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 þx No ¨

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

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

The number of shares outstanding of the Registrant’s common stock as of ~~May 4,~~November 2, 2007 was ~~28,303,019.~~28,345,371.


							September 30, 2007			December 31, 2006
	March 31, 2007			December 31, 2006			(unaudited)
ASSETS	(unaudited)
CURRENT ASSETS:
Cash and cash equivalents	$	7,572		$	6,184		$	2,064		$	6,184
Assets held for sale		1,867			—			716			—
Accounts receivable, trade and other, net of allowance		9,996			9,665			7,061			9,665
Accrued oil and gas revenue		10,949			10,689			9,660			10,689
Fair value of oil and gas derivatives		2,228			13,419			3,684			13,419
Fair value of interest rate derivatives		54			219			—			219
Prepaid expenses and other		1,257			994			2,192			994

Total current assets		33,923			41,170			25,377			41,170

PROPERTY AND EQUIPMENT:
Oil and gas properties (successful efforts method)		497,466			575,666			639,452			575,666
Furniture, fixtures and equipment		1,686			1,463			1,665			1,463

		499,152			577,129			641,117			577,129
Less: Accumulated depletion, depreciation and amortization		(94,761	)		(156,509	)		(137,878	)		(156,509	)

Net property and equipment		404,391			420,620			503,239			420,620

OTHER ASSETS:
Restricted cash		—			2,039
Restricted cash and investments								—			2,039
Deferred tax asset		9,041			9,705			—			9,705
Other		5,384			5,730			5,201			5,730

Total other assets		14,425			17,474			5,201			17,474

TOTAL ASSETS	$	452,739		$	479,264		$	533,817		$	479,264


LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	29,860		$	36,263		$	36,992		$	36,263
Accrued liabilities		37,579			26,811			35,205			26,811
Fair value of interest derivatives								102			—
Accrued abandonment costs		158			263			281			263

Total current liabilities		67,597			63,337			72,580			63,337
Long-term debt		175,000			201,500
LONG-TERM DEBT								275,000			201,500
Accrued abandonment costs		3,237			9,294			4,973			9,294

Total liabilities		245,834			274,131
Total Liabilities								352,553			274,131

Commitments and contingencies (See Note 8)
Commitments and contingencies (See Note 9)
STOCKHOLDERS’ EQUITY:
Preferred stock: 10,000,000 shares authorized:
Series B convertible preferred stock, $1.00 par value, 2,250,000 shares issued and outstanding		2,250			2,250
Common stock: $0.20 par value, 50,000,000 shares authorized; issued and outstanding 28,321,464 and 28,218,422 shares, respectively		5,066			5,049
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 28,344,872 and 28,218,422 shares, respectively								5,044			5,049
Additional paid in capital		215,153			213,666			217,549			213,666
Treasury stock		(517	)		—			(66	)		—
Accumulated deficit		(15,047	)		(14,571	)		(43,513	)		(14,571	)
Accumulated other comprehensive loss		—			(1,261	)		—			(1,261	)

Total stockholders’ equity		206,905			205,133			181,264			205,133

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	452,739		$	479,264		$	533,817		$	479,264


	Three Months Ended March 31,						Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006			2007			2006
Revenues:
Oil and gas revenues	$	23,317		$	14,423		$	27,160		$	19,465			78,337		$	53,864
Other		225			346			120			159			491			683

		23,542			14,769			27,280			19,624			78,828			54,547

Operating expenses:
Lease operating expense		4,111			2,238			5,215			3,891			15,500			8,274
Production taxes		318			902
Production and other taxes								1,292			1,039			996			3,023
Transportation		1,075			—			1,715			1,229			4,230			2,717
Depreciation, depletion and amortization		17,708			5,882			20,434			9,821			57,603			25,687
Exploration		2,326			1,399			1,754			1,528			5,847			4,435
Impairment of oil and gas properties								282			—			282			—
General and administrative		5,338			3,771			5,054			4,282			15,892			12,248

		30,876			14,192			35,746			21,790			100,350			56,384

Operating income (loss)		(7,334	)		577
Operating loss								(8,466	)		(2,166	)		(21,522	)		(1,837	)

Other income (expense):
Other income expense:
Interest expense		(2,624	)		(695	)		(3,086	)		(2,509	)		(7,932	)		(4,706	)
Gain (loss) on derivatives not qualifying for hedge accounting		(9,487	)		13,542			2,378			15,188			(3,475	)		34,611

		(12,111	)		12,847			(708	)		12,679			(11,407	)		29,905

Income (loss) before income taxes		(19,445	)		13,424			(9,174	)		10,513			(32,929	)		28,068
Income tax (expense) benefit		6,743			(4,698	)		(11,641	)		(3,669	)		(3,379	)		(9,779	)

Income (loss) from continuing operations		(12,702	)		8,726			(20,815	)		6,844			(36,308	)		18,289

Discontinued operations (See Note 6):
Gain on disposal, net of tax		10,913			—
Income from discontinued operations, net of tax		2,825			2,866
Gain (loss) on disposal, net of tax								(928	)		—			9,823			—
Income (loss) from discontinued operations, net of tax								(401	)		1,337			2,078			5,782

		13,738			2,866			(1,329	)		1,337			11,901			5,782

Net income		1,036			11,592
Net income (loss)								(22,144	)		8,181			(24,407	)		24,071
Preferred stock dividends		1,512			1,481			1,511			1,511			4,535			4,504
Preferred stock redemption premium		—			1,536			—			—			—			1,545

Net income (loss) applicable to common stock	$	(476	)	$	8,575		$	(23,655	)	$	6,670		$	(28,942	)	$	18,022

Income (loss) from continuing operations per common share:
Income (loss) per common share from continuing operations
Basic	$	(0.51	)	$	0.35		$	(0.83	)	$	0.27		$	(1.44	)	$	0.73

Diluted	$	(0.51	)	$	0.34		$	(0.83	)	$	0.27		$	(1.44	)	$	0.72

Income from discontinued operations per common share:
Income (loss) per common share from discontinued operations
Basic	$	0.55		$	0.12		$	(0.05	)	$	0.05		$	0.47		$	0.23

Diluted	$	0.54		$	0.11		$	(0.05	)	$	0.05		$	0.47		$	0.23

Net income (loss) applicable to common stock per common share:
Net income (loss) per common share applicable to common stock
Basic	$	(0.02	)	$	0.34		$	(0.94	)	$	0.27		$	(1.15	)	$	0.72

Diluted	$	(0.02	)	$	0.34		$	(0.94	)	$	0.26		$	(1.15	)	$	0.71

Average common shares outstanding:
Weighted average common shares outstanding
Basic		25,141			24,860			25,204			24,972			25,177			24,923

Diluted		25,386			25,366			25,204			25,346			25,177			25,386


	Three Months Ended March 31,						Nine Months Ended September 30,
	2007			2006			2007			2006
Cash flows from operating activities:
Net income	$	1,036		$	11,592
Adjustments to reconcile net income to net cash provided by operating activities -
Depletion, depreciation and amortization		17,708			9,832
Cash flows from operating activities:
Net income (loss)							$	(24,407	)	$	24,071
Adjustments to reconcile net income (loss) to net cash provided by operating activities—
Depletion, depreciation, and amortization								57,603			37,120
Unrealized (gain) loss on derivatives not qualifying for hedge accounting		13,124			(16,121	)		11,974			(36,370	)
Deferred income taxes		654			6,241			9,697			12,961
Dry hole costs		905			—			939			20
Amortization of leasehold costs		1,766			1,158			5,095			3,909
Impairment of oil and gas properties								1,397			—
Stock based compensation (non-cash)		1,350			932			4,250			3,694
Gain on sale of assets		(16,789	)		—			(15,037	)		—
Other non cash items		98			(193	)
Changes in assets and liabilities -
Amortization of deferred financing cost								910			186
Change in assets and liabilities:
Accounts receivable, trade and other, net of allowance		(331	)		(3,601	)		2,604			(3,825	)
Accrued oil and gas revenue		(260	)		1,926			1,029			4,319
Prepaid expenses and other		(263	)		7			(958	)		(757	)
Accounts payable		(3,049	)		8,524			4,375			2,620
Accrued liabilities		960			5,476
Accrued liabilities and other								2,117			4,505

Net cash provided by operating activities		16,909			25,773			61,588			52,453

Cash flows from investing activities:

Cash flows from investing activities:
Capital expenditures		(63,543	)		(63,504	)		(208,988	)		(196,541	)
Proceeds from sale of assets		74,029			909			72,538			1,731
Release of restricted cash funds		2,039			—
Release of restricted cash								2,039			—

Net cash provided by (used in) investing activities		12,525			(62,595	)
Net cash used in investing activities								(134,411	)		(194,810	)

Cash Flows from Financing Activities

Cash flows from financing activities:
Principal payments of bank borrowings		(65,000	)		—			(65,000	)		(21,000	)
Proceeds from bank borrowings		38,500			—			138,500			129,500
Net proceeds from preferred stock offering		—			29,037			—			28,973
Redemption of preferred stock		—			(9,310	)		—			(9,319	)
Exercise of stock options and warrants								203			400
Deferred financing costs								(464	)		(458	)
Preferred stock dividends		(1,511	)		(1,229	)		(4,535	)		(4,252	)
Deferred financing costs		(35	)		—
Other		—			(15	)		(1	)		(15	)

Net cash provided by (used in) financing activities		(28,046	)		18,483
Net cash provided by financing activities								68,703			123,829

Net increase (decrease) in cash and cash equivalents		1,388			(18,339	)
Decrease in cash and cash equivalents								(4,120	)		(18,528	)
Cash and cash equivalents, beginning of period		6,184			19,842			6,184			19,842

Cash and cash equivalents, end of period		7,572			1,503		$	2,064		$	1,314

Supplemental disclosures of cash flow information:
Cash paid during the period for interest	$	1,000			674
Supplemental disclosure of cash flow information:
Cash paid during period for interest							$	4,661		$	3,427

Cash paid during the period for income taxes	$	—			—
Cash paid during period for income taxes							$	—		$	—

The consolidated financial statements of Goodrich Petroleum Corporation (“Goodrich” or “the Company” or “we”) included in this 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. Certain reclassifications have been made to the prior year statements to conform to the current year presentation.

The accompanying consolidated financial statements of the Company should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2006.~~2006 and Current Report on Form 8-K dated August 7, 2007 which presents revised financial information to reflect discontinued operations. The results of operations for the three and nine months ended ~~March 31,~~September 30, 2007, are not necessarily indicative of the results to be expected for the full year.

Assets Held for Sale—Assets Held for Sale as of ~~March 31,~~September 30, 2007, represent our remaining assets in South Louisiana. These assets include the St. Gabriel, Bayou Bouillon and Plumb Bob fields. ~~These assets are expected to be sold within one year.~~

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

Income ~~Taxes~~—Taxes—Uncertain Tax ~~Positions—~~Positions—In June 2006, the Financial Accounting Standards Board (“FASB”) issued ~~FIN~~FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109, Accounting for Income ~~Taxes.~~Taxes(“FIN 48”). This interpretation addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN 48, the Company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. FIN 48 also provides guidance on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and requires increased disclosures. The Company adopted the provisions of FIN 48 on January 1, 2007. There was no cumulative effect adjustment to retained earnings, our financial condition or results of operations as a result of implementing FIN 48. See Note ~~7 to the Consolidated Financial Statements.~~8.

Recently Released Accounting Pronouncements—In February 2007, the FASB issued Statement of Financial Accounting Standards (“SFAS”) 159,The Fair Value Option for Financial Assets and Financial Liabilities—~~including~~Including an ~~amendment~~Amendment of FASB Statement No. 115(“SFAS 159”), which allows measurement at fair value of eligible financial assets and liabilities that are not otherwise measured at fair value. If the fair value option for an eligible item is elected, unrealized gains and losses for that item must be reported in current earnings at each subsequent reporting date. SFAS 159 also establishes presentation and disclosure requirements designed to draw comparison between the different measurement attributes the Company elects for similar types of assets and liabilities. SFAS 159 is effective for fiscal years beginning after November 15, 2007. Early adoption is permitted. We are currently assessing the impact of SFAS 159 on our consolidated financial statements.

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements (“SFAS 157”), which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. SFAS 157 applies under other accounting pronouncements that require or permit fair value measurements, the FASB having previously concluded in those accounting pronouncements that fair value is the relevant measurement attribute. Accordingly, SFAS 157 does not require any new fair value measurements. SFAS 157 is effective for fiscal years beginning after December 15, 2007. We plan to adopt SFAS 157 beginning in the first quarter of fiscal 2008. We are currently evaluating the impact, if any, the adoption of SFAS 157 will have on our consolidated financial statements.

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

Effective January 1, 2003, the Company adopted SFAS No. 143,Accounting for Asset Retirement Obligations (“SFAS 143”). SFAS 143 ~~provides accounting requirements~~requires entities to record the fair value of a liability for ~~retirement~~legal obligations associated with the retirement obligations of tangible long-lived assets ~~and requires that an asset retirement cost should be capitalized as part of~~in the ~~cost~~periods in which it is incurred. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset. The liability is accreted to the fair value at the time of settlement over the useful life of the asset, and ~~subsequently allocated to expense using a systematic and rational method. We adopted SFAS 143 on January 1, 2003 and recorded an incremental liability for asset retirement obligations~~the capitalized cost is depreciated over the useful life of ~~$1.4 million, additional oil and gas properties, net of accumulated depletion, depreciation and amortization, in~~ the ~~amount of $1.1 million and a net of tax cumulative effect of change in accounting principle of $0.2 million.~~related asset. The reconciliation of the beginning and ending asset retirement obligation for the period ending ~~March 31,~~September 30, 2007 is as follows (in thousands):


Beginning balance	$	9,557
Beginning balance, January 1, 2007				$	9,557
Liabilities incurred		—			1,832
Liabilities settled or sold		(6,207	)		(6,307	)
Accretion expense (reflected in depletion, depreciation and amortization expense)		45			172

Ending balance		3,395
Ending balance, September 30, 2007					5,254
Less current portion		(158	)		281

	$	3,237		$	4,973

The liabilities settled or sold in the ~~first quarter~~amount of ~~2007~~$6.3 million represent the ~~Asset Retirement Obligation~~asset retirement obligation for ~~substantially~~ all of our properties in South Louisiana sold to a private company. The ending balance at ~~March 31,~~September 30, 2007, includes $0.3 million for ~~Assets Held~~assets held for ~~Sale.~~sale. See Note 6.


	March 31, 2007		December 31, 2006		September 30, 2007		December 31, 2006
Senior Credit Facility	$	—	$	26,500	$	100,000	$	26,500
3.25% convertible senior notes due 2026		175,000		175,000		175,000		175,000

Total debt		175,000		201,500
Less current maturities		—		—

Total long-term debt	$	175,000	$	201,500	$	275,000	$	201,500

In December 2006, we sold $175 million of 3.25% convertible senior notes due in December 2026. With a portion of the proceeds of the note offering we fully repaid the outstanding balance of the second lien term loan. The notes mature on December 1, 2026, unless earlier converted, redeemed or repurchased. The notes will be our senior unsecured obligations and will 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 will be paid semi-annually on June 1 and December 1, ~~beginning~~which began on June 1, 2007.

Prior to December 1, 2011, the notes will not be redeemable. On or after December 11, 2011, we may redeem for cash all or a portion of the notes, and the investors may require us to repay 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:

On November 17, 2005, we amended our existing credit agreement and entered into an amended and restated senior credit agreement (the “Senior Credit Facility”) and a second lien term loan (the “Term ~~Loan “)~~Loan”) that expanded our borrowing capabilities and extended our credit facility for an additional two years. Total lender commitments under the Senior Credit Facility were ~~$200.0~~$200 million which matures on February 25, 2010. Revolving borrowings under the Senior Credit Facility are limited to, and subject to periodic redeterminations of, the borrowing base which is currently established at$~~110.0~~ $170 million. As of ~~March 31,~~September 30, 2007, we ~~repaid all~~have $100 million in outstanding ~~amounts of the~~ revolving borrowings under the Senior Credit Facility. 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 0.50%, or LIBOR plus 1.25% to ~~2.00%~~2.25%, depending on borrowing base utilization.

The terms of the Senior Credit Facility require us to maintain certain covenants. Capitalized terms are defined in the credit agreement. The covenants ~~include~~:include:

~~EBITDAX~~ (EBITDAX is earnings before interest expense, income tax, DD&A, exploration expense and ~~exploration expense.~~impairment of oil and gas properties. In calculating EBITDAX for this purpose, earnings includes realized gains (losses) from derivatives not qualifying for hedge accounting, but excludes unrealized gains (losses) from derivatives not qualifying for hedge accounting.)

On August 7, 2007, we amended the Senior Credit Facility (“Amended Senior Credit Facility”) to change the last of these financial covenants beginning with the quarter ending June 30, 2007 and ending with the quarter ending December 31, 2007. The financial covenant will return to a 3.5 times Debt to EBITDAX limitation for the trailing four quarters beginning with the quarter ending March 31, 2008. As a result of the sale of the Company’s South Louisiana assets in the first quarter of 2007 (see Note 6), a preliminary EBITDAX calculation for the trailing four quarters ending June 30, 2007 (which excluded all EBITDAX generated by the sold South Louisiana assets) indicated that the Company might not be in compliance with the ratio at the 3.5 times limitation. As a result, the Company requested and the bank group approved amending the ratio as discussed above for the purpose of clarifying the calculation of the covenant.

On September 24, 2007, we entered into the Seventh Amendment of the Amended and Restated Senior Credit Agreement. This Amendment increased the borrowing base from $110 million to $170 million and increased the upper limit of the LIBOR plus rate from 2.0% to 2.25%. All the other material terms remained the same.

As of ~~March 31,~~September 30, 2007, we were in compliance with all of the financial covenants of the Amended Senior Credit Facility.

Net income (loss) applicable to common stock was used as the numerator in computing basic and diluted income (loss) per common share for the three months and nine months ended ~~March 31,~~September 30, 2007 and 2006. The following table reconciles the weighted average shares outstanding used for these computations (in thousands):


	For the Three Months Ended March 31,		For the Three Months Ended September 30,		For the Nine Months Ended September 30,
	2007	2006	2007	2006	2007	2006
Basic Method	25,141	24,860	25,204	24,972	25,177	24,923
Dilutive Stock Warrants	—	194	—	374	—	334
Dilutive Stock Options and Restricted Stock	245	312	—	—	—	129

Dilutive Method	25,386	25,366	25,204	25,346	25,177	25,386

Common shares on assumed conversion of restricted and employee option stock for the three and nine-month periods ended September 30, 2007 in the amounts of 233,641 and 259,184 shares, respectively, were not included in the computation of diluted loss per common share since they would be anti-dilutive.

We enter into swap contracts, costless collars or other hedging 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 total production. As of ~~March 31,~~September 30, 2007, the commodity hedges we utilized were in the form of: (a) swaps, where we receive a fixed price and pay a floating price, based on NYMEX quoted prices, (b) collars, where we receive the excess, if any, of the floor price over the reference price, based on NYMEX quoted prices, and pay the excess, if any, of the reference price over the ceiling price, and (c) 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.

Our natural gas swaps and collars (all financial contracts) were deemed ineffective beginning in the fourth quarter of 2004, and since that time we have been required to reflect the change in the fair value of our natural gas swaps and collars in earnings rather than in accumulated other comprehensive loss, a

component of stockholders’ equity. Additionally, our oil swaps and collars (all financial contracts) were deemed ineffective during the fourth quarter of 2006, thus the change in the fair value of our oil hedges is reflected in earnings as well. To the extent that our financial hedge contracts do not qualify for hedge accounting in the future, we will ~~likewise~~ be exposed to volatility in earnings resulting from changes in the fair value of those hedge contracts. The 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, which recognizes changes in the derivative value each period through earnings.

As of ~~March 31,~~September 30, 2007, our open forward positions on our outstanding commodity hedging contracts and fixed price physical contracts were as follows:

The fair value of the oil and gas hedging contracts in place at ~~March 31,~~September 30, 2007, resulted in a net asset of ~~$2.2~~$3.7 million. For the three months ended ~~March 31,~~September 30, 2007, we recognized a gain in earnings ~~a loss~~ from oil and natural gas derivatives not qualifying for hedge accounting of $2.7 million, which was composed of a realized gain of $3.6 million offset by an unrealized loss of $0.9 million. For the nine months ended September 30, 2007, we recognized a loss in ~~the amount~~earnings from oil and natural gas derivatives not qualifying for hedge accounting of ~~$9.5~~$3.4 million, ~~(this amount included~~made up of an unrealized loss of $11.7 million offset by a realized ~~gains~~gain of ~~$3.7 million, as well as unrealized losses of $13.2 million).~~$8.3 million. All of our natural gas and oil hedges were deemed ineffective for ~~2007; accordingly,~~2007. Accordingly, the changes in fair value of such hedges ~~could~~may no longer be reflected in other comprehensive income. In the first quarter of 2007, we reclassified $1.3 million of previously deferred losses (net of $0.7 million in income taxes) from accumulated other comprehensive loss to loss on derivatives not qualifying for hedge accounting as the underlying properties to which the hedge was originally designated were sold.

During the first quarter we also unwound an oil collar for 400 barrels per day. As a result, we recognized a gain of $0.9 million in the first quarter of 2007. In the first quarter of 2007, we entered into a series of physical sales contracts which will result in us selling approximately 23,500 MMbtu of gas per day in calendar year 2008 for an average price of $8.03 per MMBtu at a commonly used delivery point. In April 2007, we entered into a collar with BNP Paribas for 10,000 MMbtu/day with a floor of $8.00 and a ceiling of $10.20 for calendar year 2008.

During the third quarter of 2007 we entered into natural gas swap contracts for 20,000 MMbtu/day with a price of $7.87 per MMbtu ~~before transportation charges.~~for the entire calendar year of 2009. The price of $7.87 per MMbtu is for delivery at a commonly used pricing point in East Texas, and equates to a NYMEX price of $8.25 per MMbtu with a deduction of $0.38 for presumed differential from the NYMEX hub.

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 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 ~~March 31,~~September 30, 2007, we had the following interest rate swaps in place with BNP (in ~~millions)~~thousands):

The fair value of the interest rate swap contracts in place at ~~March 31,~~September 30, 2007, resulted in ~~an asset~~a liability of ~~$54,000.~~$0.1 million. For the three months ended ~~March 31,~~September 30, 2007, ~~and 2006, our~~we recognized a $0.3 million loss in earnings that was mostly unrealized. Our earnings were not significantly affected by ~~cash flow hedging ineffectiveness~~the fair value changes of the interest ~~rates swaps.~~rate swaps for the nine months ended September 30, 2007.

On March 20, 2007, the Company and Malloy Energy Company, L.L.C. closed the sale of substantially all of their oil and gas properties in South Louisiana with the exception of the three properties discussed under Note 1 “Assets Held for ~~Sale”.~~Sale.” The total sales price for the Company’s interest in the oil and gas properties was $77 million. The total sales price for Malloy Energy’s interests in these properties was approximately $22 million. The Chairman of our Board of Directors, Patrick E. Malloy, III, is the President and controlling shareholder of Malloy Energy Company, L.L.C.

In accordance with SFAS No. 144, ~~“Accounting~~Accounting for the Impairment or Disposal of Long-Lived ~~Assets”~~Assets, the results of operations and gain relating to the sale have been reflected as discontinued operations. We recorded an after tax gain on sale of ~~$10.9~~$9.8 million (pre-tax gain of ~~$16.8~~$15.0 million and tax of ~~$5.9~~$5.2 million) on net proceeds of ~~approximately $74.0~~$72.5 million after normal closing adjustments.

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

~~We recorded a net~~ (“SFAS 109”). SFAS No. 109 requires the Company to recognize income tax ~~benefit attributable~~benefits for loss carry forwards which have not previously been recorded. The tax benefits recognized must be reduced by a valuation allowance when it is more likely than not that the deferred tax asset will not be realized. At September 30, 2007, the Company increased its valuation allowance by $14.8 million.

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. As we have incurred net operating losses in 2006 and prior years, and current conditions appear to ~~continuing~~indicate a loss in 2007, relevant accounting guidance suggests that cumulative losses in recent years constitute significant negative evidence, and that future expectations about income are insufficient to overcome a history of such losses. Therefore, with the before mentioned adjustment of $14.8 million, we have reduced the carrying value of our net deferred tax asset to zero. If we achieve profitable operations ~~totaling $6.7 million, which is~~in the future, we may reverse a portion of the valuation allowance in an ~~effective~~amount at least sufficient to eliminate any tax ~~rate of 34.7%. Our effective~~provision in that period. The valuation allowance has no impact on our net operating loss (“NOL”) position for tax ~~rate differs from the 35% federal statutory rate primarily~~purposes, and if we generate taxable income in future periods, we will be able to utilize our NOL’s to offset taxes due ~~to state income taxes.~~at that time. The income tax benefit includes tax expense of $94 thousand ($63 thousand net of federal tax benefit) attributable to the Texas Margin Tax (“TMT”) which took effect for our Texas income tax reporting purposes on January 1, 2007.

In July 2005, we received a Notice of Proposed Tax Due from the State of Louisiana asserting that we underpaid our Louisiana franchise taxes for the years 1998 through 2004 in the amount of $0.6 million. The Notice of Proposed Tax Due includes additional assessments of penalties and interest in the amount of $0.4 million for a total asserted liability of $1.0 million. In order to avoid future penalties and interest, the Company paid, under protest, $1.0 million to the State of Louisiana in April ~~2007. We have accrued for this amount at March 31,~~ 2007 which payment was expensed in general and ~~recognized an~~administrative expense ~~equal to the full $1.0 million.~~in first quarter 2007. We plan to pursue the reimbursement of the full $1.0 million paid under ~~protest in April 2007.~~protest. Should our efforts prevail, the taxes paid under protest would be refunded, at which time we would book a credit to general and administrative expense.

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

On February 7, 2007, we announced the acquisition of drilling and development rights to acreage located in the Angelina River play. We acquired a 60% working interest in the acreage and will operate the joint venture. The acquisition was completed in two separate transactions. In the initial transaction, we acquired a 40% working interest for $2.0 million from a private company. We also agreed to carry the private company for a 20% working interest in the drilling of five wells. In the second transaction, we purchased the remaining 20% working interest in the acreage in a like-kind exchange for our 30% interest in the Mary Blevins field.

On March 20, 2007, the ~~company~~Company closed the sale of substantially all of its oil and gas properties in South Louisiana to a private company. See Note 6.

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

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:

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, 2006, under the headings “Business—Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of ~~Operations”.~~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.

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. We continue to aggressively pursue the acquisition and evaluation of prospective acreage, oil and gas drilling opportunities and potential property acquisitions.

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 utilize derivative instruments to hedge future sales prices on a portion of our oil and natural gas production. While the derivative instruments may protect downward price fluctuation, the use of certain types of derivative instruments may prevent us from realizing the full benefit of upward price movements.

Our relatively low risk development drilling program in the Cotton Valley Trend is primarily centered in and around Rusk, Panola, Angelina and Nacogdoches ~~Counties,~~counties, Texas, and DeSoto, ~~and~~ Caddo and Bienville ~~Parishes,~~parishes, Louisiana. ~~In addition, we have recently expanded our acreage position in the Trend to include Harrison, Smith and Upshur Counties of Texas.~~ We have steadily increased our acreage position in these areas over the last two years to approximately ~~185,000~~184,200 gross acres as of ~~March 31,~~September 30, 2007. ~~As of March 31,~~Through September 30, 2007, we have ~~drilled and/or logged a cumulative total~~participated in the drilling and logging of ~~173~~239 Cotton Valley Trend wells with a success rate in excess of 99%, of which drilling operations were conducted on 2336 gross wells during the ~~first~~third quarter of 2007. Our net production volumes from our Cotton Valley Trend wells aggregated approximately ~~36,677~~45,444 Mcfe ~~of gas~~ per day in the ~~first~~third quarter of 2007, or approximately ~~98.5%~~37% higher than the Cotton Valley Trend production of the comparable prior year period.

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 ~~$74.0~~$72.5 million, net to the Company, after normal closing adjustments. The effective date of the sale was July 1, 2006. ~~We also expect to sell our remaining assets in South Louisiana within the next year.~~ The remaining fields treated as held for sale are St. Gabriel, Bayou Bouillon and Plumb Bob.

Our development, financial and operating performance for the ~~first~~third quarter 2007 included the following highlights:

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, 2006 and a Current Report on Form ~~10-K.~~8-K filed August 7, 2007 to reflect discontinued operations.

~~Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006~~

The financial statements include discontinued operations presentation for our assets located in ~~south~~South Louisiana. See Note 6 to our consolidated financial statements.

For the three months ended ~~March 31,~~September 30, 2007, we reported a net loss applicable to common stock of ~~$0.5~~$23.7 million, or ~~$0.02~~$0.94 per basic share on total revenue from continuing operations of ~~$23.5~~$27.3 million as compared with a net income applicable to common stock of ~~$8.6~~$6.7 million, or ~~$0.34~~$0.27 per basic share, on total revenue from continuing operations of ~~$14.8~~$19.6 million for the three months ended ~~March 31,~~September 30, 2006. The non-cash income tax expense booked in the third quarter of 2007 of $11.6 million to reduce the value of the deferred tax asset to zero was a significant contributor to the size of the loss in the third quarter of 2007 and for the nine months ending September 30, 2007.

For the nine months ended September 30, 2007, we reported a net loss applicable to common stock of $28.9 million, or $1.15 per basic share on total revenue from continuing operations of $78.8 million as compared with net income applicable to common stock of $18.0 million, or $0.72 per basic share, on total revenue from continuing operations of $54.5 million for the nine months ended September 30, 2006.

Higher depreciation, depletion and amortization expense impacted the results of operations in the three and nine month periods ended September 30, 2007 compared to the same periods in 2006 as well as a loss on derivatives not qualifying for hedge accounting in the nine months ended September 30, 2007 versus a gain for the nine months ended September 30, 2006. See our discussions below under the captions “Depreciation, Depletion and Amortization” and “Gain (Loss) on Derivatives Not Qualifying for Hedge Accounting.”

Revenues presented in the table and the discussion below ~~represent~~represents revenue from sales of our oil and natural gas production ~~volumes and include the realized gains and losses on the effective portion of our derivative instruments for 2006 as further described under Note 5 to the Consolidated Financial Statements.~~volumes. All of our derivative instruments were ineffective in ~~the first quarter of~~ 2007 and did not qualify for hedge accounting.


	Three Months Ended September 30,				% Change from 2006 to 2007		Nine Months Ended September 30,				% Change from 2006 to 2007
	2007		2006		% Change from 2006 to 2007		2007		2006		% Change from 2006 to 2007
Production – Continuing Operations:
Natural gas (MMcf)		4,101		2,910	41	%		10,846		7,590	43	%
Oil and condensate (MBbls)		30		26	15	%		84		81	4	%
Total (MMcfe)		4,282		3,066	40	%		11,349		8,076	41	%
Production – Discontinued Operations:
Natural gas (MMcf)		8		600	(99	)%		531		1,835	(71	)%
Oil and condensate (MBbls)		2		105	(98	)%		86		274	(69	)%
Total (MMcfe)		20		1,230	(98	)%		1,047		3,479	(70	)%
Revenues from production (in thousands):
Natural gas	$	24,955	$	17,670	41	%	$	72,964	$	48,622	50	%
Oil and condensate		2,205		1,795	23	%		5,373		5,242	2	%

Total revenues from production	$	27,160	$	19,465	40	%	$	78,337	$	53,864	45	%

Average sales price per unit:
Natural gas (per Mcf)	$	6.09	$	6.07	0	%	$	6.73	$	6.41	5	%
Oil and condensate (per Bbl)	$	73.32	$	68.50	7	%	$	64.12	$	64.75	(1	)%
Total (per Mcfe)	$	6.34	$	6.35	0	%	$	6.90	$	6.67	3	%

Revenues from production-continuing operations increased ~~62%~~40% in the ~~first~~third quarter of 2007 compared to the same period in 2006 due primarily to a substantial increase in Cotton Valley Trend production. Production from continuing operations also increased 40% period to period. The average sales price per unit was flat period to period.

Revenues ~~were also impacted favorably by a 2%~~from production-continuing operations for the nine months ended September 30, 2007, increased 45% compared to the same period in 2006. An increase in production in the Cotton Valley Trend led to production gains of 41% for the period. We also realized a 3% increase in our average sales price per unit.

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

Lease Operating. Lease operating expense (“LOE”) for the ~~first~~third quarter of 2007 increased on an absolute basis ($~~4.1~~5.2 million compared to ~~$2.2~~$3.9 million). However, LOE on a per unit basis was lower for the third quarter of 2007 compared to prior year quarter ($1.22 per Mcfe compared to $1.27 per Mcfe). LOE for the first nine months of 2007 increased on an absolute basis ($15.5 million compared to $8.3 million) as well as on a per unit basis ($~~1.23~~1.37 per Mcfe compared to ~~$1.06~~$1.02 per Mcfe) from the ~~first~~comparable 2006 period. The third quarter of ~~2006. This increase~~2007 and first nine months of 2007 include $0.5 million and $1.9 million, respectively, in ~~unit~~workover costs ~~was primarily attributable~~which contributed $0.11 and $0.17, respectively, to anthe LOE per Mcfe rates.

An industry wide increase in operating costs as well as high salt water disposal (“SWD”) costs ~~prevalent~~also contributed to higher LOE per Mcfe rates. SWD costs contributed $1.4 million ($0.33 per Mcfe) in ~~certain~~the third quarter of 2007 and $4.6 million ($0.41 per Mcfe) in the first nine months of 2007 to our total LOE costs. During the third quarter of 2007, we began to experience the benefits of our ~~Cotton Valley Trend fields. Once we are able to fully implement our~~new low pressure gathering system (“LPGS”) in East Texas, ~~which is nearing completion, we expect these expenses~~with SWD costs falling from $1.8 million ($0.47 per Mcfe) in second quarter 2007 to ~~be meaningfully reduced on a~~$1.4 million ($0.33 per ~~unit basis.~~Mcfe) for third quarter 2007.

Production and Other Taxes.Production and other taxes ~~decreased to $0.3~~of $1.3 million for the ~~first~~third quarter of 2007 ~~compared to $0.9~~consist of production tax of $0.6 million ~~for the comparable period in 2006 due to a greater portion~~and ad valorem tax of ~~our wells qualifying for~~$0.7 million. Production tax included $0.4 million of accrued Tight Gas Sands (“TGS”) credits for our wells in the State of Texas. Ad valorem tax included an adjustment of $0.6 million in the third quarter to true-up our estimates for full year 2007 taxes due. During the comparable period in 2006, production and ad valorem taxes were $0.8 million and $0.2 million, respectively. In the first nine months of 2007, production and other taxes of $1.0 million includes production taxes of $0.1 million (including the impact of accrued TGS credits) versus $2.5 million for the first nine months of 2006. Also included in the nine month period are $0.8 million of ad valorem tax versus $0.4 million for the comparable prior year period.

These TGS credits allow for reduced and in many cases the complete elimination of severance taxes in the State of Texas for qualifying wells for up to ten years of production. We only accrue for such credits once we have been notified of the State’s approval, 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 was $1.7 million ($0.40 per Mcfe) in the third quarter of 2007 compared to $1.2 million ($0.40 per Mcfe) in the third quarter of 2006. The increased expense is a function of our higher production volumes.

Transportation expense increased to ~~$1.1~~$4.2 million ($~~0.32~~0.37 per Mcfe) in the first ~~quarter~~nine months of 2007 as a result of increased ~~volumes~~natural gas production in the Cotton Valley Trend. As disclosed in the Company’s Quarterly Report on Form 10-Q for the period ending June 30, 2006, prior to that quarter transportation expenses were shown as a deduction from oil and gas revenues. As such, for the first quarter of 2006, there were no transportation expenses booked. However, the Company did disclose in the aforementioned Form 10-Q that the amounts included as a reduction in revenuesTransportation expense was $2.7 million ($0.34 per Mcfe) in the first ~~quarter~~nine months of ~~2006 amounted to $0.5 million.~~2006.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) expense increased to ~~$17.7~~$20.4 million in the third quarter of 2007 from ~~$5.9~~$9.8 million for the same period in 2006 primarily due to a higher DD&A rate coupled with higher levels of production. Since we utilize the successful efforts method of accounting, our DD&A rate is primarily a function of our capitalized drilling and completion costs divided by our proved developed reserves. We embarked on an aggressive drilling program to fully develop our extensive East Texas / North Louisiana Cotton Valley acreage position during a period of record high costs for drilling and completion services. Additionally, in order to hold the majority of our acreage and thereby allow for the most prudent development plan going forward, we chose to drill many wells in the outlying areas of our acreage block, where per well results were less certain than in the initial established areas. Finally, many of our initial wells in certain fields required us to pay the costs of other industry partners in order to earn access to the full acreage position. As such, we feel our DD&A rate on a company-wide basis will decrease over time as we add more proved developed reserves to our asset base through the drilling of wells where we are more certain of the results and we pay only our proportionate share of the costs. For these reasons, the average DD&A rate for the third quarter of 2007 was $4.77 per Mcfe compared to $3.20 per Mcfe for the same quarter of 2006. Similarly, DD&A expense increased to $57.6 million for the nine months ended September 20, 2007 from $25.7 million for the same period in 2006 primarily due to the same reasons. The average DD&A rate increased to ~~$5.28~~$5.08 per Mcfe infor the first ~~quarter~~nine months of 2007, compared to ~~$2.79~~$3.18 per Mcfe in the same ~~quarter~~period of ~~2006, due to a higher percentage of production coming from fields with higher average DD&A rates.~~ 2006.

We calculated first and second quarter 2007 DD&A rates using the December 31, 2006 reserves, which ~~were valued at 2006 year-end prices as required by the SEC. Given the significant pricing difference between December 31, 2006 and December 31, 2005, a number~~did not recognize any impact of our ~~wells drilled during 2006 were credited with fewer proved developed reserves than originally anticipated, thus resulting in~~2007 Cotton Valley Trend drilling program reserve additions. During the ~~higher DD&A rate. The Company is currently planning to engage its~~third quarter of 2007, we engaged an independent engineering firm to ~~audit~~fully engineer our June 30, 2007 proved reserve estimates. The mid-year ~~2007 reserves, at which time we may recalculate~~reserve report was used to calculate the rate for the third quarter of 2007. As mentioned above, the DD&A ~~rates~~rate per Mcfe based on this report was $4.77 for the ~~remainder~~third quarter of ~~2007.~~2007, which was lower than the rate used for the first half of this year primarily due to the inclusion of more wells drilled in our core areas during the first half of this year relative to the mix of wells in the December 31, 2006 reserve report.

Exploration. Exploration expenses for the ~~first~~third quarter of 2007 increased to ~~$2.3~~$1.8 million ($0.41 per Mcfe) from $1.5 million ($0.50 per Mcfe) for the third quarter of 2006. Exploration expenses for the first nine months of 2007 increased to $5.8 million from ~~$1.4~~$4.4 million during the ~~first quarter of~~same period in 2006, ~~due primarily~~however, the per unit cost declined in both comparable periods. The increase in exploration expense for the nine months ended September 30, 2007 from the prior year period relates to ~~higher~~an increase in leasehold amortization, ~~costs and delay rental costs. As the Company has increased its undeveloped acreage position since last year, the amortization of leasehold costs,~~ which is a non-cash expense ~~has~~and the largest component of exploration expense. We increased our undeveloped acreage position from last year which resulted in higher leasehold cost amortization of $5.0 million for the nine months ended September 30, 2007, compared to ~~$1.8 million from $1.2~~$3.3 million in the ~~prior year period.~~same period last year.

Impairment of oil and gas properties. We recorded an impairment expense of $0.3 million in the third quarter of 2007, all of it being determined in conjunction with the receipt of the independent engineer’s mid-year report on reserves. All of the expense relates to a single well in a non-core area of East Texas.

General and Administrative.General and administrative (“G&A”) expense increased to ~~$5.3~~$5.1 million ($1.18 per Mcfe) for the ~~first~~third quarter of 2007, compared to ~~$3.8~~$4.3 million ($1.40 per Mcfe) for the same period of 2006, resulting from generally

higher payroll costs and stock based compensation costs. Stock based compensation expense, which is a non-cash item, for the third quarter amounted to $1.6 million in 2007 versus $1.4 million in 2006. This year’s quarter includes a $0.3 million charge for the acceleration of vesting of options and restricted stock associated with the resignation of an officer of the Company.

G&A expense increased to $15.9 million for the nine months ended September 30, 2007, compared to $12.2 million for the same period of 2006. We accrued a liability for $1.0 million in March 2007, representing $0.4 million in penalties and interest and $0.6 million ~~owed to~~ the State of Louisiana claims we owe for franchise taxes (see Note 89 to our consolidated financial statements). While we paid this amount under protest in April 2007, we plan to pursue the reimbursement of the full $1.0 million. Should our efforts prevail, the taxes paid under protest would be refunded. OfG&A expense includes stock based compensation of $4.3 million for the ~~$5.3~~first nine months of 2007 versus $3.7 million ~~incurred~~ in the first ~~quarter~~nine months of ~~2007, stock based compensation expense, which is non-cash, amounted~~2006. See Note 7 “Share Based Compensation” to ~~$1.4 million versus $0.9 million in 2006.~~our consolidated financial statements for additional information.

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


	Three Months Ended March 31,
	2007			2006			Three Months Ended September 30,				Nine Months Ended September 30,
	(in thousands)						2007		2006		2007		2006
Other income (expense):
Interest Expense	$	(2,624	)	$	(695	)
Interest expense							(3,086	)	(2,509	)	(7,932	)	(4,706	)
Gain (loss) on derivatives not qualifying for hedge accounting		(9,487	)		13,542		2,378		15,188		(3,475	)	34,611
Income tax (expense) benefit		6,743			(4,698	)	(11,641	)	(3,669	)	(3,379	)	(9,779	)
Gain on disposal, net of tax		10,913			—
Income from discontinued operations, net of tax		2,825			2,866
Gain (loss) on disposal, net of tax							(928	)	—		9,823		—
Income (loss) from discontinued operations, net of tax							(401	)	1,337		2,078		5,782

Interest Expense.Interest expense increased to ~~$2.6~~$3.1 million in the third quarter of 2007 from the ~~first~~third quarter of 2006 amount of ~~$0.7~~$2.5 million as a result of the higher average level of funded debt during the ~~first~~third quarter of 2007. Interest expense for the nine months ended September 30, 2007 ~~due largely~~increased to ~~our financing activities consummated~~$7.9 million from $4.7 million for the comparable period of 2006 as a result of the higher average level of funded debt during ~~fiscal year 2006.~~2007.

Gain (Loss) on Derivatives Not Qualifying for Hedge Accounting. ~~Loss~~Gain on derivatives not qualifying for hedge accounting was ~~$9.5~~$2.4 million for the ~~first~~third quarter of 2007 compared to a $15.2 million gain ~~of $13.5 million~~ for the ~~first~~third quarter of 2006. The ~~loss~~gain in 2007 includes an unrealized loss of ~~$13.2~~$0.9 million for the change in fair value of our ineffective oil and gas hedges, and a realized gain of ~~$3.7~~$3.6 million for the effect of settled derivatives. The third quarter of 2007 also includes a $0.3 million loss on our interest rate swap.

Loss on derivatives not qualifying for hedge accounting was $3.5 million for the first nine months of 2007 compared to a gain of $34.6 million for same period in 2006. The loss in 2007 includes an unrealized loss of $11.8 million for the change in fair value of our ineffective oil and gas hedges, and a realized gain of $8.3 million for the effect of settled derivatives. There was no impact from our interest rate swap on the period.

Our natural gas hedges were deemed ineffective beginning in the fourth quarter of 2004, ~~and~~consequently we have been required to reflect the change in the fair value of our natural gas hedges in earnings rather than in accumulated other comprehensive loss, a component of stockholders’ equity. Additionally, our oil hedges were deemed ineffective beginning in the fourth quarter of 2006. To the extent that our hedges do not qualify for hedge accounting in the future, we will likewise be exposed to volatility in earnings resulting from changes in the fair value of our hedges.

Income taxes. Income taxes ~~were a benefit~~expense of ~~$6.7~~$11.6 million for the ~~first~~third quarter of 2007 compared to an expense of ~~$4.7~~$3.7 million for the third quarter of 2006. Income taxes expense of $3.4 million for the first nine months of 2007 compared to expense of $9.8 million for the first nine months of 2006. In the third quarter of ~~2006.~~2007, we increased our valuation allowance against our deferred tax assets by $14.8 million. See Note 8 “Income Taxes” to our consolidated financial statements. The amounts in ~~both~~the prior periods ~~essentially represented~~represent approximately 35% of pre-tax income (loss) from continuing operations. ~~We did not however, incur any income taxes on a current basis due to our substantial tax net operating loss carryforwards.~~

Discontinued Operations. Income from discontinued operations for the three and nine months ended ~~March 31,~~September 30, 2007 and 2006 related to the sale of our South Louisiana assets. We sold substantially all of our South Louisiana assets to a private company in a sale that closed March 20, 2007. In late September 2007, we paid the private company an additional $1.5 million for final closing adjustments. We ~~also~~ recorded aan after-tax loss of $0.9 million in the third quarter related to this final payment. Our total gain on disposal in the first nine months of 2007, net of tax, was $9.8 million. The loss on discontinued operations in the third quarter of ~~$10.9 million.~~2007 primarily represents a pre-tax impairment of $1.1 million for our assets in the St. Gabriel field. Our remaining South Louisiana assets, the St. Gabriel, Bayou Bouillon and Plumb Bob fields, were considered held for sale at ~~March 31,~~September 30, 2007.

Operating activities. Net cash provided by operating activities ~~decreased~~increased to ~~$16.9~~$61.6 million for the first ~~quarter~~nine months of 2007, from ~~$25.8~~$52.5 million in the first quarter of 2006. Virtually all of this decrease resulted from the impact of working capital changes on our operating cash flow. During the first quarter of 2007, these changes used $2.9 million of available cash flow, whereas in the first quarter ofcomparable 2006 these changes provided an additional $12.3 million of cash flow. Given the nature of our ongoing operations in the Cotton Valley Trend and the number of rigs we currently have under contract, these working capital changes will likely fluctuate from time to time between being a source of funds or a use of funds in any given quarter.period. Our cash flows before working capital changes were up from ~~$13.5~~$45.6 million in the first ~~quarter~~nine months of 2006 to ~~$19.8~~$52.4 million in the first ~~quarter~~nine months of 2007 based primarily on our increased production ~~volumes.~~volumes from continuing operations.

Investing activities. Net cash used in investing activities was ~~a source of $12.5~~$134.4 million for the first ~~quarter~~nine months of 2007 compared to ~~a use of $62.6~~$194.8 million for the first ~~quarter~~nine months of 2006. We received net proceeds of ~~$74.0~~$72.5 million resulting from the sale of substantially all of our South Louisiana assets, adjusted for final closing in the ~~first quarter of 2007, which more than offset~~third quarter. Total capital expenditures of ~~$63.5~~$209.0 million for the first nine months of 2007 were up 6% compared to the 2006 amount of $196.5 million. We also released $2.0 million from restricted cash held in escrow related to the sale properties. We conducted drilling operations on ~~approximately 19~~87 gross wells, ~~15 gross wells~~all of which are located in our Cotton Valley Trend, ~~and 4 gross wells located in Angelina River,~~ during the first ~~quarter~~nine months of 2007. ~~As a~~In comparison, we conducted drilling operations on ~~approximately 30~~76 gross wells, of which 2869 were located in our Cotton Valley Trend, during the first ~~quarter~~nine months of 2006. ~~We also~~In 2006, we received proceeds of ~~$0.9~~$1.7 million from ~~the sale~~sales of ~~a salt water disposal facility~~certain interests in ~~the first quarter of 2006.~~East Texas.

Financing activities. Net cash ~~used in~~provided by financing activities was ~~$28.0~~$68.7 million for the ~~first quarter of 2007. Net~~nine months ended September 30, 2007 versus net cash provided by financing activities ~~was $18.5~~of $123.8 million for the ~~first quarter of~~same period in 2006. We used proceeds from ~~our~~the sale of properties in the first quarter of 2007 to pay the full outstanding balance on our ~~Senior Credit Facility,~~existing bank credit facility, which had grown to $65.0 million by the time we received these proceeds.

In December 2006, our Board of Directors approved a preliminary 2007 capital expenditure budget of approximately $275 million, to be used to fund our development drilling program, lease acquisitions and installation of infrastructure in the Cotton Valley Trend of East Texas and Northwest Louisiana. ~~Our Board of Directors may increase our capital expenditure budget for 2007, subject to future economic conditions and financial resources.~~ We expect to finance the remainder of our 2007 capital expenditures through a combination of cash flow from operations ~~proceeds from the aforementioned asset sales,~~ and borrowings under our existing bank credit facility (see “Senior Credit Facility”).

In the ~~future,~~third quarter, we ~~may issue~~obtained a redetermination of the borrowing base of our Senior Credit Facility as discussed below. We intend to raise additional ~~debt or equity securities~~long term capital to provide additional financial resources for our capital expenditures and other general corporate purposes. ~~Our~~We intend to use the proceeds of this financing to pay down amounts outstanding under our Senior Credit Facility, and will then utilize the borrowing base of our Senior Credit Facility and cash flow from operations to fund our ongoing drilling activity. Our existing bank credit facility includes certain financial covenants with which we were in compliance as of ~~March 31,~~September 30, 2007. WeWhen considering the historical success of our capital raising activities and our bank relationships, we do not anticipate a lack of borrowing capacity under our senior credit facility ~~or term loan~~ in the foreseeable future due to an inability to meet any such financial covenants nor a reduction in our borrowing base.

On November 17, 2005, we amended our existing credit agreement and entered into an amended and restated senior credit agreement (the “Senior Credit Facility”) and a second lien term loan (the “Term Loan”) that expanded our borrowing capabilities and extended our credit facility for an additional two years. Total lender commitments under the Senior Credit Facility were ~~$200.0~~$200 million which matures on February 25, 2010. Revolving borrowings under the Senior Credit Facility are limited to, and subject to periodic redeterminations of the borrowing base, which is currently established at ~~$110.0 million, and is scheduled to be redetermined in the third quarter of 2007.~~$170 million. As of ~~March 31,~~September 30, 2007, we ~~repaid all~~had $100 million in outstanding ~~amounts of the~~ revolving borrowings under the Senior Credit Facility. Interest on revolving borrowings under the Senior Credit Facility accrues at a rate calculated, at our option, at either the bank base rate plus 0.00% to 0.50%, or LIBOR plus 1.25% to ~~2.00%~~2.25%, depending on borrowing base utilization.

The terms of the Senior Credit Facility require us to maintain certain covenants. Capitalized terms are defined in the credit agreement. The covenants ~~include~~:include:

On August 7, 2007, we amended the Senior Credit Facility (“Amended Senior Credit Facility”) to change the last of these financial covenants beginning with the quarter ending September 30, 2007 and ending with the quarter ending December 31, 2007. The financial covenant will return to a 3.5 times Debt to EBITDAX limitation for the trailing four quarters beginning with the quarter ending March 31, 2008. As a result of the sale of the Company’s South Louisiana assets in the first quarter of 2007 (see Note 6 “Discontinued Operations” to our consolidated financial statements), a preliminary EBITDAX calculation for the trailing four quarters ending June 30, 2007 (which excluded all EBITDAX generated by the sold South Louisiana assets) indicated that the Company might not be in compliance with the ratio at the 3.5 times limitation. As a result, the Company requested and the bank group approved amending the ratio as discussed above for the purpose of clarifying the calculation of the covenant.

As of ~~March 31,~~September 30, 2007, we were in compliance with all of the financial covenants of the Amended Senior Credit Facility.

See Note 1 to our Consolidated Financial Statements for a discussion of recently issued accounting pronouncements.

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 ~~2006~~ Annual Report on Form 10-K for the year ended December 31, 2006 and a Current Report on Form 8-K dated August 7, 2007, includes a discussion of our critical accounting policies.

Income Taxes — FASB Interpretation No. 48 (“FIN 48”),Accounting for Uncertainty in Income Taxes, provides guidance on recognition and measurement of uncertainties in income taxes and is applicable for fiscal years beginning after December 15, 2006. ~~The Company~~We adopted FIN 48 in the first quarter of 2007. See Notes 1 and 78 to our consolidated financial statements.

Despite the measures taken by us to attempt to control price risk, we remain subject to price fluctuations for natural gas and crude oil sold in the spot market. Prices received for natural gas sold on the spot market are volatile due primarily to seasonality of demand and other factors beyond our control. Domestic crude oil and gas prices could have a material adverse effect on our financial position, results of operations and quantities of reserves recoverable on an economic basis.

We enter into futures contracts or other hedging agreements from time to time to manage the commodity price risk for a portion of our production. We consider these agreements to be hedging activities and, as such, monthly settlements on the contracts that qualify for hedge accounting are reflected in our crude oil and natural gas sales. Our strategy, which is

administered by the Hedging Committee of 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 ~~March 31,~~September 30, 2007, the commodity hedges we utilized were in the form of: (a) swaps, where we receive a fixed price and pay a floating price, based on NYMEX quoted prices, (b) collars, where we receive the excess, if any, of the floor price over the reference price, based on NYMEX quoted prices, and pay the excess, if any, of the reference price over the ceiling price, and (c) 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. See Note 5 “Hedging Activities” to our consolidated financial statements for additional information.

Our hedging contracts fall within our targeted range of 30% to 70% of our estimated net oil and gas production volumes for the applicable periods of 2007. The fair value of the crude oil and natural gas hedging contracts in place at ~~March 31,~~September 30, 2007, resulted in ana net asset of ~~$2.2~~$3.7 million. Based on oil and gas pricing in effect at ~~March 31,~~September 30, 2007, a hypothetical 10% increase in oil and gas prices would have ~~decreased the~~resulted in a derivative ~~asset to $1.6~~liability of $5.2 million while a hypothetical 10% decrease in oil and gas prices would have increased the derivative asset to ~~$2.9~~$12.6 million. See Note 5 “Hedging Activities” to our consolidated financial statements for additional information.

The fair value of the interest rate swap contracts in place at ~~March 31,~~September 30, 2007, resulted in ~~an asset~~a liability of ~~$54,000.~~$0.1 million. Based on interest rates at ~~March 31,~~September 30, 2007, a hypothetical 10% increase or decrease in interest rates would not have a material effect on the asset.

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 ~~SEC rule~~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, of 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 ~~March 31,~~September 30, 2007, the end of the period covered in this report, concluded that our disclosure controls and procedures were ~~effective.~~effective at the reasonable assurance level.

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

There are no material changes from risk factors previously disclosed in ~~the Company’s~~our Annual Report on Form 10-K for the fiscal year ended December 31, ~~2006.~~2006 and a Current Report on Form 8-K dated August 7, 2007.

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.


			Page

PART I	FINANCIAL INFORMATION		3

ITEM 1.	FINANCIAL STATEMENTS
	Consolidated Balance Sheets as of ~~March 31,~~September 30, 2007 and December 31, 2006		3
	Consolidated Statements of Operations for the three and nine months ended ~~March 31,~~September 30, 2007 and 2006		4
	Consolidated Statements of Cash Flows for the ~~three~~nine months ended ~~March 31,~~September 30, 2007 and 2006		5
	Consolidated Statements of Comprehensive Income for the three and nine months ended ~~March 31,~~September 30, 2007 and 2006		6
	Notes to Consolidated Financial Statements		7

ITEM 2.	~~MANAGEMENT'S~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		14

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		21
		20
ITEM 4.	CONTROLS AND PROCEDURES		21

PART II	OTHER INFORMATION		23
		22
ITEM 1A.	RISK FACTORS		2322
ITEM 4.	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		22
ITEM 6.	EXHIBITS		2322


	Three Months Ended March 31,
	2007		2006
Net income	$	1,036	$	11,592

Other comprehensive income (loss):
Change in fair value of derivatives (1)		—		(1,079	)
Reclassification adjustment (2)		1,261		412

Other comprehensive income (loss)		1,261		(667	)

Comprehensive income	$	2,297	$	10,925

(1) Net of income tax benefit of:	$	—	$	581
(2) Net of income tax expense of:	$	679	$	222


Swaps	Volume	Average Price
Oil (Bbl/day)
2Q 2007	400	$53.35
3Q 2007	400	$53.35
4Q 2007	400	$53.35


Swaps	Volume	Average Price
Oil (Bbl/day)
4Q 2007	400	$	53.35

Fixed Price Physical Contracts	Volume	Average Price ⁽¹⁾
Natural gas (MMBtu/day)
1Q 2008	23,500	$	8.03
2Q 2008	23,500	$	8.03
3Q 2008	23,500	$	8.03
4Q 2008	23,500	$	8.03

Collars	Volume	Floor/Cap
Natural gas (MMBtu/day)
4Q 2007	10,000	$	9.00 – $10.65
4Q 2007	15,000	$	7.00 – $13.60
4Q 2007	5,000	$	7.00 – $13.90
1Q 2008	10,000	$	8.00 – $10.20
2Q 2008	10,000	$	8.00 – $10.20
3Q 2008	10,000	$	8.00 – $10.20
4Q 2008	10,000	$	8.00 – $10.20

Swaps	Volume	Price⁽²⁾
Natural gas (MMBtu/day)
1Q 2009	20,000	$	7.87
2Q 2009	20,000	$	7.87
3Q 2009	20,000	$	7.87
4Q 2009	20,000	$	7.87

~~Natural gas (MMBtu/day)~~⁽²⁾
~~2Q 2007~~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 at the time would have been $8.25/Mmbtu.	~~10,000~~	~~$9.00 – $10.65~~
~~3Q 2007~~	~~10,000~~	~~$9.00 – $10.65~~
~~4Q 2007~~	~~10,000~~	~~$9.00 – $10.65~~
~~2Q 2007~~	~~15,000~~	~~$7.00 – $13.60~~
~~3Q 2007~~	~~15,000~~	~~$7.00 – $13.60~~
~~4Q 2007~~	~~15,000~~	~~$7.00 – $13.60~~
~~2Q 2007~~	~~5,000~~	~~$7.00 – $13.90~~
~~3Q 2007~~	~~5,000~~	~~$7.00 – $13.90~~
~~4Q 2007~~	~~5,000~~	~~$7.00 – $13.90~~
~~1Q 2008~~	~~10,000~~	~~$8.00 – $10.20~~
~~2Q 2008~~	~~10,000~~	~~$8.00 – $10.20~~
~~3Q 2008~~	~~10,000~~	~~$8.00 – $10.20~~
~~4Q 2008~~	~~10,000~~	~~$8.00 – $10.20~~


Fixed Price Physical Contracts	Volume	Price
Natural gas (MMBtu/day)
1Q 2008	23,500	$8.03
2Q 2008	23,500	$8.03
3Q 2008	23,500	$8.03
4Q 2008	23,500	$8.03


~~Collars~~⁽¹⁾		~~Volume~~		~~Floor/Cap~~ Normal sale at a fixed delivery point.


Effective Date	Maturity Date	LIBOR Swap Rate		Notional Amount
02/27/07	02/26/09	4.86	%	$	40.0


Effective Date	Maturity Date	LIBOR Swap		Notional Amount
2/27/2007	2/26/2009	4.86	%	$	40,000


	For the Three Months Ended March 31,
	2007			2006
	(in thousands)
Revenues	$	8,603		$	10,482
Income from discontinued operations		4,346			4,409
Income tax expense		(1,521	)		(1,543	)
Income from discontinued operations net of tax		2,825			2,866


	Three Months Ended March 31,				Variance
Operating Expenses per Mcfe	2007		2006		Variance
Lease operating expense	$	1.23	$	1.06	$	0.17		16	%
Production taxes		0.09		0.43		(0.34	)	(79	%)
Transportation		0.32		—		—		—
Depreciation, depletion and amortization		5.28		2.79		2.49		89	%
Exploration		0.69		0.66		0.03		5	%
General and administrative		1.59		1.79		(0.20	)	(11	%)


	Nine Months Ended September 30,
	2007			2006			Variance
Cash flow statement information:
Net cash:
Provided by operating activities	$	61,588		$	52,453		$	9,135
Used in investing activities		(134,411	)		(194,810	)		60,399
Provided by financing activities		68,703			123,829			(55,126	)

Decrease in cash and cash equivalents	$	(4,120	)	$	(18,528	)	$	14,408


Effective Date	Maturity Date	LIBOR Swap Rate	Notional Amount
02/27/07	02/26/09	4.86%	$40.0


*10.1†		Amended and Restated Severance Agreement between the Company and Walter G. Goodrich, effective November 5, 2007.

*10.2†		Amended and Restated Severance Agreement between the Company and Robert C. Turnham, effective November 5, 2007.

*10.3†		Amended and Restated Severance Agreement between the Company and David R. Looney, effective November 5, 2007.

*10.4†		Amended and Restated Severance Agreement between the Company and Mark E. Ferchau, effective November 5, 2007

*10.5†		Goodrich Petroleum Corporation Annual Bonus Plan, effective November 5, 2007

*31.1		Certification of Chief Executive Officer Pursuant to 15 ~~U.S.C~~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.


	GOODRICH PETROLEUM CORPORATION (Registrant)

Date: ~~May 10,~~November 8, 2007	By:	/s/ Walter G. Goodrich
		Walter G. Goodrich
		Vice Chairman & Chief Executive Officer

Date: ~~May 10,~~November 8, 2007	By:	/s/ David R. Looney
		David R. Looney
		~~David R. Looney~~ Executive Vice President & Chief Financial Officer


EXHIBIT NO.		DESCRIPTION OF EXHIBIT
10.1		Amended and Restated Severance Agreement between the Company and Walter G. Goodrich, effective November 5, 2007.

10.2		Amended and Restated Severance Agreement between the Company and Robert C. Turnham, effective November 5, 2007.

10.3		Amended and Restated Severance Agreement between the Company and David R. Looney, effective November 5, 2007.

10.4		Amended and Restated Severance Agreement between the Company and Mark E. Ferchau, effective November 5, 2007

10.5		Goodrich Petroleum Corporation Annual Bonus Plan, effective November 5, 2007

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.