Edgar Filing: GOODRICH PETROLEUM CORP

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Form 10-Q for quarterly period ended September 30, 2010

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, 2010

¨	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.)

801 Louisiana, Suite 700

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 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.

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 2, 2010 was 37,561,845.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS


		Page
PART I	FINANCIAL INFORMATION		3
ITEM 1	FINANCIAL STATEMENTS		3
	Consolidated Balance Sheets as of September 30, 2010 and December 31, 2009		3
	Consolidated Statements of Operations for the three and nine months ended September 30, 2010 and 2009		4
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2010 and 2009		5
	Notes to Consolidated Financial Statements		6
ITEM 2	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		16
ITEM 3	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		26
ITEM 4	CONTROLS AND PROCEDURES		27

PART II	OTHER INFORMATION		29
ITEM 1	LEGAL PROCEEDINGS		29
ITEM 1A	RISK FACTORS		29
ITEM 6	EXHIBITS		30

PART 1 – FINANCIAL INFORMATION

Item 1—Financial Statements

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(In thousands, except share amounts)


	September 30, 2010			December 31, 2009
	(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	12,565		$	125,116
Accounts receivable, trade and other, net of allowance		12,873			7,944
Income taxes receivable		4,250			15,438
Accrued oil and gas revenue		12,544			17,206
Fair value of natural gas derivatives		27,352			5,403
Materials inventory		7,857			662
Restricted cash		8,465			—
Prepaid expenses and other		1,950			1,609

Total current assets		87,856			173,378

PROPERTY AND EQUIPMENT:
Oil and gas properties (successful efforts method)		1,532,885			1,339,462
Furniture, fixtures and equipment		4,800			3,985

		1,537,685			1,343,447
Less: Accumulated depletion, depreciation and amortization		(984,854	)		(669,463	)

Net property and equipment		552,831			673,984
Fair value of natural gas derivatives		20,069			—
Deferred tax assets		7,433			4,700
Deferred financing cost		6,204			8,212

TOTAL ASSETS	$	674,393		$	860,274

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	49,141		$	35,079
Accrued liabilities		40,631			25,308
Deferred tax liabilities		7,433			4,700
Accrued abandonment costs		5,589			4,574
Fair value of natural gas swap derivatives		388			—
Fair value of interest rate derivatives		—			1,087

Total current liabilities		103,182			70,748
LONG-TERM DEBT		342,063			330,147
Accrued abandonment costs		13,894			13,716
Fair value of natural gas derivatives		—			278

Total liabilities		459,139			414,889

Commitments and contingencies (See Note 10)
STOCKHOLDERS’ EQUITY:
Preferred stock: 10,000,000 shares authorized: Series B convertible preferred stock, $1.00 par value, issued and outstanding 2,250,000 shares		2,250			2,250
Common stock: $0.20 par value, 100,000,000 shares authorized; issued and outstanding 37,563,112 and 37,452,023 shares, respectively		7,188			7,166
Treasury stock (2,121 and 19,915 shares, respectively)		(27	)		(411	)
Additional paid in capital		642,149			637,335
Retained earnings (accumulated deficit)		(436,306	)		(200,955	)

Total stockholders’ equity		215,254			445,385

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	674,393		$	860,274

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,
	2010			2009			2010			2009
REVENUES:
Oil and gas revenues	$	37,443		$	23,567		$	111,920		$	78,241
Other		(19	)		(42	)		121			8

		37,424			23,525			112,041			78,249

OPERATING EXPENSES:
Lease operating expense		6,280			7,363			19,841			23,343
Production and other taxes		664			1,294			2,017			3,831
Transportation		2,977			2,300			7,619			7,479
Exploration		2,033			1,625			7,639			6,804
Depreciation, depletion and amortization		26,022			42,063			84,638			112,258
Impairment of oil and gas properties		223,304			—			223,304			23,490
General and administrative		7,275			6,802			23,722			20,572
Gain on sale of assets		—			(182	)		—			(295	)
Other		(4,232	)		—			4,268			—

		264,323			61,265			373,048			197,482

Operating loss		(226,899	)		(37,740	)		(261,007	)		(119,233	)

OTHER INCOME (EXPENSE):
Interest expense		(9,154	)		(6,646	)		(27,469	)		(17,152	)
Interest income and other		11			18			117			466
Gain (loss) on derivatives not designated as hedges		22,494			(1,545	)		57,543			38,017

		13,351			(8,173	)		30,191			21,331

Loss before income taxes		(213,548	)		(45,913	)		(230,816	)		(97,902	)
Income tax benefit		—			16,394			—			36,545

Net loss		(213,548	)		(29,519	)		(230,816	)		(61,357	)
Preferred stock dividends		1,511			1,512			4,535			4,536

Net loss applicable to common stock	$	(215,059	)	$	(31,031	)	$	(235,351	)	$	(65,893	)

PER COMMON SHARE
Net loss applicable to common stock - basic	$	(5.98	)	$	(0.87	)	$	(6.56	)	$	(1.84	)
Net loss applicable to common stock - diluted	$	(5.98	)	$	(0.87	)	$	(6.56	)	$	(1.84	)
Weighted average common shares outstanding - basic		35,936			35,771			35,904			35,892
Weighted average common shares outstanding - diluted		35,936			35,771			35,904			35,892

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,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(230,816	)	$	(61,357	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depletion, depreciation and amortization		84,638			112,258
Unrealized (gain) loss on derivatives not designated as hedges		(42,994	)		36,983
Deferred income taxes		—			(36,439	)
Exploration		1,225			160
Amortization of leasehold costs		4,467			3,916
Impairment of oil and gas properties		223,304			23,490
Stock based compensation (non-cash)		5,496			4,742
Gain on sale of assets		—			(295	)
Amortization of debt discount and finance cost		14,242			7,603
Change in assets and liabilities:
Accounts receivable, trade and other, net of allowance		6,249			1,656
Accrued oil and gas revenue		4,662			4,950
Materials inventory		(7,195	)		148
Prepaid expenses and other		(49	)		(2,896	)
Restricted cash		(8,465	)		—
Accounts payable		14,062			(14,829	)
Accrued liabilities		8,126			1,540
Income taxes payable		10			(1,361	)

Net cash provided by operating activities		76,962			80,269

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(184,081	)		(226,441	)
Proceeds from sale of assets		3			235

Net cash used in investing activities		(184,078	)		(226,206	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Principal payments of bank borrowings		—			(80,000	)
Proceeds from bank borrowings		—			5,000
Proceeds from convertible note offering		—			218,500
Exercise of stock options and warrants		10			—
Debt issuance costs		(318	)		(8,324	)
Preferred stock dividends		(4,535	)		(4,536	)
Other		(592	)		(714	)

Net cash used in financing activities		(5,435	)		129,926

DECREASE IN CASH AND CASH EQUIVALENTS		(112,551	)		(16,011	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		125,116			147,548

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	12,565		$	131,537

See accompanying notes to consolidated financial statements.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—Description of Business and Significant Accounting Policies

Goodrich Petroleum Corporation (“Goodrich” or “the Company” or “we”) is in the primary business of exploration and production of crude oil and natural gas. We and our subsidiary have interests in such operations, primarily in Texas and Louisiana.

The consolidated financial statements of the Company 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 (“US GAAP”) 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, 2009. The results of operations for the three and nine months ended September 30, 2010 are not necessarily indicative of the results to be expected for the full year.

Reclassifications—Certain amounts for prior periods have been reclassified to conform to current year presentation. These reclassifications have no impact on net loss.

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 US GAAP.

Materials Inventory—Materials inventory consists of casing and tubulars that are expected to be used in our Capital Drilling Program. Materials inventory is carried on the Balance Sheet at the lower of cost or market.

Derivative Instruments—We use derivative instruments such as collars and swaps for purposes of hedging our exposure to fluctuations in the price of crude oil and natural gas and to hedge our exposure to changing interest rates. Accounting standards related to derivative instruments and hedging activities require that all derivative instruments subject to the requirements of those standards be measured at fair value and recognized as assets or liabilities in the balance sheet. Changes in fair value are required to be recognized in earnings unless specific hedge accounting criteria are met. We do not designate our derivative contracts as hedges accordingly changes in fair value are reflected in earnings. See Note 8—Derivative Activities.

Impairment—Proved oil and gas properties accounted for under the Successful Efforts method of accounting are reviewed for impairment on a field-by-field basis when facts and circumstances indicate that their carrying amounts may not be recoverable. In performing this review, future net cash flows are calculated based on estimated future oil and gas sales revenues less future expenditures necessary to develop and produce the reserves. If the sum of these estimated future cash flows (undiscounted) is less than the carrying amount of the property, an impairment loss is recognized for the excess of the property’s carrying amount over its estimated fair value based on estimated discounted future cash flows. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We perform this comparison using our estimates of future commodity prices and proved and probable reserves. For the three and nine months ended September 30, 2010, we recorded impairments of $223.3 million. See Note 9—Fair Value.

Income Taxes—We account for income taxes 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. See Note 6—Income Taxes.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

New Accounting Pronouncements

Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance or Other Financing. In October 2009, the Financial Accounting Standards Board (“FASB”) issued guidance on accounting for own-share lending arrangements in contemplation of convertible debt issuance. The standard requires that such share-lending arrangement be measured at fair value at the date of issuance and recognized as an issuance cost with an offset to paid-in-capital and the loaned shares be excluded in the computation of basic and diluted earnings per share. The issuance cost is required to be amortized as interest expense over the life of the financing arrangement. The standard also requires additional disclosures including a description and the terms of the arrangement and the reason for entering into the arrangement. Retrospective application is required for all arrangements outstanding as of the beginning of the fiscal years beginning on or after December 15, 2009. The impact of the new guidance on our financial statements, as it relates to the shares outstanding under the share lending agreement (the “Share Lending Agreement”) that we entered into in connection with the December 2006 issuance of our 3.25% Convertible Senior Notes due 2026, was evaluated and considered immaterial.

Fair Value Measurements. In January 2010, the FASB issued authoritative guidance related to improving disclosures about fair value measurements. This guidance requires separate disclosures of the amounts of transfers in and out of Level 1 and Level 2 fair value measurements and a description of the reason for such transfers. In the reconciliation for Level 3 fair value measurements using significant unobservable inputs, information about purchases, sales, issuances and settlements shall be presented separately. These disclosures are required for interim and annual reporting periods effective January 1, 2010, except for the disclosures related to the purchases, sales, issuances and settlements in the roll forward activity of Level 3 fair value measurements, which are effective on January 1, 2011. This guidance was adopted on January 1, 2010 for Level 1 and Level 2 fair value measurements and did not impact the Company’s operating results, financial position, cash flows or disclosures.

NOTE 2—Resignation of Executive Officer

In March 2010, an officer of the Company resigned. The provisions of the Resignation Agreement dated March 24, 2010 consisted primarily of the following:

•

Term life of 60,000 fully vested options was modified;

•

Accelerated vesting of 25,000 shares of restricted stock; and

•

Execution of a consulting agreement for six months through September 2010.

The Company recognized additional expense related to the agreement of approximately $0.9 million during the nine months ended September 30, 2010.

NOTE 3—Asset Retirement Obligations

The reconciliation of the beginning and ending asset retirement obligation (“ARO”) for the period ending September 30, 2010, is as follows (in thousands):


	September 30, 2010
Carrying amount of ARO at beginning of year	$	18,290
Liabilities incurred		30
Liabilities settled or sold		—
Accretion expense		1,163

Carrying amount of ARO at September 30, 2010		19,483

Current liability		5,589
Long term liability	$	13,894

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 4—Long-Term Debt

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


	September 30, 2010			December 31, 2009
Senior Credit Facility	$	—		$	—
3.25% Convertible Senior Notes due 2026		175,000			175,000
Debt discount on 3.25% Convertible Senior Notes due 2026		(9,914	)		(15,915	)
5.0% Convertible Senior Notes due 2029		218,500			218,500
Debt discount of 5.0% Convertible Senior Notes due 2029		(41,523	)		(47,438	)

Total long-term debt	$	342,063		$	330,147

Senior Credit Facility

On May 5, 2009, we entered into a Second Amended and Restated Credit Agreement (“Senior Credit Facility”) that replaced our previous facility. Total lender commitments under the Senior Credit Facility are $350 million. The Senior Credit Facility matures on August 31, 2011. The Senior Credit Facility can be further extended to July 1, 2012 upon receipt of proceeds from a refinancing sufficient to prepay the 3.25% convertible senior notes due 2026. Revolving borrowings under the Senior Credit Facility are limited to, and subject to, periodic redeterminations of the borrowing base. The initial borrowing base was established at $175 million. The borrowing base interest on revolving borrowings under the Senior Credit Facility accrues at a rate calculated, at our option, at the bank base rate plus 0.75% to 1.50% or LIBOR plus 2.25% to 3.00%, depending on borrowing base utilization. Pursuant to the terms of the Senior Credit Facility, borrowing base redeterminations are made on a semi-annual basis on April 1 and October 1. In connection with the offering of our $218.5 million 5% convertible senior notes due 2029, we entered into an amendment of our Senior Credit Facility to permit the issuance of the notes and required payments made on the notes thereafter and to exclude up to $175 million of our 3.25% convertible senior notes due 2026 or our 5% convertible senior notes due 2029 from the definition of Total Debt used in our financial covenants under the Senior Credit Facility. On October 27, 2010, the borrowing base was increased to $250 million. The borrowing base will be reduced to $225 million upon closing on the sale of our non-core assets. As of September 30, 2010 we had no outstanding borrowings under the Senior Credit Facility. Effective September 1, 2010, any borrowed funds outstanding under the Senior Credit Facility will be classified as a current liability as long as the 3.25% convertible senior notes due 2026 are outstanding.

Substantially all of our assets are pledged as collateral to secure the Senior Credit Facility.

The terms of the Senior Credit Facility require us to maintain certain covenants. Capitalized terms used, but not defined here, have the meanings assigned to them in the Senior Credit Facility. The primary financial covenants include:

•

Adjusted Current Ratio of 1.0/1.0;

•

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

•

Total Debt no greater than 3.0 times EBITDAX for the trailing four quarters (EBITDAX is earnings before interest expense, income tax, DD&A, exploration expense and impairment of oil and gas properties. In calculating EBITDAX for this purpose, earnings include realized gains (losses) from derivatives but exclude unrealized gains (losses) from derivatives. Up to $175.0 million of our convertible senior notes are excluded from the calculation of Total Debt for the purpose of computing this ratio).

We were in compliance with all the financial covenants of the Senior Credit Facility as of September 30, 2010.

3.25% Convertible Senior Notes Due 2026

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

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Before December 1, 2011, we may not redeem the 2026 Notes. On or after December 1, 2011, we may redeem all or a portion of the 2026 Notes for cash, and the investors may require us to repurchase the 2026 Notes on each of December 1, 2011, 2016 and 2021. Upon conversion, we have the option to deliver shares at the applicable conversion rate, redeem the 2026 Notes in cash or in certain circumstances redeem in a combination of cash and shares. The 2026 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 the 2026 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 the 2026 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.

We separately account for the liability and equity components of the 2026 Notes in a manner that reflects our nonconvertible debt borrowing rate when interest is recognized in subsequent periods. As of September 30, 2010, the 2026 Notes were carried on the balance sheet at $165.1 million, net of a debt discount balance of $9.9 million. As of December 31, 2009, the 2026 Notes were carried on the balance sheet at $159.1 million, net of a debt discount of $15.9 million. The remaining amount of debt discount as of September 30, 2010 will be amortized using the effective interest rate method based upon an original five year term through December 1, 2011.

Interest expense relating to the contractual interest rate and amortization of debt discount and financing cost relating to the 2026 Notes for the three and nine months ended September 30, 2010 was $3.6 million and $10.9 million, respectively. The effective interest rate on the liability component of the 2026 Notes was 8.8% and 9.0% for the three and nine month periods ended September 30, 2010, respectively.

5% Convertible Senior Notes due 2029

In September 2009, we sold $218.5 million of 5% convertible senior notes (the “2029 Notes”) due in October 2029. The 2029 Notes mature on October 1, 2029, unless earlier converted, redeemed or repurchased. The 2029 Notes are our senior unsecured obligations and rank equally in right of payment to all of our other existing and future indebtedness. The 2029 Notes accrue interest at a rate of 5% annually, and interest is paid semi-annually in arrears on April 1 and October 1.

Before October 1, 2014, we may not redeem the 2029 Notes. On or after October 1, 2014, we may redeem all or a portion of the 2029 Notes for cash, and the investors may require us to repurchase the 2029 Notes on each of October 1, 2014, 2019 and 2024. Upon conversion, we have the option to deliver shares at the applicable conversion rate, redeem the 2029 Notes in cash or in certain circumstances redeem in a combination of cash and shares. The 2029 Notes are convertible into shares of our common stock at a rate equal to 28.8534 shares per $1,000 principal amount of the 2029 Notes (equal to an “initial conversion price” of approximately $34.66 per share of common stock).

We separately account for the liability and equity components of the 2029 Notes in a manner that reflects our nonconvertible debt borrowing rate when interest is recognized in subsequent periods. As of September 30, 2010, the $218.5 million 2029 Notes were carried on the balance sheet at $177.0 million with a debt discount balance of $41.5 million. As of December 31, 2009, the $218.5 million 2029 Notes were carried on the balance sheet at $171.1 million with a debt discount of $47.4 million. The debt discount will be amortized using the effective interest rate method based upon an original five year term through October 1, 2014. Interest expense recognized relating to the contractual interest rate and amortization of debt discount and financing cost for the three and nine months ended September 30, 2010 was $5.0 million and $14.9 million, respectively. The effective interest rate on the liability component of the 2029 Notes was 11.2% and 11.4% for the three and nine month periods ended September 30, 2010, respectively.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 5—Net Loss Per Common Share

Net loss applicable to common stock was used as the numerator in computing basic and diluted income per common share for the nine months ended September 30, 2010 and 2009. The following table reconciles the weighted average shares outstanding used for these computations (in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
	(Amounts in thousands, except per share data)
Basic loss per share:
Net loss applicable to common stock	$	(215,059	)	$	(31,031	)	$	(235,351	)	$	(65,893	)
Average shares of common stock outstanding (1)		35,936			35,771			35,904			35,892

Basic loss per share	$	(5.98	)	$	(0.87	)	$	(6.56	)	$	(1.84	)

Diluted loss per share:
Net loss applicable to common stock	$	(215,059	)	$	(31,031	)	$	(235,351	)	$	(65,893	)
Dividends on convertible preferred stock (2)		—			—			—			—
Interest and amortization of loan cost on senior convertible notes, net of tax (3)		—			—			—			—

	$	(215,059	)	$	(31,031	)	$	(235,351	)	$	(65,893	)

Average shares of common stock outstanding (1)		35,936			35,771			35,904			35,892
Assumed conversion of convertible preferred stock (2)		—			—			—			—
Assumed conversion of convertible senior notes (3)		—			—			—			—
Stock options and restricted stock (4)		—			—			—			—

Average diluted shares outstanding		35,936			35,771			35,904			35,892

Diluted loss per share	$	(5.98	)	$	(0.87	)	$	(6.56	)	$	(1.84	)

(1)	This amount does not include 1,624,300 shares of common stock outstanding under the Share Lending Agreement. See Note 7–Stockholders’ Equity.

(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 as they would not have been dilutive.

(3)	Common shares issuable upon assumed conversion of our convertible senior notes amounting to 8,958,394 shares and the accrued interest on the 2026 Notes and the 2029 Notes were not included in the computation of diluted loss per share for all periods presented as they would not have been dilutive.

(4)

Common shares issuable on assumed conversion of restricted stock and employee stock options for the three and nine months ended September 30, 2009 in the amounts of 115,109 and 98,163 shares, respectively, were not included in the computation of diluted loss per common share since their inclusion would not have been dilutive. Common shares issuable on assumed conversion of restricted stock and employee stock options for the three and nine months ended September 30, 2010 in the amounts of 6,216 and 34,800 shares, respectively, were not included in the computation of diluted loss per common share since their inclusion would not have been dilutive.

NOTE 6—Income Taxes

We recorded no income tax expense for the three and nine months ended September 30, 2010. We increased our valuation allowance and reduced our net deferred tax assets to zero during 2009 after considering all available positive and negative evidence related to the realization of our deferred tax assets. Our assessment of the realization of our deferred tax assets has not changed and as a result, we continue to maintain a full valuation allowance for our net deferred assets as of September 30, 2010.

As of September 30, 2010, we had no unrecognized tax benefits. There were no significant changes to the calculation since December 31, 2009. 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, 2011.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 7—Stockholders’ Equity

Restricted Stock

During the three months ended September 30, 2010, 5,798 restricted shares, which had a weighted average grant date value of $31.38 per share, vested. During the nine months ended September 30, 2010, 114,342 restricted shares, which had a weighted average grant date value of $21.31 per share, vested.

Share Lending Agreement

In connection with the offering of our 2026 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 Poor’s (“S&P”). On March 20, 2008, BSC had returned 1,497,963 shares of the 3,122,263 originally borrowed shares. The 1,497,963 shares returned to us were recorded as treasury stock and retired in March 2008. In May 2008, JP Morgan Chase & Co. completed its acquisition of and assumed all counterparty liabilities of The Bear Stearns Companies, Inc.

The 1,624,300 shares of common stock outstanding as of September 30, 2010 under the Share Lending Agreement have a fair value of $23.7 million based upon a closing price on September 30, 2010 of $14.57 per share and 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.

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. Approximately 77,333 options per trading day expired over each of three separate 25 consecutive trading day settlement periods. During 2009, two-thirds of the options expired. The remaining one-third of the options subject to the capped call expired unexercised in the second quarter of 2010. For more information on these transactions, please see our Annual Report on Form 10-K for the year ended December 31, 2009.

NOTE 8—Derivative Activities

We use commodity and financial derivative contracts to manage fluctuations in commodity prices and interest rates. We did not designate our derivative contracts for hedge accounting. All gains and losses both realized and unrealized from our derivative contracts have been recognized in other income (expense) on our Consolidated Statements of Operations.

The total financial impact of our derivative activities on our Consolidated Statement of Operations for the three months and nine months ended September 30, 2010 was a gain of $22.5 million and $57.5 million, respectively. The gain of $22.5 million for the three months ended September 30, 2010, included $6.3 million in realized gain and an unrealized gain of $16.2 million. The $57.5 million gain for the nine months ended September 30, 2010 consisted of $14.5 million realized gain and $43.0 million unrealized gain.

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 derivatives are in effect. In the three and nine months ended

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

September 30, 2010, approximately 55% of our total production volumes were hedged. As of September 30, 2010, the commodity derivatives we used were in the form of:

(a)

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

(b)

basis swaps, where we receive an index price less a fixed amount and pay a floating price, based on NYMEX or specific transfer point quoted prices.

As of September 30, 2010, our open forward positions on our outstanding commodity derivative contracts, all of which were with BNP Paribas, J.P. Morgan or Bank of Montreal, were as follows:


Collars (NYMEX)	Daily Volume		Total Volume		Average Floor/Cap		Fair Value at September 30, 2010 (in thousands)
Natural gas (MMBtu)							$	48,016
4Q 2010		50,000		4,600,000	$	6.00 – $7.10
1Q 2011		40,000		3,600,000	$	6.00 – $7.09
2Q 2011		40,000		3,640,000	$	6.00 – $7.09
3Q 2011		40,000		3,680,000	$	6.00 – $7.09
4Q 2011		40,000		3,680,000	$	6.00 – $7.09
1Q 2012		40,000		3,640,000	$	6.00 – $7.09
2Q 2012		40,000		3,640,000	$	6.00 – $7.09
3Q 2012		40,000		3,680,000	$	6.00 – $7.09
4Q 2012		40,000		3,680,000	$	6.00 – $7.09

Basis Swaps (NYMEX/TexOk)					Average Price (1)
Natural gas (MMBtu)							$	(983	)
4Q 2010		50,000		4,600,000	$	0.368

						Total	$	47,033

(1)	Basis swap whereby we receive NYMEX index less a contract price per MMBtu and pay Natural Gas Pipeline of America, TexOk zone price per MMBtu as published in the Inside FERC.

The fair value of the natural gas derivative contracts in place at September 30, 2010, that are marked to market resulted in a current asset of $27.4 million, a non-current asset of $20.1 million and a current liability of $0.4 million. We measure the fair value of our commodity derivatives contracts by applying the income approach, and these contracts are classified within Level 2 of the valuation hierarchy. See Note 9 Fair Value.

The following table summarizes the realized and unrealized gains and losses we recognized on our natural gas derivatives for the three and nine month periods ended September 30, 2010 and 2009.


	Three Months Ended September 30.					Nine Months Ended September 30.
Natural Gas Derivatives (in thousands):	2010		2009			2010		2009
Realized gain on natural gas derivatives	$	6,329	$	27,569		$	15,658	$	75,893
Unrealized gain (loss) on natural gas derivatives		16,165		(28,879	)		41,907		(37,250	)

Total gain (loss) on natural gas derivatives	$	22,494	$	(1,310	)	$	57,565	$	38,643

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Interest Rate Swap

We have no interest rate derivative position as of September 30, 2010. All contracts matured in April 2010.

For the nine months ended September 30, 2010, we recognized a loss of less than $0.1 million, including a realized loss of $1.1 million offset by an unrealized gain of $1.1 million.

NOTE 9—Fair Value

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

We use various methods, including the income approach and market approach, to determine the fair values of our financial instruments that are measured at fair value on a recurring basis, which depend on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. For some of our instruments, the fair value is calculated based on directly observable market data or data available for similar instruments in similar markets. For other instruments, the fair value may be calculated based on these inputs as well as other assumptions related to estimates of future settlements of these instruments. We separate our financial instruments into three levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine the fair value of our instruments. Our assessment of an instrument can change over time based on the maturity or liquidity of the instrument, which could result in a change in the classification of the instruments between levels.

Each of these levels and our corresponding instruments classified by level are further described below:

•

Level 1 Inputs—unadjusted quoted market prices in active markets for identical assets or liabilities.

•

Level 2 Inputs—quotes which are derived principally from or corroborated by observable market data. Included in this level are our long-term debt and our interest rate swaps and commodity derivatives whose fair values are based on third-party quotes or available interest rate information and commodity pricing data obtained from third party pricing sources and our creditworthiness or that of our counterparties.

•

Level 3 Inputs—unobservable inputs for the asset or liability, such as discounted cash flow models or valuations, based on the Company’s various assumptions and future commodity prices. Included in this level are our oil and gas properties which are deemed impaired.

As of September 30, 2010, the carrying amounts of our cash and cash equivalents, trade receivables and payables represented fair value because of the short-term nature of these instruments.

We periodically assess our long-lived assets recorded in oil and gas properties on the Consolidated Balance Sheets to ensure that they are not carried in excess of fair value, which is computed using level 3 inputs such as discounted cash flow models or valuations, based on estimated future commodity prices and our various operational assumptions.

We made an assessment of the fair value of our oil and gas properties as of September 30, 2010 as a result of the continued decline of projected future natural gas prices. The assessment indicated that several of our fields were being carried on our Consolidated Balance Sheet in excess of fair value, consequently, we recorded an impairment of $223.3 million for the three and nine months ended September 30, 2010. The expected future cash flows used for our impairment review and related fair-value calculation was based on judgmental assessments of future production volumes, prices, and costs, considering all available information at the date of review. Due to the uncertainty inherent in these factors, we cannot predict when or if additional future impairment charges will be recorded. We estimated future net cash flows generated from our oil and gas properties by using forecasted oil and gas prices.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

The following table summarizes the fair values of our derivative financial instruments that are recorded at fair value in our Consolidated Balance Sheet by applying the income approach and are classified in level 2 as of September 30, 2010 (in thousands):


	September 30, 2010 Fair Value Measurements
Description	Level 1		Level 2			Level 3		Total
Current Assets
Commodity Derivatives	$	—	$	27,352		$	—	$	27,352
Non-current Assets
Commodity Derivatives		—		20,069			—		20,069
Current Liabilities
Commodity Derivatives		—		(388	)		—		(388	)

Total	$	—	$	47,033		$	—	$	47,033

The following table reflects the carrying value, as recorded in our Consolidated Balance Sheet, and fair value of our long-term debt financial instruments which we classified as level 2 at September 30, 2010 (in thousands):


	September 30, 2010				December 31, 2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
3.25% Convertible Senior Notes due 2026	$	165,086	$	172,340	$	159,085	$	161,438
5.0% Convertible Senior Notes due 2029		176,977		199,425		171,062		226,694

Total long-term debt	$	342,063	$	371,765	$	330,147	$	388,132

The fair value amounts of our debt are based on quoted market prices for the same or similar type issues, including consideration of our credit risk related to those instruments and other relevant information generated by market transactions and derived from the market.

NOTE 10—Commitments and Contingencies

Hoover Tree Farm, LLC v. Goodrich Petroleum Company, LLC et al. On April 29, 2010 a state court in Caddo Parish, Louisiana, granted a judgment holding the Company solely responsible for the payment of $8.5 million in additional oil and gas lease bonus payments and related interest in an ongoing lawsuit involving the interpretation of a unique oil and gas lease provision. The lease provided for the payment of additional bonuses under certain circumstances in the event higher lease bonuses were paid by the Company, its successors or assigns, within the surrounding area. Without the Company’s knowledge, one of the sub-lessees subject to the same lease paid substantially higher bonuses in the area. The Company believes that this ruling was improperly decided and, on July 8, 2010, filed a motion for suspensive appeal. The Company satisfied the requirements for posting a suspensive appeal bond by depositing $8.5 million in July 2010 with Iberia Bank in Shreveport, Louisiana for the account of the Clerk of Caddo Parish Court.

On July 9, 2010, the sub-lessee agreed to reimburse the Company for one half of any sums for which the Company may be cast in judgment in this lawsuit in any final non-appealable judgment, and further agreed to reimburse the Company for one half of the cash bond. The Company has accrued one half of the judgment amount, $4.2 million, as of September 30, 2010 which is reflected as “Operating Expenses—Other” in the Consolidated Statement of Operations.

In addition, we are party to other 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 or results of operations or liquidity. No significant changes in any of these lawsuits have occurred since December 31, 2009.

NOTE 11—Related Party Transactions

On May 25, 2010, we entered into a participation agreement with Turnham Interests, Inc., a private company owned by Robert C. Turnham, Jr. (the “Turnham Participation Agreement”) on terms substantially identical to recent transactions, as described below. Mr. Turnham is our President and Chief Operating Officer and is a Director on the Board of Directors. Pursuant to the Turnham Participation Agreement, we purchased from Turnham Interests, Inc., at a cash price of $1,250 per

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

net acre, a 95% working interest in approximately 813 net acres in the Eagle Ford Shale oil play in Frio County, Texas. In addition, we agreed to pay for and carry the costs associated with the drilling and completion of an initial well on the acreage, to the extent such costs are attributable to the 5% working interest in such acreage retained by Turnham Interests, Inc. The total cash consideration received by Turnham Interests, Inc. was approximately $1 million. The term of the Turnham Participation Agreement is three years, or for so long as there is commercial production from the acreage.

The terms of the Turnham Participation Agreement are substantially identical to the terms of a previously announced participation agreement entered into between us and an unrelated third party, concerning approximately 6,000 net acres in the direct vicinity of the acreage covered by the Turnham Participation Agreement. Turnham Interests, Inc. had owned the leasehold interest subject to the Turnham Participation Agreement since 1999.

NOTE 12—Acquisitions and Divestitures

In April 2010, we acquired a leasehold interest within the oil window of the Eagle Ford Shale play in La Salle and Frio Counties, Texas. We paid $10.0 million in upfront cash and have the option to drill to earn the full interest through $44.0 million in carried drilling costs. We have invested a total of $22 million in leasehold acreage at September 30, 2010 in the Eagle Ford Shale play.

On October 27, 2010, we signed an agreement with a private company to sell certain non-core shallow properties in East Texas and North Louisiana for approximately $70 million, subject to normal closing adjustments. We expect the sale to close before year-end.

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

Forward-Looking Statements

The Company has made in this report, and may from time to time otherwise make in other public filings, press releases and discussions with Company management, 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 concerning the Company’s operations, economic performance and financial condition. These forward-looking statements include information concerning future production and reserves, schedules, plans, timing of development, contributions from oil and gas properties, marketing and midstream activities, and also include those statements preceded by, followed by or that otherwise include the words “may,” “could,” “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should,” or similar expressions or variations on such expressions. For such statements, the Company claims the protection of the safe harbor for forward-looking statements contained in the Private Securities Litigation Reform Act of 1995. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct. The Company undertakes no obligation to publicly update or revise any forward-looking statements whether as a result of new information, future events or otherwise.

These forward-looking statements involve risk and uncertainties. Important factors that could cause actual results to differ materially from the Company’s expectations include, but are not limited to, the following risk and uncertainties:

•

planned capital expenditures;

•

future drilling activity;

•

our financial condition;

•

business strategy;

•

the market prices of oil and gas;

•

uncertainties about the estimated quantities of oil and natural gas reserves;

•

financial market conditions and availability of capital;

•

production;

•

hedging arrangements;

•

future cash flows and borrowings;

•

litigation matters;

•

pursuit of potential future acquisition opportunities;

•

sources of funding for exploration and development;

•

general economic conditions, either nationally or in the jurisdictions in which the Company or its subsidiary are doing business;

•

legislative or regulatory changes, including retroactive royalty or production tax regimes, hydraulic-fracturing regulation, drilling and permitting regulations, derivatives reform, changes in state and federal corporate taxes, environmental regulation, environmental risks and liability under federal, state and foreign and local environmental laws and regulations;

•

the creditworthiness of the Company’s financial counterparties and operation partners;

•

the securities, capital or credit markets;

•

the Company’s ability to repay its debt; and

•

other factors discussed below and elsewhere in “Risk Factors” and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Summary of Critical Accounting Policies” included in the Company’s 2009 Annual Report on Form 10-K, the Company’s Quarterly Reports on Form 10-Q for the quarters ended March 31 and June 30, 2010 and in the Company’s other public filings, press releases and discussions with Company management.

Overview

General

We are an independent oil and gas company engaged in the exploration, development and production of oil and natural gas properties primarily in East Texas and North Louisiana, which includes the Haynesville Shale play, and South Texas, which includes the Eagle Ford Shale. We operate as one segment as each of our operating areas have similar economic

characteristics and each meet the criteria for aggregation as defined by accounting standards related to disclosures about segments of an enterprise and related information.

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

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

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

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

Haynesville Shale

We hold approximately 87,000 net acres that are prospective for the Haynesville Shale and have drilled or participated in the drilling of 87 wells that penetrated the Haynesville Shale as of September 30, 2010. Our net production volumes from our Haynesville Shale wells averaged 48,098 Mcfe per day in the third quarter of 2010 representing approximately 53% of our current production.

2010 Haynesville Shale Developments

Company Operated Haynesville Shale Drilling Program

We conducted drilling operations on four operated Haynesville Shale horizontal wells during the third quarter of 2010. For the three months ended September 30, 2010, net production from our operated Haynesville Shale wells (horizontal and vertical) averaged approximately 32,182 Mcfe per day, or 35% of our total production. We currently anticipate drilling three to five additional operated Haynesville Shale horizontal wells in the fourth quarter of 2010.

Chesapeake Haynesville Shale Joint Development

Through our joint development arrangement with Chesapeake Energy Corporation (“Chesapeake”), which covers certain portions of our acreage in North Louisiana, we had participated in drilling operations of 42 wells with 27 wells on line and producing through September 30, 2010. For the remainder of 2010, we and Chesapeake plan to utilize two rigs to conduct drilling operations on approximately four to six additional Haynesville Shale horizontal wells to be operated by Chesapeake. For the third quarter of 2010, net production from the joint development averaged 14,849 Mcfe per day or 16% of our total production.

Eagle Ford Shale

We began acquiring leasehold interest in the oil play of Eagle Ford Shale (“EFS”) in April 2010. The EFS is located in South Texas and our leasehold interest is located in La Salle and Frio counties. As of September 30, 2010, we had invested a total of $22 million in obtaining rights to and acquiring approximately 67,000 gross (38,000 net) lease acres in the EFS oil play. We are obligated to drill three wells to earn a portion of the acreage position.

On the majority of our EFS acreage, in addition to the EFS formation, we also have the drilling rights to the oil-bearing Buda Lime geological formation, which sits deeper than the EFS formation. As of September 30, 2010, we had conducted drilling operations on two EFS and two Buda Lime wells. One of each is on production and the others are being completed as of September 30, 2010. We plan on drilling two more EFS wells and one or two more Buda Lime wells in the fourth quarter of 2010.

Other

Company Operated Cotton Valley Taylor Sand Program

During 2009, we commenced a horizontal drilling program targeting the Cotton Valley Taylor Sand (“CVTS”). By the end of the third quarter of 2010, we had drilled and completed six horizontal CVTS wells in East Texas. For the third quarter of 2010, net production from these operated wells was approximately 5,632 Mcfe per day or 6% of our total production. We reached total depth on our seventh well and are currently drilling our eighth CVTS well. We plan to complete both wells during the fourth quarter of 2010 and the first quarter of 2011.

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, 2009.

Overview of Third Quarter 2010 Results

Third Quarter 2010 financial and operating results include:

•

We increased our oil and gas production volumes to 91,665 Mcfe per day, representing an increase of 11% from 82,496 Mcfe per day for the third quarter of 2009.

•

We conducted drilling operations on 21 gross wells in the third quarter of 2010, 18 in the Haynesville Shale and three in South Texas. We added 10 gross (6 net) wells to production in the third quarter of 2010. As of September 30, 2010, we had 20 gross (10 net) wells drilled but awaiting completion.

•

We increased our net ownership in the Haynesville Shale play in Northwest Louisiana and East Texas to approximately 87,000 net acres and owned approximately 38,000 net acres in the Eagle Ford Shale in South Texas at September 30, 2010.

•

We are producing from two wells drilled on our Eagle Ford Shale acreage.

•

We reduced our lease operating expense per Mcfe by 24% from the third quarter of 2009 to $0.74 per Mcfe in the third quarter of 2010.

•

We recorded an impairment expense of $223.3 million on our non-core properties.

Results of Operations

For the three months ended September 30, 2010, we reported a net loss applicable to common stock of $215.1 million, or $5.98 per basic and diluted share, on total revenue of $37.4 million as compared to a net loss applicable to common stock of $31.0 million, or $0.87 per basic and diluted share, on total revenue of $23.5 million for the three months ended September 30, 2009. As a result of a decreasing projected natural gas price environment, we recorded impairment expense of $223.3 million in the current period. The rise in our average realized oil and gas prices period to period contributed $10.1 million and the increase in production contributed $3.8 million to the $13.9 million increase in oil and gas revenues as compared to the three months ended September 30, 2009. We recorded a $22.5 million gain on derivatives not designated as hedges in the three months ended September 30, 2010 compared to a $1.5 million loss on derivatives not designated as hedges for the three months ended September 30, 2009. The increase in the derivative gain between periods is due to the decrease in futures gas prices. We increased our tax valuation allowance in the three months ended September 30, 2010, resulting in our recording no income tax benefit for the period compared to a tax benefit of $16.4 million in the three months ended September 30, 2009.

For the nine months ended September 30, 2010, we reported a net loss applicable to common stock of $235.4 million, or $6.56 per basic and diluted share, on total revenue of $112.0 million as compared to a net loss applicable to common stock of $65.9 million, or $1.84 per basic and diluted share, on total revenue of $78.2 million for the nine months ended September 30, 2009. As a result of a decreasing projected natural gas price environment, we recorded impairment expense of $223.3 million in the current period compared to $23.5 million for the nine months ended September 30, 2009. The rise in our average realized oil and gas prices period to period increased oil and gas revenues by approximately $20.6 million and the production increase contributed approximately $13.1 million to the increase of $33.7 million in oil and gas revenues. Due to favorable terms on our hedges verses market prices, we recorded a $57.5 million gain on derivatives not designated as hedges in the nine months ended September 30, 2010 compared to a $38.0 million gain on derivatives not designated as hedges for the nine months ended September 30, 2009. We continue to maintain a full valuation allowance for our net deferred tax asset as of September 30, 2010, consequently; we did not record any income tax benefit in the nine months ended September 30, 2010 compared to an income tax benefit of $36.5 million for the nine months ended September 30, 2009.

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.

Summary Operating Information:


(In thousands, except for price data)	Three Months Ended September 30,											Nine Months Ended September 30,
(In thousands, except for price data)	2010			2009			Variance					2010			2009			Variance
Revenues:
Natural gas	$	35,060		$	21,377		$	13,683		64	%	$	104,751		$	72,354		$	32,397		45	%
Oil and condensate		2,383			2,190			193		9	%		7,169			5,887			1,282		22	%
Natural gas, oil and condensate		37,443			23,567			13,876		59	%		111,920			78,241			33,679		43	%
Operating revenues		37,424			23,525			13,899		59	%		112,041			78,249			33,792		43	%
Operating expenses		264,323			61,265			203,058		331	%		373,048			197,482			175,566		89	%
Operating loss		(226,899	)		(37,740	)		(189,159	)	(501	%)		(261,007	)		(119,233	)		(141,774	)	(119	%)
Natural gas (MMcf)		8,235			7,386			849		11	%		24,202			21,153			3,049		14	%
Oil and condensate (MBbls)		33			34			(1	)	(3	%)		97			120			(23	)	(19	%)
Total (Mmcfe)		8,433			7,590			843		11	%		24,785			21,876			2,909		13	%
Average daily production (Mcfe/d)		91,665			82,496			9,169		11	%		90,786			80,132			10,654		13	%
Average realized sales price per unit:
Natural gas (per Mcf)	$	4.26		$	2.89		$	1.37		47	%	$	4.33		$	3.42		$	0.91		27	%
Oil and condensate (per Bbl)		72.30			64.43			7.87		12	%		73.85			48.87			24.98		51	%
Total (per Mcfe)		4.44			3.11			1.33		43	%		4.52			3.58			0.94		26	%

Revenues from operations increased for the three months ended September 30, 2010 compared to the same period in 2009 resulting from a 43% increase in realized sales prices and a production increase of 11%. Revenues from operations increased for the nine months ended September 30, 2010 compared to the same period in 2009 as realized sales prices increased 26% and production increased 13%. The production increase in the three-and-nine month periods ended September 30, 2010 over the same periods in 2009 are due to the increase in the production volumes obtained from our Haynesville Shale wells. In 2010, 60 Haynesville wells were producing compared to 31 Haynesville wells in 2009.

For the three months ended September 30, 2010, our average realized price was $5.03 per Mcf including the effect of the realized gains and losses on our natural gas derivatives. For the same period, our average realized price was $4.26 per Mcf, excluding the effect of the realized gains and losses on our natural gas derivatives. For the three months ended September 30, 2009, our average realized price was $6.63 per Mcf including the effect of the realized gains and losses on our natural gas derivatives. For the same period, our average realized price was $2.89 per Mcf, excluding the effect of the realized gains and losses on our natural gas derivatives.

For the nine months ended September 30, 2010, our average realized price was $4.98 per Mcf including the effect of the realized gains and losses on our natural gas derivatives. For the same period, our average realized price was $4.33 per Mcf, excluding the effect of the realized gains and losses on our natural gas derivatives. For the nine months ended September 30, 2009, our average realized price was $7.01 per Mcf including the effect of the realized gains and losses on our natural gas derivatives. For the same period, our average realized price was $3.42 per Mcf, excluding the effect of the realized gains and losses on our natural gas derivatives.

The difference between our realized prices inclusive of the hedge realizations in the 2010 and 2009 periods relates to the floor price on our collars. In 2010, we had 50,000 MMBtu per day hedged at a floor price of $6.00 per MMBtu and in 2009, we had 60,000 MMBtu per day hedged at an average floor price of $8.48 per MMbtu.

Operating Expenses

The following tables present our comparative operating expenses:


	Three Months Ended September 30,									Nine Months Ended September 30,
Operating Expenses (in thousands)	2010		2009		Variance					2010		2009		Variance
Lease operating expenses	$	6,280	$	7,363	$	(1,083	)	(15	%)	$	19,841	$	23,343	$	(3,502	)	(15	%)
Production and other taxes		664		1,294		(630	)	(49	%)		2,017		3,831		(1,814	)	(47	%)
Transportation		2,977		2,300		677		29	%		7,619		7,479		140		2	%
Exploration		2,033		1,625		408		25	%		7,639		6,804		835		12	%

	Three Months Ended September 30,									Nine Months Ended September 30,
Operating Expenses per Mcfe	2010		2009		Variance					2010		2009		Variance
Lease operating expenses	$	0.74	$	0.97	$	(0.23	)	(24	%)	$	0.80	$	1.07		(0.27	)	(25	%)
Production and other taxes		0.08		0.17		(0.09	)	(53	%)		0.08		0.18		(0.10	)	(56	%)
Transportation		0.35		0.30		0.05		17	%		0.31		0.34		(0.03	)	(9	%)
Exploration		0.24		0.21		0.03		14	%		0.31		0.31		—		0	%

Lease Operating. Lease operating expense (“LOE”) for the three months ended September 30, 2010 decreased in comparison to the same period in 2009 as a result of lower saltwater disposal and compression costs and a greater percentage of our production volumes coming from Haynesville Shale wells which carry a lower LOE per unit of production. We realized a $0.2 million savings from the continuing impact of the saltwater disposal systems installed in the second quarter of 2009. Compression costs decreased $0.5 million as we negotiated more favorable terms on certain rental contracts. On a per unit basis, LOE decreased for the three months ended September 30, 2010 compared to the same period in 2009 as a result of cost reductions, an 11% increase in production volumes and an increasing portion of our production coming from the lower production cost Haynesville Shale wells.

LOE for the nine months ended September 30, 2010 decreased as compared to the nine months ended September 30, 2009 as a result of lower saltwater disposal cost as we realized $2.0 million in savings due to the continuing impact of the saltwater disposal systems installed in the second quarter of 2009. We also realized $1.5 million in compression cost savings as a result of more favorable rental contract rates. Increased workover costs of $0.7 million were generally offset by overall reductions in other lease operating categories. On a per unit basis, LOE per Mcfe decreased for the nine months ended September 30, 2010 compared to the same period in 2009 as a result of lower costs, the 13% increase in production volumes and an increasing portion of our production coming from the Haynesville Shale which carries lower production costs.

Production and Other Taxes. Production and other taxes for the three months ended September 30, 2010 includes ad valorem tax of $0.9 million and a $0.2 million production tax credit. The production tax represents $0.4 million current period expense reduced by $0.6 million in Texas high cost severance tax credits and Louisiana horizontal well severance tax exemptions. During the comparable period in 2009, production and other taxes included ad valorem tax of $0.8 million and production tax of $0.5 million. Production tax in the three months ended September 30, 2009 included $0.3 million in Tight Gas Sands (“TGS”) tax credits.

Production and other taxes for the nine months ended September 30, 2010 includes ad valorem tax of $1.8 million and production tax of $0.2 million. Production tax included $2.0 million of new TGS severance tax credits for our wells in the State of Texas and for our horizontal wells in Louisiana. During the comparable period in 2009, production and other taxes included ad valorem tax of $2.3 million and production tax of $1.5 million. Production tax in the nine months ended September 30, 2009 included $1.2 million in TGS credits.

TGS credits allow for reduced and/or the complete elimination of severance taxes in the state of Texas for qualifying wells for up to ten years of production. We accrue for such credits once we have been notified of the State’s approval. We anticipate that we will incur a gradually lower production tax rate in the future as we add additional Texas wells to our production base and as reduced rates are approved.

Our Louisiana horizontal wells are eligible for a two year severance tax exemption from the date of first production or until payout of qualified costs, whichever comes first.

Transportation. Transportation expense in the three months ended September 30, 2010 increased as compared to the three months ended September 30, 2009 due to a contractual annual volume deficiency charge related to non-core properties. Transportation expense for the nine months ended September 30, 2010 was slightly higher than the nine months ended September 30, 2009 due to the contractual deficiency charge related to non-core properties offset by a larger portion of sales coming from non-operated properties from which the operator nets the transportation cost from revenues.

Exploration. Exploration expense for the three months ended September 30, 2010 includes exploratory seismic costs for our 3-D seismic program in the Angelina River area of $0.2 million and additional cost amortization on our undeveloped leasehold acreage position.

Exploration expense for the nine months ended September 30, 2010 includes $1.2 million in seismic costs including exploratory seismic costs for our Angelina River area 3-D seismic program, slightly higher undeveloped leasehold cost amortization offset by a decrease in exploration labor cost as compared to the same 2009 period. The nine months ended September 30, 2009 included $1.1 million in early termination fees for two drilling rig contracts.


	Three Months Ended September 30,											Nine Months Ended September 30,
Operating Expenses (in thousands)	2010			2009			Variance					2010		2009			Variance
Depreciation, depletion and amortization		26,022			42,063			(16,041	)	(38	%)		84,638		112,258			(27,620	)	(25	%)
Impairment		223,304			—			223,304		100	%		223,304		23,490			199,814		851	%
General and administrative		7,275			6,802			473		7	%		23,722		20,572			3,150		15	%
Gain on sale of assets		—			(182	)		182		100	%		—		(295	)		295		100	%
Other		(4,232	)		—			(4,232	)	(100	%)		4,268		—			4,268		100	%

	Three Months Ended September 30,											Nine Months Ended September 30,
Operating Expenses per Mcfe	2010			2009			Variance					2010		2009			Variance
Depreciation, depletion and amortization		3.09			5.54			(2.45	)	(44	%)		3.41		5.13			(1.72	)	(34	%)
Impairment		26.48			—			26.48		100	%		9.01		1.07			7.94		742	%
General and administrative		0.86			0.90			(0.04	)	(4	%)		0.96		0.94			0.02		2	%
Gain on sale of assets		—			(0.02	)		0.02		100	%		—		(0.01	)		0.01		100	%
Other		(0.50	)		—			(0.50	)	(100	%)		0.17		—			0.17		100	%

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) for the three and nine months ended September 30, 2010 decreased as compared to the comparable periods in 2009 as a result of a lower DD&A rate. We calculated the first six months of 2010 and 2009 DD&A rates using the December 31, 2009 and December 31, 2008 fully engineered reserves, respectively. Proved developed reserves increased 9% from 152.5 Bcfe at December 31, 2008 to 165.5 Bcfe at December 31, 2009. We calculated third quarter 2010 and 2009 DD&A rates using the June 30, 2010 and June 30, 2009 mid-year reserves, respectively. Proved developed reserves increased 43% from 143.6 Bcfe at June 30, 2009 to 205.8 Bcfe at June 30, 2010.

The impairment recorded in the fourth quarter of 2009 and the addition of Haynesville Shale proved reserves, which carry more attractive finding and development costs per unit of proved reserves decreased the DD&A rate. The 2009 impairment was the result of the write down of our legacy vertical Cotton Valley and Travis Peak proved reserves which reduced the book value of the oil and gas properties to be depleted.

Impairment. We recorded impairment expense of $223.3 million on several fields in the three and nine months ended September 30, 2010, related mostly to a decreasing projected natural gas price environment resulting in the write down of the carrying values of certain non-core assets. In addition to lower commodity prices, the impairment was a result of our change in forward looking development plans, which will focus on the Eagle Ford Shale, core Haynesville Shale in North Louisiana and the Angelina River Trend of the Shelby Trough. Comparably, we had no impairment in the three months ended September 30, 2009 and recorded impairment of $23.5 million in the nine months ended September 30, 2009.

General and Administrative. General and administrative (“G&A”) expense increased slightly in the three months ended September 30, 2010 compared to the same period in 2009. The increase relates to generally higher labor costs including increases in employee benefit plan cost in the current period over the prior year period. G&A on a per unit basis decreased as a result of an 11% increase in our production volumes in the third quarter of 2010 as compared to the third quarter of 2009. Stock based compensation expense, which is a non-cash item, amounted to $1.5 million in both the third quarters of 2010 and 2009.

G&A expense increased in the nine months ended September 30, 2010 compared to the same period in 2009. The nine months ended September 30, 2010 included $0.9 million of compensation costs related to the resignation of an officer of the company. See Note 2 “Resignation of Executive Officer” to our consolidated financial statements in this report for more information. G&A expense for the nine months ended September 30, 2010 also includes $0.9 million for 2009 bonuses paid out in March 2010. The remaining increase is related to generally higher compensation

cost and stock based compensation. Stock based compensation expense, a non-cash item, amounted to $5.5 million for the nine months ended September 30, 2010 compared to $4.7 million for the same period in 2009. G&A on a per unit basis increased compared to same period in 2009 due to a $3.1 million overall increase partially offset by a 13% increase in production volumes in the nine months ended September 30, 2010 as compared to the first nine months of 2009.

Other. Hoover Tree Farm, LLC v. Goodrich Petroleum Company, LLC et al. On April 29, 2010 a state court in Caddo Parish, Louisiana, granted a judgment holding us solely responsible for the payment of $8.5 million in additional oil and gas lease bonus payments and related interest in an ongoing lawsuit involving the interpretation of a unique oil and gas lease provision. The lease provided for the payment of additional bonuses under certain circumstances in the event higher lease bonuses were paid by us, or our successors or assigns, within the surrounding area. Without our knowledge, one of the sub-lessees subject to the same lease paid substantially higher bonuses in the area. We believe that this ruling was improperly decided and, on July 8, 2010, filed a motion for suspensive appeal. We satisfied the requirements for posting a suspensive appeal bond by depositing $8.5 million with Iberia Bank in Shreveport, Louisiana for the account of the Clerk of Caddo Parish Court. We accrued the full amount of $8.5 million as expense in the first quarter of 2010.

On July 9, 2010, the sub-lessee agreed to reimburse us for one half of any sums for which we may be cast in judgment in this lawsuit in any final non-appealable judgment, and further agreed to reimburse us for one half of the cash bond. We reduced our accrual by $4.2 million in the third quarter of 2010 and the remaining $4.3 million as of September 30, 2010 is reflected as “Operating Expenses—Other” in the Consolidated Statement of Operations.

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,
	2010			2009			2010			2009
Other income (expense):
Interest expense		(9,154	)		(6,646	)		(27,469	)		(17,152	)
Interest income and other		11			18			117			466
Gain (loss) on derivatives not designated as hedges		22,494			(1,545	)		57,543			38,017
Income tax benefit		—			16,394			—			36,545
Average funded borrowings		393,500			250,326			393,500			250,110
Average funded borrowings adjusted for debt discount		339,444			233,195			335,511			229,938
Weighted average interest rate		10.7	%		11.4	%		10.9	%		9.9	%

Interest Expense. Interest expense in the three months ended September 30, 2010 increased compared to three months ended September 30, 2009 as a result of the higher average level of outstanding debt in the three months ended September 30, 2010. Interest expense increased in the nine months ended September 30, 2010 compared to same period in 2009 as a result of the higher average level of outstanding debt in the current year. The higher average level of debt in both the three and nine month periods ended September 30, 2010 is the result of the issuance of our 5% convertible senior notes in September 2009. Non-cash interest of $4.8 million is included in the $9.2 million interest expense reported for the three months ended September 30, 2010. Non-cash interest of $14.2 million is included in the $27.5 million interest expense reported for the nine months ended September 30, 2010.

Gain on Derivatives Not Designated as Hedges. Gain on derivatives not designated as hedges for the three months ended September 30, 2010 consists of a realized gain of $6.3 million and an unrealized gain of $16.2 million for the change in fair value of our natural gas derivative contracts. The average futures strip prices were lower in the current period compared to the previous quarter resulting in an unrealized gain in the current period. As a comparison, loss on derivatives not designated as hedges for the three months ended September 30, 2009 included a realized gain of $27.6 million and an unrealized loss of $28.9 million for the changes in fair value of our natural gas derivative contracts.

Gain on derivatives not designated as hedges for the nine months ended September 30, 2010, includes a realized gain of $15.7 million and an unrealized gain of $41.9 million for the change in fair value of our natural gas derivative contracts. The unrealized gain was the result of the increase in the fair value of our derivative positions due to the decrease of natural gas futures prices from December 31, 2009. As a comparison, gain on derivatives not designated as hedges for the nine months ended September 30, 2009 includes a realized gain of $75.9 million and an unrealized loss of $37.3 million for the changes in fair value of our natural gas derivative contracts.

We will continue to be exposed to volatility in earnings resulting from changes in the fair value of our commodity contracts as we do not designate these contracts as hedges.

Income taxes. We recorded no income tax benefit for the three and nine months ended September 30, 2010. We increased our valuation allowance and reduced our net deferred tax assets to zero during 2009 after considering all available positive and negative evidence related to the realization of our deferred tax assets. Our assessment of the realization of our deferred tax assets has not changed and as a result, we continue to maintain a full valuation allowance for our net deferred asset as of September 30, 2010.

Income tax benefit for the three months ended September 30, 2009 includes a $0.6 million state income tax benefit. Income tax benefit for the nine months ended September 30, 2009 includes a state income tax benefit of $2.3 million.

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,
	2010			2009			Variance
Cash flow statement information:
Net cash:
Provided by operating activities	$	76,962		$	80,269		$	(3,307	)
Used in investing activities		(184,078	)		(226,206	)		42,128
Provided by (used in) financing activities		(5,435	)		129,926			(135,361	)

Decrease in cash and cash equivalents	$	(112,551	)	$	(16,011	)	$	(96,540	)

Operating activities. Net cash provided by operating activities decreased $3.3 million to $77.0 million for the nine months ended September 30, 2010, from $80.3 million for the comparable 2009 period as less cash was realized from hedging settlements offset by increased production levels during the current nine month period.

Investing activities. Net cash used in investing activities was $184.1 million for the nine months ended September 30, 2010, compared to $226.2 million for the nine months ended September 30, 2009. We conducted drilling operations on 40 gross wells, 35 of which penetrated the Haynesville Shale during the first nine months of 2010. In comparison, we conducted drilling operations on 39 gross wells, 26 of which penetrated the Haynesville Shale during the first nine months of 2009. The reduction in the investing amount between the nine month periods reflects primarily the timing of payments in 2009 and the reduced drilling and completion cost expended offset by increased leasehold acquisition in 2010.

Financing activities. Net cash used in financing activities was $5.4 million for the nine months ended September 30, 2010, compared to cash provided by financing activities of $129.9 million for the same period in 2009. During the nine months ended September 30, 2010 we used cash on hand and cash flow to fund our operations. The cash used in financing activities for the current period consisted mainly of the payment of $4.5 million in preferred stock dividends. Cash provided by financing activities in the nine months ended September 30, 2009 consisted mainly of the receipt of net proceeds of $212.5 million from the sale of our 5% convertible senior notes due 2029 offset by the repayment of our $75 million second lien term loan in September 2009.

Senior Credit Facility

On May 5, 2009, we entered into a Second Amended and Restated Credit Agreement (“Senior Credit Facility”) that replaced our previous facility. Total lender commitments under the Senior Credit Facility are $350 million. The Senior Credit Facility matures on August 31, 2011. The Senior Credit Facility can be further extended to July 1, 2012 upon receipt of proceeds from a refinancing sufficient to prepay the 3.25% convertible senior notes due 2026. Revolving borrowings under the Senior Credit Facility are limited to, and subject to periodic redeterminations of the borrowing base. The initial borrowing base was established at $175 million. The borrowing base interest on revolving borrowings under the Senior Credit Facility accrues at a rate calculated, at our option, at the bank base rate plus 0.75% to 1.50% or LIBOR plus 2.25% to 3.00%, depending on borrowing base utilization. Pursuant to the terms of the Senior Credit Facility, borrowing base redeterminations are made on a semi-annual basis on April 1 and October 1. In connection with the offering of our $218.5 million 5% convertible senior notes due 2029, we entered into an amendment of our Senior Credit Facility to permit the issuance of the notes and required payments made on the notes thereafter and to exclude up to $175 million of our 3.25% convertible senior notes due 2026 or our 5% convertible senior notes due 2029 from the definition of Total Debt used in our financial covenants under the Senior Credit Facility. On October 27, 2010, the borrowing base was increased to $250 million. The borrowing base will be reduced to $225 million upon closing on the sale of our non-core assets. As of September 30, 2010, we currently have no amounts outstanding under the Senior Credit Facility. Effective September 1, 2010, any borrowed funds

outstanding under the Senior Credit Facility will be classified as a current liability as long as the 3.25% senior convertible notes due 2026 are outstanding.

Substantially all of our assets are pledged as collateral to secure the Senior Credit Facility.

•

Adjusted Current Ratio of 1.0/1.0;

•

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

•

We were in compliance with all the financial covenants of the Senior Credit Facility as of September 30, 2010.

3.25% Convertible Senior Notes Due 2026

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

We separately account for the liability and equity components of the 2026 Notes in a manner that reflects our nonconvertible debt borrowing rate when interest is recognized in subsequent periods. As of September 30, 2010, the 2026 Notes were carried on the balance sheet at $165.1 million with a debt discount balance of $9.9 million. As of December 31, 2009, the 2026 Notes were carried on the balance sheet at $159.1 million with a debt discount of $15.9 million. The remaining amount of debt discount as of September 30, 2010 will be amortized using the effective interest rate method based upon an original five year term through December 1, 2011.

5% Convertible Senior Notes due 2029

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 Bear Stearns and Company (“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. Approximately 77,333 options per trading day expired over each of three separate 25 consecutive trading day settlement periods. During 2009, two-thirds of the options expired. The remaining one-third of the options subject to the capped call expired unexercised in the second quarter of 2010. For more information on these transactions, please see our Annual Report on Form 10-K for the year ended December 31, 2009.

Liquidity

We have a total capital expenditures budget for 2010 of approximately $255 million. We expect to finance the remainder of our 2010 estimated capital expenditures of approximately $64 million through a combination of cash flow from operations, cash on hand and availability under our senior credit facility.

As the first put date for our 2026 Notes is December 1, 2011, we expect the $175 million to be reflected as a current liability at December 31, 2010. Our Senior Credit Facility also has a maturity date of August 31, 2011. Any amounts outstanding under our Senior Credit Facility at December 31, 2010 will be reflected as a current liability. Should we redeem the 2026 Notes, the maturity date under our Senior Credit Facility will extend to July 1, 2012.

We continuously monitor our leverage position and coordinate our capital program with our expected cash flows and repayment of our projected debt. We will continue to evaluate funding alternatives as needed.

Alternatives available to us include:

•

sale of non-core assets,

•

bring in joint venture partners in core Haynesville and/or Eagle Ford Shale acreage,

•

availability under our Senior Credit Facility,

•

issuance of debt securities.

Also in October, our bank group approved the increase of our borrowing base to $250 million. This amount will be reduced to $225 million upon the closing of the sale of non-core assets.

We also have supported our cash flows by entering into favorable derivative positions as of September 30, 2010, covering approximately 50% of our projected natural gas sales volumes for the remainder of 2010, 2011 and 2012. See Note 8-Derivative Activities in the Notes to Consolidated Financial Statements under Part 1 Item 1 of this Form 10-Q.

Accounting Pronouncements

See Note 1 “Description of Business and Significant Accounting Policies”—“New Accounting Pronouncements” to our consolidated financial statements included in Part I Item 1 of this Form 10-Q for a discussion of recently issued pronouncements.

In January 2010, the FASB issued authoritative guidance related to improving disclosures about fair value measurements. These revised disclosures are required, with certain exceptions, for interim and annual reporting periods effective January 1, 2010. For information concerning the fair value at September 30, 2010 of our derivative financial instruments and our long-term debt financial instruments, see Note 9 “Fair Value of Financial Instruments” to our consolidated financial statements in this report.

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 of 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, 2009, includes a discussion of our critical accounting policies and there have been no material changes to such 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 in the spot market are volatile due primarily to seasonality of demand and other factors beyond our control. Any decrease in 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 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 production. As of September 30, 2010, the commodity hedges we utilized were in the form of:

(a)

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

(b)

basis swaps, where we receive an index price less a fixed amount and pay a floating price, based on NYMEX or specific transfer point quoted prices.

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 2010. The fair value of the natural gas hedging contracts in place at September 30, 2010, resulted in a net asset of $47.0 million. Based on oil and gas pricing in effect at September 30, 2010, a hypothetical 10% increase in oil and gas prices would have resulted in a derivative asset of $34.6 million, while a hypothetical 10% decrease in oil and gas prices would have increased the derivative asset to $62.7 million. See Note 8 “Derivative Activities” to our consolidated financial statements in this report for additional information.

As of September 30, 2010, our open forward positions on our outstanding commodity derivative contracts, all of which were with BNP Paribas, J.P. Morgan or Bank of Montreal, were as follows:


Collars (NYMEX)	Daily Volume		Total Volume		Average Floor/ Cap		Fair Value at September 30, 2010 (in thousands)
Natural gas							$	48,016
(MMBtu)
4Q 2010		50,000		4,600,000	$	6.00 – $7.10
1Q 2011		40,000		3,600,000	$	6.00 – $7.09
2Q 2011		40,000		3,640,000	$	6.00 – $7.09
3Q 2011		40,000		3,680,000	$	6.00 – $7.09
4Q 2011		40,000		3,680,000	$	6.00 – $7.09
1Q 2012		40,000		3,640,000	$	6.00 – $7.09
2Q 2012		40,000		3,640,000	$	6.00 – $7.09
3Q 2012		40,000		3,680,000	$	6.00 – $7.09
4Q 2012		40,000		3,680,000	$	6.00 – $7.09
Basis Swaps (NYMEX/TexOk)					Average Price (1)
Natural gas (MMBtu)							$	(983	)
4Q 2010		50,000		4,600,000	$	0.368

						Total	$	47,033

(1)	Basis swap whereby we receive NYMEX index less a contract price per MMBtu and pay Natural Gas Pipeline of America, TexOk zone price per MMBtu as published in the Inside FERC.

The following table summarizes the realized and unrealized gains and losses we recognized on our natural gas derivatives for the three and nine month periods ended September 30, 2010 and 2009.


	Three Months Ended September 30.					Nine months Ended September 30.
Natural Gas Derivatives (in thousands):	2010		2009			2010		2009
Realized gain on natural gas derivatives	$	6,329	$	27,569		$	15,658	$	75,893
Unrealized gain (loss) on natural gas derivatives		16,165		(28,879	)		41,907		(37,250	)

Total gain (loss) on natural gas derivatives	$	22,494	$	(1,310	)	$	57,565	$	38,643

Interest Rate Swap

We have no interest rate derivative position as of September 30, 2010, since all our contracts matured in April, 2010.

For the nine months ended September 30, 2010, we recognized a loss of less than $0.1 million, including a realized loss of $1.1 million offset by an unrealized gain of $1.1 million.

Adoption of Comprehensive Financial Reform

The recent adoption of comprehensive financial reform legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business. See Part II, Item 1A. Risk Factors of this Form 10-Q.

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, 2010, 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

No changes in our system of internal control over financial reporting occurred during our last fiscal 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

A discussion of current legal proceedings is set forth in Part I, Item 1. Financial Statements, under “Note 10—Commitments and Contingencies” to our consolidated financial statements in this Form 10-Q.

Item 1A—Risk Factors

Except as disclosed below, there are no material changes from risk factors previously disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009.

Future results from our initial drilling operations in the Eagle Ford Shale, an emerging play in South Texas with limited drilling and production history, are subject to more uncertainties than our drilling operations in more established formations and may not meet our expectations for reserves or production or may be subject to delays.

We have recently commenced drilling operations in the Eagle Ford Shale in South Texas. Production history from horizontal wells in the Eagle Ford Shale is limited. In addition, we will be competing with more established operators in the area for drilling rigs and equipment and fracturing and pressure pumping crews. The ultimate success of our drilling and completion strategy and techniques in this formation and the time required to achieve such success is accordingly subject to more uncertainties than in areas where we have more established production and operating histories.

The recent adoption of derivatives legislation by the United States Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that participate in that market. The new legislation was signed into law by the President on July 21, 2010 and requires the Commodities Futures Trading Commission (the “CFTC”) and the Securities and Exchange Commission (the “SEC”) to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition, and our results of operations.

Item 6—Exhibits


*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.

*101.INS		XBRL Instance Document

*101.SCH		XBRL Schema Document

*101.CAL		XBRL Calculation Linkbase Document

*101.LAB		XBRL Labels Linkbase Document

*101.PRE		XBRL Presentation Linkbase Document

*	Filed herewith

**	Furnished herewith

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 thereunto duly authorized.


	GOODRICH PETROLEUM CORPORATION (Registrant)

Date: November 4, 2010	By:	/s/ WALTER G. GOODRICH
		Walter G. Goodrich Vice Chairman & Chief Executive Officer

Date: November 4, 2010	By:	/s/ JAN L. SCHOTT
		Jan L. Schott
		Senior Vice President & Chief Financial Officer

GOODRICH PETROLEUM CORPORATION LIST OF EXHIBITS TO FORM 10-Q

FOR QUARTER ENDED SEPTEMBER 30, 2010


*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.

*101.INS		XBRL Instance Document

*101.SCH		XBRL Schema Document

*101.CAL		XBRL Calculation Linkbase Document

*101.LAB		XBRL Labels Linkbase Document

*101.PRE		XBRL Presentation Linkbase Document

*	Filed herewith

**	Furnished herewith

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company