certain circumstances increase the conversion rate by a number of additional shares of Common Stock. A “fundamental change” will be deemed to have occurred if any of the following occurs:

• We consolidate or merge with or into any person or convey, transfer, sell or otherwise dispose of or lease all or substantially all of our assets to any person, or any person consolidates with or merges into us or with us, in any such event pursuant to a transaction in which our outstanding voting shares are changed into or exchanged for cash, securities, or other property; or

• We are liquidated or dissolved or adopt a plan of liquidation or dissolution.

A “fundamental change” will not be deemed to have occurred if at least 90% of the consideration in the case of a merger or consolidation under the first clause above consists of common stock traded on a U.S. national securities exchange and the Series B Preferred Stock becomes convertible solely into such common stock.

On or after December 21, 2010, we may, at our option, cause the Series B Convertible Preferred Stock to be automatically converted into that number of shares of Common Stock that are issuable at the then-prevailing conversion rate, pursuant to the Company Conversion Option. We may exercise our conversion right only if, for 20 trading days within any period of 30 consecutive trading days ending on the trading day before the announcement of our exercise of the option, the closing price of the Common Stock equals or exceeds 130% of the then-prevailing conversion price of the Series B Convertible Preferred Stock. The Series B Convertible Preferred Stock is non-redeemable by us.

We used the net proceeds of the offering of Series B Convertible Preferred Stock to fully repay all outstanding indebtedness under our senior revolving credit facility. The remaining net proceeds of the offering were added to our working capital to fund 2006 capital expenditures and for other general corporate purposes.

NOTE 8—Derivative Activities

Commodity Derivative Activity

We enter into swap contracts, costless collars or other derivative agreements from time to time to manage the commodity price risk for a portion of our production. Our strategy, which is administered by the Hedging Committee of our Board of Directors, and reviewed periodically by the entire Board of Directors, has been to generally hedge between 30% and 70% of our estimated total production for the period the derivatives are in effect. As of December 31, 2008, the commodity derivatives we used were in the form of:

(a) swaps, where we receive a fixed price and pay a floating price, based on NYMEX and field prices,

(b) collars, where we receive the excess, if any, of the floor price over the reference price, based on NYMEX quoted prices, and pay the excess, if any, of the reference price over the ceiling price; and

We account for our commodity derivative contracts in accordance with SFAS 133, which requires each derivative to be recorded on the balance sheet as an asset or liability at its fair value. Additionally, the statement requires that changes in a derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met at the time the derivative contract is executed. Currently, none of our commodity derivative contracts are being accounting for as hedges and as such, all changes in the fair value of these instruments are recognized in earnings.

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GOODRICH PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

As of December 31, 2008, our open forward positions on our outstanding commodity hedging contracts, all of which were with either BNP or Bank of Montreal, was as follows:

Collars (NYMEX)	Daily Volume	Total Volume	Floor/Cap Average Price	Fair Value at December 31, 2008
Natural gas (MMBtu)				$	19,396,126
1Q 2009	20,000	1,800,000	$8.75 – $13.10
2Q 2009	20,000	1,820,000	$8.75 – $13.10
3Q 2009	20,000	1,840,000	$8.75 – $13.10
4Q 2009	20,000	1,840,000	$8.75 – $13.10
Swaps (NYMEX)			Average Price
Natural gas (MMBtu)					19,773,709
1Q 2009	20,000	1,800,000	$8.83
2Q 2009	20,000	1,820,000	$8.83
3Q 2009	20,000	1,840,000	$8.83
4Q 2009	20,000	1,840,000	$8.83
Swaps (TexOk)			Field Price (1)
Natural gas (MMBtu)					16,106,471
1Q 2009	20,000	1,800,000	$7.87
2Q 2009	20,000	1,820,000	$7.87
3Q 2009	20,000	1,840,000	$7.87
4Q 2009	20,000	1,840,000	$7.87
			Total	$	55,276,306

(1) The index price is based upon Natural Gas Pipeline of America. TexOK (“NGPLTXOK”) zone as published in the Inside FERC. The comparable index price based on NYMEX was approximately $8.25/Mmbtu.

For the year ended December 31, 2008 we recognized a gain of $53.6 million from natural gas derivatives made up of an unrealized gain of $55.4 million offset by a realized loss of $1.8 million.

We have entered into the following contracts subsequent to December 31, 2008:

(a) A NGPLTXOK priced basis swap contract with the Bank of Montreal for 20,000 Mmbtu per day for the months of March through December 2009, locking in a fixed basis to the Company of $0.52 per Mmbtu, and

(b) A NGPLTXOK priced basis swap contract with BNP for 20,000 Mmbtu per day for the months of March through December 2009 locking in a fixed basis to the Company of $0.52 per Mmbtu.

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GOODRICH PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Interest Rate Swaps

We have several variable-rate debt obligations that expose us to the effects of changes in interest rates. To partially reduce our exposure to interest rate risk, from time to time we enter into interest rate swap agreements. We have not designated our interest rate swaps as hedges under FAS 133. At December 31, 2008, we had the following interest rate swaps in place with BNP Paribas and Bank of Montreal.

Effective Date	Maturity Date	Libor Swap Rate		Notional Amount (Millions)		Fair Value (Dollars)
2/26/2007	2/26/2009	4.860	%	$	40.0	$	(271,029	)
4/22/2008	4/22/2010	3.191	%		25.0		(515,584	)
4/22/2008	4/22/2010	3.191	%		50.0		(1,017,416	)
						$	(1,804,029	)

For the year ended December 31, 2008, we recognized a $2.1 million loss from the interest rate swaps, of which $1.4 million was unrealized.

NOTE 9—Discontinued Operations

On March 20, 2007, we closed the sale of substantially all of our oil and gas properties in South Louisiana with the exception of the St. Gabriel, Bayou Bouillon and Plumb Bob fields as discussed under Note 1 “Assets Held for Sale.” In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the results of operations for the properties that were sold and for the properties that are held for sale have been reflected as discontinued operations. On August 4, 2008, we closed the sale of our St. Gabriel field and on August 12, 2008 we assigned our interest in the Bayou Bouillon field. See Note 12. We are actively pursuing bids and will accept any reasonable offer on the remaining Plumb Bob field.

The following table summarizes the amounts included in Income (loss) from discontinued operations net of tax (in thousands):

	2008			2007			2006
Revenues	$	900		$	9,470		$	41,383
Income (loss) from discontinued operations		(817	)		2,766			(11,876	)
Income tax benefit (expense)		286			(959	)		4,216
Income (loss) from discontinued operations, net of tax		(531	)		1,807			(7,660	)

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GOODRICH PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 10—Commitments and Contingencies

The table below provides estimates of the timing of future payments that we are obligated to make based on agreements in place at December 31, 2008.

	Payment due by Period
	Total		2009		2010		2011		2012		2013 and After
Contractual Obligations
Office space leases	$	1,699	$	679	$	207	$	213	$	220	$	380
Office equipment leases		387		279		79		13		8		8
Drilling contracts		47,672		26,976		8,579		7,665		4,452		—
Operational contracts		1,589		699		595		291		4		—
Transportation contracts		3,831		1,804		1,926		101		—		—
Total contractual obligations	$	55,178	$	30,437	$	11,386	$	8,283	$	4,684	$	388

Operating Leases—We have commitments under an operating lease agreement for office space. Total rent expense for the years ended December 31, 2008, 2007, and 2006, was approximately $0.9 million, $0.8 million and $0.6 million.

Drilling Contracts—We have six drilling rigs under contract as of December 31, 2008, four of which are scheduled to expire within 2009.

Litigation—We are party to lawsuits arising in the normal course of business. We intend to defend these actions vigorously and believe, based on currently available information, that adverse results or judgments from such actions, if any, will not be material to our financial position or results of operations.

NOTE 11—Related Party Transactions

Patrick E. Malloy, III, Chairman of the Board of Directors of our company is a principle of Malloy Energy Company, LLC (“MEC”). In 2003 and 2004 MEC acquired an approximate 30% working interest in the Bethany Longstreet, Plumb Bob and St. Gabriel fields for which we were the operator. In accordance with industry standard joint operating agreements, we bill MEC for its share of capital and operating cost on a monthly basis. As of December 31, 2008 and 2007, the amounts billed and outstanding to MEC for its share of monthly capital and operating costs were $0.6 million and $1.9 million, respectively, and are included in trade and other accounts receivable at each year-end. Such amounts at each year-end were paid by MEC to us in the month after billing and the affiliate is current on payment of its billings.

At the same time we sold a portion of our interests in the Haynesville Shale deep rights at Bethany Longstreet field, MEC consummated a similar transaction for its 30% working interest in the same deep rights with Chesapeake Energy Corporation, or Chesapeake. We and MEC also sold our interest in the St. Gabriel field in August, 2008. See Note 12.

We also serve as the operator for a number of other oil and gas wells owned by affiliates of MEC in which we will earn an average working interest of 11% after payout. In accordance with industry standard joint operating agreements, we bill the affiliate for its share of the capital and operating costs of these wells on a monthly basis. As of December 31, 2008 and 2007, the amounts billed and outstanding to the affiliate for its share of monthly capital and operating costs were both less than $0.1 million at the end of each period and are included in trade and other accounts receivable at each year-end. Such amounts at each year-end were paid by the affiliate to us in the month after billing and the affiliate is current on payment of its billings.

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GOODRICH PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 12—Acquisitions and Divestitures

Acquisitions

In February 2008, we acquired additional acreage located in the Angelina River trend for $2.5 million from a private company. We acquired an additional 40% working interest in the James Lime rights in our Bethune area, and an additional 31.25% working interest in the James Lime rights in our Allentown area. After the drilling of the second Allentown well, we earned an additional 6.25% working interest in the James Lime for a total working interest of 93.75%.

In May 2008, we acquired additional interests in the Cotton Valley Trend, which increased our net exposure in the Haynesville Shale. We acquired 3,665 net acres in the Longwood field of Caddo Parish, Louisiana, through the issuance of 908,098 shares of our common stock valued at approximately $33.9 million.

On June 10, 2008, we entered into a definitive agreement with a private company for the right to acquire over time a 50% non-operated interest in 5,800 gross acres (2,900 net) in the Caddo Pine Island field, adjacent to our Longwood field in Caddo Parish, Louisiana. We estimate total consideration to be approximately $3.3 million, which will be comprised of acreage costs for the 50% interest in the leasehold and the cost of a carried interest on the initial well drilled on the acreage.

In two separate transactions in the third quarter of 2008, we purchased a 70% interest in approximately 638 acres of Haynesville Shale formation deep rights in Northwest Louisiana for approximately $6.7 million. Under our joint agreement, we sold 20% of our interest to Chesapeake for $2.6 million in the third quarter 2008. We realized a gain of $0.6 million on the sale.

On August 8, 2008, we announced that we closed on the acquisition of a 50% operated interest in approximately 3,000 gross (1,500 net) acres in northern Nacogdoches County, Texas, approximately five miles southeast of the Trawick field. Purchase price for the acreage, including drilling promote on the initial well, is estimated to be approximately $1.9 million. We have the right to acquire a 50% interest in an additional 3,000 gross (1,500 net) acres through future development for $1,000 per acre, bringing the total potential acreage to approximately 6,000 gross (3,000 net) acres.

Divestitures

On June 16, 2008, we entered into a joint development agreement with Chesapeake to develop our Haynesville Shale acreage in the Bethany Longstreet and Longwood fields of Caddo and DeSoto Parishes, Louisiana. Chesapeake purchased the deep rights to approximately 10,250 net acres of oil and natural gas leasehold comprised of a 20% working interest in approximately 25,000 net acres in the Bethany Longstreet field and a 50% working interest in approximately 10,500 net acres in the Longwood field for $172.6 million. The sale closed on July 15, 2008, resulting in net proceeds of $172.0 million and a gain on the transaction of $145.1 million. Chesapeake also purchased 7,500 net acres of deep rights in the Bethany Longstreet field from a third party, bringing the ownership interest in the deep rights in both fields after closing to 50% each for us and Chesapeake.

Assets held for sale

In March 2008, we sold seismic data related to the St. Gabriel field for an adjusted price of $0.3 million. The adjusted proceeds of $0.3 million were recorded as a gain. See Note 1.

On August 4, 2008, we closed the sale of our St. Gabriel field to a private party for $0.1 million, resulting in a gain of $0.1 million. This asset was treated as held for sale at December 31, 2007. See Note 1.

On August 12, 2008, we assigned our interest in the Bayou Bouillon field to a private party for a nominal amount. This asset was treated as held for sale at December 31, 2007. We realized a loss of $0.3 million. See Note 1.

NOTE 13—Fair Value Measurements

We adopted SFAS 157 effective January 1, 2008 for financial assets and liabilities measured on a recurring basis. SFAS 157 applies to all financial assets and liabilities that are required to be measured and reported on a fair value basis. In February 2008, the

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GOODRICH PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FASB issued FSP 157-2, which delayed the effective date of SFAS 157 to fiscal years beginning after November 15, 2008 for nonfinancial assets and liabilities. For the year ended December 31, 2008, SFAS 157 affects the Company’s fair value measurements of its commodity and interest rate derivative positions.

Fair value, as defined in SFAS 157, is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value of an asset should reflect its highest and best use by market participants, whether an in-use or an in-exchange valuation premise. The fair value of a liability should reflect the risk of nonperformance, which includes, among other things, the Company’s credit risk.

Valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach. The selection and application of one or more of the techniques requires significant judgment and are primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy:

Level 1 Inputs

These inputs come from quoted prices (unadjusted) in active markets for identical assets or liabilities.

Level 2 Inputs

These inputs are other than quoted prices that are observable, for an asset or liability. This includes: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 3 Inputs

These are unobservable inputs for the asset or liability which require the Company’s own assumptions.

As required by SFAS 157, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. We measure the fair value of our derivative contracts by applying the income approach.

The following table summarizes the valuation and classification of our derivative instruments under SFAS 157 as of December 31, 2008:

	Fair Value Measurement (in thousands)
Description	Level 1		Level 2			Level 3		Total
Current assets	$	—	$	55,276		$	—	$	55,276
Current liabilities		—		(1,187	)		—		(1,187	)
Long term liabilities		—		(617	)		—		(617	)
Total	$	—	$	53,472		$	—	$	53,472

NOTE 14—Fair Value of Financial Instruments

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of SFAS No. 107, “Disclosures About Fair Value of Financial Instruments” (“SFAS 107”). The estimated fair value amounts have been

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GOODRICH PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

determined using available market information and valuation methodologies described below. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect of the estimated fair value amounts.

The carrying values of items comprising current assets and current liabilities approximate fair values due to these short-term maturities of these instruments. We estimate the fair value of our convertible senior notes using quotes from third parties. The carrying amounts and fair values of the other financial instruments and derivatives at December 31, 2008 and 2007, are as follows (in thousands):

	2008						2007
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Senior Credit Facility	$	—		$	—		$	40,500		$	40,500
Second lien term loan		75,000			75,000			—			—
3.25% Convertible Senior Notes		151,723			132,948			144,949			140,656
Derivative assets (liabilities)
Gas		55,276			55,276			(139	)		(139	)
Interest rate		(1,804	)		(1,804	)		(384	)		(384	)

NOTE 15—Oil and Gas Producing Activities (Unaudited)

Capitalized Costs Related to Oil and Gas Producing Activities

The table below reflects our capitalized costs related to oil and gas producing activities at December 31, 2008, and 2007 (in thousands):

	2008			2007
Proved properties	$	1,077,009		$	716,001
Unproved properties		33,429			25,587
		1,110,438			741,588
Less accumulated depreciation, depletion and amortization		(305,448	)		(185,068	)
Net oil and gas properties	$	804,990		$	556,520

Costs Incurred

Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized as follows (in thousands):

	Year Ended December 31,
	2008		2007		2006
Property Acquisition
Unproved	$	54,657	$	10,745	$	8,569
Proved		7,751		—		6,120
Exploration		44,765		20,429		12,263
Development (1)		315,030		269,664		244,240
	$	422,203	$	300,838	$	271,192

(1) Includes asset retirement costs of $7.4 million in 2008, $2.7 million in 2007, and $1.3 million in 2006.

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GOODRICH PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Oil and Natural Gas Reserves

All of our reserve information related to crude oil, condensate, and natural gas liquids and natural gas was compiled based on evaluations performed by Netherland, Sewell & Associates, Inc. as of December 31, 2008, 2007 and 2006. All of the subject reserves are located in the continental United States.

Many assumptions and judgmental decisions are required to estimate reserves. Quantities reported are considered reasonable but are subject to future revisions, some of which may be substantial, as additional information becomes available. Such additional knowledge may be gained as the result of reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes, and other factors.

Regulations published by the SEC define proved reserves as those volumes of crude oil, condensate, natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those volumes expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are those volumes expected to be recovered as a result of making additional investments by drilling new wells on acreage offsetting productive units or recompleting existing wells.

The following table sets forth our net proved oil and gas reserves at December 31, 2008, 2007 and 2006 and the changes in net proved oil and gas reserves for the years ended December 31, 2008, 2007 and 2006:

	Natural Gas (MMcf)						Oil (MBbls)
	2008		2007		2006		2008		2007		2006
Proved reserves at beginning of period	346,930		187,012		142,963		1,810		3,201		4,973
Revisions of previous estimates (1)	(62,616	)	10,884		(66,409	)	(137	)	714		(1,612	)
Extensions, discoveries and other additions (2)	126,350		179,959		115,732		470		712		311
Purchases of minerals in place	2,988		—		7,727		15		—		3
Sales of minerals in place	(14	)	(15,111	)	—		(1	)	(2,610	)	—
Production	(23,189	)	(15,814	)	(13,001	)	(174	)	(207	)	(474	)
Proved reserves at end of period	390,449		346,930		187,012		1,983		1,810		3,201
Proved developed reserves:
Beginning of period	108,077		76,679		56,700		282		1,862		1,796
End of period	150,174		108,077		76,679		387		282		1,862

	Natural Gas Equivalents (MMcfe)
	2008		2007		2006
Proved reserves at beginning of period	357,792		206,217		172,801
Revisions of previous estimates (1)	(63,438	)	15,169		(76,081	)
Extensions, discoveries and other additions (2)	129,170		184,232		117,597
Purchases of minerals in place	3,078		—		7,745
Sales of minerals in place	(20	)	(30,770	)	—
Production	(24,233	)	(17,056	)	(15,845	)
Proved reserves at end of period	402,349		357,792		206,217
Proved developed reserves:
Beginning of period	109,769		87,851		67,476
End of period	152,496		109,769		87,851

(1) Revisions of previous estimates were positive in the aggregate in 2007 due to a combination of increased prices from the end of 2006 to the end of 2007 and volume revisions resulting from updated production performance in many of our fields. Alternatively, the revisions of previous estimates in 2006 and 2008 were negative due primarily to significant pricing decreases in both years which caused a number of our proved undeveloped locations in the Cotton Valley area to become uneconomic at those lower price levels.

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GOODRICH PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(2) Extensions, discoveries and other reserve additions were positive on an overall basis in all three periods presented, primarily related to our continued drilling activity on existing and newly acquired properties in the Cotton Valley trend of East Texas and North Louisiana.

Standardized Measure

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves as of year-end is shown below (in thousands):

	2008			2007			2006
Future revenues	$	2,052,735		$	2,399,272		$	1,190,367
Future lease operating expenses and production taxes		(816,941	)		(794,960	)		(409,775	)
Future development costs (1)		(675,787	)		(709,355	)		(337,576	)
Future income tax expense		(6,907	)		(103,186	)		(28,764	)
Future net cash flows		553,100			791,771			414,252
10% annual discount for estimated timing of cash flows		(385,657	)		(507,654	)		(213,971	)
Standardized measure of discounted future net cash flows	$	167,443		$	284,117		$	200,281
Index price used to calculate reserves (2)
Natural gas (per Mcf)	$	5.71		$	6.80		$	5.64
Oil (per Bbl)	$	41.00		$	92.50		$	57.75

(1) Includes cumulative asset retirement obligations of $13.8 million, $6.2 million and $9.6 million in 2008, 2007 and 2006, respectively.

(2) These index prices, used to estimate our reserves at these dates, are before deducting or adding applicable transportation and quality differentials on a well-by-well basis.

Future revenues are computed by applying year-end prices of oil and gas to the year-end estimated future production of proved oil and gas reserves. The base prices used for the PV-10 calculation were public market prices on December 31 adjusted by differentials to those market prices. These price adjustments were done on a property-by-property basis for the quality of the oil and natural gas and for transportation to the appropriate location. Estimates of future development and production costs are based on year-end costs and assume continuation of existing economic conditions and year-end prices. We will incur significant capital in the development of our Cotton Valley trend properties. We believe with reasonable certainty that we will be able to obtain such capital in the normal course of business. The estimated future net cash flows are then discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows. The standardized measure of discounted cash flows is the future net cash flows less the computed discount.

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GOODRICH PETROLEUM CORPORATION

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Changes in Standardized Measure

The following are the principal sources of change in the standardized measure of discounted net cash flows for the years shown (in thousands):

	Year Ended December 31,
	2008			2007			2006
Balance, beginning of year	$	284,117		$	200,281		$	410,620
Net changes in prices and production costs related to future production		(68,643	)		94,478			(360,635	)
Sales and transfers of oil and gas produced, net of production costs		(167,516	)		(85,216	)		(81,813	)
Net change due to revisions in quantity estimates		(81,292	)		33,703			(70,212	)
Net change due to extensions, discoveries and improved recovery		105,257			178,579			122,144
Net change due to purchases and sales of minerals in place		5,219			(99,628	)		8,044
Changes in future development costs		3,426			(48,595	)		(44,339	)
Previously estimated development cost incurred in period		35,926			15,292			—
Net change in income taxes		26,165			(14,660	)		142,131
Accretion of discount		31,269			21,419			58,768
Change in production rates (timing) and other		(6,485	)		(11,536	)		15,573
Net increase (decrease) in standardized measures		(116,674	)		83,836			(210,339	)
Balance, end of year	$	167,443		$	284,117		$	200,281

NOTE 16—Summarized Quarterly Financial Data (Unaudited)

(In Thousands, Except Per Share Amounts)

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
2008
Revenues	$	46,353		$	65,173		$	60,376		$	44,149		$	216,051
Operating income (loss)		3,603			16,055			158,003			(32,234	)		145,427
Net income (loss)		(25,520	)		(39,139	)		186,302			131			121,774
Net income (loss) applicable to common stock		(27,032	)		(40,650	)		184,790			(1,381	)		115,727
Basic income (loss) per average common share		(0.85	)		(1.27	)		5.21			(0.04	)		3.42
Diluted income (loss) per average common share		(0.85	)		(1.27	)		4.47			(0.04	)		3.23
2007
Revenues	$	23,542		$	28,006		$	27,280		$	32,477		$	111,305
Operating loss		(7,334	)		(5,722	)		(8,466	)		(13,637	)		(35,159	)
Net income (loss)		62			(4,267	)		(12,383	)		(22,125	)		(38,713	)
Net loss applicable to common stock		(1,450	)		(5,779	)		(13,894	)		(23,637	)		(44,760	)
Basic loss per average common share		(0.06	)		(0.23	)		(0.55	)		(0.88	)		(1.75	)
Diluted loss per average common share		(0.06	)		(0.23	)		(0.55	)		(0.88	)		(1.75	)

52