Edgar Filing: GOODRICH PETROLEUM CORP

Form 10-Q for quarterly period ended September 30, 2008

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the Quarterly Period Ended September 30, 2008

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

Commission file number: 001-12719

GOODRICH PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Delaware

76-0466193

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

808 Travis, Suite 1320

Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

(Registrant’s telephone number, including area code): (713) 780-9494

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ¨ Accelerated filer x

Non-accelerated filer ¨ Smaller reporting company ¨

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

The number of shares outstanding of the Registrant’s common stock as of November 4, 2008 was 37,527,254.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS


		Page
PART I	FINANCIAL INFORMATION
ITEM 1	FINANCIAL STATEMENTS
	Consolidated Balance Sheets as of September 30, 2008 and December 31, 2007	3
	Consolidated Statements of Operations for the three and nine months ended September 30, 2008 and 2007	4
	Consolidated Statements of Cash Flows for the three and nine months ended September 30, 2008 and 2007	5
	Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2008 and 2007	6
	Notes to Consolidated Financial Statements	7
ITEM 2	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	19
ITEM 3	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	30
ITEM 4	CONTROLS AND PROCEDURES	31

PART II	OTHER INFORMATION	32
ITEM 1	LEGAL PROCEEDINGS	32
ITEM 1A	RISK FACTORS	32
ITEM 2	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	32
ITEM 3	DEFAULTS UPON SENIOR SECURITIES	32
ITEM 4	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	33
ITEM 5	OTHER INFORMATION	33
ITEM 6	EXHIBITS	33

PART 1 – FINANCIAL INFORMATION

Item 1 – Financial Statements

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(In Thousands, Except Share Amounts)

(Unaudited)


	September 30, 2008			December 31, 2007
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	223,955		$	4,448
Accounts receivable, trade and other, net of allowance		7,751			8,539
Accrued oil and gas revenue		17,082			12,200
Fair value of oil and gas derivatives		12,020			2,267
Assets held for sale		—			311
Prepaid expenses and other		1,399			904

Total current assets		262,207			28,669

PROPERTY AND EQUIPMENT:
Oil and gas properties (successful efforts method)		1,004,593			723,239
Furniture, fixtures and equipment		2,925			1,932

		1,007,518			725,171
Less: Accumulated depletion, depreciation and amortization		(249,252	)		(168,523	)

Net property and equipment		758,266			556,648

OTHER ASSETS:
Fair value of oil and gas derivatives		1,222			—
Other		4,875			4,801

Total other assets		6,097			4,801

TOTAL ASSETS	$	1,026,570		$	590,118


LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	43,410		$	36,967
Accrued liabilities		40,523			32,565
Income taxes payable		8,162			—
Fair value of interest rate derivatives		319			384
Accrued abandonment costs		564			312
Deferred revenue		—			12,500

Total current liabilities		92,978			82,728
LONG-TERM DEBT		250,000			215,500
Accrued abandonment costs		7,578			5,868
Fair value of oil and gas derivatives		—			2,407
Deferred income tax liability		29,450			—

Total Liabilities		380,006			306,503

Commitments and contingencies (See Note 12)
STOCKHOLDERS’ EQUITY:
Preferred stock: 10,000,000 shares authorized: Series B convertible preferred stock, $1.00 par value, issued and outstanding 2,250,000 shares		2,250			2,250
Common stock: $0.20 par value, 100,000,000 and 50,000,000 shares authorized, respectively, issued and outstanding 37,526,277 and 34,821,317 shares, respectively:		7,180			6,340
Treasury stock (shares outstanding 216 and 16,359 respectively)		(10	)		(422	)
Additional paid in capital		572,286			341,098
Retained earnings (deficit)		64,858			(65,651	)

Total stockholders’ equity		646,564			283,615

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,026,570		$	590,118

See accompanying notes to consolidated financial statements.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Revenues:
Oil and gas revenues	$	60,356		$	27,160		$	171,405		$	78,337
Other		20			120			497			491

		60,376			27,280			171,902			78,828

Operating expenses:
Lease operating expense		8,165			5,215			22,931			15,500
Production and other taxes		2,110			1,292			5,699			996
Transportation		2,224			1,715			6,480			4,230
Depreciation, depletion and amortization		26,414			20,434			80,532			57,603
Exploration		2,062			1,754			5,841			5,847
Impairment of oil and gas properties		1,059			282			1,059			282
General and administrative		6,207			5,054			17,567			15,892
Gain on sale of assets		(145,868	)		—			(145,868	)		—

		(97,627	)		35,746			(5,759	)		100,350

Operating income (loss)		158,003			(8,466	)		177,661			(21,522	)

Other income (expense):
Interest expense		(3,886	)		(3,086	)		(12,059	)		(7,932	)
Interest income		1,260			—			1,260			—
Gain (loss) on derivatives not designated as hedges		83,477			2,378			10,043			(3,475	)

		80,851			(708	)		(756	)		(11,407	)

Income (loss) before taxes		238,854			(9,174	)		176,905			(32,929	)
Income tax expense		(42,129	)		(11,641	)		(42,129	)		(3,379	)

Income (loss) from continuing operations		196,725			(20,815	)		134,776			(36,308	)

Discontinued operations (See Notes 10 and 11):
Gain (loss) on disposal, net of tax		(252	)		(928	)		28			9,823
Income (loss) from discontinued operations, net of tax		(44	)		(401	)		240			2,078

		(296	)		(1,329	)		268			11,901

Net income (loss)		196,429			(22,144	)		135,044			(24,407	)
Preferred stock dividends		1,512			1,511			4,535			4,535

Net income (loss) applicable to common stock	$	194,917		$	(23,655	)	$	130,509		$	(28,942	)

Income (loss) per common share from continuing operations
Basic	$	5.51		$	(0.83	)	$	3.93		$	(1.44	)

Diluted	$	4.69		$	(0.83	)	$	3.47		$	(1.44	)

Income (loss) per common share from discontinued operations
Basic	$	(0.01	)	$	(0.05	)	$	0.01		$	0.47

Diluted	$	(0.01	)	$	(0.05	)	$	0.01		$	0.47

Net income (loss) per common share applicable to common stock
Basic	$	5.50		$	(0.94	)	$	3.94		$	(1.15	)

Diluted	$	4.68		$	(0.94	)	$	3.48		$	(1.15	)

Weighted average common shares outstanding
Basic		35,440			25,204			33,098			25,177

Diluted		42,185			25,204			39,740			25,177

See accompanying notes to consolidated financial statements.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)


	Nine Months Ended September 30,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	135,044		$	(24,407	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities—
Depletion, depreciation, and amortization		80,532			57,603
Unrealized (gain) loss on derivatives not designated as hedges		(13,479	)		11,974
Deferred income taxes		29,450			9,697
Dry hole costs		—			939
Amortization of leasehold costs		4,169			5,095
Impairment of oil and gas properties		1,059			1,397
Stock based compensation (non-cash)		4,010			4,250
Gain on sale of assets		(145,911	)		(15,037	)
Other non-cash items		1,509			910
Change in assets and liabilities:
Accounts receivable, trade and other, net of allowance		735			2,604
Deferred revenue		(12,500	)		—
Accrued oil and gas revenue		(4,882	)		1,029
Prepaid expenses and other		54			(958	)
Accounts payable		6,443			4,375
Accrued liabilities		3,826			2,117
Income taxes payable		8,162			—

Net cash provided by operating activities		98,221			61,588

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(276,210	)		(208,988	)
Proceeds from sale of assets		175,053			72,538
Release of restricted cash funds		—			2,039

Net cash used in investing activities		(101,157	)		(134,411	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Principal payments of bank borrowings		(155,500	)		(65,000	)
Proceeds from bank borrowings		190,000			138,500
Exercise of stock options and warrants		2,819			203
Proceeds from common stock offering		191,340			—
Debt issuance costs		(1,498	)		(464	)
Preferred stock dividends		(4,535	)		(4,535	)
Other		(183	)		(1	)

Net cash provided by financing activities		222,443			68,703

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		219,507			(4,120	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		4,448			6,184

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	223,955		$	2,064

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
CASH PAID DURING THE PERIOD FOR INTEREST	$	8,335		$	4,661

CASH PAID DURING THE PERIOD FOR INCOME TAXES	$	4,663		$	—

See accompanying notes to consolidated financial statements.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In Thousands)

(Unaudited)


	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2008		2007			2008		2007
Net income (loss)	$	196,429	$	(22,144	)	$	135,044	$	(24,407	)

Other comprehensive income (loss):
Reclassification adjustment (1)		—		—			—		1,261

Other comprehensive income (loss)		—		—			—		1,261

Comprehensive income (loss)	$	196,429	$	(22,144	)	$	135,044	$	(23,146	)

(1) Net of income tax expense of:	$	—	$	—		$	—	$	679

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—Description of Business and Significant Accounting Policies

The consolidated financial statements of Goodrich Petroleum Corporation (“Goodrich” or “the Company” or “we”) included in this Quarterly Report on Form 10-Q have been prepared, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) and, accordingly, certain information normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States has been condensed or omitted. The consolidated financial statements reflect all normal recurring adjustments that, in the opinion of management, are necessary for a fair presentation. Significant intercompany balances and transactions have been eliminated in consolidation.

The accompanying consolidated financial statements of the Company should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007. The results of operations for the three and nine months ended September 30, 2008, are not necessarily indicative of the results to be expected for the full year.

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. Actual results could differ from those estimates.

Assets Held for Sale—Assets Held for Sale was reduced to zero as of September 30, 2008 as a result of the sale of the St. Gabriel and Bayou Bouillon Fields in the third quarter of 2008. Plumb Bob Field, which has been fully reserved, is our last remaining South Louisiana property held for sale.

Income Taxes—We follow the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 109, Accounting for Income Taxes, (“SFAS 109”) as clarified by 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 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. We have released a portion of our valuation allowance and have provided for income taxes in the three and nine months ended September 30, 2008, resulting in a net deferred tax liability of $29.5 million.

New Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, Fair Value Measurements (“SFAS 157”), which establishes a single authoritative definition of fair value based upon the assumptions market participants would use when pricing an asset or liability and creates a fair value hierarchy that prioritizes the information used to develop these assumptions. Under the standard, additional disclosures are required, including disclosures of fair value measurements by level within the fair value hierarchy. SFAS 157 is effective for fair value measures already required or permitted by other standards for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. FASB Staff Position (“FSP”) No. 157-2 (“FSP 157-2”) defers the effective date of SFAS 157 for non-financial assets and liabilities to fiscal years beginning after November 15, 2008. We have prospectively adopted SFAS 157 as of January 1, 2008, and this prospective adoption had an immaterial effect on our financial statements. See Note 9 “Fair Value of Financial Instruments” for additional information regarding the adoption of SFAS 157.

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, Accounting for Derivative Instruments and Hedging Activities (“SFAS 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 of 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 a material impact on our results of operations, cash flows or financial positions.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In May 2008, the FASB issued Staff Position APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (including Partial Cash Settlement) (“FSP APB 14-1”). FSP APB 14-1 requires that issuers of certain convertible debt instruments that may be settled in cash upon conversion to separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. The effective date of FSP APB 14-1 for the Company is January 1, 2009 and does not permit earlier application. However, the transition guidance requires retrospective application to all periods presented and does not grandfather existing instruments. In December 2006, we issued $175.0 million in 3.25% convertible senior notes due in December 2026. We are currently evaluating the impact of the provisions of FSP APB 14-1 on our financial statements as it relates to our convertible senior notes.

We do not believe that any other recently issued, but not yet effective accounting pronouncements, if adopted, would have a material effect on our accompanying financial statements.

NOTE 2—Share-Based Compensation Plans

On February 12, 2008, we granted 162,000 options under our 2006 Long-Term Incentive Plan to current employees who were employed by us on February 12, 2008. Executive vice presidents and above did not participate in this one time grant. The grant was intended to encourage employee retention. The stock options awarded have a term of seven years vesting over three years in equal increments on February 12, 2011, 2012 and 2013.

We apply SFAS No. 123 (revised 2004), Share-Based Payment (“SFAS 123R”),which requires 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 Accounting for Stock-Based Compensation and Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees.

The following table provides information about stock option activity for the nine months ended September 30, 2008:


	Number of Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (Years)
Outstanding at December 31, 2007	949,333		$	20.95
Granted	162,000			21.59
Exercised	(141,200	)		19.97
Forfeited	—			—

Outstanding at September 30, 2008	970,133		$	21.20	6.7

Exercisable at September 30, 2008	535,467		$	19.69	6.5

Fair value of stock options granted			$	10.72

The estimated fair value of the options granted during the nine months ended September 30, 2008, was calculated using a Black Scholes Merton option pricing model (“Black Scholes”). The following schedule reflects the various assumptions for options granted in February 2008 included in this model as it relates to the valuation of our options:

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Nine Months Ended September 30, 2008
Risk free interest rate	3.52	%
Volatility	53.3	%
Dividend yield	0	%
Expected years until exercise	5

During the nine months ended September 30, 2008, we granted 246,603 restricted (phantom) shares under our 2006 Long-Term Incentive Plan to employees. The following table summarizes information on restricted stock activity for the nine months ended September 30, 2008:


	Number of Shares		Weighted Average Grant Date Fair Value Per Share
Unvested at December 31, 2007	108,251		$	33.60
Vested	(21,628	)		24.29
Granted	246,603			22.39
Forfeited	(5,366	)		29.50

Unvested at September 30, 2008	327,860			25.85

For the three months ended September 30, 2008, we recorded $1.4 million in stock compensation expense comprised of $0.6 million from stock options and $0.8 million from restricted (phantom) share plans. In the nine months ended September 30, 2008, we recorded $4.0 million in stock compensation expense comprised of $1.6 million from stock options and $2.4 million from restricted (phantom) share plans. In the three months ended September 30, 2007, we recorded $1.6 million in stock compensation expense comprised of $0.8 million from stock options and $0.8 million from restricted (phantom) share plans. In the nine months ended September 30, 2007, we recorded $4.2 million in stock compensation expense comprised of $2.1 million from stock options and $2.1 million from restricted (phantom) share plans. As of September 30, 2008, we have $6.5 million of unrecognized compensation expense which is expected to be recognized over thee years.

NOTE 3—Asset Retirement Obligations

The Company follows SFAS No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”) which requires the Company to record the fair value of a liability associated with the retirement obligations of its tangible long-lived assets in the periods in which it is incurred. The Company capitalizes the discounted fair value of the liability when initially incurred. The liability is accreted through accretion expense to its full fair value during the life of the long-lived asset.

The reconciliation of the beginning and ending asset retirement obligation for the nine months ended September 30, 2008, is as follows (in thousands):


Beginning balance, January 1, 2008	$	6,180
Liabilities incurred		1,769
Liabilities settled or sold		(56	)
Accretion expense (reflected in depletion, depreciation and amortization expense)		249

Ending balance, September 30, 2008		8,142
Less current portion		564

	$	7,578

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 4—Long-Term Debt

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


	September 30, 2008		December 31, 2007
Senior Credit Facility	$	—	$	40,500
Second Lien Term Loan		75,000		—
3.25% convertible senior notes due 2026		175,000		175,000

Total long-term debt	$	250,000	$	215,500

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 September 30, 2008, we had a borrowing base of $175.0 million and no amounts outstanding under the Senior Credit Facility. On October 31, 2008, based upon the mid-year reserve report, the bank group reaffirmed the borrowing base at $175.0 million until the next semi-annual redetermination. 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 September 30, 2008, we were in compliance with all of the financial covenants of our Senior Credit Facility. The covenants in effect at September 30, 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 includes realized gains (losses) from derivatives but excludes 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 10% to 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, 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 September 30, 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.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. The notes are convertible into shares of our common stock at a rate equal to the sum of:

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

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.

NOTE 5—Net Income (Loss) Per Common Share

Net income (loss) was used as the numerator in computing basic and diluted income (loss) per common share for the three and nine months ended September 30, 2008 and 2007. The following table sets forth information related to the computations of basic and diluted income (loss) per share.


	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2008		2007			2008		2007
	(Amounts in thousands, except per share data)
Basic income (loss) per share:
Income (loss) applicable to common stock	$	194,917	$	(23,655	)	$	130,509	$	(28,942	)
Average shares of common stock outstanding (1)		35,440		25,204			33,098		25,177

Basic income (loss) per share	$	5.50	$	(0.94	)	$	3.94	$	(1.15	)

Diluted income (loss) per share:
Income (loss) applicable to common stock	$	194,917	$	(23,655	)	$	130,509	$	(28,942	)
Dividends on convertible preferred stock (2)		1,512		—			4,535		—
Interest and amortization of loan cost on senior convertible notes, net of tax (3)		1,096		—			3,289		—

Diluted income (loss)	$	197,525	$	(23,655	)	$	138,333	$	(28,942	)

Average shares of common stock outstanding (1)		35,440		25,204			33,098		25,177
Assumed conversion of convertible preferred stock (2)		3,588		—			3,588		—
Assumed conversion of convertible senior notes (3)		2,654		—			2,654		—
Stock options, warrants and restricted stock (4)		503		—			400		—

Average diluted shares outstanding		42,185		25,204			39,740		25,177

Diluted income (loss) per share	$	4.68	$	(0.94	)	$	3.48	$	(1.15	)

(1)	This amount does not include 1,624,300 and 3,122,263 shares of common stock outstanding as of September 30, 2008 and 2007, respectively, under the Share Lending Agreement. See Note 7 to our consolidated financial statements for additional information.

(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 all periods presented in 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 2007 as they would have not been dilutive.

(4)

Common shares on assumed conversion of restricted stock and employee stock option stock for the three and nine months ended September 30, 2007, in the amounts of 259,185 and 233,641, respectively, were not included in the computation of diluted loss per common share since their inclusion would have not been dilutive.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6—Income Taxes

We recorded tax expense in the amount of $42.3 million for the three and nine months ended September 30, 2008, primarily as a result of the gain from sale of oil and gas leasehold (See Note 11). As of September 30, 2008, we have recorded a net deferred income tax liability of $29.5 million and reversed a portion of the valuation allowance related to the deferred tax asset associated with our net operating loss (“NOL”) carry forwards. In determining the carrying value of a deferred tax asset, SFAS 109 provides for the weighing of evidence in estimating whether and how much of a deferred tax asset may be recoverable. We had 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. We will continue to assess the valuation allowance against deferred tax assets considering all available evidence obtained in future reporting periods.

Our effective tax rate for the nine months ended September 30, 2008 was 23.8%. The difference between the statutory rate and the effective rate is related to the release of a portion of our valuation allowance in the third quarter.

As of September 30, 2008, we had no unrecognized tax benefits. There were no significant changes to the calculation since December 31, 2007. 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 prior to September 30, 2009.

NOTE 7—Stockholders’ Equity

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 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 Poors (“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 September 30, 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 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; consequently, collaterization is no longer required.

Capped Call Option Transactions

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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 11.

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 plan to use the remaining net proceeds for general corporate purposes, including to fund a portion of our 2008 drilling program, other capital expenditures and working capital requirements.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 8—Derivative Activities

Commodity Derivative Activity

We enter into swap contracts, costless collars and 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 hedges are in effect. As of September 30, 2008, the commodity derivatives we used were in the form of:

•

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

•

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

•

fixed price physical contracts, whereby we agree in advance with the purchasers of our physical gas volumes as to specific quantities to be delivered and specific prices to be received for gas deliveries at specific transfer points in the future.

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. We have elected not to apply hedge accounting treatment to our swaps and collars and as such all changes in the fair value of these instruments are recognized in earnings. Our fixed price physical contracts qualify for the normal purchase and normal sale exception. Contracts that qualify for this treatment do not require mark-to-market accounting treatment.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of September 30, 2008, our open forward positions on our outstanding commodity derivative contracts, all of which were with either BNP Paribas, Bank of Montreal or Comerica Bank were as follows:


Fixed Price Physical Contracts	Daily Volume	Total Volume	Average Field Price (1)	Fair Value at September 30, 2008
Natural gas (MMBtu)
4Q 2008	28,500	2,317,000	$8.04
Collars			Floor/Cap (NYMEX) Average Price for 2009
Natural gas (MMBtu)				$6,327,264
4Q 2008	10,000	920,000	$8.00 – $10.20
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)				4,920,953
4Q 2008	5,000	155,000	$8.69
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 (2)
Natural gas (MMBtu)				1,993,759
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	$13,241,976

⁽¹⁾	Normal sale at a fixed field delivery point, a comparable NYMEX average price of $8.28.

⁽²⁾	The index price is based upon Natural Gas Pipeline of America, Texok zone as published in the Inside FERC. The comparable index price based on NYMEX was approximately $8.25/Mmbtu.

The fair value of the commodity derivative contracts in place at September 30, 2008 that are marked to market resulted in a net asset of $13.2 million. For the three months ended September 30, 2008, we recognized in earnings a $83.7 million gain from these instruments, which consisted of $1.6 million in realized losses and $85.3 million in unrealized gains. For the nine months ended September 30, 2008, we recognized in earnings a $10.3 million gain from these instruments. This includes $3.1 million in realized losses and $13.4 million in unrealized gains.

We did not enter into any new oil and gas derivative contracts in the third quarter of 2008.

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 entered into interest rate derivative swap agreements in the second quarter of 2008, whereby we have contracted an additional notional amount of $75.0 million at a fixed rate of 3.191% for the period April 2008 to April 2010. We have not designated this swap as a hedge. At September 30, 2008, we had the following interest rate swaps in place with BNP Paribas and Bank of Montreal:

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


Effective Date	Maturity Date	Libor Swap Rate		Notional Amount (Millions)		Fair Value (Dollars)
2/26/2007	2/26/2009	4.86	%	$	40.0	$	(329,633	)
4/22/2008	4/22/2010	3.19	%		25.0		9,418
4/22/2008	4/22/2010	3.19	%		50.0		33,808

						$	(286,407	)(1)

⁽¹⁾	Includes $32,603 in Other Assets on the face of our consolidated balance sheet as of September 30, 2008 (considered long-term).

For the three months ended September 30, 2008, we recognized a $0.2 million loss from the interest rate derivative which is not designated as a hedge. For the nine months ended September 30, 2008, we recognized a loss from interest rate derivatives of $0.3 million.

NOTE 9—Fair Value of Financial Instruments

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 financial liabilities that are being measured and reported on a fair value basis. In February 2008, the 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. 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. SFAS 157 affects the Company in the fair value measurement of the commodity and interest rate derivative positions which must be classified in one of the following categories:

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.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the valuation of our financial instruments by SFAS 157 input levels as of September 30, 2008:


	Fair Value Measurement (in thousands)
Description	Level 1		Level 2			Level 3		Total
Current assets		—		12,020			—		12,020
Other assets		—		1,255			—		1,255
Current liabilites		—		(319	)		—		(319	)

Total	$	—	$	12,956		$	—	$	12,956

NOTE 10—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 11. 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):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008		2007
Revenues		302			223			1,187		9,234
Expenses		217			856			818		6,053

Income (loss) from discontinued operations		85			(633	)		369		3,181
Income tax expense (benefit)		129			(232	)		129		1,103

Income (loss) from discontinued operations, net of tax	$	(44	)	$	(401	)	$	240	$	2,078

The Plumb Bob Field has been fully reserved and has an accrued abandonment cost liability of $0.3 million.

NOTE 11—Acquisitions and Divestitures

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 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 10.

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.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On June 16, 2008, we announced that 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 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.

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 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 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.

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 12—Commitments and Contingencies

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 consolidated financial position, results of operations or liquidity. No significant changes to these type lawsuits have occurred since December 31, 2007.

Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward-Looking Statements

Certain statements in this report, including statements of the future plans, objectives, and expected performance of the Company, are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, that are dependent upon certain events, risks and uncertainties that may be outside the Company’s 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;

•

continued availability of debt and equity financing;

•

business strategy;

•

the market prices of oil and gas;

•

economic and competitive conditions;

•

legislative and regulatory changes; and

•

financial market conditions.

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 substantially adversely affect the Company’s financial position, results of operations and cash flows.

These factors, as well as additional factors that could affect our operating results and performance are described in our Annual Report on Form 10-K for the year ended December 31, 2007, under the headings “Business,” “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” We urge you to carefully consider those factors.

All forward-looking statements attributable to us are qualified in their entirety by this cautionary statement. We undertake no responsibility to update our forward-looking statements.

Overview

General

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.

Our business strategy is to provide long term growth in net asset value per share through the growth and expansion of our oil and gas reserves and production. We focus on adding reserve value through the development of our relatively low risk development drilling program in the Cotton Valley Trend, and the pursuit of drilling opportunities in the underlying Haynesville Shale formation. The Cotton Valley Trend of East Texas and Northwest Louisiana generally provides multiple pay objectives including: the Cotton Valley, Travis Peak, Hosston, James Lime, Pettet and Haynesville Shale formations. We continue to aggressively pursue the acquisition and evaluation of prospective acreage, oil and gas drilling opportunities and potential property acquisitions.

Source of Revenues

We derive our revenues from the sale of oil and natural gas that is produced from our properties. Revenues are a function of both the volume produced and the prevailing market price at the time of sale. Production volumes, while somewhat predictable after wells have begun producing, can be impacted for various reasons. The price of oil and natural gas

is a primary factor affecting our revenues. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we use derivative instruments to manage future sales prices on a portion of our oil and natural gas production. While the derivative instruments may protect us against downward price fluctuation, the use of certain types of derivative instruments may prevent us from realizing the full benefit of upward price movements.

Third Quarter 2008 financial and operating results include:

•

We increased our oil and gas production volumes on continuing operations to approximately 69,000 Mcfe per day, representing an increase of 48% from approximately 47,000 Mcfe per day for the third quarter of 2007.

•

We conducted drilling operations on 38 gross wells in the third quarter of 2008.

•

We increased our net ownership in the Haynesville Shale play in Northwest Louisiana and East Texas to 63,000 net acres at September 30, 2008.

•

We entered into an agreement with Chesapeake Energy Corporation (“Chesapeake”) to jointly develop a portion of our Haynesville Shale acreage in Northwest Louisiana. We sold 50% of our interest in the Haynesville deep rights at the Bethany Longstreet and Longwood Fields to Chesapeake for net proceeds of $172 million resulting in a gain of $145.1 million. Chesapeake will serve as operator for these properties.

•

We reduced our total operating expenses by $0.73 per Mcfe from the third quarter of 2007 to the third quarter of 2008 and by $0.93 per Mcfe from the first nine months of 2007 to the comparable 2008 period. We excluded the impact of the $145.9 million gain on sale of assets during the third quarter 2008 in these calculations.

•

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.

Cotton Valley Trend

Our relatively low-risk development drilling program in the Cotton Valley Trend is primarily centered in and around Rusk, Panola, Angelina and Nacogdoches counties, Texas, and DeSoto, Caddo and Bienville parishes, Louisiana. We have steadily increased our acreage position in these areas over the last two years to approximately 200,000 gross acres as of September 30, 2008. Through September 30, 2008, we have participated in the drilling and logging of 389 Cotton Valley Trend wells with a success rate in excess of 99%. We conducted drilling operations on 38 gross wells during the third quarter of 2008 and 118 gross wells during the first nine months of 2008. Our net production volumes from our Cotton Valley Trend wells aggregated approximately 68,600 Mcfe per day in the third quarter of 2008, or approximately 51% higher than the Cotton Valley Trend production of the comparable prior year period.

Chesapeake Haynesville Joint Development

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 approximately $172.6 million, subject to normal closing adjustments. We received a deposit of $8.9 million from Chesapeake on June 15, 2008. The sale closed on July 15, 2008, and we received the remaining proceeds of $163.7 million on that date. We realized net proceeds from the sale of $172.0 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. Chesapeake will be the operator of the joint Haynesville Shale development. We will 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 are retaining the shallow rights to the base of the Cotton Valley sand and the existing production and reserves with respect to our 70% interest in the Bethany Longstreet Field and our 100% interest in the Longwood Field. We are also retaining our interest in both the shallow and Haynesville Shale rights on all of our East Texas assets. During the third quarter of 2008, drilling began on the first Haynesville horizontal well. Chesapeake re-entered a second well and drilled to the deeper Haynesville formation. Both of these wells are expected to complete in the fourth quarter of 2008. Fourth quarter 2008 drilling plans include an additional four Haynesville horizontal wells with Chesapeake running three drilling rigs in the area.

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 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. As of September 30, 2008, three wells have been drilled vertically to the Haynesville Shale formation, all of which are scheduled to be re-entered and completed as horizontal wells in the fourth quarter of 2008.

With the completion of these transactions, including the joint development agreement with Chesapeake, 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 GDP Operated Haynesville Shale Drilling Program

As of September 30, 2008, we have been the operator on and drilled two vertical wells on our North Louisiana acreage and four vertical wells on our East Texas acreage, for a total of six vertical wells targeting the Haynesville Shale. We expect to drill our first operated horizontal well in the Haynesville Shale formation in the fourth quarter of 2008.

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 development 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.

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 $72.5 million, net to us, after normal closing adjustments. We recognized a gain of $9.8 million. 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 $0.3 million on the balance sheet for properties in the Plumb Bob Field.

A more complete overview and discussion of our operations can be found in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2007.

Results of Operations

Our financial statements include discontinued operations presentation for our assets located in South Louisiana. See Note 10 to our consolidated financial statements.

For the third quarter of 2008, we reported net income applicable to common stock of $194.9 million, or $5.50 per share (basic) and $4.68 per share (diluted), on total revenue from continuing operations of $60.4 million as compared to a net loss applicable to common stock of $23.7 million, or $0.94 per share, on total revenue from continuing operations of $27.3 million for third quarter of 2007. Some highlights for the third quarter of 2008 include the following:

•

We recorded a $145.9 million gain on sale of assets in the third quarter of 2008. This gain includes $145.1 million from the sale of a portion of our interest in the Haynesville Shale deep rights to Chesapeake, with the remainder coming from smaller sales of leasehold interests.

•

In conjunction with the fall of natural gas prices during the third quarter of 2008, we recorded an $83.5 million gain on derivatives not designated as hedges in the third quarter of 2008. This includes a realized loss of $1.9 million and an unrealized gain of $85.4 million for our natural gas commodity contracts and interest rate swap.

•

Our income tax expense for the quarter was reduced by a $25.5 million decrease to our valuation allowance.

See discussions below under the captions “Gain on Sale of Assets”, “Gain (Loss) on Derivatives Not Designated as Hedges” and “Income Taxes.”

For the nine months ended September 30, 2008, we reported net income applicable to common stock of $130.5 million, or $3.94 per share (basic) and $3.48 per share (diluted), on total revenue from continuing operations of $171.9 million as compared to a net loss applicable to common stock of $28.9 million, or $1.15 per share, on total revenue from continuing operations of $78.8 million for the nine months ended September 30, 2007.

Oil and Natural Gas Revenues

Revenues presented in the table and the discussion below represent revenue from sales of our oil and natural gas production volumes for continuing operations.


Summary Operating Information: Continuing Operations	Three Months Ended September 30,											Nine Months Ended September 30,
	2008			2007			Variance					2008			2007			Variance
	(In thousands, except for price data)											(In thousands, except for price data)
Revenues:
Natural gas	$	55,645		$	24,955		$	30,690		123	%	$	157,541		$	72,964		$	84,577		116	%
Oil and condensate		4,711			2,205			2,506		114	%		13,864			5,373			8,491		158	%
Natural gas, oil and condensate		60,356			27,160			33,196		122	%		171,405			78,337			93,068		119	%
Operating revenues		60,376			27,280			33,096		121	%		171,902			78,828			93,074		118	%
Operating expenses		(97,627	)		35,746			(133,373	)	—			(5,759	)		100,350			(106,109	)	—
Operating income (loss)		158,003			(8,466	)		166,469		—			177,661			(21,522	)		199,183		—
Net income (loss) applicable to common stock		194,917			(23,655	)		218,572		—			130,509			(28,942	)		159,451		—

Net Production:
Natural gas (MMcf)		6,088			4,101			1,987		48	%		16,962			10,846			6,116		56	%
Oil and condensate (MBbls)		40			30			10		33	%		123			84			39		46	%
Total (Mmcfe)		6,328			4,281			2,047		48	%		17,700			11,350			6,350		56	%
Average daily production (Mcfe/d)		68,783			46,533			22,250		48	%		64,599			41,575			23,023		55	%

Average realized sales price per unit:
Natural gas (per Mcf)	$	9.14		$	6.09		$	3.05		50	%	$	9.29		$	6.73		$	2.56		38	%
Oil and condensate (per Bbl)		117.65			73.32			44.33		60	%		112.28			64.12			48.16		75	%
Total (per Mcfe)		9.54			6.34			3.20		50	%		9.68			6.90			2.78		40	%

Operating revenues from continuing operations increased 121% in the third quarter of 2008 compared to the same period in 2007 as a result of increased Cotton Valley Trend production and higher natural gas prices. Net production increased 48% period to period due to a substantial increase in the number of wells producing in the Cotton Valley Trend. The average realized sales price per Mcfe increased 50% over the prior year period. We estimate we curtailed approximately 300 Mmcf of natural gas production in September 2008 as a result of Hurricane Ike.

Operating revenues from continuing operations increased 118% for the first nine months of 2008 compared to the same period of 2007 as a result of increased production and higher prices. Net production increased 56% as a result of more producing Cotton Valley Trend wells. Average realized sales price per Mcfe increased 40% compared to the first nine months of 2007.

Operating Expenses

The following table presents our comparative per unit operating expenses related to continuing operations:


	Three Months Ended September 30,									Nine Months Ended September 30,
Operating Expenses (in thousands)	2008		2007		Variance					2008		2007		Variance
Lease operating expenses	$	8,165	$	5,215	$	2,950		57	%	$	22,931	$	15,500	$	7,431		48	%
Production and other taxes		2,110		1,292		818		63	%		5,699		996		4,703		472	%
Transportation		2,224		1,715		509		30	%		6,480		4,230		2,250		53	%
Depreciation, depletion and amortization		26,414		20,434		5,980		29	%		80,532		57,603		22,929		40	%
Exploration		2,062		1,754		308		18	%		5,841		5,847		(6	)	—
Impairment		1,059		282		777		276	%		1,059		282		777		276	%
General and administrative		6,207		5,054		1,153		23	%		17,567		15,892		1,675		11	%

	Three Months Ended September 30,									Nine Months Ended September 30,
Operating Expenses per Mcfe	2008		2007		Variance					2008		2007		Variance
Lease operating expenses	$	1.29	$	1.22	$	0.07		6	%	$	1.30	$	1.37	$	(0.07	)	(5	)%
Production and other taxes		0.33		0.30		0.03		10	%		0.32		0.09		0.23		256	%
Transportation		0.35		0.40		(0.05	)	(13	)%		0.37		0.37		—		—
Depreciation, depletion and amortization		4.17		4.77		(0.60	)	(13	)%		4.55		5.08		(0.53	)	(10	)%
Exploration		0.33		0.41		(0.08	)	(20	)%		0.33		0.52		(0.19	)	(37	)%
Impairment		0.17		0.07		0.10		143	%		0.06		0.03		0.03		100	%
General and administrative		0.98		1.18		(0.20	)	(17	)%		0.99		1.40		(0.41	)	(29	)%

Production (Mmcfe)		6,328		4,281		2,047		48	%		17,700		11,350		6,350		56	%

Lease Operating Expenses. Lease operating expense (“LOE”) for the third quarter of 2008 increased $3.0 million or 57% on an absolute basis compared to the corresponding period of 2007. LOE increased $0.07 or 6% on a per unit basis compared to the third quarter of 2007. The largest increases in LOE were from salt water disposal (“SWD”) costs, compressor charges and LOE for properties operated by others (Non-Op). All of these cost areas fluctuate with production. Production increased by 48% for 3Q08 versus 3Q07. The increase was less pronounced as we curtailed approximately 300 Mmcf in natural gas production in September resulting from Hurricane Ike. SWD costs increased $1.1 million to $2.5 million ($0.40 per Mcfe) for the third quarter of 2008 versus $1.4 million ($0.33 per Mcfe) for the third quarter of 2007. Increased well count, higher water production and service provider price increases were behind increased SWD costs. Compressor related charges increased $0.5 million. Non-Op LOE was up $0.3 million resulting from increased activity. Other operating costs were also generally higher period to period. These increases were partially offset by lower workover activity for the third quarter of 2008 ($0.1 million or $0.01 per Mcfe for the third quarter of 2008 versus $0.5 million or $0.12 per Mcfe for the third quarter of 2007).

On a per unit basis, LOE per Mcfe decreased $0.07 or 5% for the nine months ended September 30, 2008 as compared to the prior year period. Production gains for the period offset the impact of higher costs. LOE for the nine months ended September 30, 2008 increased by $7.4 million or 48% over the prior year period. SWD costs were $6.6 million ($0.37 per Mcfe) for the first nine months of 2008 compared to $4.6 million ($0.29 per Mcfe) for the comparable period in 2007. Compression charges were up $1.9 million period to period. Both of these cost areas fluctuate with increases in production.

Production and Other Taxes. Production and other taxes increased $0.8 million or 63% ($0.03 per Mcfe or 10%) for the third quarter 2008 as compared to third quarter 2007. Production and other taxes for the third quarter of 2008 includes production tax of $1.6 million and ad valorem tax of $0.5 million. Production tax during the quarter is net of $0.9 million of accrued Tight Gas Sands (“TGS”) credits for our wells in the State of Texas, which credits equate to $0.14 per Mcfe of production. Production and other taxes for the third quarter of 2007, included production tax of $0.6 million and ad valorem tax of $0.7 million. Production taxes are higher for the third quarter of 2008 as a result of a 48% increase in production over the third quarter of 2007.

Production and other taxes increased by $4.7 million ($0.23 per Mcfe) for the nine months ended September 30, 2008 as compared to the same period in 2007. Production and other taxes for the first nine months of 2008, include production tax of $4.2 million and ad valorem tax of $1.5 million. Production taxes during this period are net of $2.9 million of TGS credits ($0.16 per Mcfe). During the comparable period in 2007, production taxes of 2.0 million were almost fully offset by TGS credits of $1.8 million accrued during the period. A 56% increase in production for the 2008 period also contributed to the increase. Also included in the first nine months of 2007 was $0.8 million of ad valorem tax. Ad valorem tax is higher in 2008 due to higher property tax values assessments.

Our 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, and we anticipate that we will incur a gradually lower production tax rate in the future as we add additional Cotton Valley Trend wells to our production base and as reduced rates are approved.

Transportation. Transportation expense increased $0.5 million or 30% for the third quarter 2008 compared to the prior year quarter. Higher production volumes in 2008 caused the increase in costs. On a per unit basis, transportation expense is down $0.05 or 13% for the current quarter. The transportation rate of $0.35 per Mcfe reflects our current arrangements. The gathering rate on one of our contracts dropped in the third quarter of 2008 as we met cumulative volume commitments during the quarter.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) expense increased $6.0 million or 29% for the third quarter of 2008 as compared to the third quarter of 2007, primarily due to higher production partially offset by a lower DD&A rate. The average DD&A rate for the third quarter of 2008 was $4.17 per Mcfe compared to $4.77 per Mcfe for the same quarter of 2007.

The average DD&A rate declined to $4.55 per Mcfe for the first nine months of 2008, versus $5.08 per Mcfe for the same period in 2007. This equates to a 10% reduction of the per Mcfe DD&A rate. DD&A expense increased $22.9 million or 40% for the nine months ended September 30, 2008 as compared to the prior year period. This increase is a result of the 56% increase in production for the first nine months of 2008 compared to the same period in 2007.

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 quarter of 2008. As mentioned above, the DD&A rate per Mcfe based on this report was $4.17 per Mcfe for the third quarter of 2008. This rate is lower than the rate used for the first half of this year 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.

Exploration. Exploration expenses increased $0.3 million or 18% to $2.1 million for the third quarter of 2008 compared to the third quarter of 2007. On a per unit basis, exploration expenses decreased $0.08 per Mcfe or 20% for the same period. Undeveloped leasehold amortization was $1.7 million for the third quarter of 2008 compared to $1.5 million for the third quarter of 2007.

Exploration expenses were flat on an absolute dollar basis at $5.8 million for the nine months ended September 30, 2008 and 2007. Exploration expenses declined $0.19 to $0.33 per Mcfe, on a per unit basis. Undeveloped leasehold amortization decreased to $4.2 million for the first nine months of 2008 compared to $5.1 million for the first nine months of 2007.

Impairment. We recorded impairment expense of $1.1 million in the third quarter 2008, in connection with the independent engineer’s mid-year report on our reserves. The expense relates to the Alabama Bend and Gilmer Fields, which are located in non-core areas in North Louisiana and East Texas, respectively. We recorded impairment expense of $0.3 million in the third quarter of 2007.

General and Administrative. General and administrative (“G&A”) expense decreased 17% on a per unit basis to $0.98 per Mcfe in the third quarter 2008 compared to $1.18 per Mcfe in the third quarter of 2007 primarily due to a 48% increase in production volumes for the third quarter of 2008. Costs increased 23% to $6.2 million for the third quarter of 2008, due to an increase in the number of employees of 18% from 88 at September 30, 2007, to 107 at September 30, 2008. The impact of the increase due to a higher employee count was partially mitigated by the $1.0 million tax payment made under protest in 2007 to the State of Louisiana for franchise taxes. Stock based compensation expense, which is a non-cash item, amounted to $1.4 million for the third quarter of 2008 compared to $1.6 million for the prior year period.

General and administrative expense increased by $1.7 million or 11% to $17.6 million for the first nine months of 2008, compared to the same period for 2007. On a per unit basis, G&A declined $0.41 or 29% to $0.99 per Mcfe for the first nine months of 2008 versus the same period of 2007. Production increased 56% period to period. General and administrative expense includes stock based compensation of $4.0 million for the first nine month of 2008 versus $4.3 million for the first nine months of 2007.

Other Income (Expense)

The following table presents our comparative other income (expense) for the periods presented (in thousands):


	Three Months Ended September 30,				Nine Months Ended September 30,
Other income (expense):	2008		2007		2008		2007
Interest expense	(3,886	)	(3,086	)	(12,059	)	(7,932	)
Interest income	1,260		—		1,260		—
Gain (loss) on derivatives not designated as hedges	83,477		2,378		10,043		(3,475	)
Income tax expense	(42,129	)	(11,641	)	(42,129	)	(3,379	)
Gain (loss) on disposal, net of tax	(252	)	(928	)	28		9,823
Income (loss) from discontinued operations, net of tax	(44	)	(401	)	240		2,078

Average total borrowings	263,049		243,331		278,380		220,266
Weighted average interest rate	5.9	%	5.1	%	5.8	%	7.3	%

Interest Expense. Interest expense increased by $0.8 million to $3.8 million in the third quarter of 2008 compared to the third quarter of 2007 as a result of the higher average level of total borrowings in 2008 and an increase in the weighted average interest rate. Interest expense also increased for the first nine months of 2008 by $4.1 million to $12.1 million compared to the comparable period in 2007 as a result of higher average level of total borrowings in 2008, partially offset by a lower 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 3.25% 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.

Interest Income. We invested net proceeds from our equity offering and the sale of assets, both in July 2008, in money market funds with certain institutions. This line item represents the interest income earned on these investments during the third quarter 2008.

Gain (Loss) on Derivatives Not Designated as Hedges. Gain on derivatives not designated as hedges was $83.5 million in the third quarter of 2008, including a realized loss of $1.6 million and an unrealized gain of $85.3 million for the change in fair value of our natural gas commodity contracts. The decreases in natural gas prices experienced during the quarter led to the substantial unrealized gains on our commodity contracts. The third quarter of 2008 also includes a realized loss of $0.3 million and an unrealized gain of $0.1 million on our interest rate swap. As a comparison, the third quarter of 2007 included an unrealized loss of $0.9 million for the change in fair value of our commodity contracts, a realized gain of $3.6 million and a $0.3 million loss on our interest rate swap.

Gain on derivatives not designated as hedges was $10.0 million for the nine months ended September 30, 2008 compared to a loss of $3.5 million for the same period in 2007. The gain in 2008 includes a realized loss of $3.1 million and an unrealized gain of $13.4 million for the change in fair value of our natural gas commodity contracts. The gain in the first nine months of 2008 also includes a $0.3 million loss on our interest rate swap.

Income taxes. During third quarter 2008, we realized a significant gain on sale of assets which helped generate income before taxes of $238.9 million for the third quarter of 2008 and $176.9 million for the nine months ended September 30, 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 are releasing $25.5 million of our previously booked valuation allowance in the third quarter of 2008. The impact of this is to reduce income tax expense for the period. We have also recorded a state tax liability of $7.6 million and paid $4.7 million of this amount to the State of Louisiana in the third quarter of 2008.

Income tax expense of $11.6 million for the third quarter of 2007 reflects the increase of our valuation allowance of $14.8 million against our deferred tax assets.

Discontinued Operations. In a sale that closed March 20, 2007, we sold our assets in South Louisiana to a private company. We realized a gain of $9.8 million, net of tax, in the first nine months of 2007. On August 4, 2008, we closed the sale of our St. Gabriel Field to a private company for $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 continue to hold our interests in the Plumb Bob Field.

Liquidity and Capital Resources

Cash Flows

The following table presents our comparative cash flow summary for the periods reported (in thousands):


	Nine Months Ended September 30,
	2008			2007			Variance
Cash flow statement information:
Net cash:
Provided by operating activities	$	98,221		$	61,588		$	36,633
Used in investing activities		(101,157	)		(134,411	)		33,254
Provided by financing activities		222,443			68,703			153,740

Increase (decrease) in cash and cash equivalents	$	219,507		$	(4,120	)	$	223,627

Operating activities. Net cash provided by operating activities increased by $36.6 million to $98.2 million for the nine months ended September 30, 2008, compared to the same period in 2007. The increases in the first nine months of 2008 are primarily due to the 56% increase in natural gas production from continuing operations as a result of the wells added by our drilling program and the 40% increase in our realized average natural gas sales price compared to the same period in 2007. The increase in net cash provided by operating activities in the first nine months of 2008 was partially offset by $12.5 million representing the prepay transaction arranged with a physical gas purchaser prior to year end 2007. The physical volumes associated with this transaction were all delivered in the first quarter of 2008.

Investing activities. Net cash used in investing activities was $101.2 million for the nine months ended September 30, 2008, a decrease of $33.3 million compared to the nine months ended September 30, 2007. We received net proceeds of $175.1 million from sale of assets (primarily the Chesapeake transaction) compared to net proceeds of $72.5 million received from the sale of substantially all of our South Louisiana assets in 2007. Total capital expenditures of $276.2 million for the nine months ended September 30, 2008, were up $67.2 million compared to $209.0 million for the same period in 2007. In addition to having conducted drilling operations on 118 gross wells in the first nine months of 2008 compared to 87 gross wells in the first nine months of 2007, we increased our spending on leasehold acquisition from $9.7 million to $24.6 million for the first nine months of 2008.

Financing activities. Net cash provided by financing activities was $222.4 million for the nine months ended September 30, 2008, an increase of $153.7 million over same period in 2007. In January 2008, we borrowed $75.0 million on our Second Lien Term Loan using $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 in July 2008. We have zero borrowings outstanding under our senior credit facility at September 30, 2008.

Disruptions in the Credit and Capital Markets.

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 weeks, 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. Through September 30, 2008, we have expended approximately $282.2 million of our 2008 total capital expenditure budget of $350.0 million, exclusive of property acquisitions. We expect to fund the remainder of our 2008 capital expenditures with a combination of cash flow from operations and available cash at September 30, 2008. We believe that we can fund up to $300 million of capital expenditures in 2009 from available cash and cash flow from operations and without borrowing under our senior credit facility. We have a significant amount of cash on hand and $175.0 million of undrawn capacity available under our senior credit facility that matures in 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. Because we control the timing 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.

Capital Expenditures

Capital expenditures for the quarter totaled $103.0 million compared to $81.3 million in the third quarter of 2007. Of the $103.0 million, $87.4 million was incurred on the drilling and completion of Cotton Valley Trend wells during the quarter, $13.3 million was incurred on leasehold acquisitions and $2.3 million was incurred on infrastructure and other costs. We funded our capital expenditures in the quarter through a combination of cash flow from operations and available cash.

We have established a preliminary capital expenditure budget for 2009 of $300 million, down approximately 15% from the $350 million capital expenditure budget for 2008. Approximately 60% of the budget is currently estimated to be spent drilling Haynesville Shale horizontal wells, with the majority of the remaining 40% allocated to drilling James Lime horizontal wells, Cotton Valley Taylor sand horizontal wells and vertical Travis Peak wells.

We expect to fund the 2009 capital expenditure budget from cash flow from operations and available cash, which is currently $224 million.

3.25% Convertible Senior Notes

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

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 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 Poors (“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 The Bear Stearns Companies Inc. JP Morgan Chase & Co.’s credit rating exceeds that required by the Share Lending Agreement; consequently, collaterization is no longer required.

Senior Credit Facility

•

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 includes realized gains (losses) from derivatives, but excludes 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 10% total debt, excludes 3.25% convertible senior notes) of not less than 1.5 to 1.0.

Second Lien Term Loan

•

Asset coverage ratio (defined as the present value of proved reserves discounted at 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.

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 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 plan to use the remaining net proceeds for general corporate purposes, including to fund a portion of our remaining 2008 drilling program, other capital expenditures and working capital requirements.

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 September 30, 2008, our short term investments amounted to $214.1 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 September 30, 2008, we held short term investments in money market funds with four institutions meeting all of these criteria. Short term investments as of September 30, 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.

Accounting Pronouncements

See Note 1 “Description of Business and Significant Accounting Policies” “New Accounting Pronouncements” to our consolidated financial statements for a discussion of recently issued pronouncements, including Statement of Financial Accounting Standards No.157, Fair Value Measurements which we adopted effective January 1, 2008.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based on consolidated financial statements which have been prepared in accordance with generally accepted accounting principles in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts or assets, liabilities, revenues and expenses. We believe that certain accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements. Our Annual Report on Form 10-K for the year ended December 31, 2007, includes a discussion of our critical accounting policies.

Item 3 – 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 derivative arrangements 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 production. As of September 30, 2008, the commodity contracts we used were in the form of:

•

swaps, where we receive a fixed price and pay a floating price, based on NYMEX or specific transfer point quoted prices;

•

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

•

fixed price physical contracts which qualify for normal purchase and normal sale treatment, whereby we agree in advance with the purchasers of our physical gas volumes as to specific quantities to be delivered and specific prices to be received for gas deliveries at specific transfer points in the future.

Our commodity contracts fall within our targeted range of 30% to 70% of our estimated net natural gas production volumes for the applicable periods of 2008. The fair value of the natural gas commodity contracts in place at September 30, 2008, resulted in a net asset of $13.2 million. Based on natural gas pricing in effect at September 30, 2008, a hypothetical 10% increase in oil and gas prices would have resulted in a derivative liability of $2.1 million while a hypothetical 10% decrease in oil and gas prices would have resulted in a derivative asset of $29.3 million. See Note 8 “Derivative Activities” to our consolidated financial statements for additional information.

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 September 30, 2008, we had the following interest rate swaps in place with BMO and BNP:


Effective Date	Maturity Date	Libor Swap Rate		Notional Amount (Millions)		Fair Value (Dollars)
2/26/2007	2/26/2009	4.86	%	$	40.0	$	(329,633	)
4/22/2008	4/22/2010	3.19	%		25.0		9,418
4/22/2008	4/22/2010	3.19	%		50.0		33,808

						$	(286,407	)(1)

⁽¹⁾	Includes $32,603 in Other Assets on the face of our consolidated balance sheet as of September 30, 2008(considered long-term).

Based on interest rates at September 30, 2008, a hypothetical 10% increase or decrease in interest rates would not have a material effect on the liability.

Item 4 – Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We have established disclosure controls and procedures designed to ensure that material information required to be disclosed in our reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified by the Securities and Exchange Commission and that any material information relating to us is recorded, processed, summarized and reported to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. In reaching a reasonable level of assurance, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in rules 13a-15(c) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our Chief Executive Officer and Chief Financial Officer, based upon their evaluation as of September 30, 2008, the end of the period covered in this report, concluded that our disclosure controls and procedures were effective at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There were no changes in our system of internal control over financial reporting that occurred during our third quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1 – Legal Proceedings.

We are named as a defendant, from time to time, in litigation relating to our normal business operations. Our management is not aware of any significant litigation, pending or threatened, that would have a material adverse effect on our financial position, results of operations, or cash flows.

Item 1A – Risk Factors.

The results of our planned exploratory drilling in the Haynesville Shale, a newly emerging play with limited drilling and production history, are subject to more uncertainties than our drilling program in the more established shallower Cotton Valley formations and may not meet our expectations for reserves or production.

We have only recently drilled our first three vertical wells to the Haynesville Shale, one of which is still drilling, from which we do not yet have sufficient data to recognize proved reserves in the formation. Part of the drilling strategy to maximize recoveries from the Haynesville Shale involves the drilling of horizontal wells using completion techniques that have proven successful in other shale formations. We have not participated in any horizontal drilling of the Haynesville Shale and to date the industry’s drilling and production history in the formation is limited. The ultimate success of these drilling strategies and techniques in the formation will be better evaluated over time as more wells are drilled and production profiles are better established. Accordingly, the results of our future drilling in the emerging Haynesville Shale play are more uncertain than drilling results in the shallower Cotton Valley horizons with established reserves and production.

Recent changes in the financial and credit markets may impact economic growth, and a sustained depression of oil and natural gas prices can also affect our ability to obtain funding, obtain funding on acceptable terms or obtain funding under our current credit facility. This may hinder or prevent us from meeting our future capital needs.

Global financial markets and economic conditions have been, and continue to be, disrupted and volatile. The debt and equity capital markets have become exceedingly distressed. These issues, along with significant write-offs in the financial services sector, the re-pricing of credit risk and the current weak economic conditions have made, and will likely continue to make, it difficult to obtain funding.

In addition, we may be unable to obtain adequate funding under our current credit facility because (i) our lending counterparties may be unwilling or unable to meet their funding obligations or (ii) our borrowing base under our current revolving credit facility is redetermined at least twice per year and may decrease as a result of lower oil or natural gas prices, operating difficulties, declines in reserves, lending requirements or regulations, or for any other reason.

Due to these factors, we cannot be certain that funding will be available if needed, and to the extent required, on acceptable terms. If funding is not available as needed, or is available only on unfavorable terms, we may be unable to meet our obligations as they come due or we may be unable to implement our development plan, enhance our existing business, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations.

In addition to other information set forth in this report, you should carefully consider the factors discussed in “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007 which materially affect our business, financial condition or future results.

Item 2 – Unregistered Sales of Equity Securities and Use of Proceeds.

None.

Item 3 – Defaults Upon Senior Securities.

None.

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

None.

Item 5 – Other Information.

None.

Item 6 – Exhibits.

Please see the Exhibit Index accompanying this report.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned and thereunto duly authorized.


	GOODRICH PETROLEUM CORPORATION (Registrant)

Date: November 6, 2008	By:	/s/ Walter G. Goodrich
		Walter G. Goodrich
		Vice Chairman & Chief Executive Officer

Date: November 6, 2008	By:	/s/ David R. Looney
		David R. Looney
		Executive Vice President & Chief Financial Officer

GOODRICH PETROLEUM CORPORATION LIST OF EXHIBITS TO FORM 10-Q

FOR QUARTER ENDED SEPTEMBER 30, 2008


EXHIBIT NO.		DESCRIPTION OF EXHIBIT
3.1		Restated Certificate of Incorporation of Goodrich Acquisition II, Inc., dated January 31, 1997 (Incorporated by reference to Exhibit 3.1A to the Company’s Third Amended Registration Statement on Form S-1 (Registration No. 333-47078) filed on December 8, 2000).

3.2		Certificate of Amendment of Restated Certificate of Incorporation of Goodrich Acquisition II, Inc., dated January 31, 1997 (Incorporated by reference to Exhibit 3.1B to the Company’s Third Amended Registration Statement on Form S-1 (Registration No. 333-47078) filed on December 8, 2000).

3.3		Certificate of Amendment of Restated Certificate of Incorporation of Goodrich Petroleum Corporation, dated March 12, 1998 (Incorporated by reference to Exhibit 3.2 to the Company’s Annual Report on Form 10-K filed on March 20, 1998).

3.4		Certificate of Amendment of Restated Certificate of Incorporation of Goodrich Petroleum Corporation, dated May 9, 2002 (Incorporated by reference to Exhibit 3.4 to the Company’s Current Report on Form 8-K filed on December 3, 2007).

3.5		Certificate of Amendment of Restated Certificate of Incorporation of Goodrich Petroleum Corporation, dated May 30, 2007 (Incorporated by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q filed on August 9, 2007).

4.1		Specimen Common Stock Certificate (Incorporated by reference to Exhibit 4.6 of the Company’s Registration Statement filed February 20, 1996 of Form S-8 (File No. 33-01077)).

4.2		Registration Rights Agreement dated December 21, 2005 among the Company, Bear, Sterns & Co. Inc. and BNP Paribas Securities Corp. (Incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed on December 22, 2005).

4.3†		Goodrich Petroleum Corporation 2006 Long-Term Incentive Plan (Incorporated by reference to the Company’s Proxy Statement filed April 17, 2006).

4.4†		Form of Grant of Restricted Phantom Stock (1995 Stock Option Plan) (Incorporated by reference to Exhibit 4.2 to the Company’s Registration Statement of Form S-8 filed on October 23, 2006).

4.5†		Form of Grant of Restricted Phantom Stock (2006 Long-Term Incentive Plan) (Incorporated by reference to Exhibit 4.3 to the Company’s Registration Statement on Form S-8 filed on October 23, 2006).

4.6†		Form of Director Stock Option Agreement (with vesting schedule) (Incorporated by reference to Exhibit 4.4 to the Company’s Registration Statement of Form S-8 on October 23, 2006).

4.7†		Form of Director Stock Option Agreement (immediate vesting) (Incorporated by reference to Exhibit 4.5 to the company’s Registration Statement of Form S-8 filed on October 23, 2006).

4.8†		Form of Incentive Stock Option Agreement (Incorporated by reference to Exhibit 4.6 to the Company’s Registration Statement on Form S-8 filed on October 23, 2006).

4.10†		Form of Nonqualified Option Agreement (Incorporated by reference to Exhibit 4.7 to the Company’s Registration Statement of Form S-8 filed on October 23, 2006).

4.11		Registration Rights Agreement dated December 6, 2006 among Goodrich Petroleum Corporation, Bear, Sterns & Co. Inc., Deutsche Bank Securities Corp. and BNP Paribus Securities Corp (Incorporated by reference to Exhibit 4.11 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2006).

4.12		Indenture, dated December 6, 2006, between Goodrich Petroleum Corporation an Wells Fargo Bank, National Association, as Trustee (Incorporated by reference to Exhibit 4.12 of the Company’s Annual Report of Form 10-K for the year ended December 31, 2006).

4.13		Registration Rights Agreement, between Caddo Resources LP and Goodrich Petroleum Corporation, dated as of May 23, 2008 (Incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on May 29, 2008).

*31.1		Certification of Chief Executive Officer Pursuant to 15 U.S.C. Section 7241, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31.2		Certification of Chief Financial Officer pursuant to 15 U.S.C. Section 7241, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

**32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

**32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*	Filed herewith.

**	Furnished herewith.

†	Denotes management contract or compensatory plan or arrangement.

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents