Edgar Filing: GOODRICH PETROLEUM CORP

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Form 10-Q

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, 2009

¨	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 ¨ 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, 2009 was 37,399,152.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS


		Page
PART 1	FINANCIAL INFORMATION
ITEM 1	FINANCIAL STATEMENTS	3
	Consolidated Balance Sheets as of September 30, 2009 and December 31, 2008	3
	Consolidated Statements of Operations for the three and nine months ended September 30, 2009 and 2008	4
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2009 and 2008	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	24
ITEM 4	CONTROLS AND PROCEDURES	25

PART II	OTHER INFORMATION	26
ITEM 1A	RISK FACTORS	26
ITEM 6	EXHIBITS	26

PART 1 – FINANCIAL INFORMATION

Item 1 – Financial Statements

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(In Thousands, Except Share Amounts)

(Unaudited)


	September 30, 2009			December 31, 2008
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	131,537		$	147,548
Accounts receivable, trade and other, net of allowance		5,363			7,019
Accrued oil and gas revenue		10,645			15,595
Fair value of oil and gas derivatives		18,289			55,276
Assets held for sale		13			13
Prepaid expenses and other		5,874			2,778

Total current assets		171,721			228,229


PROPERTY AND EQUIPMENT:
Oil and gas properties (successful efforts method)		1,297,468			1,107,400
Furniture, fixtures and equipment		3,671			3,171

		1,301,139			1,110,571
Less: Accumulated depletion, depreciation and amortization		(440,087	)		(304,236	)

Net property and equipment		861,052			806,335

Deferred financing cost		9,000			3,723

TOTAL ASSETS	$	1,041,773		$	1,038,287


LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	26,588		$	41,462
Accrued liabilities		21,966			52,928
Deferred tax liability		6,401			18,931
Income taxes payable		22			1,383
Fair value of interest rate derivatives		1,537			1,187
Accrued abandonment costs		2,813			2,554

Total current liabilities		59,327			118,445
LONG-TERM DEBT		326,335			226,723
Accrued abandonment costs		11,990			11,250
Deferred tax liability		8,779			15,904
Fair value of interest rate derivatives		—			617
Fair value of oil and gas derivatives		263			—

Total liabilities		406,694			372,939

Commitments and contingencies (See Note 12)
STOCKHOLDERS’ EQUITY:
Preferred stock: 10,000,000 shares authorized: Series B convertible preferred stock, $1.00 par value, issued and outstanding 2,250,000 shares		2,250			2,250
Common stock: $0.20 par value, 100,000,000 shares authorized; issued and outstanding 37,398,040 and 37,562,659 shares, respectively		7,155			7,188
Treasury stock (216 and 9,793 shares, respectively)		(5	)		(293	)
Additional paid in capital		635,494			600,125
Retained earnings (accumulated deficit)		(9,815	)		56,078

Total stockholders’ equity		635,079			665,348

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,041,773		$	1,038,287

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,
	2009			2008			2009			2008
				(as adjusted)						(as adjusted)
REVENUES:
Oil and gas revenues	$	23,567		$	60,356		$	78,241		$	171,405
Other		(42	)		20			8			497

		23,525			60,376			78,249			171,902

OPERATING EXPENSES:
Lease operating expense		7,363			8,165			23,343			22,931
Production and other taxes		1,294			2,110			3,831			5,699
Transportation		2,300			2,224			7,479			6,480
Depreciation, depletion and amortization		42,063			26,414			112,258			80,532
Exploration		1,625			2,062			6,804			5,841
Impairment of oil and gas properties		—			1,059			23,490			1,059
General and administrative		6,802			6,207			20,572			17,567
Gain on sale of assets		(182	)		(145,868	)		(295	)		(145,868	)

		61,265			(97,627	)		197,482			(5,759	)

Operating income (loss)		(37,740	)		158,003			(119,233	)		177,661


OTHER INCOME (EXPENSE):
Interest expense		(6,646	)		(5,524	)		(17,152	)		(16,971	)
Interest income		4			1,260			387			1,260
Gain (loss) on derivatives not designated as hedges		(1,545	)		83,477			38,017			10,043

		(8,187	)		79,213			21,252			(5,668	)


Income (loss) from continuing operations before income taxes		(45,927	)		237,216			(97,981	)		171,993
Income tax (expense) benefit		16,394			(50,618	)		36,545			(50,618	)

Income (loss) from continuing operations		(29,533	)		186,598			(61,436	)		121,375

DISCONTINUED OPERATIONS (See Note 11):
Gain (loss) on sale of assets, net of tax		—			(252	)		—			28
Income (loss) from discontinued operations, net of tax		14			(44	)		79			240

		14			(296	)		79			268

Net income (loss)		(29,519	)		186,302			(61,357	)		121,643
Preferred stock dividends		1,512			1,512			4,536			4,535

Income (loss) applicable to common stock	$	(31,031	)	$	184,790		$	(65,893	)	$	117,108


INCOME (LOSS) PER COMMON SHARE - BASIC:
From continuing operations	$	(0.87	)	$	5.22		$	(1.84	)	$	3.53
From discontinued operations	$	—		$	(0.01	)	$	—		$	0.01

Income (loss) applicable to common stock	$	(0.87	)	$	5.21		$	(1.84	)	$	3.54

INCOME (LOSS) PER COMMON SHARE - DILUTED:
From continuing operations	$	(0.87	)	$	4.48		$	(1.84	)	$	3.21
From discontinued operations	$	—		$	(0.01	)	$	—		$	0.01

Income (loss) applicable to common stock	$	(0.87	)	$	4.47		$	(1.84	)	$	3.22


Weighted average common shares outstanding - basic		35,771			35,440			35,892			33,098
Weighted average common shares outstanding - diluted		35,771			42,185			35,892			39,740

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,
	2009			2008
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(61,357	)	$	121,643
Adjustments to reconcile net loss to net cash provided by operating activities- Depletion, depreciation and amortization		112,258			80,532
Unrealized (gain) loss on derivatives not designated as hedges		36,983			(13,479	)
Deferred income taxes		(36,439	)		37,939
Exploration costs		160			—
Amortization of leasehold costs		3,916			4,169
Impairment of oil and gas properties		23,490			1,059
Stock based compensation (non-cash)		4,742			4,010
Gain on sale of assets		(295	)		(145,911	)
Amortization of debt discount and finance cost		7,603			6,368
Other non-cash		—			53
Change in assets and liabilities:
Accounts receivable trade and other, net of allowance		1,656			735
Deferred revenue		—			(12,500	)
Accrued oil and gas revenue		4,950			(4,882	)
Prepaid expense and other		(2,748	)		54
Accounts payable		(14,829	)		6,443
Accrued liabilities		1,540			3,826
Income taxes payable		(1,361	)		8,162

Net cash provided by operating activities		80,269			98,221


CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(226,441	)		(276,210	)
Proceeds from sale of assets		235			175,053

Net cash used in investing activities		(226,206	)		(101,157	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Principal payments of bank borrowings		(80,000	)		(155,500	)
Proceeds from bank borrowings		5,000			190,000
Proceeds from common stock offering		—			191,340
Proceeds from convertible note offering		218,500			—
Exercise of stock options and warrants		—			2,819
Debt issuance costs		(8,324	)		(1,498	)
Preferred stock dividends		(4,536	)		(4,535	)
Other		(714	)		(183	)

Net cash provided by financing activities		129,926			222,443

Increase (decrease) in cash and cash equivalents		(16,011	)		219,507
Cash and cash equivalents, beginning of period		147,548			4,448

Cash and cash equivalents, end of period	$	131,537		$	223,955

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

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

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, 2008, as modified by our Current Report on Form 8-K filed on September 18, 2009. The results of operations for the three and nine months ended September 30, 2009, are not necessarily indicative of the results to be expected for the full year.

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

Impairment— Proved oil and gas properties are reviewed for impairment on a field-by-field basis when facts and circumstances indicate that their carrying amounts may not be recoverable. In performing this review, future net cash flows are calculated based on estimated future oil and gas revenues less future expenditures necessary to develop and produce the reserves. If the sum of these estimated future cash flows (undiscounted) is less than the carrying amount of the property, an impairment loss is recognized for the excess of the property’s carrying amount over its estimated fair value based on estimated discounted future cash flows. We perform this comparison using our estimates of future commodity prices and proved and probable reserves. As a result of the disappointing drilling results related to the Caddo Pine Island field and the lower natural gas price environment, we wrote down the carrying value of properties with an aggregate net book value of $25.1 million to their aggregate fair value of $1.6 million resulting in the recognition of a $23.5 million impairment in the second quarter of 2009. The company has determined that this valuation is classified within level three of the valuation hierarchy.

Assets Held for Sale—Assets Held for Sale as of September 30, 2009, represent our remaining assets in Plumb Bob field located in South Louisiana.

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.

New Accounting Pronouncements

On January 1, 2009, we adopted an update to an accounting standard related to convertible debt instruments that may be settled in cash upon conversion (including partial cash settlement). The update required that such instruments should separately account for the liability and equity components in a manner that will reflect the issuer’s nonconvertible debt borrowing rate. The resulting debt discount would be amortized over the period the convertible debt is expected to be outstanding as additional non-cash interest expense. The standard requires retrospective application to all periods presented in the financial statements with the cumulative effect of the change reported in retained earnings as of the beginning of the first period presented. Both our 3.25% Convertible Senior Notes due 2026 and our recently issued 5% Convertible Senior Notes due 2029 (See Note 4) are affected by this accounting standard. The retrospective adjustments to prior period financial statements for the 3.25% Convertible Senior Notes due 2026 are reflected in Note 2.

On January 1, 2009, we adopted an update to an existing accounting standard related to disclosures about derivative instruments and hedging activities. The updated standard requires enhanced disclosures about why an entity uses derivative instruments and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The standard requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. The adoption of this standard did not have an impact on our results of operations, cash flows or financial positions. See Note 8.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In the second quarter of 2009, we adopted the provisions of a new accounting standard relating to subsequent events, which establishes general standards of accounting for and disclosures of events that occur after the balance sheet date but before the financial statements are issued or are available to be issued. It requires the disclosure of the date through which an entity has evaluated subsequent events. Adoption of the standard did not have a material impact on our consolidated financial statements. We have evaluated subsequent events through the time of filing on November 5, 2009, the date of issuance of the financial statements.

In the second quarter of 2009, we adopted an update to accounting standards for disclosures about the fair value of financial instruments, which requires publicly-traded companies to provide disclosures on the fair value of financial instruments in interim financial statements. See Note 10.

In June 2009, the Emerging Issues Task Force (“EITF”) reached a consensus on Accounting for Own-Share Lending Arrangements in Contemplation of Convertible Debt Issuance. The standard requires that, at the date of issuance, a share-lending arrangement entered into on an entity’s own shares in contemplation of a convertible debt offering or other financing is required to be measured at fair value and accounted for as an issuance cost in the financial statements of the entity. It also clarifies the treatment of the loaned shares in the computation of basic and diluted earnings per share, requires additional disclosures in the financial statements with respect to share lending arrangements and requires recognition of a loss in the event that it becomes probable that the counterparty will default. The issue is effective for fiscal years beginning on or after December 15, 2009 and interim periods within those fiscal years for arrangements outstanding at the beginning of those years. The issue requires retrospective application for all arrangements outstanding as of the beginning of the fiscal years beginning on or after December 15, 2009. We are currently evaluating the impact of the provision on our financial statements as it relates to the shares outstanding under the share lending agreement that we entered into in connection with the issuance of our 3.25% Convertible Senior Notes due 2026 in December 2006.

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

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

NOTE 2—Retrospective Adjustment of Prior Period Financial Statements

On January 1, 2009 we adopted an update to an accounting standard that affects the accounting for our convertible senior notes. The accounting standard update did not allow early adoption but does require that previously issued financial statements for comparability purposes be retrospectively adjusted. Our 3.25% convertible senior notes due 2026 were outstanding at the time of adoption and required retrospective accounting adjustments. The following tables reflect the retrospective application to the line items affected on previously issued financial statements.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

(In Thousand- except per share data)

Financial Statement Line Items Adjusted

Balance Sheet


	As of December 31, 2008
	As Reported			Equity/ Debt Discount			Finance Cost Adjustment			As Adjusted
Deferred financing cost	$	4,382		$	—		$	(659	)	$	3,723
Total Assets	$	1,038,946		$	—		$	(659	)	$	1,038,287


Long-Term debt	$	250,000		$	(23,277	)	$	—		$	226,723
Deferred income tax liability		7,988			8,147			(231	)		15,904
Total liabilities		388,300			(15,130	)		(231	)		372,939
Additional paid in capital		576,961			23,920			(756	)		600,125
Retained earnings		64,540			(8,790	)		328			56,078
Total stockholders’ equity		650,646			15,130			(428	)		665,348
Total liabilities and stockholders’ equity	$	1,038,946		$	—		$	(659	)	$	1,038,287


Income Statement

	Three Months Ended September 30, 2008
	As Reported			Debt Discount			Loan Cost Adjustment			As Adjusted
Interest expense	$	(3,886	)	$	(1,695	)	$	57		$	(5,524	)
Income from continuing operations before income taxes		238,854			(1,695	)		57			237,216
Income tax expense		(42,129	)		(8,489	)		—			(50,618	)
Income from continuing operations		196,725			(10,184	)		57			186,598
Net Income		196,429			(10,184	)		57			186,302
Net income applicable to common stock		194,917			(10,184	)		57			184,790

Income per common share - basic
Income from continuing operations	$	5.51								$	5.22
Net loss applicable to common stock	$	5.50								$	5.21
Income per common share - diluted
Income from continuing operations	$	4.69								$	4.48
Income applicable to common stock	$	4.68								$	4.47

	Nine Months Ended September 30, 2008
	As Reported			Debt Discount			Loan Cost Adjustment			As Adjusted
Interest expense	$	(12,059	)	$	(5,081	)	$	169		$	(16,971	)
Income from continuing operations before income taxes		176,905			(5,081	)		169			171,993
Income tax expense		(42,129	)		(8,489	)		—			(50,618	)
Income from continuing operations		134,776			(13,570	)		169			121,375
Net income		135,044			(13,570	)		169			121,643
Net income applicable to common stock		130,509			(13,570	)		169			117,108
Income per common share - basic
Income from continuing operations	$	3.93								$	3.53
Income applicable to common stock	$	3.94								$	3.54
Income per common share - diluted
Income from continuing operations	$	3.47								$	3.21
Income applicable to common stock	$	3.48								$	3.22

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 3—Asset Retirement Obligations

We account for our asset retirement obligation by recording the fair value of the liability associated with the retirement obligations of our tangible long-lived assets in the periods in which it is incurred. We capitalize the discounted fair value of the liability when initially incurred. The liability is accreted through accretion expense to its full fair value over the life of the long-lived asset. Accretion expense is included in depreciation, depletion and amortization on our consolidated statement of operations.

The reconciliation of the beginning and ending asset retirement obligation for the nine months ended September 30, 2009, is as follows (in thousands):


Beginning balance, January 1, 2009	$	13,804
Liabilities incurred		382
Liabilities settled or sold		(56	)
Accretion expense		673

Ending balance, September 30, 2009		14,803
Less current portion		2,813

	$	11,990

The ending balance at September 30, 2009, includes $1.4 million related to Assets Held for Sale. See Note 11.

NOTE 4—Long-Term Debt

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


	September 30, 2009			December 31, 2008

Senior Credit Facility	$	—		$	—
Second Lien Term Loan		—			75,000
3.25% convertible senior notes dues 2026		175,000			175,000
Debt discount on 3.25% convertible senior notes		(17,756	)		(23,277	)
5% convertible senior notes due 2029		218,500			—
Debt discount on 5% convertible senior notes		(49,409	)		—

Total long-term debt	$	326,335		$	226,723

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 will be on a semi-annual basis on each April 1 and October 1 beginning on October 1, 2009. In connection with the offering of the $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 the 5% convertible senior notes due 2029 from the definition of Total Debt used in our financial covenants under the Senior Credit Facility. We currently have no amounts outstanding under the Credit Facility and expect the borrowing base of $175 million to be reaffirmed.

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

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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:

•

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 million of our convertible senior notes are excluded from the calculation of Total Debt for the purpose of computing this ratio).

Second Lien Term Loan

On September 29, 2009, we fully paid off the second lien term loan with proceeds received from the issuance of our 5% convertible senior notes due 2029.

3.25% Convertible Senior Notes Due 2026

In December 2006, we sold $175 million of 3.25% convertible senior notes due in December 2026. The notes mature on December 1, 2026, unless earlier converted, redeemed or repurchased. The notes are our senior unsecured obligations and rank equally in right of payment to all of our other existing and future indebtedness. The notes accrue interest at a rate of 3.25% annually, and interest is paid semi-annually on June 1 and December 1. Interest payments on the notes began on June 1, 2007.

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

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

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

We separately account for the liability and equity components of our 3.25% convertible senior notes due 2026 in a manner that reflects our nonconvertible debt borrowing rate when interest is recognized in subsequent periods. On January 1, 2009, we recorded a beginning of period debt discount balance of $23.3 million which represents the unamortized debt discount of the original retrospective debt discount of approximately $37.0 million and an equity component net of tax of $23.9 million. As of September 30, 2009, the $175.0 million notes were carried on the balance sheet at $157.2 million with a debt discount balance of $17.8 million. The remaining amount of debt discount will be amortized using the effective interest rate method based upon an original 5 year term through December 1, 2011. Amortization of debt discount for the three and nine months ended September 30, 2009 was $1.8 million and $5.5 million, respectively.

5% Convertible Senior Notes due 2029

In September 2009, we sold $218.5 million of 5% convertible senior notes due in October 2029. The notes mature on October 1, 2029, unless earlier converted, redeemed or repurchased. The notes are our senior unsecured obligations and rank equally in right of payment to all of our other existing and future indebtedness. The notes accrue interest at a rate of 5% annually, and interest is paid semi-annually in arrears on April 1 and October 1 of each year, beginning in 2010. Interest began accruing on the notes on September 28, 2009.

Before October 1, 2014, we may not redeem the notes. On or after October 1, 2014, we may redeem all or a portion of the notes for cash, and the investors may require us to repurchase the notes on each of October 1, 2014, 2019 and 2024.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

trading day of the preceding fiscal quarter; (2) prior to October 1, 2014, during the five business-day period after any ten consecutive trading-day period (the “measurement period”) in which the trading price of $1,000 principal amount of the notes for each trading day in the measurement period was less than 97% of the product of the last reported sale price of the Company’s common stock and the conversion rate on such trading day; (3) if the notes have been called for redemption; or (4) upon the occurrence of one of specified corporate transactions. Holders may also convert the notes at their option at any time beginning on September 1, 2029, and ending at the close of business on the second business day immediately preceding the maturity date.

The conversion rate is 28.8534 shares per $1,000 principal amount of the notes (equal to an initial conversion price of approximately $34.66 per share of common stock), subject to adjustment. Upon conversion, the Company must deliver, at its option, either (1) a number of shares of its common stock or (2) a combination of cash and shares of its common stock, if any.

We separately account for the liability and equity components of our 5% convertible senior notes due 2029 in a manner that reflects our nonconvertible debt borrowing rate when interest is recognized in subsequent periods. Upon issuance of the notes in September 2009, we recorded a debt discount of $49.4 million, thereby carrying the $218.5 million notes on the September 30, 2009 balance sheet at $169.1 million. The debt discount will be amortized using the effective interest rate method based upon an original five year term through October 1, 2014.

NOTE 5—Net Loss Per Common Share

Net loss applicable to common stock was used as the numerator in computing basic and diluted loss per common share for the three and nine months ended September 30, 2009 and 2008. The following table reconciles the weighted average shares outstanding used for these computations:


	Three Months Ended September 30,					Nine Months Ended September 30,
	2009			2008		2009			2008
				(as adjusted)					(as adjusted)
	(Amounts in thousands, except per share data)
Basic income (loss) per share:

Income (loss) applicable to common stock	$	(31,031	)	$	184,790	$	(65,893	)	$	117,108
Average shares of common stock outstanding (1)		35,771			35,440		35,892			33,098

Basic income (loss) per share	$	(0.87	)	$	5.21	$	(1.84	)	$	3.54


Diluted income (loss) per share:
Income (loss) applicable to common stock	$	(31,031	)	$	184,790	$	(65,893	)	$	117,108
Dividends on convertible preferred stock (2)		—			1,512		—			4,535
Interest and amortization of loan cost on senior convertible notes, net of tax (3)	$	—		$	2,163	$	—		$	6,488

Diluted income (loss)	$	(31,031	)	$	188,465	$	(65,893	)	$	128,131

Average shares of common stock outstanding (1)		35,771			35,440		35,892			33,098
Assumed conversion of convertible preferred stock (2)		—			3,588		—			3,588
Assumed conversion of 3.25% and 5% convertible senior notes (3)		—			2,654		—			2,654
Stock options, warrants and restricted stock (4)		—			503		—			400

Average diluted shares outstanding		35,771			42,185		35,892			39,740


Diluted income (loss) per share	$	(0.87	)	$	4.47	$	(1.84	)	$	3.22

(1)	This amount does not include 1,624 shares of common stock outstanding under the Share Lending Agreement.

(2)	Common shares issuable upon assumed conversion of our convertible preferred stock amounting to 3,588 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 have not been dilutive.

(3)

Common shares issuable upon assumed conversion of our 3.25% and 5% convertible senior notes amounting to 2,654 and 6,304 shares, respectively, and the accrued interest on the convertible senior notes were not included in the computation of diluted loss per share for the three and nine months ended September 30, 2009 as they would have not 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 and 98 shares, respectively, were not included in the computation of diluted loss per common share since their inclusion would have not been dilutive.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 6—Income Taxes

We recorded tax benefits on continuing operations of $16.4 million for the three months ended September 30, 2009, resulting in an effective tax rate of 35.7%. For the nine months ended September 30, 2009, we recorded tax benefits on continuing operations of $36.5 million, resulting in an effective tax rate of 37.3%. The effective tax rates differ from the 35% federal statutory rate primarily due to state taxes including the benefit for Louisiana net operating losses generated which are available for carryback to 2008.

As of September 30, 2009, we had no unrecognized tax benefits. There were no significant changes to the calculation since December 31, 2008. 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, 2010.

NOTE 7—Stockholders’ Equity

Restricted Stock

During the nine months ended September 30, 2009, we granted 23,925 shares of restricted stock with a weighted average value of $24.68 per share. During the same period, 88,759 restricted shares vested which had a weighted average grant date value of $23.09 per share.

Capped Call Option Transactions

On December 10, 2007, using the proceeds of a public offering, we purchased capped call options on our shares of common stock. 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 will expire over each of three separate 25 consecutive trading day settlement periods, the first of which began on May 18, 2009, and with more to follow on November 16, 2009 and May 18, 2010.

On the 25 consecutive trading days from May 18, 2009 through June 22, 2009, the first of the three tranches of options expired. During this period, the price of our common stock closed above the lower call strike price of $23.50 per share on all trading days resulting in our recoupment of 246,134 shares of our common stock. The shares recouped reduced our common stock outstanding, with no material affect on stockholders’ equity.

Equity Component of Convertible Senior Notes

We separately account for the liability and equity components of our 3.25% convertible senior notes due 2026 and our 5% convertible senior notes due 2029 in a manner that reflects our nonconvertible debt borrowing rate when interest is recognized in subsequent periods. See Note 4.

On January 1, 2009 we recorded a retroactive adjustment to Additional Paid in Capital of $22.8 million, to reflect the deemed equity portion of the 3.25% convertible senior notes due 2026. We also recorded a beginning of period adjustment to retained earnings of $8.1 million, relating to after tax interest expense representing the cumulative effect on retained earnings of the retrospective application resulting from the issuance of the notes on December 1, 2006. See Note 2.

In September 2009, we recorded $32.1 million to Additional Paid in Capital, representing the deemed equity component of the 5% convertible senior notes due 2029.

NOTE 8—Derivative Activities

We use commodity and financial derivative contracts to manage fluctuations in commodity prices and interest rates. We are currently not designating 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 statement of operations.

Commodity Derivative Activity

We produce and sell oil and natural gas into a market where selling prices are historically volatile. For example, in the year 2008, the Henry Hub natural gas spot price reached a high of $13.31 per MMbtu, but at the end of September 2009 the price was down to $3.24 per MMbtu. We enter into swap contracts, costless collars or other derivative agreements from time to time to manage this commodity price risk for a portion of our production. Our strategy, which is administered by the Hedging Committee of our Board of Directors, and reviewed periodically by the entire Board of Directors, has been to generally hedge between 30% and 70% of our estimated total production for the period the derivatives are in effect. As of September 30, 2009, the commodity derivatives we used were in the form of:

(a)

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

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

(b)

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

(c)

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, 2009, our open forward positions on our outstanding commodity derivative contracts, all of which were with BNP Paribas, JP Morgan or Bank of Montreal, were as follows:


Collars (NYMEX)	Daily Volume	Total Volume	Floor/Cap Average Price		Fair Value at September 30, 2009
Natural gas (MMbtu)
4Q 2009	20,000	1,840,000		$8.75 - $ 13.10	$	8,057,604
1Q 2010	10,000	900,000		$6.00 - $ 7.15
2Q 2010	10,000	910,000		$6.00 - $ 7.15
3Q 2010	10,000	920,000		$6.00 - $ 7.15
4Q 2010	10,000	920,000		$6.00 - $ 7.15

Swaps (NYMEX)			Average Price
Natural gas (MMbtu)						7,401,741
4Q 2009	20,000	1,840,000	$	8.83

Swaps (TexOk)			Field Price (1)
Natural gas (MMbtu)						6,034,627
4Q 2009	20,000	1,840,000	$	7.87

Swaps (NYMEX/TexOk)			Average Price (2)
Natural gas (MMbtu)						(3,467,762	)
4Q 2009	40,000	3,680,000	$	0.520
1Q 2010	50,000	4,500,000	$	0.368
2Q 2010	50,000	4,550,000	$	0.368
3Q 2010	50,000	4,600,000	$	0.368
4Q 2010	50,000	4,600,000	$	0.368


				Total	$	18,026,210

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

(2)	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 oil and gas commodity contracts in place at September 30, 2009, that are marked to market resulted in a net current asset of $18.3 million and a net non-current liability of $0.3 million. We measure the fair value of our commodity derivatives contracts by applying the income approach, and these contracts are classified within level two of the valuation hierarchy. See Note 9. For the three months ended September 30, 2009, we recognized in earnings a $1.3 million loss from these instruments, which consisted of $28.9 million in unrealized losses offset by $27.6 million in realized gains. For the nine months ended September 30, 2009, we recognized in earnings a $38.6 million gain from these instruments, which consisted of $75.9 million in realized gains offset by $37.3 million in unrealized losses.

During the third quarter of 2009, we did not enter into any derivative contracts. After September 30, 2009 we entered into a 10,000 MMbtu/day NYMEX zero cost collar contract with a floor and ceiling price of $6.00 and $7.40 per MMbtu, respectively. These contracts are for the calendar years 2010, 2011 and 2012.

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

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Interest Rate Swap

We have variable-rate debt obligations that expose us to the effects of changes in interest rates. To partially reduce our exposure to interest rate risk, from time to time we enter into interest rate swap agreements. These swaps are not designated as hedges. At September 30, 2009, we had the following interest rate swaps in place with BNP Paribas and Bank of Montreal:


Effective Date	Maturity Date	LIBOR Swap Rate		Notional Amount (Millions)		Fair Value (Dollars)
4/22/2008	4/22/2010	3.19	%	$	25.0	$	(513,112	)
4/22/2008	4/22/2010	3.19	%		50.0		(1,023,762	)

						$	(1,536,874	)

The fair value of the interest rate swap contract at September 30, 2009, resulted in a liability of $1.5 million which is reflected on the balance sheet as a current liability. We measure the fair value of our interest rate swaps by applying the income approach and these contracts are classified within level two of the valuation hierarchy. See Note 9. For the three and nine months ended September 30, 2009, we recognized losses of $0.2 million and $0.6 million, respectively, from interest rate swaps.

NOTE 9—Fair Value Measurements

On January 1, 2008 we adopted a fair value measurement accounting standard for financial assets and liabilities measured on a recurring basis. The standard applies to all financial assets and financial liabilities that are being measured and reported on a fair value basis. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. As of January 1, 2009, the standard affects the Company in the fair value measurement of the commodity and interest rate derivative positions for financial assets/liabilities and the Company’s Asset Retirement Obligation nonfinancial liabilities which must be classified in one of the following categories:

Level 1 Inputs

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

Level 2 Inputs

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

Level 3 Inputs

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

As required by the accounting standard, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table summarizes the valuation of our investments and financial instruments by pricing levels as of September 30, 2009:


	Fair Value Measurement (in thousands)
Description	Level 1		Level 2			Level 3		Total
Current assets	$	—	$	18,289		$	—	$	18,289
Current liabilities		—		(1,537	)		—		(1,537	)
Long-term liabilities		—		(263	)		—		(263	)

Total	$	—	$	16,489		$	—	$	16,489

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 10—Fair Value of Financial Instruments

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

The carrying values of items comprising current assets and current liabilities approximate fair values due to these short-term maturities of these instruments. We estimate the fair value of our convertible senior notes using quotes from third parties. The carrying amounts and fair values of the other financial instruments and derivatives at September 30, 2009 and December 31, 2008, are as follows (in thousands):


	As of September 30, 2009						As of December 31, 2008
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Second Lien Term Loan	$	—		$	—		$	75,000		$	75,000
3.25% Convertible Senior Notes		157,244			161,875			151,723			132,948
5.0% Convertible Senior Notes		169,091			232,156			—			—
Derivative assets (liabilities)
Gas		18,026			18,026			55,276			55,276
Interest rate		(1,537	)		(1,537	)		(1,804	)		(1,804	)

NOTE 11—Discontinued Operations

On March 20, 2007, the Company closed the sale of substantially all of its oil and gas properties in South Louisiana with the exception of the St. Gabriel, Bayou Bouillon and Plumb Bob fields as discussed under Note 1 “Assets Held for Sale.” The results of operations of our South Louisiana properties that have been sold or are classified as held for sale are reported in discontinued operations. The operations of these properties have been eliminated from our ongoing operating results, and we have no continuing involvement after the sale of the property. The St. Gabriel and Bayou Bouillon fields were sold in 2008. The Plumb Bob field is being held for sale.

The following table summarizes the amounts included in income from discontinued operations (in thousands):


	Three Months Ended September 30,					Nine Months Ended September 30,
	2009		2008			2009		2008
Revenues	$	75	$	302		$	298	$	1,187
Expenses		53		217			176		818

Income from discontinued operations		22		85			122		369
Income tax expense		8		129			43		129

Income (loss) from discontinued operations, net of tax	$	14	$	(44	)	$	79	$	240

The Plumb Bob field has been fully reserved and has an accrued abandonment cost liability of $1.4 million.

NOTE 12—Commitments and Contingencies

We have entered into a new operating lease for our Houston office space. The agreement is effective August 1, 2009 and has a term of ten years. Total base rent for the term of the agreement is approximately $9.5 million with annual rental expense in year one of $0.8 million and ending in year ten at $1.1 million.

We are party to lawsuits arising in the normal course of business. We intend to defend these actions vigorously and believe, based on currently available information, that adverse results or judgments from such actions, if any, will not be material to our consolidated financial position or results of operations or liquidity. No significant changes to these type lawsuits have occurred since December 31, 2008.

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

Forward-Looking Statements

Certain statements in this report, including statements of the future plans, objectives, and expected performance are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, that are dependent upon certain events, risks and uncertainties that may be outside our control, and which could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to:

•

planned capital expenditures;

•

future drilling activity;

•

our financial condition;

•

business strategy;

•

the market prices of oil and gas;

•

economic and competitive conditions;

•

legislative and regulatory changes;

•

financial market conditions and availability of capital;

•

production;

•

hedging arrangements;

•

future cash flows and borrowings;

•

litigation matters;

•

more stringent environmental laws and increased difficulty in obtaining environmental permits;

•

pursuit of potential future acquisition opportunities; and

•

sources of funding for exploration and development.

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

These factors, as well as additional factors that could affect our operating results and performance are described in this report under the heading “Risk Factors” and in our Annual Report on Form 10-K for the year ended December 31, 2008, and our Quarterly Report on Form 10-Q for the quarter ended June 30, 2009 under the headings “Business,” “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.” We urge you to carefully consider those factors.

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

Overview

General

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

Source of Revenues

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

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

3rd Quarter 2009 Financial and Operating Results Include:

•

We increased our oil and gas production volumes on continuing operations to 82,496 Mcfe per day, representing an increase of 20% from 68,783 Mcfe per day for the third quarter of 2008.

•

We conducted drilling operations on 12 gross wells in the third quarter of 2009. The Haynesville Shale was penetrated by all 12 wells.

•

We reduced lease operating expense from $1.29 to $0.97 per Mcfe, representing a 25% decrease from the third quarter of 2008.

Cotton Valley Trend

Our relatively low-risk development drilling program in the Cotton Valley Trend is primarily centered in and around Rusk, Panola, Angelina and Nacogdoches counties, Texas, and DeSoto, Caddo and Bienville parishes, Louisiana. We have increased our acreage position in these areas over the last three years to approximately 200,000 gross acres as of September 30, 2009. Through September 30, 2009, we have participated in the drilling and logging of 456 Cotton Valley Trend wells with a success rate in excess of 99%. We conducted drilling operations on 12 gross wells during the third quarter of 2009. Our net production volumes aggregated approximately 82,496 Mcfe per day in the third quarter of 2009, or approximately 20% higher than production of the comparable prior year period.

Company Operated Haynesville Shale Drilling Program

We conducted drilling operations on five operated Haynesville Shale horizontal wells during the third quarter of 2009. We expect to continue developing the Haynesville Shale through 2009 with the drilling and completion of approximately three additional operated horizontal wells in East Texas and Northwest Louisiana. As of September 30, 2009, we had conducted drilling operations on a total of nine vertical and nine horizontal operated wells that penetrated the Haynesville Shale. The nine vertical pilot wells were drilled early in our Haynesville Shale program and were meant to test the thickness and productivity of the Haynesville Shale throughout our acreage position. All nine vertical wells had reached initial production by the end of the first quarter. Of the nine vertical wells, two wells were located on our Bethany Longstreet acreage in Northwest Louisiana and the remaining seven wells were drilled in the Beckville, Minden, Naconiche Creek and South Henderson fields in Texas. Daily average net production from company operated Haynesville Shale wells was 10,156 Mcfe per day for the three months ended September 30, 2009.

Chesapeake Haynesville Shale Joint Development

Through our joint development arrangement with Chesapeake Energy Corporation (“Chesapeake”), which covers certain of our acreage in northwest Louisiana, we will continue to operate existing production and operate any new wells drilled to the base of the Cotton Valley sand, and Chesapeake will operate any wells drilled below the base of the Cotton Valley sand, including the Haynesville Shale. As of September 30, 2009, we participated in drilling operations on seventeen horizontal and one vertical well under the joint development arrangement. As of quarter end, only thirteen horizontal and one vertical well had reached initial production and the remaining four horizontal wells were in some form of drilling or completion. For the remainder of 2009, we and Chesapeake plan to utilize two to three rigs to conduct drilling operations on approximately four to six gross additional Haynesville Shale horizontal wells. Daily average net production from Chesapeake operated Haynesville Shale wells grew to 15,235 Mcfe per day for the three months ended September 30, 2009.

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, 2008.

Results of Operations

The financial statements include discontinued operations presentation for our assets located in South Louisiana. See Note 11 to our consolidated financial statements.

For the three months ended September 30, 2009, we reported a net loss applicable to common stock of $31.0 million, or $0.87 per basic and diluted share, on total revenue from continuing operations of $23.5 million as compared to a net income applicable to common stock of $184.8 million, or $5.21 per basic ($4.47 per diluted) share, on total revenue from continuing operations of $60.4 million for the three months ended September 30, 2008. The fall in oil and gas prices period to period, which decreased oil and gas revenue by approximately $48.8 million, was offset by revenue from a production increase of approximately $12.0 million, which

resulted in the $36.8 million difference in oil and gas revenues. In conjunction with the fall of natural gas prices between the comparable periods, we recorded a $1.5 million loss on derivatives not designated as hedges for the three months ended September 30, 2009 compared to a $83.5 million gain on derivatives not designated as hedges for the three months ended September 30, 2008. We also recorded an income tax benefit on continuing operations of $16.4 million for the three months ended September 30, 2009 compared to $50.6 million of income tax expense for the three months ended September 30, 2008.

For the nine months ended September 30, 2009, we reported a net loss applicable to common stock of $65.9 million, or $1.84 per basic and diluted share, on total revenue from continuing operations of $78.2 million as compared to a net income applicable to common stock of $117.1 million, or $3.54 per basic ($3.22 per diluted) share, on total revenue from continuing operations of $171.9 million for the nine months ended September 30, 2008. The fall in oil and gas prices period to period which decreased oil and gas revenue by approximately $133.5 million was offset by revenue from a production increase of approximately $40.3 million which resulted in the $93.2 million difference in oil and gas revenues. In conjunction with the fall of natural gas prices between the comparable periods, we recorded a $38.0 million gain on derivatives not designated as hedges in the nine months ended September 30, 2009 compared to a $10.0 million gain on derivatives not designated as hedges for the nine months ended September 30, 2008. We also recorded an income tax benefit on continuing operations of $36.5 million for the nine months ended September 30, 2009 compared to $50.6 million tax expense for the nine months ended September 30, 2008.

Oil and Natural Gas Revenues

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

Summary Operating Information:


	Three Months Ended September 30,											Nine Months Ended September 30,
In thousands, except for price data	2009			2008			Variance					2009			2008			Variance

Revenues:
Natural gas (1)	$	21,377		$	55,645		$	(34,268	)	(62	)%	$	72,354		$	157,541		$	(85,187	)	(54	)%
Oil and condensate		2,190			4,711			(2,521	)	(54	)%		5,887			13,864			(7,977	)	(58	)%
Natural gas, oil and condensate		23,567			60,356			(36,789	)	(61	)%		78,241			171,405			(93,164	)	(54	)%
Operating revenues		23,525			60,376			(36,851	)	(61	)%		78,249			171,902			(93,653	)	(54	)%
Operating expenses		61,265			(97,627	)		158,892		(163	)%		197,482			(5,759	)		203,241		(3529	)%
Operating income (loss)		(37,740	)		158,003			(195,743	)	(124	)%		(119,233	)		177,661			(296,894	)	(167	)%

Net Production:
Natural gas (MMcf)		7,386			6,088			1,298		21	%		21,153			16,962			4,191		25	%
Oil and condensate (MBbls)		34			40			(6	)	(15	)%		120			123			(3	)	(2	)%
Total (Mmcfe)		7,590			6,328			1,262		20	%		21,876			17,700			4,176		24	%
Average daily production (Mcfe/d)		82,496			68,783			13,713		20	%		80,132			64,599			15,533		24	%

Average realized sales price (1) per unit:
Natural gas (per Mcf)	$	2.89		$	9.14		$	(6.25	)	(68	)%	$	3.42		$	9.29		$	(5.87	)	(63	)%
Oil and condensate (per Bbl)		64.43			117.65			(53.22	)	(45	)%		48.87			112.28			(63.41	)	(56	)%
Total (per Mcfe)		3.11			9.54			(6.43	)	(67	)%		3.58			9.68			(6.10	)	(63	)%

(1)	Does not include our commodity derivatives.

Revenues from continuing operations decreased 61% in the three months ended September 30, 2009 compared to the same period in 2008 due primarily to a substantial 67% decrease in realized sales prices. Net production increased 20% period to period. Revenues from continuing operations decreased 54% in the nine months ended September 30, 2009 compared to the same period in 2008 primarily due to a 63% decrease in realized sales prices. Net production increased 24% period to period, offsetting somewhat the decrease in realized sales prices. The production increases in the three and nine month periods ended September 30, 2009 over the same periods in 2008 are due to the increase in the number of wells producing in the Cotton Valley Trend and production from wells completed in the Haynesville Shale.

Operating Expenses

The following tables present our comparative operating expenses related to continuing operations:


	Three Months Ended September 30,											Nine Months Ended September 30,
	2009			2008			Variance					2009			2008			Variance
Operating Expenses (in thousands)

Lease operating expenses	$	7,363		$	8,165		$	(802	)	(10	)%	$	23,343		$	22,931		$	412		2	%
Production and other taxes		1,294			2,110			(816	)	(39	)%		3,831			5,699			(1,868	)	(33	)%
Transportation		2,300			2,224			76		3	%		7,479			6,480			999		15	%
Depreciation, depletion and amortization		42,063			26,414			15,649		59	%		112,258			80,532			31,726		39	%
Exploration		1,625			2,062			(437	)	(21	)%		6,804			5,841			963		16	%
Impairments		—			1,059			(1,059	)	(100	)%		23,490			1,059			22,431		2118	%
General and administrative		6,802			6,207			595		10	%		20,572			17,567			3,005		17	%
Gain on sale of assets		(182	)		(145,868	)		145,686		(100	)%		(295	)		(145,868	)		145,573		(100	)%

	Three Months Ended September 30,											Nine Months Ended September 30,
	2009			2008			Variance					2009			2008			Variance
Operating Expenses per Mcfe
Lease operating expenses	$	0.97		$	1.29		$	(0.32	)	(25	)%	$	1.07		$	1.30		$	(0.23	)	(18	)%
Production and other taxes		0.17			0.33			(0.16	)	(48	)%		0.18			0.32			(0.14	)	(44	)%
Transportation		0.30			0.35			(0.05	)	(14	)%		0.34			0.37			(0.03	)	(8	)%
Depreciation, depletion and amortization		5.54			4.17			1.37		33	%		5.13			4.55			0.58		13	%
Exploration		0.21			0.33			(0.12	)	(36	)%		0.31			0.33			(0.02	)	(6	)%
Impairments		—			0.17			(0.17	)	(100	)%		1.07			0.06			1.01		1683	%
General and administrative		0.90			0.98			(0.08	)	(8	)%		0.94			0.99			(0.05	)	(5	)%
Gain on sale of assets		(0.02	)		(23.05	)		23.03		100	%		(0.01	)		(8.24	)		8.23		100	%

Lease Operating. Lease operating expense (“LOE”) for the three months ended September 30, 2009 was $7.4 million, a decrease of $0.8 million, or 10%, from the $8.2 million in the three months ended September 30, 2008. On a per unit basis, LOE decreased 25% from $1.29 to $0.97 per Mcfe for the three months ended September 30, 2009 compared to the same period in 2008. The overall cost decrease is attributed to lower saltwater disposal cost as we realized the continued impact of a new series of saltwater disposal system installations in 2009 and lower compressor rental costs, negotiated in conjunction with current market conditions. The decrease in the unit cost between the periods is attributed to the absolute dollar cost reduction, a 20% increase in production volumes and an increasing portion of our production coming from the Haynesville Shale, which carries lower production cost. LOE for the nine months ended September 30, 2009 was $23.3 million, an increase of $0.4 million or 2%, from the $22.9 million in the nine months ended September 30, 2008. On a per unit basis, LOE decreased 18% from $1.30 to $1.07 per Mcfe for the nine months ended September 30, 2009 compared to the same period in 2008. The decrease in the unit cost between the nine month periods is attributed to both the continued cost reductions realized in 2009 and the 24% increase in production volumes as a result of our successful drilling program.

Production and Other Taxes. Production and other taxes for the three months ended September 30, 2009 was $1.3 million which includes production tax of $0.5 million and ad valorem tax of $0.8 million. Production tax included $0.3 million of new Tight Gas Sands (“TGS”) tax credits for our wells in the State of Texas. During the comparable period in 2008, production and other taxes were $2.1 million, which included production tax of $1.6 million and ad valorem tax of $0.5 million. Production tax for the three months ended September 30, 2008 included $0.9 million in TGS tax credits. Production and other taxes for the nine months ended September 30, 2009 was $3.8 million which includes production tax of $1.5 million and ad valorem tax of $2.3 million. Production tax included $1.2 million of new TGS tax credits for our wells in the State of Texas. During the comparable period in 2008, production and other taxes were $5.7 million, which included production tax of $4.2 million and ad valorem tax of $1.5 million. Production tax for the nine months ended September 30, 2008 included $2.9 million in TGS credits. Lower production tax for the three and nine month periods from 2008 and 2009 is attributable to decreased gas prices period to period. Also, an increasing portion of our production is attributable to Haynesville horizontally drilled wells, which are exempt for two years from State of Louisiana production tax.

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

Transportation. Transportation expense for the three months ended September 30, 2009 was $2.3 million ($0.30 per Mcfe) compared to $2.2 million ($0.35 per Mcfe) for the three months ended September 30, 2008. The slight increase in expense is primarily due to our higher production volumes while the lower unit costs are a function of our changing geographic production mix. Transportation expense for the nine months ended September 30, 2009 was $7.5 million ($0.34 per Mcfe) compared to $6.5 million ($0.37 per Mcfe) for the nine months ended September 30, 2008. The increase in expense is primarily due to our higher production volumes while the lower unit costs are a function of our changing geographic production mix.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) for the three months ended September 30, 2009 increased to $42.1 million from $26.4 million for the three months ended September 30, 2008 resulting from higher levels of production and a higher DD&A rate. The average DD&A rate for the three months ended September 30, 2009 was $5.54 per Mcfe compared to $4.17 per Mcfe for the same period in 2008. DD&A for the nine months ended September 30, 2009 increased to $112.3 million from $80.5 million for the nine months ended September 30, 2008 with higher levels of production and a higher DD&A rate. The average DD&A rate for the nine months ended September 30, 2009 was $5.13 per Mcfe compared to $4.55 per Mcfe for the same period in 2008.

We calculated the DD&A rate for the three month period ended September 30, 2009 using an internally generated reserve report dated June 30, 2009, with a NYMEX gas price of $3.88 per MMbtu. While this internal reserve report was prepared in accordance with existing SEC guidelines, it should not be construed as a fully independent engineering reserve report similar to what we have used in the past and what we envision using at year end. The reserve estimates from this report as of June 30, 2009 resulted in a decrease in proved developed reserves from year end, due primarily to a reduction in the price used for purposes of evaluating the reserves, from $5.71 per MMbtu at December 31, 2008 to $3.88 per MMbtu at June 30, 2009. As a result, the DD&A rate utilized for the three month period ended September 30, 2009, increased to $5.54 per Mcfe versus $4.17 per Mcfe in the three month period ended September 30, 2008. The higher DD&A rate of $5.54 mainly results from the impact of lower prices on our traditional Cotton Valley Trend vertical reserves, which represent a majority of our proved developed reserves at June 30, 2009. Similarly, the higher rate for the third quarter resulted in the DD&A rate for the nine month period ended September 30, 2009 to be $5.13 per Mcfe, a 13% increase from the nine month period ended September 30, 2008.

Exploration. Exploration expenses for the three months ended September 30, 2009 decreased $0.5 million to $1.6 million compared to $2.1 million in the same period in 2008. Exploration expenses for the nine months ended September 30, 2009 increased $1.0 million to $6.8 million compared to $5.8 million in the same period in 2008. In addition to a drilling contract early termination charge of $1.1 million in the second quarter of 2009, the nine month period ended September 30, 2009 includes a $0.1 million in dry hole cost recorded in the first quarter of 2009 resulting from an unsuccessful exploration tail of a successful development well.

Impairments. We recorded no impairment expense for the three months ended September 30, 2009. In the nine months ended September 30, 2009, we recorded an impairment of $23.5 million related to our Caddo Pine Island and Brachfield fields. We recorded an impairment of $1.1 million in the three and nine months ended September 30, 2008 related to the Alabama Bend and Gilmer fields.

General and Administrative. General and administrative (“G&A”) expense increased $0.6 million or 10% to $6.8 million in the three months ended September 30, 2009 compared to $6.2 million in the same period in 2008. The increase results from higher compensation cost relative to having a larger work force. The company had 125 employees for the third quarter of 2009 versus 107 employees in the third quarter of 2008. G&A on a per unit basis decreased to $0.90 per Mcfe from $0.98 per Mcfe as a result of a 20% increase in production volumes in the third quarter of 2009 as compared to the third quarter of 2008. Stock based compensation expense, which is a non-cash item, amounted to $1.5 million in the third quarter of 2009 compared to $1.4 million for the same period in 2008. G&A expense increased $3.0 million, or 17%, to $20.6 million in the nine months ended September 30, 2009 compared to $17.6 million in the same period in 2008. The increase period to period is primarily due to the increase in compensation cost relative to having a larger work force. G&A on a per unit basis decreased to $0.94 per Mcfe from $0.99 per Mcfe as a result of a 24% increase in production volumes in the nine months ended September 30, 2009 as compared to the nine months ended September 30, 2008. Stock based compensation expense, which is a non-cash item, amounted to $4.7 million in the nine months ended September 30, 2009 compared to $4.0 million for the nine months ended September 30, 2008.

Other Income (Expense)

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2009		2008		2009		2008
			(as adjusted)				(as adjusted)

Other income (expense):

Interest expense	(6,646	)	(5,524	)	(17,152	)	(16,971	)
Interest income	4		1,260		387		1,260
Gain (loss) on derivatives not designated as hedges	(1,545	)	83,477		38,017		10,043
Income tax benefit (expense) on continuing operations	16,394		(50,618	)	36,545		(50,618	)
Gain (loss) on disposal, net of tax	—		(252	)	—		28
Income (loss) from discontinued operations net of tax	14		(44	)	79		240
Average funded borrowings	250,326		263,049		250,110		278,380
Average funded borrowings adjusted for debt discount	233,195		236,961		229,938		251,589

Interest Expense. Interest expense increased $1.1 million to $6.6 million for the three months ended September 30, 2009 compared to $5.5 million for the three months ended September 30, 2008 as a result of the write off of deferred financing cost and the pre-payment premium on the second lien term loan. Interest expense increased $0.2 million to $17.2 million in the nine months ended September 30, 2009 compared to $17.0 million in the nine months ended September 30, 2008 for essentially the same reasons but was partially offset by the lower average level of funded debt in the nine months ended September 30, 2009.

The interest expense in the three and nine month periods ended September 30, 2008 has been retrospectively increased by $1.6 million and $4.9 million, respectively (non-cash), as the result of our adoption of “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion”, on January 1, 2009. The adoption of the standard resulted in the recognition of an additional $1.8 million and $5.4 million (non-cash) in interest expense for the three and nine month periods ended September 30, 2009, respectively.

Interest Income. We invested the net proceeds from our equity offering and the sale of assets, both in July 2008, in money market funds and time deposits with certain acceptable institutions, subject to our newly implemented Short Term Investment Policy. The income earned on these investments during 2009 is reflected in the Interest income line. For more information on our Short Term Investment Policy, please see our Annual Report on Form 10-K for the year ended December 31, 2008, under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations–Liquidity–Short Term Investments.”

Gain (Loss) on Derivatives Not Designated as Hedges. Loss on derivatives not designated as hedges was $1.5 million for the three months ended September 30, 2009, including a realized gain of $27.6 million and an unrealized loss of $28.9 million for the change in fair value of our natural gas commodity contracts. The unrealized loss resulted from the roll off of existing contracts during the third quarter of 2009. The three months ended September 30, 2009 also included a loss of $0.2 million on our interest rate swap. As a comparison, gain on derivatives not designated as hedges for the three months ended September 30, 2008 was $83.5 million including a realized loss of $1.6 million and an unrealized gain of $85.3 million for the changes in fair value of our commodity contracts. The three months ended September 30, 2008 also included a net loss on interest rate swaps of $0.2 million.

Gain on derivatives not designated as hedges was $38.0 million for the nine months ended September 30, 2009, including a realized gain of $75.9 million and an unrealized loss of $37.3 million for the change in fair value of our natural gas commodity contracts. The unrealized loss resulted from the roll off of existing contracts during the nine months ended September 30, 2009. The nine months ended September 30, 2009 also included a loss of $0.6 million on our interest rate swap. As a comparison, gain on derivatives not designated as hedges for the nine months ended September 30, 2008 was $10.0 million including a realized loss of $3.1 million and an unrealized gain of $13.4 million for the changes in fair value of our commodity contracts. The nine months ended September 30, 2008 also included a loss of $0.3 million on our interest rate swap.

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

Income taxes. Income tax benefit on continuing operations for the three months ended September 30, 2009 was $16.4 million which includes $0.6 million state income tax benefit. Income tax benefit on continuing operations for the nine months ended September 30, 2009 was $36.5 million which includes a state income tax benefit of $2.3 million. Income tax expense for the three and nine months ended September 30, 2008 was $50.6 million. We provided for no income taxes in the first half of 2008. We generated tax expense in the third quarter of 2008 as a result of the gain realized on the sale of oil and gas properties.

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,
	2009			2008			Variance
Cash flow statement information:
Net cash:
Provided by operating activities	$	80,269		$	98,221		$	(17,952	)
Used in investing activities		(226,206	)		(101,157	)		(125,049	)
Provided by financing activities		129,926			222,443			(92,517	)

Increase (decrease) in cash	$	(16,011	)	$	219,507		$	(235,518	)

Operating activities. Net cash provided by operating activities decreased $17.9 million to $80.3 million for the nine months ended September 30, 2009, from $98.2 million for the comparable 2008 period due primarily to reduced natural gas prices.

Investing activities. Net cash used in investing activities was $226.2 million for the nine months ended September 30, 2009 compared to net cash used in investing activities of $101.2 million for the nine months ended September 30, 2008. We conducted drilling operations on 39 gross wells, 26 of which penetrated the Haynesville Shale during the first nine months ended September 30, 2009. In comparison, we expended $276.2 million in conducting drilling operations on 118 gross wells, all of which are located in our Cotton Valley Trend, during the nine months ended September 30, 2008. The cost per well increased in 2009 compared to 2008 due to drilling more expensive Haynesville Shale wells. In the 2008 comparable period, we received proceeds of $175.0 million from the sale of a portion of our interest in the deep rights underlying our North Louisiana acreage.

Financing activities. Net cash provided by financing activities was $129.9 million for the nine months ended September 30, 2009, versus net cash provided by financing activities of $222.4 million for the same period in 2008. In the nine months ended September 30, 2009, we had net proceeds of approximately $212.5 million from the sale of our 5% convertible senior notes offset by the repayment of our $75 million second lien term loan and payment of preferred dividends and other activity of approximately $7.6 million.

For the year 2009, we have budgeted total capital expenditures of approximately $230 million, down from our original capital expenditure budget of $300 million, of which approximately 65%, or $150 million, is expected to be focused on drilling horizontal wells in the Haynesville Shale program in East Texas and North Louisiana, where we and our partners plan to average approximately five rigs working throughout 2009. The remainder of the budgeted amount is earmarked for horizontal wells in the James Lime in the Angelina River trend, several Cotton Valley horizontal wells in East Texas, and various leasehold and infrastructure expenditures as needed across our entire acreage block. As of September 30, 2009, we have spent approximately $194 million of our total budgeted capital expenditure for 2009. The $226 million of capital expenditures reflected in the consolidated statements of cash flows includes an additional $32 million in cash paid out during the nine months ended September 30, 2009 which related to capital expenditures accrued for during 2008. We expect to fund the remainder of our 2009 capital expenditures through a combination of cash flow from operations, from cash on hand and borrowing under our senior credit facility.

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 will be on a semi-annual basis on each April 1 and October 1 beginning on October 1, 2009. In connection with the offering of the $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 the 5% convertible notes due 2029 from the definition of Total Debt used in our financial covenants under the Senior Credit Facility. We currently have no amounts outstanding under the Credit Facility and expect the borrowing base of $175 million to be reaffirmed.

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

•

Current Ratio of 1.0/1.0;

•

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

•

Second Lien Term Loan

On September 29, 2009, we fully paid off the second lien term loan with proceeds received from the issuance of our 5% convertible senior notes due 2029.

3.25% Convertible Senior Notes Due 2026

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

5% Convertible Senior Notes due 2029

Investors may convert their notes at their option at any time prior to the close of business on the second business day immediately preceding the maturity date under the following circumstances: (1) during any fiscal quarter (and only during such fiscal quarter) commencing after December 31, 2009, if the last reported sale price of the Company’s common stock is greater than or equal to 135% of the conversion price of the Notes for at least 20 trading days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter; (2) prior to October 1, 2014, during the five business-day period after any ten consecutive trading-day period (the “measurement period”) in which the trading price of $1,000 principal amount of the Notes for each trading day in the measurement period was less than 97% of the product of the last reported sale price of the Company’s common stock and the conversion rate on such trading day; (3) if the notes have been called for redemption; or (4) upon the occurrence of one of specified corporate transactions. Holders may also convert the notes at their option at any time beginning on September 1, 2029, and ending at the close of business on the second business day immediately preceding the maturity date.

We separately account for the liability and equity components of our 5% convertible senior notes due 2029 in a manner that reflects our nonconvertible debt borrowing rate when interest is recognized in subsequent periods. Upon issuance of the notes in September 2009, we recorded a debt discount of $49.4 million thereby carrying the $218.5 million notes on the September 30, 2009 balance sheet at $169.1 million. The debt discount will be amortized using the effective interest rate method based upon an original five year term through October 1, 2014.

Capped Call Option Transactions

On December 10, 2007, using the proceeds of a public offering, we purchased capped call options on our shares of common stock. 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 will expire over each of three separate 25 consecutive trading day settlement periods, the first of which began on May 18, 2009, with more to follow and on November 16, 2009 and May 18, 2010.

Equity Component of Convertible Senior Notes

We separately account for the liability and equity components of our 3.25% convertible notes due 2026 and our 5% convertible senior notes due 2029 in a manner that reflects our nonconvertible debt borrowing rate when interest is recognized in subsequent periods. See Note 4 “Long-Term Debt” to our consolidated financial statements for additional information.

In September 2009, we recorded $32.1 million to Additional Paid in Capital, representing the deemed equity component of the 5% convertible senior notes due 2029.

Accounting Pronouncements

See Note 1 “Description of Business and Significant Accounting Policies”- “New Accounting Pronouncements” to our consolidated financial statements for a discussion of recently issued pronouncements.

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, 2008, includes a discussion of our critical accounting policies.

Item 3 – Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

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, 2009, the commodity hedges we utilized were in the form of:

(a)

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

(b)

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

(c)

basis swap, 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 2009. The fair value of the natural gas hedging contracts in place at September 30, 2009, resulted in a net current asset of $18.3 million and a net non-current liability of $0.3 million. Based on oil and gas pricing in effect at September 30, 2009, a hypothetical 10% increase in oil and gas prices would have resulted in a derivative asset of $14.4 million while a hypothetical 10% decrease in oil and gas prices would have increased the derivative asset to $21.6 million. See Note 8 “Derivative Activities” to our consolidated financial statements for additional information.

Interest Rate Risk

We have several variable-rate debt obligations that expose us to the effects of changes in interest rates. To partially reduce our exposure to interest rate risk, from time to time we enter into interest rate swap agreements. We entered into interest rate derivative swap agreements in the second quarter of 2008, whereby we contracted a notional amount of $75.0 million at a fixed rate of 3.191% for the period April 2008 to April 2010. We have not designated these swaps as a hedge. At September 30, 2009, we had the following interest rate swaps in place with BNP Paribas and Bank of Montreal:


Effective Date	Maturity Date	Libor Swap Rate		Notional Amount (Millions)		Fair Value (Dollars)
4/22/2008	4/22/2010	3.19	%	$	25.0	$	(513,112	)
4/22/2008	4/22/2010	3.19	%		50.0		(1,023,762	)

						$	(1,536,874	)

The fair value of the interest rate swap contracts in place at September 30, 2009, resulted in a liability of $1.5 million. Based on interest rates at September 30, 2009, a hypothetical 10% increase or decrease in interest rates would not have a material effect on the liability.

Item 4 – Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in rules 13a-15(c) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our Chief Executive Officer and Chief Financial Officer, based upon their evaluation as of September 30, 2009, the end of the period covered in this report, concluded that our disclosure controls and procedures were effective at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

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

PART II—OTHER INFORMATION

Item 1A – Risk Factors

Climate change legislation, regulatory initiatives and litigation may adversely affect our operations, our cost structure, or the demand for oil and gas.

On April 17, 2009, the U.S. Environmental Protection Agency, or “EPA,” issued a notice of its proposed finding and determination that emissions of carbon dioxide, methane, and other greenhouse gases, or “GHGs,” presented an endangerment to human health and the environment because emissions of such gases are, according to EPA, contributing to warming of the earth’s atmosphere. Once finalized, EPA’s finding and determination would allow it to begin regulating emissions of GHGs under existing provisions of the federal Clean Air Act. Although it may take EPA several years to adopt and impose regulations limiting emissions of GHGs, any limitation on emissions of GHGs from our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. In addition, on June 26, 2009, the U.S. House of Representatives passed House Bill 2454, also referred to as the “Waxman-Markey legislation” but formally named the “American Clean Energy and Security Act of 2009,” which would establish an economy-wide cap-and-trade program to reduce U.S. emissions of carbon dioxide and other GHGs by 17 percent from 2005 levels by 2020 and just over 80 percent by 2050. President Obama is encouraging the Senate to consider climate change legislation during the fall of 2009. Further, on September 21, 2009 a U.S. Federal appellate court reinstated a lawsuit filed by several state attorneys general and others against five of the largest U.S. electric utility companies alleging that those companies have created a public nuisance due to their emissions of carbon dioxide. Although it is not possible at this time to predict if and when the Senate may act on climate change legislation, how any bill passed by the Senate would be reconciled with House Bill 2454 or what effect, if any, the recent decision permitting a nuisance lawsuit to proceed against certain utilities may have on the oil and gas industry, any future federal laws or implementing regulations that may be adopted to address greenhouse gas emissions, as well as future climate change litigation against us or our customers for GHG emissions, could result in increased compliance costs or additional operating restrictions, and could have an adverse effect on demand for the oil and natural gas we produce.

Item 6 – Exhibits


EXHIBIT NO.		DESCRIPTION OF EXHIBIT

4.1		Indenture, dated as of September 28, 2009, between Goodrich Petroleum Corporation and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (File No. 001-12719) filed on September 30, 2009).

4.2		First Supplemental Indenture dated as of September 28, 2009, between Goodrich Petroleum Corporation and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K (File No. 001-12719) filed on September 30, 2009).

4.3		Form of 5.00% Convertible Senior Note due 2029 (included in Exhibit 4.2).

10.1		First Amendment to Amended and Restated Credit Agreement between Goodrich Petroleum Company, L.L.C. and BNP Paribas and Certain Lenders, dated as of September 22, 2009 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-12719) filed on September 28, 2009.

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

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

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

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

*	Filed herewith

**	Furnished herewith

SIGNATURES

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


	GOODRICH PETROLEUM CORPORATION (Registrant)

Date: November 5, 2009	By:	/S/ WALTER G. GOODRICH
		Walter G. Goodrich
		Vice Chairman & Chief Executive Officer

Date: November 5, 2009	By:	/S/ DAVID R. LOONEY
		David R. Looney
		Executive Vice President & Chief Financial Officer

GOODRICH PETROLEUM CORPORATION LIST OF EXHIBITS TO FORM 10-Q

FOR QUARTER ENDED SEPTEMBER 30, 2009


EXHIBIT NO.		DESCRIPTION OF EXHIBIT

4.1		Indenture, dated as of September 28, 2009, between Goodrich Petroleum Corporation and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (File No. 001-12719) filed on September 30, 2009).

4.2		First Supplemental Indenture dated as of September 28, 2009, between Goodrich Petroleum Corporation and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K (File No. 001-12719) filed on September 30, 2009).

4.3		Form of 5.00% Convertible Senior Note due 2029 (included in Exhibit 4.2).

10.1		First Amendment to Amended and Restated Credit Agreement between Goodrich Petroleum Company, L.L.C. and BNP Paribas and Certain Lenders, dated as of September 22, 2009 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-12719) filed on September 28, 2009.

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

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

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

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

*	Filed herewith

**	Furnished herewith

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company