Edgar Filing: GOODRICH PETROLEUM CORP

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Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

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

For the Quarterly Period Ended March 31, 2010

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

Commission file number: 001-12719

GOODRICH PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Delaware

76-0466193

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

801 Louisiana, Suite 700

Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨

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

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

The number of shares outstanding of the Registrant’s common stock as of May 4, 2010 was 37,556,917.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS


		Page
PART I	FINANCIAL INFORMATION	3

ITEM 1	FINANCIAL STATEMENTS	3

	Consolidated Balance Sheets as of March 31, 2010 and December 31, 2009	3

	Consolidated Statements of Operations for the three months ended March 31, 2010 and 2009	4

	Consolidated Statements of Cash Flows for the three months ended March 31, 2010 and 2009	5

	Notes to Consolidated Financial Statements	6

ITEM 2	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	14

ITEM 3	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	23

ITEM 4	CONTROLS AND PROCEDURES	23

PART II	OTHER INFORMATION	24

ITEM 1	LEGAL PROCEEDINGS	24

ITEM 1A	RISK FACTORS	24

ITEM 6	EXHIBITS	25

PART 1 – FINANCIAL INFORMATION

Item 1 – Financial Statements

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(In thousands)


	March 31, 2010			December 31, 2009
	(unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	100,946		$	125,116
Accounts receivable, trade and other, net of allowance		11,576			7,944
Income taxes receivable		9,633			15,438
Accrued oil and gas revenue		15,604			17,206
Fair value of natural gas derivatives		25,519			5,403
Prepaid expenses and other		2,737			2,271

Total current assets		166,015			173,378

PROPERTY AND EQUIPMENT:
Oil and gas properties (successful efforts method)		1,383,020			1,339,462
Furniture, fixtures and equipment		4,256			3,985

		1,387,276			1,343,447
Less: Accumulated depletion, depreciation and amortization		(705,085	)		(669,463	)

Net property and equipment		682,191			673,984
Fair value of natural gas derivatives		13,926			—
Deferred tax asset		4,700			4,700
Deferred financing cost		7,435			8,212

TOTAL ASSETS	$	874,267		$	860,274


LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	34,371		$	35,079
Accrued liabilities		30,399			25,308
Deferred tax liability current		4,700			4,700
Accrued abandonment costs		3,259			4,574
Fair value of natural gas basis derivatives		1,215			—
Fair value of interest rate derivatives		548			1,087

Total current liabilities		74,492			70,748
LONG-TERM DEBT		334,119			330,147
Accrued abandonment costs		15,387			13,716
Fair value of natural gas derivatives		—			278

Total liabilities		423,998			414,889

Commitments and contingencies (See Note 10)
STOCKHOLDERS’ EQUITY:
Preferred stock: 10,000,000 shares authorized: Series B convertible preferred stock, $1.00 par value, issued and outstanding 2,250,000 shares		2,250			2,250
Common stock: $0.20 par value, 100,000,000 shares authorized; issued and outstanding 37,528,930 and 37,452,023 shares, respectively		7,181			7,166
Treasury stock (20,691 and 19,915 shares, respectively)		(409	)		(411	)
Additional paid in capital		639,383			637,335
Retained earnings		(198,136	)		(200,955	)

Total stockholders’ equity		450,269			445,385

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	874,267		$	860,274

See accompanying notes to consolidated financial statements.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, Except Per Share Amounts)

(Unaudited)


	Three Months Ended March 31,
	2010			2009
REVENUES:
Oil and gas revenues	$	40,426		$	28,440
Other		29			21

		40,455			28,461


OPERATING EXPENSES:
Lease operating expense		7,232			8,996
Production and other taxes		963			1,488
Transportation		2,453			2,588
Depreciation, depletion and amortization		30,213			33,658
Exploration		2,979			2,220
General and administrative		9,446			7,057
Other		8,500			—

		61,786			56,007

Operating loss		(21,331	)		(27,546	)

OTHER INCOME (EXPENSE):
Interest expense		(9,120	)		(5,208	)
Interest income and other		53			246
Gain on derivatives not designated as hedges		34,729			37,006

		25,662			32,044

Income before income taxes		4,331			4,498
Income tax expense		—			1,354

Net income		4,331			3,144
Preferred stock dividends		1,512			1,512

Net income applicable to common stock	$	2,819		$	1,632


PER COMMON SHARE
Net income applicable to common stock - basic	$	0.08		$	0.05
Net income applicable to common stock - diluted	$	0.08		$	0.05

Weighted average common shares outstanding - basic		35,858			35,970
Weighted average common shares outstanding - diluted		35,949			36,075

See accompanying notes to consolidated financial statements.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Three Months Ended March 31,
	2010			2009
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	4,331		$	3,144
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, and amortization		30,213			33,658
Unrealized gain on derivatives not designated as hedges		(33,644	)		(15,980	)
Deferred income taxes		—			1,358
Exploration		475			101
Amortization of leasehold costs		1,605			1,524
Stock based compensation (non-cash)		2,509			1,631
Amortization of debt discount and finance cost		4,749			2,247
Change in assets and liabilities:
Accounts receivable, trade and other, net of allowance		2,163			(2,667	)
Accrued oil and gas revenue		1,602			5,266
Prepaid expense and other		(479	)		1,170
Accounts payable		(698	)		5,104
Accrued liabilities		5,941			(299	)

Net cash provided by operating activities		18,767			36,257


CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(40,981	)		(103,314	)

Net cash used in investing activities		(40,981	)		(103,314	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Preferred stock dividends		(1,512	)		(1,512	)
Other		(444	)		(659	)

Net cash used in financing activities		(1,956	)		(2,171	)

DECREASE IN CASH AND CASH EQUIVALENTS		(24,170	)		(69,228	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		125,116			147,548

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	100,946		$	78,320

See accompanying notes to consolidated financial statements.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—Description of Business and Significant Accounting Policies

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

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

The accompanying consolidated financial statements of the Company should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009. The results of operations for the three months ended March 31, 2010, are not necessarily indicative of the results to be expected for the full year.

Reclassifications—Certain reclassifications of prior year balances have been made to conform them to current year presentation. These reclassifications have no impact on net income.

Use of Estimates—Our Management has made a number of estimates and assumptions relating to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with US GAAP.

New Accounting Pronouncements

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

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

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 2—Resignation of Executive Officer

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

•

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

•

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

•

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

The Company recognized additional expense related to the agreement of approximately $0.9 million during the quarter ended March 31, 2010.

NOTE 3—Asset Retirement Obligations

The reconciliation of the beginning and ending asset retirement obligation for the period ending March 31, 2010, is as follows (in thousands):


	March 31, 2010
Beginning balance	$	18,290
Liabilities incurred		10
Revisions in estimated liabilities		—
Liabilities settled		—
Accretion expense		346
Dispositions		—

Ending balance	$	18,646

Current liability	$	3,259
Long term liability	$	15,387

NOTE 4—Long-Term Debt

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


	March 31, 2010			December 31, 2009
Senior Credit Facility	$	—		$	—
3.25% Convertible Senior Notes due 2026		175,000			175,000
Debt discount on 3.25% Convertible Senior Notes		(13,915	)		(15,915	)
5.0% Convertible Senior Notes due 2029		218,500			218,500
Debt discount of 5.0% Convertible Senior Notes		(45,466	)		(47,438	)

Total long-term debt	$	334,119		$	330,147

Senior Credit Facility

On May 5, 2009, we entered into a Second Amended and Restated Credit Agreement (“Senior Credit Facility”) that replaced our previous facility. Total lender commitments under the Senior Credit Facility are $350 million. The Senior Credit Facility matures on August 31, 2011. The Senior Credit Facility can be further extended to July 1, 2012 upon receipt of proceeds from a refinancing sufficient to prepay the 3.25% convertible senior notes due 2026. Revolving borrowings under the Senior Credit Facility are limited to, and subject to periodic redeterminations of, the borrowing base. The initial borrowing base was established at $175 million. The borrowing base interest on revolving borrowings under the Senior Credit Facility accrues at a rate calculated, at our option, at the bank base rate plus 0.75% to 1.50% or LIBOR plus 2.25% to 3.00%, depending on borrowing base utilization. Pursuant to the terms of the Senior Credit Facility, borrowing base redeterminations are made on a semi-annual basis on April 1 and October 1. In connection with the offering of our $218.5 million 5% convertible senior notes due 2029, we entered into an amendment of our Senior Credit Facility to permit the issues of the notes and required payments made on the notes thereafter and to exclude up to $175 million of our 3.25% convertible senior notes due 2026 or our 5% convertible senior notes due 2029 from the definition of Total Debt used in our financial covenants under the Senior Credit Facility. On April 20, 2010, the borrowing base was increased to $200 million. We currently have no amounts outstanding under the Senior Credit Facility.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

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

•

Current Ratio of 1.0/1.0;

•

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

•

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

We were in compliance with all the financial covenants of the Senior Credit Facility as of March 31, 2010.

3.25% Convertible Senior Notes Due 2026

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

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

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

an additional amount of shares per $1,000 of principal amount of the 2026 Notes equal to the incremental share factor (2.6762), multiplied by a fraction, the numerator of which is the applicable stock price less the “base conversion price” and the denominator of which is the applicable stock price.

We separately account for the liability and equity components of the 2026 Notes in a manner that reflects our nonconvertible debt borrowing rate when interest is recognized in subsequent periods. As of March 31, 2010, the $175.0 million 2026 Notes were carried on the balance sheet at $161.1 million with a debt discount balance of $13.9 million. As of December 31, 2009, the $175.0 million 2026 Notes were carried on the balance sheet at $159.1 million with a debt discount of $15.9 million. The remaining amount of debt discount as of March 31, 2010 will be amortized using the effective interest rate method based upon an original five year term through December 1, 2011.

Interest expense relating to the contractual interest rate and amortization of both financing cost and debt discount relating to the 2026 Notes for the three months ended March 31, 2010 was $3.6 million. The effective interest rate on the liability component of the Notes was 9.2% for the three month period ended March 31, 2010.

5% Convertible Senior Notes due 2029

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

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

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

We separately account for the liability and equity components of the 2029 Notes in a manner that reflects our nonconvertible debt borrowing rate when interest is recognized in subsequent periods. As of March 31, 2010, the $218.5 million 2029 Notes were carried on the balance sheet at $173.0 million with a debt discount balance of $45.5 million. As of December 31, 2009, the $218.5 million 2029 Notes were carried on the balance sheet at $171.1 million with a debt discount of $47.4 million. The debt discount will be amortized using the effective interest rate method based upon an original five year term through October 1, 2014. Interest expense recognized relating to the contractual interest rate and amortization of both financing cost and debt discount for the three months ended March 31, 2010 was $5.0 million. The effective interest rate on the liability component of the notes was 11.7% for the three months ended March 31, 2010.

NOTE 5—Net Income Per Common Share

Net income applicable to common stock was used as the numerator in computing basic and diluted income per common share for the three months ended March 31, 2010 and 2009. The following table reconciles the weighted average shares outstanding used for these computations (in thousands):


	For the Three Months Ended March 31,
	2010		2009
	(Amounts in thousands, except per share data)
Basic income per share:
Income applicable to common stock	$	2,819	$	1,632
Average shares of common stock outstanding (1)		35,858		35,970

Basic income per share:	$	0.08	$	0.05

Income applicable to common stock	$	2,819	$	1,632
Dividends on convertible preferred stock (2)		—		—
Interest and amortization of loan cost and debt discount on senior convertible notes, net of tax (3)		—		—

Diluted income:	$	2,819	$	1,632

Average shares of common stock outstanding (1)		35,858		35,970
Assumed conversion of convertible preferred stock (2)		—		—
Assumed conversion of convertible senior notes (3)		—		—
Stock options and restricted stock		91		105

Average diluted shares outstanding		35,949		36,075

Diluted income per share	$	0.08	$	0.05

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

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

(3)

Common shares issuable upon assumed conversion of our convertible senior notes amounting to 8,958,394 shares in 2010 and 2,653,927 shares in 2009 and the accrued interest on the 2026 Notes and the 2029 Notes were not included in the computation of diluted loss per share for the periods presented as they would have not been dilutive.

NOTE 6—Income Taxes

We recorded no income tax expense for the three months ended March 31, 2010. We increased our valuation allowance and reduced our net deferred tax asset to zero during 2009 after considering all available positive and negative evidence related to the realization of our deferred tax asset. Our assessment of the realization of our deferred tax asset has not changed and as a result, we continue to maintain a full valuation allowance for our net deferred asset as of March 31, 2010.

As of March 31, 2010, we had no unrecognized tax benefits. There were no significant changes to the calculation since December 31, 2009. We do not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to March 31, 2011.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 7—Stockholders’ Equity

Restricted Stock

During the three months ended March 31, 2010, 78,108 restricted shares, which had a weighted average grant date value of $21.98 per share, vested.

Share Lending Agreement

In connection with the offering of our 3.25% notes in December 2026, we agreed to lend an affiliate of Bear, Stearns & Co. (“BSC”) a total of 3,122,263 shares of our common stock under the Share Lending Agreement. Under this agreement, BSC is entitled to offer and sell such shares and use the sale to facilitate the establishment of a hedge position by investors in the notes. BSC will receive all proceeds from the common stock offerings and lending transactions under this agreement. BSC is obligated to return the shares to us in the event of certain circumstances, including the redemption of the notes or the conversion of the notes to shares of our common stock pursuant to the terms of the indenture governing the notes. The Share Lending Agreement also requires BSC to post collateral if its credit rating is below either A3 by Moody’s Investors Service (“Moody’s”) or A-by Standard and Poor’s (“S&P”). On March 20, 2008, BSC had returned 1,497,963 shares of the 3,122,263 originally borrowed shares. The 1,497,963 shares returned to us were recorded as treasury stock and retired in March 2008. In May 2008, JP Morgan Chase & Co. completed its acquisition of and assumed all counterparty liabilities of The Bear Stearns Companies Inc.

The 1,624,300 shares of common stock outstanding as of March 31, 2010, under the Share Lending Agreement, have a fair value of $25.4 million based upon a closing price on March 31, 2010 of $15.64 per share and are required to be returned to us in the future. The shares are treated in basic and diluted earnings per share as if they were already returned and retired. As a result, the shares of common stock lent under the Share Lending Agreement have no impact on the earnings per share calculation.

Capped Call Option Transactions

On December 10, 2007, we closed the public offering of 6,430,750 shares of our common stock at a price of $23.50 per share. Net proceeds from the offering were approximately $145.4 million after deducting the underwriters’ discount and estimated offering expenses. We used approximately $123.8 million of the net proceeds to pay off outstanding borrowings under our Senior Credit Facility, and approximately $21.6 million of the net proceeds to purchase capped call options on shares of our common stock from affiliates of Bear Stearns and Company (“BSC”) and J.P. Morgan Securities Inc. The capped call option transactions covered, subject to customary anti-dilution adjustments, approximately 5.8 million shares of our common stock, and each of them was divided into a number of tranches with differing expiration dates. Approximately 77,333 options per trading day will expire over each of three separate 25 consecutive trading day settlement periods. During 2009, two-thirds of the options expired. The remaining one-third of the options subject to the capped call will expire beginning on May 18, 2010. For more information on these transactions, please see our Annual Report on Form 10-K for the year ended December 31, 2009.

NOTE 8—Derivative Activities

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

The total financial impact of our derivative activities on our consolidated Statement of Operations for the three months ended March 31, 2010, was a $34.7 million gain, which consisted of $1.1 million in realized gain and a $33.6 million unrealized gain.

Commodity Derivative Activity

We enter into swap contracts, costless collars or other derivative agreements from time to time to manage the commodity price risk for a portion of our production. Our strategy, which is administered by the Hedging Committee of our Board of Directors, and reviewed periodically by the entire Board of Directors, has been to generally hedge between 30% and 70% of our estimated total production for the period the derivatives are in effect. As of March 31, 2010, the commodity derivatives we used were in the form of:

(a)

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

(b)

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

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

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

As of March 31, 2010, our open forward positions on our outstanding commodity derivative contracts, all of which were with BNP Paribas, JP Morgan or Bank of Montreal, were as follows:


Collars (NYMEX)	Daily Volume	Total Volume	Average Floor/Cap		Fair Value at March 31, 2010 (in thousands)
Natural gas (MMBtu)					$	41,293
2Q 2010	50,000	4,550,000	$	6.00 – $7.10
3Q 2010	50,000	4,600,000	$	6.00 – $7.10
4Q 2010	50,000	4,600,000	$	6.00 – $7.10
1Q 2011	40,000	3,600,000	$	6.00 – $7.09
2Q 2011	40,000	3,640,000	$	6.00 – $7.09
3Q 2011	40,000	3,680,000	$	6.00 – $7.09
4Q 2011	40,000	3,680,000	$	6.00 – $7.09
1Q 2012	40,000	3,640,000	$	6.00 – $7.09
2Q 2012	40,000	3,640,000	$	6.00 – $7.09
3Q 2012	40,000	3,680,000	$	6.00 – $7.09
4Q 2012	40,000	3,680,000	$	6.00 – $7.09

Basis Swaps (NYMEX/TexOk)			Average Price (1)
Natural gas (MMBtu)					$	(3,063	)
2Q 2010	50,000	4,550,000	$	0.368
3Q 2010	50,000	4,600,000	$	0.368
4Q 2010	50,000	4,600,000	$	0.368

				Total	$	38,230

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

The fair value of the natural gas derivative contracts in place at March 31, 2010, that are marked to market resulted in a current asset of $25.5 million, a non-current asset of $13.9 million and a current liability of $1.2 million. We measure the fair value of our commodity derivatives contracts by applying the income approach, and these contracts are classified within Level 2 of the valuation hierarchy. See Note 9. For the three months ended March 31, 2010, we recognized in earnings a $34.7 million gain from these natural gas derivative instruments, which consisted of $1.6 million in realized gain and $33.1 million in unrealized gain.

Interest Rate Swap

We have variable-rate debt obligations that expose us to the effects of changes in interest rates. To partially reduce our exposure to interest rate risk, from time to time we enter into interest rate swap agreements. These swaps are not designated as hedges. At March 31, 2010, we had the following interest rate swaps in place with BNP Paribas and Bank of Montreal:


Effective Date	Maturity Date	LIBOR Swap Rate		Notional Amount (Millions)		Fair Value (in thousands)
4/22/2008	4/22/2010	3.191	%	$	25.0	$	(183	)
4/22/2008	4/22/2010	3.191	%		50.0		(365	)

						$	(548	)

The fair value of the interest rate swap contracts at March 31, 2010, resulted in a current liability of $0.5 million. We measure the fair value of our interest rate swaps by applying the income approach and these contracts are classified within Level 2 of the valuation hierarchy. See Note 9. For the three months ended March 31, 2010, we recognized a loss of less than $0.1 million, including $0.6 million of realized loss and $0.5 million of unrealized gain from interest rate swaps.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 9—Fair Value of Financial Instruments

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

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

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

•

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

•

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

•

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

As of March 31, 2010, the carrying amounts of our cash and cash equivalents, trade receivables and payables represented fair value because of the short-term nature of these instruments.

The following table summarizes the fair values of our derivative financial instruments that are recorded at fair value classified in each level as of March 31, 2010 (in thousands):


	March 31, 2010 Fair Value Measurements
Description	Level 1		Level 2			Level 3		Total
Current Assets
Commodity Derivatives	$	—	$	25,519		$	—	$	25,519
Non-current Assets
Commodity Derivatives		—		13,926			—		13,926
Current Liabilities
Interest Swaps		—		(548	)		—		(548	)
Commodity Derivatives		—		(1,215	)		—		(1,215	)

Total	$	—	$	37,682		$	—	$	37,682

The following table reflects the carrying value, as recorded in our Consolidated Balance Sheet, and fair value of our long-term debt financial instruments at March 31, 2010 (in thousands):


	March 31, 2010				December 31, 2009
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
3.25% Convertible Senior Notes due 2026	$	161,085	$	163,503	$	159,085	$	161,438
5.0% Convertible Senior Notes due 2029		173,034		189,592		171,062		226,694

Total long-term debt	$	334,119	$	353,095	$	330,147	$	388,132

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

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

NOTE 10—Commitments and Contingencies

We are party to lawsuits arising in the normal course of business. We intend to defend these actions vigorously and believe, based on currently available information, that adverse results or judgments from such actions, if any, will not be material to our consolidated financial position or results of operations or liquidity. Other than as described in Note 11, no significant changes to these type lawsuits have occurred since December 31, 2009.

NOTE 11—Subsequent Events

Litigation

Hoover Tree Farm, LLC v. Goodrich Petroleum Company, LLC et al. On April 29, 2010, a state court in Caddo Parish, Louisiana, granted a judgment holding the Company solely responsible for the payment of $8.5 million in additional oil and gas lease bonus payments and related interest in an ongoing lawsuit involving the interpretation of a unique oil and gas lease provision. The lease provided for the payment of additional bonuses under certain circumstances in the event higher lease bonuses were paid by the Company, its successors or assigns, within the surrounding area. Without the Company’s knowledge, one of the sub-lessees subject to the same lease, paid substantially higher bonuses in the area. The Company believes that this ruling was improperly decided and plans to vigorously defend and appeal. The Company has accrued the full judgment amount, $8.5 million, as of March 31, 2010 which is reflected as “Other” in the Consolidated Statement of Operations.

Acquisition

In April 2010, the Company closed on an agreement with a private company to earn an approximate 67% working interest in 45,000 net acres within the oil window of the Eagle Ford Shale play in LaSalle and Frio Counties, Texas. The Company paid $10 million upfront and has the option to drill to earn its full interest through $42.5 million in carried drilling cost.

The Company has also entered into agreements to acquire additional acreage in the Eagle Ford Shale play. The Company expects these transactions to close in the second quarter of 2010.

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

Forward-Looking Statements

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

•

planned capital expenditures;

•

future drilling activity;

•

our financial condition;

•

business strategy;

•

the market prices of oil and gas;

•

uncertainties about the estimated quantities of oil and gas reserves, including uncertainties associated with the SEC’s new rules governing reserve reporting;

•

the availability of drilling rigs and equipment or fracturing and pressure pumping crews.

•

economic and competitive conditions;

•

legislative and regulatory changes;

•

financial market conditions and availability of capital;

•

production;

•

hedging arrangements;

•

future cash flows and borrowings;

•

litigation matters;

•

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

•

pursuit of potential future acquisition opportunities; and

•

sources of funding for exploration and development.

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

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

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 East Texas and North Louisiana (“ETNL”) area, which includes the Haynesville Shale play, and South Texas, which includes the Eagle Ford Shale. We operate as one segment as each of our operating areas have similar economic characteristics and each meet the criteria for aggregation as defined by accounting standards related to disclosures about segments of an enterprise and related information.

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

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

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

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

East Texas and North Louisiana Area

Our drilling program in the ETNL area has historically been primarily centered in and around Rusk, Panola, Angelina and Nacogdoches Counties, Texas and DeSoto and Caddo Parishes, Louisiana. We continue to build our acreage position in this area and hold 215,072 gross acres as of March 31, 2010. As of March 31, 2010, we drilled and completed a cumulative total of 473 gross wells in this area with a success rate in excess of 99%. Our net production volumes from our ETNL wells aggregated approximately 88,539 Mcfe per day in the first quarter of 2010, representing greater than 99% of our total oil and gas production for the period.

Eagle Ford Shale

In April 2010, we entered into agreements to acquire an average 70% leasehold interest in approximately 50,000 gross (35,000 net) acres within the oil window of the Eagle Ford Shale play in La Salle and Frio Counties, Texas. The purchase price equates to an average of $1,675 per net acre, with approximately $15 million in upfront cash and the option to drill to earn the full interest through $44 million in carried drilling costs. The transactions are subject to customary due diligence. In light of this acquisition, we are maintaining our 2010 capital expenditure budget of $255 million, while reallocating approximately $50 million, or about 20% of its capital expenditure budget, to leasehold, drilling and completion costs associated with the Eagle Ford Shale oil play. We currently plan to spud our first Eagle Ford Shale well in the second quarter and to run one or two rigs during the second half of 2010.

2010 Haynesville Shale Developments

Company Operated Haynesville Shale Drilling Program

We conducted drilling operations on six operated Haynesville Shale horizontal wells in the first quarter of 2010. For the three months ended March 31, 2010, net production from our operated Haynesville Shale wells (horizontal and vertical) averaged approximately 20,785 Mcfe per day, or 23% of our total production. We currently anticipate drilling 10 to 12 additional operated Haynesville Shale horizontal wells in 2010.

Chesapeake Haynesville Shale Joint Development

Through our joint development arrangement with Chesapeake Energy Corporation (“Chesapeake”), which covers certain of our acreage in North Louisiana, we continue to operate existing production and operate any new wells drilled to the base of the Cotton Valley sand, and Chesapeake will operate any wells drilled below the base of the Cotton Valley sand, including the Haynesville Shale. As of March 31, 2010, we participated in drilling operations on 29 horizontal wells and one vertical Haynesville well under the joint development arrangement. As of March 31, 2010, 20 horizontal wells and one vertical well had reached initial production and the remaining 9 horizontal wells were in some form of drilling or completion. For the rest of 2010, we and Chesapeake plan to utilize three rigs to conduct drilling operations on approximately 13 additional Haynesville Shale horizontal wells to be operated by Chesapeake. For the first quarter 2010, net production from the joint development averaged 18,486 Mcfe per day.

Company Operated Cotton Valley Taylor Sand Program

During 2009 we commenced a horizontal drilling program targeting the Cotton Valley Taylor Sand (“CVTS”). By the end of the first quarter 2010 we had drilled and completed four horizontal CVTS wells in East Texas. For the first quarter 2010, net production from these four operated wells was approximately 7,928 Mcfe per day. We anticipate drilling approximately three additional CVTS wells in 2010.

A more complete overview and discussion of our operations can be found in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2009.

Overview of First Quarter 2010 Results

First Quarter 2010 financial and operating results include:

•

We increased our oil and gas production volumes to 88,646 Mcfe per day, representing an increase of 17% from 75,753 Mcfe per day for the first quarter of 2009.

•

We conducted drilling operations on 16 gross wells in the first quarter of 2010, 15 of which penetrated the Haynesville Shale. We added 6 gross (2 net) wells to production in the first quarter of 2010. At March 31, 2010 we had 14 gross (5 net) wells in the Haynesville Shale drilled but awaiting completion.

•

We increased our net ownership in the Haynesville Shale play in Northwest Louisiana and East Texas to 88,739 net acres at March 31, 2010.

•

We reduced our lease operating expense by $0.41 per Mcfe to $0.91 per Mcfe in the first quarter of 2010 from $1.32 per Mcfe in the first quarter of 2009.

Results of Operations

For the first quarter of 2010, we reported net income applicable to common stock of $2.8 million, or $0.08 per basic and diluted share, on total revenue of $40.4 million as compared to net income applicable to common stock of $1.6 million, or $0.05 per basic and diluted share, on total revenue of $28.5 million for the first quarter of 2009. In conjunction with the fall of natural gas prices during the first quarter of 2010, we recorded a $34.7 million gain on commodity derivatives not designated as hedges. This includes a realized gain of $1.6 million and an unrealized gain of $33.1 million. See discussions below under the caption “Gain (Loss) on Derivatives Not Designated as Hedges.”

Oil and Natural Gas Revenues

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

Summary Operating Information:


	Three Months Ended March 31,
	2010			2009			Variance
	(in thousands except for price data)
Revenues:
Natural gas	$	37,918		$	26,919		$	10,999		41	%
Oil and condensate		2,508			1,521			987		65	%
Natural gas, oil and condensate		40,426			28,440			11,986		42	%
Operating revenues		40,455			28,461			11,994		42	%
Operating expenses		61,786			56,007			5,779		10	%
Operating loss		(21,331	)		(27,546	)		6,215		23	%
Net income applicable to common stock		2,819			1,632			1,187		73	%

Net Production:
Natural gas (MMcf)		7,780			6,545			1,235		19	%
Oil and condensate (MBbls)		33			45			(12	)	(27	)%
Total (MMcfe)		7,978			6,818			1,160		17	%
Average daily production (Mcfe/d)		88,646			75,753			12,893		17	%

Average realized sales price per unit:
Natural gas (per Mcf)	$	4.87		$	4.11		$	0.76		18	%
Oil and condensate (per Bbl)		75.99			33.50			42.49		127	%
Average realized price (per Mcfe)		5.07			4.17			0.90		22	%

Revenues increased 42% in the first quarter of 2010 compared to the same period in 2009 due equally to higher realized sale prices and increased production. Net production increased 17% period to period due to a substantial increase in the number of wells producing in the Haynesville Shale. The increase in natural gas and oil revenues attributed to the realized price increase from the first quarter of 2009 to the first quarter of 2010 was $6.1 million while the increase in production for the same comparative period contributed $5.9 million to the increase in natural gas and oil revenues.

Operating Expenses

The following tables present our comparative operating expenses:


	Three Months Ended March 31,
Operating Expenses (in thousands)	2010		2009		Variance
Lease operating expenses	$	7,232	$	8,996	$	(1,764	)	(20	)%
Production and other taxes		963		1,488		(525	)	(35	)%
Transportation		2,453		2,588		(135	)	(5	)%
Depreciation, depletion and amortization		30,213		33,658		(3,445	)	(10	)%
Exploration		2,979		2,220		759		34	%
General and administrative		9,446		7,057		2,389		34	%
Other		8,500		—		8,500		100	%

	Three Months Ended March 31,
Operating Expenses per Mcfe	2010		2009		Variance
Lease operating expenses	$	0.91	$	1.32	$	(0.41	)	(31	)%
Production and other taxes		0.12		0.22		(0.10	)	(45	)%
Transportation		0.31		0.38		(0.07	)	(18	)%
Depreciation, depletion and amortization		3.79		4.94		(1.15	)	(23	)%
Exploration		0.37		0.33		0.04		12	%
General and administrative		1.18		1.04		0.14		13	%
Other		1.07		—		1.07		100	%

Lease Operating. Lease operating expense (“LOE”) for the first quarter of 2010 was $7.2 million, a decrease of $1.8 million or 20% from the $9.0 million in the first quarter of 2009. On a per unit basis, LOE decreased 31% from $1.32 to $0.91 per Mcfe compared to the first quarter of 2009. Salt water disposal costs have declined from $2.9 million in the first quarter of 2009 to $1.3 million for the same period in 2010. The decrease is due to lower salt water disposal costs directly associated with the Cotton Valley Trend vertical wells as well as less water produced on Haynesville Shale wells. This was primarily attributable to the installation of several salt water gathering systems associated with the Cotton Valley Trend vertical wells that became fully operational over the course of 2009, beginning in the second quarter. The full impact of these systems was realized during the first quarter of 2010. In addition, through contract negotiations with key vendors, salt water hauling rates and compression costs were lowered in 2009 and 2010. On a per unit basis, production volumes increased 17% from the prior year period.

Production and Other Taxes. Production and other taxes of $1.0 million for the first quarter of 2010 includes production tax of $0.5 million and ad valorem tax of $0.5 million. Production tax included $0.5 million of accrued Tight Gas Sands (“TGS”) credits and horizontal credits for our wells in the states of Texas and Louisiana. During the comparable period in 2009, production and other taxes were $1.5 million, which included production tax of $0.8 million and ad valorem tax of $0.7 million. Production tax in the first quarter of 2009 included $0.4 million in TGS credits.

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

The Louisiana horizontal wells are eligible for a two year severance tax exemption from the date of first production or until payout of qualified costs, whichever comes first. We accrue for such credits once we have been notified of the State’s approval.

Transportation. Transportation expense was $2.5 million ($0.31 per Mcfe) in the first quarter of 2010 compared to $2.6 million ($0.38 per Mcfe) in the first quarter of 2009. The decrease is a function of our changing geographic production mix, as well as a larger portion of sales coming from non-operated properties from which the operator nets the transportation cost from revenues.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) expense decreased to $30.2 million in the first quarter of 2010 from $33.7 million for the same period in 2009 primarily due to a lower DD&A rate. The average DD&A rate for the first quarter of 2010 was $3.79 per Mcfe compared to $4.94 per Mcfe for the same quarter of 2009. The lower rate was due to the impact of the addition of Haynesville Shale proved reserves, which carry more attractive finding and development costs per unit of proved reserves and the impairment recorded in the fourth quarter of 2009 resulting primarily from the write down of our vertical Cotton Valley proved developed reserves which reduced the book value of the oil and gas properties to be depleted.

We calculated first quarter 2010 and 2009 DD&A rates using the December 31, 2009 and December 31, 2008 reserves, respectively. Proved developed reserves increased 9% from 152.5 Bcfe at December 31, 2008 to 165.5 Bcfe at December 31, 2009.

Exploration. Exploration expenses for the first quarter of 2010 increased $0.8 million to $3.0 million compared to $2.2 million for the same period in 2009. Included in the first quarter of 2010 is $0.5 million in exploratory seismic cost, mostly related to our ongoing 3-D seismic program in the Angelina River area. On a per unit basis, exploration cost increased to $0.37 per Mcfe in the first quarter of 2010 from $0.33 per Mcfe in the same period in 2009.

General and Administrative. General and Administrative (“G&A”) expense increased $2.3 million to $9.4 million ($1.18 per Mcfe) for the first quarter of 2010, from $7.1 million ($1.04 per Mcfe) for the first quarter of 2009. The first quarter of 2010 included $0.9 million of compensation costs related to the resignation of an officer of the company. See Note 2 “Resignation of Executive Officer” to our consolidated financial statements in this report for more information. This amount includes non-cash charges of $0.3 million and $0.4 million for the accelerated vesting or modification of restricted stock and stock options, respectively. This charge also includes $0.2 million for a consulting agreement. G&A expense for the first quarter of 2010 also includes $0.9 million for additional 2009 compensation paid out in March 2010. The remaining increase is related to generally higher compensation cost and stock based compensation. Stock based compensation expense, a non-cash item, amounted to $2.5 million for the first quarter of 2010 compared to $1.6 million for the same period in 2009.

Other. Hoover Tree Farm, LLC v. Goodrich Petroleum Company, LLC et al. On April 29, 2010, a state court in Caddo Parish, Louisiana granted a judgment holding us solely responsible for the payment of $8.5 million in additional oil and gas lease bonus payments and related interest in an ongoing lawsuit involving the interpretation of a unique oil and gas lease provision. The lease provided for the payment of additional bonuses under certain circumstances in the event higher lease bonuses were paid by us, our successors or assigns, within a surrounding area. Without our knowledge, one of our sub-lessees, subject to the same lease, paid substantially higher lease bonuses in the area. We believe that this ruling was improperly decided and plan to vigorously defend and appeal, however, we have accrued the full $8.5 million, as of March 31, 2010.

Other Income (Expense)

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


	Three Months Ended March 31,
	2010			2009
Other income (expense):

Interest expense	$	(9,120	)	$	(5,208	)
Interest income and other		53			246
Gain on derivatives not designated as hedges		34,729			37,006
Income tax expense		—			1,354
Average funded borrowings		393,500			250,000
Average funded borrowings adjusted for debt discount		331,515			227,357
Weighted average interest rate on funded borrowings adjusted for debt discount		10.5	%		9.3	%

Interest Expense. Interest expense increased $3.9 million to $9.1 million in the first quarter of 2010 compared to $5.2 million in the first quarter of 2009 as a result of the higher average level of outstanding debt in the first quarter of 2010. The higher average level of debt is the result of the issuance of our 5% convertible senior notes in September 2009.

Interest Income and Other. We invested the net proceeds from our 5% convertible senior note offering in September 2009 in money market funds and time deposits in accordance with our Short Term Investment Policy. For more information on our Short Term Investment Policy, please see our Annual Report on Form 10-K for the year ended December 31, 2009.

Gain (Loss) on Derivatives Not Designated as Hedges. Gain on derivatives not designated as hedges was $34.7 million for the first quarter of 2010, including a realized gain of $1.6 million and an unrealized gain of $33.1 million for the change in fair value of our natural gas commodity contracts. The decrease in natural gas prices experienced during the first quarter of 2010 led to substantial unrealized gains on our commodity contracts. The first quarter 2010 gain also included a realized loss of $0.6 million and an unrealized gain of $0.5 million on our interest rate swap. As a comparison, the first quarter 2009 loss on derivatives not designated as hedges was $37.0 million including a realized gain of $21.1 million and an unrealized gain of $16.0 million for the changes in fair value of our commodity contracts. The first quarter of 2009 also includes a loss of $0.1 million on our interest rate swap. We will continue to be exposed to volatility in earnings resulting from changes in the fair value of our commodity contracts as we do not designate these contracts as hedges.

Income Taxes. We recorded no income tax expense for the three months ended March 31, 2010. We increased our valuation allowance and reduced our net deferred tax asset to zero during 2009 after considering all available positive and negative evidence related to the realization of our deferred tax asset. Our assessment of the realization of our deferred tax asset has not changed and as a result, we did not provide for income taxes in the first quarter of 2010. In the first quarter of 2009, we recorded income tax expense of $1.4 million which included a state income tax benefit of $0.2 million.

Liquidity and Capital Resources

Cash Flows

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


	Three Months Ended March 31,
	2010			2009			Variance
Cash flow statement information:
Net cash:
Provided by operating activities	$	18,767		$	36,257		$	(17,490	)
Used in investing activities		(40,981	)		(103,314	)		62,333
Used in financing activities		(1,956	)		(2,171	)		215

Decrease in cash and cash equivalents	$	(24,170	)	$	(69,228	)	$	45,058

Operating activities. Net cash provided by operating activities decreased $17.5 million to $18.8 million for the first three months of 2010, from $36.3 million for the comparable 2009 period due primarily to decreased realization of derivative settlements. Cash settlements in the first quarter of 2009 were higher than the first quarter of 2010 because the differentials between floor prices and strike prices were more favorable.

Investing activities. Net cash used in investing activities was $41.0 million for the first three months of 2010 compared to net cash used in investing activities of $103.3 million for the first three months of 2009. We conducted drilling operations on 16 gross wells, 15 of which penetrated the Haynesville Shale during the first three months of 2010. In comparison, we conducted drilling operations on 24 gross wells, 13 of which penetrated the Haynesville Shale in the first quarter of 2009. We reduced our capital budget in 2010 due to the low natural gas price environment.

Financing activities. Net cash used in financing activities was $2.0 million for the three months ended March 31, 2010, versus net cash used in financing activities of $2.2 million for the same period in 2009. In the first quarter of 2009 and 2010 we used cash flow and existing cash to fund our operations.

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

Senior Credit Facility

On May 5, 2009, we entered into a Second Amended and Restated Credit Agreement (“Senior Credit Facility”) that replaced our previous facility. Total lender commitments under the Senior Credit Facility are $350 million. The Senior Credit Facility matures on August 31, 2011. The Senior Credit Facility can be further extended to July 1, 2012 upon receipt of proceeds from a refinancing sufficient to prepay the 3.25% convertible senior notes due 2026. Revolving borrowings under the Senior Credit Facility are limited to, and subject to periodic redeterminations of, the borrowing base. The initial borrowing base was established at $175 million. The borrowing base interest on revolving borrowings under the Senior Credit Facility accrues at a rate calculated, at our option, at the bank base rate plus 0.75% to 1.50% or LIBOR plus 2.25% to 3.00%, depending on borrowing base utilization. Pursuant to the terms of the Senior Credit Facility, borrowing base redeterminations are made on a semi-annual basis on April 1 and October 1. In connection with the offering of our $218.5 million 5% convertible senior notes due 2029, we entered into an amendment of our Senior Credit Facility to permit the issuance of the notes and required payments made on the notes thereafter and to exclude up to $175 million of our 3.25% convertible senior notes due 2026 or our 5% convertible senior notes due 2029 from the definition of Total Debt used in our financial covenants under the Senior Credit Facility. On April 20, 2010, the borrowing base was increased to $200 million. We currently have no amounts outstanding under the Senior Credit Facility.

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

•

Current Ratio of 1.0/1.0;

•

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

•

We were in compliance with all of the financial covenants of the Senior Credit Facility as of March 31, 2010.

3.25% Convertible Senior Notes Due 2026

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

15.1653 shares per $1,000 principal amount of the 2026 Notes (equal to a “base conversion price” of approximately $65.94 per share) plus

Interest expense relating to the contractual interest rate and amortization of both financing cost and debt discount relating to the 2026 Notes for the three months ended March 31, 2010 was $3.6 million. The effective interest rate on the liability component of the 2026 Notes was 9.2% for the three month period ended March 31, 2010.

5% Convertible Senior Notes due 2029

We separately account for the liability and equity components of the 2029 Notes in a manner that reflects our nonconvertible debt borrowing rate when interest is recognized in subsequent periods. As of March 31, 2010, the $218.5 million notes were carried on the balance sheet at $173.0 million with a debt discount balance of $45.5 million. As of December 31, 2009, the $218.5 million 2029 Notes were carried on the balance sheet at $171.1 million with a debt discount of $47.4 million. The debt discount will be amortized using the effective interest rate method based upon an original five year term through October 1, 2014. Interest expense recognized relating to the contractual interest rate and amortization of both financing cost and debt discount for the three months ended March 31, 2010 was $5.0 million. The effective interest rate on the liability component of the 2029 Notes was 11.7% for the three months ended March 31, 2010.

Share Lending Agreement

Capped Call Option Transactions

On December 10, 2007, we closed the public offering of 6,430,750 shares of our common stock at a price of $23.50 per share. Net proceeds from the offering were approximately $145.4 million after deducting the underwriters’ discount and estimated offering expenses. We used approximately $123.8 million of the net proceeds to pay off outstanding borrowings under our Senior Credit Facility, and approximately $21.6 million of the net proceeds to purchase capped call options on shares of our common stock from affiliates of BSC and J.P. Morgan Securities Inc. The capped call option transactions covered, subject to customary anti-dilution adjustments, approximately 5.8 million shares of our common stock, and each of them was divided into a number of tranches with differing expiration dates. Approximately 77,333 options per trading day will expire over each of three separate 25 consecutive trading day settlement periods. During 2009, two-thirds of the options expired. The remaining one-third of the options subject to the capped call will expire beginning on May 18, 2010. For more information on our Capped Call Option Transactions, please see our Annual Report on Form 10-K for the year ended December 31, 2009.

Accounting Pronouncements

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

In January 2010, the FASB issued authoritative guidance related to improving disclosures about fair value measurements. These revised disclosures are required, with certain exceptions, for interim and annual reporting periods effective January 1, 2010. For information concerning the fair value at March 31, 2010 of our derivative financial instruments and our long-term debt financial instruments, see Note 9 “Fair Value of Financial Instruments” to our consolidated financial statements in this report.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations are based on consolidated financial statements which have been prepared in accordance with generally accepted accounting principles in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. We believe that certain accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements. Our Annual Report on Form 10-K for the year ended December 31, 2009, includes a discussion of our critical accounting policies and there have been no material changes to such policies.

Item 3 – Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

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

We enter into futures contracts or other derivative agreements from time to time to manage the commodity price risk for a portion of our production. Our strategy, which is administered by the Hedging Committee of our Board of Directors, and reviewed periodically by the entire Board of Directors, has been to generally hedge between 30% and 70% of our production. As of March 31, 2010, the commodity hedges we utilized were in the form of:

(a)

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

(b)

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

Our hedging contracts fall within our targeted range of 30% to 70% of our estimated net oil and gas production volumes for the applicable periods of 2010. The fair value of the natural gas hedging contracts in place at March 31, 2010, resulted in a net current asset of $38.2 million. Based on oil and gas pricing in effect at March 31, 2010, a hypothetical 10% increase in oil and gas prices would have resulted in a derivative asset of $20.3 million, while a hypothetical 10% decrease in oil and gas prices would have increased the derivative asset to $59.0 million. See Note 8 “Derivative Activities” to our consolidated financial statements in this report for additional information.

Interest Rate Risk


Effective Date	Maturity Date	LIBOR Swap Rate		Notional Amount (Millions)		Fair Value (in thousands)
4/22/2008	4/22/2010	3.191	%	$	25.0	$	(183	)
4/22/2008	4/22/2010	3.191	%		50.0		(365	)

						$	(548	)

The fair value of the interest rate swap contracts at March 31, 2010, resulted in a liability of $0.5 million which is reflected on the balance sheet as a current liability. We measure the fair value of our interest rate swaps by applying the income approach and these contracts are classified within Level 2 of the valuation hierarchy. See Note 9 “Fair Value of Financial Instruments” to our consolidated financial statements in this report for more information. For the three months ended March 31, 2010, we recognized a loss of less than $0.1 million, consisting of $0.6 million of realized loss offset by $0.5 million of unrealized gain from interest rate swaps. Based on the interest rates at March 31, 2010, a hypothetical 10% increase or decrease in interest rates would not have a material effect on the liability.

Item 4 – Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and Interim Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in rules 13a-15(c) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our Chief Executive Officer and Interim Chief Financial Officer, based upon their evaluation as of March 31, 2010, the end of the period covered in this report, concluded that our disclosure controls and procedures were effective at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

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

PART II—OTHER INFORMATION

Item 1 – Legal Proceedings

Hoover Tree Farm, LLC v. Goodrich Petroleum Company, LLC et al. On April 29, 2010, a state court in Caddo Parish, Louisiana, granted a judgment holding us solely responsible for the payment of $8.5 million in additional oil and gas lease bonus payments and related interest in an ongoing lawsuit involving the interpretation of a unique oil and gas lease provision. The lease provided for the payment of additional bonuses under certain circumstances in the event higher lease bonuses were paid by us, our successors or assigns, within the surrounding area. Without our knowledge, one of our sub-lessees subject to the same lease, paid substantially higher bonuses in the area. We believe that this ruling was improperly decided and plan to vigorously defend and appeal, however, we have accrued the full judgment amount, $8.5 million, as of March 31, 2010.

Item 1A – Risk Factors

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

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

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

Item 6 – Exhibits


10.1		Resignation Agreement dated as of March 24, 2010 between David R. Looney and Goodrich Petroleum Corporation (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-12719) filed on March 26, 2010).

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

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

**	Furnished herewith

SIGNATURES

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


	GOODRICH PETROLEUM CORPORATION (Registrant)

Date: May 6, 2010	By:	/S/ WALTER G. GOODRICH
		Walter G. Goodrich
		Vice Chairman & Chief Executive Officer

Date: May 6, 2010	By:	/S/ JAN L. SCHOTT
		Jan L. Schott
		Vice President & Interim Chief Financial Officer

GOODRICH PETROLEUM CORPORATION LIST OF EXHIBITS TO FORM 10-Q

FOR QUARTER ENDED MARCH 31, 2010


EXHIBIT NO.		DESCRIPTION OF EXHIBIT

10.1		Resignation Agreement dated as of March 24, 2010 between David R. Looney and Goodrich Petroleum Corporation (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (File No. 001-12719) filed on March 26, 2010).

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

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

**	Furnished herewith

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