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 March 31, 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.)

808 Travis, Suite 1320

Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

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

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

Indicate by check mark whether the registrant 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 May 4, 2009 was 37,621,020.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS


		Page
PART I	FINANCIAL INFORMATION
ITEM 1	FINANCIAL STATEMENTS
	Consolidated Balance Sheets as of March 31, 2009 and December 31, 2008	3
	Consolidated Statements of Operations for the three months ended March 31, 2009 and 2008	4
	Consolidated Statements of Cash Flows for the three months ended March 31, 2009 and 2008	5
	Notes to Consolidated Financial Statements	6
ITEM 2	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	14
ITEM 3	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	21
ITEM 4	CONTROLS AND PROCEDURES	22

PART II	OTHER INFORMATION	22
ITEM 1A	RISK FACTORS	22
ITEM 4	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	22
ITEM 5	OTHER INFORMATION	22
ITEM 6	EXHIBITS	23

PART 1 – FINANCIAL INFORMATION

Item 1 – Financial Statements

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(In thousands)

(Unaudited)


	March 31, 2009			December 31, 2008
				(as adjusted)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	78,320		$	147,548
Accounts receivable, trade and other, net of allowance		9,686			7,019
Accrued oil and gas revenue		10,329			15,595
Fair value of oil and gas derivatives		71,286			55,276
Assets held for sale		13			13
Prepaid expenses and other		1,568			2,778

Total current assets		171,202			228,229


PROPERTY AND EQUIPMENT:
Oil and gas properties (successful efforts method)		1,194,622			1,107,400
Furniture, fixtures and equipment		3,363			3,171

		1,197,985			1,110,571
Less: Accumulated depletion, depreciation and amortization		(339,191	)		(304,236	)

Net property and equipment		858,794			806,335
Deferred financing cost		3,316			3,723

TOTAL ASSETS	$	1,033,312		$	1,038,287


LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	46,566		$	41,462
Accrued liabilities		36,537			52,928
Deferred tax liability current		24,950			18,931
Income taxes payable		1,325			1,383
Fair value of interest rate derivatives		1,501			1,187
Accrued abandonment costs		2,691			2,554

Total current liabilities		113,570			118,445
LONG-TERM DEBT		228,563			226,723
Accrued abandonment costs		11,633			11,250
Deferred income tax liability		11,243			15,904
Fair value of interest rate derivatives		332			617

Total liabilities		365,341			372,939

Commitments and contingencies (See Note 11)
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 37,621,671 and 37,562,569 shares, respectively		7,199			7,188
Treasury stock (20,964 and 9,793 shares, respectively)		(637	)		(293	)
Additional paid in capital		601,077			599,753
Retained earnings		58,082			56,450

Total stockholders’ equity		667,971			665,348

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,033,312		$	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 March 31,
	2009			2008
				(as adjusted)
REVENUES:
Oil and gas revenues	$	28,440		$	46,197
Other		21			156

		28,461			46,353


OPERATING EXPENSES:
Lease operating expense		8,996			7,097
Production and other taxes		1,488			1,255
Transportation		2,588			1,870
Depreciation, depletion and amortization		33,658			25,085
Exploration		2,220			2,003
General and administrative		7,057			5,440

		56,007			42,750

Operating income (loss)		(27,546	)		3,603

OTHER INCOME (EXPENSE):
Interest expense		(5,208	)		(5,421	)
Interest income		239			—
Gain (loss) on derivatives not designated as hedges		37,006			(24,487	)

		32,037			(29,908	)


INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		4,491			(26,305	)
INCOME TAX EXPENSE		(1,354	)		—

INCOME (LOSS) FROM CONTINUING OPERATIONS		3,137			(26,305	)
DISCONTINUED OPERATIONS:
Gain on sale of assets, net of tax (See Note 10)		—			400
Income on discontinued operations, net of tax (See Note 9)		7			385

		7			785

NET INCOME (LOSS)		3,144			(25,520	)
PREFERRED STOCK DIVIDENDS		1,512			1,512

NET INCOME (LOSS) APPLICABLE TO COMMON STOCK	$	1,632		$	(27,032	)


NET INCOME (LOSS) PER COMMON SHARE-BASIC
INCOME (LOSS) FROM CONTINUING OPERATIONS	$	0.05		$	(0.88	)
DISCONTINUED OPERATIONS	$	—		$	0.03

NET INCOME (LOSS)	$	0.05		$	(0.85	)


NET INCOME (LOSS) PER COMMON SHARE-DILUTED
INCOME (LOSS) FROM CONTINUING OPERATIONS	$	0.05		$	(0.88	)
DISCONTINUED OPERATIONS	$	—		$	0.03

NET INCOME (LOSS)	$	0.05		$	(0.85	)


WEIGHTED AVERAGE COMMON SHARES OUTSTANDING-BASIC		35,970			31,705
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING-DILUTED		36,075			31,705

See accompanying notes to consolidated financial statements.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Three Months Ended March 31,
	2009			2008
				(as adjusted)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	3,144		$	(25,520	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities-
Depletion, depreciation, and amortization		33,658			25,085
Unrealized (gain) loss on derivatives not designated at hedges		(15,980	)		24,854
Deferred income taxes		1,358			—
Dry hole costs		101			—
Amortization of leasehold costs		1,524			1,564
Stock based compensation (non-cash)		1,631			1,267
Gain on sale of assets		—			(400	)
Amortization of debt discount and finance cost		2,247			2,104
Other non-cash		—			(21	)
Change in assets and liabilities:
Accounts receivable, trade and other, net of allowance		(2,667	)		(770	)
Deferred revenue		—			(12,500	)
Accrued oil and gas revenue		5,266			(6,260	)
Prepaid expense and other		1,170			517
Accounts payable		5,104			5,393
Accrued liabilities		(299	)		1,882

Net cash provided by operating activities		36,257			17,195


CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(103,314	)		(85,161	)
Proceeds from sale of assets		—			400

Net cash used in investing activities		(103,314	)		(84,761	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Principal payments of bank borrowings		—			(40,500	)
Proceeds from bank borrowings		—			109,000
Exercise of stock options and warrants		—			50
Debt issuance costs		—			(1,249	)
Preferred stock dividends		(1,512	)		(1,512	)
Other		(659	)		(3	)

Net cash provided by (used in) financing activities		(2,171	)		65,786

DECREASE IN CASH AND CASH EQUIVALENTS		(69,228	)		(1,780	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		147,548			4,448

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	78,320		$	2,668

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. The results of operations for the three months ended March 31, 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.

Assets Held for Sale—Assets Held for Sale as of March 31, 2009, represent our remaining assets in Plumb Bob field located in South Louisiana.

Income Taxes—We follow the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 109, Accounting for Income Taxes, (“SFAS 109”) as clarified by FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”), which requires income taxes be accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized.

New Accounting Pronouncements

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 (“SFAS 161”). SFAS 161 amends and expands the disclosure requirements of SFAS No. 133 by requiring enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. SFAS 161 is effective as of January 1, 2009. As SFAS 161 provides only disclosure requirements, the adoption of this standard does not have an impact on our results of operations, cash flows or financial positions. See Note 8.

On May 9, 2008, the FASB issued FASB Staff Position Accounting Principles Board (“APB”) 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlements) (“FSP APB 14-1”). FSP APB 14-1 requires the issuer of certain convertible debt instruments that may be settled in cash on conversion to separately account for the liability and equity components in a manner that reflects the issuer’s nonconvertible debt borrowing rate. The resulting debt discount would be amortized over the period the convertible debt is expected to be outstanding as additional non-cash interest expense. The effective date of FSP APB 14-1 is for financial statements issued for fiscal years beginning after December 15, 2008. FSP APB 14-1 did not permit earlier adoption, however it does require retrospective application to all periods presented in the financial statements (with the cumulative effect of the change reported in retained earnings as of the beginning of the first period presented). Our $175 million 3.25% convertible senior notes due 2026 (see Note 4) is affected by this new standard. Accordingly, we adopted the standard as of January 1, 2009. The retrospective application of this pronouncement affects years 2006 through 2008. See Note 2 for the retrospective adjustment to comparable financial statements.

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

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

We adopted FSP APB 14-1 on January 1, 2009. FSP APB 14-1 did not allow early adoption but does require that previously issued financial statements for comparability purposes be retrospectively adjusted for affect of the standard. The following tables reflect the retrospective application to the line items affected on previously issued financial statements.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

FSP APB 14-1 Adoption Retrospective Adjustments

(In thousands)

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			(1,128	)		599,753
Retained earnings		64,540			(8,790	)		700			56,450
Total stockholders’ equity		650,646			15,130			(428	)		665,348
Total Liabilities and Stockholders’ Equity	$	1,038,946		$	—		$	(659	)	$	1,038,287


Statement of Operations
	Three Months Ended March 31, 2008
	As Reported			Equity/ Debt Discount			Finance Cost Adjustment			As Adjusted
Interest Expense	$	(3,783	)	$	(1,694	)	$	56		$	(5,421	)
Loss from continuing operations before income taxes		(24,667	)		(1,694	)		56			(26,305	)
Loss from continuing operations		(24,667	)		(1,694	)		56			(26,305	)
Net loss		(23,882	)		(1,694	)		56			(25,520	)
Net loss applicable to common stock	$	(25,394	)	$	(1,694	)	$	56		$	(27,032	)

Net loss per Common Share-Basic
Loss from continuing operations	$	(0.78	)							$	(0.88	)
Net loss	$	(0.75	)							$	(0.85	)

Net loss per Common Share-Diluted
Loss from continuing operations	$	(0.78	)							$	(0.88	)
Net loss	$	(0.75	)							$	(0.85	)

NOTE 3—Asset Retirement Obligations

We apply SFAS No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”) which requires us to record the fair value of a liability associated with the retirement obligations of our tangible long-lived assets in the periods in which it is incurred. We capitalize the discounted fair value of the liability when initially incurred. The liability is accreted through accretion expense to its full fair value over the life of the long-lived asset. Accretion expense is included in depreciation, depletion and amortization on our consolidated statement of operations.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The reconciliation of the beginning and ending asset retirement obligation for the three months ended March 31, 2009, is as follows (in thousands):


Beginning balance, January 1, 2009	$	13,804
Liabilities incurred		258
Revision in estimated liabilities		35
Accretion expense		227

Ending balance, March 31, 2009		14,324
Less current portion		2,691

	$	11,633

The ending balance at March 31, 2009, includes $1.4 million related to Assets Held for Sale. See Note 10.

NOTE 4—Long-Term Debt

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


	March 31, 2009			December 31, 2008
				(as adjusted)
Senior Credit Facility	$	—		$	—
Second Lien Term Loan		75,000			75,000
3.25% convertible senior notes due 2026		175,000			175,000
Debt discount on convertible senior notes		(21,437	)		(23,277	)

Total long-term debt	$	228,563		$	226,723

Senior Credit Facility

In 2005, we amended our existing credit agreement and entered into an amended and restated senior credit agreement (as amended, the “2005 Senior Credit Facility”) and a term loan that expanded our borrowing capabilities. Total lender commitments under the 2005 Senior Credit Facility were $200 million, and the 2005 Senior Credit Facility matures on February 25, 2010. Revolving borrowings under the 2005 Senior Credit Facility are limited to, and subject to periodic redeterminations of the borrowing base. We paid off the total amount outstanding under the 2005 Senior Credit Facility in July 2008 with proceeds from our equity offering. Interest on revolving borrowings under the 2005 Senior Credit Facility accrues at a rate calculated, at our option, at the bank base rate plus 0.00% to 0.75%, or LIBOR plus 1.25% to 2.25%, depending on borrowing base utilization. At March 31, 2009, we had a borrowing base of $175 million and no amounts outstanding under the 2005 Senior Credit Facility.

Substantially all our assets are pledged as collateral to secure the 2005 Senior Credit Facility.

The terms of the 2005 Senior Credit Facility require us to maintain certain covenants. Capitalized terms used, but not defined, here have the meanings assigned to them in the 2005 Senior Credit Facility. As of March 31, 2009, we were in compliance with all of the financial covenants of our 2005 Senior Credit Facility. The covenants in effect at March 31, 2009 include:

•

Current Ratio of 1.0/1.0;

•

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

•

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

•

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

On May 5, 2009, we entered into a Second Amended and Restated Credit Agreement (“Senior Credit Facility”) which will replace the current facility. Total lender commitments under the Senior Credit Facility will be $350 million. The Senior Credit Facility will mature on October 1, 2010 and under certain conditions related to our refinancing of the Second Lien Term Loan can be extended to 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 convertible senior notes. 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 will accrue 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

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

The terms of the Senior Credit Facility will require us to maintain certain covenants. Capitalized terms used, but not defined, here have the meanings assigned to them in the Second amended Senior Credit Facility. The initial 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

•

Second Lien Term Loan

On January 16, 2008, we entered into a new Second Lien Term Loan Agreement which provides for a 3-year, secured, non-revolving loan of $75.0 million and is due in a single maturity on December 31, 2010. We had no rights to prepay in the first year. Voluntary prepayment rights in the second year are at 101% of par, and thereafter at par. Interest on the Second Lien Term Loan accrues at a rate of LIBOR plus 550 basis points and is payable quarterly in arrears. As of March 31, 2009, we were in compliance with all of the financial covenants of our Second Lien Term Loan. The terms of the Second Lien Term Loan Agreement contain financial covenants which include:

•

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

•

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

•

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

Convertible Senior Notes

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 will rank equally in right of payment to all of our other existing and future indebtedness. The notes accrue interest at a rate of 3.25% annually, and interest 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 adopted FSP APB 14-1 on January 1, 2009. FSP APB 14-1 requires that we separately account for the liability and equity components of our convertible senior notes in a manner that will reflect 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. This remaining amount of debt discount will continue to be amortized using the effective interest rate method based upon an original 5 year term through December 1, 2011.

NOTE 5—Net Income (Loss) Per Common Share

Net income (loss) applicable to common stock was used as the numerator in computing basic and diluted income (loss) per common share for the three months ended March 31, 2009 and 2008. The following table reconciles the weighted average shares outstanding used for these computations (in thousands):

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	For the Three Months Ended March 31,
	2009		2008
			(as adjusted)
	(Amounts in thousands, except per share data)
Basic income (loss) per share:
Income (loss) applicable to common stock	$	1,632	$	(27,032	)
Average shares of common stock outstanding (1)		35,970		31,705

Basic income (loss) per share:	$	0.05	$	(0.85	)

Income (loss) applicable to common stock	$	1,632	$	(27,032	)
Dividends on convertible preferred stock (2)		—		—
Interest and amortization of loan cost and debt discount on senior convertible notes, net of tax (3)		—		—

Diluted income (loss):	$	1,632	$	(27,032	)

Average shares of common stock outstanding (1)		35,970		31,705
Assumed conversion of convertible preferred stock (2)		—		—
Assumed conversion of convertible senior notes (3)		—		—
Stock options, warrants and restricted stock (4)		105		—

Average diluted shares outstanding		36,075		31,705

Diluted income (loss) per share	$	0.05	$	(0.85	)

(1)	This amount does not include 1,624,300 shares of common stock outstanding under the Share Lending Agreement.

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

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

(4)	Common shares issuable on assumed conversion of restricted stock and employee stock options for the three months ended March 31, 2008 in the amount of 105,645 shares were not included in the computation of diluted loss per common share since their inclusion would have not been dilutive.

NOTE 6—Income Taxes

We recorded tax expense in the amount of $1.4 million for the three months ended March 31, 2009, primarily as a result of the unrealized gain from commodity derivatives (See Note 8).

Our effective tax rate for the period is 30.2%. This differs from the federal statutory rate primarily due to the benefit for Louisiana net operating losses generated which are available for carryback to 2008.

As of March 31, 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 March 31, 2010.

NOTE 7—Stockholders’ Equity

Restricted Stock

During the three months ended March 31, 2009, we granted 6,675 shares of restricted stock with a weighted average value of $26.93 per share. During the same period, 79,909 restricted shares vested which had a weighted average grant date value of $21.85 per share.

Adoption of FSP APB 14-1 “Convertible Debt Instruments That May Be Settled in Cash Upon Conversion APIC”

FSP APB 14-1 requires the issuer of certain convertible debt instruments that may be settled in cash on conversion to separately account for the liability and equity components in a manner that reflects the issuer’s nonconvertible debt borrowing rate. As a result of the adoption of the standard, additional paid in capital was increased by $22.8 million, to reflect the deemed equity portion of the

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

convertible notes. We also recorded a beginning of period adjustment to retained earnings of $8.1 million, representing the cumulative effect on retained earnings of the retrospective application of FSP APB 14-1 relating to after tax interest expense.

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. In the year 2008, NYMEX Henry Hub natural gas price reached a high of $13.31 per MMbtu and at the end of April 2009 the price was down to $3.43 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 March 31, 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,

(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,

(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 March 31, 2009, our open forward positions on our outstanding commodity derivative contracts, all of which were with either BNP Paribas or Bank of Montreal, were as follows:


Collars (NYMEX)	Daily Volume	Total Volume	Floor/Cap Average Price	Fair Value at March 31, 2009
Natural gas (MMBtu)				$	24,395,606
2Q 2009	20,000	1,820,000	$8.75 - $13.10
3Q 2009	20,000	1,840,000	$8.75 - $13.10
4Q 2009	20,000	1,840,000	$8.75 - $13.10

Swaps (NYMEX)			Average Price
Natural gas (MMBtu)					24,606,969
2Q 2009	20,000	1,820,000	$8.83
3Q 2009	20,000	1,840,000	$8.83
4Q 2009	20,000	1,840,000	$8.83

Swaps (TexOk)			Field Price (1)
Natural gas (MMBtu)					22,368,324
2Q 2009	20,000	1,820,000	$7.87
3Q 2009	20,000	1,840,000	$7.87
4Q 2009	20,000	1,840,000	$7.87

Basis Swaps (NYMEX/TexOk)			Price (2)
Natural gas (MMBtu)					(85,064)
2Q 2009	40,000	3,640,000	$0.52
3Q 2009	40,000	3,640,000	$0.52
4Q 2009	40,000	3,640,000	$0.52

			Total	$	71,285,835

⁽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 $0.52 per MMBtu and pay Natural Gas Pipeline of America, TexOk zone price per MMBtu as published in the Inside FERC.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The fair value of the oil and gas commodity contracts in place at March 31, 2009, that are marked to market resulted in a net current asset of $71.3 million. For the three months ended March 31, 2009, we recognized in earnings a $37.1 million gain from these instruments, which consisted of $21.1 million in realized gains and $16.0 million in unrealized gains.

During the first quarter of 2009, we entered into basis swap contracts totaling 40,000 MMbtu/day for the period March to December 2009, as detailed above.

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.

Interest Rate Swaps

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. We have not designated this swap as a hedge. At March 31, 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	$	(612,761	)
4/22/2008	4/22/2010	3.19	%		50.0		(1,220,686	)

						$	(1,833,447	)

The fair value of the interest rate swap contract at March 31, 2009, resulted in a liability of $1.8 million which is reflected on the balance sheet as a current liability of $1.5 million and a noncurrent liability of $0.3 million. For the three months ended March 31, 2009, we recognized a $0.1 million loss from interest rate swaps.

NOTE 9—Fair Value of Financial Instruments

We adopted SFAS No. 157, Fair Value Measurements (“SFAS 157”), effective January 1, 2008 for financial assets and liabilities measured on a recurring basis. SFAS 157 applies to all financial assets and financial liabilities that are being measured and reported on a fair value basis. In February 2008, the FASB issued FSP No. 157-2, which delayed the effective date of SFAS 157 to January 1, 2009 for nonfinancial assets and liabilities. Fair value, as defined in SFAS 157, is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. As of January 1, 2009, SFAS 157 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 SFAS 157, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 SFAS 157 pricing levels as of March 31, 2009:


	Fair Value Measurement (in thousands)
Description	Level 1		Level 2			Level 3		Total
Current assets	$	—	$	71,286		$	—	$	71,286
Current liabilities		—		(1,501	)		—		(1,501	)
Non-current liabilities		—		(332	)		—		(332	)

Total	$	—	$	69,453		$	—	$	69,453

NOTE 10—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.” In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the results of operations for the properties that were sold and for the properties that are held for sale have been reflected as discontinued operations. St. Gabriel and Bayou Bouillon fields were sold in 2008. We will accept any reasonable offer on the Plumb Bob field.

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


	Three Months Ended March 31,
	2009		2008
Revenues	$	57	$	579
Expenses		46		194

Income from discontinued operations		11		385
Income tax expense		4		—

Income from discontinued operations, net of tax	$	7	$	385

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

NOTE 11—Commitments and Contingencies

We are party to lawsuits arising in the normal course of business. We intend to defend these actions vigorously and believe, based on currently available information, that adverse results or judgments from such actions, if any, will not be material to our consolidated financial position 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 of the Company, are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, that are dependent upon certain events, risks and uncertainties that may be outside the Company’s control, and which could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to:

•

planned capital expenditures;

•

future drilling activity;

•

our financial condition;

•

business strategy;

•

the market prices of oil and gas;

•

economic and competitive conditions;

•

legislative and regulatory changes; and

•

financial market conditions and availability of capital.

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

These factors, as well as additional factors that could affect our operating results and performance are described in our Annual Report on Form 10-K for the year ended December 31, 2008, 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: the 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.

1st Quarter 2009 financial and operating results include:

•

We increased our oil and gas production volumes on continuing operations to 75,753 Mcfe per day, representing an increase of 31% from 57,866 Mcfe per day for the first quarter of 2008.

•

We conducted drilling operations on 24 gross wells in the first quarter of 2009. The Haynesville Shale was penetrated by 13 of those wells.

•

We increased our net ownership in the Haynesville Shale play in Northwest Louisiana and East Texas to 63,000 net acres at March 31, 2009.

Cotton Valley Trend

Our relatively low-risk development drilling program in the Cotton Valley Trend is primarily centered in and around Rusk, Panola, Angelina and Nacogdoches counties, Texas, and DeSoto, Caddo and Bienville parishes, Louisiana. We have steadily increased our acreage position in these areas over the last three years to approximately 200,000 gross acres as of March 31, 2009. Through March 31, 2009, we have participated in the drilling and logging of 441 Cotton Valley Trend wells with a success rate in excess of 99%. We conducted drilling operations on 24 gross wells during the first quarter of 2009. Our net production volumes from our Cotton Valley Trend wells aggregated approximately 74,359 Mcfe per day in the first quarter of 2009, or approximately 30% higher than the Cotton Valley Trend production of the comparable prior year period.

Company Operated Haynesville Shale Drilling Program

We conducted drilling operations on three Haynesville horizontal wells that were in some form of drilling or completion by the quarter ended March 31, 2009. The Company expects to continue developing the Haynesville Shale through 2009 with the drilling and completion of approximately seven additional operated horizontal wells in East Texas and Northwest Louisiana. As of March 31, 2009, we had conducted drilling operations on a total of nine vertical operated wells that penetrated the Haynesville Shale, in addition to the three previously mentioned horizontal wells. 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 the Company’s acreage position. All nine wells had reached initial production by quarter end. 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.

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 March 31, 2009, we participated in drilling operations on ten horizontal and one vertical well under the joint development arrangement. As of quarter end, only three horizontal and one vertical well had reached initial production; with the remaining seven horizontal wells in some form of drilling or completion. For the remainder of 2009, the Company and Chesapeake plan to utilize two rigs to conduct drilling operations on approximately ten gross additional Haynesville Shale horizontal wells.

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 10 to our consolidated financial statements.

For the first quarter of 2009, we reported net income applicable to common stock of $1.6 million, or $0.05 per basic and diluted share, on total revenue from continuing operations of $28.5 million as compared to a net loss applicable to common stock of $27.0 million, or $0.85 per basic and diluted share, on total revenue from continuing operations of $46.4 million for first quarter of 2008. In conjunction with the fall of natural gas prices during the first quarter of 2009 we recorded

a $37.1 million gain on commodity derivatives not designated as hedges. This includes a realized gain of $21.1 million and an unrealized gain of $16.0 million. See discussions below under the captions “Gain (Loss) on Derivatives Not Designated as Hedges.”

Oil and Natural Gas Revenues

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

Summary Operating Information:


Continuing Operations	Three Months Ended March 31,
Continuing Operations	2009			2008			Variance
				(as adjusted)
Revenues:
Natural gas	$	26,919		$	42,460		$	(15,541	)	(37	)%
Oil and condensate		1,521			3,737			(2,216	)	(59	)%
Natural gas, oil and condensate		28,440			46,197			(17,757	)	(38	)%
Operating revenues		28,461			46,353			(17,892	)	(39	)%
Operating expenses		56,007			42,750			13,257		31	%
Operating income (loss)		(27,546	)		3,603			(31,149	)	—
Net income (loss) applicable to common stock		1,632			(27,032	)		28,664		—

Net Production:
Natural gas (MMcf)		6,545			5,033			1,512		30	%
Oil and condensate (MBbls)		45			39			6		15	%
Total (Mmcfe)		6,818			5,266			1,552		29	%
Average daily production (Mcfe/d)		75,753			57,866			17,887		31	%

Average realized sales price per unit:
Natural gas (per Mcf)	$	4.11		$	8.44		$	(4.33	)	(51	)%
Oil and condensate (per Bbl)		33.50			96.15			(62.65	)	(65	)%
Total (per Mcfe)		4.17			8.77			(4.60	)	(52	)%

Revenues from continuing operations decreased 39% in the first quarter of 2009 compared to the same period in 2008 due primarily to a substantial decrease in realized sale prices. Net production increased 29% period to period due to a substantial increase in the number of wells producing in the Cotton Valley Trend. The average realized sales price per unit decreased 52% over the prior year period.

Operating Expenses

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


	Three Months Ended March 31,
Operating Expenses (in thousands)	2009		2008		Variance
Lease operating expenses	$	8,996	$	7,097	$	1,899		27	%
Production and other taxes		1,488		1,255		233		19	%
Transportation		2,588		1,870		718		38	%
Depreciation, depletion and amortization		33,658		25,085		8,573		34	%
Exploration		2,220		2,003		217		11	%
General and administrative		7,057		5,440		1,617		30	%

	Three Months Ended March 31,
Operating Expenses per Mcfe	2009		2008		Variance
Lease operating expenses	$	1.32	$	1.35	$	(0.03	)	(2	)%
Production and other taxes		0.22		0.24		(0.02	)	(8	)%
Transportation		0.38		0.36		0.02		6	%
Depreciation, depletion and amortization		4.94		4.76		0.18		4	%
Exploration		0.33		0.38		(0.05	)	(13	)%
General and administrative		1.04		1.03		0.01		1	%

Lease Operating. Lease operating expense (“LOE”) for the first quarter of 2009 was $9.0 million, an increase of $1.9 million or 27% over the $7.1 million in the first quarter of 2008. On a per unit basis, the first quarter 2009 LOE decreased 2%

from $1.35 to $1.32 per Mcfe compared to the first quarter of 2008. The absolute increase is attributed to the increase in the number of wells producing as a result of our successful drilling program. The decrease in the unit cost between the first quarters of 2009 and 2008 recognizes our ongoing efforts to reduce major LOE components, including salt water disposal costs (“SWD”).

Production and Other Taxes. Production and other taxes of $1.5 million for the first quarter of 2009 includes production tax of $0.8 million and ad valorem tax of $0.7 million. Production tax included $0.4 million of accrued Tight Gas Sands (“TGS”) credits for our wells in the State of Texas. During the comparable period in 2008, production and other taxes were $1.3 million, which included production tax of $0.8 million and ad valorem tax of $0.5 million. Production tax in the first quarter of 2008 included $0.9 million in TGS credits.

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

Transportation. Transportation expense was $2.6 million ($0.38 per Mcfe) in the first quarter of 2009 compared to $1.9 million ($0.36 per Mcfe) in the first quarter of 2008. The increased expense is a function of our higher production volumes and a greater percentage of production coming from fields with higher transportation rates.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) expense increased to $33.7 million in the first quarter of 2009 from $25.1 million for the same period in 2008 primarily due to higher levels of production and a higher DD&A rate. The average DD&A rate for the first quarter of 2009 was $4.94 per Mcfe compared to $4.76 per Mcfe for the same quarter of 2008.

We calculated first quarter 2009 and 2008 DD&A rates using the December 31, 2008 and December 31, 2007 reserves, respectively. Proved developed natural gas reserves increased 39% from 108.1 Bcf at December 31, 2007 to 150.2 Bcf at December 31, 2008. Despite the increase in overall proved reserves period to period, the DD&A rate increased slightly due to the escalation of drilling costs experienced throughout the industry during 2008.

Exploration. Exploration expenses for the first quarter of 2009 increased $0.2 million to $2.2 million compared to $2.0 million in the same period in 2008. Included in the first quarter of 2009 is $0.1 million in dry hole cost resulting from an unsuccessful exploration tail of a successful development well. On a per unit basis exploration cost dropped to $0.33 per Mcfe in the first quarter of 2009 from $0.38 per Mcfe in the same period in 2008.

General and Administrative. General and administrative (“G&A”) expense increased 30% to $7.1 million in the first quarter of 2009 compared to $5.4 million in the same period in 2008. The $1.7 million increase period to period is primarily due to the increase in compensation cost relative to having a larger work force as the company headcount totaled 122 in the first quarter of 2009 versus 95 in the first quarter of 2008. G&A on a per unit basis increased only slightly to $1.04 per Mcfe from $1.03 per Mcfe as a result of a 38% increase in production volumes in 2009 as compared to 2008. Stock based compensation expense, which is a non-cash item, amounted to $1.6 million in the first quarter of 2009 compared to $1.3 million for the same period in 2008.

Other Income (Expense)

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


	Three Months Ended March 31,
	2009			2008
				(as adjusted)
Other income (expense):

Interest expense	$	(5,208	)	$	(5,421	)
Interest income		239			—
Gain (loss) on derivatives not designated as hedges		37,006			(24,487	)
Income tax expense		(1,354	)		—
Gain (loss) on disposal, net of tax		—			400
Income (loss) from discontinued operations, net of tax		7			385
Average funded borrowings		250,000			254,060
Average funded borrowings adjusted for debt discount		227,357			224,785
Weighted average interest rate		9.3	%		9.7	%

Interest Expense. Interest expense decreased $0.2 million to $5.2 million in the first quarter of 2009 compared to $5.4 million in the first quarter of 2008 as a result of the lower average level of funded debt in the first quarter of 2009. The first quarter 2008 interest expense amount has been retrospectively increased by $1.6 million (non-cash) as the result our adoption of FSP APB 14-1 “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion”, on January 1, 2009. Comparably, the adoption of the standard resulted in the recognition of an additional $1.8 million (non-cash) in interest expense in the first quarter of 2009.

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. Gain on derivatives not designated as hedges was $37.0 million for the first quarter of 2009, including a realized gain of $21.1 million and an unrealized gain of $16.0 million for the change in fair value of our natural gas commodity contracts. The decrease in natural gas prices experienced during the first quarter of 2009 led to substantial unrealized gains on our commodity contracts. The first quarter 2009 gain also included a loss of $0.1 million on our interest rate swap. As a comparison, the first quarter 2008 loss on derivatives not designated as hedges was $24.5 million including a realized gain of $0.3 million and an unrealized loss of $24.3 million for the changes in fair value of our commodity contracts. The first quarter of 2008 also includes a realized gain of $0.1 million and an unrealized loss of $0.6 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 expense on continuing operations of $1.4 million for the first quarter of 2009 includes a state income tax benefit of $0.2 million. In the first quarter of 2008, we provided for no income taxes as a result of having had a net deferred tax asset that was fully reserved.

Liquidity and Capital Resources

Cash Flows

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


	Three Months Ended March 31,
	2009			2008			Variance
Cash flow statement information:
Net cash:
Provided by operating activities	$	36,257		$	17,195		$	19,062
Used in investing activities		(103,314	)		(84,761	)		(18,553	)
Provided by (used in) financing activities		(2,171	)		65,786			(67,957	)

Increase (decrease) in cash and cash equivalents	$	(69,228	)	$	(1,780	)	$	(67,448	)

Operating activities. Net cash provided by operating activities increased $19.1 million to $36.3 million for the first three months of 2009, from $17.2 million for the comparable 2008 period due primarily to increased production levels and the realization of $21.0 million in hedging settlements during the quarter.

Investing activities. Net cash used in investing activities was $103.3 million for the first three months of 2009 compared to net cash used in investing activities of $84.8 million for the first three months of 2008. We conducted drilling operations on 24 gross wells, 13 of which penetrated the Haynesville Shale during the first three months of 2009. In comparison, we conducted drilling operations on 38 gross wells, all of which are located in our Cotton Valley Trend, during the first three months of 2008. The cost per well increased in 2009 compared to 2008 due to drilling more expensive Haynesville Shale wells. In 2008, we received proceeds of $0.4 million from sales of seismic data for our St. Gabriel field.

Financing activities. Net cash used in financing activities was $2.2 million for the three months ended March 31, 2009, versus net cash provided by financing activities of $65.8 million for the same period in 2008. In the first quarter of 2009 we had virtually no financing activities since we used cash flow and existing cash to fund our operations. In the first quarter of

2008, we borrowed $75.0 million on our Second Lien Term Loan and paid down a net of $6.5 million on our revolving credit facility, resulting in a net borrowing of $68.5 million.

For the year 2009, we have preliminarily 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. We expect to finance the remainder of our 2009 capital expenditures through a combination of cash flow from operations and from cash on hand.

Convertible Senior Notes

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

We adopted FSP APB 14-1 on January 1, 2009. FSP APB 14-1 requires that we separately account for the liability and equity components of our Convertible Senior Notes in a manner that will reflect 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. This remaining amount of debt discount will continue to be amortized using the effective interest rate method based upon an original 5 year term through December 1, 2011. We recognized debt discount amortization of $1.8 million in the three months ended March 31, 2009.

Senior Credit Facility

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

Substantially all our assets are pledged as collateral to secure the 2005 Senior Credit Facility.

The terms of the 2005 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. As of March 31, 2009, we were in compliance with all of the financial covenants of our 2005 Senior Credit Facility. The covenants in effect at March 31, 2009 include:

•

Current Ratio of 1.0/1.0;

•

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

•

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

On May 5, 2009, we entered into a Second Amended and Restated Credit Agreement (“Senior Credit Facility”) which will replace the current facility. Total lender commitments under the Senior Credit Facility will be $350 million. The Senior Credit Facility will mature on October 1, 2010 and under certain conditions related to our refinancing of the Second Lien Term Loan can be extended to August 31, 2011 and can be further extended to July 1, 2012 upon receipt of proceeds from a refinancing sufficient to prepay the convertible senior notes. Revolving borrowings under the Senior Credit Facility are limited to, and subject to periodic redeterminations of the borrowing base. The initial borrowing base will be established at $175 million. The borrowing base interest on revolving borrowings under Senior Credit Facility will accrue 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.

•

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

•

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

•

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

•

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

Capped Call Option Transactions

On December 10, 2007, we closed the public offering of 6,430,750 shares of our common stock at a price of $23.50 per share. Net proceeds from the offering were approximately $145.4 million after deducting the underwriters’ discount and estimated offering expenses. We used approximately $123.8 million of the net proceeds to pay off outstanding borrowings under our Senior Credit Facility, and approximately $21.6 million of the net proceeds to purchase capped call options on shares of our common stock from affiliates of BSC and J.P. Morgan Securities Inc. The capped call option transactions covered, subject to customary anti-dilution adjustments, approximately 5.8 million shares of our common stock, and each of them was divided into a number of tranches with differing expiration dates. Approximately 77,333 options per trading day will expire over each of three separate 25 consecutive trading day settlement periods beginning on May 18, 2009, November 16, 2009 and May 18, 2010, respectively. For more information on our Capped Call Option Transactions, 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 Cash Flows - Capped Call Option Transactions”.

Accounting Pronouncements

See Note 1 “Description of Business and Significant Accounting Policies” “New Accounting Pronouncements” to our consolidated financial statements for a discussion of recently issued pronouncements, including SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” and FASB Staff Position No. APB 14-1 “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion” which we adopted effective January 1, 2009.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based on consolidated financial statements which have been prepared in accordance with generally accepted accounting principles in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts or assets, liabilities, revenues and expenses. We believe that certain accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements. Our Annual Report on Form 10-K for the year ended December 31, 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 March 31, 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 March 31, 2009, resulted in a net current asset of $71.3 million. Based on oil and gas pricing in effect at March 31, 2009, a hypothetical 10% increase in oil and gas prices would have resulted in a derivative asset of $65.0 million while a hypothetical 10% decrease in oil and gas prices would have increased the derivative asset to $77.4 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 this swap as a hedge. At March 31, 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	$	(612,761	)
4/22/2008	4/22/2010	3.19	%		50.0		(1,220,686	)

						$	(1,833,447	)

The fair value of the interest rate swap contracts in place at March 31, 2009, resulted in a liability of $1.8 million. Based on interest rates at March 31, 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 March 31, 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 first 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

There are no material changes from risk factors previously disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008.

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

None.

Item 5 – Other Information

On May 5, 2009, we entered into a Second Amended and Restated Credit Agreement (“Senior Credit Facility”). Total lender commitments under the Senior Credit Facility will be $350 million. The Senior Credit Facility will mature on October 1, 2010 and under certain conditions related to our refinancing of the Second Lien Term Loan can be extended to August 31, 2011 and can be further extended to July 1, 2012 upon receipt of proceeds from a refinancing sufficient to prepay our convertible senior notes. Revolving borrowings under the Senior Credit Facility are limited to, and subject to periodic redeterminations of the borrowing base. The initial borrowing base will be established at $175 million. The borrowing base interest on revolving borrowings under the Senior Credit Facility will accrue 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. BNP Paribas is the lead lender and administrative agent under the Senior Credit Facility.

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

•

unrealized gains (losses) from derivatives. The 3.25% convertible senior notes are excluded from the calculation of Total Debt for the purpose of computing this ratio.).

Item 6 – Exhibits


*10.1		Second Amended and Restated Credit Agreement between Goodrich Petroleum Company, L.L.C. and BNP Paribas dated May 5, 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: May 7, 2009	By:	/s/ Walter G. Goodrich
		Walter G. Goodrich
		Vice Chairman & Chief Executive Officer

Date: May 7, 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 MARCH 31, 2009


EXHIBIT NO.		DESCRIPTION OF EXHIBIT
*10.1		Second Amended and Restated Credit Agreement between Goodrich Petroleum Company, L.L.C. and BNP Paribas dated May 5, 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

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Non-accelerated filer

Smaller reporting company