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 þ No ¨

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

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

The number of shares outstanding of the Registrant’s common stock as of ~~November 3, 2006~~May 4, 2007 was ~~25,185,801.~~28,303,019.

NOTE ~~A—Basis~~1—Description of ~~Presentation~~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. Certain reclassifications have been made to the prior year statements to conform to the current year presentation.

The accompanying consolidated financial statements of the Company should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K ~~as amended,~~ for the year ended December 31, ~~2005.~~2006. The results of operations for the ~~nine~~three months ended ~~September 30, 2006~~March 31, 2007, are not necessarily indicative of the results to be expected for the full year.

~~In September 2006,~~Assets Held for Sale—Assets Held for Sale as of March 31, 2007, represent our remaining assets in South Louisiana. These assets include the ~~Securities~~St. Gabriel, Bayou Bouillon and Exchange Commission issued Staff Accounting Bulletin No. 108 (“SAB 108”), which becomes effective beginning on January 1, 2007. SAB 108 provides guidance on the consideration of the effects of prior period misstatements in quantifying current year misstatements for the purpose of a materiality assessment. SAB 108 requires an entity to evaluate the impact of correcting all misstatements, including both the carryover and reversing effects of prior year misstatements, on current year financial statements. If a misstatement is material to the current year financial statements, the prior year financial statements should also be corrected, even though such revision was, and continuesPlumb Bob fields. These assets are expected to be immaterial to the prior year financial statements. Correcting prior year financial statements for immaterial errors would not require previously filed reports to be amended. Such correction should be made in the current period filings. We are currently evaluating the impact of adopting SAB 108.sold within one year.

Income Taxes—Uncertain Tax Positions—In ~~September~~June 2006, the Financial Accounting Standards Board (“FASB”) issued ~~SFAS No. 158 “~~FIN 48,~~Employers’~~ Accounting for ~~Defined Benefit Pension~~Uncertainty in Income Taxes—an Interpretation of FASB Statement No. 109, Accounting for Income Taxes. This interpretation addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN 48, the Company may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. FIN 48 also provides guidance on derecognition, classification, interest and ~~Other Postretirement Plans,~~penalties on income taxes, accounting in interim periods and requires increased disclosures. The Company adopted the provisions of FIN 48 on January 1, 2007. There was no cumulative effect adjustment to retained earnings, our financial condition or results of operations as a result of implementing FIN 48. See Note 7 to the Consolidated Financial Statements.

Recently Released Accounting Pronouncements—In February 2007, the FASB issued Statement of Financial Accounting Standards (“SFAS”) 159,The Fair Value Option for Financial Assets and Financial Liabilities—including an amendment of FASB ~~Statements~~Statement No. ~~87, 88, 106, and 132(R)~~115,~~” (“SFAS 158”),~~ which requires companies to recognize the overfunded or underfunded status of a defined benefit plans as an asset or liability in its balance sheet and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. SFAS 158 is effective as of the end of the fiscal year ending after December 15, 2006. We do not expect the adoption of SFAS 158 to have an impact on our consolidated financial position, results of operations or cash flows.

~~In September 2006, the FASB issued SFAS No. 157, “~~~~Fair Value Measurements~~~~” (“SFAS 157”), which defines~~allows measurement at fair value ~~establishes a framework for measuring~~of eligible financial assets and liabilities that are not otherwise measured at fair value. If the fair value option for an eligible item is elected, unrealized gains and losses for that item must be reported in ~~generally accepted accounting principles~~current earnings at each subsequent reporting date. SFAS 159 also establishes presentation and ~~expands disclosures about fair value measurements. This Statement applies under other accounting pronouncements that require or permit fair value measurements,~~disclosure requirements designed to draw comparison between the ~~FASB having previously concluded in those accounting pronouncements that fair value is~~different measurement attributes the ~~relevant measurement attribute. Accordingly, this Statement does not require any new fair value measurements.~~Company elects for similar types of assets and liabilities. SFAS ~~157~~159 is effective for fiscal years beginning after ~~December~~November 15, 2007. ~~We plan to adopt SFAS 157 beginning in the first quarter of fiscal 2008.~~Early adoption is permitted. We are currently ~~evaluating~~assessing the impact ~~if any, the adoption~~ of SFAS ~~157 will have~~159 on our ~~consolidated~~ financial ~~position, results of operations or cash flows.~~statements.

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

~~In July 2006, issued Financial Interpretation No. 48, “~~~~Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109~~” (“FIN 48”), to clarify certain aspects of accounting for uncertain tax positions, including issues related to the recognition and measurement of those tax positions. This interpretation is effective for fiscal years beginning after December 15, 2006. We are in the process of evaluating the impact of the adoption of this interpretation on our consolidated financial position, results of operations or cash flows.

~~In March 2006, the FASB issued SFAS No. 156, “~~~~Accounting for Servicing of Financial Assets~~” (“SFAS 156”), which requires all separately recognized servicing assets and servicing liabilities be initially measured at fair value. SFAS 156 permits, but does not require, the subsequent measurement of servicing assets and servicing liabilities at fair value. Adoption is required as of the beginning of the first fiscal year that begins after September 15, 2006. The adoption of SFAS 156 is not expected to have a material effect on our consolidated financial position, results of operations or cash flows.

~~In February 2006, the FASB issued SFAS No. 155, “~~~~Accounting for Certain Hybrid Financial Instruments, an amendment of FASB Statements No. 133 and 140~~” (“SFAS 155”). SFAS 155 clarifies certain issues relating to embedded derivatives and beneficial interests in securitized financial assets. The provisions of SFAS 155 are effective for all financial instruments acquired or issued after fiscal years beginning after September 15, 2006. We are currently assessing the impact that the adoption of SFAS 155 will have on our consolidated financial position, results of operations or cash flows.

~~In December 2004, the FASB issued SFAS No. 123 (revised 2004), “~~~~Share-Based Paymen~~~~t” (“SFAS 123R”), replacing SFAS No. 123, “~~~~Accounting for Stock-Based Compensation~~~~” (“SFAS 123”), and superceding Accounting Principles Board (“APB”) Opinion No. 25, “~~~~Accounting for Stock Issued to Employees~~” (“APB 25”). SFAS 123R requires recognition of share-based compensation in the financial statements. SFAS 123R was effective as of the first annual reporting period that began after June 15, 2005 and was adopted on January 1, 2006. See Note C for further details.

In May 2006, our shareholders approved our 2006 Long-Term Incentive Plan (the “2006 Plan”), at our annual meeting of stockholders. The 2006 Plan is similar to and replaces our previously adopted 1995 Incentive Plan (the “1995 Plan”) and 1997 Non-Employee Directors’ Stock Option Plan (the “Directors’ Plan”). No further awards will be granted under the previously adopted plans, however, those plans shall continue to apply to and govern awards made thereunder. Under the 2006 Plan, a maximum of 2.0 million new shares are reserved for issuance as awards of share options to officers, employees and non-employee directors. Share options granted to officers and employees will generally become exercisable in one-third increments over a three year period and to the extent not exercised, expire on the tenth anniversary of the date of grant. Share options granted to non-employee directors will usually be immediately exercisable and to the extent not exercised, expire on the tenth anniversary of the date of grant. The exercise price of share options granted under the 2006 Plan will equal the market value of the underlying stock on the date of grant. The 1995 Plan expired according to its original terms on August 16, 2005. However, on February 1, 2006, our Board of Directors approved the extension of the 1995 Plan through December 31, 2005 and the granting of a total of 101,129 shares of restricted stock and 525,000 stock options to certain of our employees and directors as of December 6, 2005, which was approved at our 2006 annual meeting of stockholders in May 2006. For accounting purposes, such restricted shares and options have been valued as of February 9, 2006, the date on which our directors and executive officers reached a level of more than 50% ownership of our common stock, so that shareholder approval of those actions was no longer uncertain.

Share options previously granted under the 1995 Plan become exercisable in one-third increments over a three year period and to the extent not exercised, expire on the tenth anniversary of the date of grant. Share options previously granted under the Directors’ Plan generally become exercisable immediately and expire, if not exercised, ten years thereafter. The exercise price of share options granted under the 1995 Plan and the Directors’ Plan equals the market value of the underlying stock on the date of grant. At September 30, 2006, options to purchase 100,000 shares of our common stock were outstanding under the 2006 Plan and options to purchase 948,500 shares of our common stock were outstanding under the 1995 Plan and the Directors’ Plan. In order to satisfy share option exercises, shares are issued from authorized but unissued common stock.

Stock based compensation for the three and nine months ended September 30, 2006 of $1.4 million and $3.7 million, respectively, has been recognized as a component of general and administrative expenses in the accompanying Consolidated Financial Statements.

Effective January 1, 2006 we adopted SFAS 123R, which required 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 and APB 25. We adopted SFAS 123R using the modified prospective application method of adoption, which required us to record compensation cost related to unvested stock awards as of December 31, 2005 by recognizing the unamortized grant date fair value of these awards over the remaining service periods of those awards with no change in historical reported earnings. Awards granted after December 31, 2005 are valued at fair value in accordance with provisions of SFAS 123R and recognized on a straight line basis over the service periods of each award. We estimated forfeiture rates for all unvested awards based on our historical experience. The January 1, 2006 balance of unamortized restricted stock awards of $2.1 million was reclassified against additional paid-in-capital upon adoption of SFAS 123R. In fiscal 2006 and future periods, common stock par value will be recorded when the restricted stock is issued and additional paid-in-capital will be increased as the restricted stock compensation cost is recognized for financial reporting purposes.

Prior to 2006, we accounted for stock-based compensation in accordance with APB 25 using the intrinsic value method, which did not require that compensation cost be recognized for our stock options provided the option exercise price was established at 100% of the common stock fair market value on the date of grant. Under APB 25, we were required to record expense over the vesting period for the value of restricted stock granted. Prior to 2006, we provided pro forma disclosure amounts in accordance with SFAS No. 148, “~~Accounting for Stock-Based Compensation – Transition and Disclosure~~” (“SFAS 148”), as if the fair value method defined by SFAS 123 had been applied to our stock-based compensation. Our net loss and net loss per share for the three and nine months ended September 30, 2005 would have been greater if compensation cost related to stock options had been recorded in the financial statements based on fair value at the grant dates.

~~Pro forma net loss as if the fair value based method had been applied to all awards for the three and nine months ended September 30, 2005 is as follows (in thousands, except per share amounts):~~

The estimated fair value of the options granted during 2006 and prior years 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:

The Black Scholes model incorporates assumptions to value stock-based awards. The risk-free rate of interest for periods within the expected term of the option is based on a zero-coupon U.S. government instrument over the expected term of the equity instrument. Expected volatility is based on the historical volatility of our common stock. We generally use the midpoint of the vesting period and the life of the grant to estimate employee option exercise timing (expected term) within the valuation model. This methodology is not materially different from our historical data on exercise timing. In the case of director options, we used historical exercise behavior. Employees and directors that have different historical exercise behavior with regard to option exercise timing and forfeiture rates are considered separately for valuation and attribution purposes.

~~The following table summarizes the components of our stock-based compensation programs recorded as expense (in thousands):~~

As of September 30, 2006, $3.3 million and $7.1 million of total unrecognized compensation cost related to restricted stock and stock options, respectively, is expected to be recognized over a weighted average period of approximately 1.6 years for restricted stock and 2.0 years for stock options.

~~Option activity under our stock option plans as of September 30, 2006 and changes during the nine months ended September 30, 2006 were as follows:~~

The aggregate intrinsic value in the table above represents the total pre-tax intrinsic value (the difference between our closing stock price on the last trading day of the third quarter of 2006 and the exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on September 30, 2006. The amount of aggregate intrinsic value will change based on the fair market value of our stock. The total intrinsic value of options exercised during the nine months ended September 30, 2006 and 2005 was $836,100 and $772,300 respectively.

~~The following table summarizes information on unvested restricted stock outstanding as of September 30, 2006:~~

In May 2006, an officer of the Company resigned and the Company accelerated the vesting of (1) options to purchase 10,000 shares and (2) 2,916 shares of previously unvested restricted stock that had been issued to the officer in 2004. The affected options are required to be accounted for as a modification of an award with a service vesting condition under SFAS 123R. The fair market value was calculated immediately prior to the modification and immediately after the modification to determine the incremental fair market value. This incremental value and the unamortized balance of the restricted stock resulted in the immediate recognition of compensation expense of approximately $0.1 million.

SFAS 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets and requires that an asset retirement cost should be capitalized as part of the cost of the related ~~long- lived~~long-lived asset and subsequently allocated to expense using a systematic and rational method. We adopted SFAS 143 on January 1, 2003 and recorded an incremental liability for asset retirement obligations of $1.4 million, additional oil and gas properties, net of accumulated depletion, depreciation and amortization, in the amount of $1.1 million and a net of tax cumulative effect of change in accounting principle of $0.2 million. The reconciliation of the beginning and ending asset retirement obligation for the period ending ~~September 30, 2006~~March 31, 2007 is as follows (in thousands):

The liabilities settled in the first quarter of 2007 represent the Asset Retirement Obligation for substantially all of our properties in South Louisiana sold to a private company. The ending balance at March 31, 2007, includes $0.3 million for Assets Held for Sale. See Note 6.

In December 2006, we sold $175 million of 3.25% convertible senior notes due in December 2026. With a portion of the proceeds of the note offering we fully repaid the outstanding balance of the second lien term loan. The notes mature on December 1, 2026, unless earlier converted, redeemed or repurchased. The notes will be our senior unsecured obligations and will rank equally in right of payment to all of our other existing and future indebtedness. The notes accrue interest at a rate of 3.25% annually and interest will be paid semi-annually on June 1 and December 1 beginning June 1, 2007.

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

~~increased to $50.0 million in August 2006.~~ Revolving borrowings under the ~~Amended and Restated~~Senior Credit ~~Agreement~~Facility are subject to periodic redeterminations of the borrowing base which is currently established at ~~$150.0~~$110.0 million. ~~With a portion~~As of ~~the net proceeds of the offering of our 5.375% Series B Cumulative Convertible Preferred Stock (the “Series B Convertible Preferred Stock”) in December 2005,~~March 31, 2007, we ~~fully~~ repaid all outstanding ~~indebtedness on our revolver in~~amounts of the ~~amount of $47.5 million leaving a zero balance outstanding as of December 31, 2005.~~revolving borrowings under the Senior Credit Facility. Interest on revolving borrowings under the ~~Amended and Restated~~Senior Credit ~~Agreement~~Facility accrues at a rate calculated, at our option, at ~~either~~ the bank base rate plus 0.00% to 0.50%, or LIBOR plus 1.25% to 2.00%, depending on borrowing base utilization. ~~BNP Paribas (“BNP”) is the lead lender and administrative agent under the amended credit facility.~~

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

Current Ratio of 1.0/~~1.0;~~1.0:

Interest Coverage Ratio which is not less than 3.0/1.0 for the trailing four ~~quarters,~~quarters; and

Total Debt no greater than 3.5 times EBITDAX for the trailing four quarters.

~~Tangible Net Worth of not less than $53,392,838, plus 50% of cumulative net~~EBITDAX is earnings before interest expense, income ~~after September 30, 2004, plus 100% of the net proceeds of any subsequent equity issuance.~~

tax, DD&A and exploration expense.

As of ~~September 30, 2006,~~March 31, 2007, we were in compliance with all of the financial covenants of the ~~Amended and Restated~~Senior Credit ~~Agreement.~~

The Second Lien Term Loan Agreement, as amended, provides for a 5-year non-revolving loan of $50.0 million and is due in a single maturity on November 17, 2010. Optional prepayments of term loan principal can be made in amounts of not less than $5.0 million during the first year at a 1% premium and without premium after the first year which period expires on November 17, 2006. Interest on term loan borrowings accrues at a rate calculated, at our option, at either base rate plus 3.50%, or LIBOR plus 4.50%, and is payable quarterly. BNP is the lead lender and administrative agent under the Second Lien Term Loan Agreement.

~~The terms of the Second Lien Term Loan Agreement require us to maintain certain covenants. Capitalized terms are defined in the loan agreement. The covenants include:~~

~~Total Debt to EBITDAX Ratio which is not greater than 4.0/1.0 for the most recent period of four fiscal quarters for which financial statements are available and~~

~~Asset Coverage Ratio to be not less than 1.5/1.0.~~

~~As of September 30, 2006, we were in compliance with all of the financial covenants of the Second Lien Term Loan Agreement.~~Facility.

NOTE ~~F—Preferred Stock~~

In December 2005, 1,650,000 shares of our Series B Convertible Preferred Stock were issued in a private placement for net proceeds of $79.8 million (after offering costs of $2.7 million). On January 23, 2006, the initial purchasers exercised their option to purchase an additional 600,000 shares of Series B Convertible Preferred Stock at the same price per share, resulting in net proceeds of $29.0 million.

As part of this transaction we filed a registration statement with the SEC on April 20, 2006 for the purpose of registering the resale of the shares of common stock issuable pursuant to the purchase agreement. The registration statement was declared effective by the SEC on August 10, 2006.

~~GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

During the first quarter of 2006 we completed the redemption of our Series A Convertible Preferred Stock. Of the previously outstanding shares of Series A Convertible Preferred Stock, holders of 15,539 shares elected to convert such shares into a net total of 6,466 shares of our common stock and the remaining shares were redeemed in cash for $12 per share, plus accrued dividends. The total redemption cost to us was approximately $9.3 million and was funded from available cash resources. This amount includes a $1.5 million redemption premium which is treated in the same manner as preferred stock dividends on the Consolidated Statement of Operations.

~~NOTE G—~~4—Net Income (Loss) Per 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 ~~and nine~~ months ended ~~September 30, 2006~~March 31, 2007 and ~~2005.~~2006. The following table reconciles the weighted average shares outstanding used for these computations (in thousands):

   Three Months Ended
September 30,    Nine Months Ended
September 30,
       2006            2005            2006            2005
Weighted average shares outstanding – basic
   24,972    24,784    24,923    23,024
Effect of dilutive securities – stock options and restricted stock
   374    —      334    —
Effect of dilutive securities – warrants
   —      —      129    —

Weighted average shares outstanding – diluted
   25,346    24,784    25,386    23,024


	For the Three Months Ended March 31,
	2007	2006
Basic Method	25,141	24,860
Dilutive Stock Warrants	—	194
Dilutive Stock Options and Restricted Stock	245	312

Dilutive Method	25,386	25,366

NOTE H—5—Hedging Activities

Commodity Hedging Activity

We enter into swap contracts, costless collars or other hedging agreements from time to time to manage the commodity price risk for a portion of our production. We consider these to be hedging activities and, as such, monthly settlements on these contracts are reflected in our crude oil and natural gas sales, provided the contracts are deemed to be “effective” hedges under FAS 133. Our strategy, which is administered by the Hedging Committee of ~~the~~our Board of Directors, and reviewed periodically by the entire Board of Directors, has been to generally hedge between 30% and 70% of our production. As of ~~September 30, 2006,~~March 31, 2007, the commodity hedges we utilized were in the form of: (a) swaps, where we receive a fixed price and pay a floating price, based on NYMEX quoted ~~prices; and~~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. Hedge ineffectiveness results from differences between~~price, and (c) fixed price physical contracts, whereby we agree in advance with the ~~NYMEX contract terms and the physical location, grade and quality~~purchasers of our ~~oil~~physical gas volumes as to specific quantities to be delivered and specific prices to be received for gas ~~production.~~

Asdeliveries at specific transfer points in the future. Our natural gas swaps and collars (all financial contracts) were deemed ineffective beginning in the fourth quarter of ~~September 30, 2006,~~2004, and since that time we have been required to reflect the change in the fair value of our ~~open forward position on our outstanding commodity hedging contracts was as follows:~~natural gas swaps and collars in earnings rather than in accumulated other comprehensive loss, a

Swaps
   Volume    Average
Price
Natural gas (MMBtu/day)

4Q 2006
   15,000    6.95
1Q 2007
   10,000    7.77
Oil (Bbl/day)

4Q 2006
   800    50.80
2007
   400    53.35

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Collars
   Volume
Average
Floor/Cap
Natural gas (MMBtu/day)

1Q 2007
   25,000    $7.80 – $12.42
2Q 2007
   30,000    7.67 – 12.67
3Q 2007
   30,000    7.67 – 12.67
4Q 2007
   30,000    7.67 – 12.67
Oil (Bbl/day)

2007
   400    $60.00 – $76.50

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

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


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


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


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

The fair value of the oil and gas hedging contracts in place at ~~September 30, 2006~~March 31, 2007, resulted in a net asset of ~~$8.7~~$2.2 million. As of September 30, 2006, $1.6 million (net of $0.9 million in income taxes) of deferred losses on derivative instruments accumulated in other comprehensive loss are expected to be reclassified into earnings during the next twelve months. For the ~~nine~~three months ended September 30, 2006, $2.2 million of previously deferred losses (net of $1.1 million in income taxes) was reclassified out of accumulated other comprehensive loss as the cash flow settlement of the hedged items was recognized in earnings.

~~For the nine months ended September 30, 2006,~~March 31, 2007, we recognized in earnings a ~~gain on~~loss from derivatives not qualifying for hedge accounting in the amount of ~~$34.6 million. This gain includes an~~$9.5 million (this amount included realized gains of $3.7 million, as well as unrealized ~~gain~~losses of ~~$36.3 million~~$13.2 million). All of our natural gas and oil hedges were deemed ineffective for 2007; accordingly, the changes in fair value of ~~our ineffective oil and gas~~such hedges ~~a realized~~could no longer be reflected in other comprehensive income. In the first quarter of 2007, we reclassified $1.3 million of previously deferred losses (net of $0.7 million in income taxes) from accumulated other comprehensive loss ~~of $1.8 million for the effect of settled~~to loss on derivatives ~~on our ineffective gas hedges and an unrealized gain of $0.1 million related to interest rate swaps that did~~ not ~~qualify~~qualifying for hedge accounting ~~treatment. Our natural gas hedges~~as the underlying properties to which the hedge was originally designated were ~~deemed ineffective, beginning~~sold.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

During the first quarter we also unwound an oil collar for 400 barrels per day. As a result, we recognized a gain of $0.9 million in the ~~fourth~~first quarter of ~~2004, and~~2007. In the first quarter of 2007, we ~~have been required to reflect the changes~~entered into a series of physical sales contracts which will result in ~~the fair value~~us selling approximately 23,500 MMbtu of ~~our natural~~ gas ~~hedges~~per day in ~~earnings rather than in accumulated other comprehensive income (loss). In addition, all~~calendar year 2008 for an average price of ~~our collars did not qualify for hedge accounting treatment and those changes in fair value have been recognized in earnings.~~$8.03 per MMbtu before transportation charges.

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 a variable-rate debt ~~obligations~~obligation that ~~expose~~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 ~~September 30, 2006~~March 31, 2007, we had the following interest rate swaps in place with BNP (in millions):

Effective
Date

Maturity
Date

LIBOR
Swap Rate

Notional
Amount
02/27/06
   02/26/07    4.08 % $ 23.0
02/27/06
   02/26/07    4.85 % 17.0
02/26/07
   02/26/09    4.86 % 40.0


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

The fair value of the interest rate swap contracts in place at ~~September 30, 2006,~~March 31, 2007, resulted in an asset of ~~$0.2~~$54,000. For the three months ended March 31, 2007 and 2006, our earnings were not significantly affected by cash flow hedging ineffectiveness of the interest rates swaps.

NOTE 6—Discontinued Operations

On March 20, 2007, the Company and Malloy Energy Company, L.L.C. closed the sale of substantially all of their oil and gas properties in South Louisiana with the exception of the three properties discussed under Note 1 “Assets Held for Sale”. The total sales price for the Company’s interest in the oil and gas properties was $77 million. AsThe total sales price for Malloy Energy’s interests in these properties was approximately $22 million. The Chairman of ~~September 30, 2006, $96,000 (net~~our Board of ~~$51,000 in income taxes)~~Directors, Patrick E. Malloy, III, is the President and controlling shareholder of ~~deferred~~Malloy Energy Company, L.L.C.

In accordance with SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets”, the results of operations and gain relating to the sale have been reflected as discontinued operations. We recorded an after tax gain on sale of $10.9 million (pre-tax gain of $16.8 million and tax of $5.9 million) on net ~~gains on derivative instruments accumulated in other comprehensive income are expected to be reclassified into earnings during the next twelve months.~~proceeds of approximately $74.0 million after normal closing adjustments.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

~~We entered into two interest rate swaps to protect against movements~~The following table summarizes the amounts included in ~~interest rates during~~income from discontinued operations:


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

The following presents the ~~fourth quarter~~main classes of ~~2005.~~ assets and liabilities associated with long-lived assets classified as held for sale:


	March 31, 2007
Assets held for sale	$	1,867
Accrued liabilities		105
Accrued abandonment costs		276

NOTE 7—Income Taxes

Uncertain Tax Positions

The ~~documentation~~Company did not have any unrecognized tax benefits and there was ~~not prepared at the time~~no effect on our financial condition or results of ~~inception for these hedges and~~operations as a result ~~we were~~of implementing FIN 48. The amount of unrecognized tax benefits did not ~~entitled to apply hedge accounting to these instruments. The failure to qualify for hedge accounting requires~~materially change as of March 31, 2007.

It is expected that ~~all changes~~the amount of unrecognized tax benefits may change in the ~~fair value~~next twelve months; however we do not expect the change to have a significant impact on the results of operations or the financial position of the ~~interest rate swap be recorded~~Company.

The Company files a consolidated federal income tax return in the ~~consolidated statements~~United States Federal jurisdiction and various combined and separate filings in several state and local jurisdictions. With limited exceptions, the Company is no longer subject to U.S. Federal, state and local, or non-U.S. income tax examinations by tax authorities for years before 1992.

The Company’s continuing practice is to recognize estimated interest and penalties related to potential underpayment on any unrecognized tax benefits as a component of ~~operations. Accordingly,~~income tax expense in the Consolidated Statement of Operations. As of the date of adoption of FIN 48, Goodrich did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the quarter. 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 30, 2008.

Provision for ~~the nine months ended September 30, 2006, we recognized in earnings~~Income taxes

We recorded a ~~gain of approximately $0.1~~net income tax benefit attributable to continuing operations totaling $6.7 million, which is ~~included in~~an effective tax rate of 34.7%. Our effective tax rate differs from the ~~aforementioned total gain~~35% federal statutory rate primarily due to state income taxes. The income tax benefit includes tax expense of ~~$34.6 million.~~$94 thousand ($63 thousand net of federal tax benefit) attributable to the Texas Margin Tax (“TMT”) which took effect for our Texas income tax reporting purposes on January 1, 2007.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE I—8—Commitments and Contingencies

In July 2005, we received a Notice of Proposed Tax Due from the State of Louisiana asserting that we underpaid our Louisiana franchise taxes for the years 1998 through 2004 in the amount of ~~$0.5~~$0.6 million. The Notice of Proposed Tax Due includes additional assessments of penalties and interest in the amount of $0.4 million for a total asserted liability of ~~$0.9~~$1.0 million. In order to avoid future penalties and interest, the Company paid, under protest, $1.0 million to the State of Louisiana in April 2007. We have accrued for this amount at March 31, 2007, and recognized an expense equal to the full $1.0 million. We ~~believe that~~plan to pursue the reimbursement of the full $1.0 million paid under protest in April 2007. Should our efforts prevail, the taxes paid under protest would be refunded, at which time we ~~have fully paid our Louisiana franchise taxes for the years in question; therefore, we intend~~would book a credit to ~~vigorously contest the Notice of Proposed Tax Due. We have commenced our analysis of this contingency~~general and ~~have not recorded any provision for possible payment of additional Louisiana franchise taxes nor any related penalties and interest.~~administrative expense.

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

NOTE ~~J—Disposition~~9 – Acquisitions and Divestitures

On February 7, 2007, we announced the acquisition of ~~Assets~~

~~In June 2006, we assigned 50% of our interest solely~~drilling and development rights to acreage located in the ~~deep rights~~Angelina River play. We acquired a 60% working interest in the acreage and will operate the joint venture. The acquisition was completed in two separate transactions. In the initial transaction, we acquired a 40% working interest for $2.0 million from a private company. We also agreed to carry the private company for a 20% working interest in the drilling of five wells. In the second transaction, we purchased the remaining 20% working interest in the acreage in a like-kind exchange for our ~~Cotton prospect~~30% interest in ~~East Texas, defined as rights below~~ the ~~top~~Mary Blevins field.

On March 20, 2007, the company closed the sale of ~~the Knowles Lime formation at 12,901’ below the surface, while reserving~~substantially all of ~~our rights to~~its oil and ~~above the Upper, Middle and Lower Travis Peak sections~~gas properties in approximately 20,500 net acres for approximately $1.6 million. We had received one-half of the sales price as of September 30, 2006 and one-half, which was received in October 2006, has been recorded as a receivable in the consolidated financial statements. Pursuant to the agreement, within 18 months of the assignment, the assignee will either pay all of our share of drilling costsSouth Louisiana to a depth of 16,500’ feet in a well (the “carried well”) drilled on the acreage or pay us a non participation fee of $4.0 million should no well be drilled. The transaction was accounted for as a recovery of cost. The carried well was spud on September 25, 2006 and as of the filing date was drilling at approximately 14,000 feet.private company. See Note 6.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

~~Executive~~ 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.

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 Form 10-K 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~~Trend of East Texas and Northwest ~~Louisiana and in the transition zone of South~~ 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, while maintaining our drilling activities in select high impact well locations in South Louisiana.~~Trend. We continue to aggressively pursue the acquisition and evaluation of prospective acreage, oil and gas drilling opportunities and potential property acquisitions.

Source of ~~Revenue~~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. ~~Hurricanes Katrina and Rita in the third quarter of 2005 are an example of how production volumes can be impacted to defer volumes from the current period to future periods.~~ The price of oil and natural gas is a primary factor affecting our revenues. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we utilize derivative instruments to hedge future sales prices on a portion of our oil and natural gas production. While the derivative instruments may protect downward price fluctuation, the use of certain types of derivative instruments may prevent us from realizing the full benefit of upward price movements.

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 and Caddo and Bienville Parishes, Louisiana. In addition, we have recently expanded our acreage position in the Trend to include Harrison, Smith and Upshur Counties of Texas. We have steadily increased our acreage position in these areas over the last two years to approximately 185,000 gross acres as of March 31, 2007. As of March 31, 2007, we have drilled and/or logged a cumulative total of 173 Cotton Valley wells with a success rate in excess of 99%, of which drilling operations were conducted on 23 gross wells during the first quarter of 2007. Our net production volumes from our Cotton Valley Trend wells aggregated approximately 36,677 Mcfe of gas per day in the first quarter of 2007, or approximately 98.5% higher than the Cotton Valley Trend production of the 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 $74.0 million, net to the Company, after normal closing adjustments. The effective date of the sale was July 1, 2006. We also expect to sell our remaining assets in South Louisiana within the next year. The remaining fields treated as held for sale are St. Gabriel, Bayou Bouillon and Plumb Bob.

~~Third~~First Quarter ~~2006~~2007 Highlights

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

We completed the sale of substantially all of our assets in South Louisiana to a private company for $77 million.

We increased our oil and gas production volumes on continuing operations to approximately ~~46,700~~37,233 Mcfe per day, representing ~~a 99% increase from the third quarter of 2005 and~~ an increase of ~~approximately 7%, on a sequential basis,~~59% from the ~~second~~first quarter of 2006.

~~Oil and gas revenues increased 69% from the third quarter of 2005 and remained constant from the second quarter of 2006.~~

~~Drilling Activity~~

We ~~had~~completed drilling operations on 1914 gross ~~wells during the third quarter of 2006.~~

~~Cotton Valley Trend~~

~~As of September 30, 2006, we had drilled 142~~ wells in the ~~Cotton Valley trend resulting in a 100% success rate.~~first quarter of 2007.

~~Cotton Valley trend volumes comprised 69%~~

We funded our capital expenditures of ~~total volumes~~$73.4 million in the ~~third~~first quarter of ~~2006.~~2007 through a combination of cash flow from operations, net proceeds from our sale of assets and available cash.

Our after-tax net loss from continuing operations reflected an income tax benefit rate of 35% in the first quarter of 2007; however, we did not incur any income taxes on a current basis due to our substantial tax net operating loss carrryforwards and other factors.

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 ~~2005~~2006 Form ~~10-K, as amended.~~10-K.

~~Hurricanes Katrina and Rita Update~~

In August and September 2005, Hurricanes Katrina and Rita caused damage to our assets on the Gulf Coast, significantly on one producing well (Norton) and offshore facilities in our Burrwood/West Delta 83 field. As of September 30, 2006, our share of hurricane related costs in these fields is approximately $7.3 million and we have received proceeds of $4.2 million. We anticipate that we will ultimately receive reimbursement for all but $1.3 million of our remaining insured losses, which represents our deductible and amounts exceeding insurance limits, $0.4 million of which has been capitalized and $0.9 million of which has been expensed to date through September 2006.

As claims are submitted to the insurance companies, they are reviewed and preliminary payments made until all losses are incurred and documented. A final payment will be made once we and our insurers agree on the total measurement value of the claim, which is expected sometime during the fourth quarter of 2006.

Results of Operations

Three Months Ended ~~September 30, 2006~~March 31, 2007 Compared to Three Months Ended ~~September 30, 2005~~March 31, 2006

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

For the three months ended ~~September 30, 2006,~~March 31, 2007, we reported ~~net income applicable to common stock of $6.7 million, or $0.27 per basic share on total revenue of $29.4 million as compared with~~ a net loss applicable to common stock of ~~$19.6~~$0.5 million, or ~~$0.79~~$0.02 per basic share on total revenue of ~~$17.5~~$23.5 million as compared with a net income applicable to common stock of $8.6 million, or $0.34 per basic share, on total revenue of $14.8 million for the three months ended ~~September 30, 2005.~~March 31, 2006.

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 and include the realized gains and losses on the effective portion of our derivative instruments for 2006 as further described under Note H5 to the Consolidated Financial Statements. All of our derivative instruments were ineffective in the first quarter of 2007 and did not qualify for hedge accounting.

   Three Months Ended
September 30, % Change
from 2005
   2006 2005 to 2006
Production:

Natural gas (MMcf)
   3,509 1,574 123 %
Oil and condensate (MBbls)
   131 98 34 %
Total (MMcfe)
   4,297 2,163 99 %
Revenues from production (in thousands):

Natural gas
   $ 21,779 $ 13,744 58 %
Effects of cash flow hedges
   —   —   —

Total
   $ 21,779 $ 13,744 58 %

Oil and condensate
   $ 9,118 $ 5,857 56 %
Effects of cash flow hedges
   (1,621 ) (2,289 ) 29 %

Total
   $ 7,497 $ 3,568 110 %

Natural gas, oil and condensate
   $ 30,897 $ 19,601 58 %
Effects of cash flow hedges
   (1,621 ) (2,289 ) 29 %

Total revenues from production
   $ 29,276 $ 17,312 69 %

~~Table continued on following page~~


	Three Months Ended March 31,				% Change from 2006 to 2007
	2007		2006		% Change from 2006 to 2007
Production – Continuing Operations:
Natural gas (MMcf)		3,195		1,975	62	%
Oil and condensate (MBbls)		26		22	18	%
Total (MMcfe)		3,351		2,107	59	%
Production – Discontinued Operations:
Natural gas (MMcf)		521		645	(19	%)
Oil and condensate (MBbls)		82		89	(8	%)
Total (MMcfe)		1,013		1,179	(14	%)
Revenues from production (in thousands):
Natural gas	$	21,861	$	13,144	66	%
Effects of cash flow hedges		—		—	—

Total	$	21,861	$	13,144	66	%

Oil and condensate	$	1,455	$	1,280	14	%
Effects of cash flow hedges		—		—	—

Total	$	1,455	$	1,280	14	%

Natural gas, oil and condensate	$	23,316	$	14,424	62	%
Effects of cash flow hedges		—		—	—

Total revenues from production	$	23,316	$	14,424	62	%

Average sales price per unit:
Natural gas (per Mcf)	$	6.84	$	6.66	3	%
Effects of cash flow hedges (per Mcf)		—		—	—

Total (per Mcf)	$	6.84	$	6.66	3	%

Oil and condensate (per Bbl)	$	56.68	$	58.18	(3	%)
Effects of cash flow hedges (per Bbl)		—		—	—

Total (per Bbl)	$	56.68	$	58.18	(3	%)

Natural gas, oil and condensate (per Mcfe)	$	6.96	$	6.85	2	%
Effects of cash flow hedges (per Mcfe)		—		—	—

Total (per Mcfe)	$	6.96	$	6.85	2	%

   Three Months Ended
September 30, % Change
from 2005
   2006 2005 to 2006
Average sales price per unit:

Natural gas (per Mcf)
   $ 6.21 $ 8.74 (29 %)
Effects of cash flow hedges (per Mcf)
   —   —   —

Total (per Mcf)
   $ 6.21 $ 8.74 (29 %)

Oil and condensate (per Bbl)
   $ 69.44 $ 59.62 16 %
Effects of cash flow hedges (per Bbl)
   (12.35 ) (23.31 ) 47 %

Total (per Bbl)
   $ 57.09 $ 36.31 57 %

Natural gas, oil and condensate (per Mcfe)
   $ 7.19 $ 9.06 (21 %)
Effects of cash flow hedges (per Mcfe)
   (0.38 ) (1.06 ) 64 %

Total (per Mcfe)
   $ 6.81 $ 8.00 (15 %)

~~Excluding the effects of settled derivatives, revenues~~Revenues from ~~production~~production-continuing operations increased ~~58%~~62% in the ~~third~~first quarter of ~~2006~~2007 compared to the same period in ~~2005~~2006 due primarily to a substantial increase in Cotton Valley ~~trend~~Trend production. Revenues were also impacted favorably by a 2% increase in our sales price per unit.


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

Lease Operating.Lease operating ~~expenses (“LOE”)~~expense for the ~~third~~first quarter of ~~2006~~2007 increased on an absolute basis ($4.1 million compared to ~~$6.1 million~~$2.2 million) as well as on a per unit basis ($~~1.41~~1.23 per Mcfe compared to $1.06 per Mcfe) from ~~$2.4 million ($1.11 per Mcfe) in~~ the ~~third~~first quarter of ~~2005.~~2006. This increase in unit costs was primarily attributable to ~~the~~an industry wide increase in ~~the number of producing wells,~~operating costs as well as ~~increases in~~high salt water ~~hauling and~~ disposal ~~and compression expenses related to the~~(“SWD”) costs prevalent in certain of our Cotton Valley ~~trend. Also contributing~~Trend fields. Once we are able to ~~this increase~~fully implement our low pressure gathering system in East Texas, which is ~~an additional loss of $0.4 million of hurricane related costs that will not~~nearing completion, we expect these expenses to be ~~covered by insurance reimbursement.~~meaningfully reduced on a per unit basis.

Production Taxes.Production taxes ~~increased~~decreased to ~~$1.8~~$0.3 million for the ~~third~~first quarter of ~~2006~~2007 compared to ~~$1.2~~$0.9 million for the comparable period in ~~2005~~2006 due to ~~an increase in production volumes. Most~~a greater portion of our ~~Cotton Valley trend~~ wells ~~qualify~~qualifying for ~~the “Tight~~Tight Gas ~~Sands” credit allowed for severance tax~~Sands (“TGS”) credits in the State of Texas. ~~While~~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 ~~only reflected credits on 35 wells that have~~ been ~~approved by~~notified of the ~~State,~~State’s approval, and we anticipate that we will incur a gradually lower production tax rate in the future as we add ~~further~~additional Cotton Valley Trend wells to our production base and as reduced rates are ~~approved and credits are received.~~approved.

Transportation.Transportation ~~costs~~expense increased to ~~$1.2~~$1.1 million ($0.32 per Mcfe) in the first quarter of 2007 as a result of increased volumes in the Cotton Valley Trend. As disclosed in the Company’s Quarterly Report on Form 10-Q for the ~~three months ended September~~period ending June 30, 2006, ~~compared~~prior to ~~$0.2 million~~that quarter transportation expenses were shown as a deduction from oil and gas revenues. As such, for the ~~comparable period~~first quarter of 2006, there were no transportation expenses booked. However, the Company did disclose in ~~2005. The increase~~the aforementioned Form 10-Q that the amounts included as a reduction in revenues in the first quarter of 2006 ~~compared~~amounted to ~~2005 is primarily due to increased production in our Cotton Valley trend and the utilization of different transportation and marketing arrangements in that region.~~$0.5 million.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) expense increased to ~~$14.2~~$17.7 million ~~($3.30 per Mcfe)~~ from ~~$6.7~~$5.9 million ~~($3.10 per Mcfe)~~ for the same period in ~~2005~~2006 primarily due to a higher DD&A rate coupled with higher levels of production. The average DD&A rate increased to $5.28 per Mcfe in the ~~third~~first quarter of ~~2006~~2007, compared to $2.79 per Mcfe in the same quarter of ~~2005~~2006, due to a higher percentage of production coming from fields with higher average DD&A rates. We calculated first quarter 2007 DD&A rates using the December 31, 2006 reserves, which were valued at 2006 year-end prices as required by the SEC. Given the significant pricing difference between December 31, 2006 and December 31, 2005, a number of our wells drilled during 2006 were credited with fewer proved developed reserves than originally anticipated, thus resulting in the higher DD&A rate. The Company is currently planning to engage its independent engineering firm to audit our mid-year 2007 reserves, at which time we may recalculate the DD&A rates for the remainder of 2007.

~~Exploration~~Exploration.. Exploration ~~expense~~expenses for the ~~third~~first quarter of 2007 increased to $2.3 million from $1.4 million during the first quarter of 2006, due primarily to higher leasehold amortization costs and delay rental costs. As the Company has increased ~~to $1.8 million compared to $1.4 million for the third quarter of 2005. This increase was primarily due to a $0.4 million increase in~~its undeveloped acreage position since last year, the amortization of leasehold costs, which is a non-cash expense, has increased to $1.8 million from ~~$1.0~~$1.2 million in the ~~third quarter of 2005 to $1.4 million in the third quarter of 2006.~~prior year period.

General and Administrative.General and administrative expense increased to ~~$4.3~~$5.3 million for the ~~third~~first quarter of ~~2006~~2007, compared to ~~$2.5~~$3.8 million for the same period of ~~2005. This increase was primarily due~~2006. We accrued a liability for $1.0 million in March 2007 representing $0.4 million in penalties and interest and $0.6 million owed to the ~~implementation~~State of ~~SFAS 123R which increased non cash~~Louisiana for franchise taxes (see Note 8 to our consolidated financial statements). While we paid this amount under protest in April 2007, we plan to pursue the reimbursement of the full $1.0 million. Should our efforts prevail, the taxes paid under protest would be refunded. Of the $5.3 million incurred in the first quarter of 2007, stock based compensation expense, ~~by $1.0~~which is non-cash, amounted to $1.4 million from the third quarter of 2005 due to expensing the fair value of stock options granted. See Note C to the Consolidated Financial Statements for more information. In addition, an approximate 40% increaseversus $0.9 million in ~~the number of employees at September 30, 2006 versus September 30, 2005 generated higher compensation related costs.~~2006.

   Three Months Ended March 31,
   2007 2006
   (in thousands)
Other income (expense):

Interest Expense
   $ (2,624 ) $ (695 )
Gain (loss) on derivatives not qualifying for hedge accounting
   (9,487 ) 13,542
Income tax (expense) benefit
   6,743 (4,698 )
Gain on disposal, net of tax
   10,913 —
Income from discontinued operations, net of tax
   2,825 2,866

Interest Expense.Interest expense increased to ~~$2.5~~$2.6 million from the ~~third~~first quarter ~~2005~~2006 amount of ~~$0.4~~$0.7 million as a result of athe higher average ~~interest rate and higher borrowings in~~level of funded debt during the ~~third~~first quarter of 2007, due largely to our financing activities consummated during fiscal year 2006.

Gain (Loss) on Derivatives Not Qualifying for Hedge Accounting. ~~Gain~~Loss on derivatives not qualifying for hedge accounting was ~~$15.2~~$9.5 million for the ~~third~~first quarter of ~~2006~~2007 compared to a ~~loss~~gain of ~~$32.6~~$13.5 million for the ~~third~~first quarter of ~~2005.~~2006. The ~~gain~~loss in ~~2006~~2007 includes an unrealized ~~gain~~loss of ~~$15.0~~$13.2 million for the ~~changes~~change in fair value of our ineffective oil and gas hedges, and a realized gain of ~~$0.7~~$3.7 million for the effect of settled ~~derivatives on our ineffective gas hedges.~~derivatives. Our natural gas hedges were deemed ineffective beginning in the fourth quarter of 2004, and we have been required to reflect the ~~changes~~change in the fair value of our natural gas hedges in earnings rather than in accumulated other comprehensive loss, a component of stockholders’ equity. ~~Also included~~Additionally, our oil hedges were deemed ineffective beginning in the ~~2006 amount is an unrealized loss~~fourth quarter of ~~$0.5 million related to interest rate swaps that did not qualify for hedge accounting treatment.~~2006. To the extent that our hedges do not qualify for hedge accounting in the future, we will likewise be exposed to volatility in earnings resulting from changes in the fair value of our hedges.

Income taxes. Income taxes were a ~~non cash expense~~benefit of ~~$4.4~~$6.7 million for the ~~third~~first quarter of ~~2006~~2007 compared to ~~a benefit~~an expense of ~~$10.5~~$4.7 million for the ~~third~~first quarter of ~~2005.~~2006. The amounts in both periods essentially represented 35% of pre-tax income (loss). from continuing operations. We did not however, incur any income taxes on a current basis due to our substantial tax net operating loss ~~carrryforwards and significant drilling activity.~~carryforwards.

~~Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005~~Discontinued Operations

~~For~~. Income from discontinued operations for the ~~nine~~three months ended ~~September 30,~~March 31, 2007 and 2006, ~~we reported net income applicable~~related to common stock of $18.0 million, or $0.72 per basic share on total revenue of $85.3 million as compared with a net loss applicable to common stock of $26.5 million, or $1.15 per basic share, on total revenue of $43.9 million for the nine months ended September 30, 2005.

~~Oil and Natural Gas Revenues~~

~~Revenues presented in the table and the discussion below represent revenue from sales~~our South Louisiana assets. We sold substantially all of our oil and natural gas production volumes and include the realized gains and losses on the effective portion of our derivative instruments as further described under Note H to the Consolidated Financial Statements.

   Nine Months Ended
September 30, % Change
from 2005
   2006 2005 to 2006
Production:

Natural gas (MMcf)
   9,424 4,094 130 %
Oil and condensate (MBbls)
   355 324 10 %
Total (MMcfe)
   11,558 6,039 91 %
Revenues from production (in thousands):

Natural gas
   $ 63,208 $ 30,804 105 %
Effects of cash flow hedges
   —   —   —

Total
   $ 63,208 $ 30,804 105 %

Oil and condensate
   $ 23,850 $ 17,100 39 %
Effects of cash flow hedges
   (3,543 ) (4,941 ) 28 %

Total
   $ 20,307 $ 12,159 67 %

Natural gas, oil and condensate
   $ 87,058 $ 47,904 82 %
Effects of cash flow hedges
   (3,543 ) (4,941 ) 28 %

Total revenues from production
   $ 83,515 $ 42,963 94 %

~~Table continued on following page~~

   Nine Months Ended
September 30, % Change
from 2005
   2006 2005 to 2006
Average sales price per unit:

Natural gas (per Mcf)
   $ 6.71 $ 7.52 (11 %)
Effects of cash flow hedges (per Mcf)
   —   —   —

Total (per Mcf)
   $ 6.71 $ 7.52 (11 %)

Oil and condensate (per Bbl)
   $ 67.04 $ 52.73 27 %
Effects of cash flow hedges (per Bbl)
   (9.96 ) (15.24 ) 35 %

Total (per Bbl)
   $ 57.08 $ 37.49 52 %

Natural gas, oil and condensate (per Mcfe)
   $ 7.53 $ 7.93 (5 %)
Effects of cash flow hedges (per Mcfe)
   (0.31 ) (0.82 ) 63 %

Total (per Mcfe)
   $ 7.22 $ 7.11 1 %

~~Excluding the effects of settled derivatives, revenues from production increased 82% in the first nine months of 2006 compared to the same period in 2005 due primarily~~South Louisiana assets to a ~~substantial increase~~private company in ~~Cotton Valley trend production.~~

~~Other~~.a sale that closed March 20, 2007. We ~~own an approximate 2.5% working interest in~~also recorded a gain on disposal, net of tax, of $10.9 million. Our remaining South Louisiana assets, the Yscloskey gas processing plant in South Louisiana. As a plant owner, we retain that same percentage of natural gas liquid (“NGL”) revenue extracted from third party gas as a fee for the services provided by the plant. In addition, some third party non-plant owners that process their gas at Yscloskey are required to pay the plant owners a monetary processing fee. We retain our 2.5% share of this fee. For the first nine months of 2006, other revenue includes $1.1 million of such plant related revenues. The plant sustained extensive damage during Hurricane KatrinaSt. Gabriel, Bayou Bouillon and ~~normal operations resumed in late June 2006.~~

~~Lease Operating.~~ Lease operating expenses for the first nine months of 2006 increased to $14.3 million ($1.24 per Mcfe) from $6.9 million ($1.15 per Mcfe) in the first nine months of 2005. This increase was primarily attributable to the increase in the number of producing wells, as well as increases in salt water hauling and disposal and compression expenses related to the Cotton Valley trend. Also contributing to this increase is an additional loss of $0.8 million of hurricane related costs that will not be covered by insurance reimbursement, $0.3 million of additional abandonment costs related to outside operated wells and the uninsured portion of costs for an oil spill that occurred from a non-producing well in our Plumb Bob ~~field on~~fields, were considered held for sale at March ~~21, 2006. The spill of an estimated 2,000 barrels of oil was quickly contained and the costs of site restoration less our deductible will be covered by our insurance.~~

~~Production Taxes.~~Production taxes increased to $5.0 million for the first nine months of 2006 compared to $2.9 million for the comparable period in 2005 due to an increase in production volumes and product prices. Most of our Cotton Valley trend wells qualify for the “Tight Gas Sands” credit allowed for severance tax in the State of Texas. While we have only reflected credits on 35 wells that have been approved by the State, we anticipate that we will incur a gradually lower production tax rate in the future as we add further Cotton Valley wells to our production base and as reduced rates are approved and credits are received.

~~Transportation.~~Transportation costs increased to $2.9 million for the first nine months of 2006 compared to $0.3 million for the comparable period in 2005. The increase in 2006 compared to 2005 is primarily due to increased production in our Cotton Valley trend and the utilization of different transportation and marketing arrangements in that region.

~~Depreciation, Depletion and Amortization~~. DD&A expense increased to $37.1 million ($3.21 per Mcfe) in the first nine months of 2006 from $18.3 million ($3.03 per Mcfe) for the same period in 2005 primarily due to higher levels of production. The average DD&A rate increased in the first nine months of 2006 compared to in the same period in 2005 due to a higher percentage of production coming from fields with higher average DD&A rates.

~~Exploration~~. Exploration expense for the first nine months of 2006 decreased to $5.2 million compared to $5.3 million for the first nine months of 2005. This decrease was primarily due to the fact that we incurred no dry hole costs in 2006 while incurring $2.0 million in dry hole costs in the first nine months of 2005. Substantially offsetting this decrease was an increase in leasehold amortization.

~~General and Administrative.~~General and administrative expense increased to $12.2 million for the first nine months of 2006 compared to $6.0 million for the same period of 2005. This increase was primarily due to the implementation of SFAS 123R which increased non cash stock based compensation expense by $2.8 million from the first nine months of 2005 due to expensing the fair value of stock options granted. See Note C to the Consolidated Financial Statements for more information. In addition, an approximate 40% increase in the number of employees at September 30, 2006 versus September 30, 2005 generated higher compensation related costs.

~~Other.~~We own an approximate 2.5% working interest in the Yscloskey gas processing plant in South Louisiana. As a plant owner, we share in the costs of operating the plant. For the first nine months of 2006, we recorded $1.3 million of such plant related expenses. The plant sustained extensive damage during Hurricane Katrina and normal operations resumed in late June 2006.

~~Interest Expense.~~~~Interest expense increased to $4.7 million from the first nine months 2005 amount of $1.2 million as a result of a higher average interest rate and higher borrowings in the first nine months of 2006.~~

~~Gain (Loss) on Derivatives Not Qualifying for Hedge Accounting~~. Gain on derivatives not qualifying for hedge accounting was $34.6 million for the first nine months of 2006 compared to a loss of $42.7 million for the first nine months of 2005. The gain in 2006 includes an unrealized gain of $36.3 million for the changes in fair value of our ineffective oil and gas hedges, and a realized loss of $1.8 million for the effect of settled derivatives on our ineffective gas hedges. Our natural gas hedges were deemed ineffective, beginning in the fourth quarter of 2004, and we have been required to reflect the changes in the fair value of our natural gas hedges in earnings rather than in accumulated other comprehensive loss, a component of stockholders’ equity. Also included in the 2006 amount is an unrealized gain of $0.1 million related to interest rate swaps that did not qualify for hedge accounting treatment. To the extent that our hedges do not qualify for hedge accounting in the future, we will likewise be exposed to volatility in earnings resulting from changes in the fair value of our hedges.

~~Income taxes~~. Income taxes were a non cash expense of $13.0 million for the first nine months of 2006 compared to a benefit of $14.0 million for the first nine months of 2005. The amounts in both periods essentially represented 35% of pre-tax income (loss). We did not however, incur any income taxes on a current basis due to our substantial tax net operating loss carrryforwards and significant drilling activity.31, 2007.

Liquidity and Capital Resources

Cash Flows


	Three Months Ended March 31,
	2007			2006			Variance
	(in thousands)
Cash flow statement information:
Net cash:
Provided by operating activities	$	16,909		$	25,773		$	(8,864	)
Provided by (used in) investing activities		12,525			(62,595	)		75,120
Provided by (used in) financing activities		(28,046	)		18,483			(46,529	)

Increase (decrease) in cash and cash equivalents	$	1,388		$	(18,339	)	$	19,727

Operating activities. Net cash provided by operating activities ~~increased~~decreased to ~~$52.5~~$16.9 million ~~up 22%~~for the first quarter of 2007, from ~~$43.1~~$25.8 million in the first ~~nine months~~quarter of ~~2005. The increase was a result~~2006. Virtually all of ~~an increase in production levels~~this decrease resulted from the impact of working capital changes on our operating cash flow. During the first quarter of 2007, these changes used $2.9 million of available cash flow, whereas in the first ~~nine months~~quarter of 2006, ~~compared~~these changes provided an additional $12.3 million of cash flow. Given the nature of our ongoing operations in the Cotton Valley Trend and the number of rigs we currently have under contract, these working capital changes will likely fluctuate from time to ~~the first nine months~~time between being a source of ~~2005, partially offset by increases~~funds or a use of funds in ~~lease operating expenses and general and administrative expenses. Excluding the effect of settled derivatives, sales of oil and gas increased $39.2~~any given quarter. Our cash flows before working capital changes were up from $13.5 million in the first ~~nine months~~quarter of 2006 ~~compared~~ to ~~the same period in 2005, with realized oil and natural gas prices decreasing 5% from the first nine months of 2005. Production volumes increased 91%~~$19.8 million in the first ~~nine months~~quarter of ~~2006 compared to the first nine months of 2005. Operating cash flow amounts are net of changes in~~2007 based primarily on our current assets and current liabilities, which resulted in adjustments to our operating cash flow in the amounts of $6.6 million and $19.4 million in the nine months ended September 30, 2006 and 2005, respectively, primarily reflecting increased ~~revenue and expenditure activity associated with our Cotton Valley trend wells.~~production volumes.

Investing activities. Net cash used in investing activities was ~~$194.8~~a source of $12.5 million for the first ~~nine months~~quarter of ~~2006~~2007 compared to ~~$106.3~~a use of $62.6 million for the first ~~nine months~~quarter of ~~2005. For~~2006. We received proceeds of $74.0 million resulting from the ~~nine months ended September 30, 2006, additions to oil and gas properties totaled $196.3 million primarily due to accelerated development~~sale of substantially all of our ~~Cotton Valley trend, which accounted for 87% of the capital costs incurred~~South Louisiana assets in the first ~~nine months~~quarter of ~~2006.~~2007, which more than offset capital expenditures of $63.5 million. We also released $2.0 million from restricted cash held in escrow related to the sale properties. We conducted drilling operations on approximately 7619 gross wells, 15 gross wells located in our Cotton Valley Trend and 4 gross wells located in Angelina River, during the first quarter of 2007. As a comparison, we conducted drilling operations on approximately 30 gross wells, of which 6928 were located in our Cotton Valley ~~trend,~~Trend, during the first ~~nine months~~quarter of 2006. We also received proceeds of ~~$1.7~~$0.9 million from the sale of ~~two~~a salt water disposal ~~wells and the sale of a partial interest in deep rights~~facility in the ~~Cotton prospect in East Texas.~~first quarter of 2006.

Financing activities. Net cash used in financing activities was $28.0 million for the first quarter of 2007. Net cash provided by financing activities was ~~$123.8~~$18.5 million for the first ~~nine months~~quarter of ~~2006 compared to $61.7 million for~~2006. We used proceeds from our sale of properties in the first ~~nine months~~quarter of ~~2005. On January 23, 2006,~~2007 to pay the ~~initial purchasers of~~full outstanding balance on our ~~5.375% Series B Cumulative Convertible Preferred Stock (the “Series B Convertible Preferred Stock”) exercised their over-allotment option~~Senior Credit Facility, which had grown to ~~purchase an additional 600,000 shares at~~$65.0 million by the ~~same price per share, resulting in net proceeds of $29.0 million. In February 2006,~~time we fully redeemed all issued and outstanding shares of our Series A Convertible Preferred Stock at a cost of approximately $9.3 million. Financing activities also included net borrowings of $108.5 million under our senior revolver and term loan, resulting in amounts outstanding and borrowing availability underreceived these facilities of $138.5 million and $61.5 million, respectively, at September 30, 2006. Subsequent to the issuance of the Series B Convertible Preferred Stock, we have approximately $150.0 million of securities available for issue under the current shelf registration statement.proceeds.

On September 30, 2006, 201,102 outstanding warrants were converted into 194,500 shares of common stock. The exercise price of the warrants, originally issued in connection with a 1999 private placement of convertible notes and subsidiary securities, ranged from $0.9375 to $1.50 per share. The warrants expired on September 30, 2006 and were deemed to be automatically converted. No cash was exchanged as a result of this conversion.

In ~~September~~December 2006, our Board of Directors approved a ~~16% increase in our full year 2006~~preliminary 2007 capital expenditure budget ~~from $220.0~~of approximately $275 million, to ~~$255.0 million, of which approximately 85% is expected~~be used to ~~be focused on the relatively low risk~~fund our development drilling program, lease acquisitions and installation of infrastructure in the Cotton Valley ~~trend~~Trend of East Texas and Northwest ~~Louisiana~~Louisiana. Our Board of Directors may increase our capital expenditure budget for 2007, subject to future economic conditions and ~~the remainder on our existing properties and new exploration programs in South Louisiana.~~financial resources. We expect to finance our ~~2006~~2007 capital expenditures through a combination of cash flow from operations, proceeds from the aforementioned asset sales, and borrowings under our existing bank credit facility (see “Senior Credit ~~Facility and Term Loan”~~Facility”). In the future, we may issue additional debt or equity securities to provide additional financial resources for our capital expenditures and other general corporate purposes. Our ~~senior credit facility and term loan include~~Senior Credit Facility includes certain financial covenants with which we were in compliance as of ~~September 30, 2006.~~March 31, 2007. We do not anticipate a lack of borrowing capacity under our senior credit facility or term loan in the foreseeable future due to an inability to meet any such financial covenants nor a reduction in our borrowing base.

Senior Credit Facility ~~and Term Loan~~

On November 17, 2005, we amended our existing credit agreement and entered into an amended and restated senior credit agreement (the ~~“Amended and Restated~~“Senior Credit ~~Agreement”~~Facility”) and a ~~funded $30.0 million~~ second lien term loan (the ~~“Second Lien Term Loan Agreement”~~“Term Loan”) that expanded our borrowing capabilities and extended our credit facility for an additional two years. Total lender commitments under the ~~Amended and Restated~~Senior Credit ~~Agreement~~Facility were ~~increased from $50.0 million to~~ $200.0 million ~~and the maturity was extended from~~which matures on February 25, ~~2008 to February 25,~~ 2010. ~~The Second Lien Term Loan Agreement was subsequently increased to $50.0 million in August 2006.~~ Revolving borrowings under the ~~Amended and Restated~~Senior Credit ~~Agreement~~Facility are subject to periodic redeterminations of the borrowing base, which is currently established at ~~$150.0 million. With a portion~~$110.0 million, and is scheduled to be redetermined in the third quarter of ~~the net proceeds~~2007. As of ~~the offering of our 5.375% Series B Cumulative Convertible Preferred Stock (the “Series B Convertible Preferred Stock”) in December 2005,~~March 31, 2007, we ~~fully~~ repaid all outstanding ~~indebtedness on our revolver in~~amounts of the ~~amount of $47.5 million leaving a zero balance outstanding as of December 31, 2005.~~revolving borrowings under the Senior Credit Facility. Interest on revolving borrowings under the ~~Amended and Restated~~Senior Credit ~~Agreement~~Facility accrues at a rate calculated, at our option, at either the bank base rate plus 0.00% to 0.50%, or LIBOR plus 1.25% to 2.00%, depending on borrowing base utilization. ~~BNP Paribas (“BNP”) is the lead lender and administrative agent under the amended credit facility.~~

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

Current Ratio of 1.0/~~1.0;~~1.0,

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

~~Tangible Net Worth of not less~~

Total Debt no greater than ~~$53,392,838, plus 50% of cumulative net~~3.5 times EBITDAX for the trailing four quarters.

EBITDAX is earnings before interest expense, income ~~after September 30, 2004, plus 100% of the net proceeds of any subsequent equity issuance.~~

As of ~~September 30, 2006,~~March 31, 2007, we were in compliance with all of the financial covenants of the ~~Amended and Restated~~Senior Credit ~~Agreement.~~

~~The terms of the Second Lien Term Loan Agreement require us to maintain certain covenants. Capitalized terms are defined in the loan agreement. The covenants include:~~

~~Total Debt to EBITDAX Ratio which is not greater than 4.0/1.0 for the most recent period of four fiscal quarters for which financial statements are available and~~

~~Asset Coverage Ratio to be not less than 1.5/1.0.~~

~~As of September 30, 2006, we were in compliance with all of the financial covenants of the Second Lien Term Loan Agreement.~~

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 and Caddo Parishes, Louisiana. In addition, we have recently expanded our acreage position in the trend to include Harrison, Smith and Upshur Counties of Texas. We have steadily increased our acreage position in these areas over the last two years to approximately 144,400 gross acres (94,500 net acres) as of September 30, 2006. As of September 30, 2006, we have drilled and/or logged a cumulative total of 142 Cotton Valley wells with a 100% success rate, of which drilling operations were conducted on 19 gross wells during the third quarter of 2006. Our net production volumes from our Cotton Valley trend wells aggregated approximately 32,300 Mcfe per day in the third quarter of 2006, or approximately 69% of our total oil and gas production in the period.

In June 2006, we assigned 50% of our interest solely in the deep rights in our Cotton prospect in East Texas, defined as rights below the top of the Knowles Lime formation at 12,901’ below the surface, while reserving all of our rights to and above the Upper, Middle and Lower Travis Peak section in approximately 20,500 net acres for approximately $1.6 million. We had received one-half of the sales price as of September 30, 2006 and one-half has been recorded as a receivable in the consolidated financial statements. Pursuant to the agreement, within 18 months of the assignment, the assignee will either pay all of our share of drilling costs to a depth of 16,500’ feet in a well (the “carried well”) drilled on the acreage or pay us a non participation fee of $4.0 million should no well be drilled. The transaction was accounted for as a recovery of cost. The carried well is currently being drilled and was spud on September 25, 2006.

~~Burrwood/West Delta 83 Fields~~— In June 2006, our Norton II prospect came on line and as of July 31, 2006 was producing approximately 1,700 Mcf/day and 150 Bbl/day. In late August 2005, our Burrwood/West Delta 83 field was shut-in due to Hurricane Katrina and, except for the partial restoration of oil production in mid September, remained shut-in for the remainder of the third quarter of 2005. Production was gradually restored beginning in the fourth quarter of 2005 through the second quarter of 2006. As of June 30, 2006, we had returned to production all of our total pre-hurricane volumes in South Louisiana, including the Burrwood/West Delta 83 field and the Second Bayou field, which was impacted to a lesser extent by Hurricane Rita in September 2005. Damage to our facilities from both hurricanes was substantially covered by insurance.

~~St. Gabriel Field~~— In the first quarter of 2006, we commenced an exploratory test well on our Bordeaux Prospect. In March 2006, we announced that an open hole log on the test well, the Gueymard No. 1, had encountered approximately 60 feet of net pay. The well was preliminarily tested at a gross production rate of approximately 4,000 Mcf of gas per day and 200 barrels of oil per day with 5,000 pounds of flowing tubing pressure. Prior to placing the well on production, a downhole mechanical failure occurred prohibiting the well from the ability to produce from the original zone. After numerous attempts to correct the problem and reestablish production from the original zone, we have abandoned the original zone in this wellbore and initiated operations to recomplete the well into one of the shallower zones. We anticipate that production from the recompletion should occur during the fourth quarter of 2006.Facility.

See Note B1 to our Consolidated Financial Statements for a discussion of recently issued accounting pronouncements.

Texas House Bill 3 (“HB3”), which was signed into law in May, 2006, provides a comprehensive change in the method of business taxation in Texas. HB3 eliminates the taxable capital and earned surplus components of the existing Texas franchise tax and replaces these components with a taxable margin tax. This change is effective for tax reports filed on or after January 1, 2008 (which are based upon 2007 business activity) and results in no impact on our current Texas income tax.

We are required to include, in income, the impact of HB3 on our deferred state income taxes during the period which includes the date of enactment. Based upon the available information regarding the proposed implementation of this new tax, we have determined that no change in the amount of net deferred state income taxes is needed since the impact is not significant to the results of operations.

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 ~~2005~~2006 Annual Report on Form 10-K, ~~as amended,~~ includes a discussion of our critical accounting policies. ~~In addition, following the adoption~~

Income Taxes — FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes, provides guidance on recognition and measurement of ~~SFAS 123R, we consider our policies related to share-based compensation to be a critical accounting policy.~~

~~Share-Based Compensation Plans.~~~~In January 2006, we~~uncertainties in income taxes and is applicable for fiscal years beginning after December 15, 2006. The Company adopted SFAS 123R which amends SFAS 123 and supercedes APB 25. SFAS 123R requires new, modified and unvested share-based payment transactions with employees to be measured at fair value and recognized as compensation expense over the vesting period. The fair value of each option award is estimated using a Black-Scholes option valuation model that requires us to develop estimates for assumptions usedFIN 48 in the ~~model. The Black-Scholes valuation model uses the following assumptions: expected volatility, expected term~~first quarter of ~~option, risk-free interest rate~~2007. See Notes 1 and ~~dividend yield. Expected volatility estimates are developed by us based on historical volatility of~~7 to our stock. We use historical data to estimate the expected term of the options. The risk-free interest rate for periods within the expected life of the option is based on the U.S. Treasury yield in effect at the grant date. Our common stock does not pay dividends; therefore the dividend yield is zero.consolidated financial statements.

Certain statements in this Quarterly Report on Form 10-Q regarding future expectations and plans for future activities may be regarded as “forward looking statements” within the meaning of Private Securities Litigation Reform Act of 1995. They are subject to various risks, such as financial market conditions, operating hazards, drilling risks and the inherent uncertainties in interpreting engineering data relating to underground accumulations of oil and gas, as well as other risks discussed in detail in our Annual Report on Form 10-K, and such material changes to these factors, if any, which are discussed in Part II, Item 1A of this Form 10-Q. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct.

We enter into futures contracts or other hedging agreements from time to time to manage the commodity price risk for a portion of our production. We consider these agreements to be hedging activities and, as such, monthly settlements on the contracts that qualify for hedge accounting are reflected in our crude oil and natural gas sales. Our strategy, which is administered by the Hedging Committee of ~~the~~our Board of Directors, and reviewed periodically by the entire Board of Directors, has been to generally hedge between 30% and 70% of our production. As of ~~September 30, 2006,~~March 31, 2007, the commodity hedges we utilized were in the form of: (a) swaps, where we receive a fixed price and pay a floating price, based on NYMEX quoted ~~prices; and~~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.~~price, and (c) fixed price physical contracts which qualify for normal purchase and normal sale treatment, whereby we agree in advance with the purchasers of our physical gas volumes as to specific quantities to be delivered and specific prices to be received for gas deliveries at specific transfer points in the future. See Note H5 “Hedging Activities” to ~~the Consolidated Financial Statements~~our consolidated financial statements for additional information.

Our hedging contracts fall within our targeted range of 30% to 70% of our estimated net oil and gas production volumes for the applicable periods of 2007. The fair value of the crude oil and natural gas hedging contracts in place at ~~September 30, 2006~~March 31, 2007, resulted in an asset of ~~$8.7~~$2.2 million. Based on oil and gas pricing in effect at ~~September 30, 2006,~~March 31, 2007, a hypothetical 10% increase in oil and gas prices would have decreased the derivative asset to ~~$5.7~~$1.6 million while a hypothetical 10% decrease in oil and gas prices would have increased the derivative asset to ~~$11.6~~$2.9 million.


		Page

PART I	FINANCIAL INFORMATION	3

ITEM 1.	FINANCIAL STATEMENTS
	Consolidated Balance ~~Sheets: September 30, 2006~~Sheets as of March 31, 2007 and December 31, ~~2005~~2006	3
	Consolidated Statements of ~~Operations: For~~Operations for the three months ended March 31, 2007 and ~~nine months ended September 30,~~ 2006 ~~and 2005~~	4
	Consolidated Statements of Cash ~~Flows: For~~Flows for the ~~nine~~three months ended ~~September 30,~~March 31, 2007 and 2006 ~~and 2005~~	5
	Consolidated Statements of Comprehensive Income ~~(Loss): For~~for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2007 and 2006 ~~and 2005~~	6
	Notes to ~~the~~ Consolidated Financial Statements	7

ITEM 2.	~~MANAGEMENT’S~~MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	1714

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	2621

ITEM 4.	CONTROLS AND PROCEDURES	2721

PART II	OTHER INFORMATION	2823

ITEM 1A.	RISK FACTORS	2823

ITEM 6.	EXHIBITS	2823


	September 30, 2006			December 31, 2005			March 31, 2007			December 31, 2006
	(unaudited)
Assets
Current assets:
ASSETS							(unaudited)
CURRENT ASSETS:
Cash and cash equivalents	$	1,314		$	19,842		$	7,572		$	6,184
Assets held for sale								1,867			—
Accounts receivable, trade and other, net of allowance		11,044			6,397			9,996			9,665
Accrued oil and gas revenue		7,544			11,863			10,949			10,689
Fair value of oil and gas derivatives								2,228			13,419
Fair value of interest rate derivatives		217			107			54			219
Fair value of oil and gas derivatives		7,444			—
Prepaid expenses and other		1,490			463			1,257			994

Total current assets		29,053			38,672			33,923			41,170

Property and equipment:
PROPERTY AND EQUIPMENT:
Oil and gas properties (successful efforts method)		513,604			316,286			497,466			575,666
Furniture, fixtures and equipment		1,339			1,075			1,686			1,463

		514,943			317,361			499,152			577,129
Less: Accumulated depletion, depreciation and amortization		(117,418	)		(74,229	)		(94,761	)		(156,509	)

Net property and equipment		397,525			243,132			404,391			420,620

Other assets:
OTHER ASSETS:
Restricted cash		2,039			2,039			—			2,039
Fair value of oil and gas derivatives		1,213			—
Deferred tax asset		—			11,580			9,041			9,705
Other		3,377			1,103			5,384			5,730

Total other assets		6,629			14,722			14,425			17,474

Total assets	$	433,207		$	296,526
TOTAL ASSETS							$	452,739		$	479,264

Liabilities and Stockholders’ Equity
Current liabilities:
LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	34,194		$	31,574		$	29,860		$	36,263
Accrued liabilities		22,922			15,973			37,579			26,811
Fair value of oil and gas derivatives		—			23,271
Accrued abandonment costs		92			92			158			263

Total current liabilities		57,208			70,910			67,597			63,337
Long-term debt		138,500			30,000			175,000			201,500
Accrued abandonment costs		9,118			7,868			3,237			9,294
Fair value of oil and gas derivatives		—			6,159
Deferred tax liability		2,020			—

Total liabilities		206,846			114,937			245,834			274,131

Stockholders’ equity:
Commitments and contingencies (See Note 8)
STOCKHOLDERS’ EQUITY:
Preferred stock: 10,000,000 shares authorized:
Series A convertible preferred stock, $1.00 par value, 791,968 shares issued and outstanding at December 31, 2005		—			792
Series B convertible preferred stock, $1.00 par value, issued and outstanding 2,250,000 and 1,650,000 shares, respectively		2,250			1,650
Common stock: $0.20 par value, 50,000,000 shares authorized; issued and outstanding 25,183,134 and 24,804,737 shares, respectively		5,037			4,961
Series B convertible preferred stock, $1.00 par value, 2,250,000 shares issued and outstanding								2,250			2,250
Common stock: $0.20 par value, 50,000,000 shares authorized; issued and outstanding 28,321,464 and 28,218,422 shares, respectively								5,066			5,049
Additional paid in capital		211,580			187,967			215,153			213,666
Retained earnings (deficit)		9,373			(8,649	)
Unamortized restricted stock awards		—			(2,066	)
Treasury stock								(517	)		—
Accumulated deficit								(15,047	)		(14,571	)
Accumulated other comprehensive loss		(1,879	)		(3,066	)		—			(1,261	)

Total stockholders’ equity		226,361			181,589			206,905			205,133

Total liabilities and stockholders’ equity	$	433,207		$	296,526
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY							$	452,739		$	479,264


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2006			2005			2006			2005			2007			2006
Revenues:
Oil and natural gas revenues	$	29,276		$	17,312		$	83,515		$	42,963
Oil and gas revenues													$	23,317		$	14,423
Other		159			225			1,797			938			225			346

		29,435			17,537			85,312			43,901			23,542			14,769

Operating expenses:
Lease operating expense		6,073			2,404			14,327			6,936			4,111			2,238
Production taxes		1,832			1,177			5,047			2,934			318			902
Transportation		1,245			167			2,921			258			1,075			—
Depreciation, depletion and amortization		14,197			6,696			37,120			18,287			17,708			5,882
Exploration		1,814			1,397			5,178			5,339			2,326			1,399
General and administrative		4,282			2,544			12,248			5,969			5,338			3,771
Gain on sale of assets		—			—			—			(169	)
Other		85			112			1,344			512

		29,528			14,497			78,185			40,066			30,876			14,192

Operating income (loss)		(93	)		3,040			7,127			3,835			(7,334	)		577

Other income (expense):
Interest expense		(2,509	)		(378	)		(4,706	)		(1,204	)		(2,624	)		(695	)
Gain (loss) on derivatives not qualifying for hedge accounting		15,188			(32,624	)		34,611			(42,736	)		(9,487	)		13,542

		12,679			(33,002	)		29,905			(43,940	)		(12,111	)		12,847

Income (loss) before income taxes		12,586			(29,962	)		37,032			(40,105	)		(19,445	)		13,424
Income tax (expense) benefit		(4,405	)		10,488			(12,961	)		14,035			6,743			(4,698	)

Net income (loss)		8,181			(19,474	)		24,071			(26,070	)
Income (loss) from continuing operations														(12,702	)		8,726

Discontinued operations (See Note 6):
Gain on disposal, net of tax														10,913			—
Income from discontinued operations, net of tax														2,825			2,866

														13,738			2,866

Net income														1,036			11,592
Preferred stock dividends		1,511			158			4,504			474			1,512			1,481
Preferred stock redemption premium		—			—			1,545			—			—			1,536

Net income (loss) applicable to common stock	$	6,670		$	(19,632	)	$	18,022		$	(26,544	)	$	(476	)	$	8,575

Net income (loss) per share applicable to common stock:
Income (loss) from continuing operations per common share:
Basic	$	0.27		$	(0.79	)	$	0.72		$	(1.15	)	$	(0.51	)	$	0.35

Diluted	$	0.26		$	(0.79	)	$	0.71		$	(1.15	)	$	(0.51	)	$	0.34

Weighted average number of common shares:
Income from discontinued operations per common share:
Basic		24,972			24,784			24,923			23,024		$	0.55		$	0.12

Diluted		25,346			24,784			25,386			23,024		$	0.54		$	0.11

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

Diluted													$	(0.02	)	$	0.34

Average common shares outstanding:
Basic														25,141			24,860

Diluted														25,386			25,366


	Nine Months Ended September 30,						Three Months Ended March 31,
	2006			2005			2007			2006
Cash flows from operating activities:
Net income (loss)	$	24,071		$	(26,070	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities -
Cash flows from operating activities:
Net income							$	1,036		$	11,592
Adjustments to reconcile net income to net cash provided by operating activities -
Depletion, depreciation and amortization		37,120			18,287			17,708			9,832
Unrealized (gain) loss on derivatives not qualifying for hedge accounting		(36,370	)		40,612			13,124			(16,121	)
Deferred income taxes		12,961			(14,035	)		654			6,241
Dry hole costs		20			2,012			905			—
Amortization of leasehold costs		3,909			2,201			1,766			1,158
Stock based compensation		3,694			824
Stock based compensation (non-cash)								1,350			932
Gain on sale of assets		—			(169	)		(16,789	)		—
Other non cash items		456			46			98			(193	)
Changes in assets and liabilities -
Accounts receivable and other assets		(2,551	)		(2	)
Accounts payable and accrued liabilities		9,143			19,422
Accounts receivable, trade and other, net of allowance								(331	)		(3,601	)
Accrued oil and gas revenue								(260	)		1,926
Prepaid expenses and other								(263	)		7
Accounts payable								(3,049	)		8,524
Accrued liabilities								960			5,476

Net cash provided by operating activities		52,453			43,128			16,909			25,773

Cash flows from investing activities:
Capital expenditures								(63,543	)		(63,504	)
Proceeds from sale of assets								74,029			909
Release of restricted cash funds								2,039			—

Cash flows from investing activities:
Additions to oil and gas properties		(196,277	)		(106,227	)
Additions to furniture and fixtures		(264	)		(185	)
Proceeds from sale of assets		1,731			155
Net cash provided by (used in) investing activities								12,525			(62,595	)

Net cash used in investing activities		(194,810	)		(106,257	)


Cash flows from financing activities:
Net proceeds from Series B Preferred Stock offering		28,973			—
Redemption of Series A Preferred Stock		(9,319	)		—
Net proceeds from common stock offering		—			53,175
Cash Flows from Financing Activities
Principal payments of bank borrowings		(21,000	)		(46,000	)		(65,000	)		—
Proceeds from bank borrowings		129,500			55,000			38,500			—
Net proceeds from preferred stock offering								—			29,037
Redemption of preferred stock								—			(9,310	)
Preferred stock dividends								(1,511	)		(1,229	)
Deferred financing costs		(458	)		(203	)		(35	)		—
Exercise of stock options		400			477
Preferred stock dividends		(4,252	)		(475	)
Production payments		—			(238	)
Other		(15	)		—			—			(15	)

Net cash provided by financing activities		123,829			61,736
Net cash provided by (used in) financing activities								(28,046	)		18,483

Decrease in cash and cash equivalents		(18,528	)		(1,393	)
Net increase (decrease) in cash and cash equivalents								1,388			(18,339	)
Cash and cash equivalents, beginning of period		19,842			3,449			6,184			19,842

Cash and cash equivalents, end of period	$	1,314		$	2,056			7,572			1,503


Supplemental disclosures of cash flow information:
Cash paid during the period for interest	$	3,427		$	1,060		$	1,000			674

Cash paid during the period for income taxes	$	—		$	85		$	—			—


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2006			2005			2006			2005			2007		2006
Net income (loss)	$	8,181		$	(19,474	)	$	24,071		$	(26,070	)

Net income													$	1,036	$	11,592

Other comprehensive income (loss):
Change in fair value of derivatives (1)		1,197			(2,743	)		(978	)		(7,124	)		—		(1,079	)
Reclassification adjustment (2)		1,063			1,592			2,165			4,056			1,261		412

Other comprehensive income (loss)		2,260			(1,151	)		1,187			(3,068	)		1,261		(667	)

Comprehensive income (loss)	$	10,441		$	(20,625	)	$	25,258		$	(29,138	)
Comprehensive income													$	2,297	$	10,925


(1) Net of income tax (expense) benefit of:	$	(644	)	$	1,477		$	527		$	3,836
(1) Net of income tax benefit of:													$	—	$	581
(2) Net of income tax expense of:		573			857			1,166			2,184		$	679	$	222


	Three Months Ended September 30, 2005			Nine Months Ended September 30, 2005
Net loss as reported	$	(19,474	)	$	(26,070	)
Add: Stock based compensation programs recorded as expense, net of tax		206			535
Deduct: Total stock based compensation expense, net of tax		(313	)		(856	)

Pro forma net loss	$	(19,581	)	$	(26,391	)


Net loss applicable to common stock, as reported	$	(19,632	)	$	(26,544	)
Add: Stock based compensation programs recorded as expense, net of tax		206			535
Deduct: Total stock based compensation expense, net of tax		(313	)		(856	)

Pro forma net loss applicable to common stock	$	(19,739	)	$	(26,865	)


Net loss applicable to common stock per share:
Basic and diluted – as reported	$	(0.79	)	$	(1.15	)
Basic and diluted – pro forma	$	(0.80	)	$	(1.17	)


	September 30, 2006		December 31, 2005
Risk free interest rate	4.50 – 5.00	%	6.00	%
Weighted average volatility	54-57	%	47	%
Dividend yield	0	%	0	%
Expected years until exercise	5-6		5


	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term In Years	Aggregate Intrinsic Value
Outstanding at January 1, 2006	519,500		$	13.70
Granted	625,000			24.10
Exercised	(41,000	)		9.75
Forfeited	(55,000	)		22.13

Outstanding at September 30, 2006	1,048,500		$	19.61	8.4	$	11,020,638

Exercisable at September 30, 2006	341,833		$	13.07	6.9	$	5,828,971


	Number of Shares		Weighted Average Grant-Date Fair Value
Unvested at January 1, 2006	263,890		$	11.13
Vested	(126,603	)		8.29
Granted	117,079			24.07
Forfeited	(11,997	)		21.80

Unvested at September 30, 2006	242,369		$	18.33


Beginning balance January 1, 2006	$	7,960
Liabilities incurred		1,114
Liabilities settled		(175	)
Accretion expense (reflected in depletion, depreciation and amortization expense)		311

Ending balance September 30, 2006	$	9,210


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

Ending balance		3,395
Less current portion		(158	)

	$	3,237


Swaps	Volume	Average Price
Natural gas (MMBtu/day)
4Q 2006	15,000	6.95
1Q 2007	10,000	7.77
Oil (Bbl/day)
4Q 2006	800	50.80
2007	400	53.35


Collars	Volume	Average Floor/Cap
Natural gas (MMBtu/day)
1Q 2007	25,000	$7.80 – $12.42
2Q 2007	30,000	7.67 – 12.67
3Q 2007	30,000	7.67 – 12.67
4Q 2007	30,000	7.67 – 12.67
Oil (Bbl/day)
2007	400	$60.00 – $76.50


Effective Date	Maturity Date	LIBOR Swap Rate		Notional Amount
02/27/06	02/26/07	4.08	%	$	23.0
02/27/06	02/26/07	4.85	%		17.0
02/26/07	02/26/09	4.86	%		40.0


	Three Months Ended September 30,						% Change from 2005
	2006			2005			to 2006
Production:
Natural gas (MMcf)		3,509			1,574		123	%
Oil and condensate (MBbls)		131			98		34	%
Total (MMcfe)		4,297			2,163		99	%
Revenues from production (in thousands):
Natural gas	$	21,779		$	13,744		58	%
Effects of cash flow hedges		—			—		—

Total	$	21,779		$	13,744		58	%

Oil and condensate	$	9,118		$	5,857		56	%
Effects of cash flow hedges		(1,621	)		(2,289	)	29	%

Total	$	7,497		$	3,568		110	%

Natural gas, oil and condensate	$	30,897		$	19,601		58	%
Effects of cash flow hedges		(1,621	)		(2,289	)	29	%

Total revenues from production	$	29,276		$	17,312		69	%


~~4.1~~		~~Goodrich Petroleum Corporation 2006 Long-Term Incentive Plan (incorporated by reference to the Company’s Proxy Statement filed April 17, 2006).~~

~~4.2~~		~~Form of Grant of Restricted Phantom Stock (1995 Stock Option Plan) (incorporated herein by reference to Exhibit 4.2 to the Company’s Form S-8 Registration Statement filed on October 23, 2006).~~

~~4.3~~		Form of Grant of Restricted Phantom Stock (2006 Long-Term Incentive Plan) (incorporated herein by reference to Exhibit 4.3 to the Company’s Form S-8 Registration Statement filed on October 23, 2006).

~~4.4~~		~~Form of Director Stock Option Agreement (with vesting schedule) (incorporated herein by reference to Exhibit 4.4 to the Company’s Form S-8 Registration Statement filed on October 23, 2006).~~

~~4.5~~		~~Form of Director Stock Option Agreement (immediate vesting) (incorporated herein by reference to Exhibit 4.5 to the Company’s Form S-8 Registration Statement filed on October 23, 2006).~~

~~4.6~~		~~Form of Incentive Stock Option Agreement (incorporated herein by reference to Exhibit 4.6 to the Company’s Form S-8 Registration Statement filed on October 23, 2006).~~

~~4.7~~		~~Form of Nonqualified Stock Option Agreement (incorporated herein by reference to Exhibit 4.7 to the Company’s Form S-8 Registration Statement filed on October 23, 2006).~~

*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.


			GOODRICH PETROLEUM CORPORATION (Registrant)

Date: ~~November 7, 2006~~May 10, 2007	By:	~~By:~~	/s/ Walter G. Goodrich
				Walter G. Goodrich
				Vice Chairman & Chief Executive Officer

Date: ~~November 7, 2006~~May 10, 2007	By:	~~By:~~	/s/ David R. Looney
				David R. Looney
				Executive Vice President & Chief Financial Officer