Edgar Filing: GOODRICH PETROLEUM CORP

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

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 June 30, 2008

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

Commission file number: 001-12719

GOODRICH PETROLEUM CORPORATION

(Exact name of registrant as specified in its charter)

Delaware

76-0466193

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

808 Travis, Suite 1320

Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

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

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

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

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 August 4, 2008 was 37,524,285.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

TABLE OF CONTENTS


		Page
PART I	FINANCIAL INFORMATION
ITEM 1	FINANCIAL STATEMENTS
	Consolidated Balance Sheets as of June 30, 2008 and December 31, 2007	3
	Consolidated Statements of Operations for the three and six months ended June 30, 2008 and 2007	4
	Consolidated Statements of Cash Flows for the three and six months ended June 30, 2008 and 2007	5
	Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2008 and 2007	6
	Notes to Consolidated Financial Statements	7
ITEM 2	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	19
ITEM 3	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	30
ITEM 4	CONTROLS AND PROCEDURES	30

PART II	OTHER INFORMATION	32
ITEM 1	LEGAL PROCEEDINGS	32
ITEM 1A	RISK FACTORS	32
ITEM 2	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	32
ITEM 3	DEFAULTS UPON SENIOR SECURITIES	32
ITEM 4	SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS	32
ITEM 5	OTHER INFORMATION	33
ITEM 6	EXHIBITS	33

PART 1 – FINANCIAL INFORMATION

Item 1 – Financial Statements

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(In Thousands, Except Share Amounts)

(Unaudited)


	June 30, 2008			December 31, 2007
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	5,982		$	4,448
Accounts receivable, trade and other, net of allowance		7,031			8,539
Accrued oil and gas revenue		26,915			12,200
Fair value of oil and gas derivatives		—			2,267
Assets held for sale		305			311
Prepaid expenses and other		969			904

Total current assets		41,202			28,669

PROPERTY AND EQUIPMENT:
Oil and gas properties (successful efforts method)		932,589			723,239
Furniture, fixtures and equipment		2,624			1,932

		935,213			725,171
Less: Accumulated depletion, depreciation and amortization		(221,960	)		(168,523	)

Net property and equipment		713,253			556,648

OTHER ASSETS:
Fair value of interest rate derivatives		372			—
Other		5,337			4,801

Total other assets		5,709			4,801

TOTAL ASSETS	$	760,164		$	590,118

LIABILITIES AND STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	46,773		$	36,967
Accrued liabilities		37,133			32,565
Fair value of interest rate derivatives		725			384
Fair value of oil and gas derivatives		44,595			—
Asset sale deposit		8,927			—
Deferred revenue		—			12,500
Accrued abandonment costs		587			312

Total current liabilities		138,740			82,728
LONG-TERM DEBT		331,000			215,500
Accrued abandonment costs		6,815			5,868
Fair value of oil and gas derivatives		27,428			2,407

Total Liabilities		503,983			306,503

Commitments and contingencies (See Note 12)
STOCKHOLDERS’ EQUITY:
Preferred stock: 10,000,000 shares authorized: Series B convertible preferred stock, $1.00 par value, issued and outstanding 2,250,000 shares		2,250			2,250
Common stock: $0.20 par value, 100,000,000 shares authorized, issued and outstanding 34,282,957 and 34,821,317 shares, respectively:		6,532			6,340
Treasury stock (shares outstanding none and 16,359 respectively)		—			(422	)
Additional paid in capital		377,458			341,098
Accumulated deficit		(130,059	)		(65,651	)

Total stockholders’ equity		256,181			283,615

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	760,164		$	590,118

See accompanying notes to consolidated financial statements.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)

(Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
Revenues:
Oil and gas revenues	$	64,852		$	27,860		$	111,049		$	51,177
Other		321			146			477			371

		65,173			28,006			111,526			51,548

Operating expenses:
Lease operating expense		7,669			6,150			14,766			10,285
Production and other taxes		2,334			(590	)		3,589			(296	)
Transportation		2,386			1,440			4,256			2,515
Depreciation, depletion and amortization		29,033			19,461			54,118			37,169
Exploration		1,776			1,767			3,779			4,093
General and administrative		5,920			5,500			11,360			10,838

		49,118			33,728			91,868			64,604

Operating income (loss)		16,055			(5,722	)		19,658			(13,056	)

Other income (expense):
Interest expense		(4,390	)		(2,222	)		(8,173	)		(4,846	)
Gain (loss) on derivatives not designated as hedges		(48,947	)		3,634			(73,434	)		(5,853	)

		(53,337	)		1,412			(81,607	)		(10,699	)

Loss before income taxes		(37,282	)		(4,310	)		(61,949	)		(23,755	)
Income tax benefit		—			1,519			—			8,262

Loss from continuing operations		(37,282	)		(2,791	)		(61,949	)		(15,493	)

Discontinued operations (See Notes 10 and 11):
Gain (loss) on disposal, net of tax		(120	)		(162	)		280			10,751
Income (loss) from discontinued operations, net of tax		(101	)		(346	)		284			2,479

		(221	)		(508	)		564			13,230

Net loss		(37,503	)		(3,299	)		(61,385	)		(2,263	)
Preferred stock dividends		1,511			1,512			3,023			3,024

Net loss applicable to common stock	$	(39,014	)	$	(4,811	)	$	(64,408	)	$	(5,287	)

Loss per common share from continuing operations
Basic	$	(1.16	)	$	(0.11	)	$	(1.94	)	$	(0.62	)

Diluted	$	(1.16	)	$	(0.11	)	$	(1.94	)	$	(0.62	)

Income (loss) per common share from discontinued operations
Basic	$	(0.01	)	$	(0.02	)	$	0.02		$	0.53

Diluted	$	(0.01	)	$	(0.02	)	$	0.02		$	0.53

Net loss per common share applicable to common stock
Basic	$	(1.21	)	$	(0.19	)	$	(2.02	)	$	(0.21	)

Diluted	$	(1.21	)	$	(0.19	)	$	(2.02	)	$	(0.21	)

Weighted average common shares outstanding
Basic		32,124			25,185			31,915			25,163

Diluted		32,124			25,185			31,915			25,163

See accompanying notes to consolidated financial statements.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)


	Six Months Ended June 30,
	2008			2007
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(61,385	)	$	(2,263	)
Adjustments to reconcile net loss to net cash provided by operating activities—
Depletion, depreciation, and amortization		54,118			37,169
Unrealized loss on derivatives not designated at hedges		71,852			10,680
Deferred income taxes		—			(1,138	)
Dry hole costs		—			929
Amortization of leasehold costs		2,449			3,569
Stock based compensation (non-cash)		2,654			2,681
Gain on sale of assets		(280	)		(16,538	)
Other non-cash items		1,009			157
Change in assets and liabilities:
Accounts receivable, trade and other, net of allowance		1,455			(2,735	)
Deferred revenue		(12,500	)		—
Accrued oil and gas revenue		(14,715	)		764
Prepaid expenses and other		484			(632	)
Accounts payable		9,806			7,581
Accrued liabilities		2,149			(308	)

Net cash provided by operating activities		57,096			39,916

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(175,620	)		(135,375	)
Asset sale deposit (See Note 11)		8,927			—
Proceeds from sale of assets		280			74,029
Release of restricted cash funds		—			2,039

Net cash used in investing activities		(166,413	)		(59,307	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Principal payments of bank borrowings		(72,500	)		(65,000	)
Proceeds from bank borrowings		188,000			87,000
Exercise of stock options and warrants		81			—
Debt issuance costs		(1,492	)		(144	)
Preferred stock dividends		(3,023	)		(3,024	)
Other		(215	)		—

Net cash provided by financing activities		110,851			18,832

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		1,534			(559	)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD		4,448			6,184

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	5,982		$	5,625

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
CASH PAID DURING THE PERIOD FOR INTEREST	$	6,033		$	3,861

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

See accompanying notes to consolidated financial statements.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In Thousands)

(Unaudited)


	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2008			2007			2008			2007
Net income (loss)	$	(37,503	)	$	(3,299	)	$	(61,385	)	$	(2,263	)

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

Other comprehensive income (loss)		—			—			—			1,261

Comprehensive income (loss)	$	(37,503	)	$	(3,299	)	$	(61,385	)	$	(1,002	)

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

See accompanying notes to consolidated financial statements.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—Description of Business and Significant Accounting Policies

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

The accompanying consolidated financial statements of the Company should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007. The results of operations for the three and six months ended June 30, 2008, are not necessarily indicative of the results to be expected for the full year.

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

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

Assets Held for Sale—Assets Held for Sale as of June 30, 2008, represent our remaining assets in South Louisiana. These assets include the St. Gabriel, Bayou Bouillon and Plumb Bob fields.

Income Taxes—We follow the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 109, Accounting for Income Taxes, (“SFAS 109”) as clarified by FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes (“FIN 48”), which requires income taxes be accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. We have established a valuation allowance against our entire deferred tax asset balance and have not provided for any income taxes in the three and six months ended June 30, 2008.

New Accounting Pronouncements

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

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 (“SFAS 161”). SFAS 161 amends and expands the disclosure requirements of SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”), by requiring enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS 161 requires qualitative disclosures about

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

In May 2008, the Financial Accounting Standards Board (FASB) issued FASB Staff Position APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (including Partial Cash Settlement) (“FSP APB 14-1”). FSP APB 14-1 requires that issuers of certain convertible debt instruments that may be settled in cash upon conversion to separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. The effective date of FSP APB 14-1 for the Company is January 1, 2009 and does not permit earlier application. However, the transition guidance requires retrospective application to all periods presented and does not grandfather existing instruments. In December 2006, Goodrich Petroleum Corporation issued $175.0 million in 3.25% convertible senior notes due in December 2026. We are currently evaluating the impact of the provisions of FSP APB 14-1 on our financial statements as it relates to our convertible senior notes.

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

NOTE 2— Share-Based Compensation Plans

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

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

The following table provides information about stock option activity for the six months ended June 30, 2008:


	Number of Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (Years)
Outstanding at December 31, 2007	949,333		$	20.95
Granted	162,000			21.59
Exercised	(22,000	)		3.69
Forfeited	—			—

Outstanding at June 30, 2008	1,089,333		$	21.39	6.99

Exercisable at June 30, 2008	654,667		$	20.29	6.87

Fair value of stock options granted			$	10.72

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The estimated fair value of the options granted during the six months ended June 30, 2008, was calculated using a Black Scholes Merton option pricing model (“Black Scholes”). The following schedule reflects the various assumptions for options granted in February 2008 included in this model as it relates to the valuation of our options:


	Six Months Ended June 30, 2008
Risk free interest rate	3.52	%
Volatility	53.3	%
Dividend yield	0	%
Expected years until exercise	5

During the six months ended June 30, 2008, we granted 243,903 restricted (phantom) shares under our 2006 Long-Term Incentive Plan to employees. The following table summarizes information on restricted stock activity for the six months ended June 30, 2008:


	Number of Shares		Weighted Average Grant Date Fair Value Per Share
Unvested at December 31, 2007	108,251		$	33.60
Vested	(17,977	)		22.82
Granted	243,903			22.08
Forfeited	(5,266	)		24.03

Unvested at June 30, 2008	328,911			25.80

For the three months ended June 30, 2008 we recorded $1.4 million in stock compensation expense comprised of $0.6 million from stock options and $0.8 million from restricted (phantom) share plans. In the six months ended June 30, 2008, we recorded $2.7 million in stock compensation expense comprised of $1.1 million from stock options and $1.6 million from restricted (phantom) share plans. In the three months ended June 30, 2007, we recorded $1.3 million in stock compensation expense comprised of $0.6 million from stock options and $0.7 million from restricted (phantom) share plans. In the six months ended June 30, 2007, we recorded $2.7 million in stock compensation expense comprised of $1.3 million from stock options and $1.4 million from restricted (phantom) share plans.

NOTE 3—Asset Retirement Obligations

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

The reconciliation of the beginning and ending asset retirement obligation for the period ending June 30, 2008, is as follows (in thousands):


Beginning balance, January 1, 2008	$	6,180
Liabilities incurred		1,089
Liabilities settled or sold		(33	)
Accretion expense (reflected in depletion, depreciation and amortization expense)		166

Ending balance, June 30, 2008		7,402
Less current portion (including $0.3 million attributable to Assets Held for Sale)		587

	$	6,815

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 4—Long-Term Debt

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


	June 30, 2008		December 31, 2007
Senior Credit Facility	$	81,000	$	40,500
Second Lien Term Loan		75,000		—
3.25% convertible senior notes due 2026		175,000		175,000

Total long-term debt	$	331,000	$	215,500

Senior Credit Facility

On November 17, 2005, we amended our existing credit agreement and entered into an amended and restated senior credit agreement (as amended, the “Senior Credit Facility”) and a term loan that expanded our borrowing capabilities and extended our credit facility for an additional two years. Total lender commitments under the Senior Credit Facility were $200 million, and the Senior Credit Facility matures on February 25, 2010. Revolving borrowings under the Senior Credit Facility are limited to, and subject to periodic redeterminations of the borrowing base. On May 7, 2008, the bank group established the new borrowing base at $175.0 million. At June 30, 2008, we had $81.0 million in outstanding revolving borrowings under the Senior Credit Facility. Interest on revolving borrowings under the Senior Credit Facility accrues at a rate calculated, at our option, at the bank base rate plus 0.00% to 0.75%, or LIBOR plus 1.25% to 2.25%, depending on borrowing base utilization.

The terms of the Senior Credit Facility, as amended, require us to maintain certain covenants. Capitalized terms used, but not defined, here have the meanings assigned to them in the Senior Credit Facility. As of June 30, 2008, we were in compliance with all of the financial covenants of our Senior Credit Facility. The covenants in effect at June 30, 2008 include:

•

Current Ratio of 1.0/1.0,

•

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

•

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

Second Lien Term Loan

On January 16, 2008, we entered into a new Second Lien Term Loan Agreement which provides for a 3-year, non-revolving loan of $75.0 million and is due in a single maturity on December 31, 2010. We have no rights to prepay in the first year. Voluntary prepayment rights in the second year are at 101% of par, and thereafter at par. Interest on the Second Lien Term Loan accrues at a rate of LIBOR plus 550 basis points and is payable quarterly in arrears. As of June 30, 2008, we were in compliance with all of the financial covenants of our Second Lien Term Loan. The terms of the Second Lien Term Loan Agreement contain financial covenants which include:

•

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

•

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

•

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

Convertible Senior Notes

In December 2006, we sold $175.0 million of 3.25% convertible senior notes (the “notes”) due in December 2026. The notes mature on December 1, 2026, unless earlier converted, redeemed or repurchased. The notes are our senior unsecured obligations and rank equally in right of payment to all of our other existing and future indebtedness. The notes accrue interest at a rate of 3.25% annually, and interest is paid semi-annually on June 1 and December 1. Interest payments on the notes began on June 1, 2007.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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

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

NOTE 5—Net Loss Per Common Share

Net loss was used as the numerator in computing basic and diluted income (loss) per common share for the three and six months ended June 30, 2008 and 2007. The following table sets forth information related to the computations of basic and diluted loss per share.


	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2008			2007			2008			2007
	(Amounts in thousands, except per share data)
Basic loss per share:
Loss applicable to common stock	$	(39,014	)	$	(4,811	)	$	(64,408	)	$	(5,287	)
Average shares of common stock outstanding		32,124			25,185			31,915			25,163

Basic loss per share	$	(1.21	)	$	(0.19	)	$	(2.02	)	$	(0.21	)

Diluted loss per share:
Loss applicable to common stock	$	(39,014	)	$	(4,811	)	$	(64,408	)	$	(5,287	)
Dividends on convertible deferred (1)		—			—			—			—
Interest and amortization of loan cost on senior convertible notes (2)		—			—			—			—

Diluted loss	$	(39,014	)	$	(4,811	)	$	(64,408	)	$	(5,287	)

Average shares of common stock outstanding		32,124			25,185			31,915			25,163
Assumed conversion of convertible preferred stock (1)		—			—			—			—
Assumed conversion of convertible senior notes (2)		—			—			—			—
Stock options, warrants and restricted stock (3)		—			—			—			—

Average diluted shares outstanding		32,124			25,185			31,915			25,163

Diluted loss per share	$	(1.21	)	$	(0.19	)	$	(2.02	)	$	(0.21	)

(1)	Common shares issuable upon assumed conversion the Company’s convertible preferred stock amounting 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 be anti-dilutive.

(2)	Common shares issuable upon assumed conversion of the Company’s convertible senior notes amounting to 2,653,927 shares and the accrued interest on the senior notes were not included in the computation of diluted loss per share for all periods presented as they would be anti-dilutive.

(3)

Common shares on assumed conversion of restricted stock and employee stock options for the three months ended June 30, 2008 and 2007, in the amount of 590,845 and 298,785 shares and for the six months ended June 30, 2008, and 2007, in the amount of 428,676 shares and 271,956 shares respectively were not included in the computation of diluted loss per common share since their inclusion would be anti-dilutive.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6—Income Taxes

The Company did not record a tax benefit for the three and six months ended June 30, 2008. We fully provided for additions to our deferred tax asset with a valuation allowance during the period. In determining the carrying value of a deferred tax asset, SFAS 109 provides for the weighing of evidence in estimating whether and how much of a deferred tax asset may be recoverable. As we have incurred net operating losses in 2006 and prior years, relevant accounting guidance suggests that cumulative losses in recent years constitute significant negative evidence, and that future expectations about income are insufficient to overcome a history of such losses. We increased our valuation allowance and reduced our net deferred tax asset to zero during 2007 after considering all available positive and negative evidence related to the realization of our deferred tax asset.

We may achieve profitable operations for 2008 due to the gain on our sale of oil and gas leasehold which closed on July 15, 2008 (see Note 11). If this occurs we anticipate reversing a portion of the valuation allowance in an amount at least sufficient to eliminate any 2008 tax provision. The valuation allowance has no impact on our net operating loss (“NOL”) position for tax purposes, and as we generate taxable income in future periods, we will be able to use our NOLs to offset taxes due at that time. The Company will continue to assess the valuation allowance against deferred tax assets considering all available evidence obtained in future reporting periods.

As of June 30, 2008, the Company had no unrecognized tax benefits. There were no significant changes to the calculation since December 31, 2007. The Company does not anticipate that total unrecognized tax benefits will significantly change due to the settlement of audits and the expiration of statute of limitations prior to June 30, 2009.

NOTE 7—Stockholders’ Equity

Share Lending Agreement

In connection with the offering of the notes, we agreed to lend an affiliate of Bear, Stearns & Co. (“BSC”) a total of 3,122,263 shares of our common stock under the Share Lending Agreement. Under this agreement, BSC is entitled to offer and sell such shares and use the sale to facilitate the establishment of a hedge position by investors in the notes. BSC will receive all proceeds from 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 Poors (“S&P”). As a result of the long term ratings downgrade of BSC in March 2008, BSC was required to return all or a portion of the borrowed shares or collateralize the return obligation with cash or highly liquid non-cash collateral. On March 20, 2008, BSC had returned 1,497,963 shares of the 3,122,263 originally borrowed shares and fully collateralized the remaining 1,624,300 borrowed shares with a cash collateral deposit of approximately $41.3 million. This amount represents the market value of the remaining borrowed shares at March 20, 2008. Under the Share Lending Agreement, BSC is required to maintain collateral value in the amount at least equal to the market value of the outstanding borrowed shares. The market value of the cash collateral deposit at June 30, 2008 was approximately $122.9 million. The 1,497,963 shares returned to the Company were recorded to Treasury stock and retired in March of 2008.

The 1,624,300 shares of common stock outstanding as of June 30, 2008, under the Share Lending Agreement are required to be returned to the Company in the future. The shares are treated in basic and diluted earnings per share as if they were already returned and retired. As a result, the shares of common stock lent under the Share Lending Agreement have no impact on the earnings per share calculation.

In May 2008, JP Morgan Chase & Co. completed its acquisition of and assumed all counterparty liabilities of The Bear Stearns Companies Inc., including those under the Share Lending Agreement.

Capped Call Option Transactions

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

estimated offering expenses. We used approximately $123.8 million of the net proceeds to pay off outstanding borrowings under our Senior Credit Facility, and approximately $21.6 million of the net proceeds to purchase capped call options on shares of our common stock from affiliates of BSC and J.P. Morgan Securities Inc. The capped call option transactions covered, subject to customary anti-dilution adjustments, approximately 5.8 million shares of our common stock, and each of them was divided into a number of tranches with differing expiration dates. One third of the options will expire over each of three separate multi-day settlement periods beginning approximately 18 months, 24 months and 30 months from the closing of the offering, respectively.

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

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

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

During the second quarter of 2008, BSC sold its position in the capped call options to Bank of America.

Caddo Parish Acquisition for Common Stock

In May 2008, we acquired approximately 3,665 net acres in the Longwood field of Caddo Parish, Louisiana, through the issuance of 908,098 shares of our common stock valued at approximately $33.9 million. See Note 11.

Equity Offering

On July 14, 2008, we closed the public offering of 3,121,300 shares of our common stock at a price of $64.00 per share. Net proceeds from the offering were approximately $192 million after deducting the underwriters’ discount and estimated offering expenses. We used approximately $96.0 million of the net proceeds to pay off outstanding borrowings under our Senior Credit Facility. We plan to use the remaining net proceeds for general corporate purposes, including to fund a portion of our 2008 drilling program, other capital expenditures and working capital requirements.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 8—Derivative Activities

Commodity Derivative Activity

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

•

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

•

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

•

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

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

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

As of June 30, 2008, our open forward positions on our outstanding commodity derivative contracts, all of which were with either BNP Paribas, Bank of Montreal or Comerica Bank were as follows:


Fixed Price Physical Contracts	Daily Volume	Total Volume	Average Field Price (1)
Natural gas (MMBtu)
3Q 2008	28,500	2,622,000	$	8.05
4Q 2008	28,500	2,317,000	$	8.04

Collars			Floor/Cap (NYMEX) Average Price		Fair Value at June 30, 2008
Natural gas (MMBtu)					$	(17,724,899	)
3Q 2008	10,000	920,000	$	8.00 – $10.20
4Q 2008	10,000	920,000	$	8.00 – $10.20
1Q 2009	20,000	1,800,000	$	8.75 – $13.10
2Q 2009	20,000	1,820,000	$	8.75 – $13.10
3Q 2009	20,000	1,840,000	$	8.75 – $13.10
4Q 2009	20,000	1,840,000	$	8.75 – $13.10

Swaps (NYMEX)			Average Price
Natural gas (MMBtu)						(27,157,486	)
3Q 2008	5,000	460,000	$	8.69
4Q 2008	5,000	155,000	$	8.69
1Q 2009	20,000	1,800,000	$	8.83
2Q 2009	20,000	1,820,000	$	8.83
3Q 2009	20,000	1,840,000	$	8.83
4Q 2009	20,000	1,840,000	$	8.83

Swaps (TexOk)			Field Price (2)
Natural gas (MMBtu)						(27,140,206	)
1Q 2009	20,000	1,800,000	$	7.87
2Q 2009	20,000	1,820,000	$	7.87
3Q 2009	20,000	1,840,000	$	7.87
4Q 2009	20,000	1,840,000	$	7.87

				Total	$	(72,022,591	)

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

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

The fair value of the commodity derivative contracts in place at June 30, 2008 that are marked to market resulted in a net liability of $72.0 million. For the three months ended June 30, 2008, we recognized in earnings a $49.4 million loss from these instruments, which consisted of $1.8 million in realized losses and $47.6 million in unrealized losses. For the six months ended June 30, 2008, we recognized in earnings a $73.3 million loss from these instruments. This includes a $1.4 million in realized losses and $71.9 million in unrealized losses.

During the second quarter of 2008 we entered into the following NYMEX priced natural gas derivative contract:

•

10,000 Mmbtu/day collar with a floor and ceiling price of $9.50 and $16.90 per Mmbtu, respectively, for the calendar year of 2009.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Interest Rate Swaps

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


Effective Date	Maturity Date	Libor Swap Rate		Notional Amount (Millions)		Fair Value (Dollars)
2/27/2007	2/26/2009	4.86	%	$	40.0	$	(581,486	)
4/22/2008	4/22/2010	3.19	%		25.0		72,243
4/22/2008	4/22/2010	3.19	%		50.0		155,934

						$	(353,309	)

For the three months ended June 30, 2008, we recognized a $0.4 million gain from the interest rate derivative which is not designated as a hedge. For the six months ended June 30, 2008, we recognized a loss from interest rate derivatives of $0.1 million.

NOTE 9—Fair Value of Financial Instruments

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

Level 1 Inputs

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

Level 2 Inputs

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

Level 3 Inputs

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

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

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The following table summarizes the valuation of our financial instruments by SFAS 157 input levels as of June 30, 2008:


	Fair Value Measurement (in thousands)
Description	Level 1		Level 2			Level 3		Total
Other assets		—		372			—		372
Current liabilities		—		(45,320	)		—		(45,320	)
Non-current liabilities		—		(27,428	)		—		(27,428	)

Total	$	—	$	(72,376	)	$	—	$	(72,376	)

NOTE 10—Discontinued Operations

On March 20, 2007, the Company closed the sale of substantially all of its oil and gas properties in South Louisiana with the exception of the St. Gabriel, Bayou Bouillon and Plumb Bob fields as discussed under Note 1 “Assets Held for Sale.” In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, the results of operations for the properties that were sold and for the properties that are held for sale have been reflected as discontinued operations. On August 4, 2008, we closed the sale of our St. Gabriel Field (See Note 11). We are actively pursuing bids and will accept any reasonable offer on the two remaining properties.

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008		2007
Revenues		306			407			885		9,011
Expenses		407			939			601		5,197

Income (loss) from discontinued operations		(101	)		(532	)		284		3,814
Income tax expense		—			186			—		(1,335	)

Income (loss) from discontinued operations, net of tax	$	(101	)	$	(346	)	$	284	$	2,479

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


	As of June 30, 2008
Assets held for sale	$	305
Accrued abandonment costs		276

NOTE 11—Acquisitions and Divestitures

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

In March 2008, we sold seismic data related to the St. Gabriel Field (treated as held for sale at June 30, 2008) for an adjusted price of $0.3 million. The adjusted proceeds of $0.3 million were recorded as a gain (See Note 10).

In May, 2008, we acquired additional interests in the Cotton Valley Trend, which increased our net exposure in the Haynesville Shale. We acquired 3,665 net acres in the Longwood field of Caddo Parish, Louisiana, through the issuance of 908,098 shares of our common stock valued at approximately $33.9 million.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

On June 10, 2008, we entered into a definitive agreement with a private company for the right to acquire over time a 50% non-operated interest in 5,800 gross acres (2,900 net) in the Central Pine Island field, adjacent to our Longwood field in Caddo Parish, Louisiana. We estimate total consideration to be approximately $3.3 million, which will be comprised of acreage costs for the 50% interest in the leasehold and the cost of a carried interest on the initial well drilled on the acreage.

On June 16, 2008, we announced that we entered into a joint development agreement with Chesapeake Energy Corporation, or Chesapeake, to develop our Haynesville Shale acreage in the Bethany Longstreet and Longwood fields of Caddo and DeSoto Parishes, Louisiana. Chesapeake purchased the deep rights to approximately 10,250 net acres of oil and natural gas leasehold comprised of a 20% working interest in approximately 25,000 net acres in the Bethany Longstreet field and a 50% working interest in approximately 10,500 net acres in the Longwood field for approximately $172.6 million, subject to normal closing adjustments. We received a deposit of $8.9 million from Chesapeake on June 15, 2008. The sale closed on July 15, 2008 and we received the remaining proceeds of $163.7 million. Chesapeake also purchased 7,500 net acres of deep rights in the Bethany Longstreet field from a third party, bringing the ownership interest in the deep rights in both fields after closing to 50% each for us and Chesapeake.

On July 25, 2008, we purchased a 70% interest in approximately 560 acres of Haynesville Shale formation deep rights in Northwest Louisiana for approximately $5.9 million.

On August 4, 2008, we closed the sale of our St. Gabriel Field to a private party for $0.1 million. These assets were treated as held for sale at June 30, 2008. See Note 1.

NOTE 12—Commitments and Contingencies

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

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

Forward-Looking Statements

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

•

planned capital expenditures;

•

future drilling activity;

•

our financial condition;

•

continued availability of debt and equity financing;

•

business strategy;

•

the market prices of oil and gas;

•

economic and competitive conditions;

•

legislative and regulatory changes; and

•

financial market conditions.

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

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

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

Overview

General

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

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

Source of Revenues

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

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

Second Quarter 2008 financial and operating results include:

•

We increased our oil and gas production volumes on continuing operations to approximately 67,000 Mcfe per day, representing an increase of 64% from the second quarter of 2007.

•

We conducted drilling operations on 46 gross wells in the second quarter of 2008.

•

We increased our net ownership in the Haynesville Shale play in Northwest Louisiana and East Texas to 60,500 net acres.

•

We entered into an agreement with Chesapeake Energy Corporation (“Chesapeake”) to jointly develop our Haynesville Shale acreage in Northwest Louisiana.

•

We reduced our total operating expenses by over $1.00 per Mcfe from the second quarter of 2007 to the second quarter of 2008 and the first half of 2007 to the first half of 2008.

Cotton Valley Trend

Our relatively low-risk development drilling program in the Cotton Valley Trend is primarily centered in and around Rusk, Panola, Angelina and Nacogdoches counties, Texas, and DeSoto, Caddo and Bienville parishes, Louisiana. We have steadily increased our acreage position in these areas over the last two years to approximately 195,000 gross acres as of June 30, 2008. Through June 30, 2008, we have participated in the drilling and logging of 363 Cotton Valley Trend wells (including 25 wells from the Caddo Parish acquisition in May 2008) with a success rate in excess of 99%. We conducted drilling operations on 46 gross wells during the second quarter of 2008 and 80 gross wells during the first half of 2008. Our net production volumes from our Cotton Valley Trend wells aggregated approximately 66,900 Mcfe per day in the second quarter of 2008, or approximately 64% higher than the Cotton Valley Trend production of the comparable prior year period.

Caddo Parish Acquisition

On May 28, 2008, we acquired additional interests in the Cotton Valley Trend, increasing our net exposure in the Haynesville Shale. We acquired approximately 3,665 net acres in the Longwood field of Caddo Parish, Louisiana, through the issuance of 908,098 shares of our common stock valued at approximately $33.9 million. The purchase included interests in 25 gross wells, with approximately 1.2 Mmcfe per day of net production, and an internally estimated 12.3 Bcfe of proved reserves (75% developed) associated with the shallower Hosston and Cotton Valley formations. We have plans to drill two new vertical wells and re-enter another to test the Haynesville Shale at Longwood by the end of 2008.

Chesapeake Haynesville Joint Development

On June 16, 2008, we entered into a joint development agreement with Chesapeake to develop our Haynesville Shale acreage in the Bethany Longstreet and Longwood fields of Caddo and DeSoto Parishes, Louisiana. Chesapeake purchased the deep rights to approximately 10,250 net acres of oil and natural gas leasehold comprised of a 20% working interest in approximately 25,000 net acres in the Bethany Longstreet field and a 50% working interest in approximately 10,500 net acres in the Longwood field for approximately $172.6 million, subject to normal closing adjustments. We received a deposit of $8.9 million from Chesapeake on June 15, 2008. The sale closed on July 15, 2008, and we received the remaining proceeds of $163.7 million on that date. Chesapeake also purchased 7,500 net acres of deep rights in the Bethany Longstreet field from a third party, bringing the ownership interest in the deep rights in both fields after closing to 50% each for us and Chesapeake. Chesapeake will be the operator of the joint Haynesville Shale development. We will hold approximately 25,000 gross (12,500 net) acres in the deep rights in the Bethany Longstreet field and approximately 10,500 gross (5,250 net) acres in the deep rights in the Longwood field, both of which are currently believed to be prospective for the Haynesville Shale. Through our joint development arrangement with Chesapeake, we will continue to operate existing production and operate any new wells drilled to the base of the Cotton Valley sand, and Chesapeake will operate any wells drilled below the base of the Cotton Valley sand, including the Haynesville Shale.

We are retaining the shallow rights to the base of the Cotton Valley sand and the existing production and reserves with respect to our 70% interest in the Bethany Longstreet field and our 100% interest in the Longwood field. We are also retaining our interest in both the shallow and Haynesville Shale rights on all of our East Texas assets. Horizontal development of the Haynesville Shale for the joint development agreement is expected to commence in the third quarter of 2008 with one rig dedicated to the play and a second rig to be added during the fourth quarter of 2008.

Central Pine Island Acquisition

With the completion of these transactions, including the joint development agreement with Chesapeake, we have a total of approximately 22,000 net acres in north Louisiana which we believe to be prospective for the Haynesville Shale formation.

Additional Haynesville Acquisitions

On July 25, 2008, we purchased a 70% interest in approximately 560 acres of Haynesville Shale formation deep rights in Northwest Louisiana for approximately $5.9 million.

Revised 2008 Capital Budget

We also announced on June 23, 2008 that our Board of Directors approved an increase in the preliminary capital expenditure budget for 2008 to $350.0 million, up from $275.0 million, as a result of anticipated increased drilling activity, primarily driven by our Haynesville Shale program.

Initial Haynesville Shale Drilling Program

As of June 30, 2008, we have drilled two wells on our North Louisiana acreage and two wells on our East Texas acreage, all of which targeted the Haynesville Shale via vertical wellbores. The initial production rates for the two Louisiana wells averaged 1.0 Mmcfe per day, and the one East Texas well which has been completed had an initial production rate of 2.6 Mmcfe per day. We expect to begin our Haynesville Shale horizontal drilling program in the third quarter of 2008.

Sale of South Louisiana Assets

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

On August 4, 2008, we closed the sale of the St. Gabriel Field to a private party for $0.1 million.

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

Results of Operations

Our financial statements include discontinued operations presentation for our assets located in South Louisiana. See Note 10 to our consolidated financial statements.

For the three months ended June 30, 2008, we reported a net loss applicable to common stock of $39.0 million, or $1.21 per share, on total revenue from continuing operations of $65.2 million as compared to a net loss applicable to common stock of $4.8 million, or $0.19 per share, on total revenue from continuing operations of $28.0 million for the three months ended June 30, 2007. We recorded a $48.9 million loss on derivatives not designated as hedges in the second quarter of 2008. See our discussion below under the caption “Gain (Loss) on Derivatives Not Designated as Hedges.”

For the six months ended June 30, 2008, we reported a net loss applicable to common stock of $64.4 million, or $2.02 per share, on total revenue from continuing operations of $111.5 million as compared to a net loss applicable to common stock of $5.3 million, or $0.21 per share, on total revenue from continuing operations of $51.5 million for the six months ended June 30, 2007. We recorded a $73.4 million loss on derivatives not designated as hedges in the first half of 2008. This loss on our derivatives was a major driver in the change from the applicable period of 2007 to 2008. For more discussion, see 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 represent revenue from sales of our oil and natural gas production volumes for continuing operations.


Summary Operating Information: Continuing Operations	Three Months Ended June 30,											Six Months Ended June 30,
	2008			2007			Variance					2008			2007			Variance
	(In thousands, except for price data)											(In thousands, except for price data)
Revenues:
Natural gas	$	59,436		$	26,148		$	33,288		127	%	$	101,896		$	48,010		$	53,886		112	%
Oil and condensate		5,416			1,712			3,704		216	%		9,153			3,167			5,986		189	%
Natural gas, oil and condensate		64,852			27,860			36,992		133	%		111,049			51,177			59,872		117	%
Operating revenues		65,173			28,006			37,167		133	%		111,526			51,548			59,978		116	%
Operating expenses		49,118			33,728			15,390		46	%		91,868			64,604			27,264		42	%
Operating income (loss)		16,055			(5,722	)		21,777		381	%		19,658			(13,056	)		32,714		251	%
Net income (loss) applicable to common stock		(39,014	)		(4,811	)		(34,203	)	(711	)%		(64,408	)		(5,287	)		(59,121	)	(1118	)%

Net Production:
Natural gas (MMcf)		5,841			3,549			2,292		65	%		10,874			6,744			4,130		61	%
Oil and condensate (MBbls)		45			28			17		61	%		83			54			29		54	%
Total (Mmcfe)		6,109			3,717			2,392		64	%		11,375			7,068			4,307		61	%
Average daily production (Mcfe/d)		67,129			40,844			26,285		64	%		62,497			39,048			23,449		60	%

Average realized sales price per unit:
Natural gas (per Mcf)	$	10.18		$	7.37		$	2.81		38	%	$	9.37		$	7.12		$	2.25		32	%
Oil and condensate (per Bbl)		121.51			61.06			60.45		99	%		109.70			58.97			50.73		86	%
Total (per Mcfe)		10.62			7.50			3.12		42	%		9.76			7.24			2.52		35	%

Operating revenues from continuing operations increased 133% in the second quarter of 2008 compared to the same period in 2007 as a result of increased Cotton Valley Trend production and higher natural gas prices. Net production increased 64% period to period due to a substantial increase in the number of wells producing in the Cotton Valley Trend. The average realized sales price per Mcfe increased 42% over the prior year period.

Operating revenues from continuing operations increased 116% in the first half of 2008 compared to the first half of 2007 as a result of increased production and higher prices. Net production increased 61% as a result of more producing Cotton Valley Trend wells. Average realized sales price per Mcfe increased 35% compared to the first half of 2007.

Operating Expenses

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


	Three Months Ended June 30,										Six Months Ended June 30,
Operating Expenses per Mcfe	2008		2007			Variance					2008		2007			Variance
Lease operating expenses	$	1.26	$	1.65		$	(0.39	)	(24	)%	$	1.30	$	1.46		$	(0.16	)	(11	)%
Production and other taxes		0.38		(0.16	)		0.54		338	%		0.32		(0.04	)		0.36		900	%
Transportation		0.39		0.39			—		—			0.37		0.36			0.01		3	%
Depreciation, depletion and amortization		4.75		5.24			(0.49	)	(9	)%		4.76		5.26			(0.50	)	(10	)%
Exploration		0.29		0.48			(0.19	)	(40	)%		0.33		0.58			(0.25	)	(43	)%
General and administrative		0.97		1.48			(0.51	)	(34	)%		1.00		1.53			(0.53	)	(35	)%

Lease Operating. Lease operating expense (“LOE”) for the second quarter of 2008 increased $1.5 million on an absolute basis compared to the corresponding period of 2007 ($7.7 million compared to $6.2 million). LOE for the first half of 2008 increased to $14.8 million versus $10.3 million for the first half of 2007 as a result of the substantial increase in the number of wells producing in the Cotton Valley Trend. LOE decreased 24% on a per unit basis compared to the second quarter of 2007 ($1.26 per Mcfe compared to $1.65 per Mcfe). LOE for the six months ended June 30, 2008 decreased 11% on a per unit basis compared to the same period of 2007 ($1.30 per Mcfe compared to $1.46 per Mcfe). Increased production led to these lower costs on a per unit basis. The second quarter of 2008, and first half of 2008 included $0.2 million and $1.2 million, respectively, in workover costs which contributed $0.04 and $0.10, respectively, to the LOE per Mcfe rates. Comparatively, the second quarter of 2007 and the first half of 2007 included $1.3 million and $1.5 million, respectively, in workover costs which contributed $0.35 and $0.21, respectively, to the LOE per Mcfe rates.

Production and Other Taxes. Production and other taxes of $2.3 million for the second quarter of 2008 includes production tax of $1.7 million and ad valorem tax of $0.6 million. Production tax during the quarter are net of $0.8 million of accrued Tight Gas Sands (“TGS”) credits for our wells in the State of Texas, which credits equate to $0.12 per Mcfe of production. Production and other taxes of $3.6 million for the first half of 2008 includes production tax of $2.6 million and ad valorem tax of $1.0 million. Production taxes during the first six months of 2008 are net of $1.6 million of TGS credits ($0.14 per Mcfe). During the comparable periods in 2007, we accrued TGS credits in excess of production taxes for the period.

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

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) expense increased to $29.0 million in the second quarter of 2008 from $19.5 million for the same period in 2007, primarily due to higher levels of production partially offset by a lower DD&A rate. The average DD&A rate for the second quarter of 2008 was $4.75 per Mcfe compared to $5.24 per Mcfe for the same quarter of 2007.

DD&A expense increased to $54.1 million in the first half of 2008 from $37.2 million for the first half of 2007. The average DD&A rate declined to $4.76 per Mcfe for the first half of 2008, versus $5.26 per Mcfe for the same period in 2007.

We calculated 2008 and 2007 DD&A rates for the first half of each respective year using the year end reserve reports. Proved developed reserves increased 41% from 76.7 Bcf at December 31, 2006 to 108.1 Bcf at December 31, 2007. The favorable impact of our 2007 Cotton Valley Trend drilling program and positive revisions of previous estimates from December 31, 2006 to December 31, 2007, led to the increase in proved developed reserves. We have engaged an independent engineering firm to prepare our June 30, 2008 reserve report, which we intend to use for calculating the DD&A rates for the remainder of 2008. We had previously engaged this same firm to prepare our June 30, 2007 reserves.

Exploration. Exploration expenses were flat at $1.8 million for both the second quarter of 2008 and 2007. On a per unit basis, exploration expenses declined from $0.48 per Mcfe for the second quarter 2007 to $0.29 per Mcfe for the second quarter 2008 as a result of higher production. For the same reason, exploration expense decreased from $4.1 million ($0.58 per Mcfe) for the first half of 2007 to $3.8 million ($0.33 per Mcfe) the first half of 2008. Undeveloped leasehold amortization declined from $3.4 million for the first half of 2007 to $2.4 million for the first half of 2008. Undeveloped leasehold amortization was $0.9 million for the second quarter of 2008.

General and Administrative. General and administrative (“G&A”) expense decreased 34% on a per unit basis to $0.97 per Mcfe in the second quarter 2008 compared to $1.48 per Mcfe in the second quarter of 2007 primarily due to a 64% increase in production volumes in the second quarter of 2008. Costs increased 8% to $5.9 million versus $5.5 million for the second quarter of 2008 and 2007, respectively, due to an increase in the number of employees of 26% from 80 at June 30, 2007, to 101 at June 30, 2008. The impact of the increase due to a higher employee count was partially mitigated by the $1.0 million tax payment made under protest in the first half of 2007 to the State of Louisiana for franchise taxes. Stock based compensation expense, which is a non-cash item, amounted to $1.4 million for the second quarter of 2008 compared to $1.3 million for the prior year period.

General and administrative expense increased to $11.4 million for the first half of 2008, compared to $10.8 million for the same period for 2007. On a per unit basis, G&A declined to $1.00 per Mcfe for the first half of 2008 versus $1.53 per Mcfe for the same period of 2007. General and administrative expense also includes stock based compensation of $2.7 million for both the first half of 2008 and 2007.

Other Income (Expense)

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


	Three Months Ended June 30,				Six Months Ended June 30,
Other income (expense):	2008		2007		2008		2007
Interest expense	(4,390	)	(2,222	)	(8,173	)	(4,846	)
Gain (loss) on derivatives not designated as hedges	(48,947	)	3,634		(73,434	)	(5,853	)
Income tax benefit	—		1,519		—		8,262

Average total borrowings	319,813		195,044		266,651		190,760
Weighted average interest rate	5.5	%	4.6	%	6.1	%	5.0	%

Interest Expense. Interest expense increased to $4.4 million in the second quarter of 2008 compared to the second quarter of 2007 amount of $2.2 million as a result of the higher average level of total borrowings in 2008 and an increase in the weighted average interest rate. Interest expense also increased for the first half of 2008 to $8.2 million compared to the comparable period in 2007 ($4.9 million) for the same reason. We added a second lien term loan in January 2008 for $75.0 million which carries a higher interest rate than both our Senior Credit Facility and our 3.25% convertible senior notes.

Gain (Loss) on Derivatives Not Designated as Hedges. Loss on derivatives not designated as hedges was $48.9 million in the second quarter of 2008, including a realized loss of $1.8 million and an unrealized loss of $47.6 million for the change in fair value of our natural gas commodity contracts. The increases in natural gas prices experienced during the period resulted in an unrealized loss on our commodity contracts. The second quarter of 2008 also includes a realized loss of $0.2 million and an unrealized gain of $0.6 million on our interest rate swap. As a comparison, the second quarter of 2007 included an unrealized gain of $2.4 million for the change in fair value of our commodity contracts and a realized gain of $1.0 million. The second quarter of 2007 also included a $0.2 million gain on our interest rate swap.

Loss on derivatives not designated as hedges was $73.4 million for the first half of 2008 compared to a loss of $5.9 million for the same period in 2007. The loss in 2008 includes a realized loss of $1.4 million and an unrealized loss of $71.9 million for the change in fair value of our natural gas commodity contracts. The loss in the first half of 2008 also includes a $0.1 million loss on our interest rate swap.

Income taxes. We increased our valuation allowance and reduced our net deferred tax asset to zero during 2007 after considering all available positive and negative evidence related to the realization of our deferred tax asset. As a result, we did not provide for income taxes on continuing operations in the second quarter and first half of 2008. Income taxes were a benefit of $1.5 million and $8.3 million for the second quarter of 2007 and first half of 2007, respectively, and represented approximately 35% of pre-tax loss from continuing operations.

We may achieve profitable operations for 2008 due to the gain on sale of oil and gas leasehold which closed on July 15, 2008. If this occurs we anticipate reversing a portion of the valuation allowance in an amount at least sufficient to eliminate any 2008 tax provision.

Discontinued Operations

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


	Three Months Ended June 30,						Six Months Ended June 30,
Discontinued Operations	2008			2007			2008		2007
Net Production:
Natural gas (MMcf)		4			8			11		523
Oil and condensate (MBbls)		2			1			4		84
Total (MMcfe)		16			14			35		1,027
Average Daily Net Production (Mcfe)		175			150			193		5,673
Gain (loss) on disposal, net of tax	$	(120	)	$	(162	)	$	280	$	10,751
Income (loss) from discontinued operations, net of tax		(101	)		(346	)		284		2,479
Total income (loss), net of tax	$	(221	)	$	(508	)	$	564	$	13,230

We realized a gain on disposal, net of tax, of $10.8 million in the first half of 2007. Our remaining South Louisiana assets, the St. Gabriel, Bayou Bouillon and Plumb Bob fields, were considered held for sale at June 30, 2008. In March 2008, we sold seismic related to the St. Gabriel field and recognized a gain on disposal of $0.3 million, as adjusted for normal closing items. On August 4, 2008, we closed the sale of our St. Gabriel Field to a private company for $0.1 million.

Income from discontinued operations for the three and six months ended June 30, 2008 and 2007 related to our South Louisiana assets. The first half of 2007 includes income from sold properties through the date of closing, March 20, 2007. The first half of 2008 and second quarters of 2008 and 2007 include income from assets held for sale only.

Liquidity and Capital Resources

Cash Flows

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


	Six Months Ended June 30,
	2008			2007			Variance
Cash flow statement information:
Net cash:
Provided by operating activities	$	57,096		$	39,916		$	17,180
Used in investing activities		(166,413	)		(59,307	)		(107,106	)
Provided by financing activities		110,851			18,832			92,019

Increase (decrease) in cash and cash equivalents	$	1,534		$	(559	)	$	2,093

Operating activities. Net cash provided by operating activities increased by $17.2 million to $57.1 million for the six months ended June 30, 2008, compared to $39.9 million for the six months ended June 30, 2007. Our cash flows before working capital changes were up from $35.2 million in the six months ended June 30, 2007, to $70.4 million in the six months ended June 30, 2008. The increases in the first six months of 2008 are primarily due to the 61% increase in natural gas production from continuing operations as a result of the wells added by our drilling program and the 32% increase in our realized average natural gas sales price compared to the same period in 2007. The increase in net cash provided by operating activities in the first half of 2008 was partially offset by $12.5 million due to the prepay transaction arranged with a physical gas purchaser prior to year end 2007. The physical volumes associated with this transaction were all delivered in the first quarter of 2008.

Investing activities. Net cash used in investing activities was $166.4 million for the six months ended June 30, 2008, compared to net cash used in investing activities of $59.3 million for the six months ended June 30, 2007. Net proceeds of $74.0 million received from the sale of substantially all of our South Louisiana assets in the first quarter of 2007 represent most of the variance. In the second quarter of 2008, we received a cash performance deposit in the amount of $8.9 million for the sale of a percentage of our deep rights in the Longwood and Bethany Longstreet fields. The sale closed in July of 2008. In the first half of 2008, we received proceeds of $0.3 million from sales of seismic data for our St. Gabriel field. The St. Gabriel Field was treated as an Asset Held for Sale at June 30, 2008. Total capital expenditures of $213.0 million for the six months ended June 30, 2008, were up $77.6 million compared to $135.4 million in the same period in 2007. In addition to having conducted drilling operations on 80 gross wells in the first six months of 2008 compared to only 57 gross wells in the first six months of 2007, the increase is attributable to the acquisition of producing and non-producing acreage in the Longwood field in Caddo Parish, Louisiana. We acquired the Longwood field assets in a non-cash transaction in which we issued 908,098 shares of our common stock to the seller, valued at approximately $33.9 million. Capital expenditures were $175.6 million for the six months ended June 30, 2008, not including this non-cash transaction.

Financing activities. Net cash provided by financing activities was $110.9 million for the six months ended June 30, 2008, compared to $18.8 million for the same period in 2007. In January 2008, we borrowed $75.0 million on our Second Lien Term Loan using $53.5 million of the proceeds to pay-off the balance on our revolving credit facility. Since the beginning of the year, we have had net borrowings of $40.5 million on the revolving credit facility. In the first quarter of 2007, we used proceeds from the sale of properties to pay the full outstanding balance on our existing bank credit facility in the amount of $65.0 million. By June 30, 2007, we had borrowed $87.0 million against our revolving credit facility.

In June 2008, our Board of Directors approved an increase in the preliminary capital expenditure budget for 2008 to $350 million, up from $275 million, as a result of the anticipated increase drilling activity primarily driven by the Haynesville Shale program.

Through June 30, 2008, we have expended approximately $179.0 million of our 2008 capital expenditure budget exclusive of property acquisitions. We expect to finance the remainder of our 2008 capital expenditures with a combination of cash flow from operations and proceeds obtained from the sale of a portion of our interests in the Haynesville Shale formation in the Longwood and Bethany Longstreet fields to Chesapeake and from proceeds obtained from our equity offering both which closed in July 2008.

3.25% Convertible Senior Notes

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

Share Lending Agreement

In connection with the offering of the notes we agreed to lend an affiliate of Bear, Stearns & Co. (“BSC”) a total of 3,122,263 shares of our common stock under the Share Lending Agreement. Under this agreement, BSC is entitled to offer and sell the 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 pursuant to the terms of the indenture governing the notes.

The Share Lending Agreement also requires BSC to post collateral of our common stock if its credit rating is below either A3 by Moody’s Investors Service (“Moody’s”) or A- by Standard and Poors (“S&P”). As a result of the long term ratings downgrade of BSC in March 2008, BSC was required to return all or a portion of the borrowed shares or collateralize the return obligation with cash or highly liquid non-cash collateral. On March 20, 2008, BSC had returned 1,497,963 shares of the 3,122,263 originally borrowed shares and fully collateralized the remaining 1,624,300 borrowed shares with a cash collateral deposit of approximately $41.3 million. This amount represents the market value of the remaining borrowed shares at March 20, 2008. Under the Share Lending Agreement, BSC is required to maintain collateral value in the amount at least equal to the market value of the outstanding borrowed shares. The market value of the cash collateral deposit at June 30, 2008 was approximately $122.9 million. The 1,497,963 shares returned to the Company were recorded to Treasury stock and retired in March of 2008.

In May 2008, JP Morgan Chase & Co. completed its acquisition of The Bear Stearns Companies Inc.

Senior Credit Facility

On November 17, 2005, we amended our existing credit agreement and entered into an amended and restated senior credit agreement (as amended, the “Senior Credit Facility”) and a term loan that expanded our borrowing capabilities and extended our credit facility for an additional two years. Total lender commitments under the Senior Credit Facility were $200 million, and the Senior Credit Facility matures on February 25, 2010. Revolving borrowings under the Senior Credit Facility are limited to, and subject to periodic redeterminations of the borrowing base. On January 11, 2008, we entered into the Ninth Amendment to our Senior Credit Facility. The amendment included the reduction in the borrowing base to $150 million less 30% of the Second Lien Term Loan (discussed below) in excess of $50 million. At June 30, 2008, we had a borrowing base of $175.0 million under the Senior Credit Facility and we had $81.0 million in outstanding revolving borrowings under the Facility. Interest on revolving borrowings under the Senior Credit Facility accrues at a rate calculated, at our option, at the bank base rate plus 0.00% to 0.75%, or LIBOR plus 1.25% to 2.25%, depending on borrowing base utilization.

•

Current Ratio of 1.0/1.0,

•

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

•

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

Second Lien Term Loan

•

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

•

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

•

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

Capped Call Option Transactions

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

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

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

During the second quarter of 2008, BSC sold its position in the capped call options to Bank of America.

Equity Offering

On July 14, 2008, we closed the public offering of 3,121,300 shares of our common stock at a price of $64.00 per share. Net proceeds from the offering were approximately $192.0 million after deducting the underwriters’ discount and estimated offering expenses. We used approximately $96.0 million of the net proceeds to pay off outstanding borrowings under our Senior Credit Facility. We plan to use the remaining net proceeds for general corporate purposes, including to fund a portion of our remaining 2008 drilling program, other capital expenditures and working capital requirements.

Accounting Pronouncements

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

Critical Accounting Policies and Estimates

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

Item 3 – Quantitative and Qualitative Disclosures about Market Risk

Commodity Price Risk

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

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

•

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

•

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

•

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

Our commodity contracts fall within our targeted range of 30% to 70% of our estimated net natural gas production volumes for the applicable periods of 2008. The fair value of the natural gas commodity contracts in place at June 30, 2008, resulted in a net liability of $72.0 million. Based on natural gas pricing in effect at June 30, 2008, a hypothetical 10% increase in oil and gas prices would have resulted in a derivative liability of $93.9 million while a hypothetical 10% decrease in oil and gas prices would have decreased the derivative liability to $52.9 million. See Note 8 “Derivative Activities” to our consolidated financial statements for additional information.

Interest Rate Risk

We have a variable-rate debt obligation that exposes us to the effects of changes in interest rates. To partially reduce our exposure to interest rate risk, from time to time we enter into interest rate swap agreements. In April 2008, we entered into interest rate derivative swap agreements whereby we have contracted an additional notional amount of $75.0 million at a fixed rate of 3.191% for the period April 2008 to April 2010. We did not designate this swap as a hedge. At June 30, 2008, we had the following interest rate swaps in place with BMO and BNP:


Effective Date	Maturity Date	Libor Swap Rate		Notional Amount (Millions)		Fair Value (Dollars)
2/27/2007	2/26/2009	4.86	%	$	40.0	$	(581,486	)
4/22/2008	4/22/2010	3.19	%		25.0		72,243
4/22/2008	4/22/2010	3.19	%		50.0		155,934

						$	(353,309	)

Based on interest rates at June 30, 2008, a hypothetical 10% increase or decrease in interest rates would not have a material effect on the liability.

Item 4 – Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We have established disclosure controls and procedures designed to ensure that material information required to be disclosed in our reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified by the Securities and Exchange Commission and that any material information relating to us

is recorded, processed, summarized and reported to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating our disclosure controls and procedures, our management recognizes that controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving desired control objectives. In reaching a reasonable level of assurance, our management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in rules 13a-15(c) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our Chief Executive Officer and Chief Financial Officer, based upon their evaluation as of June 30, 2008, the end of the period covered in this report, concluded that our disclosure controls and procedures were effective at the reasonable assurance level.

Changes in Internal Control over Financial Reporting

There were no changes in our system of internal control over financial reporting that occurred during our second 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.

We are named as a defendant, from time to time, in litigation relating to our normal business operations. Our management is not aware of any significant litigation, pending or threatened, that would have a material adverse effect on our financial position, results of operations, or cash flows.

Item 1A – Risk Factors.

The results of our planned exploratory drilling in the Haynesville Shale, a newly emerging play with limited drilling and production history, are subject to more uncertainties than our drilling program in the more established shallower Cotton Valley formations and may not meet our expectations for reserves or production.

We have only recently drilled our first three vertical wells to the Haynesville Shale, one of which is still drilling, from which we do not yet have sufficient data to recognize proved reserves in the formation. Part of the drilling strategy to maximize recoveries from the Haynesville Shale involves the drilling of horizontal wells using completion techniques that have proven successful in other shale formations. We have not participated in any horizontal drilling of the Haynesville Shale and to date the industry’s drilling and production history in the formation is limited. The ultimate success of these drilling strategies and techniques in the formation will be better evaluated over time as more wells are drilled and production profiles are better established. Accordingly, the results of our future drilling in the emerging Haynesville Shale play are more uncertain than drilling results in the shallower Cotton Valley horizons with established reserves and production.

There are no other material changes from risk factors previously disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

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

On May 23, 2008, we issued 908,098 shares of our common stock, valued at approximately $33.9 million, to Caddo Resources LP, a Delaware limited partnership, in consideration for approximately 3,665 net acres in the Longwood Field of Caddo Parish, Louisiana. The purchase included interests in 25 gross wells, with approximately 1.2 Mmcfe per day of net production, and an internally estimated 12.3 Bcfe of proved reserves (75% developed) associated with the shallower Hosston and Cotton Valley formations. This private issuance of stock was made in reliance upon exemption from the registration requirements of the Securities Act of 1933 pursuant to Section 4 (2) thereof. The 908,098 shares were registered under the Securities Act of 1933 pursuant to an effective registration statement on June 2, 2008.

Item 3 – Defaults Upon Senior Securities.

None.

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

Our Annual Meeting of Stockholders was held on May 22, 2008. Set forth below is a brief description of each matter acted upon at the meeting and the number of votes cast for, against or withheld, and abstaining or not voting as to each matter:


		For	Against	Abstained or Withheld
(i)	Election of Class I Directors

	Josiah T. Austin	31,622,972	—	381,458

	Geraldine A. Ferraro	31,577,071	—	427,359

	Gene Washington	31,636,949	—	367,481

(ii)	Ratification of the appointment of Ernst & Young LLP as the company’s independent registered public accounting firm for 2008.	31,934,964	63,221	6,244

	There were zero broker non-votes.

Item 5 – Other Information.

None.

Item 6 – Exhibits.


EXHIBIT NO		DESCRIPTION OF EXHIBIT
2.1†		Purchase and Sale Agreement, between Caddo Resources LP and Goodrich Petroleum Corporation, dated as of May 23, 2008 (Incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on May 29, 2008).

2.2†		Purchase and Sale Agreement between Goodrich Petroleum Company, L.L.C. and Chesapeake Louisiana, L.P. dated as of June 15, 2008 (Incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on June 15, 2008).

3.1		Restated Certificate of Incorporation of Goodrich Acquisition II, Inc., dated January 31, 1997 (Incorporated by reference to Exhibit 3.1A to the Company’s Third Amended Registration Statement on Form S-1 (Registration No. 333-47078) filed on December 8, 2000).

3.2		Certificate of Amendment of Restated Certificate of Incorporation of Goodrich Acquisition II, Inc., dated January 31, 1997 (Incorporated by reference to Exhibit 3.1B to the Company’s Third Amended Registration Statement on Form S-1 (Registration No. 333-47078) filed on December 8, 2000).

3.3		Certificate of Amendment of Restated Certificate of Incorporation of Goodrich Petroleum Corporation, dated March 12, 1998 (Incorporated by reference to Exhibit 3.2 to the Company’s Annual Report on Form 10-K filed on March 20, 1998).

3.4		Certificate of Amendment of Restated Certificate of Incorporation of Goodrich Petroleum Corporation, dated May 9, 2002 (Incorporated by reference to Exhibit 3.4 to the Company’s Current Report on Form 8-K filed on December 3, 2007).

3.5		Certificate of Amendment of Restated Certificate of Incorporation of Goodrich Petroleum Corporation, dated May 30, 2007 (Incorporated by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q filed on August 9, 2007).

3.6		Bylaws of the Company, as amended and restated (Incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on February 19, 2008).

4.1		Registration Rights Agreement, between Caddo Resources LP and Goodrich Petroleum Corporation, dated as of May 23, 2008 (Incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on May 29, 2008).

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

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

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

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

*	Filed herewith

**	Furnished herewith

†	Pursuant to the rules of the Commission, certain schedules and similar attachments to the Agreement have not been filed herewith. The registrant agrees to furnish supplementally a copy of any omitted schedule to the Commission upon request.

SIGNATURES

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


	GOODRICH PETROLEUM CORPORATION (Registrant)

Date: August 7, 2008	By:	/s/ Walter G. Goodrich
		Walter G. Goodrich
		Vice Chairman & Chief Executive Officer

Date: August 7, 2008	By:	/s/ David R. Looney
		David R. Looney
		Executive Vice President & Chief Financial Officer

GOODRICH PETROLEUM CORPORATION LIST OF EXHIBITS TO FORM 10-Q

FOR QUARTER ENDED JUNE 30, 2008


EXHIBIT NO		DESCRIPTION OF EXHIBIT
2.1†		Purchase and Sale Agreement, between Caddo Resources LP and Goodrich Petroleum Corporation, dated as of May 23, 2008 (Incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on May 29, 2008).

2.2†		Purchase and Sale Agreement between Goodrich Petroleum Company, L.L.C. and Chesapeake Louisiana, L.P. dated as of June 15, 2008 (Incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on June 15, 2008).

3.1		Restated Certificate of Incorporation of Goodrich Acquisition II, Inc., dated January 31, 1997 (Incorporated by reference to Exhibit 3.1A to the Company’s Third Amended Registration Statement on Form S-1 (Registration No. 333-47078) filed on December 8, 2000).

3.2		Certificate of Amendment of Restated Certificate of Incorporation of Goodrich Acquisition II, Inc., dated January 31, 1997 (Incorporated by reference to Exhibit 3.1B to the Company’s Third Amended Registration Statement on Form S-1 (Registration No. 333-47078) filed on December 8, 2000).

3.3		Certificate of Amendment of Restated Certificate of Incorporation of Goodrich Petroleum Corporation, dated March 12, 1998 (Incorporated by reference to Exhibit 3.2 to the Company’s Annual Report on Form 10-K filed on March 20, 1998).

3.4		Certificate of Amendment of Restated Certificate of Incorporation of Goodrich Petroleum Corporation, dated May 9, 2002 (Incorporated by reference to Exhibit 3.4 to the Company’s Current Report on Form 8-K filed on December 3, 2007).

3.5		Certificate of Amendment of Restated Certificate of Incorporation of Goodrich Petroleum Corporation, dated May 30, 2007 (Incorporated by reference to Exhibit 3.1 to the Company’s Quarterly Report on Form 10-Q filed on August 9, 2007).

3.6		Bylaws of the Company, as amended and restated (Incorporated by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K filed on February 19, 2008).

4.1		Registration Rights Agreement, between Caddo Resources LP and Goodrich Petroleum Corporation, dated as of May 23, 2008 (Incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on May 29, 2008).

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

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

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

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

*	Filed herewith

**	Furnished herewith

†	Pursuant to the rules of the Commission, certain schedules and similar attachments to the Agreement have not been filed herewith. The registrant agrees to furnish supplementally a copy of any omitted schedule to the Commission upon request.

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company