Edgar Filing: GOODRICH PETROLEUM CORP

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, 2008

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

Commission file number: 001-12719

GOODRICH PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Delaware

76-0466193

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

808 Travis, Suite 1320

Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

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

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

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

Large accelerated filer ¨ Accelerated filer x

Non-accelerated filer ¨ Smaller reporting company ¨

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

The number of shares outstanding of the Registrant’s common stock as of May 5, 2008 was 33,349,055.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS


		Page
PART I	FINANCIAL INFORMATION	3
ITEM 1	FINANCIAL STATEMENTS
	Consolidated Balance Sheet as of March 31, 2008 and December 31, 2007	3
	Consolidated Statements of Operations for the three months ended March 31, 2008 and 2007	4
	Consolidated Statements of Cash Flows for the three months ended March 31, 2008 and 2007	5
	Consolidated Statements of Comprehensive Income (Loss) for the three months ended March 31, 2008 and 2007	6
	Notes to Consolidated Financial Statements	7
ITEM 2	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	18
ITEM 3	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	26
ITEM 4	CONTROLS AND PROCEDURES	26

PART II	OTHER INFORMATION	28
ITEM 1	LEGAL PROCEEDINGS	28
ITEM 1A	RISK FACTORS	28
ITEM 2	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	28
ITEM 3	DEFAULTS UPON SENIOR SECURITIES	28
ITEM 4	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	28
ITEM 5	OTHER INFORMATION	28
ITEM 6	EXHIBITS	28

PART 1 – FINANCIAL INFORMATION

Item 1 – Financial Statements

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(In Thousands, Except Share Amounts)

(Unaudited)


	March 31, 2008			December 31, 2007
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2,668		$	4,448
Accounts receivable, trade and other, net of allowance		9,316			8,539
Accrued oil and gas revenue		18,460			12,200
Fair value of oil and gas derivatives		—			2,267
Assets held for sale		312			311
Prepaid expenses and other		501			904

Total current assets		31,257			28,669

PROPERTY AND EQUIPMENT:
Oil and gas properties (successful efforts method)		808,330			723,239
Furniture, fixtures and equipment		2,079			1,932

		810,409			725,171
Less: Accumulated depletion, depreciation and amortization		(194,374	)		(168,523	)

Net property and equipment		616,035			556,648

OTHER ASSETS:
Other		5,584			4,801

Total other assets		5,584			4,801

TOTAL ASSETS	$	652,876		$	590,118

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	42,360		$	36,967
Accrued liabilities		34,982			32,565
Fair value of interest rate derivatives		939			384
Fair value of oil and gas derivatives		14,685			—
Deferred revenue		—			12,500
Accrued abandonment costs		588			312

Total current liabilities		93,554			82,728
LONG-TERM DEBT		284,000			215,500
Accrued abandonment costs		6,047			5,868
Fair value of oil and gas derivatives		9,753			2,407

Total Liabilities		393,354			306,503

Commitments and contingencies (See Note 12)
STOCKHOLDERS’ EQUITY:
Preferred stock: 10,000,000 shares authorized: Series B convertible preferred stock, $1.00 par value, issued and outstanding 2,250,000 shares		2,250			2,250
Common stock: $0.20 par value, 100,000,000 and 50,000,000 shares authorized, respectively, issued and outstanding 33,344,963 and 34,821,317 shares, respectively:		6,344			6,340
Treasury stock (shares outstanding 3,615 and 16,359 respectively)		(6	)		(422	)
Additional paid in capital		341,979			341,098
Accumulated deficit		(91,045	)		(65,651	)

Total stockholders’ equity		259,522			283,615

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	652,876		$	590,118

See accompanying notes to consolidated financial statements.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

(Unaudited)


	Three Months Ended March 31,
	2008			2007
REVENUES:
Oil and gas revenues	$	46,197		$	23,317
Other		156			225

		46,353			23,542

OPERATING EXPENSES:
Lease operating expense		7,097			4,135
Production and other taxes		1,255			294
Transportation		1,870			1,075
Depreciation, depletion and amortization		25,085			17,708
Exploration		2,003			2,326
General and administrative		5,440			5,338

		42,750			30,876

Operating income (loss)		3,603			(7,334	)

OTHER EXPENSE
Interest expense		(3,783	)		(2,624	)
Loss on derivatives not designated as hedges		(24,487	)		(9,487	)

		(28,270	)		(12,111	)

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		(24,667	)		(19,445	)
INCOME TAX (EXPENSE) BENEFIT		—			6,743

INCOME (LOSS) FROM CONTINUING OPERATIONS		(24,667	)		(12,702	)
DISCONTINUED OPERATIONS
Gain on sale of assets, net of tax (See Notes 10 and 11)		400			10,913
Income on discontinued operations, net of tax (See Note 10)		385			2,825

		785			13,738

NET INCOME (LOSS)		(23,882	)		1,036
PREFERRED STOCK DIVIDENDS		1,512			1,512

NET INCOME (LOSS) APPLICABLE TO COMMON STOCK	$	(25,394	)	$	(476	)

NET INCOME (LOSS) PER COMMON SHARE-BASIC
INCOME (LOSS) FROM CONTINUING OPERATIONS	$	(0.78	)	$	(0.51	)
DISCONTINUED OPERATIONS	$	0.03		$	0.55

NET INCOME (LOSS)	$	(0.75	)	$	0.04

NET INCOME (LOSS) APPLICABLE TO COMMON STOCK	$	(0.80	)	$	(0.02	)

NET INCOME (LOSS) PER COMMON SHARE-DILUTED
INCOME (LOSS) FROM CONTINUING OPERATIONS	$	(0.78	)	$	(0.50	)
DISCONTINUED OPERATIONS	$	0.03		$	0.54

NET INCOME (LOSS)	$	(0.75	)	$	0.04

NET INCOME (LOSS) APPLICABLE TO COMMON STOCK	$	(0.80	)	$	(0.02	)

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING-BASIC		31,705			25,141
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING-DILUTED		31,705			25,386

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,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(23,882	)	$	1,036
Adjustments to reconcile net income (loss) to net cash provided by operating activities—
Depletion, depreciation, and amortization		25,085			17,708
Unrealized (gain) loss on derivatives not designated at hedges		24,854			13,124
Deferred income taxes		—			654
Dry hole costs		—			905
Amortization of leasehold costs		1,564			1,766
Stock based compensation (non-cash)		1,267			1,350
Gain on sale of assets		(400	)		(16,789	)
Other non-cash items		445			98
Change in assets and liabilities:
Accounts receivable, trade and other, net of allowance		(770	)		(331	)
Deferred revenue		(12,500	)		—
Accrued oil and gas revenue		(6,260	)		(260	)
Prepaid expenses and other		517			(263	)
Accounts payable		5,393			(3,049	)
Accrued liabilities		1,882			960

Net cash provided by operating activities		17,195			16,909

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(85,161	)		(63,543	)
Proceeds from sale of assets		400			74,029
Release of restricted cash funds		—			2,039

Net cash provided by (used in) investing activities		(84,761	)		12,525

CASH FLOWS FROM FINANCING ACTIVITIES:
Principal payments of bank borrowings		(40,500	)		(65,000	)
Proceeds from bank borrowings		109,000			38,500
Exercise of stock options and warrants		50			—
Debt issuance costs		(1,249	)		—
Preferred stock dividends		(1,512	)		(1,511	)
Other		(3	)		(35	)

Net cash provided by (used in) financing activities		65,786			(28,046	)

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(1,780	)		1,388
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		4,448			6,184

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	2,668		$	7,572

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
CASH PAID DURING THE PERIOD FOR INTEREST	$	830		$	1,000

CASH PAID DURING THE PERIOD FOR INCOME TAXES	$	20		$	—

See accompanying notes to consolidated financial statements.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In Thousands)

(Unaudited)


	For the Three Months Ended March 31,
	2008			2007
Net income (loss)	$	(23,882	)	$	1,036

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

Other comprehensive income (loss)		—			1,261

Comprehensive income (loss)	$	(23,882	)	$	2,297

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

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, 2007. The results of operations for the three ended March 31, 2008, are not necessarily indicative of the results to be expected for the full year.

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

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, 2008, represent our remaining assets in South Louisiana. These assets include the St. Gabriel, Bayou Bouillon and Plumb Bob fields.

Income Taxes—We follow the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 109, Accounting for Income Taxes, (“SFAS 109”) as clarified by FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”), which requires income taxes be accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. We have established a valuation allowance against our entire deferred tax asset balance and have not provided for any income taxes in the three months ended March 31, 2008.

New Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, Fair Value Measurements (“SFAS 157”), which establishes a single authoritative definition of fair value based upon the assumptions market participants would use when pricing an asset or liability and creates a fair value hierarchy that prioritizes the information used to develop these assumptions. Under the standard, additional disclosures are required, including disclosures of fair value measurements by level within the fair value hierarchy. SFAS 157 is effective for fair value measures already required or permitted by other standards for fiscal years beginning after November 15, 2007 and interim period within those fiscal years. FASB Staff Position (“FSP”) No. 157-2 (“FSP 175-2”) defers the effective date of SFAS 157 for non-financial assets and liabilities to fiscal years beginning after November 15, 2008. We have prospectively adopted SFAS 157 as of January 1, 2008, and this prospective adoption had an immaterial effect on our financial statements. See Note 9 “Fair Value of Financial Assets and Liabilities” for additional information regarding the adoption of SFAS 157.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 (“SFAS 161”). SFAS 161 amends and expands the disclosure requirements of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 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 of and gains and losses on

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. SFAS 161 will be effective as of January 1, 2009. As SFAS 161 provides only disclosure requirements, the adoption of this standard will not have a material impact on our results of operations, cash flows or financial positions.

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

NOTE 2— Share-Based Compensation Plans

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

We apply SFAS No. 123 (revised 2004), Share-Based Payment (“SFAS 123R”),which requires us to measure the cost of stock based compensation granted, including stock options and restricted stock, based on the fair market value of the award as of the grant date, net of estimated forfeitures. SFAS 123R supersedes SFAS 123 Accounting for Stock-Based Compensation and Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees.

The following table provides information about stock option activity for the three months ended March 31, 2008:


	Number of Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (Years)
Outstanding at December 31, 2007	949,333		$	20.95
Granted	162,000			21.59
Exercised	(10,000	)		4.96
Forfeited	—			—

Outstanding at March 31, 2008	1,101,333		$	21.19	7.18

Exercisable at March 31, 2008	633,334		$	19.56	6.97

Fair value of stock options granted			$	10.72

The estimated fair value of the options granted during the three months ended March 31, 2008 was calculated using a Black Scholes Merton option pricing model (“Black Scholes”). The following schedule reflects the various assumptions included in this model as it relates to the valuation of our options:


	Three Months Ended March 31, 2008
Risk free interest rate	3.52	%
Volatility	53.3	%
Dividend yield	0	%
Expected years until exercise	5

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

During the three months ended, March 31, 2008, we granted 239,003 restricted (phantom) shares under our 2006 Long-Term Incentive Plan to employees as normal annual awards. The following table summarizes information on restricted stock activity for the three months ended March 31, 2008:


	Number of Shares		Weighted Average Grant Date Fair Value Per Share
Unvested at December 31, 2007	108,251		$	33.60
Vested	(15,496	)		21.91
Granted	239,003			21.72
Forfeited	(1,966	)		28.13

Unvested at March 31, 2008	329,792

In the three months ended March 31, 2008, we recorded $1.3 million in stock compensation expense comprised of $0.5 million from stock options and $0.8 million from restricted (phantom) share plans. In the three months ended March 31, 2007, we recorded $1.4 million in stock compensation expense comprised of $0.7 million from stock options and $0.7 million from restricted (phantom) share plans.

NOTE 3—Asset Retirement Obligations

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

The reconciliation of the beginning and ending asset retirement obligation for the period ending March 31, 2008 is as follows (in thousands):


Beginning balance, January 1, 2008	$	6,180
Liabilities incurred		372
Accretion expense (reflected in depletion, depreciation and amortization expense)		83

Ending balance, March 31, 2008		6,635
Less current portion (including $0.3 million attributable to Assets Held for Sale)		588

	$	6,047

NOTE 4—Long-Term Debt

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


	March 31, 2008		December 31, 2007
Senior Credit Facility	$	34,000	$	40,500
Second Lien Term Loan		75,000		—
3.25% convertible senior notes due 2026		175,000		175,000

Total long-term debt	$	284,000	$	215,500

Senior Credit Facility

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

are limited to, and subject to periodic redeterminations of the borrowing base. On January 11, 2008, we entered into the Ninth Amendment to our Senior Credit Facility. The amendment included the reduction in the borrowing base to $150 million less 30% of the Second Lien Term Loan (discussed below) in excess of $50 million. At March 31, 2008, we had a borrowing base of $142.5 million under the Senior Credit Facility and we had $34.0 million in outstanding revolving borrowings under the Facility. Interest on revolving borrowings under the Senior Credit Facility accrues at a rate calculated, at our option, at the bank base rate plus 0.00% to 0.50%, or LIBOR plus 1.25% to 2.25%, depending on borrowing base utilization.

On May 7, 2008, the bank group established the new borrowing base at $175 million.

The terms of the Senior Credit Facility, as amended, require us to maintain certain covenants. Capitalized terms used, but not defined, here have the meanings assigned to them in the Senior Credit Facility. As of March 31, 2008, we were in compliance with all of the financial covenants of our Senior Credit Facility. The covenants in effect at March 31, 2008 include:

•

Current Ratio of 1.0/1.0,

•

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

•

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

Second Lien Term Loan

On January 16, 2008, we entered into a new Second Lien Term Loan Agreement which provides for a 3-year, non-revolving loan of $75.0 million and is due in a single maturity on December 31, 2010. There are 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 term loan borrowing accrues at a rate of LIBOR plus 550 basis points and is payable quarterly in arrears. As of March 31, 2008, we were in compliance with all of the financial covenants of our Second Lien Term Loan. The terms of the Second Lien Term Loan Agreement contain financial covenants which include:

•

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

•

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

•

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

Convertible Senior Notes

In December 2006, we sold $175 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 will be paid semi-annually on June 1 and December 1. Interest payments on the notes began on June 1, 2007.

Before December 1, 2011, the notes are not redeemable. On or after December 11, 2011, we may redeem for cash all or a portion of the notes, and the investors may require us to repurchase the notes on each of December 11, 2011, 2016 and 2021. The notes are convertible into shares of our common stock at a rate equal to the sum of:

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

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

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 5—Net Income (Loss) Per Common Share

Net income (loss) was used as the numerator in computing basic and diluted income (loss) per common share for the three months ended March 31, 2008 and 2007. The following table reconciles the weighted average shares outstanding used for these computations (in thousands):


	For the Three Months Ended March 31,
	2008	2007
Basic Method	31,705	25,141
Dilutive Stock Options and Restricted Stock	—	245

Dilutive Method	31,705	25,386

Common shares on assumed conversion of restricted and employee option stock 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 be anti-dilutive.

NOTE 6—Income Taxes

The Company did not record a tax benefit for the quarter ended March 31, 2008 which differs from the amount calculated at the statutory rate of 35% due to the increase in the valuation allowance of $8.4 million. In determining the carrying value of a deferred tax asset, SFAS 109 provides for the weighing of evidence in estimating whether and how much of a deferred tax asset may be recoverable. As we have incurred net operating losses in 2006 and prior years, relevant accounting guidance suggests that cumulative losses in recent years constitute significant negative evidence, and that future expectations about income are insufficient to overcome a history of such losses. We increased our valuation allowance and reduced our net deferred tax asset to zero during 2007 after considering all available positive and negative evidence related to the realization of our deferred tax asset. If we achieve profitable operations in the future, we may reverse a portion of the valuation allowance in an amount at least sufficient to eliminate any tax provision in that period. The valuation allowance has no impact on our net operating loss (“NOL”) position for tax purposes, and if we generate taxable income in future periods, we will be able to use our NOLs to offset taxes due at that time. The Company will continue to assess the valuation allowance against deferred tax assets considering all available evidence obtained in future reporting periods.

As of March 31, 2008, the Company had no unrealized tax benefits. There were no significant changes to the calculation since year end 2007. The Company does 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, 2009.

NOTE 7—Stockholders’ Equity

Share Lending Agreement

In connection with the offering of our 3.25% convertible senior notes we agreed to lend an affiliate of Bear, Stearns & Co. (“BSC”) a total of 3,122,263 shares of our common stock under the Share Lending Agreement. Under this agreement, BSC is entitled to offer and sell such shares and use the sale to facilitate the establishment of a hedge position by investors in the notes. BSC will receive all proceeds from such common stock offerings and lending transactions under this agreement. We will not receive any of the proceeds from these transactions. BSC is obligated to return the shares to us in the event of certain circumstances, including the redemption of our 3.25% convertible senior notes or the conversion of the notes to shares pursuant to the terms of the indenture governing the 3.25% convertible senior notes.

The Share Lending Agreement also requires collateral to be posted by BSC if its credit rating is below either A3 by Moody’s Investors Service (“Moody’s”) or A- by Standard and Poors (“S&P”). As a result of the long term ratings downgrade of BSC in March 2008, BSC was required to return all or a portion of the borrowed shares or collateralize the return obligation with cash or highly liquid non-cash collateral. On March 20, 2008, BSC had returned 1,497,963 shares of the 3,122,263 originally borrowed shares and fully collateralized the remaining 1,624,300 borrowed shares with a cash collateral deposit of approximately $41.3 million. This amount represents the market value of the remaining borrowed shares at March 20, 2008. Under the Share Lending Agreement, BSC is required to maintain collateral value in the amount at least

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

equal to the market value of the outstanding borrowed shares. The market value of the cash collateral deposit at March 31, 2008 was approximately $47.8 million. The 1,497,963 shares returned to the Company were recorded to Treasury stock and retired in March of 2008.

The 1,624,300 shares of common stock outstanding as of March 31, 2008, under the Share Lending Agreement are required to be returned to the Company in the future. The shares are treated in basic and diluted earnings per share as if they were already returned and retired. The shares of common stock lent under the Share Lending Agreement have no impact on the earnings per share calculation.

Capped Call Option Transactions

On December 10, 2007, we closed the public offering of 6,430,750 shares of our common stock at a price of $23.50 per share. Net proceeds from the offering were approximately $145.4 million after deducting the underwriters’ discount and estimated offering expenses. We used approximately $123.8 million of the net proceeds to pay off outstanding borrowings under our Senior Credit Facility, and approximately $21.6 million of the net proceeds to purchase capped call options on shares of our common stock from affiliates of BSC and J.P. Morgan Securities Inc. The capped call option transactions covered, subject to customary anti-dilution adjustments, approximately 5.8 million shares of our common stock, and each of them was divided into a number of tranches with differing expiration dates. One third of the options will expire over each of three separate multi-day settlement periods beginning approximately 18 months, 24 months and 30 months from the closing of the offering, respectively.

The capped call option transactions are expected to result in our receipt, on a net share, cashless basis of a certain number of shares of our common stock if the market value per share of the common stock, as measured under the terms of the capped call option agreements, on the option expiration date for the relevant tranche is greater than the lower call strike price of the capped call option transactions. We refer to the amount by which the market value per share exceeds the lower call strike price as an “in-the-money amount” for the relevant tranche of the capped call option transaction. The in-the-money amount will never exceed the difference between the upper call strike price and the lower call strike price (i.e., it will be “capped”). The lower call strike price is $23.50, which corresponds to the price to the public in the equity offering and the upper call strike price is $32.90, which corresponds to 140% of the price to the public in the offering. Both lower and upper call strike prices are subject to customary anti-dilution and certain other adjustments. The number of shares of our common stock that we will receive from the option counterparties upon expiration of each tranche of the capped call option transactions will be equal to the in-the-money amount of that tranche divided by the market value per share of the common stock, as measured under the terms of the capped call option agreements, on the option expiration date for that tranche. If the stock price is equal to the upper call strike price of $32.90 on each of the settlement dates, we will recoup up to 1.6 million shares.

The capped call option agreements were separate transactions entered into by us with the option counterparties and were not part of the terms of the offering of common stock.

The capped call option agreements require an option counterparty to transfer their rights and obligations within 30 days if their credit rating is below either Baa1 by Moody’s or BBB+ by S&P. As a result of the downgrade of BSC on March 14, 2008, BSC was obligated to transfer their rights and obligations under the capped call option agreement to a suitable counterparty (one with a credit rating of at least BBB+ by S&P and Baa1 by Moody’s) within 30 days. As a result of a ratings upgrade of BSC by S&P on March 24, 2008, the obligation to transfer their rights and obligations to an entity with a higher credit rating was cured.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 8—Derivative Activities

Commodity Derivative Activity

We enter into swap contracts, costless collars and other derivative agreements from time to time to manage the commodity price risk for a portion of our production. Our strategy, which is administered by the Hedging Committee of our Board of Directors, and reviewed periodically by the entire Board of Directors, has been to generally hedge between 30% and 70% of our estimated total production for the period the hedges are in effect. As of March 31, 2008, the commodity derivatives we used were in the form of:

•

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

•

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

•

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

We account for our commodity derivative contracts in accordance with SFAS 133. SFAS 133 requires each derivative to be recorded on the balance sheet as an asset or liability at its fair value. Additionally, the statement requires that changes in a derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met at the time the derivative contract is executed. The Company has elected not to apply hedge accounting treatment to our swaps and collars and as such all changes in the fair value of these instruments are recognized in earnings. Our fixed price physical contracts qualify for the normal purchase and normal sale exception. Contracts that qualify for this treatment do not require mark-to-market accounting treatment.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of March 31, 2008, our open forward positions on our outstanding commodity derivative contracts, all of which were with either BNP Paribas, Bank of Montreal or Comerica was as follows:


Fixed Price Physical Contracts	Daily Volume	Total Volume	Average Field Price (1)
Natural gas (MMBtu)
2Q 2008	28,500	2,593,500	$	8.05
3Q 2008	28,500	2,622,000	$	8.05
4Q 2008	28,500	2,317,000	$	8.04
Collars			Floor/Cap (NYMEX)		Fair Value at March 31, 2008
Natural gas (MMBtu)					$	(7,042,934	)
2Q 2008	10,000	910,000	$	8.00 –$10.20
3Q 2008	10,000	920,000	$	8.00 –$10.20
4Q 2008	10,000	920,000	$	8.00 –$10.20
1Q 2009	10,000	900,000	$	8.00 – $9.30
2Q 2009	10,000	910,000	$	8.00 – $9.30
3Q 2009	10,000	920,000	$	8.00 – $9.30
4Q 2009	10,000	920,000	$	8.00 – $9.30

Swaps (NYMEX)			Average Price
Natural gas (MMBtu)						(7,518,372	)
2Q 2008	5,000	455,000	$	8.69
3Q 2008	5,000	460,000	$	8.69
4Q 2008	5,000	155,000	$	8.69
1Q 2009	20,000	1,800,000	$	8.83
2Q 2009	20,000	1,820,000	$	8.83
3Q 2009	20,000	1,840,000	$	8.83
4Q 2009	20,000	1,840,000	$	8.83

Swaps(TexOk)			Field Price (2)
Natural gas (MMBtu)						(9,876,573	)
1Q 2009	20,000	1,800,000	$	7.87
2Q 2009	20,000	1,820,000	$	7.87
3Q 2009	20,000	1,840,000	$	7.87
4Q 2009	20,000	1,840,000	$	7.87

				Total	$	(24,437,879	)

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

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

The fair value of the commodity derivative contracts in place at March 31, 2008 that are marked to market, resulted in a net liability of $24.4 million. For the three months ended March 31, 2008, we recognized in earnings a $24.0 million loss from these instruments, which consisted of $0.3 million in realized gains and $24.3 million in unrealized losses.

During the first quarter of 2008 we entered into the following NYMEX priced natural gas derivative contracts:

•

5,000 Mmbtu/day swap with a price of $8.69 per Mmbtu for the period April to October 2008,

•

15,000 Mmbtu/day swap with a price of $8.81 per Mmbtu for calendar year of 2009,

•

5,000 Mmbtu/day swap with a price of $8.90 per Mmbtu for the calendar year of 2009, and

•

10,000 Mmbtu/day collar per with a floor and ceiling price of $8.00 and $9.30 per Mmbtu, respectively, for the calendar year of 2009.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

During the first quarter of 2008, we also entered into a physical sales contract for 5,000 Mmbtu/day for the period April to October 2008. The field delivery price of $8.13 per Mmbtu is comparable to a NYMEX price of approximately $8.26 per Mmbtu.

Interest Rate Swaps

We have several variable-rate debt obligations that expose us to the effects of changes in interest rates. To partially reduce our exposure to interest rate risk, from time to time we enter into interest rate swap agreements. At March 31, 2008, we had the following interest rate swap in place with BNP Paribas:


Effective Date	Maturity Date	Libor Swap Rate		Notional Amount (Millions)		Fair Value (Dollars)
Effective Date	Maturity Date	Libor Swap Rate		Notional Amount (Millions)		Fair Value (Dollars)
2/27/2007	2/26/2009	4.86	%	$	40.0	$	938,768

For the three months ended March 31, 2008, we recognized a $0.5 million loss from the interest rate derivative which is not designated as a hedge.

We have entered into interest rate derivative swap agreements subsequent to March 31, 2008, whereby we have contracted an additional notional amount of $75 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.

NOTE 9—Fair Value of Financial Instruments

We adopted SFAS 157 effective January 1, 2008 for financial assets and liabilities measured on a recurring basis. SFAS 157 applies to all financial assets and financial liabilities that are being measured and reported on a fair value basis. In February 2008, the FASB issued FSP 157-2, which delayed the effective date of SFAS 157 to fiscal years beginning after November 15, 2008 for nonfinancial assets and liabilities. Fair value, as defined in SFAS 157, is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. SFAS 157 affects the Company in the fair value measurement of the commodity and interest rate derivative positions which must be classified in one of the following categories:

Level 1 Inputs

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

Level 2 Inputs

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

Level 3 Inputs

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

As required by SFAS 157, financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the valuation of our financial instruments by SFAS 157 input levels as of March 31, 2008:


	Fair Value Measurement (in thousands)
Description (Liabilities)	Level 1		Level 2		Level 3		Total
Current liabilites	$	—	$	15,624	$	—	$	15,624
Non-current liabilites		—		9,753		—		9,753

Total	$	—	$	25,377	$	—	$	25,377

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. We are actively considering bids and will accept any reasonable offer on the three remaining properties.

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


	Three Months Ended March 31,
	2008		2007
Revenues		579		8,603
Expenses		194		4,257

Income from discontinued operations		385		4,346
Income tax expense		—		(1,521	)

Income from discontinued operations, net of tax	$	385	$	2,825

The following presents the main classes of assets and liabilities associated with long-lived assets classified as held for sale (in thousands):


	As of March 31, 2008
Assets held for sale	$	312
Accrued abandonment costs		276

NOTE 11—Acquisitions and Divestitures

In February 2008, we acquired additional acreage located in the Angelina River trend for $2.5 million from a private company. We acquired an additional 40% working interest in the James Lime rights in our Bethune area, and an additional 31.25% working interest in the James Lime rights in our Allentown area. After the drilling of the second Allentown well, we will earn an additional 6.25% working interest in the James Lime for a total working interest of 93.75%.

In March, 2008, we sold seismic data related to the St. Gabriel Field (treated as held for sale at March 31, 2008) for $0.4 million. We had no basis in the data and consequently the entire proceeds of $0.4 million was recorded as a gain (See Note 10).

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 12—Commitments and Contingencies

We are party to lawsuits arising in the normal course of business. We intend to defend these actions vigorously and believe, based on currently available information, that adverse results or judgments from such actions, if any, will not be material to our consolidated financial position, results of operations or liquidity. No significant changes to these type lawsuits have occurred since December 31, 2007.

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

Forward-Looking Statements

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

•

planned capital expenditures;

•

future drilling activity;

•

our financial condition;

•

continued availability of debt and equity financing;

•

business strategy;

•

the market prices of oil and gas;

•

economic and competitive conditions;

•

legislative and regulatory changes; and

•

financial market conditions.

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

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

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

Overview

General

We are an independent oil and gas company engaged in the exploration, exploitation, development and production of oil and natural gas properties primarily in the Cotton Valley Trend of East Texas and Northwest Louisiana.

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

Source of Revenues

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

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

First Quarter 2008 financial and operating results include:

•

We increased our oil and gas production volumes on continuing operations to approximately 57,866 Mcfe per day, representing an increase of 55% from the first quarter of 2007.

•

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

•

We entered into a $75.0 million Second Lien Term Loan in January 2008.

•

We reduced our total operating expenses by over $1.00 per Mcfe from first quarter 2007 to first quarter 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 steadily increased our acreage position in these areas over the last two years to approximately 187,000 gross acres as of March 31, 2008. Through March 31, 2008, we have participated in the drilling and logging of 300 Cotton Valley Trend wells with a success rate in excess of 99%. We conducted drilling operations on 38 gross wells during the first quarter of 2008. Our net production volumes from our Cotton Valley Trend wells aggregated approximately 57,800 Mcfe per day in the first quarter of 2008, or approximately 55% higher than the Cotton Valley Trend production of the comparable prior year period.

Sale of South Louisiana Assets

On March 20, 2007, we completed the sale of substantially all of our assets in South Louisiana to a private company. The sale resulted in total proceeds of $72.5 million, net to the Company, after normal closing adjustments. The effective date of the sale was July 1, 2006. The remaining fields treated as held for sale are St. Gabriel, Bayou Bouillon and Plumb Bob.

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

Results of Operations

Our financial statements include discontinued operations presentation for our assets located in South Louisiana. See Note 9 to our consolidated financial statements.

For the three months ended March 31, 2008, we reported a net loss applicable to common stock of $25.4 million, or $0.80 per basic share, on total revenue from continuing operations of $46.4 million as compared with a net loss applicable to common stock of $0.5 million, or $0.02 per basic share, on total revenue from continuing operations of $23.5 million for the three months ended March 31, 2007. We recorded a $24.7 million loss on derivatives not designated as hedges in the first quarter of 2008. See our discussion below under the caption “Loss on Derivatives Not Designated as Hedges.”

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.


	Three Months Ended March 31, 2008
Summary Operating Information: Continuing Operations	2008			2007			Variance
	(In thousands, except for price data)
Revenues:
Natural gas	$	42,460		$	21,862		$	20,598		94	%
Oil and condensate		3,737			1,455			2,282		157	%
Natural gas, oil and condensate		46,197			23,317			22,880		98	%
Operating revenues		46,353			23,542			22,811		97	%
Operating expenses		42,750			30,876			11,874		38	%
Operating income (loss)		3,603			(7,334	)		10,937		149	%
Net income (loss) applicable to common stock		(25,394	)		(476	)		(24,918	)	(5235	)%

Net Production:
Natural gas (MMcf)		5,033			3,195			1,838		58	%
Oil and condensate (MBbls)		39			26			13		50	%
Total (Mmcfe)		5,266			3,351			1,915		57	%
Average daily production		57,866			37,233			20,633		55	%

Average realized sales price per unit:
Natural gas (per Mcf)	$	8.44		$	6.84		$	1.60		23	%
Oil and condensate (per Bbl)		96.15			56.68			39.47		70	%
Total (per Mcfe)		8.77			6.96			1.81		26	%

Revenues from continuing operations increased 98% in the first quarter of 2008 compared to the same period in 2007 due primarily to a substantial increase in Cotton Valley Trend production and higher natural gas prices. Production from continuing operations increased 57% 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 increased 26% over the prior year period.

Operating Expenses

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


	Three Months Ended March 31,
	2008		2007		Variance
Operating Expenses per Mcfe
Lease operating expenses	$	1.35	$	1.23	$	0.12		10	%
Production and other taxes		0.24		0.09		0.15		167	%
Transportation		0.36		0.32		0.04		13	%
Depreciation, depletion and amortization		4.76		5.28		(0.52	)	(10	)%
Exploration		0.38		0.69		(0.31	)	(45	)%
General and administrative		1.03		1.59		(0.56	)	(35	)%

Lease Operating. Lease operating expense (“LOE”) for the first quarter of 2008 increased $3.0 million on an absolute basis ($7.1 million compared to $4.1 million) and ten percent on a per unit basis compared to prior year quarter ($1.35 per Mcfe compared to $1.23 per Mcfe). The first quarter of 2008 includes $1.0 million in workover costs which accounted for $0.18 of the total LOE per Mcfe rate of $1.35. In the prior year quarter, workover costs of $0.1 million accounted for $0.04 and abandonment costs accounted for $0.02 of the total LOE per Mcfe rate of $1.23. Excluding the impact of workover and abandonment costs, the LOE rate was $1.17 per Mcfe for both periods.

Production and Other Taxes. Production and other taxes of $1.3 million for the first quarter of 2008 includes production tax of $0.8 million and ad valorem tax of $0.4 million. Production taxes during the quarter are net of $0.9 million of accrued Tight Gas Sands (“TGS”) credits for our wells in the State of Texas, which credits equate to $0.17 per Mcfe of production. During the comparable period in 2007, production and other taxes of $0.3 million were net of TGS credits of $0.8 million, or $0.24 per Mcfe of production, due largely to a greater number of backlogged TGS credits being approved by the State of Texas during the first quarter of 2007.

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

Transportation. Transportation expense was $1.9 million ($0.36 per Mcfe) in the first quarter of 2008 compared to $1.1million ($0.32 per Mcfe) in the first quarter of 2007. The increased expense was 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 $25.1 million in the first quarter of 2008 from $17.7 million for the same period in 2007, primarily due to higher levels of production partially offset by a lower DD&A rate. The average DD&A rate for the first quarter of 2008 was $4.76 per Mcfe compared to $5.28 per Mcfe for the same quarter of 2007.

We calculated first quarter 2008 and 2007 DD&A rates using the December 31, 2007 and December 31, 2006 reserves, respectively. Proved developed reserves increased 25% from 87.9 Bcfe at December 31, 2006 to 109.8 Bcfe at December 31, 2007. The favorable impact of our 2007 Cotton Valley Trend drilling program and positive revisions of previous estimates from December 31, 2006 to December 31, 2007, led to the increase in proved developed reserves.

Exploration. Exploration expenses for the first quarter of 2008 decreased to $2.0 million ($0.38 per Mcfe) from $2.3 million ($0.69 per Mcfe) for the first quarter of 2007, due primarily to a decrease in the amortization of undeveloped leasehold costs, from $1.8 million in the first quarter of 2007 to $1.6 million in the first quarter of 2008.

General and Administrative. General and administrative (“G&A”) expense decreased 35% on a per unit basis to $1.03 per Mcfe in the first quarter 2008 compared to $1.59 per Mcfe in 2007 primarily due to a 57% increase in production volumes in 2008. Costs remained relatively flat at $5.4 million versus $5.3 million for the first quarter of 2008 and 2007, respectively. Stock based compensation expense, which is a non-cash item, amounted to $1.3 million for the first quarter of 2008 versus $1.4 million for the prior year period.

Other Income (Expense)

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


	Three Months Ended March 31,
	2008		2007
Other income (expense):
Interest expense	(3,783	)	(2,624	)
Loss on derivatives not designated as hedges	(24,487	)	(9,487	)
Income tax (expense) benefit	—		6,743

Average total borrowings	254,060		219,483
Weighted average interest rate	6.0	%	4.8	%

Interest Expense. Interest expense increased to $3.8 million in the first quarter of 2008 compared to the first quarter of 2007 amount of $2.6 million as a result of the higher average level of total borrowings in 2008, and an increase in the weighted average interest rate.

Loss on Derivatives Not Designated as Hedges. Loss on derivatives not designated as hedges was $24.5 million in the first quarter of 2008, including a realized gain of $0.3 million and an unrealized loss of $24.3 million for the change in fair value of our natural gas commodity contracts. The increases in natural gas prices experienced during the period resulted in an unrealized loss on 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. As a comparison, the first quarter of 2007 included an unrealized loss of $13.2 million for the change in fair value of our commodity contracts and a realized gain of $3.7 million. The first quarter of 2007 also included a realized gain of $0.1 million and an unrealized loss of $0.1 million on our interest rate swap.

Income taxes. We increased our valuation allowance and reduced our net deferred tax asset to zero during 2007 after considering all available positive and negative evidence related to the realization of our deferred tax asset. As a result, we did not provide for income taxes on continuing operations in the first quarter of 2008. Income taxes were a benefit of $6.7 million for the first quarter of 2007 and represented approximately 35% of pre-tax loss from continuing operations.

Discontinued Operations

In a sale that closed March 20, 2007, we sold our assets in South Louisiana to a private company. We have presented comparative data for our discontinued operations below (in thousands):


	Three Months Ended March 31,
Discontinued Operations	2008		2007
Net Production:
Natural gas (MMcf)		7		521
Oil and condensate (MBbls)		2		82
Total (MMcfe)		19		1,013
Average Daily Net Production (Mcfe)		212		11,256

Gain (loss) on disposal, net of tax	$	400	$	10,913
Income (loss) from discontinued operations, net of tax		385		2,825
Total income (loss), net of tax	$	785	$	13,738

We realized a gain on disposal, net of tax, of $10.9 million in the first quarter of 2007. Our remaining South Louisiana assets, the St. Gabriel, Bayou Bouillon and Plumb Bob fields, were considered held for sale at March 31, 2008. In March 2008, we sold seismic related to the St. Gabriel field and recognized a gain on disposal of $0.4 million.

Income from discontinued operations for the three months ended March 31, 2008 and 2007 related to our South Louisiana assets. The first quarter of 2007 includes income from sold properties through the date of closing – March 20, 2007. The first quarter of 2008 includes income from assets held for sale only.

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,
	2008			2007			Variance
Cash flow statement information:
Net cash:
Provided by operating activities	$	17,195		$	16,909		$	286
Provided by (used in) investing activities		(84,761	)		12,525			(97,286	)
Provided by (used in) financing activities		65,786			(28,046	)		93,832

Increase (decrease) in cash and cash equivalents	$	(1,780	)	$	1,388		$	(3,168	)

Operating activities. Net cash provided by operating activities increased $0.3 million to $17.2 million for the first three months of 2008, from $16.9 million for the comparable 2007 period. Our cash flows before working capital changes were up from $19.9 million in the first three months of 2007 to $28.9 million in the first three months of 2008 as a result of increased production volumes from continuing operations and higher natural gas prices. Net cash provided by operating activities in the first quarter of 2008 was reduced by $12.5 million due to the prepay transaction arranged with a physical gas purchaser prior to year end 2007. The physical volumes associated with this transaction were all delivered in the first quarter of 2008.

Investing activities. Net cash used in investing activities was $84.8 million for the first three months of 2008 compared to net cash provided by investing activities of $12.5 million for the first three months of 2007. Much of this change can be traced to the net proceeds of $74.0 million from the sale of substantially all of our South Louisiana assets in the first quarter of 2007. Total capital expenditures of $84.7 million for the first three months of 2008 were up 33% compared to the 2007

amount of $63.5 million. 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. In comparison, we conducted drilling operations on only 19 gross wells, all located in our Cotton Valley Trend during the first three months of 2007. In 2008, we received proceeds of $0.4 million from sales of seismic data for our St. Gabriel field. The St. Gabriel field is treated as an Asset Held for Sale at March 31, 2008.

Financing activities. Net cash provided by financing activities was $65.8 million for the three months ended March 31, 2008 versus net cash used in financing activities of $28.0 million for the same period in 2007. 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 in the first quarter of 2008. In the first quarter of 2007, we used proceeds from the sale of properties to pay the full outstanding balance on our existing bank credit facility, which had increased to $65.0 million by the time we received these proceeds.

In December 2007, our Board of Directors approved a preliminary 2008 capital expenditure budget of approximately $275 million to fund our development drilling program, lease acquisitions and installation of infrastructure in the Cotton Valley Trend. Through March 31, 2008, we have expended approximately $85.6 million of our 2008 capital expenditure budget. We expect to finance the remainder of our 2008 capital expenditures through a combination of cash flow from operations and borrowings under our existing bank credit facility (see “Senior Credit Facility”).

In the first quarter, we entered into a $75.0 million Second Lien Term Loan. We intend to use the remaining borrowing base of our Senior Credit Facility, the Second Lien Term Loan and cash flow from operations to fund our ongoing drilling activity. Our existing credit facilities include certain financial covenants with which we were in compliance as of March 31, 2008. When considering the historical success of our capital raising activities and our bank relationships, we do not anticipate a lack of borrowing capacity under our senior credit facility in the foreseeable future due to an inability to meet any such financial covenants nor a reduction in our borrowing base.

3.25% Convertible Senior Notes

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

Share Lending Agreement

collateral deposit of approximately $41.3 million. This amount represents the market value of the remaining borrowed shares at March 20, 2008. Under the Share Lending Agreement, BSC is required to maintain collateral value in the amount at least equal to the market value of the outstanding borrowed shares. The market value of the cash collateral deposit at March 31, 2008 was approximately $47.8 million. The 1,497,963 shares returned to the Company were recorded to Treasury stock and retired in March of 2008.

Senior Credit Facility

On November 17, 2005, we amended our existing credit agreement and entered into an amended and restated senior credit agreement (as amended, the “Senior Credit Facility”) and a term loan that expanded our borrowing capabilities and extended our credit facility for an additional two years. Total lender commitments under the Senior Credit Facility were $200 million, and the Senior Credit Facility matures on February 25, 2010. Revolving borrowings under the Senior Credit Facility are limited to, and subject to periodic redeterminations of the borrowing base. On January 11, 2008, we entered into the Ninth Amendment to our Senior Credit Facility. The amendment included the reduction in the borrowing base to $150 million less 30% of the Second Lien Term Loan (discussed below) in excess of $50 million. At March 31, 2008, we had a borrowing base of $142.5 million under the Senior Credit Facility and we had $34.0 million in outstanding revolving borrowings under the Facility. Interest on revolving borrowings under the Senior Credit Facility accrues at a rate calculated, at our option, at the bank base rate plus 0.00% to 0.50%, or LIBOR plus 1.25% to 2.25%, depending on borrowing base utilization.

On May 7, 2008, the bank group established the new borrowing base at $175 million.

•

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

Second Lien Term Loan

•

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

•

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

•

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

Capped Call Option Transactions

The capped call option agreements were separate transactions entered into by us with the option counterparties and were not part of the terms of the offering of common stock.

The capped call option agreements require an option counterparty to transfer their rights and obligations within 30 days if their credit rating is below either Baa1 by Moody’s or BBB+ by S&P. As a result of the downgrade of BSC on March 14, 2008, BSC was obligated to transfer their rights and obligations under the capped call option agreement to a suitable counterparty (one with a credit rating of at least BBB+ by S&P and Baa1 by Moody’s within 30 days. As a result of a ratings upgrade of BSC by S&P on March 24, 2008, the obligation to transfer their rights and obligations to an entity with a higher credit rating was cured.

Accounting Pronouncements

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

Critical Accounting Policies and Estimates

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

Item 3 – Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

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

We enter into futures contracts or other derivative arrangements from time to time to manage the commodity price risk for a portion of our production. Our strategy, which is administered by the Hedging Committee of our Board of Directors, and reviewed periodically by the entire Board of Directors, has been to generally hedge between 30% and 70% of our production. As of March 31, 2008, the commodity contracts we used were in the form of:

•

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

•

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

•

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

Our commodity contracts fall within our targeted range of 30% to 70% of our estimated net oil and gas production volumes for the applicable periods of 2008. The fair value of the natural gas commodity contracts in place at March 31, 2008, resulted in a net liability of $24.4 million. Based on oil and gas pricing in effect at March 31, 2008, a hypothetical 10% increase in oil and gas prices would have resulted in a derivative liability of $39.5 million while a hypothetical 10% decrease in oil and gas prices would have decreased the derivative liability to $4.0 million. See Note 8 “Derivative Activities” to our consolidated financial statements for additional information.

Interest Rate Risk

We have a variable-rate debt obligation that exposes us to the effects of changes in interest rates. To partially reduce our exposure to interest rate risk, from time to time we enter into interest rate swap agreements. At March 31, 2008, we had the following interest rate swaps in place with BNP:


Effective Date	Maturity Date	Libor Swap Rate		Notional Amount (Millions)		Fair Value (Dollars)
2/27/2007	2/26/2009	4.86	%	$	40.0	$	938,768

Based on interest rates at March 31, 2008, a hypothetical 10% increase or decrease in interest rates would not have a material effect on the liability.

Item 4 – Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in rules 13a-15(c) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our Chief Executive Officer and Chief Financial Officer, based upon their evaluation as of March 31, 2008, the end of the period covered in this report, concluded that our disclosure controls and procedures were effective at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

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

PART II—OTHER INFORMATION

Item 1 – Legal Proceedings.

None.

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, 2007.

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

None.

Item 3. Defaults Upon Senior Securities.

None.

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

None.

Item 5 – Other Information.

None.

Item 6 – Exhibits.


10.1		Ninth Amendment to Amended and Restated Credit Agreement between Goodrich Petroleum Company, L.L.C. and BNP Paribas and Certain Lenders, dated as of January 11, 2008 (Incorporated by reference to 10.1 of the Company’s Form 8-K filed on January 17, 2008).

10.2		Second Lien Term Loan Agreement among Goodrich Petroleum Company, L.L.C. and BNP Paribas and Certain Lenders, dated as of January 16, 2008 (Incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K filed on January 17, 2008).

3.1		Bylaws of the Company, as amended and restated (Incorporated by reference to Exhibit 2.2 of the Company’s Form 8-K filed on February 19, 2008).

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

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

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

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

*	Filed herewith

**	Furnished herewith

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 8, 2008	By:	/s/ Walter G. Goodrich
		Walter G. Goodrich
		Vice Chairman & Chief Executive Officer

Date: May 8, 2008	By:	/s/ David R. Looney
		David R. Looney
		Executive Vice President & Chief Financial Officer

GOODRICH PETROLEUM CORPORATION LIST OF EXHIBITS TO FORM 10-Q

FOR QUARTER ENDED MARCH 31, 2008


EXHIBIT NO.		DESCRIPTION OF EXHIBIT
*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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